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

CourtSafety And Environmental Enforcement Bureau
Citation84 FR 21908
Record Number2019-09362
Publication Date15 May 2019
Federal Register, Volume 84 Issue 94 (Wednesday, May 15, 2019)
[Federal Register Volume 84, Number 94 (Wednesday, May 15, 2019)]
                [Rules and Regulations]
                [Pages 21908-21985]
                From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
                [FR Doc No: 2019-09362]
                [[Page 21907]]
                Vol. 84
                Wednesday,
                No. 94
                May 15, 2019
                Part IIDepartment of the Interior-----------------------------------------------------------------------Bureau of Safety and Environmental Enforcement-----------------------------------------------------------------------30 CFR Part 250Oil and Gas and Sulfur Operations in the Outer Continental Shelf--
                Blowout Preventer Systems and Well Control Revisions; Final Rule
                Federal Register / Vol. 84 , No. 94 / Wednesday, May 15, 2019 / Rules
                and Regulations
                [[Page 21908]]
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                DEPARTMENT OF THE INTERIOR
                Bureau of Safety and Environmental Enforcement
                30 CFR Part 250
                [Docket ID: BSEE-2018-0002; 190E1700D2 ET1SF0000.EAQ000 EEEE500000]
                RIN 1014-AA39
                Oil and Gas and Sulfur Operations in the Outer Continental
                Shelf--Blowout Preventer Systems and Well Control Revisions
                AGENCY: Bureau of Safety and Environmental Enforcement, Interior.
                ACTION: Final rule.
                -----------------------------------------------------------------------
                SUMMARY: The Bureau of Safety and Environmental Enforcement (BSEE) is
                revising existing regulations for well control and blowout preventer
                systems. This final rule revises requirements for well design, well
                control, casing, cementing, real-time monitoring (RTM), and subsea
                containment. These revisions modify regulations pertaining to offshore
                oil and gas drilling, completions, workovers, and decommissioning in
                accordance with Executive and Secretary of the Interior's Orders to
                ensure safety and environmental protection, while correcting errors and
                reducing certain unnecessary regulatory burdens imposed under the
                existing regulations. Accordingly, after thoroughly reexamining the
                2016 Blowout Preventer Systems and Well Control final rule (WCR),
                experiences from the implementation process, and various BSEE policies
                (notices to lessees, answers to frequently asked questions, and
                conditions of approval), BSEE will amend, revise, or remove certain
                current regulatory provisions that create unnecessary burdens on
                stakeholders, while still maintaining safety and environmental
                protection. The final regulations also address various issues and
                errors that BSEE identified during the implementation of the 2016 WCR.
                DATES: This final rule becomes effective on July 15, 2019. BSEE will
                defer compliance with certain provisions of the final rule, however,
                until the times specified in those provisions and as described in
                Section II of this preamble.
                 The incorporation by reference of certain publications listed in
                the rule is approved by the Director of the Federal Register as of July
                15, 2019.
                FOR FURTHER INFORMATION CONTACT: For technical questions contact Fred
                Brink, Gulf of Mexico Region (GOMR) District Operations Support, (504)
                736-2400, or by email: [email protected]; for procedural questions
                contact Kirk Malstrom, Regulations and Standards Branch, (202) 258-
                1518, or by email: [email protected].
                SUPPLEMENTARY INFORMATION:
                Executive Summary
                 In the immediate aftermath of the Deepwater Horizon incident in
                2010, BSEE adopted several recommendations from multiple investigation
                teams, and promulgated multiple rulemakings including the Drilling
                Safety Rule (Oct. 2010), Safety and Environmental Management Systems
                (SEMS) I (Oct. 2010), and SEMS II (April 2013), in order to improve the
                safety of offshore operations. Subsequently, BSEE published the Blowout
                Preventer Systems and Well Control final rule (the WCR) on April 29,
                2016. The 2016 WCR consolidated the equipment and operational
                requirements for well control into one part of BSEE's regulations;
                enhanced blowout preventer (BOP), well design, and well-control
                requirements; and incorporated certain industry consensus standards.
                Most of the 2016 WCR provisions became effective on July 28, 2016.
                Although the 2016 WCR addressed a significant number of issues that
                were identified during the analysis of the Deepwater Horizon incident,
                BSEE recognized that BOP equipment and systems continue to improve
                technologically and well control processes also evolve. In 2017,
                Congress also encouraged BSEE to:
                evaluate information learned from additional stakeholder input and
                ongoing technical conversations to inform implementation of this
                rule. To the extent additional information warrants revisions to the
                rule that require public notice and comment, the Bureau is
                encouraged to follow that process to ensure that offshore operations
                promote safety and protect the environment in a technically feasible
                manner.\1\
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                 \1\ See n. 10, supra.
                Additionally, since the WCR became effective in 2016, BSEE has
                continued to engage with the offshore oil and gas industry, Standards
                Development Organizations (SDOs), and other stakeholders. During the
                course of these engagements, BSEE identified areas for regulatory
                improvement and stakeholders expressed a variety of concerns regarding
                the implementation of the 2016 WCR. For instance, oil and natural gas
                operators raised concerns about certain regulatory provisions that they
                assert impose undue burdens on their industry, but do not significantly
                enhance worker safety or environmental protection (e.g., how real time
                monitoring is monitored and utilized onshore; a strictly enforced 0.5
                pounds per gallon (ppg) drilling margin; requirements that may be
                inconsistent with American Petroleum Institute (API) Standard 53; and
                requirements for certain BSEE approvals during cementing operations
                that result in unnecessary delay). Other stakeholders suggested that
                certain regulatory requirements do not properly account for advances or
                limitations in technology and processes. Further, BSEE received
                numerous questions regarding the proper interpretation and application
                of provisions viewed to be unclear or ambiguous, requiring BSEE to
                provide substantial informal guidance regarding the terms of the 2016
                WCR. BSEE posted approximately 100 responses to questions regarding the
                2016 WCR provisions on the BSEE web page at https://www.bsee.gov/guidance-and-regulations/regulations/well-control-rule.
                 Accordingly, after thoroughly reexamining the 2016 WCR, experiences
                from the implementation process, and BSEE policy, BSEE is amending,
                revising, or removing current regulatory provisions that create
                unnecessary burdens on stakeholders while still maintaining safety and
                environmental protection. On May 11, 2018, BSEE published in the
                Federal Register a proposed rule to revise certain provisions of the
                2016 WCR (83 FR 22128) (the ``proposed rule'') and to solicit comments
                on several additional issues. In response to the proposed rule, BSEE
                received over 265 sets of comments containing individually submitted
                comments and multiple similar group form letters, totaling over 118,000
                submittals. Comments included submittals from individual entities
                (e.g., companies, industry organizations, non-governmental
                organizations, State governments, and private citizens). All relevant
                comments are posted at the Federal eRulemaking portal: http://www.regulations.gov. To access the comments at that website, enter
                BSEE-2018-0002 in the Search box. The final regulatory changes reflect
                BSEE's consideration of the public comments received on both the 2016
                WCR and the proposed rule, and stakeholders' recommendations pertaining
                to the requirements applicable to offshore oil and gas drilling,
                completions, workovers, and decommissioning. This rule revises
                regulatory provisions in 30 CFR part 250, subparts A, B, D, E, F, G,
                and Q on topics such as, but not limited to:
                 Notifications and submittals to BSEE;
                 Drilling margins;
                 Lift boats;
                 Real-time monitoring;
                [[Page 21909]]
                 BSEE Approved Verification Organizations (BAVOs);
                 Accumulator systems;
                 BOP and control station testing;
                 Coiled tubing; and
                 Mechanical barriers (packers and bridge plugs).
                 BSEE utilized the best available data to analyze the economic
                impacts of the final changes. That analysis indicates that the
                estimated overall economic impact will benefit the industry over the
                next 10 years because of the reduction in compliance costs, in addition
                to increased regulatory certainty. As this rule maintains safety and
                environmental protection, the entities realizing savings from these
                changes can deploy them for other, more productive purposes, e.g.,
                additional capital investment. Increased productivity and competiveness
                of domestic energy projects benefit consumers and the broader U.S.
                economy.
                 In keeping with recent Executive and Secretary's Orders, BSEE
                undertook a review of the 2016 WCR with a view toward the policy
                direction of encouraging energy exploration and production on the Outer
                Continental Shelf (OCS) and reducing unnecessary regulatory burdens,
                while ensuring that any such activity is safe and environmentally
                responsible. BSEE carefully reviewed all 342 provisions of the 2016
                WCR, and determined that this final rule revises or adds to 71
                provisions of the 2016 WCR--or approximately 20% of the 2016 WCR
                provisions. The regulations will still contain the core safety and
                environmental protective provisions of the 2016 WCR. In the process,
                BSEE compared each of the changes to the 424 recommendations arising
                from 26 separate reports from 14 different organizations developed in
                the wake of and in response to the Deepwater Horizon disaster, and
                determined that none of the final changes ignores or contradicts any of
                those recommendations, or alters any provision of the 2016 WCR in a way
                that would make the result inconsistent with those recommendations.
                Further, nothing in this final rule alters any elements of other rules
                promulgated since Deepwater Horizon, including the Increased Safety
                Measures for Energy Development on the OCS (Drilling Safety Rule) (75
                FR 63346, October 14, 2010), SEMS I and II (75 FR 63610, October 15,
                2010, 78 FR 20423, April 5, 2013). BSEE's review has been thorough,
                careful, and tailored to the task of reducing unnecessary regulatory
                burdens, while ensuring that operators conduct OCS activities in a safe
                and environmentally responsible manner.
                Table of Contents
                I. Background
                 A. BSEE Statutory and Regulatory Authority and Responsibilities
                 B. Purpose and Summary of the Rulemaking
                 C. Summary of Documents Incorporated by Reference
                 D. Executive and Secretary's Orders
                 E. Stakeholder Engagement
                II. Discussion of Compliance Dates for the Final Rule
                 A. April 29, 2021--Alternative Cutting Device No Longer Allowed
                 B. May 1, 2023--Drill Pipe Positioning Within Shearing Blades
                III. Discussion of Final Rule Requirements
                 A. Summary of Key Regulatory Provisions
                 B. Summary of Significant Differences Between the Proposed and
                Final Rules
                 1. Safe Drilling Margin--Sec. Sec. 250.414 and 250.427(b)
                 2. Centering Capabilities While Shearing--Sec. Sec. 250.732 and
                250.734(a)(16)
                 3. Shearing Combinations--Sec. 250.734(a)(1)(ii)
                 4. Subsea Accumulator Capacity--Sec. 250.734(a)(3)(iii)
                 5. 21-Day BOP Testing Frequency--Sec. 250.737
                IV. Discussion of Public Comments on the Proposed Rule
                 A. General Support for the Proposed Rule
                 B. General Opposition to the Proposed Rule
                 C. 21-Day BOP Testing Frequency
                 D. BSEE Approved Verification Organization (BAVO)
                 E. Legal Comments
                 F. Economic Comments
                 G. Environmental Comments
                 H. Miscellaneous Comments
                V. Section-by-Section Summary and Responses to Comments on the
                Proposed Rule
                VI. Procedural Matters
                List of Acronyms and References
                ANL Argonne National Laboratory
                ANPR Advance Notice of Proposed Rulemaking
                ANSI American National Standards Institute
                APA Administrative Procedure Act
                APD Application for Permit To Drill
                API American Petroleum Institute
                APM Application for Permit to Modify
                ASME American Society of Mechanical Engineers
                BAST Best Available and Safest Technology
                BAVO BSEE Approved Verification Organization
                BOEM Bureau of Ocean Energy Management
                BOP Blowout Preventer
                BSEE Bureau of Safety and Environmental Enforcement
                BSR Blind Shear Ram
                BTS Bureau of Transportation Statistics
                CDWOP Conceptual Deepwater Operations Plan
                Department Department of the Interior
                DWOP Deepwater Operations Plan
                EA Environmental Assessment
                ECD Equivalent Circulating Density
                EIS Environmental Impact Statement
                E.O. Executive Order
                EOR End of Operations Report
                ESA Endangered Species Act
                FOIA Freedom of Information Act
                FONSI Finding of No Significant Impact
                FRIA Final Regulatory Impact Analysis
                FSHR Free Standing Hybrid Riser
                GDP Gross Domestic Product
                HPHT High Pressure High Temperature
                IADC International Association of Drilling Contractors
                IBR Incorporated By Reference
                IC Information Collection
                IEC International Electrotechnical Commission
                IOGP International Association of Oil And Gas Producers
                IRIA Initial Regulatory Impact Analysis
                ISO International Organization For Standardization
                JIP Joint Industry Project
                LMRP Lower Marine Riser Package
                MASP Maximum Anticipated Surface Pressure
                MIA Mechanical Integrity Assessment
                MODU Mobile Offshore Drilling Unit
                MPB Multiple Physical Barrier
                NAICS North American Industry Classification System
                NEPA National Environmental Policy Act
                NPRM Notice of Proposed Rulemaking
                NTTAA National Technology Transfer and Advancement Act
                OCS Outer Continental Shelf
                OCSLA Outer Continental Shelf Lands Act
                OEM Original Equipment Manufacturer
                OFR Office of the Federal Register
                OIRA Office of Information and Regulatory Affairs
                OMB Office of Management Budget
                OORP Office of Offshore Regulatory Programs
                Psi pounds per square inch
                Ppg pounds per gallon
                PRA Paperwork Reduction Act
                PWD Pressure While Drilling
                QRA Quantitative Risk Analysis
                RCD Regional Containment Demonstration
                RFA Regulatory Flexibility Analysis
                RIA Regulatory Impact Analysis
                ROT Remotely Operated Tools
                ROV Remotely Operated Vehicle
                RTM Real-Time Monitoring
                SBA Small Business Administration
                SCCE Source Control and Containment Equipment
                SDO Standards Development Organization
                Secretary Secretary of the Interior
                SEMS Safety and Environmental Management Systems
                SPPE Safety and Pollution Prevention Equipment
                SRAM System Risk Assessment Management
                TBT Technical Barriers to Trade
                WAR Well Activity Report
                WCP Well Containment Plan
                WCR Well Control Rule
                WTO World Trade Organization
                I. Background
                A. BSEE Statutory and Regulatory Authority and Responsibilities
                 BSEE derives its authority primarily from the Outer Continental
                Shelf Lands
                [[Page 21910]]
                Act (OCSLA), 43 U.S.C. 1331-1356a. Congress enacted OCSLA in 1953,
                authorizing the Secretary of the Interior (Secretary) to lease the OCS
                for mineral development, and to regulate oil and gas exploration,
                development, and production operations on the OCS. The Secretary
                delegated authority to perform certain of these functions to BSEE.
                 To carry out its responsibilities, BSEE regulates offshore oil and
                gas operations to enhance the safety of exploration for and development
                of oil and gas on the OCS, to ensure that those operations protect the
                environment, and to implement advancements in technology. BSEE also
                conducts onsite inspections to ensure compliance with regulations,
                lease terms, and approved plans and permits. Detailed information
                concerning BSEE's regulations and guidance to the offshore oil and gas
                industry may be found on BSEE's website at: https://www.bsee.gov/guidance-and-regulations.
                 BSEE's regulatory program covers a wide range of facilities and
                activities, including drilling, completion, workover, production,
                pipeline, and decommissioning operations. Drilling, completion,
                workover, and decommissioning operations are types of well operations
                that offshore operators \2\ perform throughout the OCS. These well
                operations are the primary focus of this rulemaking.
                ---------------------------------------------------------------------------
                 \2\ BSEE's regulations at 30 CFR part 250 generally apply to ``a
                lessee, the owner or holder of operating rights, a designated
                operator or agent of the lessee(s). . . ,'' covered by the
                definition of ``you'' in Sec. 250.105. For convenience, this
                preamble will refer to all of the regulated entities as
                ``operators,'' unless otherwise indicated.
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                B. Purpose and Summary of the Rulemaking
                 This final rule amends and updates certain provisions of the
                Blowout Preventer Systems and Well Control regulations and updates the
                regulations to better implement BSEE policy. This final rule will
                strengthen the Administration's policy of facilitating energy security
                leading to increased domestic oil and gas production, and reduce
                unnecessary burdens on stakeholders while still maintaining safety and
                environmental protection. Since 2010, in order to improve worker safety
                and environmental protection, BSEE has promulgated a number of rules
                (e.g., Safety and Environmental Management Systems I and II (75 FR
                63610, October 15, 2010; 78 FR 20423, April 5, 2013), the final safety
                measures rule (77 FR 50856, August 22, 2012), the production safety
                systems final rule (83 FR 49216, September 28, 2018), and the 2016 WCR
                (81 FR 25888; April 29, 2016). The 2016 WCR consolidated into one part
                the equipment and operational requirements pertaining to BOP and well
                control for offshore oil and gas drilling, completions, workovers, and
                decommissioning that were previously codified in various parts of
                BSEE's regulations. More specifically, the 2016 WCR incorporated
                industry standards; adopted reforms to well design, well control,
                casing, cementing, real-time well monitoring, and subsea containment
                requirements; and implemented many of the recommendations arising from
                various investigations of the Deepwater Horizon incident. Most of the
                provisions of the 2016 WCR became effective on July 28, 2016.
                 Since the time the 2016 WCR regulations took effect, oil and
                natural gas operators have raised various concerns, and BSEE has
                identified issues during the implementation of the rule. The concerns
                and issues involve certain regulatory provisions that impose undue
                burdens on oil and natural gas operators, but do not significantly
                enhance worker safety or environmental protection. BSEE understands the
                operators' concerns that have been raised, but BSEE also fully
                recognizes that the BOP and other well-control requirements are
                critical to ensure safety and environmental protection. Consistent with
                recent Executive and Secretary's Orders (discussed further in Section
                I.D below) and congressional direction, BSEE undertook a review of the
                2016 WCR. It did so with a view toward the policy direction of
                encouraging energy exploration and production on the OCS and reducing
                unnecessary regulatory burdens, while ensuring that any such activity
                is conducted in a safe and environmentally responsible manner. BSEE
                carefully analyzed all 342 provisions of the 2016 WCR, and proposed to
                revise or add to 71 provisions--or approximately 20%--of the 2016 WCR
                provisions. In the process, BSEE compared each of the changes to the
                424 recommendations arising from 26 separate reports from 14 different
                organizations \3\ developed in the wake of and response to the
                Deepwater Horizon disaster. This final rule is consistent with the
                proposed revisions and none of the final changes ignore or contradict
                any of those recommendations, or alters any provision of the 2016 WCR
                in a way that would make the result inconsistent with those
                recommendations. Further, nothing in this final rule alters any
                elements of other rules promulgated since Deepwater Horizon, including
                the Drilling Safety Rule (Oct. 2010), SEMS I (Oct. 2010), and SEMS II
                (April 2013). BSEE's review was thorough, careful, and tailored to the
                task of reducing unnecessary regulatory burdens while ensuring that OCS
                activity is conducted in a safe and environmentally responsible manner.
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                 \3\ DOI, DOI OCS Safety Oversight Board, DOI OIG, DOI/Department
                of Homeland Security (DHS) Joint Investigation Team, National
                Commission on the BP Deepwater Horizon Oil Spill and Offshore
                Drilling, Chief Counsel for the National Commission, National
                Academy of Engineering, Joint Industry Subsea Well Control and
                Containment Task Force, Environmental Law Institute, Ocean Energy
                Safety Advisory Committee, Chemical Safety Board, Joint Industry Oil
                Spill Preparedness and Response Task Force, Transportation Research
                Board, U.S. Government Accountability Office (GAO).
                ---------------------------------------------------------------------------
                 This rule revises current regulations that impact offshore oil and
                gas drilling, completions, workovers, and decommissioning activities.
                The final regulations also address various issues that BSEE identified
                during the implementation of the 2016 WCR, as well as numerous
                questions that have required substantial informal guidance from BSEE
                regarding the interpretation and application of the 2016 WCR.\4\ For
                example, this final rule:
                ---------------------------------------------------------------------------
                 \4\ BSEE posted approximately 100 responses to questions
                regarding the 2016 WCR provisions on the BSEE web page https://www.bsee.gov/guidance-and-regulations/regulations/well-control-rule.
                ---------------------------------------------------------------------------
                 Clarifies the rig movement reporting requirements.
                 Clarifies and revises the requirements for certain
                submittals to BSEE to eliminate redundant and unnecessary reporting.
                 Clarifies the drilling margin requirements in Sec. Sec.
                250.414 and 250.427.
                 Revises Sec. 250.723 by removing references to lift boats
                from the section.
                 Removes certain prescriptive requirements for RTM.
                 Replaces the use of a BAVO with the use of an independent
                third party for certain certifications and verifications of BOP systems
                and components, and removes the requirement to have a BAVO submit a
                Mechanical Integrity Assessment report for the BOP stack and system.
                 Revises the accumulator system requirements and
                accumulator bottle requirements to better align with API Standard 53.
                 Revises the control station and pod testing schedules to
                ensure component functionality without inadvertently requiring
                duplicative testing.
                 Includes coiled tubing and snubbing requirements in
                Subpart G.
                 Revises the text to ensure consistency and conformity
                across the applicable sections of the regulations.
                 Revises the regulation to include a 21-day BOP testing
                frequency.
                [[Page 21911]]
                C. Summary of Documents Incorporated by Reference
                 This rule updates a document currently incorporated by reference to
                a newer edition, includes an addendum to an already incorporated
                standard, and adds two new standards for incorporation. A brief summary
                of the final changes, based on the descriptions in each standard or
                specification, is provided in the text that follows.
                API Standard 53 and Addendum--Blowout Prevention Equipment Systems for
                Drilling Wells
                 API Standard 53 (Fourth Edition published November 2012) and
                addendum (published July 2016) provide requirements for the
                installation and testing of blowout prevention equipment systems whose
                primary functions are to confine well fluids to the wellbore, provide
                means to add fluid to the wellbore, and allow controlled volumes to be
                removed from the wellbore. BOP equipment systems are comprised of a
                combination of components that are covered by this document, Including:
                Installations for surface and subsea BOPs; choke and kill lines; choke
                manifolds; control systems; and auxiliary equipment. The document also
                addresses equipment arrangements. The Addendum contains clarifications
                to API Standard 53, 4th Edition.
                 This standard also provides industry best practices related to the
                use of dual shear rams, maintenance and testing requirements, and
                failure reporting. The standard does not address diverters, shut-in
                devices, and rotating head systems (rotating control devices), whose
                primary purpose is to safely divert or direct flow, rather than to
                confine fluids to the wellbore. It also does not include procedures and
                techniques for well control and extreme temperature operations.
                API Bulletin 92L--Drilling Ahead Safely With Lost Circulation in the
                Gulf of Mexico
                 API Bulletin 92L, First Edition, was published in August 2015. API
                Bulletin 92L addresses drilling margins and drilling ahead with lost
                circulation in wells drilled in the OCS environments. The drilling
                margin is the difference between the maximum pore pressure and minimum
                fracture pressure of a formation. Lost circulation is the flow of
                drilling fluid into the formation instead of returning up the annulus.
                If uncontrolled, lost circulation can lead to consequences potentially
                as severe as a blowout. This bulletin identifies items that should be
                considered to safely address lost circulation challenges when
                equivalent circulation density (ECD) exceeds the fracture gradient of a
                formation. It also provides guidance regarding appropriate responses
                when lost circulation is experienced with either surface or subsea BOP
                stack operations (excluding diverter operations). Lastly, the bulletin
                recommends four decision tree flow charts for common lost circulation
                scenarios in the OCS: (1) Drilling Exploration Wells with Lost
                Circulation; (2) Drilling Ahead Below Salt with Lost Circulation; (3)
                Drilling Depleted Zones with Lost Circulation; and (4) Managed Pressure
                Drilling with Lost Circulation. Although similar, each flow chart is
                unique and specific to the circumstances surrounding the lost
                circulation event. The flow charts serve as an aid for operators to use
                when deciding how best to safely drill ahead when lost circulation
                occurs.
                API Standard 65--Part 2, Isolating Potential Flow Zones During Well
                Construction
                 This standard, which API issued in December 2010 (reaffirmed
                November 2016), outlines the process for isolating potential flow zones
                during well construction. The new Standard 65--part 2 enhances the
                description and classification of well-control barriers, and defines
                testing requirements for cement to be considered a barrier.
                API Recommended Practice 17H--Remotely Operated Tools and Interfaces on
                Subsea Production Systems
                 The final rule updates the incorporated version of this document
                from the First Edition (July 2004, reaffirmed January 2009) to the
                Second Edition (June 2013) and Errata (January 2014). This recommended
                practice provides general recommendations and overall guidance for the
                design and operation of remotely operated tools (ROT) and remotely
                operated vehicle (ROV) tooling used on offshore subsea systems. ROT and
                ROV performance is critical to ensuring safe and reliable deepwater
                operations and this document provides general performance guidelines
                for this and associated equipment. One of the main differences between
                the first edition and second edition of this recommended practice is
                that the second edition includes provisions on high flow Type D hot
                stabs.
                International Organization for Standardization (ISO)/IEC (International
                Electrotechnical Commission) 17021-1--Conformity assessment--
                Requirements for Bodies Providing Audit and Certification of Management
                Systems--Part 1: Requirements.
                 The final rule incorporates into the regulations a reference to
                ISO/IEC 1702-1, First Edition, June 15, 2015, for purposes of the
                quality management system certification requirements of Sec.
                250.730(d). This standard contains principles and requirements to
                ensure the competence, consistency, and impartiality of bodies
                providing audit and certification of all types of management systems.
                It provides general requirements for such bodies performing audit and
                certification in the fields of quality, the environment, and other
                types of management systems. Incorporation of this standard will
                provide clarity and consistency surrounding the critical qualifications
                of entities responsible for certifying quality management systems for
                the manufacture of BOP stacks.
                How To View the Documents Incorporated by Reference
                 When a copyrighted publication is incorporated by reference into
                BSEE regulations, BSEE is obligated to observe and protect that
                copyright. BSEE is working with the standards organizations to provide
                free online viewing for standards incorporated by reference. Many such
                organizations already make relevant standards publicly available free
                of charge. BSEE provides members of the public with website addresses
                where these standards may be accessed for viewing--sometimes for free
                and sometimes for a fee. Standards development organizations decide
                whether to charge a fee. One such organization, API, provides free
                online public access to view read-only copies of its key industry
                standards, including a broad range of technical standards. All API
                standards that are safety-related and that are incorporated into
                Federal regulations, or that are considered for incorporation, are
                available to the public for free viewing online in the Incorporation by
                Reference Reading Room on API's website at: http://publications.api.org.\5\ In addition to the
                [[Page 21912]]
                free online availability of these standards for viewing on API's
                website, hardcopies and printable versions are available for purchase
                from API. The API website address to purchase standards is: https://www.api.org/products-and-services/standards/purchase.
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                 \5\ To view these standards online, go to the API publications
                website at: http://publications.api.org. You must then log-in or
                create a new account, accept API's ``Terms and Conditions,'' click
                on the ``Browse Documents'' button, and then select the applicable
                category (e.g., ``Exploration and Production'' or ``IBR Documents
                Under Consideration'') for the standard(s) you wish to review.
                ---------------------------------------------------------------------------
                 The International Organization for Standardization (ISO) creates
                documents that provide requirements, specifications, guidelines, or
                characteristics that can be used consistently to ensure that materials,
                products, processes, and services are fit for their purposes. All ISO
                International Standards are available at the ISO Store for purchase at:
                https://www.iso.org/store.html.
                 For the convenience of members of the viewing public who may not
                wish to purchase copies or view these incorporated documents online,
                they may be inspected at BSEE's office in Houston, at 1919 Smith
                Street, Suite 14042, Houston, Texas 77002. To make an appointment to
                inspect incorporated material at the Houston BSEE office, call 1-844-
                259-4779. BSEE may also make the standards available at its other
                offices located in: Washington, DC; Sterling, Virginia; New Orleans,
                Louisiana; Camarillo, California; and Anchorage, Alaska. Individuals
                wishing to view standards at a BSEE office may make arrangements by
                sending an email to: [email protected].
                D. Executive and Secretary's Orders
                 On March 28, 2017, the President issued Executive Order (E.O.)
                13783--Promoting Energy Independence and Economic Growth (82 FR 16093).
                The E.O. directed Federal agencies to review all existing regulations
                and other agency actions with a goal toward ``avoiding regulatory
                burdens that unnecessarily encumber energy production, constrain
                economic growth, and prevent job creation.'' It instructs agencies to
                ``review existing regulations that potentially burden the development
                or use of domestically produced energy resources and appropriately
                suspend, revise, or rescind those that unduly burden the development of
                domestic energy resources beyond the degree necessary to protect the
                public interest or otherwise comply with the law.''
                 On April 28, 2017, the President issued E.O. 13795--Implementing an
                America-First Offshore Energy Strategy (82 FR 20815), which directed
                the Secretary to review the 2016 WCR for consistency with the policy
                ``to encourage energy exploration and production, including on the
                Outer Continental Shelf, in order to maintain the Nation's position as
                a global energy leader and foster energy security and resilience for
                the benefit of the American people, while ensuring that any such
                activity is safe and environmentally responsible'' and to ``publish for
                notice and comment a proposed rule revising that rule, if appropriate
                and as consistent with law.'' It further directed the Secretary of the
                Interior to ``take all appropriate action to lawfully revise any
                related rules and guidance for consistency with the policy set forth in
                section 2 of this order. Additionally, the Secretary of the Interior
                shall review BSEE's regulatory regime for offshore operators to
                determine the extent to which additional regulation is necessary.''
                 To further implement E.O. 13795, the Secretary issued Secretary's
                Order No. 3350 on May 1, 2017, directing BSEE to review the 2016 WCR
                for consistency with E.O. 13795 and prepare a report ``providing
                recommendations on whether to suspend, revise, or rescind the rule'' in
                response to concerns raised by stakeholders that the 2016 WCR
                ``unnecessarily include[s] prescriptive measures that are not needed to
                ensure safe and responsible development of our OCS resources.''
                 Based on E.O.s 13783 and 13795, congressional guidance, and
                Secretary's Order No. 3350, and in light of the requests received for
                clarification and revision of various provisions, BSEE reviewed the
                regulations promulgated through the 2016 WCR and is making revisions to
                those regulations that will reduce unnecessary burdens on industry
                without affecting key 2016 WCR provisions that have a significant
                impact on improving safety and equipment reliability.
                 On September 28, 2018, the Department of the Interior (Department)
                issued Secretary's Order No. 3369 (S.O. 3369), ``Promoting Open
                Science.'' S.O. 3369 directs bureaus within the Department to ensure
                that their use of science in decision-making is open and transparent to
                facilitate public awareness, and to ensure that, when decisions are
                based on scientific data or literature, bureaus utilize the ``best
                available science.'' As previously discussed, BSEE used a number of
                sources of information to inform decisions related to these revisions,
                including comments received through a ``Request for comments'' on the
                DOI's regulatory reform initiatives, published in the Federal Register
                on June 22, 2017 (82 FR 28429), and experience gained during the
                implementation of the 2016 WCR and the policies developed in response
                to those experiences. In addition, BSEE solicited input from interested
                parties to identify potential revisions to the regulations, including
                through the public forum held on September 20, 2017, in Houston, Texas.
                Further, BSEE gained valuable insights from comments received in
                response to the proposed rule. BSEE regulatory staff used information
                from these sources and worked directly with BSEE regional subject
                matter experts to assess the current requirements for well control and
                blowout preventers in order to determine which provisions could
                potentially be revised, while leaving critical safety provisions intact
                to maintain safety and environmental protection. BSEE also reviewed
                publically available lists of alternate procedures and departures that
                BSEE granted through permits, and reviewed past incident data,
                specifically concerning information on equipment failure after a
                successful seal of the well.
                E. Stakeholder Engagement
                Implementation of the 2016 WCR--BSEE Qs and As
                 The Department promulgated the original ``Blowout Preventer Systems
                and Well Control'' final rule (WCR) (81 FR 25888, April 29, 2016).
                Subsequently, during the implementation of the regulations, BSEE
                received numerous questions from stakeholders seeking clarification and
                guidance concerning the 2016 WCR's provisions. The questions covered a
                vast array of issues and spanned multiple subparts of the regulations.
                 BSEE reviewed each question it received and decided whether the
                question presented an issue that was appropriate for Bureau guidance.
                To the extent that a question required guidance or clarification, BSEE
                provided a response to clarify any potentially confusing language. In
                addition to deciding on the appropriateness of a question for guidance,
                BSEE determined whether the question was of sufficient public interest
                to merit broader publication of a response. After finalizing regulatory
                guidance in response to a stakeholder's question, BSEE typically
                publishes both the question and BSEE's answer on its web page. The
                information, which reflects BSEE's guidance on the current regulations,
                may be found at: https://www.bsee.gov/guidance-and-regulations/regulations/well-control-rule. BSEE posted approximately 100 responses
                to questions regarding the 2016 WCR provisions on the web page.
                 BSEE reexamined the questions and answers pertaining to the 2016
                WCR.
                [[Page 21913]]
                After carefully considering all relevant information in the questions
                and answers, BSEE determined that it is appropriate to revise certain
                of the regulations promulgated through the 2016 WCR to support the
                goals of the regulatory reform initiative, while still maintaining
                safety and environmental protection. Additionally, the revisions will
                help clarify any ambiguity in the regulatory language, eliminate
                redundancies in the provisions, and align specific requirements more
                closely with relevant technical standards.
                 BSEE public forum on well control and blowout preventer rule: To
                ensure a complete and thorough review of the 2016 WCR, prior to this
                rulemaking, BSEE solicited input from interested parties to identify
                potential revisions to the regulations promulgated through the 2016 WCR
                that would reduce regulatory burdens while maintaining safety and
                environmental protection on the OCS. BSEE held a public forum on
                September 20, 2017, in Houston, Texas. More than 110 participants
                attended and provided comments and suggestions. Participants included
                representatives from:
                 Federal agencies;
                 Media;
                 Oil and gas companies;
                 Classification societies;
                 Trade associations;
                 Environmental groups; and
                 Equipment manufacturers.
                 Additionally, there were eight presentations made at the forum.
                These presentations are available at: https://www.bsee.gov/guidance-and-regulations/regulations/well-control-rule/public%20forum.
                II. Discussion of Compliance Dates for the Final Rule
                 BSEE considered the public comments on the proposed rule, as well
                as relevant information gained during, among other activities, BSEE's
                interactions with stakeholders, involvement in development of industry
                standards, and evaluation of current technology. Based on its analysis,
                BSEE is setting an effective date of 60 days following publication of
                the final rule, by which time operators will be required to comply with
                most of the final rule's provisions. BSEE determined, however, that it
                is appropriate to identify alternative compliance dates, subsequent to
                the effective date of the final rule, for certain provisions identified
                below. Detailed explanations for the requirements associated with these
                compliance dates are provided in Sections IV and V of this preamble.
                A. April 29, 2021--Alternative Cutting Device No Longer Allowed
                 Current regulations require, at Sec. 250.733(a)(1), that operators
                use an alternative cutting device capable of shearing any electric-,
                wire-, or slick-line before closing the BOP if, prior to April 29,
                2021, an operator's blind shear rams (BSR) are unable to cut such lines
                under maximum anticipated surface pressure (MASP) and seal the
                wellbore. After April 29, 2021, BSEE will no longer allow the use of an
                alternative cutting device, and the BSR in the surface stack will be
                required to shear any electric-, wire-, or slick-line under MASP and
                seal the wellbore. BSEE is aware that some current BSR technology is
                available to shear electric-, wire-, or slick-line. BSEE established
                this extended timeframe to allow operators to acquire and install
                equipment to meet the requirements and to discontinue the use of the
                alternative cutting device. Current regulations at Sec. 250.733(b)(1)
                require that new surface BOPs installed on floating production
                facilities after April 29, 2019, comply with the BOP requirements of
                Sec. 250.734(a)(1). This final rule extends that compliance date to
                April 29, 2021, in order to eliminate any confusion between applicable
                compliance dates for Sec. Sec. 250.733(b)(1) and 250.734(a)(1). The
                dual shear ram requirements for both surface and subsea BOPs will now
                have the same compliance date of April 29, 2021.
                B. May 1, 2023--Drill Pipe Positioning Within Shearing Blades
                 Current regulations at Sec. 250.734(a)(16)(i) require operators to
                have the capability to position the drill pipe completely within the
                area of the shearing blades during shearing operations no later than
                May 1, 2023. This final rule retains that compliance date from the 2016
                WCR.
                III. Discussion of Final Rule Requirements
                A. Summary of Key Regulatory Provisions
                 After review of all the public comments received in response to the
                proposed rule, BSEE determined that it will include the following
                proposed revisions in this final rule. This final rule includes most of
                the provisions in the proposed rule without change, although the final
                rule revises several of the proposed provisions in response to
                comments, as explained in sections IV and V of this preamble.
                 Documents incorporated by reference \6\--The final rule:
                ---------------------------------------------------------------------------
                 \6\ To view online read-only API documents visit: http://publications.api.org/AccessToDocuments.aspx.
                ---------------------------------------------------------------------------
                 Requires compliance with the industry standards contained
                in API Standard 53.
                 Requires compliance with API RP 17H to standardize ROV hot
                stab activities. This will allow certain functions of the BOP to be
                activated remotely and within specified timeframes.
                 Requires compliance with the cementing guidelines of API
                Standard 65--Part 2 to help achieve a successful cement job.
                 Requires compliance with ISO/IEC 17021-1, which provides
                requirements of an entity that certifies quality management systems for
                BOP stack manufacturing.
                 Requires compliance with API Bulletin 92L, which provides
                guidance regarding how to safely address lost circulation challenges.
                 Safe drilling practices--The final rule:
                 Requires operators to maintain safe drilling margins,
                provides details on when operators may request BSEE approval of the
                safe drilling margins, and specifies actions the operator must take if
                a safe drilling margin cannot be maintained.
                 Includes requirements related to downhole equipment that
                operators use to help reduce the likelihood of a major well-control
                event and ensure the overall integrity of the well.
                 Requires real-time monitoring when conducting well
                operations with a subsea BOP or with a surface BOP on a floating
                facility, or when operating in a high pressure high temperature (HPHT)
                environment. Also requires operators to develop and implement a real-
                time monitoring plan. This will allow operators to anticipate and
                identify issues in a timely manner and to utilize resources to assist
                in addressing critical issues.
                 Failure reporting and analysis--The final rule:
                 Requires that operators report any significant problems
                with BOP or well-control equipment to BSEE or BSEE's designated third
                party, so BSEE can help analyze failure trends and determine whether
                information should be provided, in a timely manner, to OCS operators
                and, if appropriate, to international offshore regulators and
                operators.
                 Requires that operators conduct an investigation and
                failure analysis within a designated timeframe to help ensure that the
                causes of failures are identified and addressed.
                [[Page 21914]]
                 Equipment requirements--The final rule:
                 Requires access to and utilization of well intervention
                equipment for certain subsea completed wells with a tree installed.
                This will allow the necessary equipment to be maintained and available
                to perform intervention operations when necessary.
                 Requires the BOP accumulator capacity to provide fast
                closure of the BOP components for autoshear/deadman in accordance with
                API Standard 53.
                 Operational requirements--The final rule:
                 Requires retesting protocols for when the BOP or lower
                marine riser package (LMRP) are unlatched and then relatched. These
                requirements provide clarity for the testing required when an operator
                returns to a well location and relatches the BOP or LMRP to the well.
                These tests help confirm that the BOP or LMRP is properly functional
                prior to resuming operations after being removed.
                 Requires high and low pressure testing procedures for
                certain BOP components. The testing requirements codify BSEE policy and
                provide clarity and consistency for permitting.
                 Requires the development of an alternate testing schedule
                for control stations and pods for subsea BOPs. The intended result of
                an alternating testing schedule is to ensure that operators can use
                each control station, and each pod for subsea, to properly function all
                required BOP components, while reducing unnecessary duplicative testing
                and risk of component wear.
                B. Summary of Significant Differences Between the Proposed and Final
                Rules
                 After consideration of all relevant and significant comments, BSEE
                made a number of revisions from the proposed rule to the final rule. We
                are highlighting several of these changes here because they are
                significant and because numerous comments addressed these topics.
                Discussions of the relevant and significant comments and BSEE's
                responses are found in sections IV and V of this preamble. The
                significant revisions made in response to comments include:
                1. Safe Drilling Margin--Sec. Sec. 250.414 and 250.427(b)
                 When drilling a well, operators use the hydrostatic pressure from a
                mud column to keep sufficient pressure on the formation to prevent gas
                or oil from flowing into the wellbore (i.e., a ``kick''). If the
                hydrostatic pressure from the mud column is too high, however, the
                formation may fracture and result in a significant number of
                operational issues, one of which is ``lost returns.'' Lost returns, or
                lost circulation, occur when drilling fluids escape from the well into
                the formation. A drilling margin is the difference between the pore
                pressure of the formation, with the mud weight taken into
                consideration, and the fracture pressure of the formation. The 2016 WCR
                established a default minimum drilling margin of 0.5 ppg, but also
                provided avenues for operators to obtain approval of lower margins
                through the permitting process (81 FR 25894). Since the effective date
                of the 2016 WCR, BSEE has approved many Applications for Permit to
                Drill (APDs) with a drilling margin less than 0.5 ppg.\7\ BSEE did not
                propose changes to the 0.5 ppg safe drilling margin requirements;
                however, BSEE solicited comments on possible revisions to, or options
                regarding, the 0.5 ppg drilling margin issue.
                ---------------------------------------------------------------------------
                 \7\ Between August 1, 2016 and March 22, 2018, ``BSEE's records
                show that there have been 305 wells drilled. Of those wells, BSEE
                approved operators' use of drilling margins that are less than 0.5
                ppg for 32 wells.'' 83 FR 22128, 22133 (May 11, 2018).
                ---------------------------------------------------------------------------
                 Multiple commenters recommended replacing the current requirement
                with a performance-based standard under which an approved safe drilling
                margin would be established on a case-by-case basis, based on data and
                analysis specific to a particular well. They suggested that this is a
                safer and better alternative that would provide a risk-based approach
                that ensures safety and provides investment certainty to the industry.
                Multiple commenters also submitted comments on Sec. 250.427 and
                recommended that, in instances where an operator encounters a lost
                circulation zone, the operator should have options for safely
                addressing the situation. In particular, many commenters asserted that
                suspending operations in certain circumstances may negatively impact
                safety and that drilling ahead to get through a lost circulation zone
                may be the safest option to restore the integrity of the well. For
                example, a commenter asserted that suspending drilling while in the
                weak zone to set casing (or otherwise remedy the situation) may simply
                transfer risk to a deeper hole section, where conditions may be even
                more challenging. Commenters suggested that it is appropriate for
                operators to specify in the Deepwater Operations Plan (DWOP) or APD how
                they will remedy an anticipated loss of circulation on bottom. They
                suggested using API Bulletin 92L as the standard for responding to such
                situations. A significant number of commenters also strongly opposed
                any changes to the 0.5 ppg drilling margin requirements in the current
                regulations.
                 In this final rule, BSEE is not revising the 0.5 ppg default
                drilling margin requirement or the requirements for justifying any
                alternative equivalent downhole mud weight. However, based on comments
                received, BSEE is revising Sec. 250.414(c)(2) to allow operators the
                option to submit the required justification for BSEE approval at an
                earlier date rather than waiting to submit with the APD. The proposed
                rule indicated that BSEE was considering ``whether it should adhere to
                its practice of identifying a specific drilling margin with an avenue
                for allowing operators to submit adequate documentation justifying the
                use of a different drilling margin . . . .'' (83 FR 22133). The
                relevant comments informed BSEE's decision to revise Sec.
                250.414(c)(2) to permit submission of the alternative drilling margin
                justification prior to submitting an APD. Also, based on comments
                received, BSEE is revising Sec. 250.427(b) to allow an operator to
                respond to lost circulation events in accordance with API Bulletin 92L
                and to require notification to the BSEE District Manager documenting
                the operator's use of API Bulletin 92L.\8\ In conjunction with the use
                of API Bulletin 92L, BSEE is requiring that an operator submit a
                revised permit documenting any remedial actions. BSEE is also
                clarifying that the District Manager must review and approve proposed
                remedial actions in an APD. BSEE recognizes that API Bulletin 92L may
                not be a consensus document. According to API policy,\9\ documents that
                are classified as ``bulletins'' may be developed without following a
                consensus process, which is the preferred process for documents
                incorporated by reference in government regulations according to the
                guidance in OMB Circular A-119. However, OMB Circular A-119 does not
                preclude the use of standards that are developed without following a
                voluntary consensus process. API Bulletin 92L addresses specific
                technical issues, such as lost circulation while drilling, to help
                operators diagnose well stability issues and remedy the situation. BSEE
                determined that this document is consistent with BSEE policy in the
                approaches used to
                [[Page 21915]]
                address these issues, appropriate for meeting the agency's regulatory
                needs, and preferable to an agency-developed standard. Therefore, API
                Bulletin 92L is appropriate for incorporation into the regulations,
                even though it is a non-consensus developed bulletin. BSEE has
                evaluated API Bulletin 92L and determined that compliance with it would
                not reduce safety. The content of the bulletin includes flow charts
                that can be used as an aid for operators to use in deciding how best to
                safely drill ahead when lost circulation occurs and the required
                criteria and procedures are met.
                ---------------------------------------------------------------------------
                 \8\ API Bulletin 92L provides operators with flow charts to help
                evaluate what is happening in the well during lost circulation
                events and to respond accordingly. (e.g., Depending on the situation
                operators may have to stop drilling and run casing, or contact the
                regulator and drill ahead no more than 300 ft.)
                 \9\ The Organization and Procedures for the CSOEM: Policy
                Document 2017 (S1) and the Procedures for Standards Development 2016
                (Procedures for Standards Development).
                ---------------------------------------------------------------------------
                2. Centering Capabilities While Shearing--Sec. Sec. 250.732 and
                250.734(a)(16)
                 Current regulations at Sec. Sec. 250.732 and 250.734 require the
                use of a shear ram positioning mechanism to ensure that pipe is
                centered within the area of the shearing blade. Since the publication
                of the 2016 WCR, many of the shear ram designs have improved the
                shearing capabilities to help ensure shearing is conducted on the
                appropriate shearing area of the shear blades. This is commonly done by
                shaping the shear ram cutting blades in a ``V'' or ``W'' pattern to
                help center the pipe as it shears, as well as to increase the blade
                face surface area to ensure there are no areas that cannot shear the
                pipe in the well. Accordingly, BSEE proposed to remove the centering
                mechanism requirements in both Sec. Sec. 250.732 and 250.734. However,
                in the proposed rule preamble, BSEE solicited comments about the
                effectiveness of requiring shear rams to center pipe or wire while
                shearing, or requiring shear rams to have the capability to shear any
                pipe or wire in the hole without a separate centering mechanism. BSEE
                also discussed the option of retaining the centering mechanism
                requirements, but expressly provided that the shear rams with these
                capabilities satisfy the requirements.
                 Based on comments, BSEE recognizes that the technology exists to
                help ensure the pipe is positioned within the shear surface to optimize
                shearing capabilities. BSEE agrees that even though this technology
                exists, the rule as proposed would not have specifically required the
                use of such technology. In this final rule, BSEE is now retaining the
                existing requirement to maintain the capability to position the pipe
                within the shearing blade, however BSEE will not require this to be
                achieved using a separate mechanism and will allow this capability to
                be accomplished with the shear ram itself. As encouraged by Congress
                \10\ to ensure that offshore operations promote safety and protect the
                environment in a technically feasible manner, BSEE does not want to
                limit the use of improved technological advancements in shear blade
                designs.
                ---------------------------------------------------------------------------
                 \10\ Explanatory Statement to Accompany Div G. of Consolidated
                Appropriations Act, 2017 (Interior, Environment, and Related
                Agencies), Public Law 115-31 (May 5, 2017). (``Blowout Preventer
                Systems and Well Control Rule.--The Committees encourage the Bureau
                to evaluate information learned from additional stakeholder input
                and ongoing technical conversations to inform implementation of this
                rule. To the extent additional information warrants revisions to the
                rule that require public notice and comment, the Bureau is
                encouraged to follow that process to ensure that offshore operations
                promote safety and protect the environment in a technically feasible
                manner.''). 163 Cong. Rec. H 3327, 3880 (May 3, 2017).
                ---------------------------------------------------------------------------
                3. Shearing Combinations--Sec. 250.734(a)(1)(ii)
                 In the 2016 WCR, BSEE established that both shear rams must have
                the capability to shear the specified equipment. During the development
                of the 2016 WCR, BSEE did not receive comments specific to the ``both
                shear rams'' provision.
                 BSEE proposed to revise Sec. 250.734(a)(1)(ii) by clarifying that
                a ``combination of the'' shear rams must be capable of shearing all the
                items specified in the paragraph. BSEE is aware that certain casing
                shears still have difficulty shearing electric-, wire-, or slick-line,
                while certain BSRs have difficulties shearing larger casing sizes. As
                stated in the proposed rule, the proposed revision would have provided
                the operators flexibility for how they utilize the BOP system and
                components for operations, while still ensuring all critical shearing
                capabilities.
                 Multiple commenters generally agreed with the proposed language;
                however, other commenters opposed any changes to existing requirements.
                Commenters expressed concerns about the proposed removal of the
                requirement to have two fully redundant shear rams and suggested that
                such a change would not account for the possibility of one shear ram
                malfunctioning. The benefit of having two, fully capable shear rams is
                a fully redundant back up. Under the proposed revisions, if one shear
                ram were to fail and the remaining shear ram could not independently
                shear the necessary equipment, well control might not have been
                achieved.
                 Based on comments received, BSEE is keeping the language in
                existing Sec. 250.734(a)(1)(ii) that requires ``both shear rams to be
                capable of shearing'' the specified equipment in the hole. BSEE
                principally bases this decision on comments BSEE received concerning
                the importance of shearing redundancy and a recognition that the
                proposed language's reliance on a ``combination'' of shear rams
                potentially interjected some ambiguity regarding the number of rams
                subject to this shearing requirement.
                 BSEE is not revising the dual shear ram requirements or the
                associated compliance date of April 29, 2021, found in existing Sec.
                250.734(a)(1).
                4. Subsea Accumulator Capacity--Sec. 250.734(a)(3)(iii)
                 The purpose of the accumulator system and applicable accumulator
                capacity requirements is to ensure that there is sufficient volume and
                pressure in the accumulator bottles to properly operate BOP components
                in a specified timeframe regardless of the location of the accumulator
                bottles.
                 In the proposed rule, BSEE proposed to remove the reference to the
                subsea location of the accumulator capacity. BSEE understands that the
                accumulator system works together with the surface and subsea
                accumulator capacity to achieve full functionality and BSEE determined
                that it was unnecessary to specifically identify only subsea
                requirements when API Standard 53 covers the entire system.
                 BSEE received multiple comments supporting the proposed revisions;
                however, BSEE also received comments asserting that BSEE had not
                explained how removing the reference to the subsea location of
                accumulator capacity would ensure that the accumulator system can
                adequately function if there is a loss of the power fluid connection to
                the surface. Based on these comments, BSEE has decided to keep the
                clarification that certain accumulator capacity must be located subsea
                in order to avoid confusion about how the autoshear and deadman systems
                utilize accumulator capacity. The autoshear and deadman systems do not
                use accumulator capacity from the surface accumulators. The conditions
                to function these emergency systems involve the loss of electrical/
                hydraulic communication or connection between the BOP stack and the
                rig. Therefore, it is necessary to require that the autoshear and
                deadman emergency systems' accumulator capacity must be able to
                function properly without connection or communication with the surface
                and therefore the accumulator capacity must be located subsea.
                 In this final rule, BSEE is clarifying that the accumulator bottles
                for the autoshear/deadman systems need to be located subsea. The
                autoshear/deadman systems are not controlled by surface personnel and
                are essentially considered failsafe. Consistent with the
                [[Page 21916]]
                existing regulations, the accumulator bottles that operate these
                systems need to be located subsea to ensure there is enough fluid and
                pressure to operate the associated functions. This is a clarification
                to ensure there is no confusion about where the required fluid and
                pressure must reside to operate the autoshear/deadman emergency
                functions.
                5. 21-Day BOP Testing Frequency--Sec. 250.737
                 In the proposed rule, BSEE requested comments on whether the BOP
                testing interval should be 7 days, 14 days, or 21 days for all
                operations (i.e., drilling, completions, workovers, and
                decommissioning). BSEE also requested comments on the specific cost and
                operational implications of each testing interval to further its
                consideration of the issue. Current regulations (multiple citations
                throughout Sec. 250.737) require pressure and function testing of
                specific BOP components for drilling, completions, workovers, and
                decommissioning operations every 14 days. Although BSEE did not present
                revisions to the testing frequency regulatory text in the proposed
                rule, BSEE raised the option of 21-day BOP testing in the preamble.
                 The industry and BSEE currently rely on function and hydrostatic
                tests to verify the performance of BOP equipment in the field. These
                tests have traditionally been the primary method of verifying the
                capability of in-service equipment. In recent years, the industry has
                raised concerns related to the benefits of pressure and function
                testing of subsea BOPs when compared to the costs and potential
                operational issues associated with such testing, including wear and
                tear.
                 BSEE received multiple comments supporting a 21-day BOP testing
                frequency. These comments provided some data to justify a 21-day BOP
                testing frequency. However, BSEE also received many comments opposing
                any changes to the BOP testing frequency and a commenter even stated
                that the BOP testing frequency should be increased to every 7 days.
                 BSEE analyzed the justifications provided in the 2016 WCR for the
                decision to adopt a 14-day rather than a 21-day testing frequency. The
                relevant analysis offered little by way of data-driven conclusions, so
                BSEE has, through this rulemaking, undertaken a thorough analysis of
                the information available. In the final rule, based on comments
                received, BSEE is revising Sec. 250.737 to allow the use of a 21-day
                BOP testing frequency if an operator meets certain criteria and if BSEE
                approves an operator's 21-day BOP testing frequency request. BSEE is
                requiring operators to demonstrate, in the 21-day BOP testing frequency
                request, that they have developed a BOP health monitoring plan that
                includes certain system capabilities. BSEE is requiring the BOP health
                monitoring plan to include condition monitoring tools that are able to
                provide continuous surveillance of sensor readings from the BOP control
                system, real-time condition analysis and displays, functional pressure
                signal analysis, and trending capabilities of the sensor data. The
                condition monitoring tools also must include failure propagation
                analysis and a failure tracking and resolution system to identify
                recurring problems. BSEE is also requiring operators to submit
                quarterly reports of the data collected to the BSEE Regional
                Supervisor, District Field Operations. BSEE will review this data to
                help ensure compliance with the requirements of the regulations and
                help support its continual analysis of the 21-day BOP testing
                frequency.
                 This approach offers a path for operators to avoid the identified
                cost and operational concerns associated with more frequent testing,
                while at the same time requiring that adequate and proven tools for
                ensuring safety and environmental protection are in place before
                testing frequency is changed to a 21-day interval.
                IV. Discussion of Public Comments on the Proposed Rule
                 In response to the proposed rule, BSEE received over 265 sets of
                comments containing individually submitted comments and multiple
                similar group form letters, totaling over 118,000 submittals. Comments
                included submittals from individual entities (e.g., companies, industry
                organizations, non-governmental organizations, State governments, and
                private citizens). Some entities submitted comments multiple times and
                a majority of the individual commenters submitted nearly identical
                comments (similar to a form letter). Over 117,000 of the comments
                submitted follow a type of form letter and contain similar comments.
                All relevant comments are posted at the Federal eRulemaking portal:
                http://www.regulations.gov. To access the comments at that website,
                enter BSEE-2018-0002 in the Search box. BSEE reviewed all comments
                submitted, and this section and section V of this preamble contain
                brief summaries of the relevant comments as well as of BSEE's
                responses.
                A. General Support for the Proposed Rule
                 BSEE received hundreds of comments expressing general support for
                the proposed rule. The public comments expressing or suggesting general
                support for the proposed rule as a whole or for some of its major
                provisions comprise a few hundred of the total number of comments
                received. BSEE received supporting comments from, but not limited to,
                oil and gas companies, contractors, industry trade groups, equipment
                manufacturers, class societies, private citizens, and legal firms. Some
                of the commenters expressing general support for the proposed rule also
                provided specific detailed comments, addressed further infra.
                 The comments submitted by industry trade groups, operators, and
                service companies generally supported the proposed alleviation of
                administrative burdens and reduction of prescriptive regulations. As
                rationale for their support of the proposed rule, those commenters
                often identified concerns about how the current regulations increase
                operational risks and impose unnecessary cost burdens but provide no
                commensurate safety improvements or environmental protection. However,
                while the commenters voiced support broadly for the proposed changes,
                some of them also cited additional regulatory provisions that they
                asserted impose unnecessary regulatory burdens that the proposed
                revisions would not go far enough to relieve, as discussed in this
                section and section V of this preamble.
                B. General Opposition to the Proposed Rule
                 A majority of entities and individuals that commented on the
                proposed revisions expressed general opposition to the proposed rule
                and many of its major proposals. A majority of those comments were
                submitted by non-governmental organizations, environmental groups,
                multiple State Attorneys General, lawmakers from the U.S. House of
                Representatives and U.S. Senate, public, and academia.
                 A large majority of the approximately 118,000 comments that BSEE
                received voiced significant concerns about the proposed changes. The
                rationale for the commenters' opposition to the proposed revisions to
                the existing regulations generally fell into two main categories.
                First, many commenters asserted that BSEE does not have sufficient
                evidence to support many of the proposed revisions to the existing
                regulations. However, many of the commenters did not provide additional
                information/data
                [[Page 21917]]
                to support assertions. Comments in this first group highlighted the
                fact that BSEE adopted the WCR in 2016 and thus asserted that it has
                not had enough time to gather the data necessary to support any
                changes.
                 Second, some commenters cited the findings from the investigations
                and reports arising out of Deepwater Horizon to support their general
                contention that oversight of the oil and gas industry in the form of
                regulations is vitally important and necessary. Among these comments,
                opposition to the proposed rule was apparently premised on the belief
                that any ``rollback'' of the existing regulations will adversely impact
                safety and environmental protection.
                 For a discussion of the substantive comments in opposition to
                specific provisions and BSEE's responses, refer to later parts of this
                section and Section V of this preamble.
                C. 21-Day BOP Testing Frequency
                 In the proposed rule, BSEE did not propose any specific regulatory
                text changes to the existing requirement for the minimum 14-day testing
                frequency for BOP systems. However, BSEE solicited comments in the
                proposed rule on whether the BOP testing frequency should be 7 days, 14
                days, or 21 days for all types of operations. BSEE also requested
                comments on the adequacy of the current function and pressure test
                requirements for BOP systems in predicting the performance of this
                equipment in subsequent drilling operations. Furthermore, BSEE
                requested comments about what circumstances or environments might
                justify an increase or decrease to the required testing frequency.
                 In addition, BSEE is aware of potential technologies that may
                improve the operability and reliability of BOP systems and thus may
                affect the need for and appropriate frequency of BOP testing.
                Accordingly, BSEE also solicited comments on whether there are
                additional technologies, processes, or procedures that can be used to
                supplement existing requirements and provide additional assurances
                related to the performance of this equipment. BSEE asked commenters to
                provide justifications and data to support their comments.
                Summary of Comments--21-Day BOP Testing Frequency
                 BSEE received comments both supporting a 21-day BOP testing
                frequency and opposing such a change. Numerous commenters proposed
                aligning the regulatory requirement for BOP testing frequency with the
                21-day testing frequency found in API Standard 53; some of those
                commenters cited the fact that Texas regulations for onshore operations
                have successfully used 21-day testing for many years. These commenters
                cited studies indicating that a 21-day testing frequency: Provides for
                a safe and reliable BOP system; aligns with global practices and
                technological capabilities; and prevents extensive pressure testing
                that can cause premature system wear. Some commenters also asserted
                that function tests provide more reliable indications of BOP
                performance. Commenters also suggested a pilot program that would
                implement 21-day testing to gather data to assess the difference in BOP
                performance between 14 and 21-day testing frequency. Another commenter
                provided some data comparing the results of 14-day and 21-day BOP
                testing worldwide. Another commenter suggested that a 21-day testing
                interval is appropriate if there are tools, systems, and data
                collection to ensure that the 21-day testing keeps operational risk and
                process safety performance equivalent to the 14-day testing interval.
                 Commenters who did not support the change to the 21-day testing
                frequency noted that BSEE considered a 21-day BOP testing interval in
                the context of the 2016 WCR, but rejected that testing interval because
                the agency did not receive data to support it. The commenters further
                asserted that BSEE is again proposing a 21-day BOP testing interval,
                despite not having any new data to support the change. Another
                commenter proposed a 7-day interval for BOP testing, along with a
                recommendation that BSEE undertake a technical risk analysis of BOP
                failure rates for 7-, 14-, and 21-day BOP test intervals. One commenter
                suggested that BSEE postpone a revision to the BOP testing frequency
                and solicit input from an advisory committee regarding what a
                reasonable and prudent standard should be. A commenter requested that
                BSEE show the impact of the proposed change on all system risks and
                asserted that BSEE should not rely on industry comments as a basis for
                the change.
                 Response: After considering all comments regarding this
                potential change, BSEE agrees with many of the commenters'
                recommendations to allow a 21-day test frequency, under limited
                circumstances when an operator meets appropriate qualifications.
                Therefore, BSEE is revising Sec. 250.737 in the final rule to maintain
                the 14-day test frequency as the default requirement, but to allow
                operators to request special approval to use a 21-day BOP testing
                frequency in lieu of a 14-day BOP testing frequency if the operator
                meets certain criteria and receives BSEE approval. To address the
                concerns raised by commenters regarding the availability of data that
                demonstrates the impact on reliability due to testing frequency, the
                final rule requires any operator seeking to change testing frequency to
                develop a BOP health monitoring plan that includes condition monitoring
                tools that provide continuous surveillance of sensor readings from the
                BOP control system, real-time condition analysis and displays,
                functional pressure signal analysis, and trending capabilities of the
                sensor data. The condition monitoring tools also must include failure
                propagation analysis and a failure tracking and resolution system to
                identify recurring problems. BSEE is also requiring operators to submit
                quarterly reports of the data collected to the BSEE Regional
                Supervisor, District Field Operations. The BOP health monitoring plan
                will provide BSEE with relevant data on how the BOP equipment operates
                throughout the equipment lifecycle and additional assurance of the
                successful functioning and oversight of the BOP equipment. BSEE will
                review this data to help ensure compliance with the requirements of the
                regulations and help support its continual analysis of the 21-day
                testing frequency.
                 These efforts are consistent with BSEE's implementation of E.O.s
                13783 and 13795, congressional guidance, and Secretary's Order No. 3350
                (described in Section I.D above).
                 BSEE analyzed the justifications provided in the 2016 WCR for the
                decision to adopt a 14-day rather than a 21-day testing frequency,
                which offered little by way of data-driven conclusions. Following
                closure of the comment period, BSEE undertook a thorough review of
                available data, existing regulations, and all comments related to the
                evaluation of 7-, 14-, and 21-day BOP testing interval requirements. As
                part of its analysis, BSEE considered the BOP equipment failure
                reporting data captured in the U.S. Department of Transportation Bureau
                of Transportation Statistics (BTS) 2017 SafeOCS report titled Blowout
                Prevention Safety System--2017 Annual Report.\11\ The report analyzed
                1129 events and found that there were 1044 notifications for subsea
                BOPs and 85 notifications for surface BOPs. Of the total events, 946
                reported events were found while the BOPs were not in operation. That
                report observes on page 28 that ``[w]ear and tear was the most
                frequently reported root cause of
                [[Page 21918]]
                failures (53.6 percent).'' This data helps BSEE establish a baseline of
                operating events for the 14-day BOP testing frequency. That report also
                indicates that various forms of monitoring were responsible for
                detecting at least as many reported ``in-operation'' BOP equipment
                failures as the equipment failures detected through additional testing
                during 2017. These data suggest that monitoring plays an important role
                in the detection of BOP equipment failures, in conjunction with regular
                testing. Health monitoring systems allow operators to detect and
                remediate potential failures before they occur, and to understand
                potential failures and their impact on overall BOP system reliability,
                potentially contributing to downward failure trends. Accordingly, BSEE
                determined that operators who desire to reduce the frequency of their
                regular testing should be required to adopt more robust BOP health
                monitoring capabilities to ensure that oversight of BOP operability is
                not compromised. Adopting a 21-day testing frequency would align BSEE
                requirements with the BOP testing provisions of API Standard 53 that
                are widely utilized and accepted internationally. A 21-day testing
                frequency would also align with widely adopted BOP testing standards
                followed by the international offshore oil and gas industry. BSEE
                contacted many international regulators \12\ responsible for overseeing
                offshore operations and requested information on whether those
                regulators allow the use of a 21-day BOP testing frequency. BSEE was
                informed that, among others, Brazil, Denmark, the United Kingdom,\13\
                and the Netherlands allow a 21-day BOP testing frequency. BSEE
                recognizes the successful international use of the 21-day testing
                frequency and relied, in part, on that experience to support its
                decision that a 21-day testing frequency may be appropriate for OCS
                operations under certain conditions.
                ---------------------------------------------------------------------------
                 \11\ https://www.safeocs.gov/2017_WCR_Annual_Report_v4.pdf.
                 \12\ Canada-Nova Scotia Offshore Petroleum Board (CNSOPB),
                Canada-Newfoundland and Labrador Offshore Petroleum Board, Danish
                Offshore Oil and Gas, United Kingdom, Brazil ANP (National Agency of
                Petroleum, Natural Gas and Biofuels), Norway PSA (Petroleum Safety
                Authority), and Australia National Offshore Petroleum Safety and
                Environmental Management Authority.
                 \13\ http://www.hse.gov.uk/offshore/ed-well-control.pdf.
                ---------------------------------------------------------------------------
                 BSEE also requires additional specified function testing of certain
                BOP components. For example, existing Sec. 250.737(d)(9) requires BOP
                function testing of annular and pipe/variable bore rams every 7 days.
                This function testing would continue to confirm important aspects of
                BOP functionality at more frequent intervals if pressure testing is
                conducted at a 21-day frequency.
                 In addition, one commenter submitted an analysis of field pressure
                testing data across two rigs with similar BOP equipment--one subject to
                14-day testing under requirements applicable in the Gulf of Mexico and
                the other on a 21-day testing cycle overseas. The commenter's analysis
                indicates that no reduction in BOP reliability was found in connection
                with the international 21-day testing standards. BSEE reviewed the
                commenter's data and agrees that the commenter's analysis demonstrates
                successful use of 21-day BOP testing.
                Summary of Comments--21-Day BOP Testing Frequency in the Economic and
                Environmental Analyses
                 Multiple commenters questioned the validity of BSEE's cost and
                environmental analyses and asserted that BSEE did not provide any
                concrete data or analysis to support a change to the BOP testing
                frequency in the regulations.
                 Response: BSEE disagrees with the commenters' assertion
                that the draft economic and environmental analyses released with the
                proposed rule were invalid. BSEE reviewed all relevant comments related
                to these analyses and updated or revised them, as appropriate, for the
                final rule (see discussions of the 21-day testing provisions in the
                environmental assessment and Regulatory Impact Analysis).
                D. BSEE Approved Verification Organization (BAVO)
                 The 2016 WCR established criteria and associated requirements
                related to the use of BAVOs. Pursuant to the regulations promulgated
                through the 2016 WCR, a BAVO is an entity that submits qualifications
                to BSEE and receives BSEE approval in order to perform certain
                independent engineering reviews and provides reasonable assurances that
                certain equipment would perform as designed under the operating
                conditions relevant to the particular well where the equipment will be
                used. The 2016 WCR regulations at Sec. Sec. 250.731, 250.732, 250.734,
                250.738, and 250.739 covered BAVO requirements. The 2016 WCR
                established that the BAVO requirements would not take effect until one
                year after BSEE published a list of BAVOs. BSEE has not yet published a
                BAVO list; accordingly, the BAVO requirements are not currently
                effective. However, the 2016 WCR also required that operators use
                independent third-parties to perform certain of the certifications,
                verifications, and reporting functions pending implementation of the
                BAVO requirements.
                 In the proposed rule, BSEE proposed to remove all references to
                BAVOs and to replace them with references to an independent third party
                in Sec. Sec. 250.731, 250.732, 250.734, 250.738, and 250.739. BSEE
                received many comments supporting these proposed changes. This section
                includes a summary of the general BAVO-related comments and BSEE
                responses. For additional discussions of comments associated with BAVO-
                specific provisions and BSEE responses, refer to section V of this
                final rule preamble.
                 Summary of comments: Multiple commenters expressed concerns that
                changing BAVO requirements in the new rule would negatively affect
                safety and accountability. Multiple comments requested keeping the
                requirement for BSEE to certify BAVOs, as described in the 2016 WCR.
                Those commenters desired assurance that the third-party will be well-
                qualified for the extremely important work that is required, which
                includes verifying and documenting the proper functioning of the BOP. A
                commenter requested that BSEE explain how it will ensure that third-
                party reviewers are truly independent, qualified, and consistent in
                their execution of inspections and establish a process to evaluate the
                independent third parties. Another commenter recommended that BSEE not
                surrender the authority to approve the third-party organizations. A
                different commenter asserted that BSEE cannot avoid the
                responsibilities it has to ensure drilling safety by allowing
                inspections by organizations that may not have the expertise or
                capacity to determine whether blowout preventers are being correctly
                operated and maintained. Another commenter asserted that this change
                would reduce oversight, suggesting that if BSEE does not have a role in
                approving the inspectors, the operators would be able to choose who
                inspects their BOPs, and that such inspectors would not even be
                required to be present during inspection. One commenter asserted that
                reports prepared by a third-party that is not present during the actual
                inspection would be of minimal value and be too late to affect real
                change/improvement.
                 Response: BSEE does agree that the independent third-
                parties need to be qualified to perform the required work. The
                independent third-party must have the qualifications listed under Sec.
                250.732(b), which requires the independent third-party to be a
                technical classification society, or a licensed professional
                engineering firm, or a registered professional engineer
                [[Page 21919]]
                capable of providing the required certifications and verifications. As
                BSEE described in the preambles to the 2016 WCR and the proposed rule,
                BSEE expected most of the companies or individuals that would be
                approved as BAVOs to be drawn from the group currently being used as
                independent third-parties. BSEE determined that, under these
                circumstances, submittal to become a BAVO would be unnecessary and
                would not provide significant meaningful improvements to safety or
                environmental protection. BSEE has increased its interaction with the
                independent third-parties to better understand how they operate and
                carry out certifications and verifications. For example, BSEE engineers
                and inspectors are regularly on a rig or at a testing facility
                concurrently with independent third-parties during BOP testing. BSEE
                utilizes these opportunities to observe the independent third-parties
                and discuss the required verifications for the associated operations
                with them. If BSEE becomes aware of any concerns with the required
                independent third-party certifications or verifications, there are
                still options for BSEE to address the issues through the operator
                (e.g., verifications through the permitting process).
                 BSEE disagrees with the assertions that BSEE is surrendering
                authority to approve third parties, that BSEE is avoiding
                responsibilities for ensuring safety, or that the changes reduce
                oversight. The regulatory revision that eliminates the BAVO process
                will continue to meet the objectives BSEE stated in 2015: ``The
                objective is to have this equipment monitored during its entire
                lifecycle by an independent third-party to verify compliance with BSEE
                requirements, OEM recommendations, and recognized engineering
                practices. The BSEE believes that the importance and complexity of BOP
                systems and the fact that they might be operated at various worldwide
                locations throughout their service life warrants a thorough and regular
                assessment of the systems and verification that design, installation,
                maintenance, inspection, and repair activities are documented and
                traceable.'' (Proposed WCR, 80 FR 21504).
                 Although the regulations allow operators to select the independent
                third party who performs the inspection, there are multiple paths by
                which BSEE can directly verify the adequacy of independent third party
                performance. For example, BSEE will continue to review the
                verifications and certifications submitted by independent third parties
                and confirm that they provide a sufficient level of detail to ensure
                compliance with the regulations. Since 2015, BSEE has consistently
                articulated the importance of independent third-party verification and
                documentation. This regulatory amendment does not eliminate or reduce
                the role of such verification and documentation. While the regulations
                do not require the independent third party to be present at the major
                inspections, they require the independent third party to review the
                documentation of the inspections to help ensure that the appropriate
                entities accurately and appropriately complete the inspection and
                maintenance. The independent third party document review also allows
                the comparison of the design data to the current status of the
                equipment. The intent of the major inspection is to verify that the
                well control system components are fit for service and within design
                tolerances to be utilized for specific well conditions, which can be
                verified through a data review and does not require a physical
                presence.
                 Summary of comments: Commenters suggested that BSEE should take
                steps to ensure that any third-party is acting in good faith before it
                verifies rig safety measures and that BSEE should provide additional
                explanation and justification to support the proposed change.
                 Response: BSEE agrees with the commenters that the
                independent third-parties must act in good faith and be capable and
                competent when conducting the required verifications and
                certifications. The qualification requirements set forth in final Sec.
                250.732(b) are designed, in part, to ensure such professional
                standards. If BSEE becomes aware of any concerns with certifications or
                verifications that are performed by an independent third-party as
                required by the regulations, BSEE retains options to address these
                potential issues through its regulation of the operator (e.g.,
                verifications through the permitting process).
                 Summary of comments: A commenter asserted that the proposed
                definition of independent third-party is too broad and would allow
                organizations or individuals to perform verification activities without
                having the proper expertise. The commenter recommends retaining and
                applying the current BAVO requirements found in previous Sec.
                250.732(a)(3)(i) through (vi) to potential independent third-parties.
                 Response: BSEE disagrees with the commenter's suggestion
                to include the identified BAVO requirements in this final rule. Final
                Sec. 250.732 paragraph (b) references the independent third party
                qualifications. The existing regulations do not require a BAVO to be a
                technical classification society, a licensed professional engineering
                firm, or a registered professional engineer capable of performing the
                required actions; however, for an individual or company to become an
                independent third-party that performs the required certifications and
                verification under this final rule, it must continue to meet the
                qualifications currently set forth in Sec. 250.732(a)(2) and being
                retained in the final rule at Sec. 250.732(b). These standards ensure
                a level of professional competence and independence comparable to that
                required of BAVOs in the existing regulations.
                E. Legal Comments
                General Comments on Legal Aspects of the Rulemaking Process
                 Summary of comments: BSEE received a number of comments regarding
                the rulemaking process. Some commenters raised specific concerns about
                the process. For example, a commenter asserted that BSEE engaged in an
                inadequate information-gathering process. Several others claimed the
                public comment period was too short, and did not involve enough
                participation from stakeholders. Other commenters expressed support for
                the rulemaking process, asserting that this rule would address
                perceived deficits in the previous rule.
                 Response: BSEE disagrees with the assertion that the
                bureau provided an unreasonably short public comment and that BSEE
                engaged in an inadequate information gathering process. As previously
                discussed, BSEE held a public forum on September 20, 2017, in Houston,
                Texas, prior to initiating the rulemaking process, to solicit input on
                the development of the proposed rule. In addition, BSEE accepted
                comments through a ``Request for comments'' on the Department of the
                Interior's regulatory reform initiatives, published in the Federal
                Register on June 22, 2017 (82 FR 28429), with no deadline for comments.
                BSEE received 19 comments relevant to this rulemaking from interested
                parties as a result of this request for comments. BSEE published the
                proposed rule with a 60-day comment period that was scheduled to close
                on July 10, 2018, and extended that comment period by 27 days to August
                6, 2018. BSEE determined that this 87 day comment period on the
                proposed rule was reasonably sufficient because it afforded interested
                parties a meaningful opportunity to participate in the rulemaking
                process.
                [[Page 21920]]
                Compliance With the Administrative Procedure Act (APA)
                 Summary of comments: A commenter asserted that if BSEE chooses to
                publish a final rule, then it must first provide analysis and data upon
                which the proposed rule is based, in compliance with the fair notice
                requirements of the Administrative Procedure Act (APA), asserting that
                the APA requires BSEE to provide specific revisions with data and
                analysis supporting those proposals and to request further public
                comments on those specific proposed revisions, rather than simply ask
                for comments on a broad range of topics. The commenter asserted that
                there are several places in the proposed rule where BSEE solicits
                comments for amending certain existing provisions but provides no
                specific plans for how it intends to amend those provisions and
                asserted that without a defined course of action, the public cannot
                intelligently critique the proposed rule. The commenter asserted that
                BSEE did not include the analysis or data on which other proposed
                revisions are based, thus precluding meaningful public criticism.
                 Response: BSEE disagrees. The APA's notice and comment
                provision (5 U.S.C. 553(b)) requires that an agency test its regulation
                through exposure to diverse public comment and give affected parties an
                opportunity to develop evidence in the record to support their
                positions regarding the rulemaking, thereby enhancing the quality of
                agency decisionmaking.\14\ As evidenced by BSEE's receipt of diverse,
                extensive public comments, the proposed rule fairly apprised interested
                parties about the rule's detailed subjects and the range of
                alternatives the bureau was considering. BSEE's evaluation of the
                comments it received permitted the bureau to test these final
                regulatory provisions. Through this rulemaking process, BSEE provided
                ample and adequate notice of the potential for each regulatory change
                implemented through this final rule and ensured that the rulemaking
                record included adequate justification for each such change.
                ---------------------------------------------------------------------------
                 \14\ Prometheus Radio Project v. F.C.C., 652 F.3d 431, 449 (3d
                Cir. 2011), certiorari denied 567 U.S. 951 (2012).
                ---------------------------------------------------------------------------
                 With regard to revisions to the BOP system testing requirements,
                BSEE solicited comments in the proposed rule ``on whether the BOP
                testing interval should be 7 days, 14 days, or 21 days for all types of
                operations including drilling, completions, workovers, and
                decommissioning,'' as well as comments ``on the specific cost and
                operational implications of each testing interval.'' \15\ Contrary to
                the commenter's assertion, BSEE specifically discussed industry's and
                BSEE's current reliance on function and hydrostatic tests and
                industry's concerns ``related to the benefits of pressure and
                functional testing of subsea BOPs when compared to the costs and
                potential operational issues.'' \16\ BSEE requested comments on these
                specific tests and intervals, including ``[u]nder what circumstances or
                environments . . . the testing frequency [should] be increased or
                decreased,'' and what ``technologies, processes, or procedures can be
                used to supplement existing requirements and provide additional
                assurances related to the performance of this equipment.'' BSEE did not
                propose the regulatory text adopted in the final rule regarding BOP
                testing frequency. However, BSEE discussed all of the final rule
                elements in the proposed rule, and a reasonable commenter could have
                anticipated the adopted changes and the text of the final rule BOP
                testing frequency provisions was a logical outgrowth of the proposed
                rule. BSEE specifically requested comments on whether the BOP testing
                interval should be 21 days for all types of operations, including
                associated costs and operational considerations, and highlighted
                questions surrounding the benefits of current testing requirements
                compared to known concerns. 83 FR 22143. BSEE specifically requested
                comments on circumstances in which testing frequency might be decreased
                and alternative approaches to ensuring the operability and reliability
                of BOP systems. Id. BSEE derived the final regulatory changes from
                comments received pursuant to the solicitations in the proposed rule.
                The final rule's BOP testing interval constitutes a logical outgrowth
                from the proposed rule because interested parties should have
                anticipated that this change was possible and, in fact, filed relevant
                comments.\17\
                ---------------------------------------------------------------------------
                 \15\ 83 FR 22143 (May 11, 2018).
                 \16\ Ibid.
                 \17\ ``A rule is deemed a logical outgrowth if interested
                parties `should have anticipated' that the change was possible, and
                thus reasonably should have filed their comments on the subject
                during the notice-and-comment period.'' NE Maryland Waste Disposal
                Auth. v. E.P.A., 358 F.3d 936, 952 (D.C. Cir. 2004) (internal cites
                omitted). See also, CSX Transp., Inc. v. Surface Transp. Bd., 584
                F.3d 1076, 1081 (D.C. Cir. 2009) (``[A] final rule represents a
                logical outgrowth where the NPRM expressly asked for comments on a
                particular issue or otherwise made clear that the agency was
                contemplating a particular change.'').
                ---------------------------------------------------------------------------
                Enforcement of Compliance With Documents Incorporated by Reference
                 Summary of comments: A number of commenters asserted that, by
                relying on incorporation by reference of industry standards, the
                proposed rule would allow the oil and gas industry to regulate itself
                without government oversight.
                 Response: BSEE disagrees. As discussed elsewhere in this
                final rule, BSEE incorporates technical standards by reference in
