61703 Federal Register / Vol. 82, No. 249 / Friday, December 29, 2017 / Proposed Rules 
553, as any further delays in the process 
for issuance of temporary scheduling orders would be contrary to the public interest in view of the urgent need to control fentanyl-related substances to avoid an imminent hazard to the public safety. 
Since this notice of intent is not a 
‘‘rule’’ as defined by 5 U.S.C. 601(2), it is not subject to the requirements of the Regulatory Flexibility Act (RFA). The requirements for the preparation of an initial regulatory flexibility analysis in 5 U.S.C. 603(a) are not applicable where, as here, the DEA is not required by section 553 of the APA or any other law to publish a general notice of proposed rulemaking. 
Additionally, this action is not a 
significant regulatory action as defined by Executive Order 12866 (Regulatory Planning and Review), section 3(f), and, accordingly, this action has not been reviewed by the Office of Management and Budget. 
This action will not have substantial 
direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government. Therefore, in accordance with Executive Order 13132 (Federalism) it is determined that this action does not have sufficient federalism implications to warrant the preparation of a Federalism Assessment. 
List of Subjects in 21 CFR Part 1308 
Administrative practice and 
procedure, Drug traffic control, 
Reporting and recordkeeping requirements. 
For the reasons set out above, the DEA 
proposes to amend 21 CFR part 1308 as follows: 
PART 1308—SCHEDULES OF 
CONTROLLED SUBSTANCES 
■1. The authority citation for part 1308 
continues to read as follows: 
Authority: 21 U.S.C. 811, 812, 871(b), 
956(b), unless otherwise noted. 
■2. In § 1308.11, add paragraph (h)(30), 
to read as follows: 
§ 1308.11 Schedule I 
* * * * * 
(h) * * * 
(30) Fentanyl-related substances, their 
isomers, esters, ethers, salts and salts of 
isomers, esters and ethers . . . 9850 
(i) Fentanyl-related substance means 
any substance not otherwise listed under another Administration Controlled Substance Code Number, and for which no exemption or approval is in effect under section 505 of the Federal Food, Drug, and Cosmetic Act [21 U.S.C. 355], that is structurally related to fentanyl by one or more of the following modifications: 
(A) Replacement of the phenyl 
portion of the phenethyl group by any monocycle, whether or not further substituted in or on the monocycle; 
(B) Substitution in or on the 
phenethyl group with alkyl, alkenyl, alkoxyl, hydroxyl, halo, haloalkyl, amino or nitro groups; 
(C) Substitution in or on the 
piperidine ring with alkyl, alkenyl, alkoxyl, ester, ether, hydroxyl, halo, haloalkyl, amino or nitro groups; 
(D) Replacement of the aniline ring 
with any aromatic monocycle whether or not further substituted in or on the aromatic monocycle; and/or 
(E) Replacement of the N-propionyl 
group by another acyl group. 
(ii) This definition includes, but is not 
limited to, the following substances: 
[Reserved] 
* * * * * 
Dated: December 21, 2017. 
Robert W. Patterson, 
Acting Administrator. 
[FR Doc. 2017–28114 Filed 12–28–17; 8:45 am] 
BILLING CODE 4410–09–P 
DEPARTMENT OF THE INTERIOR 
Bureau of Safety and Environmental 
Enforcement 
30 CFR Part 250 
[Docket ID: BSEE–2017–0008; 189E1700D2 
ET1SF0000.PSB000 EEEE500000] 
RIN 1014–AA37 
Oil and Gas and Sulphur Operations 
on the Outer Continental Shelf—Oil and Gas Production Safety Systems— Revisions 
AGENCY : Bureau of Safety and 
Environmental Enforcement, Interior. 
ACTION : Proposed rule. 
SUMMARY : The Bureau of Safety and 
Environmental Enforcement (BSEE) proposes to amend the regulations regarding oil and natural gas production to reduce certain unnecessary regulatory burdens imposed under the existing regulations, while correcting errors and clarifying current requirements. Accordingly, after thoroughly reexamining the current regulations, and based on experiences from the implementation process, and BSEE policy, BSEE proposes to amend, revise, or remove current regulatory provisions that create unnecessary burdens on stakeholders while maintaining or advancing the level of safety and environmental protection. 
DATES : Submit comments by January 29, 
2018. BSEE may not fully consider comments received after this date. You may submit comments to the Office of Management and Budget (OMB) on the information collection burden in this proposed rule by January 29, 2018. The deadline for comments on the information collection burden does not affect the deadline for the public to comment to BSEE on the proposed regulations. 
ADDRESSES : You may submit comments 
on the rulemaking by any of the following methods. Please use the Regulation Identifier Number (RIN) 1014–AA37 as an identifier in your message. See also Public Availability of Comments under Procedural Matters. 
•Federal eRulemaking Portal: http:// 
www.regulations.gov. In the entry titled 
Enter Keyword or ID, enter BSEE–2017– 0008, then click search. Follow the instructions to submit public comments and view supporting and related materials available for this rulemaking. The BSEE may post all submitted comments. 
•Mail or hand-carry comments to the 
Department of the Interior (Department or DOI); Bureau of Safety and Environmental Enforcement; Attention: Regulations Development Branch; 45600 Woodland Road, VAE–ORP, Sterling VA 20166. Please reference ‘‘Oil and Gas Production Safety Systems—Revisions, 1014–AA37’’ in your comments and include your name and return address. 
•Send comments on the information 
collection in this proposed rule to: Interior Desk Officer 1014–0003, Office of Management and Budget; 202–395– 5806 (fax); email: oira_ submission@
omb.eop.gov. Please send a copy to 
BSEE. 