                accordance with the requirements of the National Technology Transfer
                and Advancement Act (NTTAA) \18\ and implementing Office of Management
                and Budget (OMB) guidance, the Office of the Federal Register (OFR)
                regulations (1 CFR part 51), and BSEE's own procedures for
                incorporation (Sec. 250.115, What are the procedures for, and effects
                of, incorporation of documents by reference in this part?). These
                processes include thorough evaluation of the pertinent standards for
                appropriateness and adequacy as regulatory requirements. The effect of
                incorporation by reference of an industry standard into the regulations
                is that the incorporated document becomes a regulatory requirement, see
                Sec. 250.115(c), and, thus, becomes subject to BSEE oversight and
                enforcement in the same manner as other regulatory requirements. BSEE
                incorporates standards developed by SDOs with a preference for those
                standards that are developed using a consensus process. Furthermore,
                BSEE may incorporate portions of SDO standards, limit their
                applicability to specified sections of BSEE's regulations, and impose
                other limitations such as providing that where a provision of an
                incorporated standard conflicts with BSEE regulatory provisions, those
                regulatory provisions prevail. If an SDO later revises a standard that
                BSEE has previously incorporated in a final rule, BSEE would need to
                evaluate the revised standard before incorporating it through
                rulemaking in the regulations; in other words, industry itself cannot
                change the regulatory requirements by revising a standard after that
                standard is incorporated in BSEE's regulations. Nor is industry
                authorized to oversee or enforce compliance with standards once
                incorporated into regulation. Once incorporated, BSEE enforces these
                standards as any other regulatory requirement.
                ---------------------------------------------------------------------------
                 \18\ National Technology Transfer and Advancement Act, 15 U.S.C.
                370 et seq.
                ---------------------------------------------------------------------------
                Correcting Issues From the 2016 Rulemaking Process
                 Summary of comments: A commenter asserted that this proposed rule
                corrected a failure in the 2016 WCR to provide a Statement of Energy
                Effects, as required by E.O. 13211. According to
                [[Page 21921]]
                the commenter, E.O. 13211 required BSEE to publish for public comment a
                detailed statement relating to (1) ``any adverse effects on energy
                supply'' and (2) ``reasonable alternatives to the action.'' A commenter
                claimed that the proposed rule makes adjustments to the 2016 rule to
                provide ``economically feasible'' regulations as required by OCSLA.\19\
                A commenter asserted that a detailed evaluation of ``reasonable
                alternatives'' to the 2016 WCR ``would necessarily have included use of
                consensus standards.'' According to this same commenter, BSEE's recent
                cost impact assessment of the 2016 WCR found needless waste under
                certain provisions of the rule, leading to ``idled rigs, unnecessary
                new equipment, unnecessary reporting, non-productive time, and lost
                production opportunities, all of which have no offsetting benefit to
                safety or environmental protection.'' This commenter contended that the
                proposed rule included adjustments to the 2016 WCR that provide
                economically feasible avenues for reaching the safety and environmental
                goals required by OCSLA. One commenter asserted that E.O. 13211 is
                unconstitutional, so any reliance on it is unlawful.
                ---------------------------------------------------------------------------
                 \19\ The commenter cited 43 U.S.C. 1347(b) as the basis for its
                assertion. BSEE-2018-0002-0050 Attch. 1 (p. 3).
                ---------------------------------------------------------------------------
                 Response: BSEE's articulation of its 2016 position with
                respect to the applicability of E.O. 13211 to the 2016 WCR constitutes
                the best evidence of the bureau's position.\20\ The OCSLA provision
                cited by the commenter addresses economic feasibility with respect to
                the use of certain technologies during OCS operations, not with respect
                to the economic feasibility of regulatory updates.\21\ This rulemaking
                does not make a determination regarding the economic feasibility of any
                technology under 43 U.S.C. 1347(b). As explained in more detail in
                section I of this final rule preamble, E.O.s 12866 and 13563 direct
                BSEE to assess the costs and benefits of available regulatory
                alternatives and, if regulation is necessary, to select a regulatory
                approach that maximizes net benefits (accounting for the potential
                economic, environmental, public health, and safety effects). As a
                general matter, BSEE informs its decision-making with respect to
                rulemaking through fulfillment of the requirements of the APA and
                associated regulations and guidance.
                ---------------------------------------------------------------------------
                 \20\ 81 FR 25888, 26013 (April 29, 2016).
                 \21\ 43 U.S.C. 1347(b) states, in part: ``[The Secretary] shall
                require, on all new drilling and production operations and, wherever
                practicable, on existing operations, the use of the best available
                and safest technologies which the Secretary determines to be
                economically feasible . . . .''
                ---------------------------------------------------------------------------
                Comments on Other Legal Issues
                 Summary of comments: A commenter asserts that the agency cannot
                adopt new revisions in the final rule based on solicited comments when
                the agency did not propose those revisions in the proposed rule nor
                provide an opportunity for public comment on those revisions.
                 Response: BSEE disagrees. BSEE decision-making regarding
                regulatory revisions is governed by the requirements of the APA and
                associated regulations and guidance. BSEE has complied with the notice
                and comment requirements of applicable law with respect to all
                provisions of the final rule. Any provisions not specifically proposed
                in the proposed rule reflect existing requirements and/or are logical
                outgrowths from the proposed rule.
                 Summary of comments: A commenter asserted that BSEE must perform a
                Quantitative Risk Analysis (QRA) before BSEE can realistically conclude
                that the changes ensure safe operations. In addition, the commenter
                asserted that BSEE must evaluate the significant environmental impacts
                of the rulemaking by preparing an Environmental Impact Statement (EIS).
                The commenter based this assertion on the requirement under the
                National Environmental Policy Act (NEPA) to take a ``hard look'' at the
                cumulative impacts the rulemaking would have on water resources,
                wildlife, coastal habitats, marine species, air quality, and
                sociocultural and economic systems, including direct and indirect
                impacts. The commenter also asserted that the rulemaking requires BSEE
                to undertake Endangered Species Act (ESA) consultations because
                removing certain regulatory provisions regarding environmental and
                worker protections may affect listed species and critical habitat.
                 Response: BSEE disagrees with the claim that a QRA is the
                only way for BSEE to conclude that these changes ensure safe
                operations. As more fully discussed in the final Environmental
                Assessment (EA), NEPA requires that BSEE take a ``hard look'' at the
                potential impacts of a rulemaking, however it does not specifically
                require a QRA. BSEE took its ``hard look'' through the final EA, and
                reached a Finding of No Significant Impact (FONSI), demonstrating that
                an EIS is not required. Further, before any actual operations can be
                conducted on the OCS, there are a number of additional stages (e.g.,
                leasing program, lease sales, planning, permitting) at which additional
                analyses of potential impacts are and will be performed. In addition,
                guidance in OMB Circular A4 regarding the preparation of a regulatory
                impact analysis (RIA) for significant rulemakings states that agencies
                ``should seek to use more rigorous approaches with higher consequence
                rules.'' BSEE evaluated the recommendations from the stakeholders and
                commenters, considering a number of factors including risk, benefits,
                and cost. As previously discussed, consistent with congressional
                encouragement, BSEE solicited input from stakeholders early in this
                rulemaking process to identify those provisions of the existing
                regulations that BSEE could amend, revise, or remove to reduce
                unnecessary burdens on stakeholders while still maintaining safety and
                environmental protection. BSEE generally focused on those provisions in
                the existing regulations that did not significantly enhance worker
                safety or environmental protection.
                 With respect to ESA consultation, BSEE considered the ongoing
                Section 7 ESA consultations with the U.S. Fish and Wildlife Service,
                and whether this rule would affect any listed species or habitat. The
                National Marine Fisheries Service expressly excluded this rule making
                from the ongoing programmatic consultation. The final rule would not
                give rise to any additional or modified activities that would affect
                listed species or designated critical habitat. BSEE has determined that
                the final rule will have ``no effect'' on listed species or designated
                critical habitat. BSEE has determined that ESA consultation is
                therefore not required for this rule.
                Comments on Best Available and Safest Technology (BAST) Requirement in
                OCSLA
                 Summary of comments: A commenter emphasized that OCSLA requires
                BSEE to ensure that operators use ``the best available and safest''
                technology (BAST) possible, unless BSEE determines that the narrow
                impracticability exception applies. The commenter asserted that BSEE
                failed to ensure or otherwise determine that the proposed rule meets
                these requirements. This commenter asserted that before BSEE may
                rescind and revise technological requirements that were determined to
                meet the requirements of BAST, BSEE is obligated to demonstrate
                compliance with BAST by ensuring that those revisions are as good as
                the original requirements. The commenter maintained that BSEE may not
                adopt the proposed revisions without a determination that the benefits
                of the
                [[Page 21922]]
                original provisions are clearly insufficient to justify the incremental
                costs of implementing these technologies. This commenter asserted that
                BSEE must provide information demonstrating that the rulemaking will
                meet the BAST requirements of OCSLA.
                 A commenter urged BSEE to expeditiously finalize its consideration
                of the potential revisions to Sec. 250.107.
                 Response: The Conference Report regarding OCSLA's BAST
                provision \22\ explains that that this provision requires the Secretary
                to make a ``determination as to what are the best available and safest
                technologies economically feasible . . . .'' \23\ Neither the 2016 WCR
                nor this rule made or makes any such determination with respect to any
                specific technology. Therefore, in this rule, the Secretary has not
                undertaken any BAST evaluation of economic feasibility of any specific
                technology, nor did the Secretary do so in the context of the 2016 WCR
                (see, e.g., 81 FR 25901; 25911; and 25929). Thus, the BAST statutory
                requirement does not apply here because this rulemaking makes no BAST
                determinations, nor does it alter any existing BAST determinations. The
                BAST statutory requirement is independent from OCSLA's provisions
                establishing the Secretary's authority to promulgate regulations to
                govern OCS operations.\24\
                ---------------------------------------------------------------------------
                 \22\ 43 U.S.C. 1347(b).
                 \23\ Conf. Rpt. 95-1091 (Aug. 10, 1978) (p. 109).
                 \24\ 43 U.S.C. 1334(a) states, in part: ``The Secretary shall .
                . . prescribe . . . regulations as may be necessary to carry out
                [OCSLA]. The Secretary may at any time prescribe and amend such . .
                . regulations as may be necessary and proper in order to provide for
                the prevention of waste and conservation of the natural resources of
                the [OCS], and the protection of correlative rights therein . . .
                .''
                ---------------------------------------------------------------------------
                Comments on Grounds for Decisions
                 Summary of comments: A commenter asserted that BSEE failed to meet
                the APA's legal standards and argued that BSEE must provide ``the
                grounds of its decision and the essential facts upon which the
                administrative decision was based,'' and ``good reasons'' for the
                proposed changes in policy, explaining the reasons why BSEE disregarded
                the ``facts and circumstances that underlay or were engendered by'' the
                prior rule. The commenter asserted that BSEE needs to provide a more
                detailed justification, providing ``reasoned explanation.'' The
                commenter also asserted that it is arbitrary and capricious for BSEE to
                assume that the proposal to repeal regulations, that two years ago BSEE
                found would provide significant societal benefits, will not have an
                effect on societal costs and benefits.
                 Response: BSEE disagrees. The APA's provisions regarding
                notice and comment (5 U.S.C. 553(b) and (c)) require that an agency
                test its regulation through exposure to diverse public comment and give
                affected parties an opportunity to develop evidence in the record to
                support their positions regarding the rulemaking, thereby enhancing the
                quality of agency decisionmaking.\25\ BSEE provided thorough and
                reasoned explanations for its proposed regulatory actions and submitted
                them to public comment. BSEE's evaluation of the comments it received
                permitted the bureau to test these final regulatory provisions. Through
                this rulemaking process, BSEE provided ample and adequate notice of
                each regulatory change implemented through this final rule and ensured
                that the rulemaking record included adequate justification for each
                such change. Further, BSEE undertook its review of the provisions of
                existing regulations as promulgated through the 2016 WCR pursuant to
                the direction of multiple Executive Orders and Secretary's Orders, as
                well as congressional direction. Thus, BSEE faithfully implements OCSLA
                and fully complied with procedural legal requirements, including those
                applicable to this rulemaking.
                ---------------------------------------------------------------------------
                 \25\ Prometheus Radio Project v. F.C.C., 652 F.3d 431, 449 (3d
                Cir. 2011), certiorari denied 567 U.S. 951 (2012).
                ---------------------------------------------------------------------------
                Comments on Weakening of Requirements
                 Summary of comments: One commenter strongly opposed the proposed
                rule, asserting that the proposal to weaken the existing well control
                regulations, just two years after they were promulgated, and before
                some provisions of the regulations are effective, would increase the
                likelihood of another Deepwater Horizon disaster. The commenter
                observed that the previous rulemaking was specifically designed to
                prevent another scenario similar to the Deepwater Horizon event. The
                commenter stressed that this action would ``epitomize an arbitrary and
                capricious reversal of position.''
                 Response: The APA requires that BSEE give a ``general
                statement of [the regulations'] basis and purpose.'' (5 U.S.C. 553(c)).
                As previously described, BSEE broadly based this rulemaking on
                congressional guidance, interaction with stakeholders, BSEE's
                experience implementing the 2016 WCR, BSEE's recognition of
                technological advancements, and directions contained in Executive and
                Secretary's Orders issued subsequent to the 2016 WCR. Pursuant to those
                Orders, BSEE evaluated existing regulatory provisions to identify
                unnecessary regulatory burdens, but always within the bounds of
                maintaining safety and environmental protection. BSEE believes that its
                process accomplished these goals without ``weaken[ing]'' existing
                regulation or failing to maintain safety and environmental protection.
                BSEE's articulation of these sound reasons for its regulatory decisions
                demonstrates that it is not acting arbitrarily or capriciously.\26\
                BSEE disagrees with the commenter's assertion that this rule would
                increase the likelihood of an event similar to DWH. As discussed in
                section I.D of this preamble, this rulemaking reduces regulatory burden
                while maintaining safety and environmental protection.
                ---------------------------------------------------------------------------
                 \26\ See, Natl. Indus. Sand Ass'n v. Marshall, 601 F.2d 689, 717
                (3d Cir. 1979).
                ---------------------------------------------------------------------------
                F. Economic Comments
                Comments on Cost and Benefits
                 Summary of comments: Some commenters made assertions regarding the
                cost/benefit aspects of the proposed rule as presented in the initial
                regulatory impact analysis (IRIA). These comments were varied in scope
                and in position. Some commenters supported the overall conclusion of
                the IRIA, that BSEE is alleviating unnecessary regulatory burdens on
                industry with no foregone benefit to the public. Many commenters
                challenged this conclusion, both for the rule as a whole and with
                respect to some of the individual provisions. Commenters often
                supported their claims with descriptions in the 2016 WCR or by
                highlighting statements from the multiple investigative and engineering
                studies following the Deepwater Horizon incident in 2010.
                 Most comments did not challenge the IRIA's methodology or the
                compliance cost or savings estimates. Commenters that noted these did
                so generally, usually in the context of added risks or foregone
                benefits to the public. In other words, commenters mostly accepted the
                compliance savings estimates in the IRIA, but asserted that it was
                incomplete and that BSEE essentially ignored the ``benefit'' part of a
                cost-benefit analysis. On this basis, one commenter challenged BSEE's
                ``neutral'' designation for safety and environment impacts, claiming it
                treats foregone benefits as having zero value. The commenter further
                asserted, ``BSEE must analyze and monetize the forgone societal
                benefits from [the proposed rule] that it analyzed and monetized in
                [[Page 21923]]
                2016, including the risk reduction benefits.'' In the absence of such
                an analysis, a separate commenter asserts that, ``BSEE provides no
                evidence that the existing rule is actually a burden or that removing
                safeguards will ensure adequate protections remain in place.'' Further
                comments suggest the savings estimates presented in the IRIA are
                insignificant in comparison to the billions in gross domestic product
                (GDP) generated by the coastal communities placed at greater risk if
                this rule is finalized--a risk, commenters note, BSEE did not evaluate.
                Variations of these claims are found in multiple comments.
                 Response: The 2016 WCR did not make specific claims
                regarding the reduced risk created by the provisions in that
                rulemaking. A breakeven analysis of the rule's total compliance costs
                claimed only that BSEE believed the risk reduction was greater than one
                percent. This final rule does not modify or change the overwhelming
                majority of the provisions codified in the previous rulemaking.
                Further, BSEE identified the changes being made specifically because
                they maintain safety and environmental protection, and the societal
                benefits associated therewith. The revisions made through this
                rulemaking exemplify that there are multiple approaches to maintaining
                safety and environmental protection, and the associated societal
                benefits. As discussed in the ``Section-by-Section Summary''
                discussions in this preamble, this final rule leaves in place several
                of the provisions proposed for revision in the proposed rule. The final
                rule focuses only on those provisions that are expected to reduce
                unnecessary burdens on operators, while still maintaining safety and
                environmental protection. Accordingly, BSEE has adequately incorporated
                those benefits into its formulation of this final rule.
                Comments on Compliance Costs or Savings Estimates
                 Summary of comments: BSEE received few comments on compliance cost
                or savings estimations in the IRIA. One commenter resubmitted a cost
                analysis prepared for the 2016 WCR to support the position that BSEE
                should revise additional provisions not included in the proposed rule.
                Similarly, a separate commenter highlighted an unspecified cost burden
                related to the retention period of real-time monitoring data as defined
                by a provision not proposed for revision in the proposed rule.
                 Response: BSEE's rulemaking process revises only the
                provisions identified in the proposed rule and changes that would be
                considered a ``logical outgrowth'' of the proposed rule. These comments
                suggested that BSEE should revise provisions that it did not propose
                for modification in the Notice of Proposed Rulemaking (NPRM) and that
                it did not analyze in the IRIA. BSEE considers the suggestions made in
                these comments to be outside the scope of this rulemaking.
                Comments on the Elimination of BAVO Requirements
                 Summary of comments: Regarding elimination of the BAVO framework, a
                commenter asserted that, based on the supporting RIA for the 2016 WCR,
                ``BSEE estimated that the BAVO system would result in a mere $10,000 in
                annual costs to operators and verification organizations. BSEE has
                provided no evidence that such a small annual cost outweighs the
                critical benefits of the BAVO system.''
                 Response: As discussed previously, BSEE concluded that the
                use of independent third parties will provide the same level of safety
                as the BAVO framework. Implementation of the BAVO framework would also
                impose meaningful costs and burdens on BSEE. BSEE considers any
                compliance cost that does not contribute to safety or environmental
                protection burdensome and therefore believes it is appropriate that the
                regulatory impact analysis reflect a compliance savings and no foregone
                public benefit.
                Comments on Lack of a Risk Analysis or Risk Assessment and Financial
                Analysis
                 Summary of comments: Several comments asserted that the proposed
                rule lacks sufficient risk analysis and asserted that additional
                analyses are required, while other commenters stated they were
                satisfied with the proposed risk assessment.
                 One commenter asserted that BSEE claimed the proposed rule would
                not cause a major increase in costs or prices for: Consumers;
                individual industries; Federal, State, Tribal, or local governments; or
                regions of the nation. The commenter then asserted that these
                conclusions do not consider the risk of another spill like Deepwater
                Horizon or consider the impacts of that event related to the shutdown
                of fishing and tourism businesses for months or longer. The same
                commenter noted that according to BSEE, the proposed changes would
                reduce regulatory costs over a 10-year period at a rate less than $1
                billion total, which the commenter asserted is a relatively small
                amount when compared to the damage of one oil spill.
                 Another commenter made a similar assertion regarding BSEE's
                position that the rule would not cause major increases in cost or
                prices, and asserted that this position does not address important risk
                factors. The commenter asserted that the proposed rule failed to
                account for foregone benefits along with the avoided costs. The
                commenter asserted that because the proposed revisions ``would have a
                positive annual effect on the economy of $100 million or more,'' this
                rulemaking is subject to the cost-benefit analysis requirements under
                E.O.s 12866 and 13563, as well as OMB Circular A-4. The commenter
                asserted that BSEE claimed it has conducted the required analysis, but
                argued that while BSEE's analysis quantifies industry's anticipated
                reduction in compliance costs, it does not address the foregone
                benefits of protections against the types of spills that have cost
                billions of dollars to remediate. The commenter further asserted that
                BSEE simply stated that, ``[t]he proposed amendments would not
                negatively impact worker safety or the environment.'' The commenter
                observed that the economic analysis conducted for the 2016 WCR
                ``quantified and monetized the potential benefits of the rule,
                including time savings, reductions in oil spills, and reductions in
                fatalities.''
                 One commenter asserted that the rulemaking is consistent with the
                Executive and Secretary's Orders, in that the rulemaking would remove
                undue burdens on operators. The commenter supported BSEE's assertion
                that the proposed rule would increase the competitiveness of America's
                offshore energy industry.
                 Another commenter asserted that the proposed rule would hold risk
                to an acceptable level and that the risk-based standards and procedures
                as currently used by operators are sufficient to maintain well control.
                The commenter asserted that operators can maintain well control and
                manage events safely when: Wells are designed for the range of
                anticipated risk; equipment and safeguards have the required redundancy
                and are properly maintained and tested; personnel are trained; tests
                and drills are conducted; and established procedures are followed. The
                commenter emphasized the importance of highly skilled and trained
                personnel on location who are able to provide timely and effective well
                control and safety decision making. The commenter also recommended that
                BSEE consider these general operating practices when finalizing this
                and other regulations.
                [[Page 21924]]
                 Response: BSEE disagrees with the commenters' assertion
                that BSEE did not consider risk in the development of the proposed and
                final rule. BSEE evaluated operational considerations, equipment design
                and specifications, and relevant public input and comments to identify
                appropriate revisions. As previously discussed in this preamble, BSEE
                carefully considered potential changes to these regulations, under
                direction to identify possible revisions that would reduce unnecessary
                regulatory burdens on stakeholders, while still maintaining safety and
                environmental protection. As discussed qualitatively in the RIA, BSEE
                determined that the selected revisions are likely to maintain the same
                worker safety and environmental protection as the 2016 final rule,
                therefore BSEE did not evaluate the costs related to a potential
                increase in spills or safety issues. BSEE recognizes that pursuant to
                OMB guidance (OMB circular A-4),\27\ agencies are encouraged to ``seek
                to use more rigorous [economic analysis] approaches with higher
                consequence rules,'' i.e., those rulemakings that are expected to have
                annual benefits and/or costs in the range from $100 million to $1
                billion. BSEE recognizes that there is a potential relationship between
                a decrease in regulatory requirements and an increase in risks.
                However, during the rulemaking process, BSEE considered the potential
                impacts of contemplated revisions to safety and environmental risks to
                identify those revisions that would reduce burdens on operators while
                maintaining safety and environmental protection. While BSEE did not
                develop a specific risk analysis for this rulemaking, BSEE considered
                potential risks as part of the process of developing this rule and RIA.
                BSEE has a number of completed and ongoing efforts related to
                evaluating risk in OCS operations. BSEE considered information from
                these efforts when evaluating the requirements of the current well
                control regulations to identify requirements that could be revised
                while still maintaining safety and protection of the environment. Among
                the ongoing efforts considered by BSEE that address well control-
                related risk issues, are:
                ---------------------------------------------------------------------------
                 \27\ https://www.whitehouse.gov/sites/whitehouse.gov/files/omb/circulars/A4/a-4.pdf.
                ---------------------------------------------------------------------------
                 (1) The SafeOCS failure reporting program, and the ``Blowout
                Preventions System Events and Equipment Component Failures'' 2016
                Annual Report and ``Blowout Preventions System Safety'' 2017 Annual
                Report on failures, by BTS. These reports include summaries and
                analysis of the data received through the SafeOCS program on BOP
                equipment component failures on the OCS and other key information, such
                as failure causes, operational impacts, and opportunities to improve
                data quality. More information on the SafeOCS reporting system and
                copies of the 2016 and 2017 BTS reports are available at: https://www.safeocs.gov/wcr_home.htm.
                 (2) Argonne National Laboratory (ANL) 2017 report and updated 2018
                report on Risk-Based Evaluation of Offshore Oil and Gas Operations
                Using a Multiple Physical Barrier Approach. This project was designed
                to assist BSEE in developing a multiple physical barrier (MPB) model of
                risk analysis. The project resulted in a risk-analysis technique,
                developed by ANL, that focuses on the use of physical barriers to
                prevent hydrocarbon release. BSEE has used a multiple barrier approach
                as part of its approach to regulations for many years. This project
                supports that approach through the development of a formalized
                methodology for evaluating process safety, to ensure that success paths
                (e.g., systems, components, and human actions needed to ensure the
                success (of a barrier)) are in place and are capable of performing
                their functions in all expected conditions and circumstances. The
                initial (2016) ANL project resulted in a joint industry project (JIP),
                a case study on plug and abandonment barriers. More information on this
                project and the two ANL reports is available at: https://www.bsee.gov/research-record/risk-based-evaluation-of-offshore-oil-and-gas-operations-using-a-multiple-physical.
                 Regarding the comments on BSEE's determination that the proposed
                rule would not cause a major increase in costs or prices, the revisions
                to the regulatory requirements in this final rule are expected to
                reduce unnecessary burdens, while still maintaining safety and
                environmental protection. The 2016 WCR did not make specific claims
                regarding the risk reduction created by the provisions in that
                rulemaking. A breakeven analysis of the rule's compliance costs claimed
                only that BSEE had concluded that the risk reduction was greater than
                one percent (81 FR 25987). This final rule does not modify or change
                the overwhelming majority of the provisions codified in the 2016 WCR.
                BSEE determined that the selected revisions are likely to maintain
                safety and environmental protection.
                 This final rule does not codify some provisions of the proposed
                rule. One example is the proposed revision to existing Sec.
                250.734(a)(1)(ii), which requires ``both shear rams to be capable of
                shearing'' the specified equipment run in the hole. BSEE proposed to
                change this provision to require only that a ``combination of the shear
                rams must be capable of shearing'' the specified equipment run in the
                hole. As previously stated, BSEE based the decision not to make that
                change in this final rule on consideration of the public comments on
                the proposed rule, the importance of shearing redundancy, and the
                potential ambiguity the change would create regarding the number of
                rams subject to this shearing requirement. For more information on
                specific proposed provisions that are not being codified in this final
                rule, refer to section V of this preamble.
                 Concerning the comment that recommended that BSEE consider these
                general operating practices when finalizing these and other
                regulations; BSEE agrees and does this routinely as part of developing
                regulations and policies. The incorporation by reference of industry
                developed standards in the regulations is one approach BSEE uses to
                address general operating practices used by the industry. Since these
                documents are developed by industry, they reflect common industry
                practices. BSEE also considered input from industry to identify those
                provisions from the existing regulations that were unduly burdensome,
                although this was not the only input that BSEE considered in
                determining how to revise these regulations.
                Comments on Potential Safety Impacts of Proposed RTM Rrevisions
                 Summary of comments: One commenter asserted that BSEE must
                ascertain whether removing certain provisions, such as RTM
                requirements, would increase the risk of human error, or remove a check
                on human error, regarding the need for an operator's offshore and
                onshore teams to come to consensus on how to proceed. The commenter
                also asserted that BSEE must provide quantitative risk analyses to
                support the proposed rule provisions, stating that such an analysis is
                critical to understanding whether BSEE's proposal to rescind such
                built-in safety checks would impermissibly undermine safety. The
                commenter also cited System Risk Assessment and Management (SRAM) as an
                approach that works effectively in other countries.
                 Response: The final rule revises part of the existing RTM
                requirements, but does not entirely remove them. Section 250.724
                paragraph (a) of the final rule continues to require RTM when operators
                conduct ``well operations with a subsea BOP or with a
                [[Page 21925]]
                surface BOP on a floating facility, or when operating in a high
                pressure high temperature (HPHT) environment.'' The operator must
                ``gather and monitor real-time well data using an independent,
                automatic, and continuous monitoring system capable of recording,
                storing, and transmitting data.'' This includes data regarding the BOP
                control system, the well's active fluid circulating system, and the
                downhole conditions with bottom hole assembly tools.
                 The final rule continues to require operators to transmit such data
                as they are gathered in accordance with a real-time monitoring plan.
                The final rule requires that operators have the capability to monitor
                the data using qualified personnel. In addition, BSEE requires the
                operator to develop and maintain a real-time monitoring plan that meets
                certain specified criteria.
                 The final rule removes the language in existing Sec. 250.724(b)
                discussing contact between onshore and offshore personnel and stating
                that, after completing operations, the operator must preserve and store
                these data for recordkeeping purposes as required in Sec. Sec. 250.740
                and 250.741, and must provide BSEE with access to the designated real-
                time monitoring data onshore upon request. The final rule also removes
                the requirement from Sec. 250.724 that the operators include
                certifications that they have a real-time monitoring plan in their APD.
                These provisions are prescriptive, but unnecessary. The regulations
                still require the operator's RTM plan to describe how the data will be
                transmitted and monitored by qualified personnel, procedures for, and
                methods of, communication between rig personnel and monitoring
                personnel, and actions to be taken in the event of loss of
                communications. Further, the existing regulations (Sec. Sec. 250.740
                and 250.741) already specify recordkeeping requirements for all of
                Subpart G. BSEE also has the authority to request these records from
                the operators. Removal of these redundant or unnecessary requirements
                for storage of RTM data from Sec. 250.724 do not remove the obligation
                for the operator to develop and implement an RTM plan, which includes a
                description of how the data will be stored; therefore, the change in
                risk is minimal and a quantitative risk analysis, as suggested by the
                commenter is not needed.
                 Regarding the commenter's mention of the SRAM, BSEE recognizes that
                there are numerous ways to approach risk assessments and may consider
                other approaches for future policies or regulations.
                Comments on Financial Assurance
                 Summary of comments: A commenter asserted that operators should
                provide evidence of financial ability to plug wells and cover lost
                income, including the loss of income to those who rely on [acy] clean
                ocean for their livelihoods.
                 Response: BSEE assumes that this comment is related to
                financial assurance (bonding) issues. BSEE does not regulate financial
                assurance for the offshore oil and gas industry; the Bureau of Ocean
                Energy Management's (BOEM's) regulations at 30 CFR parts 553, Oil Spill
                Financial Responsibility for Offshore Facilities and 556, Leasing of
                Sulfur or Oil and Gas and Bonding Requirements in the Outer Continental
                Shelf address that responsibility.
                G. Environmental Comments
                Comments on the OCS Leasing Program
                 Summary of comments: A number of commenters addressed elements of
                the BOEM draft proposed 2019-2024 National OCS Leasing Program (Leasing
                Program). These commenters focused on the potential impacts of the
                proposed regulations in conjunction with the potential for oil and gas
                exploration and development in areas that could be opened for leasing
                under BOEM's proposed Leasing Program. One commenter asserted that
                BOEM's proposed expansion of leasing would entail the issuance of
                leases at a pace that exceeds the pace of recent leasing activities.
                The commenter further asserted that this would lead to an increase in
                the risk of spills, blowouts, and other consequences, and that the
                leases would be issued in areas where there is currently no oil and gas
                production and little or no production of oil and natural gas has taken
                place. The commenter asserted that the proposed rule would weaken the
                precautions in place to prevent these consequences just as offshore
                drilling would begin in areas that are not prepared to respond to
                spills.
                 Some comments asserted that the proposal in the Leasing Program to
                expand OCS leasing into additional geographic areas would magnify any
                reduction in safety and environmental protection resulting from the
                proposed revisions in this rulemaking. Some commenters asserted that
                BSEE must consider the impacts that the proposed rule would have under
                the expanded Leasing Program proposed by BOEM.
                 Response: BSEE is aware of BOEM's Leasing Program. The
                proposed Leasing Program is a separate action by BOEM, which is a
                separate bureau from BSEE within the Department. The Leasing Program
                specifies the size, timing, and location of potential leasing activity
                that the Secretary determines will best meet national energy needs for
                the five-year period under consideration. The Leasing Program is
                subject to its own separate public comment processes and is beyond the
                scope of this rulemaking. While certain regulations apply exclusively
                to certain regions, the bulk of BSEE's regulations apply to the entire
                OCS regardless of location. As analyzed throughout, BSEE disagrees with
                the commenters' assertion that this rulemaking weakens the precautions
                to prevent spills and incidents. Accordingly, the impacts of this rule
                are not pertinent to commenters' concerns, and any concerns related to
                the expansion of operations into new areas should be directed toward
                BOEM's proposed Leasing Program, as that is not a subject of this
                rulemaking. Regardless of the BOEM leasing pace, BSEE permits
                operations on an individual well-by-well basis taking into account
                site-specific environmental and operational conditions to help ensure
                safety and environmental protection.
                 BSEE disagrees that the regulations are being weakened and it
                selected the revisions implemented through this rule based in part on
                the fact that they are likely to maintain the same level of safety and
                environmental protection for OCS activities as established by the 2016
                final regulations. This rulemaking does not revise or reduce the oil
                spill response plan requirements.
                General Comments on Environmental Impacts
                 Summary of comments: Multiple commenters were concerned that the
                proposed rule would increase environmental impacts of drilling and
                other well operations, thus negatively affecting the environment. One
                commenter asserted that the penalties imposed for failures are
                insufficient to motivate operators to comply with the regulations. The
                commenter asserted that the 2016 WCR was overly conservative in its
                estimations of its environmental benefits. The commenter also asserted
                that BSEE admitted that it understated the environmental benefits when
                BSEE assumed that the rule would reduce oil spill risk by only one
                percent per year. The commenter asserted that this mistake is further
                compounded by the fact that BSEE relies on this erroneous one percent
                reduction of risk assessment in its costs reduction analysis for the
                proposed revisions to the regulations promulgated through the 2016 WCR.
                The commenter also asserted that a significant monetary imbalance
                exists between current civil penalties and operating costs; asserting
                [[Page 21926]]
                that the penalties are too small to deter risk-taking and provide a
                financial incentive to disregard regulatory compliance. The commenter,
                however, acknowledged that BSEE cannot address this problem through
                regulations, and that Congress needs to mandate penalties that will
                discourage this behavior.
                 A different commenter expressed concern regarding how the proposed
                rule would negatively affect the environment. The commenter expressed
                opposition to any provisions of the proposed rule that would weaken
                requirements for decommissioning, such as possibly excluding
                decommissioning from RTM requirements. The commenter referenced a 2010
                article by the Associated Press asserting that there are more than
                27,000 sealed and abandoned oil and gas wells in the Gulf of Mexico,
                with more than 3,200 wells classified as active that have no cement
                plugging. The commenters asserted that these 3,200 wells pose a
                significant risk to the health of the Gulf and coastal communities
                because the factors that could lead to leaks are not being monitored.
                The commenter noted that in recent years, millions of dollars from
                Deepwater Horizon recovery and restoration funds were provided to state
                programs to safely plug abandoned wells. The commenter asserted that
                BSEE should strengthen requirements for decommissioning activities to
                prevent the risk of future leaks.
                 Response: BSEE disagrees with the commenters' assertions
                that the selected regulatory revisions would negatively affect the
                environment. BSEE has determined that this rulemaking does not alter
                the baseline (2016 level) risk profile of the 2016 WCR, for the reasons
                specified in the rule and RIA. There are no benefits (forgone or
                otherwise) to quantify because the baseline risk profile is unchanged.
                Therefore, those forgone benefits are ultimately quantified at zero. In
                the EA, BSEE evaluated the revisions in this rulemaking to focus the
                impact analyses on those revisions that could potentially change
                operators' responsibilities for how they conduct their operations. The
                impact analysis focuses on the likely impacts associated with a
                possible loss of well control, discharges of hydrocarbons to the
                environment, and air pollution emissions associated with testing
                activities. BSEE evaluated the impacts of the final rule provisions and
                determined that none of the provisions will significantly impact the
                quality of the human environment under NEPA (refer to the final EA and
                FONSI).
                 BSEE generally agrees with the commenters' assertions about the
                importance of civil penalties. However, those considerations are beyond
                the scope of this rulemaking. BSEE also agrees that the sufficiency of
                the maximum civil penalties allowable under OCSLA is a question that
                would need to be addressed by Congress. BSEE also generally agrees with
                the commenters' assertions about the importance of decommissioning.
                However, this aspect of decommissioning operations is also beyond the
                scope of this rulemaking.
                Comments on the Need for an EIS
                 Summary of comments: Multiple commenters recommended that BSEE
                should prepare an EIS. These commenters asserted that the environmental
                impacts discussed in the draft EA are significant in scope and
                intensity and that the impacts of a catastrophic discharge would be
                severe. The commenters also asserted that the proposed rule would
                increase the risk of significant impacts; therefore, BSEE should
                prepare an EIS for this rulemaking. Another commenter asserted that the
                standard for triggering an EIS is low and that an EIS should be
                prepared when substantial questions are raised about whether a project
                may have a significant impact on the environment. A commenter also
                asserted that agencies must identify their methodologies, indicate when
                information is incomplete or unavailable, acknowledge scientific
                disagreement and data gaps, and evaluate indeterminate adverse impacts
                based on approaches or methods ``generally accepted in the scientific
                community.'' Some commenters asserted that BSEE's utilization of an
                environmental assessment is unsupportable because of the potential
                effects from a possible catastrophic oil spill, like the Deepwater
                Horizon incident, and BOEM's plans to dramatically expand the scope of
                offshore drilling through the National OCS Program under development.
                 Response: BSEE disagrees that the potential impacts of the
                rule are significant. BSEE used the best available scientific
                information to conduct a comprehensive review of the potential
                environmental impacts of the provisions of the proposed rule. More
                specifically, BSEE reviewed and incorporated the impact analyses from
                multiple existing environmental documents into the draft EA and
                determined that there were no significant environmental impacts
                associated with any of the NEPA alternatives considered, and, most
                importantly, with the provisions in this final rule. Furthermore, BSEE
                disagrees that the proposed rule would increase the risk of significant
                impacts. As previously mentioned, BSEE considered potential risks while
                developing the final rule. In particular, we concluded that the risk of
                a catastrophic oil spill is not increased by the regulatory revisions
                of this rule. These considerations included the public's input on the
                proposed rule and information from a number of BSEE efforts related to
                evaluating risk in OCS operations--such as BSEE's SafeOCS failure
                reporting program and the ANL report on Risk-Based Evaluation of
                Offshore Oil and Gas Operations Using a Multiple Physical Barrier
                Approach. These various sources of information led BSEE to identify
                changes to the regulations implemented through the 2016 WCR that would
                reduce regulatory burden while maintaining safety and environmental
                protection on the OCS. For example, the final rule does not include
                certain changes initially mentioned in the proposed rule that would
                have eliminated the requirement for both shear rams in a BOP to be
                capable of shearing specific equipment run in the hole and eliminated
                requirements related to pipe positioning for shear rams. Inasmuch as
                the impacts of the rule are either neutral or positive, the potential
                for expansion of the geographic area subject to leasing does not
                increase the risks to a level approaching significance. General
                statements of dissatisfaction with the draft EA's analyses or general
                statements regarding NEPA legal standards, do not assist BSEE in
                providing any supplemental analysis that could assist the public in
                understanding the potential environmental impacts of the final rule.
                Comments on the Adequacy of Impacts Analysis
                 Summary of comments: A number of comments asserted that BSEE's
                analyses of impacts on environmental resources are inadequate. One
                comment asserted that BSEE's one-sided evaluation of economic impacts
                violates NEPA and that the analysis fails to address the ``crippling
                economic consequences of failing to prevent an oil spill that could
                have been prevented under the 2016 well control rule.'' Another comment
                asserted that the draft EA fails to disclose and analyze impacts to
                water resources, wildlife on nearby habitats, air quality,
                sociocultural systems, commercial and recreational fisheries, tourism,
                and recreation, as well as cumulative impacts. The commenter also
                disapproved of BSEE's determination that consultation for threatened
                and endangered species is
                [[Page 21927]]
                not necessary at this time. The commenter asserted that BSEE's
                conclusions are not supported by any qualitative or quantitative
                analysis and therefore fail to satisfy the hard look requirement of
                NEPA.
                 Response: BSEE stands by the conclusions provided in the
                EA, while noting that BSEE used the best available scientific
                information to conduct a comprehensive review of the potential
                environmental impacts. This information includes multiple existing
                environmental analysis documents, listed in the next paragraph, as well
                as information received through public comment on the proposed rule and
                a number of BSEE efforts (e.g., ANL studies) related to evaluating risk
                in OCS operations. As previously mentioned, the changes to the
                regulations promulgated through the 2016 WCR are limited only to those
                that would reduce regulatory burden while maintaining safety and
                environmental protection on the OCS. Those comments that express
                general dissatisfaction with the analyses do not provide any
                supplemental analysis that could assist the public in understanding the
                potential environmental impacts of the rule.
                 The project area evaluated in the EA is fully described in Chapter
                3 of the EA, Affected Environment. The EA incorporates by reference
                baseline information regarding resources that are relevant to the
                operations conducted under the revised regulations from the Final
                Programmatic Environmental Impact Statement; Outer Continental Shelf
                Oil and Gas Leasing Program: 2017-2022; Final Environmental Impact
                Statement; Gulf of Mexico OCS Oil and Gas Lease Sales: 2017-2022; Gulf
                of Mexico Lease Sales 249, 250, 251, 252, 253, 254, 256, 257, 259, and
                261; Final Programmatic Environmental Assessment of the Use of Well
                Stimulation Treatments on the Pacific Outer Continental Shelf: May
                2016; and the Final Environmental Assessment; Oil and Gas and Sulfur
                Operations on the Outer Continental Shelf--Blowout Preventer Systems
                and Well Control: April 2016. BSEE rigorously evaluated and discussed
                in Chapter 4 of the EA, Environmental Consequences, the analyses of
                impacts on water resources, wildlife on nearby habitats, air quality,
                sociocultural systems, commercial and recreational fisheries, tourism,
                and recreation, as well as cumulative impacts, while noting that many
                of the quantitative and qualitative analyses are supported in the
                documents incorporated by reference.
                 In the EA, BSEE identified the scope of reasonably foreseeable
                activities that may be attributed to this rulemaking in order to
                estimate its environmental effects. BSEE acknowledges that there is
                some level of risk associated with offshore oil and gas activities;
                however the scope of this EA is limited to this rulemaking, which
                adopted changes to the current regulations that reduce regulatory
                burdens while maintaining safety and environmental protection.
                 The cumulative impacts analysis considered the baseline data
                included in Chapter 3, Affected Environment, which describes current
                conditions and past and ongoing impacts on the resources that could
                potentially be affected by the activities included under each
                alternative, as well as reasonably foreseeable future activities that
                should be taken into account. The EA appropriately describes and
                analyzes all of the current and reasonably foreseeable future impacts
                from other activities described in the Cumulative Effects section 4.5
                of the EA based on the estimated negligible to small impacts attributed
                to promulgating the final regulations in this rulemaking under
                Alternative 4, and the small contribution to total cumulative impacts.
                 BSEE considered the ongoing Section 7 ESA consultations with the
                U.S. Fish and Wildlife Service and National Marine Fisheries Service,
                and whether this rule would affect any listed species or habitat. The
                final rule would not give rise to any additional or modified activities
                that would affect listed species or designated critical habitat. BSEE
                has determined that the final rule will have ``no effect'' on listed
                species or designated critical habitat. BSEE has determined that ESA
                consultation is therefore not required for this rule.
                H. Miscellaneous Comments
                Comments on General Safety Issues
                 A number of comments discussed overall safety issues purportedly
                implicated by the rulemaking, not related to a specific proposed
                revision. Some commenters stated that they perceived that the proposed
                rule would improve the overall safety of operations, while others
                raised concerns that the proposed rule would decrease overall safety.
                 Summary of comments: Multiple commenters expressed support for the
                proposed rule's reliance on best management practices, innovation to
                increase safety and reliability, optimization of risk reduction,
                support for the nation's efforts to increase energy independence, and
                incorporation of API Standard 53. One commenter asserted that adoption
                of API Standard 53 would improve safety by aligning the regulations
                with actual industry practices; by incorporating the standard it would
                apply to operators, suppliers, and contractors; and that the standard
                would provide for timely introduction and management of new technology.
                 A commenter asserted that the economic production of crude oil and
                natural gas in the Gulf of Mexico is vital to the U.S. economy and
                American consumers. The commenter emphasized the importance of ensuring
                that any regulations BSEE adopts optimize risk reduction without making
                development and production uneconomic or unsafe.
                 A commenter asserted that new technologies can provide industry
                with operational information. The commenter asserted that the industry
                and BSEE recognize that technologies already exist, or are in
                development, that can provide operators with data regarding the
                equipment's performance. The commenter asserted that use of these and
                other emerging technologies, along with API Standard 53 failure
                reporting, may lead to advances that further improve safety and
                reliability.
                 Response: BSEE agrees with the comments generally
                supporting the selected revisions. BSEE has reviewed all comments
                submitted and is revising the proposed rule as appropriate. BSEE
                responds directly to comments on specific provisions and discusses the
                final rule provisions in section V of this preamble.
                 Summary of comments: Several commenters asserted that the proposed
                rule failed to adequately demonstrate how it will protect safety.
                Another commenter asserted that the proposed rule allows operators to
                govern their own safety. The commenter asserted that the proposed
                revisions would allow a substantial degree of self-governance to the
                operators and that this is an industry that has demonstrated an
                inability to obtain oil in a safe, responsible way. The commenter
                referred to a recent series of surprise inspections of drilling rigs
                that revealed a number of major safety violations and asserted that
                several of the companies pushing hardest against the regulations were
                cited for violations more often than the industry average. A different
                commenter asserted that the proposed rule lacked adequate evidence that
                it would protect safety. This commenter asserted that BSEE must
                evaluate safety with respect to the different geographical environments
                where the oil and gas operations will occur. The commenter noted that
                different ocean environments present different constraints, challenges,
                and operational risks; and asserted that BSEE must
                [[Page 21928]]
                evaluate whether the proposed revisions would ensure safety in all
                environments. The commenter further asserted that BSEE did not provide
                evidence that the existing regulations are actually a burden or that
                removing safeguards will ensure adequate protections remain in place.
                The commenter also asserted that the proposed rule did not provide
                sufficient analysis on how it would safeguard workers and protect the
                environment, but focused on assertions about reducing regulatory
                burdens for industry and burdensome paperwork for regulators. The
                commenter asserted that the proposed rule lacked any studies,
                investigations, reports, or public solicitations for information.
                 A commenter contended that the reduced oversight contemplated by
                the proposed rule would make losses of well control and oil spills more
                likely to occur. The commenter claimed that weakening safety
                regulations designed to prevent blowouts would further contribute to
                the already routine oil spills that will occur in the Atlantic if the
                Administration finalizes its plan to allow oil and gas development in
                that area. The commenter asserted that, if offshore drilling increases,
                the level of safety and prudence must also increase.
                 Response: BSEE reviewed all comments submitted and is
                revising the proposed rule as appropriate. BSEE does not agree with the
                commenters' assumption that this rulemaking will allow the operators to
                govern their own safety. The use of various regulatory approaches in
                this rulemaking--including the incorporation of standards; performance-
                based requirements; independent third parties instead of BAVOs--
                increases the responsibilities on operators, but does not reduce BSEE's
                oversight responsibilities. BSEE continues to review and approve permit
                applications for specific activities and to inspect all OCS facilities
                for compliance with applicable law, regulation, plans, permits, and
                lease terms. Operator applications must contain appropriate information
                to demonstrate compliance with BSEE regulations, including any
                documents incorporated by reference. The incorporation by reference of
                industry standards does not mean the industry is self-regulating. BSEE
                participates in the development of many of the standards incorporated
                by reference. In addition, BSEE reviews and analyzes any standards
                incorporated in the regulations to ensure the documents provide for
                safety and environmental protection and are consistent with BSEE's
                authorities and policies. BSEE may supplement standards with specific
                regulatory provisions, if there are any places where the standards are
                lacking. Most importantly, once incorporated by reference, such
                standards are enforceable as any other regulatory requirement, and BSEE
                is responsible for oversight of compliance and enforcement--it is not
                left to industry. Further, if industry modifies an incorporated
                standard, those modifications do not impact the regulatory requirements
                unless and until BSEE incorporates those modifications through a
                separate rulemaking.
                 The commenter referred to a recent series of surprise inspections
                of drilling rigs that revealed a number of major safety violations and
                asserted that several of the companies pushing hardest against the
                regulations were cited for violations more often than the industry
                average. BSEE regularly conducts unscheduled or ``surprise''
                inspections of facilities on the OCS. BSEE is not certain whether this
                comment is referring to the regular unplanned inspections or a specific
                increased inspection effort. Regardless, BSEE normally inspects mobile
                offshore drilling units (MODUs) at least once every 30 days when they
                are in operation on the OCS. BSEE does not agree with the assertion
                that the companies most vigorously opposing the regulations were cited
                for violations more often than the industry average. BSEE did not
                consider the number of violations issued to specific operators when
                developing this rulemaking.
                 Regarding the concern that BSEE must evaluate safety with respect
                to the different geographic environments where the oil and gas
                operations will occur, BSEE agrees that differences in geographic
                environment can impact the nature of operations. This is reflected in
                the fact that certain of BSEE's regulatory requirements are
                specifically tailored to particular geographic environments, such as
                the Arctic or frontier areas. Prior to receiving approval from BSEE to
                begin drilling operations on the OCS, an operator must submit an
                exploration or development plan to BOEM for approval. The exploration
                or development plan addresses operational considerations relevant to
                the specific location and operating environment (for more information
                on the content of exploration and development plans, go to: https://www.boem.gov/Submitting-Complete-Exploration-and-Development-Plans/).
                As part of the review of the APD, BSEE confirms whether the APD is
                consistent with the approved exploration or development plan, as well
                as consistent with the additional requirements applicable to such
                submissions, under the circumstances presented.
                 Concerning the commenter's assertion that the development of the
                proposed rule did not include studies, investigations, reports, or
                public solicitations for information, BSEE disagrees. As previously
                discussed, BSEE considered questions that arose during the
                implementation of the 2016 WCR and the policies developed in response
                to those questions. In addition, BSEE solicited input from interested
                parties to identify potential revisions to the regulations; including
                the public forum held on September 20, 2017, in Houston, Texas.
                Further, BSEE received and considered a substantial amount of
                information from commenters through the APA notice and comment process.
                BSEE's approach to this regulatory reform was to consider input from a
                variety of sources to make proposals that would carefully remove
                unnecessary burdens while leaving critical safety provisions intact.
                 Summary of comments: One commenter asserted that implementation of
                the proposed rule and adoption of a related procedure for checking well
                pressures as a standard industry practice would potentially have
                prevented a number of fatalities. This commenter recommended that BSEE
                incorporate a specific safety procedure in the regulations, so it would
                become a standard industry practice.
                 Response: BSEE received and assessed the comment and is
                not incorporating the commenter's suggested procedure into the
                regulations at this time. BSEE disagrees that it would be appropriate
                to require the commenters' identified specific procedures on all wells
                and rigs, and doing so would be beyond the scope of this rulemaking.
                BSEE may evaluate the procedures for possible inclusion in future
                rulemakings, if appropriate.
                Comments on Energy Independence
                 Summary of comments: Some commenters expressed concern that BSEE is
                promoting increased drilling and energy independence at the expense of
                its obligations to protect the environment. One commenter asserted that
                BSEE's function is to promote safety and protect the environment. The
                commenter referenced BSEE's explanation in the proposed rule that the
                intention of this rulemaking is to fortify the Administration's
                position toward facilitating energy security leading to increased
                domestic oil and gas production and to reduce unnecessary burdens on
                stakeholders.
                [[Page 21929]]
                However, the commenter asserted that it is not BSEE's duty to increase
                production of oil or gas. The commenter noted BSEE's mission statement
                that says its mission is to ``promote safety, protect the environment,
                and conserve resources offshore through vigorous regulatory oversight
                and enforcement.'' The commenter asserted that it is inappropriate for
                BSEE to sacrifice its public trust obligations in favor of enhancing
                industry profits.
                 Response: BSEE disagrees with the commenters' assertions
                that this rulemaking is promoting increased drilling and energy
                independence at the expense of BSEE's obligations to protect safety and
                the environment. BSEE recognizes its obligations to protect safety and
                the environment under OCSLA; however, as stated in Sec. 250.101(b),
                and pursuant to 43 U.S.C. 1332(3). BSEE is also obligated to follow
                sound conservation practices to make OCS resources available for
                development to meet the Nation's energy needs. Applying sound
                conservation practices includes ensuring that the requirements in the
                regulations do not unduly burden responsible development and production
                of oil and natural gas resources, while maintaining safety and
                environmental protection. BSEE's responsibilities go beyond safety and
                environmental protection and extend to numerous aspects of the proper
                management of OCS oil and gas operations. In addition, as previously
                discussed, this rulemaking executes the mandates from the President and
                the Secretary, as set forth in E.O. 13783--Promoting Energy
                Independence and Economic Growth; E.O. 13795--Implementing an America-
                First Offshore Energy Strategy; and Secretary's Order No. 3350. BSEE
                disagrees that this rule fails to maintain safety and environmental
                protection and stands by its determination that every change made in
                this rule meets that standard.
                Comments on Conflicts of Interest
                 Summary of comments: Some commenters took issue with the fact that
                BSEE incorporated input from interested parties in the proposed rule.
                The commenters claimed that the proposed rule would allow operators to
                provide their own oversight, while not acknowledging API's role as a
                lobbyist for the oil and gas industry. These commenters asserted that
                this creates a conflict of interest for these parties and for BSEE and
                that this would make losses of well control and catastrophic oil spills
                more likely. One of these commenters asserted that adopting standards
                developed by API creates a conflict of interest, because API is a major
                oil and gas industry trade association and lobbying firm. The other
                commenter views the performance-based standards in the proposed rule as
                poorly defined, claiming they should be clearly established before the
                final rule's publication. The commenter asserts that a number of
                provisions in the proposed rule regarding performance-based standards
                are extremely vague. This commenter opined that BSEE should have
                published an Advance Notice of Proposed Rulemaking (ANPR) to gather the
                information necessary to prepare a better defined proposed rule, if
                BSEE did not know which proposed standards to include.
                 Response: BSEE disagrees with the suggestion that BSEE should have
                published an ANPR before publishing the proposed rule. As previously
                discussed, when BSEE initiated its review of these regulations, BSEE
                held a public forum in Houston, Texas, which was attended by more than
                110 interested parties. The participants of the public forum provided
                comments and suggestions before BSEE began the process of developing
                the proposed rule. BSEE likewise obtained useful input into the
                development of this rulemaking through the Department's ``request for
                comment'' on its overall regulatory reform initiatives. The proposed
                rule also served as an opportunity for BSEE to secure public comment
                and input.
                 As discussed previously, this rulemaking does not allow operators
                to operate without oversight. BSEE continues to serve in an oversight
                and enforcement capacity, even where regulatory requirements are tied
                to industry standards. BSEE also disagrees with the commenters'
                assertion that there is a conflict of interest inherent in using
                industry standards. Federal law in fact requires that an agency ``use
                standards developed or adopted by voluntary consensus standards bodies
                rather than government-unique standards, except where inconsistent with
                applicable law or otherwise impractical.'' NTTAA; OMB Circular A-119 at
                p. 13. BSEE follows the requirements of the NTTAA and the relevant
                guidance in OMB Circular A-119 when incorporating standards into its
                regulations. Membership in an API standard development committee is not
                limited to industry representatives \28\ and may include non-industry
                members, such as government personnel, consumer advocates, and
                academics.
                ---------------------------------------------------------------------------
                 \28\ http://mycommittees.api.org/standards/Reference/API%20Procedures%20for%20Standards%20Development-2016.pdf.
                ---------------------------------------------------------------------------
                 BSEE disagrees with the assertion that the performance-based
                standards incorporated by reference in this rulemaking are poorly
                defined and vague and need to be more ``clearly established'' before
                they can be adopted in a final rule. Performance-based standards
                establish expectations for safe operations that allow for more
                flexibility to determine the appropriate approach to meeting the
                expectations based on specific operating conditions. This approach is
                not a design flaw that must be corrected, but rather an important
                feature of such standards. BSEE's regulations include a mix of
                prescriptive and performance-based regulatory standards, and both
                approaches offer a variety of strengths and benefits.
                Comments on Production Safety Systems
                 Summary of comments: A commenter discussed the removal of the
                requirement for third-party certification for safety and pollution
                prevention equipment (SPPE). This commenter asserted that both safety
                and environmental risks would increase by removing the requirement for
                third-party inspection and certification, especially for extreme
                conditions. The commenter expressed concern regarding BSEE's proposal
                to remove the requirement for review and certification of SPPE by an
                independent third party contained in Sec. 250.802(c)(1), including the
                requirement of inspection and certification to demonstrate that the
                SPPE will function under the most extreme conditions to which it may be
                exposed. The commenter opposed this change, asserting that: These
                inspections were specifically tailored to address one of the causes of
                the Deepwater Horizon catastrophe; third-party inspections respond to
                extreme conditions becoming more prevalent and intense with climate
                change; and SPPE implicates a level of risk that meets BSEE's standard
                for requiring third-party inspection.
                 Response: This comment is related to another rulemaking--
                1014-AA37 Production Safety Systems (AA37). The final rule for that
                rulemaking was published in the Federal Register on September 28, 2018
                (83 FR 49216). BSEE received this comment in connection with that
                rulemaking, as well, and responded to it in the AA37 production safety
                systems final rule.
                [[Page 21930]]
                V. Section-by-Section Summary and Responses to Comments on the Proposed
                Rule
                 This summary discusses every section of 30 CFR part 250 proposed
                for revision in the proposed rule and this final rule. This summary
                does not address sections of the existing regulations that are not
                implicated by the proposed or final rule. Although BSEE did not receive
                substantive comments on numerous sections covered by the proposed rule,
                the final rule includes and summarizes those sections. BSEE received
                substantive comments on many other sections covered by the proposed
                rule, some of which are included in this final rule without revision
                and some of which are revised in the final rule. Those sections, as
                well as the relevant comments on those sections and BSEE's responses,
                are summarized here.
                Subpart A--General
                What are the procedures for, and effects of, incorporation of documents
                by reference in this part? (Sec. 250.115)
                 This section in the current regulations is reserved.
                Summary of Proposed Revisions
                 BSEE did not propose any specific changes to this section in the
                proposed rule. However, in the proposed rule discussion of Sec.
                250.198, BSEE discussed the potential for technical (non-substantive)
                revisions to Sec. 250.198 for the purposes of reorganizing and
                revising that section to make it clearer, more user-friendly, and more
                consistent with the OFR's recommendations for incorporations by
                reference in Federal regulations. BSEE consulted with the OFR regarding
                its suggestions for specific organizational and language changes to
                Sec. 250.198 and addressed such technical revisions in this final
                rule. One element of the organizational changes involved moving certain
                portions of existing Sec. 250.198 out of that regulation, so that it
                is focused more exclusively on the incorporated materials themselves.
                BSEE chose to implement this action by relocating the relevant
                provisions to reserved Sec. 250.115. BSEE determined that those
                technical revisions will not have a substantive impact on the
                incorporations by reference of industry standards discussed in this
                rule or elsewhere.
                Summary of Final Rule Revisions
                 This final rule adds new Sec. 250.115 in accordance with the
                recommendations and requirements of the OFR pertaining to regulations
                that incorporate documents by reference. The language of Sec. 250.115
                is based on the introductory language in the existing Sec. 250.198,
                with certain minor, non-substantive wording changes for clarity. The
                revised Sec. 250.198, which will serve as a centralized Incorporated
                by Reference (IBR) section, deletes the introductory language in
                accordance with OFR's recommendations for these types of IBR
                provisions. Specifically, the OFR recommends that a centralized IBR
                section, such as Sec. 250.198, should not include language regarding
                legal requirements or justifications, scope of the regulations,
                instructions, or policy. The OFR recommends that the centralized IBR
                section list documents incorporated by reference and provide
                information about where the standards are referenced in the regulations
                and how to obtain a copy of the actual standards. Accordingly, this
                rulemaking removes the introductory language in existing Sec. 250.198
                and relocates the language to the new Sec. 250.115 with minor
                revisions.
                Documents Incorporated by Reference (Sec. 250.198)
                 This section of the existing regulations includes citations and
                other information regarding all documents (e.g., industry standards)
                incorporated by reference in 30 CFR part 250, including where to find
                references to the incorporated documents in specific sections of the
                regulations. The requirements for complying with a specific
                incorporated document can be found where the document is referenced in
                the regulations, as specified in existing Sec. 250.198. The existing
                section also discusses BSEE's process for incorporating documents by
                reference, the regulatory effects of incorporation, and procedures that
                operators may follow to seek BSEE's approval to comply with
                alternatives to an incorporated document.
                Summary of Proposed Revisions
                 BSEE proposed to:
                 Revise existing paragraph (h)(63), which incorporates API Standard
                53, to add a new cross reference to Sec. 250.734, as revised in the
                final rule. BSEE also solicited comments on whether to incorporate the
                2016 addendum to this standard;
                 Revise existing paragraph (h)(78), which incorporates API Standard
                65--Part 2, Isolating Potential Flow Zones During Well Construction;
                Second Edition, December 2010, to add a new cross reference to Sec.
                250.420(a);
                 Revise existing paragraph (h)(94) to update the incorporation of
                API RP 17H to the Second Edition; and
                 Add a new paragraph (j)(2) for the incorporation by reference of
                ISO/IEC 17021-1 in order to update the erroneous standard previously
                incorporated by the 2016 WCR.
                 As previously mentioned, the proposed rule also discussed potential
                technical (non-substantive) revisions to Sec. 250.198 that BSEE was
                considering to address recommendations from the OFR.
                Summary of Final Rule Revisions
                 As explained in the previous discussion of new Sec. 250.115, BSEE
                is reorganizing this section consistent with the OFR's recommendations.
                These revisions include technical, non-substantive changes to the
                organization of the section to remove discussions of matters other than
                the incorporated materials themselves and to make the section more user
                friendly, as well as minor wording and formatting changes for clarity
                and consistency.
                 Also, based on comments on the proposed rule, BSEE is revising
                final paragraph (e)(94) to include the addendum to the already
                incorporated API Standard 53 Fourth Edition, November 2012.
                 For the reasons discussed in the section-by-section summary for
                Sec. 250.427 of this final rule, BSEE is also adding a new paragraph
                (e)(6), incorporating by reference API Bulletin 92L.
                 The final rule includes, without change, all other documents
                proposed for incorporation by reference, including:
                 API Standard 65--Part 2, Isolating Potential Flow Zones During Well
                Construction; Second Edition, December 2010;
                 API Recommended Practice 17H, Remotely Operated Tool and Interfaces
                on Subsea Production Systems, Second Edition, June 2013, Errata January
                2014; and
                 ISO/IEC 17021-1--Conformity assessment--Requirements for bodies
                providing audit and certification of management systems--Part 1:
                Requirements, First Edition, June 2015.
                Summary of Comments
                Comments Related to Proposed Sec. 250.198--Incorporation of API
                Standard 53 Addendum
                 Summary of comments: Some commenters suggested that BSEE
                incorporate API Standard 53, 4th Edition, Addendum, which was released
                in July 2016. These commenters asserted that many of the operations in
                the Gulf of Mexico already comply with the July 2016 Addendum
                [[Page 21931]]
                of API Standard 53 4th Edition. They asserted that the Addendum
                clarifies the existing text of API Standard 53, including clarifying
                unintended conflicts with API Specification 16C, Specification for
                Choke and Kill Equipment and that these clarifications would increase
                operational safety and reliability. They also asserted that the
                Addendum was compiled, reviewed, and approved by industry
                representatives, including operators, equipment owners, original
                equipment manufacturers (OEMs), independent third parties, and service
                companies. These commenters stated that API is developing a 5th Edition
                of API Standard 53, but that it was not available at the time of the
                rulemaking.
                 Response: BSEE agrees with the commenter's suggestion
                about incorporating the API Standard 53 addendum into the regulations.
                BSEE reviewed the Addendum and determined that it would not
                significantly alter or negatively impact safety. It does, however,
                address and resolve the same problematic issues for which BSEE
                currently grants departures, and the IBR of the Addendum will eliminate
                the need for granting such departures going forward (e.g., section
                7.2.3.2.9 Side outlet location and section 7.3.13.2.5 fire rating of
                MUX lines). Therefore, BSEE determined that the Addendum is appropriate
                for incorporation into the regulations.
                 With regard to the comments about API developing API standard 53
                5th Edition, BSEE will evaluate that document when it is finalized for
                possible incorporation into the regulations in a future rulemaking.
                 Summary of comments: A commenter suggested that arbitrary
                requirements beyond the provisions in API Standard 53 ``reduce safety
                by adding unnecessary complexity to the blowout prevention equipment
                systems.''
                 Response: The commenter does not specify which
                requirements in the regulations the commenter considers to be arbitrary
                or how such requirements add ``unnecessary complexity to the blowout
                prevention equipment systems.'' In any event, BSEE disagrees with the
                commenter's assertion that any requirements in this final rule or
                existing regulations related to BOP systems are arbitrary or
                unnecessary. For all the reasons discussed in the 2016 WCR, other prior
                rulemakings, and in the proposed rule and this final rule, BSEE has
                determined that any such additional requirements are reasonable and
                appropriate to ensure that BOP systems are designed and utilized
                appropriately.
                Comments Related to Proposed Sec. 250.198--Effectiveness of Using
                Industry Standards
                 Summary of comments: A commenter objected to BSEE incorporating by
                reference any industry standards developed by the oil and gas industry,
                asserting that standards are ``more fluid and not enforceable by law.''
                The commenter asserted that this makes it more difficult for BSEE to be
                effective, noting that similar problems existed prior to the Deepwater
                Horizon oil spill. The commenter cited the BP Oil Spill Commission
                report, asserting that it criticized this culture and stated that the
                Department of the Interior has in turn relied on API in developing its
                own regulatory safety standards and that API's shortfalls have
                undermined the entire Federal regulatory system. This commenter was
                concerned about findings from the BP Oil Spill Commission report that
                the API standards represent the ``lowest common denominator,'' and do
                not reflect ``best industry practices.''
                 Response: BSEE disagrees with the commenters' assertions
                that the documents incorporated by reference are not enforceable and
                that BSEE relies on API to develop regulations. First, BSEE notes that
                the cited Report's concerns with incorporation of industry standards
                were based on agency practices and other circumstances pre-dating the
                2010 Deepwater Horizon incident. Since that event, many BSEE and
                industry practices and circumstances have changed significantly.
                Concerning the comments on BSEE's use of API standards and the
                assertion that API standards increasingly do not represent best
                industry practices, BSEE does not agree that incorporation and use of
                the standards referenced in this final rule is either inappropriate or
                detrimental to safety and environmental protection. For example, BSEE
                evaluated the differences between the first and second editions of API
                RP 17H and determined that the second edition of API RP 17H eliminates
                the conflict between the first edition and API Standard 53, helps
                ensure that the appropriate methods are utilized to comply with the API
                Standard 53 ROV closure timeframes of 45 seconds, and includes
                provisions on high flow Type D 17H hot stabs. All of the standards
                referenced in this rulemaking serve as a valuable complement to BSEE's
                regulations in helping to achieve the bureau's safety and environmental
                objectives under OCSLA. When incorporated into the regulations, these
                standards provide a binding baseline that BSEE may supplement with
                specific requirements where appropriate.
                 Moreover, as previously discussed, the NTTAA mandates that Federal
                agencies use technical standards developed by voluntary consensus
                standards organizations, instead of government-developed standards,
                where practicable and consistent with applicable law. There are only a
                few SDOs, including API, that address issues related to offshore oil
                and gas operations. Also, API provides standards on technical topics
                that are not addressed by other SDOs. Additionally, consistent with the
                NTTAA's preference for agency use of voluntary consensus standards (see
                15 U.S.C. 272(e)(1)(A)(v)), API develops its standards through a
                general consensus process, which provides for input from those who are
                potentially materially impacted by the standard, however, membership on
                API standards committees is not limited to industry participants. In
                addition, based on recommendations in other post-Deepwater Horizon
                reports (see, e.g., Final Report on the Investigation of the Macondo
                Well Blowout, Deepwater Horizon Study Group (March 1, 2011) at pp. 94-
                98), BSEE has expanded its standards program and increased its
                involvement in the standards development process, including development
                of many API standards, and is continuously improving and formalizing
                BSEE's internal process for reviewing standards relevant to the
                regulatory program. These developments help BSEE identify issues that
                may not be adequately addressed in incorporated standards and to
                supplement those standards, as necessary, in its regulations.
                 BSEE also disagrees with the commenter's assertion that industry
                developed standards should not be incorporated in its regulations
                because BSEE does not have the authority to enforce compliance with
                incorporated documents. BSEE incorporates industry standards by
                reference in accordance with the requirements of the NTTAA and
                implementing OMB guidance, OFR regulations (1 CFR part 51), and BSEE's
                own procedures for incorporation (Sec. 250.115, What are the
                procedures for, and effects of, incorporation of documents by reference
                in this part?). The effect of incorporation by reference of an industry
                standard into the regulations is that the incorporated document becomes
                a regulatory requirement, see existing Sec. 250.198(a)(3) (moved to
                new final Sec. 250.115(c)), and thus becomes subject to BSEE oversight
                and enforcement in the same manner as other regulatory requirements.
                BSEE has
                [[Page 21932]]
                repeatedly described this principle in a number of previous
                rulemakings.
                 BSEE is not certain what the commenter means by industry standards
                being ``more fluid.'' However, the commenter may be concerned about
                industry issuance of revisions to or new editions of incorporated
                standards. The OFR regulations, at 1 CFR part 51, govern how BSEE and
                other Federal agencies incorporate documents by reference. Agencies may
                incorporate a document by reference by publishing in the Federal
                Register the document title, edition, date, author, publisher,
                identification number, and other specified information. Incorporation
                by reference of a document is limited to the edition of the document so
                incorporated. See existing Sec. 250.198(a)(1) (moved to new final
                Sec. 250.115(a)). In short, the operator must comply with the edition
                of the standard that BSEE incorporates in its regulations. If an SDO
                later revises a standard that BSEE has previously incorporated in a
                final rule, BSEE would need to evaluate the revised standard before
                choosing whether to incorporate it through rulemaking into the
                regulations; in other words, industry itself cannot change the
                regulatory requirements by revising a standard after BSEE incorporates
                the standard in its regulations.
                Comments Related to Proposed Sec. 250.198--Use of the Latest Published
                Edition and Incorporation of Additional Documents
                 Summary of comments: Several commenters recommended that BSEE
                incorporate the latest published edition of each standard into the
                regulations. Commenters asserted that BSEE has directly participated in
                the development of these standards and that recognition of these
                standards in the regulations would be consistent with the expectations
                of the NTTAA, which requires BSEE to consult and use technical
                standards that are developed or adopted by voluntary consensus
                standards bodies in lieu of BSEE creating its own unique standards.
                 Response: BSEE generally agrees that it should consider
                whether to incorporate the latest editions of standards for which prior
                editions are already incorporated in the regulations. BSEE reviews its
                regulations in accordance with E.O. 13563--Improving Regulation and
                Regulatory Review and E.O. 13610--Identifying and Reducing Regulatory
                Burdens, ``to ensure, among other things, that regulations
                incorporating standards by reference are updated on a timely basis . .
                . .'' (OMB Circular A-119 at p. 4). In fact, BSEE is currently
                reviewing many of the standards incorporated in the existing
                regulations and will provide additional information regarding its
                review when appropriate. If BSEE decides that some updating of
                incorporated standards (e.g., by referencing new editions of existing
                standards, or replacing previously incorporated standards with
                different standards, or simply deleting outdated standards) in the
                regulations is warranted, it will explain its position through future
                rulemakings, as appropriate. Of course, BSEE may also decide, for
                appropriate reasons, to keep a previously incorporated edition of a
                standard in the regulations even if there is an updated edition. BSEE
                is not in a position at this time, either substantively or
                procedurally, to implement the updates suggested by the commenter as
                part of this final rule.
                 Summary of comments: Some commenters recommended that BSEE should
                incorporate into its regulations additional documents and updated
                editions associated with BOP systems (e.g., ANSI/API Spec. 16A--
                Specification for Drill-through Equipment, API Standard 16AR--Standard
                for Repair and Remanufacture of Drill-through Equipment, and API Spec
                20E--Alloy and Carbon Steel Bolting for Use in the Petroleum and
                Natural Gas Industries).
                 Response: BSEE acknowledges the importance of those
                standards to offshore operations. However, they were not proposed for
                incorporation in the proposed rule and BSEE is not currently in a
                position--procedurally or substantively--to incorporate them into this
                final rule. BSEE will evaluate these documents for possible future
                incorporation in the regulations. BSEE continually evaluates new
                standards and new editions of existing standards for possible
                incorporation into the regulations. If, after completing evaluations of
                these standards, BSEE determines they are appropriate to incorporate,
                we may proceed with a separate rulemaking process to incorporate the
                documents.
                 Summary of comments: A commenter recommended that BSEE define
                international standards as any globally recognized, good-practice
                standards.
                 Response: BSEE does not agree that any such definition is
                necessary in these regulations. BSEE follows the guidance established
                by OMB Circular A-119. With respect to international standards, OMB
                Circular A-119 explains that the United States is obligated under the
                Technical Barriers to Trade (TBT) Agreement to use relevant
                international standards, except where such standards would be an
                ineffective or inappropriate means to fulfill the legitimate objective
                pursued. In particular, according to OMB Circular A-119, the TBT
                Agreement, Article 2.4, provides that where technical regulations are
                required and relevant international standards exist or their completion
                is imminent, World Trade Organization (WTO) Members shall use them, or
                the relevant parts of them, as a basis for their technical regulation.
                In addition, 19 U.S.C. 2532 directs Federal agencies, in developing
                standards, to base their standards on international standards, if
                appropriate. OMB Circ. A-119 (p. 22).
                Subpart B--Plans and Information
                What must the DWOP contain? (Sec. 250.292)
                 This section of the existing regulations specifies information
                (e.g., description of the typical wellbore, structural design for each
                surface system) that must be included in a DWOP. Paragraph (p) of this
                section details the information that must be contained within a DWOP
                relating to free standing hybrid risers (FSHR) and the associated buoy
                and tether system.
                Summary of Proposed Revisions
                 BSEE proposed to revise the FSHR requirements of this section to
                eliminate duplicative submittals and certifications of FSHR systems.
                Summary of Final Rule Revisions
                 BSEE received no substantive comments on these provisions of the
                proposed rule and includes the proposed language in the final rule
                without change.
                Subpart D--Oil and Gas Drilling Operations
                What must my description of well drilling design criteria address?
                (Sec. 250.413)
                 This section of the existing regulations specifies the type of
                information that must be provided in the well drilling description
                portion of an APD.
                Summary of Proposed Revisions
                 BSEE proposed to add to paragraph (g) a parenthetical clarification
                of ``surface and downhole'' after ``proposed drilling fluid weights,''
                to ensure the operator includes the weight of the drilling fluid in
                both places. BSEE proposed this clarification to help ensure the
                drilling fluid weight is fully evaluated and appropriate for the
                estimated bottom hole pressures.
                [[Page 21933]]
                Summary of Final Rule Revisions
                 BSEE received a few comments in general support of the proposed
                revisions to this section, and is including the proposed language in
                the final rule without change.
                What must my drilling prognosis include? (Sec. 250.414)
                 This section of the existing regulations describes the information
                that must be included in the drilling prognosis portion of an APD.
                Summary of Proposed Revisions
                 BSEE proposed to revise paragraph (c)(3) of this section to add the
                words ``and analogous'' before ``well behavior observations'' and ``,
                if available'' at the end of the paragraph. BSEE proposed this minor
                wording change to ensure that operators use available data from wells
                with similar conditions to those of the well being drilled when
                determining the pore pressure and fracture gradient to ensure accuracy
                and safety when establishing the drilling margin. In the proposed rule,
                BSEE solicited comments on many of the safe drilling margin provisions,
                including potential alternatives to the current default 0.5 ppg
                drilling margin and the possibility of replacing it with a more
                performance-based standard.
                Summary of Final Rule Revisions
                 The 0.5 ppg drilling margin requirements in this section remain
                unchanged. As in the existing regulations, the final rule requires the
                use of a default 0.5 ppg drilling margin while continuing to allow for
                a deviation from the default under certain circumstances. The request
                to deviate does not have to be submitted as an alternate procedure or
                departure request. However, as the proposed rule indicated, BSEE
                considered whether to allow a different method or ``avenue'' for
                operators to submit a justification for a different drilling margin (83
                FR 22133). Based on comments received, BSEE is revising Sec.
                250.414(c)(2) to allow operators the option to submit the required
                justification for BSEE approval at an earlier date prior to the APD.
                Any such approval will be contingent upon confirmation in the APD that
                the plans and information underlying the BSEE approved justifications
                have not changed. An operator may submit such requests prior to an APD,
                or continue to provide that information within the APD. Regardless of
                the timing of the request to use an alternative drilling margin, each
                request will require the supporting justifications as provided in
                existing regulations. BSEE is currently approving some APDs with
                drilling margins other than 0.5 ppg based on specific well conditions.
                Summary of Comments
                Comments Related to Proposed Sec. 250.414--Opposition to Any Proposed
                Revisions to the 0.5 ppg Safe Drilling Margin
                 Summary of comments: Multiple commenters expressed significant
                concerns about potential revisions to the 0.5 ppg safe drilling margin
                requirements and emphasized the importance of a safe drilling margin.
                Many commenters also asserted that the 0.5 ppg margin was added to the
                existing regulations based on the technical work and recommendations
                from the National Academy of Engineering and the National Research
                Council arising out of Deepwater Horizon investigations and that any
                proposed changes to or removal of the safe drilling margin requirements
                lack technical evidence or justification. Commenters asserted that BSEE
                must have clear, defined, and enforceable criteria to determine whether
                the proposed drilling margin will be safe and cannot simply accept an
                operator's conclusory statements that its proposal is safe.
                 Response: BSEE agrees with the commenters' concerns about
                making revisions to the 0.5 ppg drilling margin requirements at this
                time. BSEE is keeping the 0.5 ppg drilling margin as a presumptive
                minimum requirement as a default standard in the regulations. As more
                drilling margin data and research becomes available, BSEE may
                reevaluate the drilling margin for possible revisions in future
                rulemakings.
                Comments Related to Proposed Sec. 250.414--Use of a Performance-Based
                Drilling Margin
                 Summary of comments: Multiple commenters expressed support for
                revising or removing the 0.5 ppg safe drilling margin default standard
                requirement. Some commenters recommended replacing the current
                requirements with a performance-based standard established on a case-
                by-case basis, based on data and analysis specific to a particular
                well. Those commenters asserted that this would be a safer and better
                alternative for establishing safe drilling margins. They asserted that
                such an alternative would provide a risk-based approach that ensures
                safety and provides investment certainty to the industry. Some
                commenters also suggested that industry would welcome the opportunity
                to propose an engineered, performance-based standard for the
                establishment of appropriate safe drilling margins through the well
                permitting process. Some commenters asserted that technology has
                improved to justify a performance-based drilling margin, specifically
                citing hydraulic modeling techniques, managed pressure drilling, and
                use of real-time downhole pressure while drilling (PWD).
                 Response: BSEE does not accept the commenters'
                recommendations to replace the 0.5 ppg drilling margin with a