•Public Availability of Comments— 
Before including your address, phone number, email address, or other personal identifying information in your comment, you should be aware that your entire comment—including your personal identifying information—may be made publicly available at any time. In order for BSEE to withhold from disclosure your personal identifying information, you must identify any information contained in the submittal of your comments that, if released, would constitute a clearly unwarranted invasion of your personal privacy. You must also briefly describe any possible harmful consequence(s) of the disclosure of information, such as embarrassment, injury, or other harm. While you can ask us in your comment 
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to withhold your personal identifying 
information from public review, we cannot guarantee that we will be able to do so. 
FOR FURTHER INFORMATION CONTACT : 
Amy White, Regulations and Standards Branch, 703–787–1665 or by email: regs@bsee.gov. 
Table of Contents 
A. BSEE Statutory and Regulatory Authority 
and Responsibilities 
B. Summary of the Rulemaking 
C. Recent Executive and Secretarial Orders D. Incorporation by Reference of Industry 
Standards 
E. Section-by-Section Discussion of Changes 
Procedural Matters 
Regulatory Planning and Review (E.O. 12866, 
E.O. 13563, E.O. 13771) 
Small Business Regulatory Enforcement 
Fairness Act and Regulatory Flexibility Act 
Unfunded Mandates Reform Act of 1995 Takings Implication Assessment (E.O. 12630) Federalism (E.O. 13132) Civil Justice Reform (E.O. 12988) Consultation With Indian Tribes (E.O. 13175) Paperwork Reduction Act (PRA) of 1995 National Environmental Policy Act of 1969 Data Quality Act Effects on the Nation’s Energy Supply (E.O. 
13211) 
Clarity of This Regulation (E.O. 12866) 
SUPPLEMENTARY INFORMATION : 
A. BSEE Statutory and Regulatory 
Authority and Responsibilities 
BSEE derives its authority primarily 
from the Outer Continental Shelf Lands Act (OCSLA), 43 U.S.C. 1331–1356a. Congress enacted OCSLA in 1953, authorizing the Secretary of the Interior (Secretary) to lease the Outer Continental Shelf (OCS) for mineral development and to regulate oil and gas exploration, development, and production operations on the OCS. In 1978, Congress amended OCSLA to create environmental safeguards, promote greater cooperation between the Federal government and States and localities, and to ensure safe working conditions for those employed on the OCS. The Secretary has delegated authority to perform certain of these functions to BSEE. 
To carry out its responsibilities, BSEE 
regulates offshore oil and gas operations to enhance the safety of offshore exploration and development of oil and gas on the OCS and to ensure that those operations protect the environment and implement advancements in technology. BSEE also conducts onsite inspections to assure compliance with regulations, lease terms, and approved plans. Detailed information concerning BSEE’s regulations and guidance to the offshore oil and gas industry may be found on BSEE’s website at: http://www.bsee.gov/ Regulations-and-Guidance/index. 
BSEE’s regulatory program covers a 
wide range of facilities and activities, including drilling, completion, workover, production, pipeline, and decommissioning operations. 
B. Summary of the Rulemaking 
This proposed rule would amend and 
update the 30 CFR part 250, subpart H, 
Oil and Gas Production Safety Systems regulations. This proposed rule would fortify the Administration’s objective of facilitating energy dominance though encouraging increased domestic oil and gas production, by reducing unnecessary burdens on stakeholders while maintaining or advancing the level of safety and environmental protection. Since 2010, the Department has promulgated several rulemakings (e.g., Safety and Environmental 
Management Systems (SEMS) I and II final rules, the final safety measures rule, the annular casing pressure management final rule, and the blowout preventer systems and well control final rule) to improve worker safety and environmental protection. On September 7, 2016, the Department published a final rule substantially revising Subpart H—Oil and Gas Production Safety Systems (81 FR 61834). That final rule addressed issues such as production safety systems, subsurface safety devices, and safety device testing. These systems play a critical role in protecting workers and the environment. Most of the provisions of that rulemaking took effect on November 7, 2016. Since that time, BSEE has become aware that certain provisions in that rulemaking created potentially unduly burdensome requirements to oil and natural gas production operators on the OCS, without significantly increasing safety of the workers or protection of the environment. While implementing the requirements from the previous rulemaking, BSEE reassessed a number of the provisions in the original rulemaking and determined that some provisions could be revised to reduce or eliminate some of the concerns expressed by the operators, reducing the burden, while providing the same level of safety and protection of the environment. 
This proposed rulemaking would 
primarily revise sections of 30 CFR part 250, subpart H—Oil and Gas Production Safety Systems that address the following requirements in the current Subpart H regulations: 
•Update the incorporated edition of 
standards referenced in subpart H. •Add gas lift shut down valves 
(GLSDVs) to the list of safety and 
pollution prevention equipment (SPPE). 
•Revise requirements for SPPE to 
clarify the existing regulations, and remove the requirement for operators to 
certify through an independent third party that each device is designed to function in the most extreme conditions to which it will be exposed and that the device will function as designed. Compliance with the various required standards (including American Petroleum Institute (API) Spec Q1, American National Standards Institute (ANSI)/API Spec. 14A, ANSI/API RP 14B, ANSI/API Spec. 6A, and API Spec. 6AV1) ensures that each device will function in the conditions for which it was designed. 
•Clarify failure reporting 
requirements. 
•Clarify and revise some of the 
production safety system design requirements, including revising the requirements for piping schematics, simplifying the requirements for electrical system information, clarifying when operators must provide certain documents to BSEE, and clarifying when operators must update existing documents. 
•Clarify requirements for Class 1 
vessels. 
•Clarify requirements for inspection 
of the fire tube for tube-type heaters. 
•Clarify the requirement for 
notifying the District Manager before commencing production. 
•Make other conforming changes to 
ensure consistency within the regulations and minor edits. 