                performance-based option. BSEE notes, however, that existing
                regulations provide opportunities for similar case-by-case analyses
                based on specific well conditions. The regulations establish default
                minimum requirements; however, they also allow for deviation from the
                default 0.5 ppg drilling margin with sufficient justification, based on
                demonstrated well conditions and operational plans. It is the
                operator's responsibility to provide sufficient data and justification
                to use a lower drilling margin. BSEE is retaining the 0.5 ppg drilling
                margin as a presumptive minimum requirement as a default standard in
                the regulations. As more drilling margin data and research becomes
                available, BSEE may reevaluate the drilling margin for possible
                revisions in future rulemakings.
                 BSEE agrees that technology is improving and could help justify a
                performance-based drilling margin at some point. However, BSEE would
                need to obtain and evaluate more research and data before it can
                develop and adopt a performance-based drilling margin. In the meantime,
                an operator may use the improved technologies cited by the commenters
                to substantiate an alternative drilling margin specified in an APD,
                provided it complies with the requirement in existing Sec.
                250.414(c)(2) regarding adequate documentation to justify the
                alternative margin.
                Comments Related to Proposed Sec. 250.414--Drilling Margin Below 0.5
                ppg
                 Summary of comments: Some commenters asserted that evaluation and
                analysis of industry data on wells drilled demonstrates that operators
                have safely planned and drilled sections of wells below the current
                default 0.5 ppg drilling margin and that the current 0.5 ppg margin is
                arbitrary and does not ensure safety.
                 Response: BSEE agrees with the commenters that operators
                have successfully drilled some wells below the default 0.5 ppg drilling
                margin under the current regulations. As noted in the proposed rule,
                between promulgation of that default margin in
                [[Page 21934]]
                the 2016 WCR and publication of the proposed rule, BSEE approved the
                drilling of 32 wells with drilling margins below the 0.5 ppg default.
                Operators may continue to utilize drilling margins below 0.5 ppg
                provided that they apply for such a margin in their APDs and comply
                with the requirements in Sec. 250.414(c)(2) by providing adequate
                documentation to justify the alternative drilling margin. However, BSEE
                disagrees with the commenters' assertion that the 0.5 ppg margin is
                arbitrary and does not ensure safety. A 0.5 ppg is an appropriate safe
                drilling margin for normal drilling scenarios, and, prior to the
                promulgation of the 2016 WCR, BSEE approved (and thus made a
                requirement) this margin in numerous APDs. BSEE understands that there
                are some well-specific circumstances that may justify an acceptable
                lower drilling margin to drill a well safely and BSEE has approved
                appropriate alternative downhole mud weights as part of a safe drilling
                margin in many APDs. However, BSEE is choosing not to alter the 0.5 ppg
                default drilling margin in this final rule.
                 Summary of comments: A commenter recommended adding the Conceptual
                Deepwater Operations Plan (CDWOP or DWOP) into the regulatory text with
                the objective of obtaining field-wide approvals when it is anticipated
                that a lower drilling margin may be needed on numerous wells. The
                commenter asserted that this would be important for sanctioning major
                capital projects, since regulatory certainty is critical when making
                multi-billion dollar investment decisions. In particular, the commenter
                asserted that industry needs clarity on the requirements for permit
                approval and reasonable certainty that BSEE will approve an engineered
                drilling margin before incurring major costs that would be wasted if
                approval were denied.
                 Response: BSEE declines to accept the commenter's
                suggestion. The DWOP or CDWOP is a field overview and not well-
                specific. The operator submits a DWOP for each development project in
                which it will use non-conventional production or completion technology,
                however that submission does not include the full scope of relevant
                information required in the APD. BSEE does not believe that the
                relevant determinations can be reached at a field level through the
                DWOP process, as opposed to the well-specific level. However, BSEE
                recognizes that the timing of drilling margin approval may affect
                sanctioning of major capital projects, and BSEE is revising Sec.
                250.414(c)(2) to allow operators the option to submit the required
                justification for a proposed alternative safe drilling margin for BSEE
                approval at an earlier date prior to the APD. Any such approval will be
                contingent upon confirmation in the APD that the plans and information
                underlying the BSEE approved justifications have not changed. BSEE is
                not revising the requirements to use a default 0.5 ppg drilling margin
                or the standards for obtaining approval of a deviation from the default
                under certain circumstances. As such, this change will have no impact
                on safety or environmental protection. The revision to Sec.
                250.414(c)(2) will simply provide operators with the option to request
                BSEE approval for alternative safe drilling margins on a well-by-well
                basis at any time that the necessary information is available. BSEE
                drilling engineers review drilling margins and the APD with intimate
                knowledge of the particular field and are the subject matter experts on
                drilling in their respective BSEE regions.
                What well casing and cementing requirements must I meet? (Sec.
                250.420)
                 This section of the existing regulations imposes specific
                requirements for casing and cementing of all wells.
                Summary of Proposed Revisions
                 BSEE proposed to incorporate by reference API Standard 65--Part 2
                in paragraph (a)(6) of this section for purposes of specifying the
                standards to ensure centralization of the pipe during cementing. BSEE
                determined that the standards set forth in API Standard 65--Part 2
                would provide clearer guidelines for operators than the existing
                regulatory language.
                Summary of Final Rule Revisions
                 BSEE received a few comments in general support of the proposed
                revisions to this section and is including the proposed language in the
                final rule without change.
                What are the casing and cementing requirements by type of casing
                string? (Sec. 250.421)
                 This section of the existing regulations specifies casing and
                cementing requirements applicable to certain types of casing strings
                (e.g., drive or structural strings, conductor strings).
                Summary of Proposed Revisions
                 BSEE proposed to make minor revisions in paragraphs (c), (d), (e),
                and (f) to clarify that all identified length requirements are to be
                taken from measured depth. This clarification of the existing
                regulatory requirements would provide consistency for planning and
                permitting purposes. Also, in paragraph (f), BSEE proposed removing the
                specifics of the listed example regarding when a liner may be used as
                intermediate casing. The proposed rule stated that the example is
                redundant because it restates the same information already contained in
                this section.
                Summary of Final Rule Revisions
                 BSEE received a few comments in general support of the proposed
                revisions to this section, and is including the proposed language in
                the final rule without change.
                What are the requirements for casing and liner installation? (Sec.
                250.423)
                 This section of the existing regulations establishes requirements
                for proper installation of casing in the subsea wellhead or liner in
                the liner hanger, including requirements for latching or lock down
                mechanisms and pressure testing on the seal assembly.
                Summary of Proposed Revisions
                 BSEE proposed to revise paragraphs (a) and (b) by removing the
                words ``and cementing'' after ``upon successfully installing.'' The
                proposed rule explained that revisions to this section are necessary
                because there are many situations in the design of the casing or liner
                string running tool where the latching or lock down mechanism is
                automatically engaged upon installing the string. BSEE proposed these
                revisions to allow more flexibility on an operational, case-by-case
                basis for determining the appropriate time to engage these mechanisms
                and thus reduce the number of alternate procedure requests submitted to
                BSEE for approval under Sec. 250.141.
                Summary of Final Rule Revisions
                 BSEE received and considered comments on the proposed revisions and
                includes the proposed revisions in the final rule. Additionally, as
                suggested by some commenters, BSEE is revising paragraphs (a) and (b)
                by removing from each the following language: ``If there is an
                indication of an inadequate cement job, you must comply with Sec.
                250.428(c).'' These statements are unnecessary because Sec. 250.428(c)
                is applicable for any cementing operation and does not need to be
                specifically cross referenced in this section. Removing this cross
                reference does not change any requirements for how operators must
                respond to indications of an inadequate cement job; if there are any
                indications of an inadequate cement
                [[Page 21935]]
                job, the operator must evaluate the cement job as required in Sec.
                250.428.
                Summary of Comments
                 Summary of comments: Many commenters agreed with the proposed
                changes, and also asserted that references to section Sec. 250.428 in
                this section were redundant and should be removed from this section.
                 Response: BSEE agrees with the commenters that referencing
                Sec. 250.428 is not necessary in this section, and has revised the
                final regulatory text accordingly. This language is unnecessary because
                Sec. 250.428(c) is applicable for any cementing operation and thus
                does not need to be specifically cross-referenced in paragraphs (a) and
                (b). Removing this cross-reference does not change any requirements for
                how operators must respond to indications of an inadequate cement job;
                if there are any indications of an inadequate cement job, the operator
                must evaluate the cement job as required in Sec. 250.428.
                 Summary of comments: A commenter expressed concerns that the
                proposed revisions to this section would compromise safety and asserted
                that BSEE failed to explain why its prior rationale for the language of
                Sec. 250.423 contained in the 2016 WCR was inaccurate or no longer
                applies. The commenter recommended retaining the current regulatory
                requirements.
                 Response: BSEE disagrees that this revision compromises
                safety or is inaccurate and inconsistent with prior rationale. After
                further BSEE review since the 2016 WCR, and as discussed in the
                proposed rule, some of these latching or locking mechanisms are
                designed to automatically engage upon installation of the associated
                string. The revisions made by this final rule continue to ensure the
                lock down mechanisms are properly securing the appropriate liner or
                casing in place to ensure wellbore integrity while eliminating
                inconsistency between the existing regulatory text and certain common
                designs of the relevant mechanisms.
                What are the requirements for pressure integrity tests? (Sec. 250.427)
                 This section in the current regulations specifies the requirements
                for conducting pressure integrity testing. This section also requires
                the operator to revise its drilling program based upon pressure
                integrity testing and hole behavior observations and requires the
                operator to maintain the safe drilling margin while drilling.
                Summary of Proposed Revisions
                 BSEE did not propose any revisions to this section. BSEE did,
                however, solicit comments regarding potential alternative approaches to
                administering the safe drilling margin requirements, including
                specifically ``whether there are situations where drilling can continue
                prior to receiving alternative safe drilling margin approval from
                BSEE,'' such as ``where, despite not being able to maintain the
                approved safe drilling margin, an operator's continued drilling with an
                alternative drilling margin creates little risk'' and ``what level of
                follow-up reporting . . . would be appropriate.''
                Summary of Final Rule Revisions
                 Based upon comments received, BSEE is revising paragraph (b) to
                require notification to the BSEE District Manager in the event the
                required safe drilling margin cannot be maintained, and to incorporate
                API Bulletin 92L as a standard for further action, where appropriate.
                In conjunction with the incorporation of API Bulletin 92L, BSEE is
                requiring submittal of a revised permit documenting any responsive
                actions taken to remedy lost circulation. BSEE is also clarifying that
                the District Manager must review and approve any proposed remedial
                actions where the operator suspends drilling operations in response to
                an inability to maintain the drilling margin.
                Summary of Comments
                Comments Related to Proposed Sec. 250.427--Incorporation of API
                Bulletin 92L
                 Summary of comments: Many commenters requested that BSEE
                incorporate API Bulletin 92L, in accordance with NTTAA requirements,
                for managing certain well conditions such as mud losses. The commenters
                asserted that this document was developed by API with BSEE
                participation to provide detailed operational direction in the event of
                lost circulation while drilling in the Gulf of Mexico. The commenters
                asserted that it is appropriate for operators to specify, in the well's
                DWOP or APD, how they will remedy an anticipated loss of circulation on
                bottom. They also asserted that, if an operator experiences an
                unanticipated loss of circulation or a reduced drilling margin, the
                operator should provide notice and the operator's plan for remedying
                the issue to BSEE within a reasonable timeframe.
                 Response: For the reasons explained in part III.B.1 of
                this notice, BSEE agrees with the commenters' recommendations to
                incorporate API Bulletin 92L. BSEE is revising Sec. 250.427(b) to
                allow operators to take action in accordance with API Bulletin 92L, and
                provide notification to the BSEE District Manager documenting the
                operator's use of API Bulletin 92L, when the operator cannot maintain
                its approved drilling margin. In conjunction with the use of API
                Bulletin 92L, BSEE is requiring submittal of a revised permit
                documenting any remedial actions. BSEE has evaluated API Bulletin 92L
                and determined that reliance on that standard when responding to
                drilling margin issues would not reduce safety. BSEE also determined
                that this document is consistent with BSEE policy in the approaches
                used to address these issues, appropriate for meeting the agency's
                regulatory needs, and preferable to an agency-developed standard. API
                Bulletin 92L includes flow charts that can be used as an aid to safely
                drill ahead when lost circulation occurs and the required criteria and
                procedures are met.
                What must I do in certain cementing and casing situations? (Sec.
                250.428)
                 This section of the existing regulations describes actions that
                must be taken when certain situations (e.g., unexpected formation
                pressures) are encountered during casing or cementing operations.
                Summary of Proposed Revisions
                 BSEE proposed to revise paragraph (c) to include the term
                ``unplanned'' when describing the lost returns that provide indications
                of an inadequate cement job. BSEE proposed this revision to minimize
                the number of unnecessary revised permits submitted to BSEE for
                approval. Current cementing practices utilize improved well modelling
                to identify and account for zones that may have anticipated losses that
                are not indicative of an inadequate cement job.
                 BSEE proposed to redesignate existing paragraph (c)(iii) as new
                paragraph (c)(iv) and to add new paragraph (c)(iii) to allow the use of
                tracers in the cement, and the logging of the tracers' location prior
                to drill out, as an alternative approach for locating the top of
                cement. BSEE proposed this addition to provide more viable options and
                more flexibility for locating top of cement, without compromising
                safety, in order to help minimize rig down time from running in and out
                of the hole multiple times.
                 In addition, BSEE proposed a revision to paragraph (d) to clarify
                that, if there is an inadequate cement job, operators are required to
                comply with Sec. 250.428(c)(1). This revision would help assess the
                overall cement job to
                [[Page 21936]]
                allow for improved planning of remedial actions.
                 BSEE also proposed to revise paragraph (d) to allow BSEE to pre-
                approve remedial cementing actions through a contingency plan within
                the original approved permit. BSEE proposed to allow operators to
                include the remedial actions as contingency plans in the original APD,
                for BSEE to consider for pre-approval, in order to minimize the time
                necessary for operators to commence approved remedial cementing
                actions, and to reduce burdens on operators and BSEE resulting from
                multiple submissions of revised permits. However, the rule clarifies
                that, if BSEE has not already approved the remedial actions, the
                operator must submit the remedial actions in a revised permit
                application for BSEE review and approval.
                Summary of Final Rule Revisions:
                 BSEE received and considered comments on these provisions of the
                proposed rule and includes the proposed language in the final rule
                without change.
                Summary of Comments
                Comments Related to Proposed Sec. 250.428(d)--Use of a Professional
                Engineer (PE)
                 Summary of comments: A commenter opposed the proposal to allow pre-
                approval of remedial cementing actions in lieu of requiring [acy]
                [Rcy][IEcy] approval at the time, asserting that pre-approval would be
                hypothetical since the problem to b[iecy] remedied would not b[iecy]
                known at the time of approval.
                 Response: BSEE disagrees with the commenter. PE
                certification of the remedial actions may be included in the original
                permit, if the operator is able to anticipate where losses may occur
                (e.g., depleted zones, known geology). The PE may review the proposed
                remedial actions in the original permit to ensure integrity and
                consistency with BSEE's regulations. If the operator chooses to include
                contingency planning in the original permit application, those
                contingencies would be reviewed and certified by the PE. If the
                operator encounters circumstances that the approved permits do not
                address (including PE certification), it would be required to submit a
                revised permit for BSEE approval that would include the PE
                certification. Accordingly, the commenter's concern that the problem
                would not be known at the time of approval is addressed by the fact
                that any approval will reach only those issues foreseen and considered
                at the time of approval; if the issue that arises was not considered
                and approved for remedial action, the operator must obtain separate
                approval to remedy the actual issue presented.
                Comments Related to Proposed Sec. 250.428--Unplanned Versus
                Unanticipated Lost Returns
                 Summary of comments: A commenter suggested that the proposed
                wording change should be ``unanticipated lost returns'' instead of
                ``unplanned lost returns.''
                 Response: BSEE disagrees with commenter. This change is
                not necessary because certain lost returns can be planned for within a
                BSEE-approved permit, and the information can be identified, included,
                and approved within the permit. Further, there can be lost returns that
                an operator may not ``anticipate'' occurring, but which the operator
                nevertheless may be able to plan for in advance, should they occur. The
                key is whether the operator has an acceptable plan in place for
                addressing the lost returns, regardless of whether it anticipates them
                occurring or not. If an operator encounters circumstances that are not
                described in an approved permit, such as unplanned lost returns, then a
                new BSEE approval would be required at that time.
                Comments Related to Proposed Sec. 250.428(c)(1)--Use of a Casing Shoe
                Test
                 Summary of comments: Some commenters suggested that BSEE add the
                use of a casing shoe test to locate the top of cement.
                 Response: BSEE disagrees with commenter. A casing shoe
                test by itself does not confirm cement integrity behind the casing/
                liner or verify the top of cement (TOC).
                Comments Related to Proposed Sec. 250.428(c)(1)(iii)--Use of Tracers
                 Summary of comments: Some commenters expressed concerns about the
                proposed language to require logging of the tracers prior to drill out.
                The commenters recommended removal of ``prior to drill out.'' The
                commenters asserted that tracers are meant to be used when the losses
                are more likely, and that operators should be able to find the TOC
                through the use of bottom hole assembly (BHA) measurement while
                drilling (MWD).
                 Response: BSEE does not accept the commenters' suggested
                removal of ``prior to drill out.'' The addition of tracers to this
                section allows operators another option for determining if the cement
                job is adequate. The commenters incorrectly assumed that BSEE is
                requiring an additional logging run to confirm the location of the
                tracers; however, BSEE expects that operators will still be able to
                locate the TOC by logging tracers with the BHA.
                Comments Related to Proposed Sec. 250.428(c)--Evaluation Logs
                 Summary of comments: A commenter suggested that BSEE require a
                cement evaluation log in complex, higher risk wells and for wells in
                environmentally sensitive locations. The commenter asserted that
                temperature and tracer logs will indicate the cement top, but will not
                provide information on cement quality throughout the entire cement
                column. The commenter also asserted that a cement evaluation log
                provides substantially more information on cement placement and
                quality. The commenter also suggested that if remedial cementing is
                needed, a cement evaluation log should be run to verify the repair.
                 Response: BSEE agrees with the commenter that a cement
                evaluation log helps determine cement placement and the overall quality
                of the cement job. However, BSEE disagrees with the commenter's
                suggestion that a cement evaluation log is necessary for the specified
                wells even when there is not an indication of an inadequate cement job.
                BSEE requires other tests to help confirm well and cement integrity
                (e.g., pressure integrity testing required in existing Sec. 250.427).
                The purpose of paragraph (c) is to help determine whether remedial
                actions are necessary when there is an indication of an inadequate
                cement job, and BSEE's regulations offer the option to run cement
                evaluation logs to determine the TOC. Furthermore, BSEE also has the
                discretion to require additional logs if warranted on a case-by-case
                basis.
                Comments Related to Proposed Sec. 250.428(d)--Use of Flow Charts
                 Summary of comments: A commenter recommended the addition of
                language to allow the use of approved operator flow charts to determine
                the extent and timeliness of the remedial actions in lieu of BSEE-
                approved permits.
                 Response: BSEE declines to expressly include a reference
                in the regulations that would allow the use of operator flow charts for
                remedial actions in lieu of a BSEE-approved permit. If a cement job is
                deemed inadequate according to the criteria specified in the existing
                regulations, then the operator must take remedial actions. BSEE does
                not limit the information that is submitted within a permit application
                for BSEE review and approval. An operator may submit flow charts in the
                permit application outlining the
                [[Page 21937]]
                proposed remedial actions, if it so chooses. BSEE may consider approval
                of such flow charts as part of the operator's remedial actions. But
                flow charts will not replace permits in the approval process.
                What are the diverter actuation and testing requirements? (Sec.
                250.433)
                 This section of the existing regulations describes the requirements
                for diverter actuation, pressure testing, and vent line flow testing.
                Summary of Proposed Revisions
                 BSEE proposed to revise existing paragraph (b) to modify
                requirements for subsequent diverter testing after the initial test, by
                allowing partial activation of the diverter element and by not
                requiring a flow test. BSEE proposed these changes to codify
                longstanding BSEE policy, minimize the number of alternate procedure
                requests submitted to BSEE, and help minimize the possibility of
                accidental discharge of mud overboard during full flow testing.
                Summary of Final Rule Revisions
                 BSEE received and considered multiple comments regarding this
                proposed provision, including a number in general support, and includes
                the proposed language in the final rule without change.
                Summary of Comments
                Comments Related to Proposed Sec. 250.433--Opposition to Proposed
                Changes
                 Summary of comments: A commenter opposed the proposed changes
                asserting that the proposed rule did not adequately define the proposed
                reduced diverter system testing or demonstrate that the new test
                regimen would provide a level of safety equivalent to the existing test
                requirements.
                 Response: BSEE disagrees with the commenter. The final
                rule requirements will improve the existing regulation and will ensure
                safety at least equivalent to the existing requirements. The revisions
                will minimize the risk of hydrocarbons or mud inadvertently being
                discharged overboard during subsequent testing while ensuring
                functionality and integrity of the components by requiring the partial
                activation. Furthermore, BSEE still requires actuation of the diverter
                sealing element, diverter valves, and diverter control systems upon
                installation, and a flow test of the vent lines as required in existing
                Sec. 250.433.
                What are the requirements for directional and inclination surveys?
                (Sec. 250.461)
                 This section of the existing regulations specifies operational
                requirements for conducting surveys in vertical and directional wells.
                Summary of Proposed Revisions
                 BSEE proposed to revise paragraph (b) by extending the maximum
                permitted survey intervals during angle-changing portions of
                directional wells from 100 feet to 180 feet. This would account for the
                majority of the pipe stand lengths in use and would address
                technological developments that BSEE has accommodated through approvals
                of alternative procedures under Sec. 250.141 since before the 2016
                WCR.
                Summary of Final Rule Revisions
                 BSEE received a few comments in general support of the proposed
                revisions to this section, and is including the proposed language in
                the final rule without change.
                What are the source control, containment, and collocated equipment
                requirements? (Sec. 250.462)
                 This section of the existing regulations outlines the requirements
                for BSEE approval of the operator's source control and containment
                capabilities, including a determination of the source control and
                containment equipment capabilities, assurance of access to the
                equipment, and ability to deploy Source Control and Containment
                Equipment (SCCE). This section also includes maintenance, inspection,
                and testing requirements for specified containment equipment.
                Summary of Proposed Revisions
                 In paragraph (b) of this section, BSEE proposed to clarify that the
                SCCE to which operators need to have access is based on the
                determinations regarding source control and containment capabilities
                required in Sec. 250.462(a). BSEE also proposed to clarify that the
                identified list of equipment represents examples of the types of SCCE
                that may be determined appropriate in specific circumstances rather
                than equipment that is universally required.
                 BSEE proposed revisions to paragraph (e)(1)(ii) to replace the
                phrase ``a BSEE approved verification organization'' with the phrase
                ``an independent third party.''
                 BSEE also proposed revisions to paragraph (e)(3) to clarify that
                subsea utility equipment utilized solely for containment operations
                must be available for inspection at all times. BSEE proposed revising
                paragraph (e)(4) to clarify that it is applicable only to collocated
                equipment identified in the Regional Containment Demonstration (RCD) or
                Well Containment Plan and not to all collocated equipment. BSEE
                proposed revisions to both paragraphs (e)(3) and (e)(4) to help ensure
                that the equipment described in those paragraphs is available for BSEE
                inspection.
                Summary of Final Rule Revisions
                 BSEE received and considered multiple comments in support of and in
                opposition to the proposed changes. BSEE is including the proposed
                language in the final rule. BSEE is also including in this final rule
                an administrative revision to paragraph (e)(2)(i) to reflect the
                correct cross-reference to the Subpart H regulations. This change is
                technical, non-substantive, and necessary due to the updated citations
                from another recently published BSEE rulemaking, Final Rule: Oil and
                Gas and Sulphur Operations on the Outer Continental Shelf--Oil and Gas
                Production Safety Systems (83 FR 49216, September 28, 2018) which
                updated the production safety systems requirements of Subpart H.
                Summary of Comments
                Comments Related to Proposed Sec. 250.462--SCCE Availability
                 Summary of comments: Some commenters opposed the proposed revisions
                to this section, asserting that the proposed changes would weaken the
                requirements to have SCCE available, and could significantly increase
                the time involved to control a major oil spill.
                 Response: BSEE disagrees with these comments. The
                dedicated equipment at issue is used solely for containment and must be
                available for inspection by BSEE at all times, and the location of this
                collocated equipment will be provided to BSEE. The equipment required
                for the specific well location is determined based on the operator's
                RCD or Well Containment Plan (WCP). As discussed in the proposed rule,
                the majority of SCCE, such as capping stacks and top hats, has no other
                commercial purpose and is used solely for containment operations. This
                unique containment equipment is maintained and readily available for
                inspection by BSEE at any time and would be available for immediate use
                if a well control event occurs. Other equipment listed for source
                control that has broader commercial purposes, such as ROVs and vessels,
                are also required to be readily available. The clarifying revisions to
                these regulatory provisions
                [[Page 21938]]
                do not weaken these key safety elements.
                Subpart E--Oil and Gas Well-Completion Operations
                Tubing and Wellhead Equipment (Sec. 250.518)
                 This section of the existing regulations outlines the completion
                operational requirements for tubing, wellhead equipment, subsurface
                safety equipment, and packers and bridge plugs.
                Summary of Proposed Revisions
                 BSEE proposed revisions to paragraph (e)(1) to clarify that only
                permanently installed packers or bridge plugs, which are qualified as
                mechanical barriers, are required to comply with ANSI/API Spec. 11D1.
                BSEE proposed these changes to ensure that the packers and bridge plugs
                utilized as required mechanical barriers are ANSI/API Spec. 11D1
                compliant, while eliminating the requirement that packers and plugs
                used for other, non-critical, purposes meet the standard.
                Summary of Final Rule Revisions
                 BSEE received and considered comments on the proposed revisions
                and, based on that review, BSEE is revising paragraph (e)(1) in this
                final rule to further clarify that the ``uppermost'' permanently
                installed packer and ``all permanently installed'' bridge plugs, which
                qualify as a mechanical barrier, must comply with ANSI/API Spec. 11D1.
                These revisions provide further clarity about what packers and bridge
                plugs are covered by this section and codify BSEE policy that has been
                in place since the implementation of the 2016 WCR. Also based on BSEE's
                consideration of comments received on the proposed rule, BSEE is adding
                in the final rule a new paragraph (g) to require operators to ``have
                two independent barriers, one being mechanical, in the exposed center
                wellbore prior to removing the tree and/or well control equipment.''
                Summary of Comments
                Comments Related to Proposed Sec. 250.518--Barrier clarification
                 Summary of comments: Multiple commenters supported the proposed
                clarification of this section. However, one commenter expressed
                concerns that there would b[iecy] confusion about the use of mechanical
                barriers designed for other operations during well completion or
                workovers. The commenter asserted that identification of the proper
                barriers should b[iecy] stated in the well control plan to eliminate
                any potential confusion.
                 Response: BSEE agrees with the commenters who expressed
                general support for the proposed revisions. BSEE also agrees to some
                extent with one commenter's concerns about potential confusion
                regarding the mechanical barriers language in the proposed changes to
                Sec. 250.518, Tubing and Wellhead Equipment. The required mechanical
                barriers are specific to the associated operation (workover,
                completion, or decommissioning) and the regulatory text should be clear
                and consistent with similar requirements. Based on the consideration of
                this comment, BSEE revised the language in final Sec. 250.518 to be
                consistent with the language in final Sec. 250.619, pertaining to
                workover operations. During comment review, BSEE determined that it
                should add a new final paragraph (g) that mimics the language proposed
                for Sec. 250.619, Tubing and wellhead equipment, to address the
                circumstance of well control equipment being unlatched during initial
                completion operations. This language is consistent with how BSEE has
                implemented this regulation, and BSEE is making this addition to
                further clarify the intent to have two barriers in place prior to
                removing the tree or well control equipment. This addition reflects
                current BSEE requirements and operational practice. However, BSEE
                disagrees with the commenter's suggestion that the barriers should be
                identified in the well control plan, as these mechanical barriers are
                identified within the well schematics submitted in BSEE permit
                applications.
                What are the requirements for casing pressure management? (Sec.
                250.519)
                 This section of the existing regulations requires casing pressure
                management and adherence to specified industry standards and the
                requirements of this subpart.
                Summary of Proposed Revisions
                 BSEE proposed minimal revisions to this section in order to update
                incorrect citations. These revisions are administrative in nature and
                ensure that the appropriate citations are correctly cross referenced.
                Summary of Final Rule Revisions
                 BSEE received a few comments in general support of the proposed
                revisions to this section and is including the proposed language in the
                final rule without change.
                How do I manage the thermal effects caused by initial production on a
                newly completed or recompleted well? (Sec. 250.522)
                 This section of the existing regulations specifies operational
                requirements regarding thermal casing pressure during initial startup.
                Summary of Proposed Revisions
                 BSEE proposed minimal revisions to this section to update incorrect
                citations. These revisions are administrative in nature and ensure that
                the appropriate citations are correctly cross referenced.
                Summary of Final Rule Revisions
                 BSEE received a few comments in general support of the proposed
                revisions to this section and is including the proposed language in the
                final rule without change.
                When am I required to take action from my casing diagnostic test?
                (Sec. 250.525)
                 This section of the existing regulations specifies certain
                operational conditions that, when identified in the casing diagnostic
                tests, would require an operator to take actions.
                Summary of Proposed Revisions
                 BSEE proposed minimal revisions to paragraph (d) of this section to
                update incorrect citations. These revisions are administrative in
                nature and ensure that the appropriate citations are correctly cross
                referenced.
                Summary of Final Rule Revisions
                 BSEE received a few comments in general support of the proposed
                revisions to this section and is including the proposed language in the
                final rule without change.
                What do I submit if my casing diagnostic test requires action? (Sec.
                250.526)
                 This section of the existing regulations specifies the required
                submittals in the event of a casing diagnostic test that requires
                action.
                Summary of Proposed Revisions
                 BSEE proposed minimal revisions to this section to update incorrect
                citations. These revisions are administrative in nature and ensure that
                the appropriate citations are correctly cross referenced.
                Summary of Final Rule Revisions
                 BSEE received a few comments in general support of the proposed
                revisions to this section and is including the proposed language in the
                final rule without change.
                [[Page 21939]]
                What if my casing pressure request is denied? (Sec. 250.530)
                 This section of the existing regulations outlines the steps an
                operator must take when BSEE denies its casing pressure request.
                Summary of Proposed Revisions:
                 BSEE proposed minimal revisions to paragraph (b) of this section to
                update incorrect citations. These revisions are administrative in
                nature and ensure that the appropriate citations are correctly cross
                referenced.
                Summary of Final Rule Revisions
                 BSEE received a few comments in general support of the proposed
                revisions to this section and is including the proposed language in the
                final rule without change.
                Subpart F--Oil and Gas Well-Workover Operations
                Definitions (Sec. 250.601)
                 This section in the existing regulations lists the definitions
                specific to workover operations.
                Summary of Proposed Revisions
                 BSEE revises the definition of ``routine operations'' in this
                section to make it consistent with the definition of routine operations
                in Sec. 250.105 by adding paragraph (m) ``Acid treatments.'' The 2016
                WCR did not address this provision, however based on BSEE experience,
                this revision is necessary to help minimize confusion about the
                definition of routine operations.
                Summary of Final Rule Revisions
                 BSEE received a few comments in general support of the proposed
                revisions to this section and is including the proposed language in the
                final rule without change.
                Coiled Tubing and Snubbing Operations (Sec. 250.616)
                 This section of the existing regulations specifies the minimum
                requirements for coiled tubing and snubbing equipment as well as
                operational requirements for conducting workover operations with the
                production tree in place.
                Summary of Proposed Revisions
                 BSEE proposed to remove and reserve this section, and to move the
                content of this section to proposed Sec. 250.750, with minor revisions
                discussed in connection with that provision. BSEE proposed these
                revisions to help eliminate inconsistencies between similar
                requirements throughout different subparts of BSEE's regulations (in 30
                CFR part 250) by consolidating those requirements in Subpart G, which
                is applicable to drilling, completions, workovers, and decommissioning
                operations.
                Summary of Final Rule Revisions
                 BSEE received a few comments in general support of the proposed
                revisions to this section and is including the proposed removal and
                reservation in the final rule without change.
                Tubing and Wellhead Equipment (Sec. 250.619)
                 This section of the existing regulations outlines the workover
                operational requirements for tubing, wellhead equipment, subsurface
                safety equipment, and packers and bridge plugs.
                Summary of Proposed Revisions
                 BSEE proposed to revise paragraph (e)(1) by clarifying that only
                permanently installed packers and bridge plugs that are qualified as
                mechanical barriers are required to comply with ANSI/API Spec. 11D1.
                This revision would codify BSEE's policy developed since promulgation
                of the 2016 WCR, to ensure that the required mechanical barriers in a
                well are held to a higher standard than other common packers or bridge
                plugs used for various well-specific conditions and completions design.
                Furthermore, BSEE is aware that certain packers and bridge plugs cannot
                meet the specifications of ANSI/API Spec. 11D1.
                 BSEE also proposed to require operators to have two independent
                barriers, including one mechanical barrier, in the exposed center
                wellbore prior to removing the tree or well control equipment. This
                addition would codify existing BSEE policy and make the workover
                requirements in Subpart F regarding mechanical barriers similar to
                those already found in existing Sec. 250.720(a).
                Summary of Final Rule Revisions
                 BSEE received and considered comments on the proposed revisions
                and, based on that review, BSEE is revising paragraph (e)(1) in this
                final rule to further clarify that both the ``uppermost'' permanently
                installed packer and ``all permanently installed'' bridge plugs that
                qualify as a mechanical barrier must comply with ANSI/API Spec. 11D1.
                These revisions provide further clarity about what packers and bridge
                plugs are covered by this section and codify BSEE policy that has been
                in place since the implementation of the 2016 WCR. BSEE is also moving
                the phrase ``You must have two independent barriers, one being
                mechanical, in the exposed center wellbore prior to removing the tree
                and/or well control equipment'' from proposed paragraph (e)(1) to new
                final paragraph (g). This administrative change will help clarify the
                requirements in paragraph (e)(1) and confirm that paragraph (g) is a
                stand-alone requirement.
                Summary of Comments
                Comments Related to Proposed Sec. 250.619--Barrier Clarification
                 Summary of comments: Multiple commenters supported the proposed
                clarification of this section for the reasons explained in the proposed
                rule. However, one commenter expressed concerns that there would
                b[iecy] confusion about the use of mechanical barriers designed for
                other operations during well completion or workovers. The commenter
                asserted that identification of the proper barriers should b[iecy]
                included in the well control plan to eliminate any potential confusion.
                 Response: BSEE agrees with the commenters' expression of
                general support for the proposed revisions. BSEE also agrees to some
                extent with one commenter's concerns about potential confusion
                regarding the mechanical barriers language in the proposed changes to
                Sec. 250.518. The required mechanical barriers are specific to the
                associated operation (workover, completion, or decommissioning) and the
                regulatory text should be clear and consistent with similar
                requirements. Based on the consideration of this comment BSEE revised
                the language in final Sec. 250.518 to be consistent with the language
                in proposed and final Sec. 250.619, and modified the proposed
                organization of Sec. 250.619 for clarity and consistency. This
                language is consistent with how BSEE has implemented this regulation,
                and BSEE is making this addition to further clarify the intent to have
                two barriers in place prior to removing the tree or well control
                equipment. This addition reflects current BSEE requirements and
                operational practice. However, BSEE disagrees with the commenter's
                suggestion that the barriers should be identified in the well control
                plan as these mechanical barriers are identified within the well
                schematics submitted in BSEE permit applications.
                [[Page 21940]]
                Subpart G--Well Operations and Equipment
                What rig unit movements must I report? (Sec. 250.712)
                 This section of the existing regulations specifies the requirements
                for reporting to BSEE of rig unit movement on and off location, and
                specifies the required content of the reporting.
                Summary of Proposed Revisions
                 BSEE proposed to revise this section by adding new paragraphs (g)
                and (h). BSEE proposed to add paragraph (g) to clarify that reporting
                is not necessary for rig movements to and from the safe zone during
                permitted operations. BSEE proposed to add paragraph (h) to clarify
                that, if a rig unit is already on a well, BSEE would not require a
                notification for any additional rig unit movements on that well.
                Summary of Final Rule Revisions
                 BSEE received a comment in general support of the proposed
                revisions to this section and is including the proposed language in the
                final rule without change.
                When and how must I secure a well? (Sec. 250.720)
                 This section of the existing regulations outlines the requirements
                for securing a well whenever operations are interrupted (e.g.,
                evacuation of the rig crew, inability to keep the rig on location, and
                repair to major rig or well-control equipment).
                Summary of Proposed Revisions
                 BSEE proposed to revise paragraph (a)(1) to add an impending
                National Weather Service-named tropical storm or hurricane to the list
                of example events that would interrupt operations and require
                notification. Furthermore, BSEE also proposed to add new paragraph
                (a)(3) to include provisions for testing the applicable BOP or LMRP
                upon relatch according to Sec. 250.734 paragraphs (b)(2) or (b)(3),
                respectively, and obtaining BSEE approval before resuming operations.
                BSEE proposed these revisions to codify the BSEE storm policy reflected
                in longstanding guidance and to provide clarity for testing
                requirements when an operator has returned to the well location and
                relatched the BOP or LMRP. BSEE also proposed to add new paragraph (d)
                requiring equipment and capabilities for well intervention and
                specifying that equipment used solely for well intervention must be
                readily available for use, maintained in accordance with applicable OEM
                recommendations, and available for inspection by BSEE upon request.
                BSEE proposed this addition to ensure that when intervention is
                necessary on a well, the applicable tools (such as the tree interface
                tools) are available and ready for their intended use.
                Summary of Final Rule Revisions
                 BSEE received and considered comments on the proposed revisions and
                includes the proposed language in the final rule. Furthermore, based on
                comments received, BSEE is also adding language to paragraph
                (a)(3)(iii) to require that the operator, upon relatch of a BOP or
                LMRP, ``submit a revised permit with a written statement from an
                independent third party certifying that the previous certification in
                Sec. 250.731(c) remains valid. . . .'' This revision will provide BSEE
                with additional assurance that the related equipment is fit for service
                upon relatch and clarifies the necessary submittal and associated
                information required in order to receive District Manager approval.
                This addition reflects current BSEE practice and is the same
                information operators must submit with the required BSEE permits. This
                provides assurance that the specified BOP certifications are still
                valid and provides consistent documentation of recertification.
                Corresponding edits are also made to Sec. Sec. 250.734 and 250.738.
                 BSEE is also revising paragraph (d) to clarify that operators need
                only meet the requirements from the proposed rule for subsea completed
                wells with a tree installed that have a shut-in tubing pressure that is
                greater than the hydrostatic pressure of the water column, or subsea
                wells that are not capable of having the annulus monitored. This
                revision will help ensure that operators have available the appropriate
                intervention tools for wells with higher risk potential, and will
                reduce the unnecessary burden of applying this new requirement to lower
                risk wells.
                Summary of Comments
                Comments Related to Proposed Sec. 250.720(a)--Retesting the Deadman
                System
                 Summary of comments: Some commenters expressed concerns with the
                requirement in Sec. 250.734(b), incorporated here, to re-test the
                deadman systems when they have not been repaired or affected by the
                suspension. The commenters recommend not to test the deadman upon
                relatch. The commenters asserted that, while it is important to verify
                that the system is functional, in cases where the system has not been
                modified, the previous test should be sufficient.
                 Response: BSEE disagrees with the comments. When the
                functional system is disconnected, whether it is modified or not, it is
                important to ensure that the emergency systems are completely
                functional upon reconnection of that system. The deadman system
                functionality is verified by testing that system, as required by this
                regulation.
                Comments Related to Proposed Sec. Sec. 250.720(a)(3)(iii), 734, and
                738--Independent Third Party Re-Verifications
                 Summary of comments: A commenter recommended that BSEE require a
                report from an independent third party if the events listed in Sec.
                250.720(a)(1) would invalidate a verification submitted pursuant to
                Sec. Sec. 250.731(d) and 250.732(c).
                 Response: BSEE agrees with the commenter and added a
                requirement for submitting a revised permit with a written statement
                from an independent third party certifying that the previous
                certification under Sec. 250.731(c) remains valid. BSEE also made
                corresponding edits to similar requirements in Sec. Sec. 250.734 and
                250.738. These revisions help ensure that the BOP is still fit for
                service at the same location following relatch after disconnect.
                Comments Related to Proposed Sec. 250.720(d)--Intervention Equipment
                Requirements
                 Summary of comments: Multiple commenters expressed concerns with
                the proposed requirements related to the availability of intervention
                equipment. Commenters asserted that the proposed requirements were
                ``overly prescriptive'' and would place undue financial burden on
                operators. The commenters proposed replacing Sec. 250.720(d) with
                language that requires operators to prepare and have available a well
                intervention readiness plan based on a risk analysis, and that only
                requires the equipment identified as necessary through that plan to be
                available for use and BSEE inspection. Additionally, one of the
                commenters recommended adding a definition for ``readily available.''
                 Response: BSEE agrees with the commenter's recommendation
                that the operator should determine the required intervention equipment
                based on an analysis of the risks associated with a well. Accordingly,
                BSEE revised proposed Sec. 250.720(d) to limit the intervention
                equipment requirements to subsea completed wells with a tree installed,
                that have a shut-in tubing pressure that is greater than the
                [[Page 21941]]
                hydrostatic pressure of the water column, or that are not capable of
                having the annulus monitored. BSEE wants to ensure that appropriate
                intervention equipment is available and properly maintained for higher
                risk wells, but not to impose unnecessary burdens through application
                of these new requirements to low risk wells. BSEE disagrees with the
                recommendation to define ``readily available'' because it would be
                impractical to establish uniform requirements for the deployment
                timeframe of the intervention equipment due to the variability of
                equipment and logistics for each well location. Operators should not
                rely on SCCE for routine intervention operations where intervention
                equipment is required.
                What are the requirements for prolonged operations in a well? (Sec.
                250.722)
                 This section of the existing regulations specifies actions
                necessary to determine well integrity for operations continuing longer
                than 30 days from a previous casing or liner test. If well integrity
                has deteriorated to a level below minimum safety factors, this section
                requires repairs or installation of additional casing and subsequent
                pressure testing, as approved by the District Manager.
                Summary of Proposed Revisions
                 BSEE proposed to revise the prolonged operations well casing
                reporting requirements in paragraph (a)(2) of this section to clarify
                that BSEE does not require District Manager approval to resume
                operations if an operator conducts a successful pressure test as
                already approved in the applicable permit. BSEE also proposed to
                clarify that operators must document the successful pressure test
                results in the Well Activity Report (WAR), and also proposed minor
                revisions to this paragraph to provide that the calculations are used
                to ``indicate'' not ``show'' that the well's integrity is above the
                minimum safety factors.
                Summary of Final Rule Revisions
                 BSEE received a few comments in general support of the proposed
                revisions to this section and is including the proposed language in the
                final rule without change.
                What additional safety measures must I take when I conduct operations
                on a platform that has producing wells or has other hydrocarbon flow?
                (Sec. 250.723)
                 This section of the existing regulations requires additional safety
                measures (e.g., installation of an emergency shutdown station for the
                production system, and shutting in producing wells for certain rig
                movements) for operations on a platform that has a producing well or
                other hydrocarbon flow.
                Summary of Proposed Revisions
                 BSEE proposed to revise this section by removing the phrase ``or
                lift boat.'' This would primarily impact paragraph (c)(3), which
                requires a shut-in of all producible wells located in the affected
                wellbay when a lift boat moves within 500 feet of the platform until
                the lift boat is in place, secured, and ready to begin operations.
                Summary of Final Rule Revisions
                 BSEE received and considered comments on the proposed revisions and
                includes the proposed language in the final rule without change. BSEE
                received comments in general support of and opposition to the proposed
                changes in addition to the following specific, substantive comments.
                Summary of Comments
                Comments Related to Proposed Sec. 250.723--Lift Boat Activities
                 Summary of comments: A commenter recommended requiring lift boats
                to approach platforms from the opposite side of subsea pipeline
                placement, which the commenter understands is the current industry-
                accepted practice. The commenter also asserted that the specific
                regulations should take into consideration the type of work the lift
                boat is performing to help minimize unnecessary shut-ins.
                 Response: BSEE agrees that operators should consider
                subsea infrastructure when positioning any type of bottom supported
                vessels. BSEE is not including the commenter's recommendations in the
                regulations due to the diverse equipment, multiple possible subsea
                configurations, and varying operational situations presented by
                impacted operations. They are likewise outside the scope of this
                rulemaking. Removal of lift boats from this provision should address
                the commenter's concerns regarding unnecessary shut-ins.
                Comments Related to Proposed Sec. 250.723--Lift Boat Size
                 Summary of comments: Multiple commenters expressed concerns with
                the removal of lift boats from this section. However, the commenters
                also suggested that, if the current regulations are too onerous, the
                shut-in requirement should only apply to lift boats that are above a
                certain size or class, or when lift boats approach during more
                challenging weather or environmental conditions that could make mooring
                more difficult.
                 Response: BSEE generally agrees with the commenter that
                different lift boat sizes may present different risks; however, BSEE is
                not making any changes to this section of the proposed rule. BSEE
                determined that the vast majority of lift boats used on the OCS are
                relatively small compared to the size of a MODU and would not typically
                be expected to have the same operational impacts and potential risks as
                a MODU. BSEE is considering the effects of the size of lift boats for
                potential future rulemakings, and may gather additional information and
                provide guidance on a case-by-case basis for any lift boats that could
                reasonably be expected to have an operational impact comparable to a
                MODU.
                What are the real-time monitoring requirements? (Sec. 250.724)
                 This section of the existing regulations requires operators to
                gather and monitor real-time well data when conducting operations with
                a subsea BOP or with a surface BOP on a floating facility, or when
                operating in an HPHT environment, and to develop a real time monitoring
                (RTM) plan detailing how the operator will develop and utilize RTM.
                Summary of Proposed Revisions
                 BSEE proposed to revise this section by removing many of the
                prescriptive real-time monitoring requirements and moving towards a
                more performance-based approach. BSEE proposed to remove existing
                paragraph (b) with its associated prescriptive requirements, and to re-
                designate existing paragraph (c) as paragraph (b), with minor revisions
                to shift certain prescriptive elements to be more performance-based.
                BSEE also proposed to continue requiring the items in existing
                paragraph (c) in an RTM plan.
                Summary of Final Rule Revisions
                 BSEE received and considered comments on this section, and is
                revising proposed paragraph (a)(2) to clarify that it relates to
                monitoring of ``the well's active fluid circulating system.'' This
                revision would clarify the intent of the 2016 WCR RTM requirements and
                ensure that the system used for circulation of the well fluid is
                properly monitored, while removing any implication that RTM is required
                for fluids not in active circulation. BSEE is also adding back in
                clarifying language similar to the first sentence in existing paragraph
                (b) (with certain prescriptive elements removed), as follows: ``(b) You
                must transmit these data as they are
                [[Page 21942]]
                gathered, barring unforeseeable or unpreventable interruptions in
                transmission, and have the capability to monitor the data, using
                qualified personnel in accordance with a real-time monitoring plan, as
                provided in paragraph (c) of this section.'' BSEE is also re-
                designating proposed paragraph (b) as final paragraph (c) with no other
                changes to the remainder of the proposed section. These revisions
                address comments received about clarifying who will be monitoring the
                data by making that a matter to be addressed in the RTM plan. These
                revisions do not alter the requirements of the substantive RTM
                operational capabilities and what is addressed within the company-
                specific RTM plan.
                Summary of Comments
                Comments Related to Proposed Sec. 250.724--Performance-Based Real Time
                Monitoring Plan
                 Summary of comments: Some of the commenters support the transition
                from prescriptive requirements to a performance-based Real Time
                Monitoring (RTM) plan. The commenters assert that a performance-based
                approach will allow them to develop plans that are tailored to the
                operating conditions, risk profiles, and operator policies and
                procedures for specific wells.
                 Response: BSEE agrees in part with the commenters'
                assertion that a performance-based approach has the potential to align
                an operator's RTM plan more effectively with a specific well's
                operating condition and risk profile. BSEE is establishing an initial
                framework for RTM and may supplement the regulations with additional
                operational provisions as more experience and research becomes
                available.
                Comments Related to Proposed Sec. 250.724--Scope and Applicability of
                Real Time Monitoring Plan
                 Summary of comments: Some of the commenters support limiting the
                scope of RTM plans to drilling operations only and providing operators
                with discretion regarding whether or not to include workover,
                completion, and decommissioning activities in their RTM plans. On the
                other hand, multiple other commenters assert that RTM should apply to
                all operations.
                 Response: BSEE currently requires RTM for all
                operations conducted with a subsea BOP, surface BOP on a floating
                facility, and BOPs used in HPHT environments. BSEE is not making any
                changes to this requirement. As explained in the regulations, the RTM
                requirements are located in Subpart G, which covers operations and
                equipment associated with drilling, completion, workover, and
                decommissioning activities. BSEE agrees with the commenters that RTM
                should apply to drilling, completion, workover, and decommissioning
                operations because all the operations have similar potential hazards
                and risks, and are also usually conducted utilizing the same types of
                rigs and equipment.
                 Summary of comments: Some of the commenters request that BSEE apply
                RTM only to the operations covered in API Standard 53, reduce the data
                retention period for RTM data from 2 years to 90 days, and clarify that
                an RTM monitoring center located onshore is not required.
                 Response: BSEE disagrees with the comments
                regarding restricting the applicability of RTM to the scope of API
                Standard 53 and reducing the data retention timeframes. BSEE believes
                that it is important for the RTM requirements to apply to all
                operations conducted with a subsea BOP, surface BOP on a floating
                facility, and BOPs used in HPHT environments because these types of
                operations usually have the highest potential for hazards and increased
                risks. The regulations allow the operator to tailor its approach toward
                monitoring the specific operational components covered under paragraph
                (a) in the context of the specific rig and operation through the RTM
                plan. BSEE is also establishing an initial framework for RTM and may
                supplement the regulations to include a reduced time period for data
                retention as more experience and research becomes available. For now,
                BSEE believes that the longer data retention window is important to
                ensure the availability of needed data.
                 BSEE agrees with the commenters that an onshore RTM monitoring
                center is not required. With currently available technology, operators
                are capable of using RTM remotely on computers and tablets using web
                based applications. This allows for subject matter experts to utilize
                the data anywhere and at any time as necessary, as detailed in the
                company's RTM plan. BSEE requires the operator to identify in the RTM
                plan how the RTM data will be transmitted and monitored, requires the
                rig personnel and monitoring personnel to be separate individuals, and
                requires certain communication capabilities among personnel, but does
                not prescriptively dictate the establishment of an onshore monitoring
                center.
                Comments Related to Proposed Sec. 250.724--Weakening Real Time
                Monitoring Plan Requirements
                 Summary of comments: Many of the commenters oppose BSEE's proposed
                elimination of prescriptive requirements for RTM plans and adoption of
                a performance-based approach. The commenters also assert that the
                proposed rule: Lacks meaningful standardization of RTM requirements;
                does not provide sufficient oversight if operators are not required to
                transmit data onshore in real time for monitoring by qualified
                personnel; and should not limit the requirements to drilling
                operations. As the basis for opposing the removal of prescriptive
                requirements for RTM plans, many of the commenters cite the findings
                and recommendations of the post-Deepwater Horizon investigations and
                reports as well as the rationales that support the RTM requirements
                found in the 2016 WCR.
                 Response: BSEE is establishing an initial
                framework for RTM and may supplement the regulations with additional
                operational provisions as more experience and research becomes
                available. Even though the 2016 RTM requirements have a compliance date
                of April 29, 2019, a majority of the operators already utilize many of
                the RTM capabilities within their current operations. BSEE was able,
                through increased interaction with these companies, to better
                understand the logistical and operational considerations for
                implementation of the RTM requirements. The 2016 WCR's RTM requirements
                were themselves largely performance-based, relying primarily on the
                operator's development of an RTM plan tailored to its operations but
                built off of core principles. The revisions implemented here do not
                reflect a sea change in philosophy, but rather merely remove certain
                unnecessarily prescriptive elements (e.g., specifying that the RTM data
                must be transmitted onshore, certain communications protocols, and that
                monitoring personnel must be onshore). Notwithstanding the performance-
                based nature of these revisions, BSEE agrees that it is important to
                retain specific requirements concerning data transmission and has
                revised the proposed RTM requirements to preserve content similar to
                the first sentence of existing paragraph (b), due to confusion from the
                commenters about who is allowed to monitor the data. BSEE bases this
                revision on comments received seeking clarification regarding who must
                monitor the data, but does not require changes to RTM operations or the
                contents of the company-specific
                [[Page 21943]]
                RTM plan. This revision clarifies who must monitor the RTM data as
                described in the RTM plan. In accordance with paragraphs (c)(5) and
                (6), BSEE requires the rig personnel and monitoring personnel to be
                separate individuals. Additionally, the updated regulations still
                establish requirements for RTM processes and systems.
                Comments Related to Proposed Sec. 250.724--RTM Verification
                 Summary of comments: Multiple commenters recommend that BSEE
                periodically verify that operators are implementing their RTM plans via
                audits conducted by the agency, a BAVO, or an independent third-party.
                The commenters also recommend that BSEE clarify the process by which
                the implementation of RTM requirements will be verified and enforced.
                 Response: This regulation requires that
                operators develop and implement RTM plans, and specifically requires
                that those plans be made available to BSEE upon request. If BSEE has
                any concerns with an operator's RTM operations, then BSEE may undertake
                inspections and enforcement actions to ensure compliance with the
                regulations. BSEE has additional options such as routine onsite
                inspections or verifications through the permitting process to ensure
                that RTM plans are implemented in compliance with the regulations.
                What are the general requirements for BOP systems and system
                components? (Sec. 250.730)
                 This section of the existing regulations includes requirements for
                the design, fabrication, installation, maintenance, inspection, repair,
                testing, and use of BOP systems and components. This section also
                requires compliance with certain provisions of API Standard 53 and
                several related industry standards, and requires operators to use
                failure reporting procedures.
                Summary of Proposed Revisions
                 BSEE proposed to revise paragraph (a) by removing ``excluding
                casing shear'' and replacing ``at all times'' with ``in the event of
                flow due to a kick.'' BSEE requires the BOP system as a whole to be
                capable of closing and sealing the wellbore. BSEE also proposed to
                clarify that the BOP system must be able to close and seal the wellbore
                in the event of flow due to a kick. BSEE knows there are mechanical and
                operational design limits of equipment, and expects operators to ensure
                ram closure time and sealing integrity to avoid exceeding those
                operational and mechanical limits.
                 BSEE proposed to amend paragraph (b) to clarify that BSEE expects
                the use of ``applicable'' OEM recommendations for the design,
                fabrication, maintenance, and repair of BOP systems, as well as
                personnel training in their use. The proposed revision to include
                ``applicable'' is necessary because some OEMs may not have specific
                recommendations for every item required by this paragraph.
                 BSEE also proposed to revise the failure reporting requirements in
                paragraph (c) to codify BSEE guidance and current practice. BSEE
                proposed to remove the failure reporting references to ANSI/API Specs
                6A and 16A because the failure reporting process outlined in those
                standards is redundant to API Standard 53 and the remaining
                requirements of this section. Proposed revisions to this paragraph also
                included clarification on submitting failure data and reports to BSEE,
                unless BSEE has designated a third party to collect the data and
                reports, and ensuring that an investigation and failure analysis are
                started within 120 days. BSEE reevaluated the timeframes set forth in
                the 2016 WCR for performing the investigation and failure analysis and
                determined that certain operations would preclude operators from
                meeting the original timeframes. Accordingly, BSEE proposed to require
                that operators start their investigation and failure analysis within
                120 days of the failure. BSEE then proposed a 120-day timeframe for the
                operator to complete the investigation and failure analysis once they
                have started the process.
                 BSEE proposed to revise paragraph (c)(4) to explain that BSEE may
                designate a third party to collect failure data and reports on behalf
                of BSEE, and if it does so, operators must send the failure data and
                reports to the designated third party.
                 BSEE also proposed to revise paragraph (d) by removing the
                reference to a document incorrectly incorporated by reference, and
                incorporating the correct document. The regulations promulgated
                pursuant to the 2016 WCR require that BOP stacks be manufactured
                pursuant to a quality management system certified by an entity that
                meets the requirements of ISO 17011. The reference to the ISO 17011
                standard in the 2016 WCR is incorrect, and BSEE proposed to correct the
                error by incorporating the ISO/IEC 17021-1 standard.
                Summary of Final Rule Revisions
                 BSEE received and considered comments on the proposed revisions,
                and includes in the final rule most of the proposed language without
                change, except for the following revisions to paragraph (c). BSEE is
                revising proposed paragraph (c) by replacing the references to ``BSEE''
                with ``the Chief, Office of Offshore Regulatory Programs (OORP)'' for
                purposes of directing where to send submittals, and adding the address
                for the Chief of OORP in paragraph (c)(4). These revisions clarify to
                whom and where to send failure reporting submittals within BSEE, unless
                BSEE designates a third party to receive that information. Based on
                comments received, BSEE is also clarifying how to request an extension
                to the failure analysis timeframe. BSEE is adding to paragraph (c)(2) a
                requirement that, if an operator cannot complete the investigation and
                analysis within the allotted time, they must submit a request for an
                extension of time detailing how the investigation and analysis will be
                completed. The request for an extension of time must be submitted for
                approval to BSEE through the Chief of OORP.
                Summary of Comments
                Comments Related to Proposed Sec. 250.730--What Are the General
                Requirements for BOP Systems and System Components?
                Casing Shear Ram Requirements
                 Summary of comments: BSEE received a comment regarding the proposed
                changes to Sec. 250.730(a) removing the phrase ``excluding casing
                shear'' from requirements for the BOP. The commenter expressed concern
                that BSEE's justification refers to the fact that BSEE ``expects
                operators to ensure ram closure time and sealing integrity before
                exceeding those operational and mechanical limits.'' The commenter
                asserted that BSEE should clearly define and state these expectations
                in the regulations. The commenter also asserted that BSEE should
                confirm all relevant specifications through their permitting process,
                inspection program, and performance testing requirements, asserting
                that [Acy][Rcy][Iukcy] Standard 53 and [Acy][Rcy][Iukcy] Spec 16D
                include details about the accumulator system that enable BSEE to
                confirm compliance.
                 Response: BSEE disagrees with the comment. The
                requirements in this section ensure that operators properly design,
                install, maintain, inspect, test, and operate each BOP component and
                the entire BOP system. The requirements of this section apply to the
                entire BOP system, including the casing
                [[Page 21944]]
                shear. BSEE requires the BOP system as a whole to be capable of closing
                and sealing the wellbore before exceeding mechanical or operational
                limits of the equipment. BSEE reviews compliance with the incorporated
                documents through the permit and inspection process.
                Comments Related to Proposed Sec. 250.730(c)--Failure Reporting
                Requirements
                 Summary of comments: A commenter recognized BSEE's efforts related
                to the reporting, analysis, and use of failure data. However, the
                commenter was concerned that the proposed changes to failure reporting
                do not provide a clear definition of [acy] reportable failure.
                 Response: BSEE disagrees that the definition of
                failure provided in Sec. 250.730(c)(1) is unclear. The definition
                aligns with the definition used by the Blowout Preventer Reliability
                Joint Industry Project (JIP), a joint effort of the International
                Association of Drilling Contractors (IADC) and the International
                Association of Oil and Gas Producers (IOGP). This definition is
                generally used and understood by the industry and adopted in the
                SafeOCS implementing guidance, which was informed by input from the
                JIP.
                Comments Related to Proposed Sec. 250.730(c)--Timing of Failure
                Investigations
                 Summary of comments: Multiple commenters expressed concern
                regarding the timing requirements related to failure investigations.
                One commenter recognized that BSEE did propose to add additional time
                for the investigation, but asserted that this did not address potential
                extenuating circumstances (operational or investigation related) that
                may prevent the operator from completing an investigation within 120
                days. Therefore, the commenter requested that BSEE include a provision
                in the final rule to address investigations that cannot be completed
                within the allotted time. The commenter proposed that the provision
                require operators to provide a progress report, reasons regarding why
                the investigation was not completed, and a defined period for the
                extension.
                 Response: BSEE disagrees with including a
                provision that would allow operators a blanket extension of the 120
                days to complete the failure analysis. The final rule provides adequate
                time for an operator to initiate and complete a failure analysis. BSEE
                does, however, acknowledge that there may be extenuating circumstances
                that prevent an operator from meeting these timelines. Accordingly, the
                final rule provides that the operator may request an extension to the
                failure analysis timeframes by submitting a request to the Chief, OORP
                and, if appropriate, BSEE may approve an extension. The nature of
                certain operational failures--such as systematic failures, stack pulls,
                and lower marine riser pulls--may warrant additional case-by-case
                consideration, as it is reasonable to expect the related analyses would
                require more time than allowed in the rule. In 2017, only 1.5% of the
                reported failure notifications resulted in an investigation and failure
                analysis that required more than 120 days to complete. BSEE extended
                the timeframe in the final rule to reduce its own administrative burden
                for those cases where extra time could enable the timely resolution and
                completion of an investigation and analysis report. For those rare
                cases requiring more time, BSEE believes that providing for an
                extension request is appropriate and that the request may reasonably be
                expected to include the items recommended by the commenter.
                 Summary of comments: A commenter stressed that the failure
                investigation and submittal of the reports to BSEE should occur as soon
                as practicable, preferably immediately after the failure. The commenter
                asserted that, for conducting a failure investigation and analysis, it
                makes more sense to provide a required time ``from the time equipment
                first becomes available for testing'' and not from the time of the
                incident. In addition, the commenter asserted that, in addition to an
                option for operators to request an extension, there should be a
                provision for BSEE to require an accelerated investigation, if
                warranted by the circumstances. The commenter also suggested that BSEE
                should not tie the failure analysis to continuing well operations,
                asserting that continuing well operations should depend on the
                replacement of the failed equipment with properly functioning
                equipment.
                 Response: BSEE agrees that an investigation and
                failure analysis should occur as soon as practicable after a failure.
                For subsea BOP operations, equipment is not readily available for
                investigation until it is returned to the surface. If BSEE were to tie
                the requirement to begin the investigation and failure analysis to the
                time the equipment becomes available for testing, rather than the time
                of the incident, it could result in delays in commencing the
                investigation. BSEE believes that the new timeframes provide ample time
                for commencing the investigation without leaving the timing open and
                indefinite.
                 BSEE disagrees that a provision is needed for BSEE to require
                accelerated investigations. BSEE has determined that the timeframes
                required by the final rule are reasonable for conducting timely and
                thorough investigations, given that they will generally involve
                multiple parties and complex, large equipment.
                 BSEE disagrees that the continuation of well operations should
                always require the replacement or repair of failed equipment. BSEE
                regulations require redundant components for well control. Thus, in
                some cases, well operations may continue following an equipment
                component failure.
                 Summary of comments: A commenter asserted that allowing the same
                amount of time to initiate the failure investigation as to perform and
                complete the investigation does not seem appropriate. The commenter
                asserted that an operator should start the investigation within 30
                days, and then complete the investigation within 120 days of
                commencement. The commenter also suggested that if the operator cannot
                complete the report within the timeframe allotted, the operator should
                submit monthly progress reports to show progress towards a solution.
                Another commenter observed that the proposed changes would essentially
                double the time permitted for failure investigation, thereby delaying
                completion of the investigation by four months. This commenter asserted
                that delaying a failure investigation does not make sense because the
                purpose of this requirement is to inform BSEE and the manufacturer of
                problems, so those problems may be resolved quickly in order to prevent
                other accidents or failures.
                 Response: The commenter's assumption that
                operators will use all available time to delay a submission does align
                with BSEE's experience with the recent history of reporting since the
                rule implementation began. BSEE's experience shows operators to be
                making a good faith effort to complete investigations as soon as
                practicable. Based upon a substantial number of submissions, BSEE
                expects most submitters will have completed their investigation and
                analysis reports long before the allowable time runs. In 2017, only
                1.5% of the reported failure notifications resulted in an investigation
                and failure analysis that required more than 120 days to complete. The
                provision in the rule allows extra time for the moderately complicated
                cases that require more time to process. For example, the nature of
                certain operational failures--such as systematic
                [[Page 21945]]
                failures, stack pulls, and lower marine riser pulls--may warrant
                additional case-by-case consideration, as it is reasonable to expect
                the related analyses would require more time beyond that allowed in the
                rule. BSEE extended the timeframe in the final rule to reduce
                administrative burden for those cases where extra time could enable the
                timely resolution and completion of an investigation and analysis
                report. For those rare cases requiring more time than the rule allows,
                BSEE believes that providing for an extension request is appropriate.
                BSEE does not, however, expect these revised timelines to result in
                general delays of the type described by the commenter.
                 We agree with the commenter that it is important for BSEE and the
                manufacturer to acquire and review the equipment failure information to
                make recommendations to prevent similar failures in the future. BSEE
                works with the U.S. Department of Transportation's Bureau of
                Transportation Statistics (BTS),\29\ to ensure technical review of the
                information provided by submitters. The analysis considers potential
                consequences related to specific failures, potential systematic
                concerns, and any reduction in effective barrier operation. When
                significant safety concerns are identified, there are processes in
                place to raise awareness in a timely manner to prevent similar
                failures. Items of lesser potential significance are dealt with through
                public reports based on aggregated data.
                ---------------------------------------------------------------------------
                 \29\ Operators submit failure information through
                www.SafeOCS.gov, where it is received and processed by BTS. BSEE
                identified BTS as the designee and recommended that SPPE failure
                information should be sent to BTS via www.SafeOCS.gov through a
                press release issued on October 26, 2016 (https://www.bsee.gov/newsroom/latest-news/statements-and-releases/press-releases/bsee-expands-safeocs-program). BSEE and BTS entered into a Memorandum of
                Understanding (MOU) that provides for BTS to collect BOP and SPPE
                failure reports. The MOU may be viewed on BSEE's website at: https://www.bsee.gov/sites/bsee.gov/files/bsee-bts-mou-08-18-2016_0.pdf.
                Reporting instructions are on the SafeOCS website at: https://www.SafeOCS.gov.
                ---------------------------------------------------------------------------
                 Summary of comments: A commenter suggested that the rule include a
                method to extend investigations that have been started, but are not
                complete within the 120 days. This commenter recommended including a
                requirement for the operator to submit a status update to BSEE
                detailing the progress to date, the reasons why the investigation was
                not completed within the required timeframe, and an extension period,
                if any. The commenter is concerned that the fixed number of 120 days
                may result in conclusions that do not identify the true root cause,
                thereby ultimately compromising safety.
                 Response: BSEE disagrees with allowing a blanket
                extension of the 120-day completion date for the failure analysis. BSEE
                does, however, acknowledge that there may be extenuating circumstances
                that prevent an operator from meeting these timelines. Accordingly, the
                final rule provides that if an operator cannot meet the required
                timeframes, the operator may request an extension to the failure
                analysis timeframes by submitting a request to the Chief, OORP and, if
                appropriate, BSEE may approve an extension. Due to the potential for
                some failures to have broader safety implications, it is not reasonable
                to allow the operator to define an open-ended period in which to
                complete the investigation. Extension requests will be handled on case-
                by-case basis to allow consideration of circumstances. In 2017, only
                1.5% of the reported failure notifications resulted in an investigation
                and failure analysis that required more than 120 days to complete. BSEE
                extended the timeframe in the final rule to reduce administrative
                burden for those cases where extra time could enable the timely
                resolution and completion of an investigation and analysis report. For
                those rare cases requiring more time than the rule allows, BSEE
                believes providing for an extension request is appropriate and that
                such a request may reasonably be expected to address the items
                recommended by the commenter.
                 Summary of comments: A commenter asserted that proposed Sec.
                250.730(c)(1) would reduce the clarity, safety, and effectiveness of
                BOP systems by limiting information exchange about equipment failures.
                The commenter opposed the proposed language because it does not specify
                who the operator must notify at BSEE or other entities, such as the
                equipment manufacturer. The commenter also asserted that the use of
                third parties to receive data and reports on behalf of BSEE will make
                it substantially more difficult for the public to acquire those data
                and reports using the Freedom of Information Act (FOIA). The commenter
                contends that because the focus is on equipment failure, it would be
                important for technical experts to acquire and review the equipment
                failure information to make recommendations to prevent similar failures
                in the future. The commenter supported the 120-day failure analysis
                completion date in the existing regulations, asserting that this
                timeframe ensures that any needed equipment changes are quickly
                identified, and changes can be made at problematic wells as soon as
                possible to prevent additional failures.
                 Response: BSEE disagrees with the assertion that
                the language in paragraph (c)(1) will ``reduce the clarity, safety, and
                effectiveness of BOP systems by limiting information exchange about
                equipment failures.'' In terms of specifying to whom data should be
                submitted, BSEE agrees that this was less than clear with respect to
                submissions to BSEE, and accordingly modified the proposed rule text to
                clarify that submissions directed to BSEE should be sent to the Chief,
                OORP. With respect to a third party designated to receive data, BSEE
                can provide information on who operators should submit this data to
                through a variety of public notices, such as a press release or NTL.
                Not including these specifics in the regulations allows BSEE to change
                the designated third party without undertaking rulemaking. With respect
                to reporting to equipment manufacturers, it is up to the operator to
                find out from the equipment manufacturer to whom the required data and
                information should be submitted.
                 With respect to the use of a third party to receive data, as
                previously discussed, BSEE currently has an agreement with BTS to
                receive and process the data through the SafeOCS program. This
                agreement is consistent with the policies of the Confidential
                Information Protection and Statistical Efficiency Act (CIPSEA).\30\
                CIPSEA requires that BTS treat and store such reports confidentially,
                under strict criminal and civil penalties for noncompliance.
                Information submitted under CIPSEA also is protected from release to
                other government agencies (including BSEE), from Freedom of Information
                Act (FOIA) requests and subpoenas. If the information were to be
                submitted to BSEE, BSEE could only protect its confidentiality to the
                extent allowed by Federal law other than CIPSEA. The SafeOCS program
                was designed to protect the confidentiality of information submitted
                and promote failure reporting without fear of reprisals. BSEE uses this
                third-party approach for submission of equipment component failure
                information in the interest of promoting the sharing of safety data and
                information, while protecting sensitive identifying information the
                release of which could
                [[Page 21946]]
                reduce the incentive to share all of the facts related to an incident.
                This determination was made to protect trade secrets and proprietary
                information and especially to ensure facts that pertain to safety are
                not left out of reports due to concerns about disclosure under FOIA.
                BSEE believes placing this raw data at risk of disclosure under FOIA
                would reduce operator openness in what is shared regarding equipment
                component failures. For this reason, the Bureau of Transportation
                Statistics currently houses BSEE's system of record on this collection
                effort.
                ---------------------------------------------------------------------------
                 \30\ Reports submitted through www.SafeOCS.gov are collected and
                analyzed by BTS and protected from release under the Confidential
                Information Protection and Statistical Efficiency Act (CIPSEA) (44
                U.S.C. 101). Annual reports for 2016 and 2017 reporting periods for
                well control regulations are available at: https://www.safeocs.gov/wcr_home.htm.
                ---------------------------------------------------------------------------
                 We agree with the commenter that it is important for technical
                experts and others to acquire and review the equipment failure
                information to make recommendations to prevent similar failures in the
                future. BTS engages subject matter experts to analyze the reports and
                prepare public reports that are available to all stakeholders. BTS has
                the ability under CIPSEA to have a confidentiality officer from BTS
                communicate with a respondent when safety issues arise of particular
                concern to subject matter experts. The BTS confidentiality officer may
                recommend that the submitter of the information communicate the safety
                issue directly with BSEE and the OEM.
                 In addition, Sec. 250.730(c)(1) requires that operators follow the
                failure reporting procedures in API Standard 53, which is incorporated
                by reference in BSEE regulations at Sec. 250.198. API Standard 53
                includes processes for the sharing of equipment failure information
                between the manufacturers and owners of blowout prevention equipment.
                This would include reporting of any malfunction or failure by the
                equipment owner to the equipment manufacturer and the manufacturer's
                response to the equipment owner with a timeline for failure resolution.
                Comments Related to Proposed Sec. 250.730(c)--Anonymous Failure
                Reporting
                 Summary of comments: One commenter expressed concern that the
                proposal to allow companies to anonymously submit the results of
                equipment failure investigations through a third-party would
                effectively make the failure reporting requirement voluntary.
                 Response: BSEE disagrees. The failure reporting
                is required regardless of where and how an operator submits the data.
                This revision does not provide for anonymous failure reporting through
                a designated third party. The failure reporting is not anonymous. Each
                time BTS receives a notification of failure under Sec. 250.730(c), it
                provides BSEE with a notification that a submission was made and
                includes the name of the company. BSEE may choose to open an
                investigation at any time when information received from non-BTS
                sources demonstrates operators are not complying with the requirements.
                However, it is important to note, BSEE does not receive any information
                from BTS about a single failure report other than the name, submittal
                date, and reference ID numbers of the report of the reporting company.
                 BTS maintains the raw data and entity information to allow
                aggregated reporting. BTS also has measures available under CIPSEA
                whereby a confidentiality officer from BTS may communicate with a
                respondent when safety issues of particular concern to subject matter
                experts arise and warrant immediate action. Thus far, BSEE has observed
                a close correlation between the companies engaged in drilling activity
                and those reporting equipment component failures.
                Comments Related to Proposed Sec. 250.730(d)--BOP Stack Manufacturing
                Requirements
                 Summary of comments: A commenter recommended that BSEE add the
                phrase ``or stack sub-assemblies'' to the BOP stack manufacturing
                requirements under Sec. 250.730(d). The commenter asserted that this
                change would clarify that the rule covers the overall BOP stack and the
                component assemblies contained within the stack.
                 Response: BSEE disagrees with this
                recommendation. The commenter did not provide enough information or
                justification to substantiate the recommended change. Stack sub-
                assemblies are part of the BOP stack; therefore it is BSEE's view that
                they are already covered under these requirements.
                Comments Related to Proposed Sec. 250.730(b)--Corrective Maintenance
                 Summary of comments: A commenter recommended that BSEE remove
                ``maintenance'' and ``repair'' from the requirement for the operator to
                follow original equipment manufacturer (OEM) recommendations for the
                BOP systems in Sec. 250.730(b). The commenter suggested adding
                ``remanufacture'' to this requirement. According to the commenter, the
                recommended changes would ensure consistency with API 53, further
                noting that maintenance is covered in Sec. 250.730(a).
                 Response: BSEE disagrees with the comment. The
                OEM designs the equipment according to detailed specifications.
                Therefore, the OEM recommendations, if they exist, for maintenance and
                repair are important for ensuring the condition of the equipment
                remains within the design limits. BSEE is not adding ``remanufacture''
                because this is covered under ``repair''.
                Comments Related to Proposed Sec. 250.730--Proposed Revisions Reduce
                Operational Requirements for BOPs
                 Summary of comments: A commenter asserted that the proposed
                revisions in Sec. 250.730 would reduce the conditions under which a
                BOP must function, while increasing the time allowed for operators to
                investigate and report on a BOP failure. The commenter asserted that
                the proposed revisions would only require a BOP to be capable of
                closing and sealing a wellbore ``in the event of flow due to a kick,''
                eliminating the existing language that requires a BOP to be capable of
                closing and sealing the wellbore ``at all times.'' The commenter
                emphasized that there are other conditions that may necessitate closure
                and sealing besides a kick, such as an approaching hurricane or a fire
                or other malfunction. This commenter asserted that the proposed change
                would substantially narrow the conditions under which a BOP would be
                required to be capable of closing.
                 Response: BSEE disagrees. The proposed revisions
                would not weaken or alter the underlying requirements that the BOP
                system must be able to function during all operations. This section
                ensures that the BOP system is designed to close and seal a well in the
                event of flow from a kick from the well because that is representative
                of the most critical and challenging circumstances a BOP must address.
                The operator must verify the ability of the BOP to function during a
                non-kick event through the regular function and pressure testing as
                required by final Sec. 250.737. The operator will also still be
                required to obtain independent third-party certification that the BOP
                is designed, tested, and maintained to perform under the maximum
                environmental and operational conditions anticipated to occur at the
                well under Sec. 250.731.
                Comments Related to Proposed Sec. 250.730--Incorporate API Standard 53
                Addendum 1 and API Standard 53, 5th Edition
                 Summary of comments: A commenter recommended that the incorporation
                by reference of API Standard 53, Blowout Prevention Equipment Systems
                for Drilling Wells, Fourth Edition, July 2016, should include Addendum
                1 of that standard. The commenter also
                [[Page 21947]]
                noted that the 5th edition of that standard is being finalized and
                recommended that BSEE consider the 5th edition for incorporation by
                reference to ensure operations on the OCS are conducted according to
                the latest edition of the API standard for well control systems and are
                consistent with operations around the world.
                 Response: BSEE reviewed the addendum and
                determined it is appropriate for incorporation into the regulations.
                The addendum addresses multiple issues that BSEE has had to deal with
                through departures from compliance with the incorporated API Standard
                53 (without the addendum) since the development of the 2016 WCR (e.g.,
                section 7.2.3.2.9 Side outlet location and section 7.3.13.2.5 fire
                rating of MUX lines). The inclusion of the addendum to API Standard 53
                brings the regulations in line with the current latest edition of this
                standard. BSEE understands that API is developing a 5th Edition of API
                Standard 53, and BSEE will evaluate that document when it is finalized
                for possible incorporation into the regulations in a future rulemaking.
                Comments Related to Proposed Sec. 250.730--Use of OEM Recommended
                Maintenance Practices
                 Summary of comments: A commenter asserted that the OEMs do not have
                operational experience and the type of continuous feedback needed to
                develop effective maintenance practices to manage assets. The commenter
                also asserted that because OEMs do not need to worry about rig
                downtime, they can afford to be conservative. The commenter concluded
                that this poses a significant risk that the OEM-developed maintenance
                practices would require the operator to perform unnecessary maintenance