C. Recent Executive and Secretarial 
Orders 
Since the start of 2017, the President 
issued several Executive Orders (E.O.) that necessitated the review of BSEE’s rules. On January 30, 2017, the President issued E.O. 13771, entitled, ‘‘Reducing Regulation and Controlling Regulatory Costs,’’ which requires Federal agencies to take proactive measures to reduce the costs associated with complying with Federal regulations. On March 28, 2017, the President issued E.O. 13783, ‘‘Promoting Energy Independence and Economic Growth,’’ (82 FR 16093). This E.O. directed Federal agencies to review all existing regulations and other agency actions and, ultimately, to suspend, revise, or rescind any such regulations or actions that unnecessarily burden the development of domestic energy resources beyond the degree necessary to protect the public interest or otherwise comply with the law. E.O. 13783 also required a review of all 
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1Oil and Gas and Sulfur Operations in the Outer 
Continental Shelf—Blowout Preventer Systems and 
Well Control, 81 FR 25887 (April 29, 2016). 2To 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’’) for the standard(s) you wish to review. ‘‘existing rules, regulations, orders, 
guidance documents, policies, and any other similar agency actions,’’ that may burden energy development. The E.O. directed agencies to ‘‘suspend, revise, or rescind, or publish for notice and comment proposed rules suspending, revising, or rescinding, those actions’’ that unduly burden oil and gas development beyond what is needed to protect the public interest or comply with the law. 
On April 28, 2017, the President 
issued E.O. 13795, ‘‘Implementing an America-First Offshore Energy Strategy,’’ (82 FR 20815). The E.O. directed the Secretary to reconsider the Well Control Rule
1and to take 
appropriate action to revise any related rules for consistency with the order’s stated 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 ‘‘publish for notice and comment a proposed rule revising that rule, if appropriate and as consistent with law.’’ 
To further implement E.O. 13783, the 
Secretary issued Secretary’s Order (S.O.) 3349, ‘‘American Energy Independence’’ on March 29, 2017. The order directed the DOI to review all existing regulations ‘‘that potentially burden the development or utilization of domestically produced energy resources.’’ To further implement E.O. 13795, the Secretary issued S.O. 3350, ‘‘America-First Offshore Energy Strategy,’’ on May 1, 2017, which directed BSEE to review the Well Control Rule and related rulemakings. BSEE interpreted each of these orders to apply to the Subpart H—Production Safety System rulemaking (Subpart H Rule). 
As part of its response to E.O.s 13783 
and 13795, and S.O.s 3349 and 3350, BSEE reviewed the previous Subpart H Rule and is proposing revisions to the current regulations that could potentially reduce burdens on operators without impacting safety and protection of the environment. In addition, in 
response to comments from industry received since the previous final Subpart H Rule was published, BSEE is proposing certain revisions that would clarify the existing regulations. D. Incorporation by Reference of 
Industry Standards 
BSEE frequently uses standards (e.g., 
codes, specifications (Spec.), and 
recommended practices (RP)) developed through a consensus process, facilitated by standards development organizations and with input from the oil and gas industry, as a means of establishing requirements for activities on the OCS. BSEE may incorporate these standards into its regulations by reference without republishing the standards in their entirety in regulations. The legal effect of incorporation by reference is that the incorporated standards become regulatory requirements. This incorporated material, like any other regulation, has the force and effect of law. Operators, lessees, and other regulated parties must comply with the documents incorporated by reference in the regulations. BSEE currently incorporates by reference over 100 consensus standards in its regulations. (See 30 CFR 250.198.) 
Federal 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. The preamble of the proposed rule must also discuss the ways that the incorporated materials are reasonably available to interested parties and how those materials can be obtained by interested parties. The Director of the Federal Register will approve each incorporation of a publication by reference in a final rule that meets the criteria of 1 CFR part 51. 
When a copyrighted publication is 
incorporated by reference into BSEE regulations, BSEE is obligated to observe and protect that copyright. BSEE provides members of the public with website addresses where these standards may be accessed for viewing—sometimes for free and sometimes for a fee. Standards development organizations decide whether to charge a fee. One such organization, the American Petroleum Institute (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 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.
2In addition to the 
free online availability of these 
standards for viewing on API’s website, hardcopies and printable versions are available for purchase from API. The API website address to purchase standards is: http://www.api.org/ publications-standards-and-statistics/ publications/government-cited-safety- documents. 
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, 45600 Woodland Road, Sterling, Virginia 20166, or by sending a request by email to regs@bsee.gov. 
E. Section-by-Section Discussion of 
Changes 
Documents Incorporated by Reference 
(§ 250.198) 
This proposed rulemaking would 
update the incorporation by reference of superseded standards currently incorporated in Subpart H to the current edition of the relevant standard. This includes incorporating new or recently reaffirmed editions of a number of standards referenced in Subpart H, as well as replacing one standard currently incorporated in the regulations, that was withdrawn by API, with a new standard. However, BSEE is still evaluating the newer editions of these standards to analyze the specific changes between the incorporated editions and the current editions and to assess the potential impacts of those changes on offshore operations. BSEE may decide not to replace the incorporated edition of a specific standard before the publication of the final rule. BSEE is soliciting comments that will inform our decision on updating these standards, including comments on potential risks and costs associated with the new editions. BSEE will consider a number of factors in evaluating the current editions; primarily focusing how compliance with the current edition balances impacts on safety and protection of the environment and with costs and burdens. If BSEE decides to replace the incorporated documents with new editions in the final rule, the new editions would apply to all sections of 30 CFR part 250 where those documents are incorporated. BSEE may also make some conforming changes to the regulatory text in the final rule that 
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were not identified in this proposed 
rule. 