                and repairs. The commenter also asserted that this practice could
                result in OEMs leveraging this as an aftermarket revenue generator, and
                this approach presents a technical barrier to trade and causes a
                conflict of interest. The commenter generally challenged certain OEM
                maintenance recommendations, based on proven field results.
                 Response: This regulation does not require the
                OEM to perform the maintenance or train the personnel performing
                maintenance. With regard to the OEM recommendations, operators are
                required to comply only with applicable OEM recommendations to the
                extent that they exist. If an operator has a specific issue with OEM
                recommendations, BSEE may recognize other alternative procedures. OEMs
                of offshore operational equipment generally maintain close
                communications with operators and drilling contractors, including
                coming on location as needed. OEMs develop maintenance procedures
                through an effective communication program including practices for
                sharing information under API Standard 53 and through notification
                requirements under this final rule.
                 The TBT Agreement seeks to avoid unnecessary obstacles to
                international trade, in part by requiring that technical regulations
                and conformity assessment procedures be consistent with international
                standards promulgated by international standards developing
                organizations (SDOs). This rule does not create a technical barrier to
                trade because it is neutral as to the national origin of regulated
                equipment. The proposed rule did not, and this final rule does not,
                discriminate in favor of U.S.-fabricated equipment. The final rule is
                equally applicable to all relevant equipment, regardless of the
                equipment's country of origin. Accordingly, BSEE's proposed rule did
                not, and the final rule does not, create an unnecessary technical
                barrier to trade.
                Comments Related to Proposed Sec. 250.730--Use of Word ``applicable''
                for Applying OEM Recommendations
                 Summary of comments: A commenter asserted that ``applicable'' is
                subjective and the proposed rule is not clear about who determines if
                an OEM recommendation is applicable. The commenter was concerned that
                an operator or drilling contractor could decide to simply disregard OEM
                recommendations as not applicable. The commenter recommended changing
                the proposed regulations to state that the operator must follow the OEM
                recommendations unless BSEE directs them otherwise or they receive
                other directions in writing from the OEM.
                 Response: BSEE disagrees. As BSEE explained in
                the proposed rule preamble, and included in the final Sec. 250.730(b)
                clarifies that BSEE expects the use of ``applicable'' OEM
                recommendations for the design, fabrication, maintenance, and repair of
                BOP systems, as well as personnel training in their use. The proposed
                revision to include ``applicable'' is necessary because some OEMs may
                not have specific recommendations for every item required by this
                paragraph, and operators are not required to follow recommendations
                that are not applicable to the relevant equipment or operation. BSEE
                expects operators to follow OEM recommendations to the extent relevant
                recommendations exist.
                Comments Related to Proposed Sec. 250.730(a)--Request To Incorporate
                API RP 59
                 Summary of comments: A commenter recommended that BSEE incorporate
                by reference API Recommended Practice 59, Second Edition--Recommended
                Practice for Well Control, Section 4.4 in Sec. 250.730(a). The
                commenter asserts that the methodology of API RP 59, section 4.4
                focuses on one open hole interval of flow, not on the entire open well
                bore interval pertinent to the worst case discharge. This addresses the
                long-standing, safe well control practice of drilling 10 to 20 feet
                into a drilling break or a prospective hydrocarbon interval, then
                stopping drilling operations to ``check for flow'' as the proven method
                of determining a kick in a well.
                 Response: BSEE will evaluate API RP 59 for
                possible incorporation by reference in a future rulemaking. Operators
                should develop appropriate control procedures based on specific well
                and site conditions and accepted good engineering practices.
                Comments Related to Proposed Sec. 250.730--BOP System Requirements
                 Summary of comments: A commenter strongly opposed the proposed
                revisions to requirements in Sec. Sec. 250.730, 250.733, and 250.734
                regarding the BOP systems. The commenter expressed concern that the
                proposed revisions would allow the use of BOPs that cannot close and
                seal a wellbore under the range of conditions encountered, including
                high-pressure, high-temperature drilling environments. The commenter
                noted that the existing language in Sec. 250.730(a) is unambiguous
                regarding the key capabilities of the BOP system, stating that the BOP
                system is required to be able to close and seal the wellbore at all
                times. The commenter asserted that the proposed rule would weaken this
                language by specifying only certain circumstances in which the BOP
                system must function, i.e., only in the event of flow due to a kick.
                 Response: BSEE disagrees. The revisions do not
                weaken or alter the underlying requirement that the BOP system must be
                able to function during all operations. This section specifically
                ensures that the BOP system is designed to close and seal a well in the
                event of flow from a kick from the well because that is representative
                of the most critical and challenging circumstances a BOP must address.
                The operator is required to verify the ability of the BOP to operate in
                a non-kick event through regular function and pressure testing required
                by Sec. 250.737. The regulation
                [[Page 21948]]
                still requires that the operator obtain independent third-party
                certification that the BOP is designed, tested, and maintained to
                perform under the maximum environmental and operational conditions
                anticipated to occur at the well under Sec. 250.731.
                What information must I submit for BOP systems and system components?
                (Sec. 250.731)
                 This section of the existing regulations details the information
                that must be included in the applicable BSEE permit (e.g., APD or APM)
                for any operation that uses a BOP. The required information includes a
                complete description of the BOP system and system components, schematic
                drawings, and verifications demonstrating that the BOP is fit for
                service on the applicable well.
                Summary of Proposed Revisions
                 BSEE proposed to revise the information submitted to BSEE pursuant
                to paragraph (a)(5) by replacing ``to achieve an effective seal of each
                ram BOP'' with ``to close each ram BOP.'' This revision would affect
                information submitted to BSEE and would more accurately align with the
                control system and regulator control setting requirements of API
                Standard 53.
                 BSEE also proposed to revise this section by removing the BAVO
                verification requirements in existing paragraphs (d) and (f). The BAVO
                verifications required by existing paragraphs (d)(1) and (d)(3) were
                redundant to the verifications required by paragraph (c). However, the
                verifications required by current paragraph (d)(2) are still necessary
                and BSEE therefore proposed to add them to revised paragraph (c). BSEE
                proposed to remove paragraph (f) because the Report that is the subject
                of that paragraph would be eliminated by the proposed revisions to
                Sec. 250.732(d). The independent third-party verifications under
                paragraph (c) help ensure that the BOP is fit for service at each
                specific well. BSEE also proposed to revise this section by replacing
                references to a BAVO with references to an independent third party that
                meets the requirements of Sec. 250.732(b).
                Summary of Final Rule Revisions
                 BSEE received and considered comments on the proposed revisions and
                includes the proposed language in the final rule without change.
                Summary of Comments
                Comments Related to Proposed Sec. 250.731(a)(5)--Regulator Set Points
                 Summary of comments: Multiple commenters asserted that there is
                [acy] difference between sealing and closing in this context and
                requested clarification on the intent of the regulation. Commenters
                expressed concerns with BSEE's explanation and reference to
                [Acy][Rcy][Iukcy] Standard 53 to adequately clarify the intent.
                Commenters also requested justification for the removal of the word
                ``effective''.
                 Response: BSEE does not agree with the comments. Paragraph
                (a)(5) principally identifies information that must be submitted to
                BSEE for BOP systems and system components. Subsequent sections
                regulate operational and equipment requirements for these systems and
                components. BSEE used the term ``close'' because the regulator settings
                are not changed throughout operations. The requirements of paragraph
                (a)(5) only relate to the regulator set points, and do not alter any of
                the ram operational requirements contained in Sec. Sec. 250.733 and
                250.734 for surface and subsea BOPs, respectively. Some of the rams do
                not seal, such as the casing shear ram, and BSEE utilizes this data in
                the permit application to evaluate ram closing and sealing
                capabilities. The word ``effective'' in this context is not necessary
                and does not provide any supplemental regulatory standard.
                Comments Related to Proposed Sec. 250.731(c)--Applicability to Coiled
                Tubing
                 Summary of comments: A commenter requested clarification about the
                applicability of paragraph (c) to coiled tubing. The commenter also
                asserted that Sec. 250.731(c)(1) can be interpreted to mean that a
                shear test at depth is required. In reality, the depth adjustment is a
                calculation based on different densities of hydraulic fluid and
                seawater. The commenter, therefore, recommended adding the words ``and
                depth'' to Sec. 250.732(a)(3) so that the provision states, ``Include
                shearing and sealing pressures for all pipe to be used in the well
                including correction for MASP and depth.'' The commenter also suggested
                removing Sec. 250.731(c)(1).
                 Response: Section 250.731(c) applies to coiled tubing;
                however, Sec. 250.731(c)(4) is only applicable to the specified
                situations (subsea BOP, a BOP in an HPHT environment, or a surface BOP
                on a floating facility). BSEE disagrees with the suggestion to add the
                term ``and depth'' because the definition of MASP already takes into
                account depth, whether at surface or subsea. BSEE also disagrees with
                the recommendation to revise Sec. 250.732(a)(3) and remove Sec.
                250.731(c)(1) because the requirements in Sec. 250.732 are utilized to
                provide supporting documentation for the verifications required in
                Sec. 250.731.
                What are the independent third party requirements for BOP systems and
                system components? (Sec. 250.732)
                 This section of the existing regulations describes the criteria for
                an organization to become a BAVO, and identifies the circumstances in
                which an operator must use a BAVO to satisfy certification,
                verification, or reporting requirements.
                Summary of Proposed Revisions
                 BSEE proposed to revise this section by removing all references to
                a BAVO and, where appropriate, replacing those references with an
                independent third party. This change would also be made in appropriate
                locations throughout Subpart G where BAVOs are referenced. Independent
                third parties have been utilized as a long-standing industry practice
                to carry out certifications and verifications similar to those that a
                BAVO would perform. Independent third parties have been performing the
                functions identified for BAVOs since promulgation of the 2016 WCR.
                Based on BSEE's determination to remove the use of BAVOs, as previously
                discussed under section IV of this final rule preamble, BSEE revised
                the section heading to reflect the change from a BAVO to an independent
                third party, removed paragraphs (a)(1) and (a)(3), and replaced all
                remaining BAVO references with references to an independent third
                party. The independent third-party qualifications in existing paragraph
                (a)(2) remain in this section, but would now be in proposed paragraph
                (b).
                 BSEE also proposed to remove the requirements in current paragraph
                (b)(1)(iv) to verify that testing was performed on the outermost edges
                of the shearing blades of the shear ram positioning mechanism. This
                proposed change would align the verification requirements with BSEE's
                proposal to remove the centering mechanism requirement from existing
                Sec. 250.734(a)(16) that is the subject of this verification. BSEE
                also proposed to remove from existing paragraph (b)(1)(i)--a vestigial
                reference to a compliance deadline that has already passed. This is
                merely an administrative revision.
                [[Page 21949]]
                 BSEE also proposed to revise existing paragraph (b)(2)(ii) by
                changing the testing facilities' verification pressure testing hold
                time demonstration from 30 minutes to 5 minutes. This revision would
                allow the use of previously established historical data to help
                demonstrate the blind shear ram functionality in the applicable permit
                application.
                 BSEE proposed to make a minor revision to paragraph (c) to update
                an incorrect citation--the referenced definition of HPHT environments
                is found in Sec. 250.804(b), rather than Sec. 250.807(b), as stated
                in the existing regulations.
                 BSEE proposed to remove the Mechanical Integrity Assessment (MIA)
                report requirements from paragraph (d). The MIA report was required as
                a function of the use of BAVOs. BSEE determined that an MIA report is
                no longer necessary because BSEE proposed to eliminate the use of BAVOs
                and the information contained within the MIA report is redundant with
                the BOP equipment capability verifications required by Sec. 250.731.
                Summary of Final Rule Revisions
                 BSEE received and considered comments on the proposed revisions,
                and includes in the final rule most of the proposed language without
                change, except for the following revisions. BSEE is revising proposed
                paragraphs (a)(1)(i) and (iii) and (iv) (final paragraphs (a)(1)(i) and
                (iii) and (v)) by replacing ``drill pipe'' with ``tubular body of any
                drill pipe (excluding tool joints, bottom-hole tools, and bottom hole
                assemblies such as heavy-weight pipe or collars), workstring, tubing
                and associated exterior control lines and any electric-, wire-, and
                slick-line to be used in the well.'' BSEE made these revisions to
                provide consistency with the shearing requirements of Sec. Sec.
                250.733(a)(1) and 250.734(a)(1)(ii). This clarification would help
                ensure that the shear testing applies to the required equipment that
                needs to be shearable. This revision does not add new equipment
                required for shear testing, but instead clarifies BSEE's established
                practice.
                 BSEE also is re-designating proposed paragraphs (a)(1)(iv) and
                (a)(1)(v) as (a)(1)(v) and (a)(1)(vi) respectively, and retaining (in
                large part) existing paragraph (b)(1)(iv) as new (a)(1)(iv) to ensure
                that testing is performed on the outermost edges of the shearing blades
                of the shear ram. This retention was based on comments, and modifies
                the existing text of the relevant provision only to remove reference to
                the shear ram positioning mechanism that is no longer required under
                the cross-referenced regulation. BSEE is retaining in Sec.
                250.734(a)(16)(i) the centering requirement for shearing, but not
                requiring that it utilize a positioning mechanism. BSEE is making
                corresponding edits to this section to help ensure the shearing
                verifications and certifications align with the revised shearing
                requirements. This requirement helps verify that the shear rams will
                shear along any point of the shearing surface.
                 BSEE is revising proposed paragraph (a)(2) to clarify that the
                pressure integrity test applies to sealing components. A pressure
                integrity test for a non-sealing component is not practicable or
                feasible. BSEE is also revising proposed paragraph (a)(2)(i) to
                indicate that testing is conducted after the shearing is completed and
                prior to opening. BSEE made this revision based on comments to provide
                clarity for defining how the verification is conducted. BSEE revised
                this section to help ensure that the testing is accomplished in one
                continuous action to better simulate sealing after shearing in real-
                world well control applications.
                Summary of Comments
                Comments Related to Proposed Sec. 250.732(a)(1)--Definition of Drill
                Pipe
                 Summary of comments: A commenter asserted that the use of the word
                ``drill pipe'' throughout Sec. 250.732(a) is not complete. The
                commenter recommends that BSEE include terms, such as coiled tubing,
                shear subs, and landing strings in this section for completeness.
                 Response: BSEE agrees with the commenter and has revised
                proposed paragraphs (a)(1)(i), (iii), and (v) by replacing ``drill
                pipe'' with ``tubular body of any drill pipe (excluding tool joints,
                bottom-hole tools, and bottom hole assemblies such as heavy-weight pipe
                or collars), workstring, tubing and associated exterior control lines
                and any electric-, wire-, and slick-line to be used in the well.''
                These revisions make these testing requirements consistent with the
                shearing requirements of Sec. Sec. 250.733(a)(1) and 734(a)(1)(ii).
                This clarification will help ensure that the shear testing applies to
                the required equipment that needs to be shearable.
                Comments Related to Proposed Sec. 250.732(a)(2)(i)--Pressure Integrity
                Testing Procedures
                 Summary of comments: A commenter recommended that BSEE remove
                ``immediately'' and add ``after the shearing is completed and prior to
                opening the rams'' to provide clarity to the pressure integrity
                testing.
                 Response: BSEE agrees with the commenter and has revised
                this paragraph to reflect the commenter's recommendation, except that
                we have used the phrase ``prior to opening the component.'' BSEE
                revised this paragraph to help ensure that the testing is done in one
                continuous action to better simulate sealing after shearing in real
                world well control applications.
                Comments Related to Proposed Sec. 250.732(a)(2)(ii)--Lab 30 Minute vs
                5 Minute Pressure Hold Time
                 Summary of comments: Multiple commenters oppose the proposed
                replacement of the existing requirements in Sec. 250.732(b)(2)(ii) of
                [acy] 30-minute hold time for [acy] verification pressure test with the
                proposed Sec. 250.732(a)(2)(ii) [acy] 5-minute hold time. The
                commenters asserted that [acy] 30-minute test is an established
                practice according to various standards organizations, and therefore
                the commenters see no reason for the change. The commenters also
                asserted that BSEE does not provide any analysis or data to support
                this change and should make any data available.
                 Response: BSEE does not agree that holding a constant
                pressure for 30 minutes is necessary to demonstrate sealing
                capabilities. Based on BSEE experience since the promulgation of the
                2016 WCR and a review of longstanding historical data demonstrating
                successful application of 5 minute hold time testing, BSEE concluded
                that 30 minute testing is unnecessary. BSEE is unaware of standards
                referencing a standardized 30-minute lab test pressure holding time for
                BOP shearing verification. However, BSEE is aware of an industry
                standard, API 16TR1, Shear Ram Performance Test Protocol, that includes
                field performance testing and specifies a 5 minute pressure hold time
                after shearing pipe. BSEE reviewed the publicly available incident data
                on the BSEE website to try to identify any past incidents involving
                failure of equipment after successfully sealing in a well, but was
                unable to identify any such incidents. BSEE is also unaware of any data
                showing lab failures during the hold times between the 30-minute and 5-
                minute intervals. BSEE also reviewed permits issued prior to 2010 to
                verify the historic lab shear and seal data hold times. Of the permits
                reviewed, pressure hold times did not indicate any failures after the
                5-minute mark. BSEE uses this 5 minute testing data to verify that the
                component will provide a seal when activated.
                [[Page 21950]]
                Comments Related to Proposed Sec. 250.732--BAVOs
                 Summary of comments: A commenter expressed concerns about the
                removal of the BAVO and MIA report. A commenter recommended that in the
                absence of the BAVO and MIA report requirements, it is critical that
                BSEE ensure strict compliance with all third-party certification
                requirements, including the BOP equipment capability verifications
                required by Sec. 250.731.
                 Response: BSEE agrees with the commenter that it is
                important to ensure compliance with independent third-party
                certification and verification requirements. In final Sec. 250.731(c),
                BSEE requires certifications by an independent third party, in lieu of
                a BAVO, that include verification, for a subsea BOP, a BOP in an HPHT
                environment as defined in Sec. 250.804(b), or a surface BOP on a
                floating facility, that the BOP has not been compromised or damaged
                from previous service. BSEE expects full compliance with these
                certification requirements, regardless of who is performing the
                certification. The requirements of Sec. 250.731 adequately cover the
                substance of the matters previously addressed in the MIA report, and
                BSEE expects that independent third parties will capably perform the
                same functions previously assigned to BAVOs, as they have since
                promulgation of the 2016 WCR.
                 Summary of comments: Multiple commenters oppose the proposed
                revisions to remove the BAVO, and recommend that the companies that
                operators use to assess blowout preventers should continue to be BSEE-
                certified. The commenters assert that this is important to ensure that
                reviews of important equipment are objective and standardized through
                the use of BSEE-certification of third-parties.
                 Response: BSEE disagrees that BSEE needs to certify the
                parties used to assess blowout preventers. BSEE is maintaining rigorous
                qualification requirements for independent third parties that ensure
                their professional qualification and independence. The independent
                third party must be a technical classification society, or a licensed
                professional engineering firm, or a registered professional engineer
                capable of providing the required certifications and verifications. If
                BSEE becomes aware of any performance issues with an independent third
                party, BSEE has options for addressing the issues (e.g., verifications
                through the permitting process).
                Comments Related to Proposed Sec. 250.732--MIA Report Content
                 Summary of comments: A commenter suggested that specific items in
                the MIA report are not redundant of other requirements and should be
                included in the regulations (e.g., existing Sec. Sec. 250.732(d)(5),
                250.732(d)(8), 250.732(d)(9), 250.732(d)(11), and 250.732(d)(13)).
                 Response: BSEE disagrees with the suggested changes. The
                MIA report content is not only redundant of Sec. 250.731, but also of
                other independent third-party reviews, certifications, and
                verifications required in Sec. Sec. 250.734, 250.738, and 250.739, as
                well as personnel operational requirements in existing Sec. 250.710,
                What instructions must be given to personnel engaged in well
                operations? among others. It is not necessary to retain the identified
                elements of the MIA report.
                What are the requirements for a surface BOP stack? (Sec. 250.733)
                 This section of the existing regulations describes the capability,
                type, and number of BOPs required when an operator uses a surface BOP
                stack for drilling or for conducting operations. This section also
                describes the requirements for the risers and BOP stack when a surface
                BOP is used on a floating production facility.
                Summary of Proposed Revisions
                 BSEE proposed to revise paragraph (a)(1) by removing the reference
                to an extended time for compliance with exterior control line shearing
                requirements under the 2016 WCR, which has elapsed and no longer
                warrants reference in the regulations. BSEE also proposed to remove the
                requirement to have an alternative cutting device used for shearing
                electric-, wire-, or slick-line if your blind shear rams are unable to
                cut and seal under maximum anticipated surface pressure (MASP).
                 BSEE also proposed to revise paragraph (b)(1) by extending the
                compliance date from April 29, 2019, to April 29, 2021, to correspond
                with the same requirements for subsea BOP stacks. This revision would
                align the dual shear ram requirements for surface BOPs installed on
                floating facilities and subsea BOPs. Aligning these dates will reduce
                confusion between the different effective dates of the similar
                requirements for surface BOPs used on floating facilities and subsea
                BOPs.
                 BSEE proposed to add new paragraph (e) to clarify the minimum
                requirements of a surface BOP system for well-completion, workover, and
                decommissioning operations where estimated well pressures are low. The
                provisions in this proposed paragraph were inadvertently removed from
                the regulations through the 2016 WCR, and are consolidated from
                Sec. Sec. 250.516, 250.616, and 250.1706 of the regulations as they
                existed before the 2016 WCR. BSEE proposed minor revisions to the
                original language to conform to the applicable operations covered under
                revised Subpart G and to update cross-referenced citations.
                Summary of Final Rule Revisions
                 BSEE received and considered comments on the proposed revisions and
                includes in the final rule most of the proposed language without
                change, except for the following revisions. BSEE is revising paragraph
                (a)(1) by adding: ``Prior to April 29, 2021, if your blind shear rams
                are unable to cut any electric-, wire-, or slick-line under MASP as
                defined for the operation and seal the wellbore, you must use an
                alternative cutting device capable of shearing the lines before closing
                the BOP. This device must be available on the rig floor during
                operations that require their use.'' BSEE is retaining the alternative
                cutting device requirements, similar to those found in existing
                regulations, based on comments. As many commenters stated, BSEE is
                aware that not all OEMs currently offer wireline cutting capability for
                all BOP sizes and rated working pressures. This addition is necessary
                to ensure that a device capable of cutting wire is available to help
                ensure sealing efficiency. BSEE is limiting this requirement to the
                window prior to April 29, 2021, because, after that point, shear rams
                must be capable of shearing wire. Since the publication of the proposed
                rule, BSEE has discussed these shearing requirements with relevant OEMs
                and has determined that the technology currently exists, but is not yet
                available for commercial off-the-shelf use.
                 BSEE is also revising paragraph (b)(1) to clarify that, after April
                29, 2021, operators must follow the BOP requirements in Sec.
                250.734(a)(1) for new floating production facilities installed with a
                surface BOP. These revisions are based on comments seeking clarity.
                Since the publication of the 2016 WCR, including in the comments for
                this rulemaking, stakeholders have expressed confusion about the
                requirements in this section that reference Sec. 250.734 regarding
                dual shear rams, which do not take effect until 2021. BSEE is making
                the compliance date of April 29, 2021 the same for Sec. Sec.
                250.733(b)(1) and 250.734(a)(1) to
                [[Page 21951]]
                avoid confusion. This will apply only to new floating production
                facilities with a surface BOP, and the expected number of those types
                of facilities is minimal. The intent of the proposed rule was for the
                requirements to apply to new facilities installed after 2021. These
                regulations do not apply to existing facilities, even if they are
                redeployed at another location because of several issues, including,
                but not limited to, clearance and weight issues.
                 BSEE is revising proposed paragraph (e)(4) to clarify that the
                drill string should include the drill pipe, work string, or tubing,
                depending on the operation. Based on BSEE's review of the proposed rule
                and submitted comments, this clarification will help ensure the set of
                pipe rams can seal around drill pipe, work string, or tubing. When
                conducting well completions, workover, and decommissioning operations,
                there are many types of equipment that are run in the hole through the
                BOP. This requirement reflects longstanding and current BSEE practice.
                This revision does not change or affect an operator's burden, as it is
                currently reflected in operational practice and does not add new
                equipment required for shear testing. The revision simply clarifies
                current, longstanding BSEE practice.
                Summary of Comments
                Comments Related to Proposed Sec. 250.733--Compliance Dates
                 Summary of comments: A commenter suggests that it would be
                preferable to apply the April 2019 deadline for surface BOPs to both
                subsea and surface BOPs.
                 Response: BSEE disagrees that the compliance dates for
                subsea BOP dual shear ram requirements should be 2019, because there
                would not be sufficient time to install and implement the required
                equipment modifications. BSEE understands that there is potential
                confusion about the compliance date applicable to this section's
                reference to the dual shear ram requirements of Sec. 250.734, because
                those requirements do not take effect until 2021. Therefore, BSEE is
                making the compliance dates of April 29, 2021 the same for Sec. Sec.
                250.733(b)(1) and 250.734(a)(1) to avoid confusion. This requirement
                only applies to newly installed floating production facilities that use
                a surface BOP.
                Comments Related to Proposed Sec. 250.733(e)--5K Systems
                 Summary of comments: A commenter asserted that there are
                differences and confusion between the regulations pertaining to 5,000
                psi (5K) systems and API Standard 53. The commenter recommended that
                BSEE align those regulations with API Standard 53 to avoid confusion.
                 Response: BSEE agrees that there are differences between
                the regulations and API Standard 53; furthermore, BSEE does not agree
                with using the API Standard 53 options for stack arrangements for 5K
                systems. Paragraph (e) applies to well-completion, workover, and
                decommissioning operations.
                Comments Related to Proposed Sec. 250.733(b)(1)--Floating Facilities
                 Summary of comments: Multiple commenters assert that paragraph
                (b)(1) is applicable only to new floating production facilities.
                 Response: BSEE agrees with the commenters and has revised
                proposed paragraph (b)(1) to clarify its applicability only to new
                floating production facilities installed after April 29, 2021, that use
                a surface BOP.
                Comments Related to Proposed Sec. 250.733(a)(1)--Alternative Cutting
                Device
                 Summary of comments: Multiple commenters oppose removing the
                alternative cutting device requirement, as there are no qualified OEM
                blind shear rams for certain BOPs. Commenters assert that the
                alternative cutting device is considered necessary to meet the
                requirement and considered part of the BOP system; therefore, BSEE must
                allow the alternative cutting device. A commenter also suggested that
                BSEE should allow the use of the alternative cutting device prior to
                April 29, 2021, and, after this date, require that the shearing rams be
                capable of shearing the wire.
                 Response: BSEE agrees with the commenters and has added
                back in the provisions related to the alternative cutting device to
                paragraph (a)(1). BSEE is aware that not all OEMs currently offer
                wireline cutting capability for all BOP sizes and rated working
                pressures. As encouraged by Congress \31\ to ensure that offshore
                operations promote safety and protect the environment in a technically
                feasible manner, this addition is necessary to ensure that a device
                capable of cutting wire is available to ensure sealing efficiency.
                Consistent with an option discussed in the proposed rule to extend the
                compliance date, BSEE is limiting the timeframe for allowing the
                alternative cutting device. The cutting device may only be used until
                April 29, 2021, after which the shear rams must be capable of shearing
                wire.
                ---------------------------------------------------------------------------
                 \31\ See n. 10, supra.
                ---------------------------------------------------------------------------
                Comments Related to Proposed Sec. Sec. 250.733 and 250.734--Dual Blind
                Shear Rams
                 Summary of comments: Multiple commenters recommended that BSEE
                require dual blind shear rams. The commenters assert that blind shear
                rams provide an extra layer of safety because they are designed to be
                capable of sealing and shearing the drill pipe during active drilling.
                 Response: BSEE disagrees with the recommendation to
                require dual blind shear rams. Other shearing rams have other shearing
                utility besides shearing the listed components in Sec. Sec. 250.733
                and 250.734 (e.g., the casing shear ram is still necessary to shear
                casing, which the BSR cannot shear). The current regulations provide
                the operators flexibility for how they utilize the BOP system and
                components for operations, while still requiring all critical shearing
                capabilities. This final rule does not change the requirement for
                operators to utilize dual shear rams by 2021, and does not require both
                shear rams to seal.
                What are the requirements for a subsea BOP system? (Sec. 250.734)
                 This section of the existing regulations identifies the
                requirements of a subsea BOP system used for drilling or to conduct
                operations. The section describes the requirements for subsea BOP
                system capabilities, as well as the functionality, type, and quantity
                of required equipment (e.g., BOPs, pod control systems, accumulator
                capacity, ROVs, autoshear and deadman, acoustic control system, and
                management and operating protocols). This section also describes the
                actions that an operator must take if it suspends operations to repair
                the subsea BOP system.
                Summary of Proposed Revisions
                 BSEE proposed to revise paragraph (a)(1)(ii) by providing that a
                ``combination of the'' shear rams must be capable of shearing all the
                items specified in the paragraph. This revision would have aligned the
                functionality of the BOP system with API Standard 53 and proposed Sec.
                250.730(a). BSEE explained that certain casing shears still have
                difficulty shearing electric-,wire-, or slick-line, while certain blind
                shear rams have difficulties shearing larger casing sizes. This
                proposed revision would have provided the operators flexibility in
                designing the BOP system and components for operations while still
                ensuring all critical shearing capabilities. BSEE further proposed to
                revise paragraph
                [[Page 21952]]
                (a)(1)(ii) by removing references to the extended compliance dates for
                certain shearing requirements under the 2016 WCR, which have passed and
                no longer warrant reference in the regulations.
                 BSEE proposed to revise the accumulator requirements in paragraph
                (a)(3) to better align with API Standard 53. BSEE also proposed to
                remove the reference to the subsea location of the accumulator
                capacity. BSEE understands that the accumulator system works together
                with the surface and subsea accumulator capacity to achieve full
                functionality, and BSEE proposed that it would be unnecessary for this
                provision to identify only subsea requirements when the entire system
                is covered under API Standard 53.
                 BSEE proposed to revise paragraph (a)(3)(i) by clarifying that the
                accumulator capacity must be sufficient to close each required shear
                ram, ram locks, and one pipe ram and to disconnect the LMRP. During a
                well control event, the most critical functions would be to close the
                BOP components and seal the well.
                 BSEE proposed to revise paragraph (a)(3)(ii) to clarify that the
                accumulator capacity must have the capability to perform the ROV
                functions within the required times specified in API Standard 53 using
                the ROVs or flying leads. These revisions were proposed to better align
                this section with API Standard 53, and to account for technological
                advancements in ROV capabilities to meet the appropriate BOP closing
                times.
                 BSEE proposed to revise paragraph (a)(3)(iii) by removing the word
                ``dedicated'' before bottles, thus allowing bottles to be shared among
                emergency and secondary control system functions to secure the
                wellbore. This revision would further align the accumulator capacity
                requirements with API Standard 53, account for the appropriate number
                of accumulator bottles on the subsea BOP stack, help ensure that the
                regulatory requirements do not exceed the operational or mechanical
                design limits of the wellhead and BOP systems, and help minimize risks
                associated with approaching those design limits.
                 BSEE also proposed to revise paragraph (a)(4) by removing the word
                ``opening'' and adding references to the ROV function response times
                contained in API Standard 53. After publication of the 2016 WCR, the
                API Standard 53 committee clarified that standard's definition of
                ``operate,'' with respect to critical functions, included only the
                ``close'' function and not the ``open'' function. Removal of the ROV
                ``open'' function could limit the ability for well intervention after
                the well has already been secured. However, it would not affect or
                decrease the ROV's ability to close the required components for well
                control purposes. During a well control event, the most critical
                functions would be to close the BOP components and seal the well.
                 BSEE also proposed to revise paragraph (a)(4) by requiring the ROV
                to function the appropriate BOP component within the required response
                time contained in API Standard 53. BSEE proposed to revise this
                paragraph not only to better align it with API Standard 53, but also to
                account for recent technological advancements in ROV capabilities to
                meet the appropriate BOP closing times. BSEE is aware that operators
                currently use high flow rate ROVs to meet the BOP component closing
                times of API Standard 53.
                 BSEE proposed to incorporate the latest edition (i.e., the 2nd
                edition) of API RP 17H in proposed paragraph (a)(4). BSEE explained
                that there is a conflict between the ANSI/API RP 17H 1st edition, as
                incorporated by reference in the 2016 WCR, and the API Standard 53 ROV
                requirements. The 2nd edition of API RP 17H eliminates the conflict
                with API Standard 53. By incorporating by reference the 2nd edition of
                API RP 17H, BSEE would ensure that the appropriate methods are utilized
                to comply with the API Standard 53 ROV closure timeframe of 45 seconds.
                 BSEE proposed to revise paragraph (a)(6)(iv) by clarifying that the
                autoshear/deadman functions must be able to close, at a minimum, two
                shear rams in sequence, but do not need to operate every emergency
                function. Closing two shear rams in sequence may not be advantageous
                for certain Emergency Disconnect Sequence (EDS) functions, as discussed
                in the proposed rule (83 FR 22140).
                 BSEE proposed to revise paragraph (a)(16) by removing references to
                the centering mechanism and the ability to mitigate compression of the
                pipe between the shear rams in paragraphs (a)(16)(i) and (ii),
                respectively. Many of the shear ram designs have improved the shearing
                capabilities to help ensure the shearing is conducted on the
                appropriate shearing area of the shear blades.
                 BSEE proposed to revise paragraph (b)(1) by replacing the BAVO
                references with references to an independent third party.
                 BSEE also proposed to revise paragraph (b)(2), redesignate existing
                paragraph (b)(3) as (b)(4), and add new paragraph (b)(3) in order to
                include provisions for testing the applicable BOP or LMRP upon relatch
                of the BOP or LMRP to the well. BSEE proposed these revisions to codify
                longstanding BSEE policy and to clarify testing requirements when an
                operator has returned to the well location and relatched the BOP or
                LMRP to the well. These tests would help confirm that the BOP or LMRP
                is properly functional prior to resuming operations after the BOP or
                LMRP is removed.
                Summary of Final Rule Revisions
                 BSEE received and considered comments on the proposed revisions and
                includes most of the proposed language in the final rule without
                change, except for the following revisions.
                 BSEE is not finalizing the proposed revisions to paragraph
                (a)(1)(ii) and is keeping many of the existing requirements, except for
                the references to the now-past compliance date from the 2016 WCR. This
                change from the proposed rule is based on BSEE's consideration of
                comments received and on BSEE's understanding concerning the importance
                of shearing redundancy. It is also based on BSEE's recognition that the
                proposed language would have permitted reliance on a ``combination'' of
                shear rams, which would have created some potential ambiguity regarding
                the number of rams subject to this shearing requirement.
                 BSEE revised final paragraph (a)(3)(iii) by removing the extended
                compliance date and clarifying that the accumulator bottles for
                autoshear and deadman must be located subsea. Based on comments
                received, BSEE is removing the existing compliance date of April 29,
                2021, for this provision because an extension of time is no longer
                necessary due to the current operational abilities of the accumulator
                systems. The autoshear/deadman systems are functions not controlled by
                surface personnel and are essentially considered failsafe. The bottles
                need to be located subsea to ensure there is enough fluid and pressure
                to operate the associated respective functions. BSEE revised final
                paragraph (a)(4) by clarifying that the operator must have the ROV
                intervention capability to close the identified BOP components. This
                revision is based on comments received and will help ensure that the
                BOP components can be properly functioned, if necessary, through the
                use of an ROV hot stab. BSEE emphasizes that the response times are a
                critical function of the ROV capabilities; BSEE does not want to limit
                the options available to function the required BOP components. The use
                of flying leads, a Subsea Accumulator Module (SAM) unit, or a
                [[Page 21953]]
                high flow ROV can all meet the required component closing time. This
                revision is consistent with a BSEE Q and A posted on BSEE's website at
                https://www.bsee.gov/guidance-and-regulations/regulations/well-control-rule.
                 BSEE also revised paragraph (a)(6)(iv) by adding ``and an EDS
                mode'' after ``functions.'' This revision is based on BSEE's
                consideration of comments and is intended to clarify that an EDS mode
                must be able to shear in an emergency situation. This is also
                consistent with guidance provided in the BSEE Q and As posted on BSEE's
                website at https://www.bsee.gov/guidance-and-regulations/regulations/well-control-rule.
                 Based on consideration of comments, BSEE is revising paragraph
                (a)(6)(v) to retain a modified version of the existing requirement that
                the sequencing must allow a sufficient delay when closing two shear
                rams in order to provide maximum sealing efficiency. Due to the various
                BOP configurations across industry, BSEE wants to provide clarity about
                how the BOP systems should function properly to achieve necessary
                shearing and sealing during a well control event.
                 Based on consideration of comments received, BSEE is revising
                paragraph (a)(16)(i) to preserve a modified version of the existing
                requirement for operators to have the capability to position the entire
                pipe completely within the area of the shearing blade. This capability
                cannot be another ram BOP or annular preventer, but these may be used
                during a planned shear. BSEE recognizes that the technology exists to
                help ensure the pipe is positioned within the shear surface to optimize
                shearing capabilities. BSEE agrees with some commenters that, even
                though this technology exists, the proposed rule's wholesale removal of
                the positioning requirement did not specifically require the use of
                such technology. BSEE is restoring the requirement to have the
                capability to position the pipe within the shearing blade; however,
                BSEE does not require this to be achieved with a separate mechanism and
                allows use of the shear ram. As encouraged by Congress \32\ to ensure
                that offshore operations promote safety and protect the environment in
                a technically feasible manner, BSEE does not want to limit the use of
                improved technological advancements in shear blade designs. BSEE
                retained the compliance date of May 1, 2023, associated with the
                original centering mechanism requirement.
                ---------------------------------------------------------------------------
                 \32\ See n. 10, supra.
                ---------------------------------------------------------------------------
                 BSEE is also revising paragraph (b)(1) to require operators to
                submit a revised permit with a written statement from an independent
                third party documenting the BOP system repairs and certifying that the
                previous certification, required in Sec. 250.731(c), remains valid.
                This revision is necessary for consistency with similar requirements
                and revisions based on BSEE's consideration of comments received on
                proposed Sec. 250.720. This revision will provide BSEE with additional
                assurance that the related equipment is fit for service upon relatch of
                the BOP to the well, and will reflect current BSEE practice. The type
                of information required within this new submittal is similar to the
                type of information operators submit with their original required BSEE
                permits. This revision helps provide assurance that there is a current
                certification of the BOP and provides consistent documentation of
                recertification. BSEE includes the proposed language for paragraphs
                (b)(2) and (3) in the final rule without change.
                Summary of Comments
                Comments Related to Proposed Sec. 250.734--(Dual Shear Rams)
                 Summary of comments: Numerous commenters opposed the proposed
                elimination of the existing requirement that both shear rams be capable
                of shearing certain equipment in the hole and the proposal to replace
                that requirement with a requirement that a combination of shear rams be
                capable of shearing the equipment. The commenters asserted that this
                proposed change would weaken the regulations and negatively impact
                safety because it would not provide for a fully redundant shear ram as
                a backup. The commenters also asserted that the proposed revision would
                not account for situations in which one of the shear rams malfunctions.
                One of these commenters requested an explanation from BSEE as to why
                requiring only one shear ram to seal under MASP is acceptable. Another
                commenter suggested that the regulations should prescribe a minimum
                design basis capability for shear rams, along with a clear date for
                compliance.
                 Response: BSEE agrees with the comments about the utility
                of redundant shear rams and is revising the proposed requirement in
                Sec. 250.734(a)(1)(ii) that a ``combination of the shear rams must be
                capable of . . .'' to preserve in the final rule the existing
                requirement that ``[b]oth shear rams must be capable of . . . .'' This
                revision will keep that portion of paragraph (a)(1)(ii) as it is in the
                existing regulations. BSEE's analysis is set forth in further detail
                above at Section III.B.3. BSEE may consider possible revisions to this
                provision in future rulemakings.
                Comments Related to Proposed Sec. 250.734(a)(3)(iii)--Compliance Date
                for Shared Accumulator Bottles
                 Summary of comments: A commenter questioned whether the reference
                to the April 29, 2021, date is necessary if there is no longer a
                requirement to have dedicated bottles in the accumulator system.
                 Response: BSEE agrees with the commenter and removed the
                reference to the compliance date of April 29, 2021 from final Sec.
                250.734(a)(3)(iii). BSEE is removing the compliance date because no
                extension of time is necessary due to the current operational
                capabilities of the accumulator systems.
                Comments Related to Proposed Sec. 250.734(a)(6)(v)--Shearing Risk
                Assessment
                 Summary of comments: A commenter suggested that a risk assessment
                should be performed to ensure the fish of the sheared tubular is clear
                of the blind ram while it is trying to close. For example, the
                commenter asserted, if the drill pipe was in compression and the
                sequence was casing shear ram (CSR) then BSR, the BSR would not be
                closing on an open hole due to fact that it must be located above the
                CSR. The commenter also requested clarification that, for emergency
                functions, no additional steps can be taken (such as lifting the drill
                pipe, hanging off on pipe rams, etc.).
                 Response: BSEE does not agree with the suggestion that a
                risk assessment should be required for shearing procedures. However, an
                operator may use a risk assessment to help identify the actions by
                personnel required in the well control plan in accordance with Sec.
                250.710, What instructions must be given to personnel engaged in well
                operations? The regulations also require that the well control plan
                contain specific procedures regarding how operators would seal the
                wellbore and shear pipe, including what to do when non-shearables are
                located across a BSR.
                 Summary of comments: A commenter suggested adding a requirement
                that a single shear ram, or a combination of shear rams, must be
                capable of performing the shearing tasks.
                 Response: BSEE does not agree with the suggested revision.
                BSEE is keeping the existing provision in Sec. 250.734(a)(1)(ii) that
                requires both shear rams to be capable of shearing the specified
                components. The suggested
                [[Page 21954]]
                revisions would not support a fully redundant shear ram in the event
                one shear ram is unable to function. BSEE may evaluate revisions to
                this provision in future rulemakings.
                Comments Related to Proposed Sec. 250.734--Centering Pipe While
                Shearing
                 Summary of comments: Several commenters supported removing the
                requirement to have a centering mechanism to center the drill pipe
                prior to shearing. Those same commenters, however, disagreed with the
                need for prescriptive design requirements for the shear ram, since
                those requirements are already adequately addressed in ANSI/API Spec.
                16A 4th Edition--Specification for Drill-through Equipment.
                 Response: BSEE disagrees in part and agrees in part. BSEE
                is retaining the requirement that operators have the capability to
                position the pipe within the shearing blade; however, BSEE does not
                require this to be achieved with a separate mechanism and will allow
                this capability to be established with the shear ram. BSEE recognizes
                that the technology exists to help ensure the pipe is positioned within
                the shear surface to optimize shearing capabilities. The proposed rule,
                however, did not specifically require the use of such centering
                technology. As encouraged by Congress \33\ to ensure that offshore
                operations promote safety and protect the environment in a technically
                feasible manner, BSEE agrees with the importance of such capabilities,
                but does not want to limit the use of improved technological
                advancements in shear blade designs. For further analysis, see Section
                III.B.2. BSEE currently incorporates ANSI/API Spec. 16A, Third edition
                in Sec. 250.198.
                ---------------------------------------------------------------------------
                 \33\ See n. 10, supra.
                ---------------------------------------------------------------------------
                 Summary of comments: Numerous commenters disagree with eliminating
                the requirement for a drill pipe centering mechanism. These commenters
                cite numerous reasons for why they disagree, including that the need
                for a centering mechanism was a lesson learned from the Deepwater
                Horizon investigation, and that the existing shear rams that do not use
                newer technology would not be able to center the drill pipe. One of
                these commenters suggests that using the newer shearing blades that can
                center a pipe should be a baseline requirement, and that a specific
                timeframe for compliance should be established. The commenters also
                question whether the agency has sufficient experience with implementing
                the centering mechanism requirement of the 2016 WCR, because that
                requirement is not currently in effect. One commenter agrees that a
                centering mechanism is not necessary, but asserts that there should be
                a requirement for the capability to shear the tubular in any position
                in the wellbore.
                 Response: BSEE agrees with the comments about the
                importance of requiring pipe centering capabilities, and is retaining
                the requirement that operators have the capability to position the pipe
                within the shearing blade. However, BSEE will not find it necessary for
                this to be achieved with a separate mechanism and will allow this
                capability to be established with the shear ram (e.g., shear ram blade
                design). BSEE recognizes the technology exists to help ensure the pipe
                is positioned within the shear surface to optimize shearing
                capabilities. The proposed rule, however, did not specifically require
                the use of such centering technology. As encouraged by Congress \34\ to
                ensure that offshore operations promote safety and protect the
                environment in a technically feasible manner, BSEE agrees with the
                importance of such capabilities, but does not want to limit the use of
                improved technological advancements in shear blade designs. For further
                analysis, see Section III.B.2.
                ---------------------------------------------------------------------------
                 \34\ See n. 10, supra.
                ---------------------------------------------------------------------------
                Comments Related to Proposed Sec. 250.734--Emergency Functions--EDS,
                Autoshear/Deadman
                 Summary of comments: One commenter asserts that the justification
                for eliminating the requirement for the Emergency Disconnect Sequence
                (EDS) system to be capable of closing two shear rams in sequence is
                inadequate because the proposed revisions would not sufficiently
                address how shear ram closure will be assured when an EDS occurs.
                 Response: BSEE has revised paragraph (a)(6)(iv) by adding
                ``and an EDS mode'' after ``functions'' to provide clarity about how
                the BOP systems should function properly to achieve necessary shearing
                and sealing. This revision is based on BSEE's consideration of comments
                and is intended to clarify that an EDS mode must be able to shear in an
                emergency situation. BSEE wants to ensure optimal shearing and sealing
                functionality during a well control event. Depending on the rig
                operations, operators develop different EDS modes that would function
                different BOP components at appropriate times. The selection of the EDS
                mode and the specific sequencing of emergency functions should be
                developed by the operator based on safety considerations and an
                operational risk assessment. The EDS mode is a separate type of
                emergency function from the autoshear/deadman. EDS is a function that
                is manually initiated and operated by rig personnel and involves a
                controlled disconnect.
                 Summary of comments: Multiple commenters support the requirement
                that the autoshear/deadman systems close, at a minimum, two shear rams
                in sequence. A commenter proposed to add that: The sequence should
                allow a sufficient delay to complete the shearing function before
                sealing and that a risk assessment should be performed to ensure no
                conditions exist where the sealing rams would be expected to shear
                after the non-sealing ram shears, and no additional procedures, such as
                lifting the drill pipe, can be performed for emergency systems.
                 Response: BSEE has revised paragraph (a)(6)(v) to retain a
                modified version of the existing requirement that the sequencing must
                allow a sufficient delay when closing two shear rams in order to
                provide maximum sealing efficiency. Due to the various BOP
                configurations across industry, BSEE wants to provide clarity about how
                the BOP systems should function properly to achieve necessary shearing
                and sealing during a well control event. BSEE wants to ensure optimal
                shearing and sealing functionality during a well control event.
                Depending upon the rig operations, operators develop different EDS
                modes that would function different BOP components at appropriate
                times. The selection of the EDS mode and the specific sequencing of
                emergency functions should be developed by the operator based on safety
                considerations and an operational risk assessment. The EDS mode is a
                separate type of emergency function from the autoshear/deadman. EDS is
                a function that is manually initiated and operated by rig personnel and
                involves a controlled disconnect. Operators may use a risk assessment
                to help identify the actions required of personnel in the well control
                plan in accordance with Sec. 250.710. The well control plan contains
                specific procedures about how operators would seal the wellbore and
                shear pipe, including what to do when non-shearables are located across
                a BSR.
                Comments Related to Proposed Sec. 250.734--Pipe Compression
                 Summary of comments: Several commenters identified a potential pipe
                compression issue when functioning the shear rams. Commenters asserted
                that pipe compression could compromise
                [[Page 21955]]
                the proper functioning of the BOP, and a commenter adds that a better
                understanding of dynamic fluid conditions inside the BOP is needed in
                order to improve shearing and sealing capabilities. Another commenter
                asserted that drill pipe compression along with a sequence of casing
                shear ram then blind shear ram would preclude the blind shear ram from
                closing on an open hole, and that operators must have the ability to
                mitigate compression of the pipe stub between the shearing rams when
                both shear rams are closed. The commenters question whether there have
                been sufficient technological advances in BOP and shear ram design in
                the two years since the adoption of the 2016 WCR, and the validity of
                the assumption that there will be industry-wide adoption of the new
                technologies if they exist.
                 Response: As a general matter, BSEE agrees that
                understanding the dynamic fluid condition inside the BOP is an
                important research area. BSEE is requiring in Sec. 250.734(a)(16)(i)
                of the final rule the capability to position the pipe within the
                shearing blade, which will help mitigate the concerns about the ability
                to shear pipe due to compression. BSEE recognizes that the technology
                exists to help ensure the pipe is positioned within the shear surface
                to optimize shearing capabilities. BSEE is retaining the requirement to
                utilize such technology, but allowing for different technologies to
                meet this requirement.
                Comments Related to Proposed Sec. 250.734--Retesting Deadman
                 Summary of comments: Multiple commenters disagreed with the
                requirement to retest the deadman system when the system has not been
                repaired or affected by a suspension of operations. The commenters
                asserted that retesting the deadman subsea after a successful surface
                certification is not necessary every time the BOP or LMRP is latched to
                the wellhead, and that the previous test is sufficient to demonstrate
                the system's proper functioning when the system has not been modified.
                The commenters assert that testing the deadman system in such
                situations presents unnecessary risks.
                 Response: BSEE disagrees. When the functional system is
                disconnected, it is important to ensure that the emergency systems are
                completely functional upon reconnection of that system. BSEE has
                determined that this requires retesting upon relatch.
                 Summary of comments: One commenter is concerned with allowing
                operators to conduct the deadman test at a low psi, so long as
                operators end the test with an acceptable psi, because allowing such a
                test procedure would place a significant amount of trust in industry
                self-regulation.
                 Response: BSEE is allowing the use of a 1,000 psi test for
                the initial deadman test to verify functionality of the system. BSEE
                will still require operators to fully pressure test the components used
                within the deadman system according to Sec. 250.737(d)(4). BSEE will
                oversee and enforce compliance with these testing requirements and will
                not rely on industry self-regulation.
                Comments Related to Proposed Sec. 250.734(a)(4)--ROV Intervention
                 Summary of comments: Numerous commenters supported removing the
                open function requirement from the ROV panel. However, the commenters
                also requested clarity regarding whether the timing requirements could
                be met by using only an ROV or by using a flying lead. These commenters
                suggested aligning the timing requirements with those in API Standard
                53 and prior references in the rule with respect to ROV capability.
                 Response: BSEE is revising this section to clarify that
                operators must have the capability to perform the required function in
                the response times outlined in API Standard 53. This can be
                accomplished with a flying lead or SAM unit, or the ROV. This
                clarification is based on a BSEE Q and A related to the 2016 WCR. BSEE
                agrees that the response times are the critical function of the ROV
                capabilities. BSEE has not mandated a high capacity ROV, but rather
                that the ROV hot stabs would accept the high flow via flying leads.
                 Summary of comments: Some commenters expressed concern about the
                reference to compliance with API RP 17H 2nd Edition, since API Standard
                53 already covers the same requirement and the relevant receptacles are
                not materially different from those addressed in ANSI/API RP 17H 1st
                Edition.
                 Response: BSEE disagrees with the assertion that BSEE
                should only reference API Standard 53. API Standard 53 does not contain
                all of the same information or the same level of specificity covered
                under API RP 17H.
                 Summary of comments: One commenter opposed removing the requirement
                that ROVs be capable of opening each shear ram, ram lock, or pipe ram,
                since the ability to temporarily open the ram or lock may be necessary
                for well control intervention. The commenter also disagreed with
                relying on API Standard 53 because industry standards can be weakened,
                whereas standards established by the agency and set in regulations can
                be more stringent.
                 Response: As more thoroughly described in the preamble to
                the proposed rule, the most critical ROV functions would be to close
                the BOP components and seal the well for well control purposes. This
                regulatory revision does not limit the operator's ability to include
                the open function on the ROV panel. With respect to the comments
                regarding reliance on industry standards, BSEE incorporates a specific
                edition of a standard; when a standard is updated by the standards
                organization, BSEE evaluates the updated edition and would only
                incorporate the updated edition as appropriate. In other words, BSEE
                only incorporates into its regulations (through public rulemaking)
                those standards that it has determined to be adequate and appropriate,
                and the regulatory force and content of those incorporated standards
                can only be altered through subsequent rulemaking. BSEE also utilizes
                industry standards to establish foundational requirements which it can
                supplement.
                Comments Related to Proposed Sec. 250.734--Accumulator Systems and
                Capacity
                 Summary of comments: A commenter supported BSEE's proposed
                revisions to allow sharing of bottles among emergency and secondary
                control system functions to secure [acy] wellbore. The commenter
                recommended that BSEE reference the [Acy][Rcy][Iukcy] Spec. 16D,
                Specification for Control Systems for Drilling Well Control Equipment
                and Control Systems for Diverter Equipment, Second Edition,
                incorporated by reference in Sec. 250.198 related to controls systems,
                and clarify whether sharing bottles would be [acy] sufficiently
                redundant system to allow for emergency use.
                 Response: BSEE agrees with the commenter generally about
                the use of API Spec. 16D related to control systems; however, BSEE
                disagrees that a reference to API Spec. 16D is necessary in this
                section. BSEE already incorporates API Spec. 16D and API Standard 53,
                and requires sufficient accumulator volume for the emergency
                operations. The accumulator requirements are covered under Sec.
                250.735.
                 Summary of comments: A commenter asserted that BSEE's proposed
                revisions to the accumulator requirements in Sec. 250.734(a)(3) would
                reduce safety and severely weaken the ability of the subsea BOP system
                to function in the
                [[Page 21956]]
                event of a lost connection to the surface rig. The commenter further
                asserted that BSEE does not explain how removing the reference to the
                subsea location of accumulator capacity would ensure that the
                accumulator system could adequately function if there is a loss of the
                power fluid connection to the surface, and that BSEE therefore must
                continue to require that the necessary accumulator capacity be located
                subsea. The commenter recommended that BSEE should retain the
                requirement in Sec. 250.734(a)(3)(iii) for dedicated bottles.
                 Response: BSEE agrees with the commenter and has revised
                the language in final Sec. 250.734(a)(3)(iii) to clarify that the
                accumulator capacity for autoshear/deadman must be located subsea. The
                autoshear/deadman systems are considered failsafe systems that function
                automatically in emergency situations and do not require surface
                personnel action to function. Consistent with the current requirements,
                the accumulator bottles that function those systems need to be located
                subsea to ensure there is enough fluid and pressure to operate the
                associated functions. This is a clarification to ensure there is no
                confusion about where the required fluid and pressure must reside to
                operate the autoshear/deadman emergency functions. Autoshear/deadman
                are separate triggers to operate the same equipment and would not be
                functioned together. Each emergency function has different criteria
                that must be met before it will automatically function.
                Comments Related to Proposed Sec. 250.734--Accumulators and Industry
                Standards
                 Summary of comments: Multiple commenters asserted that BSEE should
                explain why allowing operators to simply use industry standards, which
                do not necessarily require accumulators, is justified.
                 Response: BSEE disagrees with the commenters. BSEE
                incorporates industry standards, not all of which include accumulator
                specifications, into the regulations as required by the NTTAA. Before
                incorporating standards, BSEE thoroughly evaluates them for adequacy
                and appropriateness. BSEE also supplements those standards with its own
                regulatory requirements related to operations and equipment, as we do
                in the case of accumulators.
                Comments Related to Proposed Sec. 250.734--Centering Pipe While
                Shearing
                 Summary of comments: A commenter asserted that this section refers
                to the use of ``newer shearing blades'' which [scy][acy]n center
                [rcy][iukcy][rcy][iecy] as justification for the removal of
                requirements to verify that testing is performed [ocy]n the outermost
                edges of the shearing blades of the shear ram positioning mechanism.
                The commenter asserted that this assumes that these newer blades, which
                are not clearly defined, are used universally. Multiple commenters
                recommended that BSEE should clarify that the newer shearing blades
                that [scy][acy]n center [rcy][iukcy][rcy][iecy] are required and that
                BSEE should give [acy] specific time frame for operators to comply.
                 Response: BSEE generally agrees with the commenters and
                has retained (with modifications) provisions in Sec. 250.734(a)(16)(i)
                that require operators to have the capability to position the entire
                pipe completely within the area of the shearing blade. This capability
                can be achieved by a separate mechanism or by ram design. As encouraged
                by Congress \35\ to ensure that offshore operations promote safety and
                protect the environment in a technically feasible manner, BSEE agrees
                with the importance of positioning capabilities, but does not want to
                limit the technology that can be used to meet those requirements.
                ---------------------------------------------------------------------------
                 \35\ See n. 10, supra.
                ---------------------------------------------------------------------------
                What associated systems and related equipment must all BOP systems
                include? (Sec. 250.735)
                 This section of the existing regulations details the associated
                systems and related equipment that all BOP systems must include. The
                required items include an accumulator system; an automatic backup to
                the primary accumulator-charging system; at least two full BOP control
                stations; choke, kill, and fill-up lines; and locking devices.
                Summary of Proposed Revisions
                 BSEE proposed to revise paragraph (a) by clarifying that the
                accumulator system must have the fluid volume capacity and appropriate
                pre-charge pressures in accordance with API Standard 53. These proposed
                revisions would provide consistency with API Standard 53 and conform to
                the other proposed accumulator system revisions in Sec. 250.734.
                Summary of Final Rule Revisions
                 BSEE received and considered comments on the proposed revisions and
                includes the proposed language in the final rule without change.
                Summary of Comments
                 Comments Related to Sec. 250.735(g)(2)(i)--Remotely Operated
                Locking Devices
                 Summary of comments: A commenter suggested that BSEE remove the
                requirements for remotely operated locking devices on surface BOP blind
                shear rams that are required by April 29, 2019. The commenter asserted
                that, while these types of devices are necessary by design for subsea
                BOPs, due to the inability to manually access the rams and engage
                locking devices, manual access is not an issue on surface BOPs and the
                manual locking devices that have been successfully utilized for decades
                are sufficient to allow securing of these surface rams when necessary.
                The commenter asserted that there are multiple surface BOP sizes and
                ratings that would require these modifications and expressed concerns
                about space issues to accommodate the modified locking systems,
                depending on the rig size and type being utilized.
                 Response: BSEE did not propose or discuss changes to this
                provision in the proposed rule and as such would not be in a position
                to make the suggested changes in this final rule. Regardless, BSEE
                disagrees with the suggestion about removing the remotely locking
                device requirement for surface BOP blind shear rams. BSEE's position is
                that a manual lock would require rig personnel to enter a potentially
                hazardous area and that a remotely locking device would help limit
                personnel exposure to the potentially hazardous area, if a shearing
                event is necessary.
                 Summary of comments: A commenter requested clarification in
                paragraph (g)(2) that a pilot-operated check valve is considered a
                remotely operated locking device. The commenter suggested that the rule
                should be modified to read as follows: ``(2) For surface BOPs: (i)
                Remotely operated locking devices (i.e., pilot operated check valve)
                must be installed on blind shear rams no later than April 29, 2021. . .
                .''
                 Response: BSEE did not propose or discuss changes to this
                provision in the proposed rule, and as such would not be in a position
                to make the suggested changes in this final rule. Regardless, BSEE does
                not want to limit the types of devices (e.g., pilot operated check
                valve) that can be used for locking. Operators should contact the
                appropriate BSEE District Manager if there are any questions about the
                specified use of this type of equipment.
                [[Page 21957]]
                What are the requirements for choke manifolds, kelly-type valves inside
                BOPs, and drill string safety valves? (Sec. 250.736)
                 This section of the existing regulations describes the requirements
                for the installation, use, and capability of choke manifolds, BOP
                systems, valves, pipes, and flexible hoses appropriate for the working
                pressure and temperature and operating conditions.
                Summary of Proposed Revisions
                 BSEE proposed to revise paragraph (d)(5) by including equipment
                requirements for the safety valve when running casing with a subsea
                BOP. This revision would specify that the safety valve must be
                available on the rig floor if the length of casing being run exceeds
                the water depth, which would result in the casing being across the BOP
                stack and the rig floor prior to crossing over to the drill pipe
                running string. This revision would provide clarity and consistency
                throughout BSEE permitting and minimize the number of alternate
                procedure or equipment requests submitted to BSEE.
                Summary of Final Rule Revisions
                 BSEE received a few comments in general support of the proposed
                revisions to this section and is including the proposed language in the
                final rule without change.
                What are the BOP system testing requirements? (Sec. 250.737)
                 This section of the existing regulations details the pressure test
                frequency, procedures, and duration for BOP systems. This section also
                contains additional testing requirements, including compliance with API
                Standard 53, using water to test a surface BOP system, stump testing a
                subsea BOP system, performing an initial subsea BOP test, alternating
                testing pods between control stations, as well as pressure and function
                tests of various components.
                Summary of Proposed Revisions
                 BSEE solicited comments in the proposed rule ``on whether the BOP
                testing interval should be 7 days, 14 days, or 21 days for all types of
                operations including drilling, completions, workovers, and
                decommissioning,'' as well as ``on the specific cost and operational
                implications of each testing interval.'' \36\ BSEE proposed to revise
                paragraph (b) to clarify the BOP system pressure testing requirements.
                These proposed revisions included clarification that the test rams and
                non-sealing shear rams do not need to be pressure tested, because the
                non-sealing shear rams are not pressure holding components and the test
                ram is an inverted ram that is not utilized for well control purposes.
                BSEE also proposed to revise paragraph (b)(2) to reflect the current
                BSEE policy for conducting the high-pressure test for specific
                components. For example, some of the proposed revisions included
                specific procedures and testing parameters for initial equipment
                pressure testing, as well as provisions for subsequent pressure testing
                on the same equipment.
                ---------------------------------------------------------------------------
                 \36\ 83 FR 22143 (May 11, 2018).
                ---------------------------------------------------------------------------
                 In the proposed rule, BSEE proposed to revise paragraphs (d)(2)(ii)
                and (d)(3)(iii) by removing the requirement to submit test results to
                BSEE where BSEE is unable to witness testing. These proposed revisions
                would significantly reduce the number of submittals to BSEE and
                minimize the associated burden for BSEE to review those submittals. If
                BSEE is unable to witness the testing, BSEE may access the testing
                documentation upon request, in accordance with Sec. Sec. 250.740,
                250.741, and 250.746.
                 BSEE proposed to revise paragraph (d)(3)(iv) by removing ``test
                and[.]'' BSEE would remove this term to minimize confusion regarding
                verification and testing. In this instance, verification of closure
                qualifies as testing the ROV functions. The purpose of the stump test
                is to help ensure the BOP components and control systems can function
                properly before being utilized on a well.
                 BSEE proposed to revise paragraph (d)(3)(v) to clarify that
                pressure testing of each ram and annular on the stump test is only
                required once. This revision would help ensure that the testing of BOP
                components during stump testing would limit unnecessarily duplicative
                pressure testing of each ram or annular. It is unnecessary to pressure
                test a ram or annular multiple times during stump testing if that
                component has already been successfully pressure tested, verifying
                proper functionality.
                 BSEE proposed to revise paragraph (d)(4)(i) to clarify that the
                initial subsea BOP test on the seafloor would need to begin ``within 30
                days of the stump test.'' BSEE receives many questions about the timing
                of the initial subsea test and, as written, the regulation was
                ambiguous regarding exactly what needed to occur within the 30 days.
                BSEE proposed this revision to clarify that the testing must begin
                within 30 days of the stump test. BSEE wants to ensure that the time
                between the stump testing and the initial subsea test is minimal to
                help confirm that all of the BOP components can properly function upon
                installation on the well.
                 BSEE proposed to revise paragraph (d)(4)(iii) to include annulars
                in the pressure testing requirements of paragraphs (b) and (c) of this
                section. This proposed revision would not alter the current testing
                requirements for annulars and would provide clarity for where to find
                them.
                 BSEE proposed to revise paragraph (d)(4)(v) to clarify the initial
                subsea pressure testing requirements to confirm closure of the selected
                ram through an ROV hot stab. This revision would require the operator
                to confirm closure through a 1,000 psi pressure test held for 5
                minutes. This proposed revision would codify BSEE policy for pressure
                testing the selected ram through the ROV hot stabs. BSEE has concluded
                that testing to higher pressures is not necessary for this circumstance
                because the intended purpose of this test is to verify operability of
                the ROV hot stab to close the selected ram. Selected rams must be
                pressure tested according to other regularly required pressure testing
                intervals and prior to commencing well operations.
                 BSEE proposed to remove existing paragraph (d)(4)(vi) because the
                testing requirements of the selected ram would now be covered under
                proposed paragraph (d)(4)(v).
                 BSEE also proposed to revise paragraph (d)(5) by clarifying the
                alternating testing schedules of control stations and pods. These
                proposed revisions help ensure that operators develop a testing
                schedule that provides for alternating testing between the control
                stations, and also between the pods for subsea BOPs. The intended
                result of alternating the testing is to ensure that each control
                station, and each pod for subsea, can properly function all required
                BOP components. BSEE proposed to revise paragraph (d)(12)(iv) by
                clarifying that, during the deadman test on the seafloor, operators are
                not required to indicate the discharge pressure of the subsea
                accumulator throughout the entire test. These revisions would require
                that the remaining pressure be documented at the end of the test, to
                help verify the proper accumulator settings required to function the
                specific critical BOP components.
                 BSEE proposed to revise paragraph (d)(12)(vi) to clarify the
                pressure testing requirements of the 2016 WCR, and to confirm closure
                of the BSR(s) during the autoshear/deadman and EDS testing. This
                proposed revision would require confirmation of closure through a 1,000
                psi pressure test held for 5 minutes.
                [[Page 21958]]
                Testing to higher pressures is not necessary for this circumstance
                because the BSR(s) will be pressure tested according to other regularly
                required pressure testing intervals and prior to commencing well
                operations.
                 BSEE proposed to add paragraph (d)(13) setting forth exceptions
                from the requirements for pressure testing the choke and kill side
                outlet valves. This proposed addition would codify BSEE policy and
                provide consistency for permitting throughout the Regions and Districts
                without meaningfully reducing safety or environmental protection.
                Summary of Final Rule Revisions
                 BSEE received and considered comments on the proposed revisions and
                includes most of the proposed language in the final rule without
                change, except for the following revisions. Based on comments received,
                BSEE is redesignating existing paragraph (a)(4) as (a)(5) and adding
                new paragraph (a)(4) to allow the use of a 21-day BOP pressure testing
                frequency, in lieu of meeting the schedule established in paragraph
                (a)(2), if certain criteria are met and BSEE approves an operator's 21-
                day BOP testing frequency request. BSEE is requiring operators to
                demonstrate, in the 21-day BOP testing frequency request, that they
                have developed a BOP health monitoring plan that includes certain
                system capabilities. BSEE is requiring the BOP health monitoring plan
                to include condition monitoring tools that are able to provide
                continuous surveillance of sensor readings from the BOP control system,
                real-time condition analysis and displays, functional pressure signal
                analysis, and historical sensor data. The plan also must include
                failure propagation analysis and a failure tracking and resolution
                system to identify recurring problems. BSEE is also requiring the
                operators to submit quarterly reports of the data collected to the BSEE
                Regional Supervisor, District Field Operations.
                 BSEE is revising paragraph (b)(3) by adding ``or APM'' after APD.
                This addition is based on BSEE's further analysis of the proposed rule
                and provides clarification. This revision codifies longstanding BSEE
                practice of identifying the applicable operational permit that is used
                for specific types of operations.
                 Based on comments received, BSEE is revising paragraph (c) to
                clarify that the use of a digital recorder is an acceptable method for
                documenting the duration of pressure tests. This revision is only a
                minor clarification. BSEE already allows the use of a digital recorder
                on subsea BOP tests and this revision codifies current practice.
                 BSEE is revising paragraph (d)(10) to address the 21-day BOP
                pressure testing option in new paragraph (a)(4). If BSEE approves an
                operator's request to use a 21-day BOP test frequency in accordance
                with paragraph (a)(4), then BSEE will allow the operator to function
                test its shear ram(s) BOPs every 21 days in accordance with the terms
                of that approval.
                 BSEE is also making minor corresponding revisions to paragraph
                (d)(13)(i) to remove the reference to the 14-day BOP testing and to
                clarify that the specified procedure applies to BOP testing,
                irrespective of the BOP testing frequency.
                Summary of Comments
                Comments Related to Sec. 250.737(a)(2)--21-Day BOP Testing Frequency
                 Summary of comments: BSEE received multiple comments supporting and
                opposing any changes to the BOP testing frequency, as discussed in
                sections III and IV of this preamble. However, a commenter recommended
                that BSEE allow a 21-day testing frequency if additional requirements
                were put in place to help provide assurances of BOP functionality,
                equivalent performance, and operational risk as under a 14-day BOP
                testing frequency. The commenter recommended that BSEE require
                condition monitoring tools, failure propagation analysis, and a failure
                tracking and resolution system. In addition, the commenter suggested
                that if BSEE allowed a 21-day BOP testing frequency, it should require
                the operator to collect lifecycle data related to the reliability of
                performance of functioned components, determine whether there is a
                relationship between usage and deterioration, and understand the impact
                of testing frequency on reliability. In addition, a commenter asserted
                that the proposed rule did not identify to which technologies BSEE was
                referring with regard to possible revisions to BOP system testing
                requirements, or under what circumstances or based on what information
                BSEE might amend or restructure Sec. 250.737.
                 Response: BSEE agrees with the commenter's recommendations
                about allowing a 21-day BOP testing frequency if there are additional
                requirements to help provide assurance of equivalent performance and
                operational risk when compared to a 14-day BOP testing frequency. In
                the final rule, BSEE is allowing the use of a 21-day BOP testing
                frequency. However, before an operator can use this option, it must
                submit a request to BSEE for approval to use a 21-day BOP testing
                frequency. In the 21-day BOP testing frequency request, BSEE is
                requiring the operator to develop a BOP health monitoring plan that
                includes the use of condition monitoring tools capable of providing
                continuous surveillance of sensor readings from the BOP control system,
                real-time condition analysis and displays, functional pressure signal
                analysis, and trending capabilities of the sensor data. The plan must
                include failure propagation analysis and a failure tracking and
                resolution system to identify recurring problems. BSEE is also
                requiring operators to submit quarterly reports of the data collected
                to the BSEE Regional Supervisor, District Field Operations. BSEE will
                review this data to help ensure compliance with the requirements of the
                regulations and help evaluate the effectiveness and appropriateness of
                the 21-day testing frequency. BSEE disagrees with the assertion that it
                did not identify clearly enough the types of actions it was
                considering. The proposed rule solicited comments on a number of issues
                related to this topic, along with context for the solicitation (see 83
                FR 22143) and BSEE's final rule is based on its analysis of the input
                received in response to that solicitation and other elements of the
                record. Further analysis of BSEE's action on this issue is found at
                Sections III.B.5 and IV.C of this preamble.
                Comments Related to Proposed Sec. 250.737(b)--BOP Testing Validity
                 Summary of comments: Multiple commenters recommended that BSEE
                align the regulations with the testing requirements of API Standard 53
                and allow the use of alternative pressure testing systems that can
                determine test validity in less than 5 minutes. The commenters
                requested that BSEE clarify the statement in paragraph (b) that states
                ``. . . test must hold pressure long enough to demonstrate the tested
                component(s) holds the required pressure.''
                 Response: BSEE disagrees with the recommendation that BSEE
                should allow the use of systems that can test in less than 5 minutes.
                More research and consistency is necessary before BSEE will be in a
                position to allow pressure testing systems that demonstrate test
                validity in less than 5 minutes. BSEE also disagrees with the
                commenters' request to clarify that the test must hold pressure long
                enough to demonstrate the tested component(s) holds the required
                pressure, because more research and consistency is necessary before
                BSEE
                [[Page 21959]]
                will be in a position to validate alternative timeframes.
                Comments Related to Proposed Sec. 250.737(d)--Verification of ROV
                Intervention Functions
                 Summary of comments: Multiple commenters recommended that any
                additional installed ROV intervention functions must be verified per
                the equipment owner's maintenance program, but not to exceed once per
                year.
                 Response: BSEE disagrees with this recommendation. BSEE
                wants to ensure that operators verify all ROV hot stabs prior to
                commencing operations on each well.
                Comments Related to Proposed Sec. 250.737(d)(2) and (3)--Review of
                Testing Results
                 Summary of comments: Multiple commenters opposed the proposed
                removal of the requirement that the operator must provide the initial
                test results to the District Manager if BSEE cannot witness testing.
                The commenters expressed concerns with removing the real-time
                supervision of the methods used to conduct inspections of well control
                system components, asserting that the change would allow too much
                discretion to operators, and would remove a safeguard that prevents
                inadequate testing, thus reducing safety.
                 Response: BSEE disagrees with the assertion that the
                removal of the requirement to provide the initial test results to BSEE,
                when BSEE is unable to witness testing, reduces safety. BSEE reviews
                the test results during routine inspections of facilities. The operator
                is still required to make the results available to BSEE upon request
                for verification. BSEE also retains the option for BSEE to witness the
                testing.
                Comments Related to Proposed Sec. 250.737(d)(3)(iv)--Testing of ROV
                Panels During Stump Testing
                 Summary of comments: A commenter asserted that, since BSEE proposed
                that BOP ROV panels should not be required to have open functions, BSEE
                should remove the requirement to test systems that currently have open
                functions for rams on the ROV panels. The commenter was concerned that
                operators with systems that already have open functions for rams will
                remove them so they do not have to test.
                 Response: BSEE disagrees with the comment. The referenced
                testing requirement is applicable to the stump test, which is performed
                before the BOP is installed. The stump test is used to verify the
                functionality of the ROV components while on the surface, before the
                equipment is run subsea and latched onto the well. BSEE wants to ensure
                that the equipment, as configured, is operational before it is run
                subsea.
                Comments Related to Proposed Sec. 250.737(d)(4)(v)--Verifying Closure
                of Rams Through ROV Hot Stabs
                 Summary of comments: A commenter asserted that although the
                proposed method for confirming closure of the rams may be a valid
                method of verifying closure, there are other methods that should be
                approved, such as position indicators, and a combination of parameters
                such as volume, time, and a pressure spike at the end of travel. The
                commenter asserted that the pressure of 1,000 psi seems completely
                arbitrary and had been specifically rejected by BSEE in the alternate
                procedure/departures section of the August 17, 2016 WCR presentation in
                Houston, Texas.
                 Response: BSEE disagrees with the recommendation to accept
                use of the identified methods to confirm closure of the rams. More
                research and data is necessary to fully evaluate those methods and BSEE
                may include those methods in future rulemakings, depending on future
                findings. BSEE is allowing the use of 1,000 psi pressure for the ROV
                test because that is sufficient to verify functionality of the system.
                The BOP system and each BOP component are still required to be fully
                pressure tested according to Sec. 250.737(b).
                Comments Related to Proposed Sec. 250.737(d)(5)(ii)--Testing of Remote
                Panels
                 Summary of comments: Multiple commenters recommended that BSEE
                revise the regulations to allow additional alignment between the
                proposed rule and API Standard 53, Section 7.6.5.1.4, which states,
                ``[i]f installed, remote panels where all BOP functions are not
                included (e.g. lifeboat panels, etc.) shall be function tested in
                accordance with the equipment owner's procedures.'' The commenters
                asserted that the inclusion of the phrase ``in accordance with the
                equipment owner's procedures'' in the regulations would allow the
                operator to conduct the test with the BOP on-deck and would not alter
                the effectiveness or intent of the proposed BSEE text.
                 Response: BSEE disagrees with the comment. Operators must
                function test the remote panels upon the initial BOP test to ensure
                functionality with the complete installed system. On-deck testing alone
                is not sufficient.
                Comments Related to Proposed Sec. 250.737(d)(3)(v)--Stump Test
                Procedures
                 Summary of comments: Multiple commenters expressed concerns with
                the proposed revisions to Sec. 250.737(d)(3)(v) that stated ``pressure
                testing of each ram and annular component is only required once.'' The
                commenters further expressed concerns with BSEE's proposed rationale to
                eliminate ``unnecessarily duplicative pressure testing'' and to limit
                the risk of component wear. Section 250.737(c) requires repeat testing
                if a pressure test under Sec. 250.737(b) and (c) is not successful.
                The commenters asserted that the proposed revision to Sec.
                250.737(d)(3)(v) does not appear to take into account the possibility
                of a failed test and the need for a repeat test.
                 The commenters further asserted that the Department also proposed
                to weaken Sec. 250.737(d)(5)(i)(A) and (B) by reducing BOP control
                station testing from weekly to every other week and that this change
                would cut in half the BOP control station testing frequency.
                 Response: BSEE disagrees with the assertion that the
                proposed revisions would weaken the regulations. Paragraph (d)(3)(v)
                applies to the stump testing which is conducted prior to the subsea BOP
                stack being latched onto the well. The stump test is the main
                opportunity to identify and correct issues with the stack before
                deployment. There is additional required testing once the BOP stack is
                installed, plus regularly scheduled testing during operations while the
                BOP is latched onto the well. Section 250.737(c) requires a successful
                pressure test of the required components and applies to paragraph (d).
                Accordingly, paragraph (c) states that ``If the equipment does not hold
                the required pressure during a test, you must correct the problem and
                retest the affected component(s).''
                Comments Related to Proposed Sec. 250.737(d)(12)(iv)--Deadman Test
                Procedures
                 Summary of comments: A commenter disagreed with the proposed
                changes to the deadman system test procedures. The commenter expressed
                concerns with the proposed revision that would only require operators
                to record starting and stopping pressure to determine deadman closing
                efficiency.
                 Response: BSEE disagrees that there is any basis for
                concern. In paragraph (d)(12)(iv) testing is used to verify that there
                is sufficient accumulator capacity for the required BOP deadman
                functions. Documenting the final pressure on the subsea accumulator
                [[Page 21960]]
                after a deadman test is sufficient to verify that the subsea
                accumulation system can deliver the necessary fluid volume to execute
                this emergency operation. This verification demonstrates the system is
                adequately deployed in the application on the well for safe operation.
                Comments Related to Proposed Sec. 250.737(d)(12)(vi)--Deadman Test
                Procedures
                 Summary of comments: A commenter asserted that BSEE's proposed
                revision to paragraph (d)(12)(vi) would place a significant amount of
                trust in industry self-regulation because the revision seems to allow
                for operators to conduct the deadman test at low pounds per square inch
                (psi) during the test, as long as operators complete the test with an
                acceptable psi. The commenter recommended that BSEE provide
                justification for the revisions.
                 Response: BSEE is allowing the use of a 1,000 psi test for
                the initial deadman test because that is sufficient to verify
                functionality of the system. The components utilized within the deadman
                system are still required to be fully pressure tested according to
                Sec. 250.737(d)(4). BSEE will oversee compliance with and enforcement
                of these testing requirements and will not rely on industry self-
                regulation.
                What must I do in certain situations involving BOP equipment or
                systems? (Sec. 250.738)
                 This section of the existing regulations describes actions that
                operators must take when certain situations occur with BOP systems,
                such as if the BOP equipment does not hold the required pressure during
                a test or if the BOP control station or pod does not function properly.
                Summary of Proposed Revisions
                 BSEE proposed to revise paragraphs (b), (i), (m), and (o) by
                replacing the references to BAVOs with references to an independent
                third party throughout.
                 BSEE proposed to revise paragraph (f) to clarify the testing
                requirements implemented by the 2016 WCR necessary to verify the
                integrity of the affected casing ram or casing shear ram and
                connections. This proposed revision would codify BSEE policy to allow
                the pressure testing to test the pressure of the BOP component above
                this ram, as specified in the approved permit.
                 BSEE also proposed to revise paragraph (m) to replace the term
                ``well-control equipment'' with ``circulating or ancillary equipment.''
                This revision would eliminate confusion arising from the use of
                conflicting terms that may have different meanings throughout the
                regulations.
                Summary of Final Rule Revisions
                 BSEE received and considered comments on the proposed revisions and
                generally includes the proposed language in the final rule without
                change, except for the following revisions. BSEE is reversing the order
                of existing paragraphs (b)(3) and (b)(4), and redesignating them
                appropriately. This change was necessary to avoid confusion about the
                process for submitting and then getting BSEE approval and reflects the
                logical order for the process. BSEE is revising final paragraph (b)(3)
                with conforming edits to Sec. Sec. 250.720 and 250.734, to require