This proposed rulemaking would 
replace the following standard: 
•API RP 14H, Recommended 
Practice for Installation, Maintenance and Repair of Surface Safety Valves and Underwater Safety Valves Offshore was withdrawn by API and superseded by API STD 6AV2—Installation, Maintenance, and Repair of Surface Safety Valves and Underwater Safety Valves Offshore. API STD 6AV2, first edition 2014 revises and supersedes API Recommended Practice 14H, Fifth Edition 2007. API STD 6AV2 provides practices for installing and maintaining SSVs and USVs used or intended to be used as part of a safety system, as defined by documents such as API Recommended Practice 14C. The standard includes provisions for conducting inspections, installations, and maintenance, field and off-site repair. Other provisions address testing procedures, acceptance criteria, failure reporting, and documentation. Significant changes include updated definitions; new provisions for qualified personnel; documentation, test procedures and acceptance criteria for post-installation and post-field repair, and offsite repair and remanufacture alignment to API 6A. 
BSEE would update the incorporated 
edition of the following standards: 
•ANSI/American Society of 
Mechanical Engineers (ASME) Boiler and Pressure Vessel Code, Section I, Rules for Construction of Power Boilers; including Appendices, 2017 Edition; and July 2017 Addenda, and all Section I Interpretations Volume 55. This would update the current incorporation of the 2004 Edition (and 2005 Addenda) of the same standard. ASME BPVC Section 1 provides all methods and requirements for construction of power, electric, and miniature boilers; high temperature water boilers, heat recovery steam generators, and certain fired pressure vessels to be used in stationary service; and power boilers used in locomotive, 
portable, and traction service. Major Changes in this edition include (a) visual examination guidance in the fabrication process, (b) a non-mandatory option for ultrasonic examination acceptance criteria, (c) rules for retaining radiographs as digital images, (d) clarification on material identification requirements for a ‘‘pressure part material’’, (e) updated mandatory training for qualified personnel for various non-destructive examination (NDE) techniques, (f) updated what types of auxiliary lift devices can be used for alternative testing of valves to align with current state of the art, (g) clarified that welded 
pressure parts shall be hydrostatic tested with the completed boiler, and references to other standards updated. 
•ANSI/ASME Boiler and Pressure 
Vessel Code, Section IV, Rules for Construction of Heating Boilers; including Appendices 1, 2, 3, 5, 6, and Non-mandatory Appendices B, C, D, E, F, H, I, K, L, and M, and the Guide to Manufacturers Data Report Forms, 2017 Edition; July 2017 Addenda, and all Section IV Interpretations Volume 55. This would update the current incorporation of the 2004 Edition (and 2005 Addenda) of the same standard. This Section provides requirements for design, fabrication, installation and inspection of steam heating, hot water heating, hot water supply boilers, and potable water heaters intended for low pressure service that are directly fired by oil, gas, electricity, coal or other solid or liquid fuels. The new edition has (a) equipment scope clarifications, (b) a new mandatory appendix for feedwater economizers, (c) deleted conformity assessments requirements and moved them to normative reference ASME CA– 1, (d) new corrosion resistant alloy requirements for internal tank surfaces of heat exchangers installed in storage tanks, and (e) clarified requirements for modular boilers. 
•ANSI/ASME Boiler and Pressure 
Vessel Code, Section VIII, Rules for Construction of Pressure Vessels; Divisions 1 and 2, 2017 Edition; July 2017 Addenda, Divisions 1, 2, and 3 and all Section VIII Interpretations Volumes 54 and 55. 
This document gives detailed 
requirements for the design, fabrication, testing, inspection, and certification of both fired and unfired pressure vessels. It specifically refers to those pressure vessels that operate at pressures, either internal or external, that exceed 15 psig. Since the 2004 edition, ASME has attempted to rewrite the ASME code to incorporate the latest technologies and engineering knowledge. Section VIII 
contains three divisions, each of which covers different vessel specifications. 
Division 1 of Section VIII largely 
contains appendixes, some mandatory and some non-mandatory, that detail supplementary design criteria, nondestructive examination techniques, and inspection acceptance standards for pressure vessels. It also contains rules that apply to the use of the single ASME certification mark. Significant changes include (a) new general requirements for quick-actuating closures and quick- opening closures, (b) updated nozzle design methods, (c) moved conformity assessment requirements to the newly referenced ASME CA–1 standard, (d) clarified when manual or automated 
ultrasonic examination methods are acceptable, and (e) allowance for organizations who fabricate parts without design responsibility to obtain an ASME certification. 
Division 2 contains more rigorous 
requirements for the materials, design, and nondestructive examination techniques for pressure vessels to offset the use of higher stress intensity values in the design. Significant changes include (a) the addition of two classes of vessels, with differing design margins, and certification requirements, (b) updated acceptance criteria for shear stresses, (c) moved conformity assessment requirements to the newly referenced ASME CA–1 standard, (d) axial and compressive hoop compression requirements, and (e) corrected design equation for non- circular vessels. 
•API 510, Pressure Vessel Inspection 
Code: In-Service Inspection, Rating, Repair, and Alteration, Downstream Segment, Tenth Edition, May 2014; Addendum 1, May 2017. This would update the current incorporation of the Ninth Edition (from 2006) of the same standard. The tenth edition of API 510 was issued May 2014 and replaces the ninth edition from June 2006. API 510 covers the in-service inspection, repair, alteration, and re-rating activities for pressure vessels and the pressure- relieving devices protecting these vessels. The intent of API 510 is to specify the in-service inspection and condition-monitoring program that is needed to determine the integrity of pressure vessels and pressure-relieving devices. The tenth edition includes updated normative references, updated definitions, and new requirements for inspection programs, corrective actions, management of change, integrity operating windows, pressure testing, corrosion considerations and marking requirements. 
•API STD 2RD, Dynamic Risers for 
Floating Production Systems, Second Edition, September 2013. This would update the current incorporation of the First Edition (from 1998; as well as 2009 Errata) of the same standard. API RP 2RD first edition was published in 1998. In September 2013, the second edition of the document was issued as a standard instead of a recommended 
practice (RP). The second edition attempts to address the advancement in technology and deepwater environments and addresses a broader scope of marine risers compared to the first edition. The design approach has changed from an allowable stress criteria to a load and resistance factor design, also known as limit state design. 
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From there, four different methods are 
given to evaluate combined loads and the designer has the flexibility to choose which one to use. Each method ensures burst limit states are not exceeded for the extreme ‘‘Accidental Limit State’’ (survival) case. Other design changes addressed include both structural and leak limit states for components, exceedance of yield, combined load approach, explicit burst and collapse checks, temperature de-rating, special material testing requirements, fatigue checks, and accidental load assessments. A requirement to develop and implement an integrity management program is also in the second edition, along with integrity management activities such as new installation requirements and monitoring, post installation surveys, and fatigue damage analyses. 
•API RP 2SK, Recommended 
Practice for Design and Analysis of Stationkeeping Systems for Floating Structures, Third Edition, October 2005, Addendum, May 2008, Reaffirmed June 2015. This would update the current incorporation of this standard to reflect its reaffirmation in June 2015. The third edition of API RP 2SK was released in October 2005 and reaffirmed in 2015. This document presents a rational method for analyzing, designing, or evaluating station-keeping systems used for floating units. This document addresses station-keeping system (mooring, dynamic positioning, or thruster-assisted mooring) design, analysis and operation. Different design requirements for mobile and permanent moorings are provided. There are no changes to this document; we are simply revising to reflect the reaffirmation of this standard. 
•API RP 2SM, Recommended 
Practice for Design, Manufacture, Installation, and Maintenance of Synthetic Fiber Ropes for Offshore Mooring, Second Edition, July 2014. This would update the current incorporation of the First Edition (from 2001; as well as 2007 Addendum) of the same standard. API 2SM first edition was published March 2001 and its update was published in July 2014. This document covers recommended practices for manufacture, installation and maintenance of synthetic fiber ropes as offshore moorings for permanent and temporary offshore installations. The document also discusses the difference between steel catenary moorings and synthetic fiber moorings. This scope and structure provides guidance as to the advantages of utilizing each anchoring methodology 
and the logic an operator should use in selecting mooring systems. The most significant change in the new edition of 
API 2SM is the addition of more requirements for in-service inspection, testing, and maintenance. This document intends to ensure robust design and use of synthetic fiber rope for offshore moorings. 
•ANSI/API RP 14B, Recommended 
Practice for Design, Installation, Repair and Operation of Subsurface Safety Valve Systems, Sixth Edition, September 2015. This would update the current incorporation of the fifth edition (from 2005) of the same standard. ANSI/ API RP 14B sixth edition was published September 2015, and supersedes the fifth edition published October 2005. This standard creates requirements and provides guidelines for subsurface safety valves (SSSV) system equipment. Subsurface safety valve systems are designed and installed to prevent uncontrolled well flow when actuated. The new edition addresses system design, installation, operation, testing, redress, support activities, documentation, and failure reporting. Specific equipment covered in the standard includes control systems, control lines, SSSVs and secondary tools. The new edition also emphasizes supplier and manufacturer operating manuals, systems integration manuals, handling, system quality, documentation, and data control. Finally, ANSI/API RP 14B provides criteria for proper redress for replacement or disassembly of an SSSV. 
•API RP 14C, Recommended Practice 
for Analysis, Design, Installation, and Testing of Basic Surface Safety Systems for Offshore Production Platforms, Eighth Edition, February 2017. This would update the current incorporation of the Seventh Edition (from 2001, reaffirmed 2007) of the same standard. The eighth edition API RP 14C contains extensive changes compared to the last substantive revision (sixth edition) in 1998. This document presents provisions for designing, installing, and testing both process safety and non- marine emergency support systems (ESSs) on an offshore fixed or floating facility. API RP 14C addresses methods to document and verify process safety system functions, as well as procedures for testing common safety devices with recommendations for test data and 
acceptable test tolerances. 
Components addressed in the new 
standard are boarding shut down valve requirements, pipeline Shutdown Valve (SDV)/Flow Safety Valve (FSV) leakage and testing requirements, compressors, heat exchangers, High Integrity Pressure Protection System (HIPPS), acceptable SSV leakage rates, pump suction lines, and Temperature Safety Element (TSE) requirements. For users of HIPPS, the 
eighth edition references to more performance based standards, such as API 521, ‘‘Guide for Pressure-Relieving and Depressuring Systems.’’ New annexes in the eighth edition cover HIPPS, logic solvers, safety system bypassing, and remote operations. Finally, all subsea requirements were removed and relocated to the new standard API 17V, ‘‘Recommended Practice for Analysis, Design, Installation, and Testing of Safety Systems for Subsea Applications,’’ while API 14C addresses topside safety systems. 
•API RP 14FZ, Recommended 
Practice for Design and Installation 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. This would update the current incorporation of the first Edition (from 2001, reaffirmed 2007) of the same standard. API RP 14FZ first edition was published September 2001 and reaffirmed March 2007. The second edition of API RP 14FZ was published May 2013 and contains substantial changes from the first edition. The second edition establishes minimum requirements and guidelines for design and installation of electrical systems on fixed and floating petroleum facilities located offshore when hazardous locations are classified as Zone 0, Zone 1, or Zone 2. As revised, API RP 14FZ applies to both permanent and temporary electrical installations and is intended to describe basic desirable electrical practices for offshore electrical systems. 
•API RP 14G, Recommended 
Practice for Fire Prevention and Control on Fixed Open-type Offshore Production Platforms, Fourth Edition, April 2007; reaffirmed January 2013. This would update the current incorporation of this standard to reflect its reaffirmation in 2013. This publication includes provisions for minimizing the likelihood of having an accidental fire, and for designing, inspecting, and maintaining fire control systems. It emphasizes the need to train personnel in firefighting, to conduct routine drills, and to establish methods and procedures for safe evacuation. The fire control systems in this publication are intended to provide an early response to incipient fires to prevent their growth. However, this recommended practice is not intended to preclude the application of more extensive practices to meet special situations or the substitution of other 
systems which will provide an equivalent or greater level of protection. 