                operators to submit a revised permit instead of a report. The revised
                permit must include a written statement from an independent third party
                documenting the BOP repairs, replacement, or reconfiguration and
                certifying that the previous certification under Sec. 250.731(c)
                remains valid. This revision is necessary to be consistent with the
                independent third-party certification comments on proposed Sec.
                250.720 and BSEE's final approach to that provision. This revision will
                provide BSEE with additional assurance that the relevant BOP system is
                fit for service upon relatch and reflects current BSEE practice. The
                independent third-party certification contains the same type of
                information operators submit with their original required BSEE permits.
                This revision provides assurance that there is a current certification
                of the BOP and provides consistent documentation of recertification.
                 BSEE removes the language ``with the new, repaired, or reconfigured
                BOP.'' from existing paragraph (b)(3); redesignated by this final rule
                as paragraph (b)(4) because they are redundant to the updated
                introductory language for paragraph (b).
                Summary of Comments
                Comments Related to Proposed Sec. 250.738(f)--Shell Test for Casing
                Rams
                 Summary of comments: Multiple commenters agreed with the intent of
                this revision, but requested that BSEE clarify the timing and location
                of the test.
                 Response: BSEE disagrees that the timing and location of
                the shell test needs to be clarified. The regulations state that the
                operator must conduct the shell test before running casing.
                Comments Related to Sec. 250.738--Riser Gas Handler Systems
                 Summary of comments: A commenter recommended requiring the use of a
                riser gas handler system for all rigs with marine risers. The commenter
                asserted that requiring the use of riser gas handler systems would
                safely manage gas in the marine riser, prevent future incidents like
                Deepwater Horizon, and prevent environmental damage.
                 Response: BSEE disagrees with the recommendation to
                require the use of a riser gas handler system on all wells. Operators
                are currently allowed to use riser gas handler systems pursuant to this
                section. However, it is beyond the scope of this rulemaking to require
                it for all rigs with marine risers. BSEE may evaluate the use of riser
                gas handler systems for possible inclusion in future rulemakings.
                Comments Related to Proposed Sec. 250.738(b)--Reverification of BOP
                System
                 Summary of comments: A commenter recommended that BSEE should
                consider requiring a report from an independent third party if
                operations are interrupted due to the events listed in Sec.
                250.720(a)(1). The commenter asserted that the events listed in Sec.
                250.720(a)(1) would invalidate a verification submitted under
                Sec. Sec. 250.732(c) and 250.731(d) and that consideration should be
                given to including or moving these requirements to Sec. 250.738, as
                well.
                 Response: BSEE agrees with the commenter, in part, and
                added a requirement for submitting a revised permit with a written
                statement from an independent third party certifying that the previous
                certification under Sec. 250.731(c) remains valid. BSEE also made
                corresponding edits to similar requirements in Sec. Sec. 250.734 and
                250.738. These revisions help ensure that the BOP remains fit for
                service at the same location.
                What are the BOP maintenance and inspection requirements? (Sec.
                250.739)
                 This section of the existing regulations details the maintenance
                and inspection requirements for BOPs. The requirements include: Meeting
                or exceeding minimum thresholds for maintenance and inspection; a
                complete breakdown and physical inspection of the BOP every 5 years; a
                visual inspection of the surface BOP system on a daily basis; and
                training of all personnel who maintain, inspect, or repair BOPs.
                [[Page 21961]]
                Summary of Proposed Revisions
                 BSEE proposed to revise paragraph (b) by replacing ``complete
                breakdown and detailed physical inspection'' with a ``major, detailed
                inspection,'' identifying examples of well control system components,
                replacing references to the BAVO with references to an independent
                third party, and replacing the requirement to have a BAVO present
                during each inspection with a requirement for an independent third
                party to review inspection results.
                 BSEE proposed replacing ``complete breakdown and detailed physical
                inspection'' with a ``major, detailed inspection'' to correct the
                industry misconception, prevalent since the promulgation of the 2016
                WCR, that each component of the BOP must be dismantled to its smallest
                possible part. This was never the intent behind this provision of the
                2016 WCR and the proposed revisions would clarify BSEE's positions on
                the 2016 WCR requirement and resolve perceived ambiguities, without
                substantively altering the inspection requirement.
                 BSEE also proposed to remove the requirement for the BAVO to be
                present during each inspection and replace it with a requirement that
                an independent third party review the inspections results. BSEE expects
                the independent third party to review the documentation of the
                inspections to help ensure that the appropriate entities accurately and
                appropriately complete the activities. The proposed revisions would
                ease the logistical and economic burdens derived from the 2016 WCR
                requirement to have the BAVO onsite at all times during all
                inspections.
                Summary of Final Rule Revisions
                 BSEE received and considered comments on these provisions of the
                proposed rule and includes the proposed language in the final rule
                without change. BSEE received comments in general support and
                opposition to the proposed changes, in addition to the following
                comments.
                Summary of Comments
                Comments Related to Proposed Sec. 250.739--BOP Complete Breakdown
                Versus Major Detailed Inspection
                 Summary of comments: Multiple commenters asserted that the proposed
                rule would make a number of provisions more confusing. For example, one
                proposed revision to Sec. 250.739 replaces the requirement for regular
                ``complete breakdowns and detailed physical inspections'' with a
                requirement for ``major, detailed inspections.'' The commenters
                asserted that changing this phrase makes the associated requirements
                less specific, adds ambiguity to otherwise clear language, and leaves
                some testing requirements open for interpretation, which cannot ensure
                the safety and environmental protection provided by BOPs. The
                commenters suggested that BSEE should be more specific in its proposed
                regulation in explaining how far the BOP must be broken down to meet an
                acceptable BOP ``major, detailed'' 5-year inspection.
                 Response: BSEE disagrees with the assertion that the
                proposed language adds ambiguity regarding what is required for the 5
                year inspection. This revision is designed to provide clarity and
                eliminate misconceptions regarding the existing inspection requirement,
                not to substantively alter that requirement. BSEE expects this 5-year
                inspection to be conducted in the same manner, whether it is called a
                complete breakdown and detailed physical inspection or a major detailed
                inspection. This revision is consistent with the guidance posted on the
                BSEE website at https://www.bsee.gov/guidance-and-regulations/regulations/well-control-rule. As discussed in the proposed rule, BSEE
                used the term ``major detailed inspection'' to correct the industry
                misconception prevalent since the promulgation of the 2016 WCR that
                each BOP component must be dismantled to its smallest possible part.
                This was never the intent behind this provision of the 2016 WCR. These
                revisions clarify BSEE's position on the 2016 WCR requirements and
                resolve perceived ambiguities, without substantively altering the
                inspection requirement.
                 Summary of comments: Multiple commenters supported the proposed
                clarification to the rule. The commenters asserted that the proposed
                language codifies clarification previously given by BSEE regarding the
                intent of the phrase ``complete breakdown'' in the current regulation
                and also ensures that proven industry practice to phase recertification
                as part of a continuous maintenance and inspection program is
                acceptable. The commenters also asserted that this approach is
                consistent with the requirements of API Standard 53 and that BSEE
                appropriately retained the requirement that inspections be documented
                and reviewed by an independent third party.
                 Response: BSEE agrees with the commenter and no changes
                are necessary.
                Comments Related to Proposed Sec. 250.739--BAVO Present During
                Inspections
                 Summary of comments: Multiple commenters asserted that BSEE
                proposed to weaken the rule by eliminating the requirement for a BAVO
                to be physically present at the 5-year BOP inspection and by proposing
                an inadequate substitute of having a third-party inspector read
                industry's inspection report after-the-fact before compiling its own
                report. The commenters asserted that if a third-party inspector is not
                physically present at the 5-year BOP inspection, that person would not
                have the opportunity to physically inspect the equipment, collect
                independent data and photos, or make recommendations for repairs/
                replacements before the BOP is returned to service or rebuilt. The
                commenters further asserted that any report prepared by a third-party
                absent the opportunity to participate in the actual inspection would
                have little value and would come much too late in the process to effect
                real change/improvement.
                 Response: BSEE disagrees with the assertions that having
                an independent third party reviewing the documents, instead of being
                physically present for the inspections, is inadequate. BSEE requires
                the independent third party to review the documentation of the
                inspections and compile a detailed inspection report. These independent
                third party responsibilities help ensure that the appropriate entities
                accurately and appropriately complete the inspection activities, as
                well as identify any necessary corrective actions. The independent
                third party document review allows the comparison of the design data
                with the current status of the equipment. The intent of the major
                inspection is to verify that the well control system components are fit
                for service and within design tolerances to be utilized for specific
                well conditions. These goals can be verified during a data review and
                do not require the independent third party to be physically present
                during the major inspection to make that determination. Because the
                inspection may be performed in phased intervals, as provided in the
                2016 WCR, having a BAVO or third party present during the inspection
                would not be practical or logistically feasible. For example, in the
                situation where the rig is arriving on the OCS from overseas, the
                independent third party would not be present during any maintenance and
                inspections, and the independent third party review of the major
                inspections results would correspond to the certifications and
                verifications required
                [[Page 21962]]
                by Sec. Sec. 250.731 and 250.732, without being present during the
                inspections.
                What are the coiled tubing and snubbing requirements? (Sec. 250.750)
                 This is a new section in which BSEE proposed to consolidate coiled
                tubing and snubbing operational requirements.
                Summary of Proposed Revisions
                 The content of this proposed section was moved from current
                Sec. Sec. 250.616 and 250.1706, both titled Coiled tubing and snubbing
                operations and removed and reserved both in this final rule. BSEE
                proposed this section to consolidate some of the minimum BOP system
                component requirements for coiled tubing and snubbing operations. BSEE
                proposed minor revisions to the original language to conform to the
                applicable operations covered under Subpart G. BSEE also proposed to
                add a paragraph (d) to conform snubbing unit testing with updated
                requirements.
                Summary of Final Rule Revisions
                 BSEE did not receive any comments specific to this section and only
                received one comment asking how the proposed requirements of a
                different section apply to coiled tubing operations. Based on BSEE's
                review and continued analysis of the proposed rule and the single
                comment applicable to coiled tubing, BSEE is making administrative and
                technical revisions by modifying the proposed undesignated center
                heading and separating out the coiled tubing and snubbing requirements
                to create separate sections only applicable to snubbing operations. To
                avoid confusion between coiled tubing and snubbing requirements in this
                final rule, BSEE is separating their respective requirements into
                different sections. The coiled tubing requirements are addressed under
                new Sec. Sec. 250.750, What are the coiled tubing requirements? and
                250.751, Coiled tubing testing requirements. The requirements for
                snubbing operations, which were proposed as Sec. 250.750 paragraphs
                (b), (c), and (d), were revised and moved to new Sec. 250.760, What
                are the snubbing requirements? in the final rule. BSEE is also
                including minor clarifications to the proposed text to more accurately
                reflect BSEE's longstanding coiled tubing practices. BSEE is removing
                ``with the production tree in place'' proposed in paragraph (a) because
                coiled tubing requirements apply to any well operation that uses coiled
                tubing. BSEE is also adding ``follow the applicable requirements of
                this subpart . . .'' to final Sec. Sec. 250.750(a) and 250.760(a) to
                align with the Q and A guidance on the BSEE website at https://www.bsee.gov/guidance-and-regulations/regulations/well-control-rule.
                Many regulations contained in Subpart G are applicable to coiled tubing
                operations, such as, but not limited to, the items listed in the
                relevant Q and A on the BSEE website at https://www.bsee.gov/guidance-and-regulations/regulations/well-control-rule.
                 In Sec. 250.750, BSEE is adding a new paragraph (b) to clarify
                that BSEE considers all coiled tubing operations to be non-routine.
                BSEE is making this clarification based on our review of the proposed
                rule and a review of the comments associated with the definition of
                routine operations in Sec. 250.601, Definitions. This clarification
                also codifies longstanding BSEE policy that considers operations with a
                coiled tubing unit to be non-routine and require a permit. This
                addition helps clarify the approval process for use of coiled tubing
                for workovers.
                Coiled Tubing Testing Requirements (Sec. 250.751)
                 This is a new section in which BSEE proposed to consolidate coiled
                tubing and snubbing operational requirements.
                Summary of Proposed Revisions
                 BSEE proposed to add this section to codify current BSEE policy
                regarding the coiled tubing testing and recording requirements. In this
                addition, BSEE proposed to reintroduce language similar to provisions
                that were inadvertently removed from the regulations through the 2016
                WCR, consolidating elements from Sec. Sec. 250.617 and 250.1707 of the
                regulations as they existed before the 2016 WCR. Both sections are
                currently reserved. BSEE proposed revisions to the original language to
                conform to the applicable requirements of Subpart G. For example, in
                the proposed rule, this section would not include the former provisions
                regarding testing of the coiled tubing connector, because the proposal
                would instead state that operators ``must test the coiled tubing unit
                in accordance with Sec. 250.737 paragraphs (a), (b), (c), (d)(9), and
                (d)(10).'' Section 250.737 requires testing of the system when
                installed and provides testing criteria. As proposed, identifying the
                connector testing in this section is not necessary because it is
                already covered by the testing requirements of Sec. 250.737.
                Summary of Final Rule Revisions
                 BSEE did not receive any comments specific to this section. BSEE is
                making minor revisions to better reflect changes to the undesignated
                center heading that applies only to coiled tubing. As previously stated
                in the final rule discussion under Sec. 250.750, based on BSEE's
                review of the proposed rule, BSEE is revising this new section and
                separating out the snubbing requirements, creating a separate section
                applicable only to snubbing operations under final Sec. 250.760.
                What are the snubbing requirements? (Sec. 250.760)
                Summary of Proposed Revisions
                 BSEE did not propose to add this new section, however the content
                was included in proposed Sec. 250.750.
                Summary of Final Rule Revisions
                 BSEE is adding this new section and undesignated center heading to
                clarify the snubbing requirements. To avoid confusion between coiled
                tubing and snubbing requirements in this final rule, BSEE is separating
                their respective requirements into different sections and relocating
                the proposed snubbing requirements under this new section. The content
                of this section is being moved from proposed Sec. 250.750(b), (c), and
                (d), with minor conforming revisions to reflect the separation of
                coiled tubing requirements and the applicability only to snubbing
                operations and equipment. These changes are administrative and non-
                substantive. BSEE did not receive comments on the relevant language
                from proposed Sec. 250.750 and is finalizing it as described.
                Subpart Q--Decommissioning Activities
                What are the general requirements for decommissioning? (Sec. 250.1703)
                 This section of the existing regulations details decommissioning
                requirements, including getting District Manager approval, permanently
                plugging all wells, removing all platforms and facilities,
                decommissioning all pipelines, and clearing the seafloor of
                obstructions.
                Summary of Proposed Revisions
                 BSEE proposed to revise paragraph (b) to clarify that only packers
                or bridge plugs used as mechanical barriers are required to comply with
                ANSI/API Spec. 11D1. BSEE proposed this revision to codify BSEE's
                policy to ensure that the required mechanical barriers in a well are
                held to a higher standard than other common packers or bridge plugs
                used for various well specific conditions and completions design.
                Furthermore, BSEE is aware that certain packers and bridge plugs cannot
                meet the specifications of ANSI/API
                [[Page 21963]]
                Spec. 11D1. This revision would reduce the number of alternate
                equipment requests submitted to BSEE. BSEE also proposed to add that
                operators must have two independent barriers, one being mechanical, in
                the exposed center wellbore (e.g., this could be the tubing or casing
                depending on the well configuration) prior to removing the tree or well
                control equipment. BSEE proposed this addition to codify BSEE policy,
                align the well decommissioning requirements with similar requirements
                from Sec. Sec. 250.720(a) and 250.1712(g), and to help ensure the well
                is properly secured before removal of the tree or well control
                equipment.
                Summary of Final Rule Revisions
                 BSEE received no substantive comments on these provisions of the
                proposed rule, however BSEE did receive comments on similar mechanical
                barrier requirements in Sec. Sec. 250.518 and 250.619. Based on its
                consideration of the comments, BSEE is revising paragraph (b) to
                clarify that only the required mechanical barrier must be ANSI/API
                Spec. 11D1 qualified. This revision is consistent with the similar
                requirements in final Sec. Sec. 250.518 and 250.619 and BSEE's
                implementation of the mechanical barrier requirements finalized in the
                2016 WCR.
                What decommissioning applications and reports must I submit and when
                must I submit them? (Sec. 250.1704)
                 This section of the existing regulations provides a table that
                identifies the required decommissioning applications and subsequent
                reports, as well as the deadlines for when to submit them.
                Summary of Proposed Revisions
                 BSEE proposed to revise paragraph (g) by shifting the requirements
                for submittal of the site clearance verification activity information
                to an Application for Permit to Modify (APM). The site clearance
                verification activity information will be removed from the end of
                operations report (EOR). BSEE proposed these revisions to better
                reflect current practice and limit redundant reporting.
                 BSEE also proposed to revise paragraph (h) by adding the submittal
                of the decommissioning activity information, upon completion, to the
                EOR. BSEE proposed these revisions to better reflect current practice
                and limit redundant reporting.
                Summary of Final Rule Revisions
                 BSEE received and considered comments on the proposed revisions and
                includes the proposed language in the final rule without change.
                Summary of Comments
                Comments Related to Proposed Sec. 250.1704--Plug and Abandonment Plans
                 Summary of comments: One commenter suggested that plugging and
                abandonment plans should be based on risk acceptance and planned on a
                well-by-well basis. The commenter also recommended the use of a DNV
                Recommended Practice.
                 Response: BSEE disagrees with the suggestion that plugging
                and abandonment activities should be based on risk. BSEE does not
                consider a risk assessment by itself sufficient for determination of
                all plugging and abandonment operations. Plugging and abandonment
                operations are currently conducted on a well specific basis as approved
                within the applicable BSEE permits. BSEE will review the identified DNV
                Recommended Practice for possible inclusion in future rulemakings, as
                appropriate.
                Coiled Tubing and Snubbing Operations (Sec. 250.1706)
                Summary of Proposed Revisions
                 BSEE proposed to remove and reserve this section. BSEE proposed to
                move the content of this existing regulation to proposed Sec. 250.750.
                BSEE proposed these revisions to help eliminate inconsistencies between
                similar requirements spread throughout different regulatory subparts by
                consolidating those requirements into Subpart G, which is applicable to
                drilling, completions, workovers, and decommissioning operations.
                Summary of Final Rule Revisions
                 BSEE received no substantive comments on these provisions of the
                proposed rule and will remove and reserve this section in the final
                rule.
                Must I notify BSEE before I begin well plugging operations? (Sec.
                250.1713)
                Summary of Proposed Revisions
                 BSEE proposed to remove and reserve this section. Based upon BSEE
                experience with the implementation of the 2016 WCR, BSEE determined
                that the submittal of the information required by this section is
                redundant with similar rig movement notification information required
                under Sec. 250.712, What rig unit movements must I report?
                Summary of Final Rule Revisions
                 BSEE received no substantive comments on these provisions of the
                proposed rule and will remove and reserve this section in the final
                rule.
                To what depth must I remove wellheads and casings? (Sec. 250.1716)
                 This section of the existing regulations establishes the minimum
                depth below the mud line for removal of all wellheads and casings,
                unless an alternate depth is approved by the District Manager.
                Summary of Proposed Revisions
                 BSEE proposed to revise paragraph (b)(3) by changing the water
                depth criteria for when BSEE may approve an alternate depth for removal
                of the wellhead or casing from 800 meters to 1,000 feet. At depths
                greater than 1,000 feet, there is little risk of obstruction to other
                users of the OCS or its waters or contact with other equipment, and
                little risk of safety or environmental issues from removal to an
                alternate depth.
                Summary of Final Rule Revisions
                 BSEE received comments in general support of the proposed revisions
                to this section and is including the proposed language in the final
                rule without change.
                If I install a subsea protective device, what requirements must I meet?
                (Sec. 250.1722)
                 This section of the existing regulations states that if a subsea
                protective device is installed, then it must be done in a manner that
                allows fishing gear to pass over the obstruction without damage to the
                obstruction, the protective device, or the fishing gear.
                Summary of Proposed Revisions
                 BSEE proposed to revise paragraph (d) to direct the submittal of
                the trawl test report to the EOR rather than an APM. This proposed
                revision would not affect the substance of the reporting requirement or
                the information BSEE receives, only the mechanism through which it is
                received.
                Summary of Final Rule Revisions
                 BSEE received no substantive comments on these provisions of the
                proposed rule and includes the proposed language in the final rule
                without change.
                VI. Procedural Matters
                Regulatory Planning and Review (Executive Orders (E.O.) 12866, 13563,
                and 13771)
                 Executive Order 12866 provides that the Office of Information and
                Regulatory Affairs (OIRA) within the OMB will review all significant
                rules. This action is an economically significant regulatory
                [[Page 21964]]
                action that was submitted to OMB for review as it would have a positive
                annual effect on the economy of $100 million or more. BSEE coordinated
                development of an economic analysis to assess the anticipated costs and
                potential benefits of the final rule. The significant positive economic
                effect on the economy is the result of the estimated cost savings of
                this rule. BSEE estimates the amendments in this rulemaking would save
                the regulated industry $152 million annually over ten years (discounted
                at 7 percent).
                 Details on the estimated cost savings of this rule can be found in
                the rule's regulatory impact analysis. The cost savings for this final
                rule are due to regulatory clarifications, reduction in paperwork
                burdens, adoption of industry standards, and migration to performance-
                based standards for select provisions.
                 This rule revises regulatory provisions in 30 CFR part 250,
                subparts D, E, F, G, and Q. BSEE has reassessed a number of the
                provisions in the (1014-AA11) 2016 WCR and revises some provisions to
                reflect performance-based standards rather than prescriptive
                requirements. Other revisions reduce or eliminate parts of the
                paperwork burden, without impacting the current levels of safety and
                environmental protection. BSEE sought the best available data and
                information to analyze the economic impact of these changes. The
                Regulatory Impact Analysis (RIA) for this rulemaking can be found in
                the https://www.regulations.gov/ docket (Docket ID: BSEE-2018-0002).
                The Final RIA (FRIA) indicates that the estimated overall cost savings
                to the industry over the next 10 years would exceed $1.5 billion in
                nominal dollars.
                 BSEE revised certain provisions of the 2016 WCR to support the
                goals of the Administration's regulatory reform initiatives, while
                ensuring safety and environmental protection. BSEE has received
                additional information since the publication of the 2016 WCR and
                revisited several of the compliance cost assumptions in the economic
                analysis for the 2016 final rule. The modifications to the BSEE
                compliance cost estimates in the 2016 WCR analysis are primarily
                because that analysis:
                 (1.) Underestimated the cost for revising permits or reporting
                certain operations to the District Manager (Sec. Sec. 250.428 and
                250.722), and
                 (2.) Underestimated both the number of subsea BOPs that would
                require modifications and the cost of those modifications under the
                1014-AA11 regulations (Sec. 250.734).
                 The revisions to existing ram and accumulator requirements for
                subsea BOPs (Sec. 250.734) yield cost savings of $369 million (nominal
                $). The changes to Sec. 250.734 better align the shear ram provisions
                with API Standard 53 and revise the accumulator capacity requirements
                for subsea BOP stacks.
                 With changes to Sec. 250.737, BSEE is allowing operators to move
                to a 21-day BOP testing interval upon satisfaction of certain
                conditions. These changes align the testing interval with industry and
                global standards and help avoid premature wear and tear on critical
                components. BSEE expects operators using subsea BOPs to seek to move to
                a 21-day interval, realizing a cost savings of $919 million (nominal $)
                over 10-years. The changes to this provision represent the single
                largest cost savings in the rule.
                 This rule will reduce the regulatory burden on industry, while
                maintaining worker safety and environmental protection. BSEE is
                providing industry flexibility, when practical, to meet the safety or
                equipment standards, rather than specifying the compliance method. For
                example, BSEE will eliminate the requirement that operators resubmit an
                APD in the event of planned mud losses or inadequate cement jobs.
                Instead, BSEE will allow the operator to outline remedial actions to
                these scenarios in contingency plans included in the original BSEE-
                approved APD. This revision will not change the operational responses
                to these events, and therefore reduces the paperwork burden and
                expensive operational downtime without affecting operational risks.
                Other changes remove BOP stack certification requirements regarding
                design specifications and equipment conditions and replace the BAVO
                requirements for BOP systems and system components with independent
                third party requirements. The previous provisions were either
                duplicative or required a more burdensome certification process than
                reasonably necessary. The changes to the certification processes do not
                affect worker safety and the environment.
                 The revisions to final Sec. 250.734 better define the BOP
                components functionality requirements, revise the requirements for ROV
                capability and functionality, and amend accumulator capacity
                requirements for subsea BOP stacks. This revision to the accumulator
                requirements increases operator flexibility to utilize the appropriate
                accumulator capacity to perform the necessary emergency functions.
                Through the implementation of the WCR, BSEE was able to better evaluate
                the effects of the WCR accumulator requirements on subsea BOP space and
                weight limitations. After reevaluating the API 53 standards, BSEE
                agrees that certain prescriptive requirements in the current
                regulations are unnecessary. The regulatory text revisions to Sec.
                250.734 align BSEE regulations with the performance standards in API
                Standard 53, ensuring the subsea accumulator capacity is sufficient to
                actuate the BOP ram functions necessary to seal the well. This
                performance standard meets the intent of the 1014-AA11 WCR without the
                prescriptive and unnecessarily burdensome requirements.
                 The Sec. 250.737 paragraph (d)(5) amendments allow operators to
                alternate BOP tests between the two control stations rather than
                testing from both control stations on each test. The rule returns the
                regulations to pre-2016 WCR regulatory language in order to prevent the
                additional wear and tear on the BOP components. This change aligns BSEE
                regulations with the industry testing standards.
                 BSEE's estimate of the net total, annualized and discounted
                regulatory cost savings can be found in the following table.
                 Total 10-Year Estimated Cost Savings Associated With Amendments to Subparts D, E, F, G, and Q
                ----------------------------------------------------------------------------------------------------------------
                 Year Undiscounted Discounted at 3% Discounted at 7%
                ----------------------------------------------------------------------------------------------------------------
                Total.................................................. $1,543,093,357 $1,309,246,758 $1,067,468,876
                Annualized............................................. 154,309,336 153,483,661 * 151,983,553
                ----------------------------------------------------------------------------------------------------------------
                * The annualized cost savings assuming the rule is effective in 2019 and discounted over an infinite time
                 horizon, would be $60,996,080 at a 7% discount rate (using 2016$).
                 This rule reduces the burden imposed on industry, while ensuring
                continued safety and environmental protection. Additional information
                on the compliance costs, savings, and benefits
                [[Page 21965]]
                can be found in the FRIA posted in the docket.
                 This rule revises multiple provisions in the current regulations to
                implement performance-based provisions based upon reasonably obtainable
                safety, technical, economic, and other information. Other redundant or
                unnecessary reporting requirements are also being eliminated. BSEE is
                providing industry flexibility, when practical, to meet the safety or
                equipment standards, rather than specifying the compliance method.
                Based on a consideration of the qualitative and quantitative safety and
                environmental factors related to the rule, BSEE's assessment is that it
                is consistent with the policies of the applicable E.O.s and the OCSLA.
                 Executive Order 13563 reaffirms the principles of E.O. 12866 while
                calling for improvements in the Nation's regulatory system to promote
                predictability, to reduce uncertainty, and to use the best, most
                innovative, and least burdensome tools for achieving regulatory ends.
                The E.O. directs agencies to consider regulatory approaches that reduce
                burdens and maintain flexibility and freedom of choice for the public
                where these approaches are relevant, feasible, and consistent with
                regulatory objectives. E.O. 13563 emphasizes further that regulations
                must be based on the best available science and that the rulemaking
                process must allow for public participation and an open exchange of
                ideas. We have developed this rule in a manner consistent with these
                requirements.
                 Executive Order 13771 requires Federal agencies to take proactive
                measures to reduce the costs associated with complying with Federal
                regulations. This rule is an E.O. 13771 deregulatory action.
                Regulatory Flexibility Act and Small Business Regulatory Enforcement
                Fairness Act
                 The Regulatory Flexibility Act, 5 U.S.C. 601-612, requires agencies
                to analyze the economic impact of regulations when a significant
                economic impact on a substantial number of small entities is likely and
                to consider regulatory alternatives that will achieve the agency's
                goals, while minimizing the burden on small entities. In addition, the
                Small Business Regulatory Enforcement Fairness Act of 1996, 5 U.S.C.
                601 note, requires agencies to produce compliance guidance for small
                entities if the rule has a significant economic impact. For the reasons
                explained in this analysis, BSEE believes the rule may have a
                significant economic impact and, therefore, a Regulatory Flexibility
                Analysis (RFA) for the rule is required by the Regulatory Flexibility
                Act. The RFA, which assesses the impact of this rule on small entities,
                can be found in the FRIA within the docket for this rulemaking.
                 As defined by the Small Business Administration (SBA), a small
                entity is one that is ``independently owned and operated and which is
                not dominant in its field of operation.'' What characterizes a small
                business varies from industry to industry in order to properly reflect
                industry size differences. This rule affects lease operators that are
                conducting OCS drilling or well operations. BSEE's analysis shows this
                includes about 69 companies with active drilling or well operations. Of
                the 69 companies, 21 (30 percent) are large and 48 (70 percent) are
                small. Entities affected by this rule are classified primarily under
                North American Industry Classification System (NAICS) codes 211120
                (Crude Petroleum Extraction), 211130 (Natural Gas Extraction), and
                213111 (Drilling Oil and Gas Wells). The rule indirectly impacts OCS
                drilling contractors that are classified under NAICS code 21311,
                however this analysis focuses on the OCS oil and gas lessees and
                operators to which the rule's provisions will apply directly. For NAICS
                codes 211120 and 211130, SBA defines a small company as having fewer
                than 1,251 employees.
                 BSEE considers that a rule will have an impact on a ``substantial
                number of small entities'' when the total number of small entities
                impacted by the rule is equal to or exceeds 10 percent of the relevant
                universe of small entities in a given industry. BSEE's analysis shows
                that there are 48 small companies with active operations on the OCS and
                all of these companies could be impacted by the rule if conducting
                drilling or well operations. Therefore, BSEE expects that the rule
                would affect a substantial number of small entities.
                 Large companies are responsible for the majority of activity in
                deepwater, where subsea BOPs are used with floating MODUs. BSEE's
                first-order estimate for the rule's small entity cost savings is
                proportional to the number of drilling rigs being operated or
                contracted by small companies (circa October 2017).
                 This rule is a deregulatory action; BSEE has evaluated possible
                costs and benefits and has estimated that there is an overall
                associated cost savings. BSEE has estimated the annualized cost savings
                by regulatory provision and then allocated those savings to small or
                large entities based on drilling/well activity (circa October, 2017;
                activity breakouts can be found in the RFA). The changes to Sec. Sec.
                250.423, 250.734, and 250.737(d)(5) would only apply to subsea BOPs and
                would yield cost savings that sum to $47,421,114. All remaining changes
                apply to all well operations or subsea/surface BOPs and yield cost
                savings that sum to $106,888,221. Using the share of small and large
                companies subject to each suite of provisions, we estimate that small
                companies would realize 25 percent of the cost savings from this rule
                and large companies 75 percent. The allocation is displayed in the
                following table.
                 Cost Savings by Operator Size
                 [Undiscounted annualized $]
                ----------------------------------------------------------------------------------------------------------------
                 Small companies Large companies
                 ---------------------------------------------------------------- Total cost
                 Provision Percent of Percent of savings
                 operators Cost savings operators Cost savings
                ----------------------------------------------------------------------------------------------------------------
                Subsea BOP Provisions........... 12 $5,578,955 88 $41,842,160 $47,421,114
                All Other Provisions............ 30 32,315,044 70 74,573,178 106,888,221
                 -------------------------------------------------------------------------------
                 Total....................... .............. *37,893,998 .............. **116,415,337 154,309,336
                ----------------------------------------------------------------------------------------------------------------
                * (25% of Total).
                ** (75% of Total).
                [[Page 21966]]
                 This rule:
                 a. Will have a positive economic effect on the economy of $100
                million or more. The cost savings will not materially affect the
                economy nationally or in any local area.
                 b. Will not cause a major increase in costs or prices for
                consumers; individual industries; Federal, State, Tribal, or local
                governments; or regions of the nation. This rule will have positive
                effects on OCS operators and is not anticipated to negatively impact
                oil, gas, and sulfur production or the cost of fuels for consumers.
                 c. Will not have significant or adverse effects on competition,
                employment, investment, productivity, innovation, or the ability of
                U.S.-based enterprises to compete with foreign-based enterprises.
                 This rule is a major rule because it will have an annual effect on
                the economy of $100 million or more in at least one year of the 10-year
                period analyzed. The requirements apply to all entities operating on
                the OCS regardless of company designation as a small business. For more
                information on the small business impacts, see the RFA in the FRIA.
                Small businesses may send comments on the actions of Federal employees
                who enforce, or otherwise determine compliance with, Federal
                regulations to the Small Business and Agriculture Regulatory
                Enforcement Ombudsman, and to the Regional Small Business Regulatory
                Fairness Board. The Ombudsman evaluates these actions annually and
                rates each agency's responsiveness to small business. If you wish to
                comment on actions by employees of BSEE, call 1-888-REG-FAIR (1-888-
                734-3247).
                Unfunded Mandates Reform Act of 1995
                 This final rule will not impose an unfunded mandate on State,
                local, or tribal governments or the private sector of more than $100
                million per year. The final rule will not have a significant or unique
                effect on State, local, or tribal governments or the private sector. A
                statement containing the information required by the Unfunded Mandates
                Reform Act (2 U.S.C. 1531 et seq.) is not required.
                Takings Implication Assessment (E.O. 12630)
                 Under the criteria in E.O. 12630, this final rule does not have
                significant takings implications. The rule is not a governmental action
                capable of interference with constitutionally protected property
                rights. A Takings Implication Assessment is not required.
                Federalism (E.O. 13132)
                 Under the criteria in section 1 of E.O. 13132, this final rule does
                not have sufficient federalism implications to warrant the preparation
                of a federalism summary impact statement. This rule will not
                substantially and directly affect the relationship between the Federal
                and State governments. To the extent that State and local governments
                have a role in OCS activities, this rule will not affect that role. A
                federalism summary impact statement is not required.
                 The BSEE has the authority to regulate offshore oil and gas
                drilling, completion, workover, and decommissioning operations. State
                governments do not have authority over offshore drilling, completion,
                workover, and decommissioning operations on the OCS. None of the
                changes in this rule will affect areas that are under the jurisdiction
                of the States. It will not change the way that the States and the
                Federal government interact, or the way that States interact with
                private companies.
                Civil Justice Reform (E.O. 12988)
                 This final rule complies with the requirements of E.O. 12988.
                Specifically, this rule:
                 (1) Meets the criteria of section 3(a) requiring that all
                regulations be reviewed to eliminate errors and ambiguity and be
                written to minimize litigation; and
                 (2) Meets the criteria of section 3(b)(2) requiring that all
                regulations be written in clear language and contain clear legal
                standards.
                Consultation With Indian Tribes (E.O. 13175)
                 BSEE is committed to regular and meaningful consultation and
                collaboration with tribes on policy decisions that have tribal
                implications. Under the criteria in E.O. 13175 and the Department's
                Policy on Consultation with Indian Tribes (S.O. 3317, Amendment 2,
                dated December 31, 2013), we have evaluated this final rule and
                determined that it has no substantial direct effects on federally
                recognized Indian tribes.
                National Technology Transfer and Advancement Act (NTTAA)
                 BSEE complies with the National Technology Transfer and Advancement
                Act (NTTAA) (15 U.S.C. 3701 et seq.) requirement that an agency ``use
                standards developed or adopted by voluntary consensus standards bodies
                rather than government-unique standards, except where inconsistent with
                applicable law or otherwise impractical.'' (OMB Circular A-119 at p.
                13). BSEE also complies with the OFR regulations governing
                incorporation by reference. (See, 1 CFR part 51.) Those regulations
                specify the process for updating an incorporated standard at Sec.
                51.11(a), including seeking approval by OFR for a change to a standard
                incorporated by reference in a final rule.
                Paperwork Reduction Act (PRA) of 1995
                 This final rule contains collections of information that will be
                submitted to OMB for review and approval under the PRA, 44 U.S.C. 3501
                et seq. As part of its continuing effort to reduce paperwork and
                burdens on respondents, BSEE invites the public and other Federal
                agencies to comment on any aspect of the reporting and recordkeeping
                burden. If you wish to comment on the information collection (IC)
                aspects of this final rule, you may send your comments directly to OMB
                and send a copy of your comments to the Regulations and Standards
                Branch (see the ADDRESSES section of this final rule). Please reference
                30 CFR 250, subpart G, Blowout Preventer Systems and Well Control,
                1014-0028, in your comments. To see a copy of the information
                collection request submitted to OMB, go to http://www.reginfo.gov
                (select Information Collection Review, Currently Under Review); or you
                may obtain a copy of the supporting statement for the collection of
                information by contacting the Bureau's Information Collection Clearance
                Officer at (703) 787-1607.
                 The PRA provides that an agency may not conduct or sponsor, and a
                person is not required to respond to, a collection of information
                unless it displays a currently valid OMB control number. The OMB is
                required to make a decision concerning the collection of information
                contained in these regulations 30-60 days after publication of this
                document in the Federal Register.
                 The public may comment, at any time, on the accuracy of the IC
                burden in this rule and may submit any comments to DOI/BSEE; ATTN:
                Regulations and Standards Branch; VAE-ORP; 45600 Woodland Road,
                Sterling, VA 20166; email [email protected], or fax (703) 787-1093.
                 The title of the collection of information for this rule is 30 CFR
                part 250, Blowout Preventer Systems and Well Control Revisions (Final
                Rulemaking). The final regulations concern BOP system requirements and
                maintaining well control, among others, and the information is used in
                BSEE's efforts to regulate oil and gas operations on the OCS to protect
                life and the environment, conserve natural resources, and prevent
                waste.
                [[Page 21967]]
                 Potential respondents comprise Federal OCS oil, gas, and sulphur
                operators and lessees. Responses to this collection of information are
                mandatory, or are required to obtain or retain a benefit; they are also
                submitted on occasion, daily and weekly (during drilling operations),
                monthly, quarterly, biennially, and as a result of situations
                encountered, depending upon the requirement. The IC does not include
                questions of a sensitive nature. The BSEE will protect proprietary
                information according to the Freedom of Information Act (5 U.S.C. 552)
                and DOI implementing regulations (43 CFR part 2), 30 CFR part 252, OCS
                Oil and Gas Information Program, and 30 CFR 250.197, Data and
                information to be made available to the public or for limited
                inspection.
                 This final rule will increase BSEE's IC inventory by +87,744 annual
                hour burdens; as well as increase annual non-hour costs burdens by
                $10,918,000 for Independent Third Party (ITP) costs. BSEE-Approved
                Verification Organization (BAVO); is being replaced with ITP. In
                connection with the original WCR, BSEE assumed hour burdens in place of
                non-hour costs associated with BAVO submissions; however, in this final
                rule, we are capturing non-hour costs associated with hiring ITPs.
                Below is a list of the current OMB Control Numbers affected by this
                final rulemaking and their associated increases/decreases in hour
                burdens and non-hour costs:
                 Applications for Permits to Drill (APD-1014-0025,
                expiration 4/30/20) will increase annual burden by +14,523 hours
                annually (-69 hours due to this rulemaking, and +14,592 due to re-
                estimating the annual number of response) and increase +$3,999,000
                annual non-hour costs for ITP;
                 Applications for Permits to Modify (APM-1014-0026,
                expiration 7/31/20) will decrease annual burden by -33 hours (+277
                hours due to this rulemaking, and -310 hours due to re-estimating the
                annual number of responses) and increase +$6,138,000 annual non-hour
                costs for ITP;
                 Subpart A (1014-0022, expiration 2/28/21), BSEE is not
                making any changes to hour-burden or non-hour costs;
                 Subpart B (1014-0024, expiration 10/31/21), BSEE is not
                making any changes to hour-burden or non-hour costs;
                 Subpart D (1014-0018, expiration 3/31/2021) will increase
                the annual burden by +40 hours (+40 due to this rulemaking) and
                increase +$16,000 annual non-hour costs for ITP;
                 Subpart G (1014-0028, expiration 07/31/19) will increase
                annual burden by +73,214 hours (+4,048 hours is due to this rulemaking
                and +69,166 hours due to re-estimating the annual number of responses)
                and increase +$765,000 annual non-hour costs for ITP.
                 The following is a brief explanation of how the final regulatory
                changes will affect the various subpart hour burdens:
                Application for Permit To Drill (APD) 1014-0025
                 Sec. 250.414(c)(2) is new and will allow operators the option to
                submit the required justification and documentation for a proposed
                alternative safe drilling margin for BSEE approval at an earlier date
                prior to the APD. This will increase the annual burden hour by 15
                hours.
                 Sec. 250.428 removes the requirement to resubmit an APD in the
                event of planned mud losses, or remedial actions for inadequate cement
                jobs, if these circumstances are addressed in the original approved
                APD. Reductions will be shown during the renewal process (see
                Discussion of Final Rule Requirements above).
                 Sec. 250.724(b) will eliminate the requirement to submit
                certification that you have a real-time monitoring plan that meets the
                criteria listed. This will decrease the annual hour burden by 109 hours
                (see Discussion of Final Rule Requirements above).
                 Sec. 250.731 will add Independent Third Party costs, increasing
                the non-hour cost burdens by $31,000 per submission (see Discussion of
                Final Rule Requirements above). During this rulemaking it was
                discovered that BSEE had underestimated the number of responses/
                submittals. We are increasing that by 128 submittals annually, which in
                turn increase the annual hour burden by 14,592 hours.
                 Sec. 250.738(b) requires operators submit a revised permit with a
                written statement from an independent third party documenting the
                repairs, replacement, or reconfiguration and certifying that the
                previous certification in Sec. 250.731(c) remains valid. This will
                increase the annual hour burden by 25 hours (see Discussion of Final
                Rule Requirements above).
                Application for Permit To Modify (APM) 1014-0026
                 Sec. 250.724(b) will eliminate the requirement to submit
                certification that you have a real-time monitoring plan that meets the
                criteria listed. This will decrease the annual hour burden by 125 hours
                (see Discussion of Final Rule Requirements above).
                 Sec. 250.731 will add Independent Third Party costs, increasing
                the non-hour cost burdens by $31,000 per submission (total of
                $6,138,000 annual non-hour costs) (see Discussion of Final Rule
                Requirements above). During this rulemaking it was discovered that BSEE
                had overestimated the number of responses/submittals. We are decreasing
                that by 62 responses; which in turn decrease the annual hour burden by
                310 hours.
                 Sec. 250.750(a)(4) requires operators that plan to conduct
                operations without downhole check valves, describe alternate procedures
                and equipment in Form BSEE-0124, APM, and have it approved by the
                District Manager. The responses/burden associated with Sec. 250.616
                (245 approvals x .75 hour = 184 annual hour burdens) and Sec. 250.1706
                (503 requests x .25 hour = 126 annual hour burdens) are being relocated
                to 250.750(a)(4) (for a total of 748 requests x 1 hour); increasing the
                annual hour burden by 438 hours (see Discussion of Final Rule
                Requirements above).
                 Sec. 250.1722(d) will direct the submittal of the trawl test
                report to the End of Operations Report (EOR) rather than an APM; and
                will decrease the annual hour burden by 36 hours (see Discussion of
                Final Rule Requirements above).
                Subpart A 1014-0022
                 Sec. 250.115 is the regulatory text from Sec. 250.198 but moved
                and relocated to Sec. 250.115. This burden will remain the same and is
                covered under Sec. 250.141 (see Discussion of Final Rule Requirements
                above).
                 Sec. 250.423 is rewording the requirement in a manner that will
                reduce the number of alternative procedure or equipment requests under
                Sec. 250.141. Reductions will be shown during the renewal process (see
                Discussion of Final Rule Requirements above).
                Subpart B 1014-0024
                 Sec. 250.292(p) will require less information to be submitted in
                the DWOP. Reductions will be shown during the renewal process (see
                Discussion of Final Rule Requirements above).
                Subpart D 1014-0018
                 Sec. 250.427(b) will revise the requirement to include a
                notification to BSEE District Manager. BSEE is also clarifying that the
                District Manager must review and approve proposed remedial actions.
                This will increase the annual hour burden by 40 hours (see Discussion
                of Final Rule Requirements above).
                [[Page 21968]]
                 Sec. 250.462(e)(1) will add Independent Third Party costs
                increasing the non-hour cost burdens by $8,000 per notification (total
                of $16,000 annual non-hour costs) (see Discussion of Final Rule
                Requirements above).
                 Sec. 250.1722 will direct the submittal of the trawl test report
                to the End of Operations Report (EOR) rather than an APM. Burden hours
                associated with Subpart Q are already covered under EOR reporting. Any
                reductions/increases will be shown during the renewal process (see
                Discussion of Final Rule Requirements above).
                Subpart G 1014-0028
                 Sec. 250.720(a)(3) will require operators submit a revised permit
                with a written statement from an independent third party certifying
                that the previous certification remains valid and to request and
                receive District Manager approval before resuming operations after
                unlatching the BOP or LMRP. This will increase the annual hour burden
                by 13 hours (see Discussion of Final Rule Requirements above).
                 Sec. 250.720(d) was proposed but had been inadvertently omitted
                from the information collection. The requirement is new and will
                require operators to identify and make available for BSEE inspection,
                specified equipment used solely for intervention operations. This will
                increase the annual hour burden by 10 hours (see Discussion of Final
                Rule Requirements above).
                 Sec. 250.722(a)(2) will require operators to document successful
                pressure test in the Well Activity Report (WAR). This will increase the
                annual hour burden by 150 hours (see Discussion of Final Rule
                Requirements above).
                 Sec. 250.730(c)(2) will increase the annual hour burden by 5
                hours. Based on comments received BSEE is clarifying how to request an
                extension to the failure analysis timeframe. Furthermore, they must
                submit an extension request to the Chief, Office of Offshore Regulatory
                Programs, detailing how the investigation and analysis will get
                completed to BSEE for approval (see Discussion of Final Rule
                Requirements above).
                 New Sec. 250.732(a) will add Independent Third Party costs,
                increasing the non-hour cost burdens by $5,100 per verification (total
                increase is $765,000 annual non-hour costs) (see Discussion of Final
                Rule Requirements above).
                 Old Sec. 250.732(a) will eliminate the requirement to request and
                submit for approval all relevant information to become a BAVO. This
                will decrease the annual hour burden by 700 hours (see Discussion of
                Final Rule Requirements above).
                 New Sec. 250.732(d) requires operators to make all documentation
                that demonstrates compliance with the requirements of this section
                available to BSEE upon request; increasing the annual hour burden by 40
                hours (see Discussion of Final Rule Requirements above).
                 Old Sec. 250.732(d) will eliminate the submission of Mechanical
                Integrity Assessment Reports; decreasing the annual hour burden by 900
                hours (see Discussion of Final Rule Requirements above).
                 Sec. 250.737(a)(4) and (d)(10) (test frequency for function test
                shear rams) will increase the annual hour burden by 75 hours. BSEE is
                requiring operators that wish to request approval for a 21-day BOP
                testing frequency, demonstrate the development of a BOP health
                monitoring plan (including, but not limited to, information/
                requirements such as condition monitoring tool; failure propagation
                analysis; a failure tracking and resolution system that includes
                detailed failure reports and identification of recurring problems). In
                addition, this will increase annual hour burdens by 100 hours to submit
                quarterly reports of the data collected with the health monitoring plan
                to the BSEE Regional Supervisor, District Field Operations (see
                Discussion of Final Rule Requirements above).
                 Sec. 250.737(d)(5) will allow for alternating tests between two
                control stations. This will increase the annual hour burden by 25 hours
                (see Discussion of Final Rule Requirements above).
                 Sec. 250.751 will include the coiled tubing testing and recording
                requirements that were inadvertently removed in the original Well
                Control Rule. This will increase the annual hour burden by 3,630 hours
                (see Discussion of Final Rule Requirements above).
                 Once this rule becomes effective, BSEE will use the current OMB
                control numbers for the affected subparts discussed and will have their
                information collection burdens adjusted accordingly through the renewal
                process.
                National Environmental Policy Act of 1969 (NEPA)
                 BSEE has prepared a final environmental assessment (EA) that
                concludes that this final rule will not have a significant impact on
                the quality of the human environment under the National Environmental
                Policy Act of 1969 (NEPA) (42 U.S.C. 4321 et seq.). The final EA
                supports the issuance of a Finding of No Significant Impact (FONSI) for
                the rule, therefore the preparation of an environmental impact
                statement pursuant to NEPA is not required. A copy of the final EA and
                FONSI can be viewed at www.regulations.gov (use the keyword/ID ``BSEE-
                2018-0002'').
                Data Quality Act
                 In developing this rule, we did not conduct or use a study,
                experiment, or survey requiring peer review under the Data Quality Act
                (Pub. L. 106-554, app. C, sec. 515, 114 Stat. 2763, 2763A-153-154).
                Effects on the Nation's Energy Supply (E.O. 13211)
                 This final rule is not a significant energy action under the
                definition in E.O. 13211. Although the rule is a significant regulatory
                action under E.O. 12866, it is not likely to have a significant adverse
                effect on the supply, distribution, or use of energy. A Statement of
                Energy Effects is not required.
                Severability
                 If a court holds any provisions of this final rule or their
                applicability to any persons or circumstances invalid, the remainder of
                the provisions and their applicability to other people or circumstances
                will not be affected.
                List of Subjects in 30 CFR Part 250
                 Administrative practice and procedure, Continental shelf,
                Continental Shelf--mineral resources, Continental Shelf--rights-of-way,
                Environmental impact statements, Environmental protection, Government
                contracts, Incorporation by reference, Investigations, Oil and gas
                exploration, Penalties, Pipelines, Reporting and recordkeeping
                requirements, Sulfur.
                Joseph R. Balash,
                Assistant Secretary--Land and Minerals Management, U.S. Department of
                the Interior.
                 For the reasons stated in the preamble, the Bureau of Safety and
                Environmental Enforcement (BSEE) amends 30 CFR part 250 as follows:
                PART 250--OIL AND GAS AND SULFUR OPERATIONS IN THE OUTER
                CONTINENTAL SHELF
                0
                1. The authority citation for part 250 continues to read as follows:
                 Authority: 30 U.S.C. 1751, 31 U.S.C. 9701, 33 U.S.C.
                1321(j)(1)(C), 43 U.S.C. 1334.
                Subpart A--General
                0
                2. Add Sec. 250.115 to read as follows:
                [[Page 21969]]
                Sec. 250.115 What are the procedures for, and effects of,
                incorporation of documents by reference in this part?
                 For the documents incorporated by reference in this part:
                 (a) Incorporation by reference of a document is limited to the
                edition of the document, or the specific edition and supplement or
                addendum, that is cited in Sec. 250.198. Future amendments or
                revisions of the incorporated document are not included. BSEE will
                publish any changes to the incorporation of the document in the Federal
                Register and amend Sec. 250.198 as appropriate.
                 (b) BSEE may make a rule amending the incorporation of a document
                effective without prior opportunity for public comment when BSEE
                determines:
                 (1) That the revisions to the document result in safety
                improvements or represent new industry standard technology and do not
                impose undue costs on the affected parties; and
                 (2) BSEE meets the requirements for making a rule immediately
                effective under 5 U.S.C. 553.
                 (c) The effect of incorporation by reference of a document into the
                regulations in this part is that the incorporated document is a
                requirement. When a section in this part refers to an incorporated
                document, you are responsible for complying with the provisions of that
                entire document, except to the extent that the section that refers to
                the document provides otherwise. When a section in this part refers to
                a part of an incorporated document, you are responsible for complying
                with that part of the document as provided in that section.
                 (d) Under Sec. Sec. 250.141 and 250.142, you may comply with a
                later edition of a specific document incorporated by reference,
                provided:
                 (1) You show that complying with the later edition provides a
                degree of protection, safety, or performance equal to or better than
                would be achieved by compliance with the listed edition; and
                 (2) You obtain prior written approval for alternative compliance
                from the authorized BSEE official.
                0
                3. Revise Sec. 250.198 to read as follows:
                Sec. 250.198 Documents incorporated by reference.
                 Certain material is incorporated by reference into this part with
                the approval of the Director of the Federal Register under 5 U.S.C.
                552(a) and 1 CFR part 51. All incorporated material is available for
                inspection at the Houston BSEE office at 1919 Smith Street Suite 14042,
                Houston, Texas 77002 and is available from the sources indicated in
                this section. It is also available for inspection at the National
                Archives and Records Administration (NARA). To make an appointment to
                inspect incorporated material at the Houston BSEE office, call 1-844-
                259-4779. For information on the availability of this material at NARA,
                call 202-741-6030 or go to http://www.archives.gov/federal-register/cfr/ibr-locations.html.
                 (a) American Concrete Institute (ACI), ACI Standards, 38800 Country
                Club Drive, Farmington Hills, MI 48331-3439: http://www.concrete.org;
                phone: 248-848-3700:
                 (1) ACI Standard 318-95, Building Code Requirements for Reinforced
                Concrete, 1995; incorporated by reference at Sec. 250.901.
                 (2) ACI 318R-95, Commentary on Building Code Requirements for
                Reinforced Concrete, 1995; incorporated by reference at Sec. 250.901.
                 (3) ACI 357R-84, Guide for the Design and Construction of Fixed
                Offshore Concrete Structures, 1984; reapproved 1997, incorporated by
                reference at Sec. 250.901.
                 (b) American Gas Association (AGA Reports), 400 North Capitol
                Street NW, Suite 450, Washington, DC 20001, http://www.aga.org; phone:
                202-824-7000;
                 (1) AGA Report No. 7--Measurement of Natural Gas by Turbine Meters;
                Revised February 2006; incorporated by reference at Sec. 250.1203(b);
                 (2) AGA Report No. 9--Measurement of Gas by Multipath Ultrasonic
                Meters; Second Edition, April 2007; incorporated by reference at Sec.
                250.1203(b);
                 (3) AGA Report No. 10--Speed of Sound in Natural Gas and Other
                Related Hydrocarbon Gases; Copyright 2003; incorporated by reference at
                Sec. 250.1203(b).
                 (c) American Institute of Steel Construction, Inc. (AISC), AISC
                Standards, One East Wacker Drive, Suite 700, Chicago, IL 60601-1802;
                http://www.aisc.org; phone: 312-670-2400:
                 (1) ANSI/AISC 360-05, Specification for Structural Steel Buildings,
                incorporated by reference at Sec. 250.901.
                 (2) [Reserved]
                 (d) American National Standards Institute (ANSI), http.www./
                webstore.ansi.org/; phone: 212-642-4900:
                 (1) ANSI/ASME B 16.5-2003, Pipe Flanges and Flanged Fittings,
                incorporated by reference at Sec. 250.1002;
                 (2) ANSI/ASME B 31.8-2003, Gas Transmission and Distribution Piping
                Systems, incorporated by reference at Sec. 250.1002;
                 (3) ANSI Z88.2-1992, American National Standard for Respiratory
                Protection, incorporated by reference at Sec. 250.490.
                 (e) American Petroleum Institute (API), API Recommended Practices
                (RP), Specs, Standards, Manual of Petroleum Measurement Standards
                (MPMS) chapters, 1220 L Street, NW, Washington, DC 20005-4070; http://www.api.org; phone: 202-682-8000:
                 (1) API 510, Pressure Vessel Inspection Code: In-Service
                Inspection, Rating, Repair, and Alteration, Tenth Edition, May 2014;
                Addendum 1, May 2017; incorporated by reference at Sec. Sec.
                250.851(a) and 250.1629(b);
                 (2) API 570, Piping Inspection Code: In-service Inspection, Rating,
                Repair, and Alteration of Piping Systems, Fourth Edition, February
                2016; Addendum 1, May 2017; incorporated by reference at Sec.
                250.841(b).
                 (3) API Bulletin 2INT-DG, Interim Guidance for Design of Offshore
                Structures for Hurricane Conditions, May 2007; incorporated by
                reference at Sec. 250.901;
                 (4) API Bulletin 2INT-EX, Interim Guidance for Assessment of
                Existing Offshore Structures for Hurricane Conditions, May 2007;
                incorporated by reference at Sec. 250.901;
                 (5) API Bulletin 2INT-MET, Interim Guidance on Hurricane Conditions
                in the Gulf of Mexico, May 2007; incorporated by reference at Sec.
                250.901;
                 (6) API Bulletin 92L, Drilling Ahead Safely with Lost Circulation
                in the Gulf of Mexico, First Edition, August 2015; incorporated by
                reference at Sec. 250.427(b);
                 (7) API MPMS Chapter 1--Vocabulary, Second Edition, July 1994;
                incorporated by reference at Sec. 250.1201;
                 (8) API MPMS Chapter 2--Tank Calibration, Section 2A--Measurement
                and Calibration of Upright Cylindrical Tanks by the Manual Tank
                Strapping Method, First Edition, February 1995; reaffirmed February
                2007; incorporated by reference at Sec. 250.1202;
                 (9) API MPMS Chapter 2--Tank Calibration, Section 2B--Calibration
                of Upright Cylindrical Tanks Using the Optical Reference Line Method,
                First Edition, March 1989; reaffirmed, December 2007; incorporated by
                reference at Sec. 250.1202;
                 (10) API MPMS Chapter 3--Tank Gauging, Section 1A--Standard
                Practice for the Manual Gauging of Petroleum and Petroleum Products,
                Second Edition, August 2005; incorporated by reference at Sec.
                250.1202;
                 (11) API MPMS Chapter 3--Tank Gauging, Section 1B--Standard
                Practice for Level Measurement of Liquid Hydrocarbons in Stationary
                Tanks by Automatic Tank Gauging, Second Edition, June 2001; reaffirmed,
                October
                [[Page 21970]]
                2006; incorporated by reference at Sec. 250.1202;
                 (12) API MPMS Chapter 4--Proving Systems, Section 1--Introduction,
                Third Edition, February 2005; incorporated by reference at Sec.
                250.1202;
                 (13) API MPMS Chapter 4--Proving Systems, Section 2--Displacement
                Provers, Third Edition, September 2003; incorporated by reference at
                Sec. 250.1202;
                 (14) API MPMS Chapter 4--Proving Systems, Section 4--Tank Provers,
                Second Edition, May 1998, reaffirmed November 2005; incorporated by
                reference at Sec. 250.1202;
                 (15) API MPMS Chapter 4--Proving Systems, Section 5--Master-Meter
                Provers, Second Edition, May 2000, reaffirmed, August 2005;
                incorporated by reference at Sec. 250.1202;
                 (16) API MPMS Chapter 4--Proving Systems, Section 6--Pulse
                Interpolation, Second Edition, May 1999; reaffirmed 2003; incorporated
                by reference at Sec. 250.1202;
                 (17) API MPMS Chapter 4--Proving Systems, Section 7--Field Standard
                Test Measures, Second Edition, December 1998; reaffirmed 2003;
                incorporated by reference at Sec. 250.1202;
                 (18) API MPMS Chapter 4--Proving Systems, Section 8--Operation of
                Proving Systems; First Edition, reaffirmed March 2007; incorporated by
                reference at Sec. 250.1202(a), (f), and (g);
                 (19) API MPMS Chapter 5--Metering, Section 1--General
                Considerations for Measurement by Meters, Fourth Edition, September
                2005; incorporated by reference at Sec. 250.1202;
                 (20) API MPMS Chapter 5--Metering, Section 2--Measurement of Liquid
                Hydrocarbons by Displacement Meters, Third Edition, September 2005;
                incorporated by reference at Sec. 250.1202;
                 (21) API MPMS Chapter 5--Metering, Section 3--Measurement of Liquid
                Hydrocarbons by Turbine Meters, Fifth Edition, September 2005;
                incorporated by reference at Sec. 250.1202;
                 (22) API MPMS Chapter 5--Metering, Section 4--Accessory Equipment
                for Liquid Meters, Fourth Edition, September 2005; incorporated by
                reference at Sec. 250.1202;
                 (23) API MPMS Chapter 5--Metering, Section 5--Fidelity and Security
                of Flow Measurement Pulsed-Data Transmission Systems, Second Edition,
                August 2005; incorporated by reference at Sec. 250.1202;
                 (24) API MPMS Chapter 5--Metering, Section 6--Measurement of Liquid
                Hydrocarbons by Coriolis Meters; First Edition, reaffirmed, March 2008;
                incorporated by reference at Sec. 250.1202(a);
                 (25) API MPMS Chapter 5--Metering, Section 8--Measurement of Liquid
                Hydrocarbons by Ultrasonic Flow Meters Using Transit Time Technology;
                First Edition, February 2005; incorporated by reference at Sec.
                250.1202(a);
                 (26) API MPMS Chapter 6--Metering Assemblies, Section 1--Lease
                Automatic Custody Transfer (LACT) Systems, Second Edition, May 1991;
                reaffirmed, April 2007; incorporated by reference at Sec. 250.1202;
                 (27) API MPMS Chapter 6--Metering Assemblies, Section 6--Pipeline
                Metering Systems, Second Edition, May 1991; reaffirmed, February 2007;
                incorporated by reference at Sec. 250.1202;
                 (28) API MPMS Chapter 6--Metering Assemblies, Section 7--Metering
                Viscous Hydrocarbons, Second Edition, May 1991; reaffirmed, April 2007;
                incorporated by reference at Sec. 250.1202;
                 (29) API MPMS Chapter 7--Temperature Determination, First Edition,
                June 2001; reaffirmed, March 2007; incorporated by reference at Sec.
                250.1202;
                 (30) API MPMS Chapter 8--Sampling, Section 1--Standard Practice for
                Manual Sampling of Petroleum and Petroleum Products, Third Edition,
                October 1995; reaffirmed, March 2006; incorporated by reference at
                Sec. 250.1202;
                 (31) API MPMS Chapter 8--Sampling, Section 2--Standard Practice for
                Automatic Sampling of Liquid Petroleum and Petroleum Products, Second
                Edition, October 1995; reaffirmed, June 2005; incorporated by reference
                at Sec. 250.1202;
                 (32) API MPMS Chapter 9--Density Determination, Section 1--Standard
                Test Method for Density, Relative Density (Specific Gravity), or API
                Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer
                Method, Second Edition, December 2002; reaffirmed October 2005;
                incorporated by reference at Sec. 250.1202(a) and (l);
                 (33) API MPMS Chapter 9--Density Determination, Section 2--Standard
                Test Method for Density or Relative Density of Light Hydrocarbons by
                Pressure Hydrometer, Second Edition, March 2003; incorporated by
                reference at Sec. 250.1202;
                 (34) API MPMS Chapter 10--Sediment and Water, Section 1--Standard
                Test Method for Sediment in Crude Oils and Fuel Oils by the Extraction
                Method, Third Edition, November 2007; incorporated by reference at
                Sec. 250.1202;
                 (35) API MPMS Chapter 10--Sediment and Water, Section 2--Standard
                Test Method for Water in Crude Oil by Distillation, Second Edition,
                November 2007; incorporated by reference at Sec. 250.1202;
                 (36) API MPMS Chapter 10--Sediment and Water, Section 3--Standard
                Test Method for Water and Sediment in Crude Oil by the Centrifuge
                Method (Laboratory Procedure), Third Edition, May 2008; incorporated by
                reference at Sec. 250.1202;
                 (37) API MPMS Chapter 10--Sediment and Water, Section 4--
                Determination of Water and/or Sediment in Crude Oil by the Centrifuge
                Method (Field Procedure), Third Edition, December 1999; incorporated by
                reference at Sec. 250.1202;
                 (38) API MPMS Chapter 10--Sediment and Water, Section 9--Standard
                Test Method for Water in Crude Oils by Coulometric Karl Fischer
                Titration, Second Edition, December 2002; reaffirmed 2005; incorporated
                by reference at Sec. 250.1202;
                 (39) API MPMS Chapter 11.1--Volume Correction Factors, Volume 1,
                Table 5A--Generalized Crude Oils and JP-4 Correction of Observed API
                Gravity to API Gravity at 60 [deg]F, and Table 6A--Generalized Crude
                Oils and JP-4 Correction of Volume to 60 [deg]F Against API Gravity at
                60 [deg]F, API Standard 2540, First Edition, August 1980; reaffirmed
                March 1997; incorporated by reference at Sec. 250.1202;
                 (40) API MPMS Chapter 11.2.2--Compressibility Factors for
                Hydrocarbons: 0.350-0.637 Relative Density (60 [deg]F/60 [deg]F) and -
                50 [deg]F to 140 [deg]F Metering Temperature, Second Edition, October
                1986; reaffirmed: December 2007; incorporated by reference at Sec.
                250.1202;
                 (41) API MPMS Chapter 11--Physical Properties Data, Section 1--
                Temperature and Pressure Volume Correction Factors for Generalized
                Crude Oils, Refined Products, and Lubricating Oils; May 2004
                (incorporating Addendum 1, September 2007); incorporated by reference
                at Sec. 250.1202(a), (g), and (l);
                 (42) API MPMS Chapter 11--Physical Properties Data, Addendum to
                Section 2, Part 2--Compressibility Factors for Hydrocarbons,
                Correlation of Vapor Pressure for Commercial Natural Gas Liquids, First
                Edition, December 1994; reaffirmed, December 2002; incorporated by
                reference at Sec. 250.1202;
                 (43) API MPMS Chapter 12--Calculation of Petroleum Quantities,
                Section 2--Calculation of Petroleum Quantities Using Dynamic
                Measurement Methods and Volumetric Correction Factors, Part 1--
                Introduction, Second Edition, May 1995; reaffirmed March 2002;
                incorporated by reference at Sec. 250.1202;
                 (44) API MPMS Chapter 12--Calculation of Petroleum Quantities,
                Section 2--Calculation of Petroleum
                [[Page 21971]]
                Quantities Using Dynamic Measurement Methods and Volumetric Correction
                Factors, Part 2--Measurement Tickets, Third Edition, June 2003;
                incorporated by reference at Sec. 250.1202;
                 (45) API MPMS Chapter 12--Calculation of Petroleum Quantities,
                Section 2--Calculation of Petroleum Quantities Using Dynamic
                Measurement Methods and Volumetric Correction Factors, Part 3--Proving
                Reports; First Edition, reaffirmed 2009; incorporated by reference at
                Sec. 250.1202(a) and (g);
                 (46) API MPMS Chapter 12--Calculation of Petroleum Quantities,
                Section 2--Calculation of Petroleum Quantities Using Dynamic
                Measurement Methods and Volumetric Correction Factors, Part 4--
                Calculation of Base Prover Volumes by the Waterdraw Method, First
                Edition, December 1997; reaffirmed, 2009; incorporated by reference at
                Sec. 250.1202(a), (f), and (g);
                 (47) API MPMS Chapter 14--Natural Gas Fluids Measurement, Section
                3--Concentric, Square-Edged Orifice Meters, Part 1--General Equations
                and Uncertainty Guidelines, Third Edition, September 1990; reaffirmed,
                January 2003; incorporated by reference at Sec. 250.1203;
                 (48) API MPMS Chapter 14--Natural Gas Fluids Measurement, Section
                3--Concentric, Square-Edged Orifice Meters, Part 2--Specification and
                Installation Requirements, Fourth Edition, April 2000; reaffirmed March
                2006; incorporated by reference at Sec. 250.1203;
                 (49) API MPMS Chapter 14--Natural Gas Fluids Measurement, Section
                3--Concentric, Square-Edged Orifice Meters; Part 3--Natural Gas
                Applications; Third Edition, August 1992; Errata March 1994,
                reaffirmed, February 2009; incorporated by reference at Sec. 250.1203;
                 (50) API MPMS Chapter 14.5/GPA Standard 2172-09; Calculation of
                Gross Heating Value, Relative Density, Compressibility and Theoretical
                Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody
                Transfer; Third Edition, January 2009; incorporated by reference at
                Sec. 250.1203;
                 (51) API MPMS Chapter 14--Natural Gas Fluids Measurement, Section
                6--Continuous Density Measurement, Second Edition, April 1991;
                reaffirmed, February 2006; incorporated by reference at Sec. 250.1203;
                 (52) API MPMS Chapter 14--Natural Gas Fluids Measurement, Section
                8--Liquefied Petroleum Gas Measurement, Second Edition, July 1997;
                reaffirmed, March 2006; incorporated by reference at Sec. 250.1203;
                 (53) API MPMS Chapter 20--Section 1--Allocation Measurement, First
                Edition, September 1993; reaffirmed October 2006; incorporated by
                reference at Sec. 250.1202;
                 (54) API MPMS Chapter 21--Flow Measurement Using Electronic
                Metering Systems, Section 1--Electronic Gas Measurement, First Edition,
                August 1993; reaffirmed, July 2005; incorporated by reference at Sec.
                250.1203;
                 (55) API MPMS Chapter 21--Flow Measurement Using Electronic
                Metering Systems, Section 2--Electronic Liquid Volume Measurement Using
                Positive Displacement and Turbine Meters; First Edition, June 1998;
                incorporated by reference at Sec. 250.1202(a);
                 (56) API MPMS Chapter 21--Flow Measurement Using Electronic
                Metering Systems, Addendum to Section 2--Flow Measurement Using
                Electronic Metering Systems, Inferred Mass; First Edition, reaffirmed
                February 2006; incorporated by reference at Sec. 250.1202(a);
                 (57) API RP 2A-WSD, Recommended Practice for Planning, Designing
                and Constructing Fixed Offshore Platforms--Working Stress Design,
                Twenty-first Edition, December 2000; Errata and Supplement 1, December
                2002; Errata and Supplement 2, September 2005; Errata and Supplement 3,
                October 2007; incorporated by reference at Sec. Sec. 250.901, 250.908,
                250.919, and 250.920;
                 (58) API RP 2D, Operation and Maintenance of Offshore Cranes, Sixth
                Edition, May 2007; incorporated by reference at Sec. 250.108;
                 (59) API RP 2FPS, RP for Planning, Designing, and Constructing
                Floating Production Systems; First Edition, March 2001; incorporated by
                reference at Sec. 250.901;
                 (60) API RP 2I, In-Service Inspection of Mooring Hardware for
                Floating Structures; Third Edition, April 2008; incorporated by
                reference at Sec. 250.901(a) and (d);
                 (61) ANSI/API RP 2N, Third Edition, ``Recommended Practice for
                Planning, Designing, and Constructing Structures and Pipelines for
                Arctic Conditions'', Third Edition, April 2015; incorporated by
                reference at Sec. 250.470(g);
                 (62) API RP 2RD, Recommended Practice for Design of Risers for
                Floating Production Systems (FPSs) and Tension-Leg Platforms (TLPs),
                First Edition, June 1998; reaffirmed, May 2006, Errata, June 2009;
                incorporated by reference at Sec. Sec. 250.733, 250.800(c),
                250.901(a), (d), and 250.1002(b);
                 (63) API RP 2SK, Design and Analysis of Stationkeeping Systems for
                Floating Structures, Third Edition, October 2005, Addendum, May 2008,
                reaffirmed June 2015; incorporated by reference at Sec. Sec.
                250.800(c) and 250.901(a) and (d);
                 (64) API RP 2SM, Recommended Practice for Design, Manufacture,
                Installation, and Maintenance of Synthetic Fiber Ropes for Offshore
                Mooring, First Edition, March 2001, Addendum, May 2007; incorporated by
                reference at Sec. Sec. 250.800(c) and 250.901(a) and (d);
                 (65) API RP 2T, Recommended Practice for Planning, Designing, and
                Constructing Tension Leg Platforms, Second Edition, August 1997;
                incorporated by reference at Sec. 250.901(a) and (d);
                 (66) ANSI/API RP 14B, Design, Installation, Operation, Test, and
                Redress of Subsurface Safety Valve Systems, Sixth Edition, September
                2015; incorporated by reference at Sec. Sec. 250.802(b), 250.803(a),
                250.814(d), 250.828(c), and 250.880(c);
                 (67) API RP 14C, Recommended Practice for Analysis, Design,
                Installation, and Testing of Basic Surface Safety Systems for Offshore
                Production Platforms, Seventh Edition, March 2001, reaffirmed: March
                2007; incorporated by reference at Sec. Sec. 250.125(a), 250.292(j),
                250.841(a), 250.842(a), 250.850, 250.852(a), 250.855, 250.856(a),
                250.858(a), 250.862(e), 250.865(a), 250.867(a), 250.869(a) through (c),
                250.872(a), 250.873(a), 250.874(a), 250.880(b) and (c), 250.1002(d),
                250.1004(b), 250.1628(c) and (d), 250.1629(b), and 250.1630(a);
                 (68) API RP 14E, Recommended Practice for Design and Installation
                of Offshore Production Platform Piping Systems, Fifth Edition, October
                1991; reaffirmed, January 2013; incorporated by reference at Sec. Sec.
                250.841(b), 250.842(a), and 250.1628(b) and (d);
                 (69) API RP 14F, Recommended Practice for Design, Installation, and
                Maintenance of Electrical Systems for Fixed and Floating Offshore
                Petroleum Facilities for Unclassified and Class 1, Division 1 and
                Division 2 Locations, Upstream Segment, Fifth Edition, July 2008,
                reaffirmed: April 2013; incorporated by reference at Sec. Sec.
                250.114(c), 250.842(c), 250.862(e), and 250.1629(b);
                 (70) API RP 14FZ, Recommended Practice for Design, Installation,
                and Maintenance of Electrical Systems for Fixed and Floating Offshore
                Petroleum Facilities for Unclassified and Class I, Zone 0, Zone 1 and
                Zone 2 Locations, Second Edition, May 2013; incorporated by reference
                at Sec. Sec. 250.114(c), 250.842(c), 250.862(e), and 250.1629(b);
                 (71) API RP 14G, Recommended Practice for Fire Prevention and
                Control on Fixed Open-type Offshore Production Platforms, Fourth
                Edition, April 2007; Reaffirmed, January 2013; incorporated by
                reference at
                [[Page 21972]]
                Sec. Sec. 250.859(a), 250.862(e), 250.880(c), and 250.1629(b);
                 (72) API RP 14J, Recommended Practice for Design and Hazards
                Analysis for Offshore Production Facilities, Second Edition, May 2001;
                reaffirmed: January 2013; incorporated by reference at Sec. Sec.
                250.800(b) and (c), 250.842(c), and 250.901(a) and (d);
                 (73) API RP 17H, Remotely Operated Tools and Interfaces on Subsea
                Production Systems, Second Edition, June 2013; Errata, January 2014;
                incorporated by reference at Sec. 250.734(a);
                 (74) API RP 65, Recommended Practice for Cementing Shallow Water
                Flow Zones in Deepwater Wells, First Edition, September 2002;
                incorporated by reference at Sec. 250.415;
                 (75) API RP 75, Recommended Practice for Development of a Safety
                and Environmental Management Program for Offshore Operations and
                Facilities, Third Edition, May 2004, reaffirmed May 2008; incorporated
                by reference at Sec. Sec. 250.1900, 250.1902, 250.1903, 250.1909,
                250.1920;
                 (76) API RP 86, API Recommended Practice for Measurement of
                Multiphase Flow; First Edition, September 2005; incorporated by
                reference at Sec. Sec. 250.1202(a) and 250.1203(b);
                 (77) API RP 90, Annular Casing Pressure Management for Offshore
                Wells, First Edition, August 2006; incorporated by reference at Sec.
                250.519;
                 (78) API RP 500, Recommended Practice for Classification of
                Locations for Electrical Installations at Petroleum Facilities
                Classified as Class I, Division 1 and Division 2, Third Edition,
                December 2012; Errata January 2014, incorporated by reference at
                Sec. Sec. 250.114(a), 250.459, 250.842(a), 250.862(a) and (e),
                250.872(a), 250.1628(b) and (d), and 250.1629(b);
                 (79) API RP 505, Recommended Practice for Classification of
                Locations for Electrical Installations at Petroleum Facilities
                Classified as Class I, Zone 0, Zone 1, and Zone 2, First Edition,
                November 1997; reaffirmed, August 2013; incorporated by reference at
                Sec. Sec. 250.114(a), 250.459, 250.842(a), 250.862(a) and (e),
                250.872(a), 250.1628(b) and (d), and 250.1629(b);
                 (80) API RP 2556, Recommended Practice for Correcting Gauge Tables
                for Incrustation, Second Edition, August 1993; reaffirmed November
                2003; incorporated by reference at Sec. 250.1202;
                 (81) API Spec. 2C, Specification for Offshore Pedestal Mounted
                Cranes, Sixth Edition, March 2004, Effective Date: September 2004;
                incorporated by reference at Sec. 250.108;
                 (82) ANSI/API Spec. 6A, Specification for Wellhead and Christmas
                Tree Equipment, Twentieth Edition, October 2010; Addendum 1, November
                2011; Errata 2, November 2011; Addendum 2, November 2012; Addendum 3,
                March 2013; Errata 3, June 2013; Errata 4, August 2013; Errata 5,
                November 2013; Errata 6, March 2014; Errata 7, December 2014; Errata 8,
                February 2016; Addendum 4, June 2016; Errata 9, June 2016; Errata 10,
                August 2016; incorporated by reference at Sec. Sec. 250.730,
                250.802(a), 250.803(a), 250.833, 250.873(b), 250.874(g), and
                250.1002(b);
                 (83) API Spec. 6AV1, Specification for Verification Test of
                Wellhead Surface Safety Valves and Underwater Safety Valves for
                Offshore Service, Second Edition, February 2013; incorporated by
                reference at Sec. Sec. 250.802(a), 250.833, 250.873(b), and
                250.874(g);
                 (84) API STD 6AV2, Installation, Maintenance, and Repair of Surface
                Safety Valves and Underwater Safety Valves Offshore; First Edition,
                March 2014; Errata 1, August 2014; incorporated by reference at
                Sec. Sec. 250.820, 250.834, 250.836, and 250.880(c)
                 (85) ANSI/API Spec. 6D, Specification for Pipeline Valves, Twenty-
                third Edition, April 2008; Effective Date: October 1, 2008, Errata 1,
                June 2008; Errata 2, November 2008; Errata 3, February 2009; Addendum
                1, October 2009; Contains API Monogram Annex as Part of U.S. National
                Adoption; ISO 14313:2007 (Identical), Petroleum and natural gas
                industries--Pipeline transportation systems--Pipeline valves;
                incorporated by reference at Sec. 250.1002(b);
                 (86) ANSI/API Spec. 11D1, Packers and Bridge Plugs, Second Edition,
                July 2009; incorporated by reference at Sec. Sec. 250.518, 250.619,
                and 250.1703;
                 (87) ANSI/API Spec. 14A, Specification for Subsurface Safety Valve
                Equipment, Eleventh Edition, October 2005, reaffirmed, June 2012;
                incorporated by reference at Sec. Sec. 250.802 and 250.803(a);
                 (88) ANSI/API Spec. 16A, Specification for Drill-through Equipment,
                Third Edition, June 2004, reaffirmed August 2010; incorporated by
                reference at Sec. 250.730;
                 (89) ANSI/API Spec. 16C, Specification for Choke and Kill Systems,
                First Edition, January 1993, reaffirmed July 2010; incorporated by
                reference at Sec. 250.730;
                 (90) API Spec. 16D, Specification for Control Systems for Drilling
                Well Control Equipment and Control Systems for Diverter Equipment,
                Second Edition, July 2004, reaffirmed August 2013; incorporated by
                reference at Sec. 250.730;
                 (91) ANSI/API Spec. 17D, Design and Operation of Subsea Production
                Systems--Subsea Wellhead and Tree Equipment, Second Edition, May 2011;
                incorporated by reference at Sec. 250.730;
                 (92) ANSI/API Spec. 17J, Specification for Unbonded Flexible Pipe,
                Third Edition, July 2008, incorporated by reference at Sec. Sec.
                250.852(e), 250.1002(b), and 250.1007(a).
                 (93) ANSI/API Spec. Q1, Specification for Quality Management System
                Requirements for Manufacturing Organizations for the Petroleum and
                Natural Gas Industry, Ninth Edition, June 2013; Errata, February 2014;
                Errata 2, March 2014; Addendum 1, June 2016; incorporated by reference
                at Sec. Sec. 250.730 and 250.801(b) and (c);
                 (94) API Standard 53, Blowout Prevention Equipment Systems for
                Drilling Wells, Fourth Edition, November 2012, Addendum 1, July 2016,
                incorporated by reference at Sec. Sec. 250.730, 250.734, 250.735,
                250.736, 250.737, and 250.739;
                 (95) API Standard 65--Part 2, Isolating Potential Flow Zones During
                Well Construction; Second Edition, December 2010; incorporated by
                reference at Sec. Sec. 250.415(f) and 250.420(a);
                 (96) API Standard 2552, USA Standard Method for Measurement and
                Calibration of Spheres and Spheroids, First Edition, 1966; reaffirmed,
                October 2007; incorporated by reference at Sec. 250.1202;
                 (97) API Standard 2555, Method for Liquid Calibration of Tanks,
                First Edition, September 1966; reaffirmed March 2002; incorporated by
                reference at Sec. 250.1202;
                 (f) American Society of Mechanical Engineers (ASME), 22 Law Drive,
                P.O. Box 2900, Fairfield, NJ 07007-2900; http://www.asme.org; phone: 1-
                800-843-2763.
                 (1) 2017 ASME Boiler and Pressure Vessel Code (BPVC), Section I,
                Rules for Construction of Power Boilers, 2017 Edition, July 1, 2017,
                incorporated by reference at Sec. Sec. 250.851(a) and 250.1629(b).
                 (2) 2017 ASME Boiler and Pressure Vessel Code, Section IV, Rules
                for Construction of Heating Boilers, 2017 Edition, July 1, 2017,
                incorporated by reference at Sec. Sec. 250.851(a) and 250.1629(b).
                 (3) 2017 ASME Boiler and Pressure Vessel Code, Section VIII, Rules
                for Construction of Pressure Vessels; Division 1, 2017 Edition; July 1,
                2017, incorporated by reference at Sec. Sec. 250.851(a) and
                250.1629(b).
                 (4) 2017 ASME Boiler and Pressure Vessel Code, Section VIII, Rules
                for Construction of Pressure Vessels; Division 2: Alternative Rules,
                2017 Edition, July 1, 2017, incorporated by
                [[Page 21973]]
                reference at Sec. Sec. 250.851(a) and 250.1629(b).
                 (5) 2017 ASME Boiler and Pressure Vessel Code, Section VIII, Rules
                for Construction of Pressure Vessels; Division 3: Alternative Rules for
                Construction of High Pressure Vessels, 2017 Edition, July 1, 2017,
                incorporated by reference at Sec. Sec. 250.851(a) and 250.1629(b).
                 (g) American Society for Testing and Materials (ASTM), ASTM
                Standards, 100 Bar Harbor Drive, P.O. Box C700, West Conshohocken, PA
                19428-2959; http://www.astm.org; phone: 1-877-909-2786:
                 (1) ASTM Standard C 33-07, approved December 15, 2007, Standard
                Specification for Concrete Aggregates; incorporated by reference at
                Sec. 250.901;
                 (2) ASTM Standard C 94/C 94M-07, approved January 1, 2007, Standard
                Specification for Ready-Mixed Concrete; incorporated by reference at
                Sec. 250.901;
                 (3) ASTM Standard C 150-07, approved May 1, 2007, Standard
                Specification for Portland Cement; incorporated by reference at Sec.
                250.901;
                 (4) ASTM Standard C 330-05, approved December 15, 2005, Standard
                Specification for Lightweight Aggregates for Structural Concrete;
                incorporated by reference at Sec. 250.901;
                 (5) ASTM Standard C 595-08, approved January 1, 2008, Standard
                Specification for Blended Hydraulic Cements; incorporated by reference
                at Sec. 250.901;
                 (h) American Welding Society (AWS), AWS Codes, 8669 NW 36 Street,
                #130, Miami, FL 33126; http://www.aws.org;phone: 800-443-9353:
                 (1) AWS D1.1:2000, Structural Welding Code--Steel, 17th Edition,
                October 18, 1999; incorporated by reference at Sec. 250.901;
                 (2) AWS D1.4-98, Structural Welding Code--Reinforcing Steel, 1998
                Edition; incorporated by reference at Sec. 250.901;
                 (3) AWS D3.6M:1999, Specification for Underwater Welding (1999);
                incorporated by reference at Sec. 250.901.
                 (i) National Association of Corrosion Engineers (NACE)
                International, NACE Standards, Park Ten Place, Houston, TX 77084;
                http://www.nace.org; phone: 281-228-6200:
                 (1) NACE Standard MR0175-2003, Standard Material Requirements,
                Metals for Sulfide Stress Cracking and Stress Corrosion Cracking
                Resistance in Sour Oilfield Environments, Revised January 17, 2003;
                incorporated by reference at Sec. Sec. 250.490 and 250.901;
                 (2) NACE Standard RP0176-2003, Standard Recommended Practice,
                Corrosion Control of Steel Fixed Offshore Structures Associated with
                Petroleum Production; incorporated by reference at Sec. 250.901.
                 (j) International Organization for Standardization (ISO), 1, ch. de
                la Voie-Creuse, CP 56, CH-1211, Geneva 20, Switzerland; www.iso.org;
                phone: 41-22-749-01-11:
                 (1) ISO/IEC (International Electrotechnical Commission) 17011,
                Conformity assessment--General requirements for accreditation bodies
                accrediting conformity assessment bodies, First edition 2004-09-01;
                Corrected version 2005-02-15; incorporated by reference at Sec. Sec.
                250.1900, 250.1903, 250.1904, and 250.1922.
                 (2) ISO/IEC 17021-1, Conformity assessment--Requirements for bodies
                providing audit and certification of management systems--Part 1:
                Requirements, First Edition, June 2015, incorporated by reference at
                Sec. 250.730(d).
                 (3) [Reserved]
                 (k) Center for Offshore Safety (COS), 1990 Post Oak Blvd., Suite
                1370, Houston, TX 77056; www.centerforoffshoresafety.org; phone: 832-
                495-4925.
                 (1) COS Safety Publication COS-2-01, Qualification and Competence
                Requirements for Audit Teams and Auditors Performing Third-party SEMS
                Audits of Deepwater Operations, First Edition, Effective Date October
                2012; incorporated by reference at Sec. Sec. 250.1900, 250.1903,
                250.1904, and 250.1921.
                 (2) COS Safety Publication COS-2-03, Requirements for Third-party
                SEMS Auditing and Certification of Deepwater Operations, First Edition,
                Effective Date October 2012; incorporated by reference at Sec. Sec.
                250.1900, 250.1903, 250.1904, and 250.1920.
                 (3) COS Safety Publication COS-2-04, Requirements for Accreditation
                of Audit Service Providers Performing SEMS Audits and Certification of
                Deepwater Operations, First Edition, Effective Date October 2012;
                incorporated by reference at Sec. Sec. 250.1900, 250.1903, 250.1904,
                and 250.1922.
                Subpart B--Plans and Information
                0
                4. Amend Sec. 250.292 by revising paragraph (p) to read as follows:
                Sec. 250.292 What must the DWOP contain?
                * * * * *
                 (p) If you propose to use a pipeline free standing hybrid riser
                (FSHR) on a permanent installation that utilizes a buoyancy air can
                suspended from the top of the riser, you must provide the following
                information in your DWOP in the discussions required by paragraphs (f)
                and (g) of this section:
                 (1) A detailed description and drawings of the FSHR, buoy, and the
                associated connection system;
                 (2) Detailed information regarding the system used to connect the
                FSHR to the buoyancy air can, and associated redundancies; and
                 (3) Descriptions of your monitoring system and monitoring plan to
                monitor the pipeline FSHR and the associated connection system for
                fatigue, stress, and any other abnormal condition (e.g., corrosion)
                that may negatively impact the riser system's integrity.
                * * * * *
                Subpart D--Oil and Gas Drilling Operations
                0
                5. Amend Sec. 250.413 by revising paragraph (g) to read as follows:
                Sec. 250.413 What must my description of well drilling design
                criteria address?
                * * * * *
                 (g) A single plot containing curves for estimated pore pressures,
                formation fracture gradients, proposed drilling fluid weights (surface
                and downhole), planned safe drilling margin, and casing setting depths
                in true vertical measurements;
                * * * * *
                0
                6. Amend Sec. 250.414 by revising paragraphs (c)(2) and (c)(3) to read
                as follows:
                Sec. 250.414 What must my drilling prognosis include?
                * * * * *
                 (c) * * *
                 (2) In lieu of meeting the criteria in paragraph (c)(1)(ii) of this
                section, you may use an equivalent downhole mud weight as specified in
                your APD, provided that you submit adequate documentation (such as risk
                modeling data, off-set well data, analog data, seismic data) to justify
                the alternative equivalent downhole mud weight. You may submit such
                justification in advance of your full APD, and BSEE may consider such
                justification for approval when submitted. Any such approval will be
                contingent upon your confirmation in the APD that your plans and the
                information underlying your approved justification have not changed.
                 (3) When determining the pore pressure and lowest estimated
                fracture gradient for a specific interval, you must consider related
                off-set and analogous well behavior observations, if available.
                * * * * *
                0
                7. Amend Sec. 250.420 by revising paragraph (a)(6) to read as follows:
                [[Page 21974]]
                Sec. 250.420 What well casing and cementing requirements must I
                meet?
                * * * * *
                 (a) * * *
                 (6) Provide adequate centralization consistent with the guidelines
                of API Standard 65--Part 2 (as incorporated by reference in Sec.
                250.198); and
                * * * * *
                0
                8. Amend Sec. 250.421 by revising paragraphs (c), (d), (e), and (f) to
                read as follows:
                Sec. 250.421 What are the casing and cementing requirements by type
                of casing string?
                * * * * *
                ------------------------------------------------------------------------
                 Cementing
                 Casing type Casing requirements requirements
                ------------------------------------------------------------------------
                