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This publication is applicable to fixed 
open-type offshore production platforms which are generally installed in moderate climates and which have sufficient natural ventilation to minimize the accumulation of vapors. Enclosed areas, such as quarters buildings and equipment enclosures, normally installed on this type platform, are addressed. Totally enclosed platforms installed for extreme weather conditions or other reasons are beyond the scope of this RP. 
•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. This would update the current incorporation of the second edition (from 1997, reaffirmed in 2002) of the same standard. The purpose of this recommended practice is to provide guidelines for classifying locations Class I, Division 1 and Class I, Division 2 at petroleum facilities for the selection and installation of electrical equipment. Basic definitions given in the 2011 edition of National Fire Protection Association (NFPA) 70, National Electrical Code (NEC), have been followed in developing this RP. 
•ANSI/API Specification Q1 (ANSI/ 
API Spec. Q1), Specification for Quality Programs for the Petroleum, Petrochemical and Natural Gas Industry, Ninth Edition, June 2013; effective date June 1, 2014; Errata, February 2014; Errata 2, March 2014; Addendum 1, June 2016. This would update the current incorporation of the eighth edition (from 2007) of the same standard. API Specification Q1, ninth edition was published June 2013, and supersedes API Specification Q1, eighth edition 2007. This revision features over 85 new clauses and 5 new sections, creating a major shift in quality management as it applies to the oil and gas industry. A thematic change is the approach to quality through risk assessment and risk management. The five new sections include risk assessment and management, contingency planning, product quality plan, preventative maintenance, and management of change. Another motivation for the ninth edition revision is alignment with the 2011 publication API Specification Q2, Specification for Quality Management System Requirements for Service Supply Organizations for the Petroleum and Natural Gas Industries, first edition. Overall, the goal of API Q1 ninth edition is to further enhance the minimum baseline requirements of quality management systems of oil and gas equipment manufacturers. 
•ANSI/API Specification 6A (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. This would update the current incorporation of the Nineteenth Edition (from 2004) of the same standard. The twentieth edition of API Spec. 6A includes notable changes from the previous edition. Major changes include: (a) Updated definitions and terms, (b) updated normative references to other standards, (c) temperature ratings, (d) more stringent material performance requirements, (e) revamped repair and remanufacture annex, (f) updated requirements for equipment in hydrogen sulfide service, and (g) Surface Safety Valve (SSV) and Underwater Safety Valve (USV) performance requirements. This edition also aligns with other standards, such as material performance to NACE MR0175 (for use in H
2S- 
containing Environments), and options to use various ASTM (American Society for Testing and Materials) International documents for material testing. References to obsolete standards and requirements for obsolete equipment were removed from the twentieth edition. 
•API Spec. 6AV1, Specification for 
Verification Test of Wellhead Surface Safety Valves and Underwater Safety Valves for Offshore Service, Second Edition, February 2013. This would update the current incorporation of the first edition (from 1996, reaffirmed in 2003) of the same standard. The second edition of API Spec 6AV1 is the first substantive change in 21 years. The new edition establishes design validation requirements for API Specification 6A, Specification for Wellhead and Christmas Tree Equipment, for SSVs and USVs and associated valve bore sealing mechanisms for Class II and Class III. Major changes from the first edition include: Replacing ‘‘Performance Requirement’’ with the term ‘‘Class,’’ phasing out the use of Class 1/PR1 valves, the API licensing of test agencies, updated facility requirements, more specificity on the validation testing procedures of Class II, and new validation tests for Class III SSVs and USVs. •ANSI/API Spec. 14A, Specification 
for Subsurface Safety Valve Equipment, 
Twelfth Ed. January 2015; Errata, July 2015; Addendum, June 2017. This would update the current incorporation of the eleventh edition (from 2005) of the same standard. API 14A twelfth edition was published January 2015 and was the successor to the eleventh edition of the document published October 2005. SSSVs are downhole valves that have integral importance to the safety of an offshore production system. The new edition now addresses other equipment such as injection valves (SSISVs), alternative SSSV technology, and secondary tools to SSSVs. Other significant changes include design analysis methods, new validation grades and associated testing, new HPHT requirements, and finally, harmonization with ANSI/API 14B, Design, Installation, Operation, Test, and Redress of Subsurface Safety Valves. This specification covers both valves and the secondary tools that interface with the valves to function properly. 
•ANSI/API Spec. 17J, Specification 
for Unbonded Flexible Pipe, Fourth Edition May 2014; Errata 1, September 2016; Errata 2, May 2017; Addendum 1, October 2017. This would update the current incorporation of the third edition (from 2008) of the same standard. API 17J fourth edition was published May 2014 and it follows the third edition from July 2008. API 17J defines the technical requirements for safe, dimensionally and functionally interchangeable, flexible pipes. Minimum requirements are specified for the design, material selection, manufacture, testing, pipe composition, marking, and packaging of flexible pipes, with reference to existing codes and standards where applicable. The current edition updates definitions, overall functional requirements, internal pressure and temperature design considerations, fluid composition, corrosion protection, gas venting, fire resistance, and exothermal chemical reaction cleaning. Flexible pipe span lengths can flow from seabed to platform and from offshore to an onshore receiving entity. 