                 * * * * * * *
                (c) Surface................. Design casing and Use enough cement to
                 select setting fill the calculated
                 depths based on annular space to at
                 relevant least 200 feet
                 engineering and measured depth (MD)
                 geologic factors. inside the
                 These factors conductor casing.
                 include the When geologic
                 presence or absence conditions such as
                 of hydrocarbons, near-surface
                 potential hazards, fractures and
                 and water depths. faulting exist, you
                 must use enough
                 cement to fill the
                 calculated annular
                 space to the
                 mudline.
                (d) Intermediate............ Design casing and Use enough cement to
                 select setting cover and isolate
                 depth based on all hydrocarbon-
                 anticipated or bearing zones and
                 encountered isolate abnormal
                 geologic pressure intervals
                 characteristics or from normal
                 wellbore conditions. pressure intervals
                 in the well.
                 As a minimum, you
                 must cement the
                 annular space 500
                 feet MD above the
                 casing shoe and 500
                 feet MD above each
                 zone to be
                 isolated.
                (e) Production.............. Design casing and Use enough cement to
                 select setting cover or isolate
                 depth based on all hydrocarbon-
                 anticipated or bearing zones above
                 encountered the shoe.
                 geologic As a minimum, you
                 characteristics or must cement the
                 wellbore conditions. annular space at
                 least 500 feet MD
                 above the casing
                 shoe and 500 feet
                 MD above the
                 uppermost
                 hydrocarbon-bearing
                 zone.
                (f) Liners.................. If you use a liner Same as cementing
                 as surface casing, requirements for
                 you must set the specific casing
                 top of the liner at types. For example,
                 least 200 feet MD a liner used as
                 above the previous intermediate casing
                 casing/liner shoe.. must be cemented
                 If you use a liner according to the
                 as an intermediate cementing
                 string below a requirements for
                 surface string or intermediate
                 production casing casing.
                 below an
                 intermediate
                 string, you must
                 set the top of the
                 liner at least 100
                 feet MD above the
                 previous casing
                 shoe..
                 You may not use a
                 liner as conductor
                 casing.
                 A subsea well casing
                 string whose top is
                 above the mudline
                 and that has been
                 cemented back to
                 the mudline will
                 not be considered a
                 liner.
                ------------------------------------------------------------------------
                0
                9. Amend Sec. 250.423 by revising paragraphs (a) and (b) to read as
                follows:
                Sec. 250.423 What are the requirements for casing and liner
                installation?
                * * * * *
                 (a) You must ensure that the latching mechanisms or lock down
                mechanisms are engaged upon successfully installing the casing string.
                 (b) If you run a liner that has a latching mechanism or lock down
                mechanism, you must ensure that the latching mechanisms or lock down
                mechanisms are engaged upon successfully installing the liner.
                * * * * *
                0
                10. Amend Sec. 250.427 by revising paragraph (b) to read as follows:
                Sec. 250.427 What are the requirements for pressure integrity tests?
                * * * * *
                 (b) While drilling, you must maintain the safe drilling margin
                identified in Sec. 250.414. When you cannot maintain the safe drilling
                margin, you must:
                 (1) Suspend drilling operations and submit proposed remedial
                actions to the District Manager. The District Manager must review and
                approve your proposed remedial actions, which may include limited
                drilling through a lost circulation zone; or
                 (2) Notify the District Manager and take further action in
                accordance with API Bulletin 92L (as incorporated by reference in Sec.
                250.198), if appropriate. You must submit a revised permit documenting
                any responsive actions taken.
                0
                 11. Amend Sec. 250.428 by revising paragraphs (c) and (d) to read as
                follows:
                Sec. 250.428 What must I do in certain cementing and casing
                situations?
                * * * * *
                [[Page 21975]]
                ------------------------------------------------------------------------
                 If you encounter the following
                 situation: Then you must . . .
                ------------------------------------------------------------------------
                
                 * * * * * * *
                (c) Have indication of inadequate (1) Locate the top of cement
                 cement job (such as unplanned lost by:
                 returns, no cement returns to mudline (i) Running a temperature
                 or expected height, cement channeling, survey;
                 or failure of equipment), (ii) Running a cement
                 evaluation log;
                 (iii) Using tracers in the
                 cement and logging them prior
                 to drill out; or
                 (iv) 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,............. Comply with Sec.
                 250.428(c)(1) and take
                 remedial actions. The District
                 Manager must review and
                 approve all remedial actions
                 either through a previously
                 approved contingency plan
                 within the permit or remedial
                 actions included in a revised
                 permit before you may take
                 them, unless immediate actions
                 must be taken to ensure the
                 safety of the crew or to
                 prevent a well-control event.
                 If you complete any immediate
                 action to ensure the safety of
                 the crew or to prevent a well-
                 control event, submit a
                 description of the action to
                 the District Manager when that
                 action is complete. Any
                 changes to the well program,
                 that are not included in the
                 approved permit, will require
                 submittal of a certification
                 by a professional engineer
                 (PE) certifying that they have
                 reviewed and approved the
                 proposed changes. You must
                 also meet any other
                 requirements of the District
                 Manager for remedial actions.
                
                 * * * * * * *
                ------------------------------------------------------------------------
                0
                12. Amend Sec. 250.433 by revising paragraph (b) to read as follows:
                Sec. 250.433 What are the diverter actuation and testing
                requirements?
                * * * * *
                 (b) For floating drilling operations with a subsea BOP stack, you
                must actuate the diverter system within 7 days after the previous
                actuation. For subsequent testing, you may partially actuate the
                diverter element and a flow test is not required.
                * * * * *
                0
                13. Amend Sec. 250.461 by revising paragraph (b) to read as follows:
                Sec. 250.461 What are the requirements for directional and
                inclination surveys?
                * * * * *
                 (b) Survey requirements for a directional well. You must conduct
                directional surveys on each directional well and digitally record the
                results. Surveys must give both inclination and azimuth at intervals
                not to exceed 500 feet during the normal course of drilling. Intervals
                during angle-changing portions of the hole may not exceed 180 feet.
                * * * * *
                0
                14. Amend Sec. 250.462 by revising paragraphs (b) introductory text,
                (e)(1)(ii), (e)(2)(i), (e)(3), and (e)(4) to read as follows:
                Sec. 250.462 What are the source control, containment, and
                collocated equipment requirements?
                * * * * *
                 (b) You must have access to and the ability to deploy Source
                Control and Containment Equipment (SCCE) and all other necessary
                supporting and collocated equipment to regain control of the well. SCCE
                means the capping stack, cap-and-flow system, containment dome, and/or
                other subsea and surface devices, equipment, and vessels, which have
                the collective purpose to control a spill source and stop the flow of
                fluids into the environment or to contain fluids escaping into the
                environment based on the determinations outlined in paragraph (a) of
                this section. This SCCE, supporting equipment, and collocated equipment
                may include, but is not limited to, the following:
                * * * * *
                 (e) * * *
                ------------------------------------------------------------------------
                 Requirements, you Additional
                 Equipment must: information
                ------------------------------------------------------------------------
                (1) * * *
                 (ii) Pressure test Pressure containing
                 pressure containing critical components
                 critical components are those
                 on a bi-annual components that
                 basis, but not will experience
                 later than 210 days wellbore pressure
                 from the last during a shut-in.
                 pressure test. All These components
                 pressure testing include, but are
                 must be witnessed not limited to: All
                 by BSEE (if blind rams,
                 available) and an wellhead
                 independent third connectors, and
                 party. outlet valves.
                