•API 570 Piping Inspection Code: In- 
service Inspection, Rating, Repair, and Alteration of Piping Systems, Fourth Edition, February 2016; Addendum 1: May 2017. This would update the current incorporation of the third edition (from 2009) of the same standard. API 570 covers inspection, rating, repair, and alteration procedures for metallic and fiberglass-reinforced 
plastic (FRP) piping systems and their associated pressure relieving devices 
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that have been placed in service. This 
inspection Code applies to all hydrocarbon and chemical process piping covered in section 1.2.1 that have been placed in service unless specifically designated as optional per section 1.2.2. This publication does not cover inspection of specialty equipment including instrumentation, exchanger tubes and control valves. Process piping systems that have been retired from service and abandoned in place are no longer covered by this ‘‘in service inspection’’ Code. However abandoned in place piping may still need some amount of inspection and/or risk mitigation to assure that it does not become a process safety hazard because of continuing deterioration. Process piping systems that are temporarily out of service but have been mothballed 
(preserved for potential future use) are still covered by this Code. BSEE is also proposing to revise §§ 250.198(h)(58) and 250.198(h)(62) to update cross references to § 250.842(b) that would change to § 250.842(c) in this rulemaking. 
What must the DWOP contain? 
(§ 250.292) 
BSEE is proposing to revise § 250.292 
paragraph (p)(3) to replace the incorporation by reference of API RP 2RD to API STD 2RD. 
General (§ 250.800) 
BSEE is proposing to revise § 250.800 
paragraph (c)(2) to replace the 
incorporation by reference of API RP 2RD to API STD 2RD. 
Safety and Pollution Prevention 
Equipment (SPPE) Certification. (§ 250.801) 
This section would be revised to 
explicitly state that GLSDVs are included in SPPE. This is merely a clarification, since GLSDVs already must follow § 250.801. Under § 250.873 in the current regulations, GLSDVs must meet the requirements in §§ 250.835 and 250.836 for boarding shutdown valves (BSDVs). Further, § 250.835 requires that BSDVs meet the requirements in §§ 250.801 through 250.803. Since § 250.835 currently requires that BSDVs meet the requirements in § 250.801, and GLSDVs must meet the requirements for BSDVs in § 250.835 pursuant to § 250.873, it follows that GLSDVs are already required to meet the requirements of § 250.801. BSEE proposes to revise § 250.801 to expressly include GLSDVs in the list of equipment that BSEE considers to be SPPE to make this requirement more clear. BSEE also considered identifying water injection shutdown valves (WISDVs) as SPPE. However, under normal operation 
WISDVs do not handle hydrocarbons, so they do not serve the same function as other equipment identified as SPPE. 
BSEE is proposing to revise the 
introductory sentence in paragraph (a) of this section to remove the phrase, ‘‘[i]n wells located on the OCS.’’ BSEE does not need to specify the location of the SPPE, since all of the equipment that is considered SPPE, is either located in a well or a riser. 
Requirements for SPPE (§ 250.802) 
Consistent with the proposed revision 
to § 250.801, BSEE would revise this 
section to add GLSDVs to the list of equipment in this section, as well. 
BSEE would also remove the 
provision at § 250.802(c)(1) and redesignate subsequent paragraphs under paragraph (c). Current § 250.802(c)(1), is redundant with industry standards incorporated in BSEE’s regulations. This section currently requires that a qualified independent third-party certify that SPPE will function as designed, including under the most extreme conditions to which it may be exposed. 
Operators raised concerns that it may 
not be possible for independent third parties to certify that specific SPPE will perform under the most extreme conditions to which it will be exposed. Compliance with the various required standards (including API Spec Q1, ANSI/API Spec. 14A, ANSI/API RP 14B, ANSI/API Spec. 6A, and API Spec. 6AV1) ensures that each device will function in the conditions for which it was designed. In addition, the third- party reviews and certifications are 
unnecessary because the use of the standards referenced in paragraphs (a) and (b) of this section (e.g., ANSI/API 
Spec. 6A, API Spec. 6AV1, ANSI/API Spec. 14A, and ANSI/API RP 14B) ensures the valves will function in the full range of operating conditions for which they were designed. BSEE generally requires independent third party reviews when the regulated technology, system, or component: (1) Is not addressed in existing engineering standards; (2) requires a high degree of specialized or technically complex engineering expertise to understand or evaluate; and/or (3) has an associated level of risk (or even novelty) associated that additional review, assurance, or evaluation is deemed prudent prior to acceptance or approval. These criteria for independent third-party review are not present since the SPPE meet the applicable specified industry standards incorporated into BSEE’s regulations. Industry has used these SPPE for decades and the use of these valves does not require highly specialized expertise. 
Using these valves as intended reduces the risk associated with oil and natural gas production operations. Therefore, after review and consideration of the current requirements, BSEE concluded that requiring independent third party review and certification of these valves is not necessary, because ANSI/API Spec. 14A and ANSI/API Spec. Q1 provide for independent testing to ensure the devices will function as designed. 
During the implementation of the 
original final rule, a number of operators inquired about using existing inventory of BSDVs that meet the requirements of § 250.802, but are not certified. BSEE is considering an approach that would allow operators to use this existing inventory. We are requesting comments on how to allow this, including information on the size of existing inventory and timing for use of that inventory, as well as comments on an approach to allow for this. 
Consistent with the proposed change 
in § 250.801(a), BSEE would revise paragraph (d)(2) to remove the phrase, ‘‘on that well.’’ BSEE does not need to specify the location of the SPPE, since all of the equipment that is considered SPPE, is either located in a well or a riser. The preamble to the 2016 final rule describes the current table in § 250.802(d) as clarifying ‘‘when operators must install SPPE equipment that conforms to the requirements of § 250.801’’ and makes no mention of whether the SPPE is located in the well or riser (81 FR 61859). Consistently throughout, that preamble describes the requirements of existing §§ 250.800 through 250.802 without any reference to the location of the SPPE as on a well or riser, (e.g., (81 FR 61846), describing 
the existing § 250.800(c)(2) as allowing 
operators to continue using BDSV and single bore production risers already installed on floating production systems). 