                 * * * * * * *
                (2) Production safety (i) Meet or exceed ....................
                 systems used for flow and the requirements
                 capture operations. set forth in
                 Subpart H,
                 excluding required
                 equipment that
                 would be installed
                 below the wellhead
                 or that is not
                 applicable to the
                 cap and flow
                 system.
                
                 * * * * * * *
                (3) Subsea utility Have all equipment Subsea utility
                 equipment,. utilized solely for equipment includes,
                 containment but is not limited
                 operations to: Hydraulic power
                 available for sources, debris
                 inspection at all removal, and
                 times. hydrate control
                 equipment.
                [[Page 21976]]
                
                (4) Collocated equipment Have equipment Collocated equipment
                 designated by the operator available for includes, but is
                 in the Regional Containment inspection at all not limited to,
                 Demonstration (RCD) or Well times. dispersant
                 Containment Plan (WCP), injection equipment
                 and other subsea
                 control equipment.
                ------------------------------------------------------------------------
                Subpart E--Oil and Gas Well-Completion Operations
                0
                15. Amend Sec. 250.518 by revising paragraph (e)(1) and adding new
                paragraph (g) to read as follows:
                Sec. 250.518 Tubing and wellhead equipment.
                * * * * *
                 (e) * * *
                 (1) The uppermost permanently installed packer and all permanently
                installed bridge plugs qualified as mechanical barriers must comply
                with ANSI/API Spec. 11D1 (as incorporated by reference in Sec.
                250.198);
                * * * * *
                 (g) You must have two independent barriers, one being mechanical,
                in the exposed center wellbore prior to removing the tree and/or well
                control equipment.
                0
                16. Revise Sec. 250.519 to read as follows:
                Sec. 250.519 What are the requirements for casing pressure
                management?
                 Once you install your wellhead, you must meet the casing pressure
                management requirements of API RP 90 (as incorporated by reference in
                Sec. 250.198) and the requirements of Sec. Sec. 250.519 through
                250.531. If there is a conflict between API RP 90 and the casing
                pressure requirements of this subpart, you must follow the requirements
                of this subpart.
                0
                17. Revise Sec. 250.522 to read as follows:
                Sec. 250.522 How do I manage the thermal effects caused by initial
                production on a newly completed or recompleted well?
                 A newly completed or recompleted well often has thermal casing
                pressure during initial startup. Bleeding casing pressure during the
                startup process is considered a normal and necessary operation to
                manage thermal casing pressure; therefore, you do not need to evaluate
                these operations as a casing diagnostic test. After 30 days of
                continuous production, the initial production startup operation is
                complete and you must perform casing diagnostic testing as required in
                Sec. Sec. 250.521 and 250.523.
                0
                18. Amend Sec. 250.525 by revising paragraph (d) to read as follows:
                Sec. 250.525 When am I required to take action from my casing
                diagnostic test?
                * * * * *
                 (d) Any well that has sustained casing pressure (SCP) and is bled
                down to prevent it from exceeding its MAWOP, except during initial
                startup operations described in Sec. 250.522;
                * * * * *
                0
                19. Revise Sec. 250.526 to read as follows:
                Sec. 250.526 What do I submit if my casing diagnostic test requires
                action?
                 Within 14 days after you perform a casing diagnostic test requiring
                action under Sec. 250.525:
                ----------------------------------------------------------------------------------------------------------------
                You must submit either . . and it must include . . .
                 . to the appropriate . . . You must also . . .
                ----------------------------------------------------------------------------------------------------------------
                (a) a notification of District Manager and copy requirements under Sec. submit an Application for
                 corrective action; or, the Regional Supervisor, 250.527, Permit to Modify or
                 Field Operations, Corrective Action Plan
                 within 30 days of the
                 diagnostic test.
                (b) a casing pressure Regional Supervisor, Field requirements under Sec. .............................
                 request, Operations, 250.528.
                ----------------------------------------------------------------------------------------------------------------
                0
                20. Amend Sec. 250.530 by revising paragraph (b) to read as follows:
                Sec. 250.530 What if my casing pressure request is denied?
                * * * * *
                 (b) You must submit the casing diagnostic test data to the
                appropriate Regional Supervisor, Field Operations, within 14 days of
                completion of the diagnostic test required under Sec. 250.523(e).
                Subpart F--Oil and Gas Well-Workover Operations
                0
                21. Amend Sec. 250.601 by adding paragraph (m) to the definition of
                ``routine operations'' to read as follows:
                Sec. 250.601 Definitions.
                * * * * *
                 (m) Acid treatments.
                * * * * *
                0
                22. Remove and reserve Sec. 250.616
                Sec. 250.616 [Reserved]
                0
                23. Amend Sec. 250.619 by revising paragraph (e)(1) and adding new
                paragraph (g) to read as follows:
                Sec. 250.619 Tubing and wellhead equipment.
                * * * * *
                 (e) * * *
                 (1) The uppermost permanently installed packer and all permanently
                installed bridge plugs qualified as mechanical barriers must comply
                with ANSI/API Spec. 11D1 (as incorporated by reference in Sec.
                250.198).
                * * * * *
                 (g) You must have two independent barriers, one being mechanical,
                in the exposed center wellbore prior to removing the tree and/or well
                control equipment.
                Subpart G--Well Operations and Equipment
                0
                24. Amend Sec. 250.712 by adding paragraphs (g) and (h) to read as
                follows:
                Sec. 250.712 What rig unit movements must I report?
                * * * * *
                 (g) You are not required to report rig unit movements to and from
                the safe zone during the course of permitted operations.
                 (h) If a rig unit is already on a well, you are not required to
                report any additional rig unit movements on that well.
                0
                25. Amend Sec. 250.720 by revising paragraph (a)(1) and adding
                paragraphs (a)(3) and (d) to read as follows:
                Sec. 250.720 When and how must I secure a well?
                 (a) * * *
                 (1) The events that would cause you to interrupt operations and
                notify the District Manager include, but are not limited to, the
                following:
                 (i) Evacuation of the rig crew;
                 (ii) Inability to keep the rig on location;
                [[Page 21977]]
                 (iii) Repair to major rig or well-control equipment;
                 (iv) Observed flow outside the well's casing (e.g., shallow water
                flow or bubbling); or
                 (v) Impending National Weather Service-named tropical storm or
                hurricane.
                * * * * *
                 (3) If you unlatch the BOP or LMRP:
                 (i) Upon relatch of the BOP, you must test according to Sec.
                250.734(b)(2), or
                 (ii) Upon relatch of the LMRP, you must test according to Sec.
                250.734(b)(3); and
                 (iii) You must submit a revised permit with a written statement
                from an independent third party certifying that the previous
                certification under Sec. 250.731(c) remains valid and receive District
                Manager approval before resuming operations.
                * * * * *
                 (d) You must have the equipment used solely for intervention
                operations (e.g., tree interface tools) identified, readily available,
                properly maintained, and available for BSEE inspection upon request.
                This equipment is required for subsea completed wells with a tree
                installed, that meet the following conditions:
                 (1) Have a shut-in tubing pressure that is greater than the
                hydrostatic pressure of the water column, or
                 (2) Are not capable of having the annulus monitored.
                0
                26. Amend Sec. 250.722 by revising paragraph (a)(2) to read as
                follows:
                Sec. 250.722 What are the requirements for prolonged operations in a
                well?
                * * * * *
                 (a) * * *
                 (2) Report the results of your evaluation to the District Manager
                and obtain approval of those results before resuming operations. Your
                report must include calculations that indicate the well's integrity is
                above the minimum safety factors, if an imaging tool or caliper is
                used. District Manager approval is not required to resume operations if
                you conducted a successful pressure test as approved in your permit.
                You must document the successful pressure test in the WAR.
                * * * * *
                0
                27. Amend Sec. 250.723 by revising the introductory text and paragraph
                (c)(3) to read as follows:
                Sec. 250.723 What additional safety measures must I take when I
                conduct operations on a platform that has producing wells or has other
                hydrocarbon flow?
                 You must take the following safety measures when you conduct
                operations with a rig unit on or jacked-up over a platform with
                producing wells or that has other hydrocarbon flow:
                * * * * *
                 (c) * * *
                 (3) A MODU moves within 500 feet of a platform. You may resume
                production once the MODU is in place, secured, and ready to begin
                operations.
                * * * * *
                0
                28. Revise Sec. 250.724 to read as follows:
                Sec. 250.724 What are the real-time monitoring requirements?
                 (a) When conducting well operations with a subsea BOP or with a
                surface BOP on a floating facility, or when operating in an high
                pressure high temperature (HPHT) environment, you must gather and
                monitor real-time well data using an independent, automatic, and
                continuous monitoring system capable of recording, storing, and
                transmitting data regarding the following:
                 (1) The BOP control system;
                 (2) The well's active fluid circulating system; and
                 (3) The well's downhole conditions with the bottom hole assembly
                tools (if any tools are installed).
                 (b) You must transmit these data as they are gathered, barring
                unforeseeable or unpreventable interruptions in transmission, and have
                the capability to monitor the data, using qualified personnel in
                accordance with a real-time monitoring plan, as provided in paragraph
                (c) of this section.
                 (c) You must develop and implement a real-time monitoring plan.
                Your real-time monitoring plan, and all real-time monitoring data, must
                be made available to BSEE upon request. Your real-time monitoring plan
                must include the following:
                 (1) A description of your real-time monitoring capabilities,
                including the types of the data collected;
                 (2) A description of how your real-time monitoring data will be
                transmitted during operations, how the data will be labeled and
                monitored by qualified personnel, and how the data will be stored as
                required in Sec. Sec. 250.740 and 250.741;
                 (3) A description of your procedures for providing BSEE access,
                upon request, to your real-time monitoring data;
                 (4) The qualifications of the personnel monitoring the data;
                 (5) Your procedures for, and methods of, communication between rig
                personnel and the monitoring personnel; and
                 (6) Actions to be taken if you lose any real-time monitoring
                capabilities or communications between rig personnel and monitoring
                personnel, and a protocol for how you will respond to any significant
                and/or prolonged interruption of monitoring capabilities or
                communications, including your protocol for notifying BSEE of any
                significant and/or prolonged interruptions.
                0
                29. Revise Sec. 250.730 to read as follows:
                Sec. 250.730 What are the general requirements for BOP systems and
                system components?
                 (a) You must ensure that the BOP system and system components are
                designed, installed, maintained, inspected, tested, and used properly
                to ensure well control. The working-pressure rating of each BOP
                component (excluding annular(s)) must exceed MASP as defined for the
                operation. For a subsea BOP, the MASP must be determined at the
                mudline. The BOP system includes the BOP stack, control system, and any
                other associated system(s) and equipment. The BOP system and individual
                components must be able to perform their expected functions and be
                compatible with each other. Your BOP system must be capable of closing
                and sealing the wellbore in the event of flow due to a kick, including
                under anticipated flowing conditions for the specific well conditions,
                without losing ram closure time and sealing integrity due to the
                corrosiveness, volume, and abrasiveness of any fluids in the wellbore
                that the BOP system may encounter. Your BOP system must meet the
                following requirements:
                 (1) The BOP requirements of API Standard 53 (incorporated by
                reference in Sec. 250.198) and the requirements of Sec. Sec. 250.733
                through 250.739. If there is a conflict between API Standard 53 and the
                requirements of this subpart, you must follow the requirements of this
                subpart.
                 (2) The provisions of the following industry standards (all
                incorporated by reference in Sec. 250.198) that apply to BOP systems:
                 (i) ANSI/API Spec. 6A;
                 (ii) ANSI/API Spec. 16A;
                 (iii) ANSI/API Spec. 16C;
                 (iv) API Spec. 16D; and
                 (v) ANSI/API Spec. 17D.
                 (3) For surface and subsea BOPs, the pipe and variable bore rams
                installed in the BOP stack must be capable of effectively closing and
                sealing on the tubular body of any drill pipe, workstring, and tubing
                (excluding tubing with exterior control lines and flat packs) in the
                hole under MASP, as defined for the operation, at the
                [[Page 21978]]
                proposed regulator settings of the BOP control system.
                 (4) The current set of approved schematic drawings must be
                available on the rig and at an onshore location. If you make any
                modifications to the BOP or control system that will require changes to
                your BSEE-approved schematic drawings, you must suspend operations
                until you obtain approval from the District Manager.
                 (b) You must ensure that the design, fabrication, maintenance, and
                repair of your BOP system is in accordance with the requirements
                contained in this part, applicable Original Equipment Manufacturer's
                (OEM) recommendations unless otherwise directed by BSEE, and recognized
                engineering practices. The training and qualification of repair and
                maintenance personnel must meet or exceed applicable OEM training
                recommendations unless otherwise directed by BSEE.
                 (c) You must follow the failure reporting procedures contained in
                API Standard 53, (incorporated by reference in Sec. 250.198), and:
                 (1) You must provide a written notice of equipment failure to the
                Chief, Office of Offshore Regulatory Programs (OORP), unless BSEE has
                designated a third party as provided in paragraph (c)(4) of this
                section, and the manufacturer of such equipment within 30 days after
                the discovery and identification of the failure. A failure is any
                condition that prevents the equipment from meeting the functional
                specification.
                 (2) You must ensure that an investigation and a failure analysis
                are started within 120 days of the failure to determine the cause of
                the failure, and are completed within 120 days upon starting the
                investigation and failure analysis. You must also ensure that the
                results and any corrective action are documented. You must ensure that
                the analysis report is submitted to the Chief OORP, unless BSEE has
                designated a third party as provided in paragraph (c)(4) of this
                section, as well as the manufacturer. If you cannot complete the
                investigation and analysis within the specified time, you must submit
                an extension request detailing how you will complete the investigation
                and analysis to BSEE for approval. You must submit the extension
                request to the Chief, OORP.
                 (3) If the equipment manufacturer notifies you that it has changed
                the design of the equipment that failed or if you have changed
                operating or repair procedures as a result of a failure, then you must,
                within 30 days of such changes, report the design change or modified
                procedures in writing to the Chief OORP, unless BSEE has designated a
                third party as provided in paragraph (c)(4) of this section.
                 (4) Submit notices and reports to the Chief, Office of Offshore
                Regulatory Programs; Bureau of Safety and Environmental Enforcement;
                45600 Woodland Road, Sterling, Virginia 20166. BSEE may designate a
                third party to receive the data and reports on behalf of BSEE. If BSEE
                designates a third party, you must submit the data and reports to the
                designated third party.
                 (d) If you plan to use a BOP stack manufactured after the effective
                date of this regulation, you must use one manufactured pursuant to an
                ANSI/API Spec. Q1 (as incorporated by reference in Sec. 250.198)
                quality management system. Such quality management system must be
                certified by an entity that meets the requirements of ISO/IEC 17021-1
                (as incorporated by reference in Sec. 250.198).
                 (1) BSEE may consider accepting equipment manufactured under
                quality assurance programs other than ANSI/API Spec. Q1, provided you
                submit a request to the Chief, OORP for approval, containing relevant
                information about the alternative program.
                 (2) You must submit this request to the Chief, OORP; Bureau of
                Safety and Environmental Enforcement; 45600 Woodland Road, Sterling,
                Virginia 20166.
                0
                30. Amend Sec. 250.731 by:
                0
                a. Removing paragraphs (d) and (f);
                0
                b. Redesignating paragraph (e) as (d); and
                0
                c. Revising paragraphs (a)(5) and (c) to read as follows:
                Sec. 250.731 What information must I submit for BOP systems and
                system components?
                * * * * *
                ------------------------------------------------------------------------
                 You must submit: Including:
                ------------------------------------------------------------------------
                (a) * * *......................... (5) Control system pressure and
                 regulator settings needed to close
                 each ram BOP under MASP as defined
                 for the operation;
                
                 * * * * * * *
                (c) Certification by an Verification that:
                 independent third party, (1) Test data demonstrate the shear
                 ram(s) will shear the drill pipe at
                 the water depth as required in Sec.
                 250.732;
                 (2) The BOP was designed, tested,
                 and maintained to perform under the
                 maximum environmental and
                 operational conditions anticipated
                 to occur at the well;
                 (3) The accumulator system has
                 sufficient fluid to operate the BOP
                 system without assistance from the
                 charging system; and
                 (4) If using a subsea BOP, a BOP in
                 an HPHT environment as defined in
                 Sec. 250.804(b), or a surface BOP
                 on a floating facility, the BOP has
                 not been compromised or damaged
                 from previous service.
                
                 * * * * * * *
                ------------------------------------------------------------------------
                0
                31. Revise Sec. 250.732 to read as follows:
                Sec. 250.732 What are the independent third party requirements for
                BOP systems and system components?
                 (a) Prior to beginning any operation requiring the use of any BOP,
                you must submit verification by an independent third party and
                supporting documentation as required by this paragraph to the
                appropriate District Manager and Regional Supervisor.
                [[Page 21979]]
                ------------------------------------------------------------------------
                 You must submit verification and
                 documentation related to: That:
                ------------------------------------------------------------------------
                (1) Shear testing,................ (i) Demonstrates that the BOP will
                 shear the tubular body of any drill
                 pipe (excluding tool joints, bottom-
                 hole tools, and bottom hole
                 assemblies such as heavy-weight
                 pipe or collars), workstring,
                 tubing and associated exterior
                 control lines and any electric-,
                 wire-, and slick-line to be used in
                 the well;
                 (ii) Demonstrates the use of test
                 protocols and analysis that
                 represent recognized engineering
                 practices for ensuring the
                 repeatability and reproducibility
                 of the tests, and that the testing
                 was performed by a facility that
                 meets generally accepted quality
                 assurance standards;
                 (iii) Provides a reasonable
                 representation of field
                 applications, taking into
                 consideration the physical and
                 mechanical properties of the
                 tubular body of any drill pipe
                 (excluding tool joints, bottom-hole
                 tools, and bottom hole assemblies
                 such as heavy-weight pipe or
                 collars), workstring, tubing and
                 associated exterior control lines
                 and any electric-, wire-, and slick-
                 line to be used in the well;
                 (iv) Ensures testing was performed
                 on the outermost edges of the
                 shearing blades of the shear ram;
                 (v) Demonstrates the shearing
                 capacity of the BOP equipment to
                 the physical and mechanical
                 properties of the tubular body of
                 any drill pipe (excluding tool
                 joints, bottom-hole tools, and
                 bottom hole assemblies such as
                 heavy-weight pipe or collars),
                 workstring, tubing and associated
                 exterior control lines and any
                 electric-, wire-, and slick-line to
                 be used in the well; and
                 (vi) Includes relevant testing
                 results.
                (2) Pressure integrity testing for (i) Shows that testing is conducted
                 sealing components, and after the shearing is completed and
                 prior to opening the component;
                 (ii) Demonstrates that the equipment
                 will seal at the rated working
                 pressures (RWP) of the BOP for 5
                 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.
                ------------------------------------------------------------------------
                 (b) The independent third-party must be a technical classification
                society, a licensed professional engineering firm, or a registered
                professional engineer capable of providing the required certifications
                and verifications.
                 (c) For wells in an HPHT environment, as defined by Sec.
                250.804(b), you must submit verification by an independent third party
                that it conducted a comprehensive review of the BOP system and related
                equipment you propose to use. You must provide the independent third
                party access to any facility associated with the BOP system or related
                equipment during the review process. You must submit the verifications
                required by this paragraph (c) to the appropriate District Manager and
                Regional Supervisor before you begin any operations in an HPHT
                environment with the proposed equipment.
                ------------------------------------------------------------------------
                 You must submit: Including:
                ------------------------------------------------------------------------
                (1) Verification that the independent
                 third party conducted a detailed
                 review of the design package to ensure
                 that all critical components and
                 systems meet recognized engineering
                 practices,
                (2) Verification that the designs of (i) Identification of all
                 individual components and the overall reasonable potential modes of
                 system have been proven in a testing failure; and
                 process that demonstrates the (ii) Evaluation of the design
                 performance and reliability of the verification tests. The design
                 equipment in a manner that is verification tests must assess
                 repeatable and reproducible, the equipment for the
                 identified potential modes of
                 failure.
                (3) Verification that the BOP equipment
                 will perform as designed in the
                 temperature, pressure, and environment
                 that will be encountered, and
                (4) Verification that the fabrication, For the quality control and
                 manufacture, and assembly of assurance mechanisms, complete
                 individual components and the overall material and quality controls
                 system uses recognized engineering over all contractors,
                 practices and quality control and subcontractors, distributors,
                 assurance mechanisms. and suppliers at every stage
                 in the fabrication,
                 manufacture, and assembly
                 process.
                ------------------------------------------------------------------------
                 (d) You must make all documentation that demonstrates compliance
                with the requirements of this section available to BSEE upon request.
                0
                32. Amend Sec. 250.733 by:
                0
                a. Revising paragraphs (a)(1) and (b)(1); and
                0
                b. Adding paragraph (e) to read as follows:
                Sec. 250.733 What are the requirements for a surface BOP stack?
                 (a) * * *
                 (1) The blind shear rams must be capable of shearing at any point
                along the tubular body of any drill pipe (excluding tool joints,
                bottom-hole tools, and bottom hole assemblies that include heavy-weight
                pipe or collars), workstring, tubing and associated exterior control
                lines, and any electric-, wire-, and slick-line that is in the hole and
                sealing the wellbore after shearing. Prior to April 29, 2021, if your
                blind shear rams are unable to cut any electric-, wire-, or slick-line
                under MASP as defined for the operation and seal the wellbore, you must
                use an alternative cutting device capable of shearing the lines before
                closing the BOP. This device must be available on the rig floor during
                operations that require their use.
                * * * * *
                 (b) * * *
                 (1) On new floating production facilities installed after April 29,
                2021, that include a surface BOP, follow the BOP requirements in Sec.
                250.734(a)(1).
                * * * * *
                 (e) Additional requirements for surface BOP systems used in well-
                completion, workover, and decommissioning operations. The minimum BOP
                system for well-completion, workover, and decommissioning operations
                must meet the appropriate standards from the following table:
                [[Page 21980]]
                ------------------------------------------------------------------------
                 The minimum BOP stack must include .
                 When . . . . .
                ------------------------------------------------------------------------
                (1) The expected pressure is less Three BOPs consisting of an annular,
                 than 5,000 psi, one set of pipe rams, and one set
                 of blind-shear rams.
                (2) The expected pressure is 5,000 Four BOPs consisting of an annular,
                 psi or greater or you use two sets of pipe rams, and one set
                 multiple tubing strings, of blind-shear rams.
                (3) You handle multiple tubing Four BOPs consisting of an annular,
                 strings simultaneously, one set of pipe rams, one set of
                 dual pipe rams, and one set of
                 blind-shear rams.
                (4) You use a tapered drill pipe, At least one set of pipe rams that
                 work string, or tubing, are capable of sealing around each
                 size of drill pipe, work string, or
                 tubing. If the expected pressure is
                 greater than 5,000 psi, then you
                 must have at least two sets of pipe
                 rams that are capable of sealing
                 around the larger size drill pipe,
                 work string, or tubing. You may
                 substitute one set of variable bore
                 rams for two sets of pipe rams.
                (5) You use a surface BOP on a The elements required by Sec.
                 floating facility, 250.733(b)(1) of this part.
                ------------------------------------------------------------------------
                0
                33. Amend Sec. 250.734 by:
                0
                a. Removing paragraph (a)(6)(vi); and
                0
                b. Revising paragraphs (a)(1)(ii), (a)(3), (a)(4), (a)(6)(iv),
                (a)(6)(v), (a)(16), and (b) to read as follows:
                Sec. 250.734 What are the requirements for a subsea BOP system?
                 (a) * * *
                ------------------------------------------------------------------------
                 When operating with a subsea
                 BOP system, you must: Additional requirements
                ------------------------------------------------------------------------
                (1) * * *.................... (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 collars), workstring, tubing and
                 associated exterior control lines,
                 appropriate area for the liner or casing
                 landing string, shear sub on subsea test
                 tree, and any electric-, wire-, slick-
                 line in the hole; under MASP. At least
                 one shear ram must be capable of sealing
                 the wellbore after shearing under MASP
                 conditions as defined for the operation.
                 Any non-sealing shear ram(s) must be
                 installed below a sealing shear ram(s).
                
                 * * * * * * *
                (3) Have the accumulator The accumulator capacity must:
                 capacity, to provide fast (i) Close each required shear ram, ram
                 closure of the BOP locks, one pipe ram, and disconnect the
                 components and to operate LMRP.
                 all critical functions; (ii) Have the capability to perform ROV
                 functions within the required times
                 outlined in API Standard 53 with ROV or
                 flying leads.
                 (iii) Have bottles located subsea for the
                 autoshear and deadman (which may be
                 shared between those two systems) to
                 secure the wellbore. These bottles may
                 also be utilized to perform the
                 secondary control system functions
                 (e.g., ROV or acoustic functions).
                 (iv) Perform under MASP conditions as
                 defined for the operation.
                (4) * * *.................... You must have the ROV intervention
                 capability to close each shear ram, ram
                 locks, one pipe ram, and disconnect the
                 LMRP under MASP conditions as defined
                 for the operation. You must be capable
                 of performing these functions in the
                 response times outlined in API Standard
                 53 (as incorporated by reference in Sec.
                 250.198). The ROV panels on the BOP
                 and LMRP must be compliant with API RP
                 17H (as incorporated by reference in
                 Sec. 250.198).
                
                 * * * * * * *
                (6) * * *.................... (iv) Autoshear/deadman functions and an
                 EDS mode must close, at a minimum, two
                 shear rams in sequence and be capable of
                 performing their expected shearing and
                 sealing action under MASP conditions as
                 defined for the operation.
                 (v) Your sequencing must allow a
                 sufficient delay when closing your two
                 shear rams in order to provide maximum
                 sealing efficiency.
                
                 * * * * * * *
                (16) Use a BOP system that (i) No later than May 1, 2023, you must
                 has the following mechanisms have the capability to position the
                 and capabilities; entire pipe completely within the area
                 of the shearing blade. This capability
                 cannot be a separate ram BOP or annular
                 preventer, but you may use those during
                 a planned shear.
                 (ii) If your control pods contain a
                 subsea electronic module with batteries,
                 a mechanism for personnel on the rig to
                 monitor the state of charge of the
                 subsea electronic module batteries in
                 the BOP control pods.
                ------------------------------------------------------------------------
                 (b) If you suspend operations to make repairs to any part of the
                subsea BOP system, you must stop operations at a safe downhole
                location. Before resuming operations you must:
                 (1) Submit a revised permit with a written statement from an
                independent third party documenting the repairs and certifying that the
                previous certification in Sec. 250.731(c) remains valid;
                 (2) Upon relatch of the BOP, perform an initial subsea BOP test in
                accordance with Sec. 250.737(d)(4), including deadman in accordance
                with Sec. 250.737(d)(12)(vi). If repairs take longer than 30 days,
                once the BOP is on deck, you must test in accordance with the
                requirements of Sec. 250.737;
                 (3) Upon relatch of the LMRP, you must test according to the
                following:
                 (i) Pressure test riser connector/gasket in accordance with Sec.
                250.737(b) and (c);
                 (ii) Pressure test choke and kill stabs at LMRP/BOP interface in
                accordance with Sec. 250.737(b) and (c);
                 (iii) Full function test of both pods and both control panels;
                 (iv) Verify acoustic pod communication (if equipped); and
                 (v) Deadman test with pressure test in accordance with Sec.
                250.737(d)(12)(vi).
                [[Page 21981]]
                 (4) Receive approval from the District Manager.
                * * * * *
                0
                34. Amend Sec. 250.735 by revising paragraph (a) to read as follows:
                Sec. 250.735 What associated systems and related equipment must all
                BOP systems include?
                * * * * *
                 (a) An accumulator system (as specified in API Standard 53,
                incorporated by reference in Sec. 250.198). Your accumulator system
                must have the fluid volume capacity and appropriate pre-charge
                pressures in accordance with API Standard 53. If you supply the
                accumulator regulators by rig air and do not have a secondary source of
                pneumatic supply, you must equip the regulators with manual overrides
                or other devices to ensure capability of hydraulic operations if rig
                air is lost;
                * * * * *
                0
                35. Amend Sec. 250.736 by revising paragraph (d)(5) to read as
                follows:
                Sec. 250.736 What are the requirements for choke manifolds, kelly-
                type valves inside BOPs, and drill string safety valves?
                * * * * *
                 (d) * * *
                 (5) When running casing, a safety valve in the open position
                available on the rig floor to fit the casing string being run in the
                hole. For subsea BOPs, the safety valve must be available on the rig
                floor if the length of casing being run exceeds the water depth, which
                would result in the casing being across the BOP stack and the rig floor
                prior to crossing over to the drill pipe running string;
                * * * * *
                0
                36. Amend Sec. 250.737 by:
                0
                a. Redesignating paragraph (a)(4) as (a)(5),
                0
                b. Adding new paragraph (a)(4),
                0
                c. Revising paragraphs (b) introductory text, (b)(2), (b)(3), (c),
                (d)(2)(ii), (d)(3)(iii), (d)(3)(iv), (d)(3)(v), (d)(4)(i), (d)(4)(iii),
                (d)(4)(v);
                0
                d. Removing paragraph (d)(4)(vi),
                0
                e. Revising paragraphs (d)(5), (d)(10), (d)(12)(iv), and (d)(12)(vi);
                and
                0
                f. Adding paragraph (d)(13).
                 The additions and revisions read as follows:
                Sec. 250.737 What are the BOP system testing requirements?
                * * * * *
                 (a) * * *
                 (4) In lieu of meeting the schedule established in paragraph (a)(2)
                of this section, you may request that BSEE approve a 21-day BOP testing
                frequency. To obtain BSEE approval, you must submit a request to the
                appropriate BSEE Regional Supervisor, District Field Operations. Your
                request must demonstrate that you have developed a BOP health
                monitoring plan that includes certain system capabilities. As long as
                your plan is consistent with recognized engineering and industry
                practice, BSEE will approve your request if it includes the following:
                 (i) Condition monitoring tools, including continuous surveillance
                of sensor readings from the BOP control system, real-time condition
                analysis and displays, functional pressure signal analysis, historical
                sensor data;
                 (ii) Failure propagation analysis;
                 (iii) A failure tracking and resolution system that includes
                detailed failure reports and identification of recurring problems; and
                 (iv) Submission of quarterly reports of the data collected pursuant
                to paragraphs (a)(4)(i)(iii) to the BSEE Regional Supervisor, District
                Field Operations.
                * * * * *
                 (b) Pressure test procedures. When you pressure test the BOP
                system, you must conduct a low-pressure test and a high-pressure test
                for each BOP component (excluding test rams and non-sealing shear
                rams). You must begin each test by conducting the low-pressure test
                then transition to the high-pressure test. Each individual pressure
                test must hold pressure long enough to demonstrate the tested
                component(s) holds the required pressure. The table in this paragraph
                (b) outlines your pressure test requirements.
                ------------------------------------------------------------------------
                 According to the following
                 You must conduct a . . . procedures . . .
                ------------------------------------------------------------------------
                
                 * * * * * * *
                (2) High-pressure test for blind shear (i) The high-pressure test must
                 ram-type BOPs, ram-type BOPs, the equal the RWP of the equipment
                 choke manifold, outside of all choke or be 500 psi greater than
                 and kill side outlet valves (and your calculated MASP, as
                 annular gas bleed valves for subsea defined for the operation for
                 BOP), inside of all choke and kill the applicable section of
                 side outlet valves below uppermost hole. Before you may test BOP
                 ram, and other BOP components. equipment to the MASP plus 500
                 psi, the District Manager must
                 have approved those test
                 pressures in your permit.
                 (ii) The blind shear ram (BSR)
                 must be tested to:
                 (A) MASP plus 500 psi for
                 the hole section to which
                 it is exposed; or
                 (B) Full well MASP plus 500
                 psi on initial latch up and
                 all subsequent BSR pressure
                 tests can be done to the
                 casing/liner test pressure
                 for the applicable hole
                 section.
                 (iii) The choke and kill side
                 outlet valves must be tested
                 to, except as provided in
                 paragraph (d)(13) of this
                 section:
                 (A) MASP plus 500 psi for
                 the hole section to which
                 it is exposed; or
                 (B) Full well MASP plus 500
                 psi on initial latch up and
                 all subsequent pressure
                 tests can be done to the
                 casing/liner test pressure
                 for the applicable hole
                 section.
                (3) High-pressure test for annular-type The high pressure test must
                 BOPs, inside of choke or kill valves equal 70 percent of the RWP of
                 (and annular gas bleed valves for the equipment or be 500 psi
                 subsea BOP) above the uppermost ram greater than your calculated
                 BOP. MASP, as defined for the
                 operation for the applicable
                 section of hole. Before you
                 may test BOP equipment to the
                 MASP plus 500 psi, the
                 District Manager must have
                 approved those test pressures
                 in your APD or APM.
                
                 * * * * * * *
                ------------------------------------------------------------------------
                [[Page 21982]]
                 (c) Duration of pressure test. Each test must hold the required
                pressure for 5 minutes, which must be recorded on a chart not exceeding
                4 hours, or on a digital recorder. However, for surface BOP systems and
                surface equipment of a subsea BOP system, a 3-minute test duration is
                acceptable if recorded on a chart not exceeding 4 hours, or on a
                digital recorder. The recorded test pressures must be within the middle
                half of the chart range, i.e., cannot be within the lower or upper one-
                fourth of the chart range. If the equipment does not hold the required
                pressure during a test, you must correct the problem and retest the
                affected component(s).
                * * * * *
                 (d) * * *
                ------------------------------------------------------------------------
                 You must . . . Additional requirements . . .
                ------------------------------------------------------------------------
                
                 * * * * * * *
                (2) * * *.............................. (ii) Contact the District
                 Manager at least 72 hours
                 prior to beginning the initial
                 test to allow BSEE
                 representative(s) to witness
                 testing.
                (3) * * *.............................. (iii) Contact the District
                 Manager at least 72 hours
                 prior to beginning the stump
                 test to allow BSEE
                 representative(s) to witness
                 testing.
                 (iv) You must 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.
                 Pressure testing of each ram
                 and annular component is only
                 required once.
                (4) * * *.............................. (i) You must begin the initial
                 subsea BOP test on the
                 seafloor within 30 days of the
                 stump test.
                
                 * * * * * * *
                 (iii) You must pressure test
                 well-control rams and annulars
                 according to paragraphs (b)
                 and (c) of this section.
                
                 * * * * * * *
                 (v) You must test and verify
                 closure of at least one set of
                 rams during the initial subsea
                 test through a ROV hot stab.
                 You must confirm closure of
                 the selected ram through the
                 ROV hot stab with a 1,000 psi
                 pressure test for 5 minutes.
                (5) Alternate tests between control (i) For two complete BOP
                 stations. control stations you must:
                 (A) Designate a primary and
                 secondary station;
                 (B) Alternate testing between
                 the primary and secondary
                 control stations on a weekly
                 basis; and
                 (C) For a subsea BOP, develop
                 an alternating testing
                 schedule to ensure the primary
                 and secondary control stations
                 will function each pod.
                 (ii) Remote panels where all
                 BOP functions are not included
                 (e.g., life boat panels) must
                 be function-tested upon the
                 initial BOP tests.
                
                 * * * * * * *
                (10) * * *............................. If BSEE approves your request
                 to utilize a 21-day BOP test
                 frequency pursuant to Sec.
                 250.737(a)(4), you may
                 function test shear ram(s)
                 BOPs every 21 days in
                 accordance with the terms of
                 that approval.
                
                 * * * * * * *
                (12) * * *............................. (iv) Following the deadman
                 system test on the seafloor
                 you must document the final
                 remaining pressure of the
                 subsea accumulator system.
                
                 * * * * * * *
                 (vi) You must confirm closure
                 of the BSR(s) with a 1,000 psi
                 pressure test for 5 minutes.
                
                 * * * * * * *
                (13) Pressure test the choke and kill According to paragraph (b) of
                 side outlet valves. this section, except as
                 follows:
                 (i) Test the wellbore side of
                 the choke and kill side outlet
                 valves above the uppermost
                 pipe ram to the approved
                 annular test pressure. Choke
                 and kill side outlet valves
                 below the uppermost pipe ram
                 must be tested to MASP plus
                 500 psi for the applicable
                 hole section.
                 (ii) For the 30 day BSR
                 testing, test the wellbore
                 side of the choke and kill
                 side outlet valves between the
                 upper most pipe ram and the
                 upper most ram, to the casing/
                 liner test pressure or annular
                 test pressure, whichever is
                 greater.
                 (iii) For BOPs with only one
                 choke and kill side outlet
                 valve, you are only required
                 to pressure test the choke and
                 kill side outlet valves from
                 the wellbore side.
                ------------------------------------------------------------------------
                [[Page 21983]]
                * * * * *
                0
                37. Amend Sec. 250.738 by revising paragraphs (b) introductory text,
                (b)(3), (b)(4), (f), (i), (m), and (o) to read as follows:
                Sec. 250.738 What must I do in certain situations involving BOP
                equipment or systems?
                * * * * *
                ------------------------------------------------------------------------
                 If you encounter the following
                 situation: Then you must . . .
                ------------------------------------------------------------------------
                (b) Need to repair, replace, or
                 reconfigure a surface BOP or subsea
                 BOP system;
                
                 * * * * * * *
                 (3) Submit a revised permit
                 with a written statement from
                 an independent third party
                 documenting the repairs,
                 replacement, or
                 reconfiguration and certifying
                 that the previous
                 certification under Sec.
                 250.731(c) remains valid.
                 (4) You must receive approval
                 from the District Manager
                 prior to resuming operations.
                
                 * * * * * * *
                (f) Plan to install casing rams or Before running casing, perform
                 casing shear rams in a surface BOP a shell test to the permit
                 stack; approved test pressure of the
                 BOP component above the casing
                 ram/casing shear. If this
                 installation was not included
                 in your approved permit, and
                 changes the BOP configuration
                 approved in the APD or APM,
                 you must notify and receive
                 approval from the District
                 Manager.
                
                 * * * * * * *
                (i) You activate any shear ram and pipe Retrieve, physically inspect,
                 or casing is sheared;. and conduct a full pressure
                 test of the BOP stack after
                 the situation is fully
                 controlled. You must submit to
                 the District Manager a report
                 from an independent third
                 party certifying that the BOP
                 is fit to return to service.
                
                 * * * * * * *
                (m) Plan to utilize any other Contact the District Manager
                 circulating or ancillary equipment and request approval in your
                 (e.g., but not limited to, subsea APD or APM. Your request must
                 isolation device, subsea accumulator include a report from an
                 module, or gas handler) that is in independent third party on the
                 addition to the equipment required in equipment's design and
                 this subpart; suitability for its intended
                 use as well as any other
                 information required by the
                 District Manager. The District
                 Manager may impose any
                 conditions regarding the
                 equipment's capabilities,
                 operation, and testing.
                
                 * * * * * * *
                (o) You install redundant components Comply with all testing,
                 for well control in your BOP system maintenance, and inspection
                 that are in addition to the required requirements in this subpart
                 components of this subpart (e.g., pipe/ that are applicable to those
                 variable bore rams, shear rams, well-control components. If
                 annular preventers, gas bleed lines, any redundant component fails
                 and choke/kill side outlets or lines); a test, you must submit a
                 report from an independent
                 third party that describes the
                 failure and confirms that
                 there is no impact on the BOP
                 that will make it unfit for
                 well-control purposes. You
                 must submit this report to the
                 District Manager and receive
                 approval before resuming
                 operations. The District
                 Manager may require you to
                 provide additional information
                 as needed to clarify or
                 evaluate your report.
                
                 * * * * * * *
                ------------------------------------------------------------------------
                0
                38. Amend Sec. 250.739 by revising paragraph (b) introductory text to
                read as follows:
                Sec. 250.739 What are the BOP maintenance and inspection
                requirements?
                * * * * *
                 (b) A major, detailed inspection of the well control system
                components (including but not limited to riser, BOP, LMRP, and control
                pods) must be performed every 5 years. This major inspection may be
                performed in phased intervals. You must track and document all system
                and component inspection dates. These records must be available on the
                rig. An independent third party is required to review the inspection
                results and must compile a detailed report of the inspection results,
                including descriptions of any problems and how they were corrected. You
                must make these reports available to BSEE upon request. This major
                inspection must be performed every 5 years from the following
                applicable dates, whichever is later:
                * * * * *
                0
                39. Add an undesignated center and Sec. 250.750 to read as follows:
                Coiled Tubing Operations
                Sec. 250.750 What are the coiled tubing requirements?
                 (a) For coiled tubing operations, you must follow the applicable
                requirements of this subpart and you must meet the following minimum
                requirements for the BOP system:
                 (1) BOP system components must be in the following order from the
                top down:
                [[Page 21984]]
                ------------------------------------------------------------------------
                 BOP system when
                 BOP system when expected expected surface BOP system for wells
                 surface pressures are less pressures are with returns taken
                 than or equal to 3,500 psi greater than through an outlet on
                 3,500 psi the BOP stack
                ------------------------------------------------------------------------
                (i) Stripper or annular-type Stripper or Stripper or annular-
                 well control component. annular-type type well control
                 well control component.
                 component.
                (ii) Hydraulically-operated Hydraulically- Hydraulically-
                 blind rams. operated blind operated blind rams.
                 rams.
                (iii) Hydraulically-operated Hydraulically- Hydraulically-
                 shear rams. operated shear operated shear rams.
                 rams.
                (iv) Kill line inlet.......... Kill line inlet.. Kill line inlet.
                (v) Hydraulically-operated two- Hydraulically- Hydraulically-
                 way slip rams. operated two-way operated two-way
                 slip rams. slip rams.
                 Hydraulically-
                 operated pipe rams.
                (vi) Hydraulically-operated Hydraulically- A flow tee or cross.
                 pipe rams. operated pipe Hydraulically-
                 rams. operated pipe rams.
                 Hydraulically- Hydraulically-
                 operated blind- operated blind-shear
                 shear rams. rams on wells with
                 These rams surface pressures
                 should be >3,500 psi. As an
                 located as close option, the pipe
                 to the tree as rams can be placed
                 practical. below the blind-
                 shear rams. The
                 blind-shear rams
                 should be located as
                 close to the tree as
                 practical.
                ------------------------------------------------------------------------
                 (2) You may use a set of hydraulically-operated combination rams
                for the blind rams and shear rams.
                 (3) You may use a set of hydraulically-operated combination rams
                for the hydraulic two-way slip rams and the hydraulically-operated pipe
                rams.
                 (4) You must attach a dual check valve assembly to the coiled
                tubing connector at the downhole end of the coiled tubing string for
                all coiled tubing operations. If you plan to conduct operations without
                downhole check valves, you must describe alternate procedures and
                equipment in Form BSEE-0124, Application for Permit to Modify and have
                it approved by the District Manager.
                 (5) You must have a kill line and a separate choke line. You must
                equip each line with two full-opening valves and at least one of the
                valves must be remotely controlled. You may use a manual valve instead
                of the remotely controlled valve on the kill line if you install a
                check valve between the two full-opening manual valves and the pump or
                manifold. The valves must have a working pressure rating equal to or
                greater than the working pressure rating of the connection to which
                they are attached, and you must install them between the well control
                stack and the choke or kill line. For operations with expected surface
                pressures greater than 3,500 psi, the kill line must be connected to a
                pump or manifold. You must not use the kill line inlet on the BOP stack
                for taking fluid returns from the wellbore.
                 (6) You must have a hydraulic-actuating system that provides
                sufficient accumulator capacity to close-open-close each component in
                the BOP stack. This cycle must be completed with at least 200 psi above
                the pre-charge pressure, without assistance from a charging system.
                 (7) All connections used in the surface BOP system from the tree to
                the uppermost required ram must be flanged, including the connections
                between the well control stack and the first full-opening valve on the
                choke line and the kill line.
                 (b) BSEE considers all coiled tubing operations to be non-routine.
                0
                40. Add Sec. 250.751 to read as follows:
                Sec. 250.751 Coiled tubing testing requirements.
                 You must test the coiled tubing unit in accordance with Sec.
                250.737(a), (b), (c), (d)(9), and (d)(10). You must successfully
                pressure test the dual check valves to the rated working pressure of
                the connector, the rated working pressure of the dual check valve,
                expected surface pressure, or the collapse pressure of the coiled
                tubing, whichever is less. The test interval for coiled tubing
                operations must include a 10 minute high-pressure test for the coiled
                tubing string.
                0
                41. Add an undesignated center heading and Sec. 250.760 to read as
                follows:
                Snubbing Operations
                Sec. 250.760 What are the snubbing requirements?
                 (a) For snubbing operations, you must follow the applicable
                requirements of this subpart and have the following minimum BOP-system
                components:
                 (1) One set of pipe rams hydraulically operated,
                 (2) Two sets of stripper-type pipe rams hydraulically operated with
                spacer spool,
                 (3) An inside BOP or a spring-loaded, back-pressure safety valve in
                the open position located on the rig floor, and
                 (4) An essentially full-opening, work-string safety valve in the
                open position must be maintained on the rig floor at all times and a
                wrench to fit the work-string safety valve must be readily available.
                 (5) Proper connections must be readily available for inserting
                valves in the work string.
                 (b) Test the snubbing unit in accordance with Sec. 250.737(a),
                (b), and (c).
                Subpart Q--Decommissioning Activities
                0
                42. Amend Sec. 250.1703 by revising paragraph (b) to read as follows:
                Sec. 250.1703 What are the general requirements for decommissioning?
                * * * * *
                 (b) Permanently plug all wells. Packers and bridge plugs used as
                qualified mechanical barriers must comply with ANSI/API Spec. 11D1 (as
                incorporated by reference in Sec. 250.198). You must have two
                independent barriers, one being an ANSI/API Spec. 11D1 qualified
                mechanical barrier, in the exposed center wellbore prior to removing
                the tree and/or well control equipment;
                * * * * *
                0
                43. Amend Sec. 250.1704 by adding paragraph (g)(4) and revising
                paragraph (h)(2) to read as follows:
                Sec. 250.1704 What decommissioning applications and reports must I
                submit and when must I submit them?
                * * * * *
                [[Page 21985]]
                ------------------------------------------------------------------------
                 Decommissioning applications
                 and reports When to submit Instructions
                ------------------------------------------------------------------------
                
                 * * * * * * *
                (g) * * *....................... (4) Within 30 days Include
                 after you information
                 complete site required under
                 clearance Sec.
                 verification 250.1743(a).
                 activities,
                (h) * * *....................... (2) Within 30 days Include
                 after completion information
                 of required under
                 decommissioning Sec. Sec.
                 activity, 250.1712 and
                 250.1721.
                
                 * * * * * * *
                ------------------------------------------------------------------------
                Sec. 250.1706 [Reserved]
                0
                44. Remove and reserve Sec. 250.1706:
                Sec. 250.1713 [Reserved]
                0
                45. Remove and reserve Sec. 250.1713:
                0
                46. Amend Sec. 250.1716 by revising paragraph (b)(3) to read as
                follows:
                Sec. 250.1716 To what depth must I remove wellheads and casings?
                * * * * *
                 (b) * * *
                 (3) The water depth is greater than 1,000 feet.
                0
                47. Amend Sec. 250.1722 by revising paragraph (d) introductory text to
                read as follows:
                Sec. 250.1722 If I install a subsea protective device, what
                requirements must I meet?
                * * * * *
                 (d) Within 30 days after you complete the trawling test described
                in paragraph (c) of this section, submit a report to the appropriate
                District Manager using form BSEE-0125, End of Operations Report (EOR)
                that includes the following:
                * * * * *
                [FR Doc. 2019-09362 Filed 5-14-19; 8:45 am]
                 BILLING CODE 4310-VH-P
                

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