What SPPE failure reporting procedures 
must I follow? (§ 250.803) 
In addition to the specific proposals 
described below, BSEE is seeking input about how to revise the current language specifying what constitutes ‘‘failure’’ used in this regulation. In response to comments received on the previous proposed rulemaking, BSEE included this language in the previous Subpart H rulemaking. During implementation of the current rule, BSEE received a number of questions from industry asking for additional clarification of this language and of what specific equipment issues operators must report. BSEE is requesting comments on 
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revising how ‘‘failure’’ is specified. The 
current § 250.803 states, ‘‘[a] failure is any condition that prevents the equipment from meeting the functional specification or purpose.’’ 
Operators are required to follow the 
failure reporting requirements from ANSI/API Spec. 6A for SSVs, BSDVs, and USVs and to follow ANSI/API Spec. 14A and ANSI/API RP 14B for SSSVs. BSEE seeks input on specifying what constitutes ‘‘failure’’ for the purposes of the reporting requirements under § 250.803. The documents incorporated by reference in § 250.803 have different definitions of failure or may not include a definition of failure at all. Given these various definitions of failure, BSEE is inquiring as to if it is appropriate to include a single description of what constitutes failure that applies to all of the SPPE covered in § 250.803? Or is it more useful to include various descriptions, based on the type of equipment? 
BSEE reviewed the definition of 
failure in various industry standards related to production systems, and found the following definitions: 
API Spec 6AV1, Specification for 
Verification Test of Wellhead Surface Safety 
Valves and Underwater Safety Valves for Offshore Service, Second Edition (incorporated by reference at §§ 250.802(a), 250.833, 250.873(b), and 250.874(g)), defines failure as: [i]mproper performance of a device or equipment item that prevents completion of its design function.’’ 
ANSI/API Spec. 14A, Specification for 
Subsurface Safety Valve Equipment, Twelfth Edition (incorporated by reference at §§ 250.802(b) and 250.803(a)), defines failure as: [a]ny equipment condition that prevents it from performing to the requirements of the functional specification. 
ABS 281, Guide for Classification and 
Certification of Subsea Production Systems, Equipment and Components, August 2017, defines failure as: [a]n event causing an undesirable condition (e.g., loss of 
component or system function) or deterioration of functional capability to such an extent that the safety of the unit, personnel, or environment is significantly reduced. 
BSEE would revise paragraph (a) of 
this section to include GLSDVs in the 
list of equipment that are subject to the failure reporting requirements. In addition, BSEE is proposing to revise this paragraph to require operators to submit their SPPE failure information to BSEE through the Chief, Office of Offshore Regulatory Programs, unless BSEE has designated a third-party. If BSEE has designated a third party, then operators would be required to submit it to that party. Currently, operators submit this information through www.SafeOCS.gov, where it is received and processed by the U.S. Department 
of Transportation’s Bureau of Transportation Statistics (BTS), the designee of the Chief of the Office of Offshore Regulatory Programs (OORP). BSEE previously identified BTS as the designee of the Chief of OORP and recommended that SPPE failure information 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 have an MOU that provides for BTS collection of 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. 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). BTS operates under this Federal law, the CIPSEA, which requires that the program, under strict criminal and civil penalties for noncompliance, treats and stores reports confidentially. Information submitted under this statute also is protected from release to other government agencies, Freedom of Information Act (FOIA) requests, and subpoena. If the information were to be submitted to BSEE, BSEE could only protect its confidentiality as allowed by Federal law. Accordingly, while BSEE could keep certain information confidential, it would likely need to release much of the information related to the failure of SPPE. Were BSEE to reconsider its agreement with BTS to collect these reports, BSEE would look for arrangements with other agencies or non-governmental organizations that could provide the same degree of confidentiality as that provided by BTS under CIPSEA. 
BSEE proposes to revise paragraph (d) 
to address the use of a BSEE-designated third party to receive the failure reporting information. 
Design, Installation, and Operation of 
SSSVs—Dry Trees (§ 250.814) 
BSEE would revise § 250.814 
paragraph (d) to replace the incorporation by reference of API RP 14B with ANSI/API 14B. 
Use of SSVs (§ 250.820) 
This section would be revised to 
replace the incorporation by reference of 
API RP 14H, which was withdrawn by API, to API STD 6AV2. Emergency Action and Safety System 
Shutdown—Dry Trees (§ 250.821) 
BSEE is proposing to revise paragraph 
(a) of this section to clarify that operators must shut in the production on any facility that ‘‘is impacted or that will potentially be impacted by an emergency situation.’’ BSEE includes some examples of emergencies such as named storms, ice events in the Arctic, or earthquakes. It was not BSEE’s intent to specify all emergency events that could trigger this regulation. The operator must determine when their 
facility is impacted or will potentially be impacted due to an emergency situation. The existing regulations do not clearly state that operators must shut in any facility that has been or may potentially be impacted by an impending emergency. The proposed clarification is to ensure that operators understand that they have an obligation to properly secure wells before the platform is evacuated in the event of an emergency. For example, if a well is capable of flowing and does not have a subsurface safety device, one must be installed. The current regulations require that this activity be done as soon as possible. BSEE requests comments on whether the phrase ‘‘as soon as possible’’ provides sufficient regulatory certainty or if there are more objective criteria, such as a before the facility is evacuated, that could be used to define these obligations. 
Design, Installation, and Operation of 
SSSVs—Subsea Trees (§ 250.828) 
BSEE would revise § 250.828 
paragraph (c) to replace the incorporation by reference of API RP 14B with ANSI/API 14B. 
Specification for Underwater Safety 
Valves (USVs) (§ 250.833) 
BSEE is proposing to revise the 
introductory paragraph in this section to replace API Spec. 6A with ANSI/API Spec. 6A. 
Use of USVs (§ 250.834) 
This section would be revised to 
update the incorporation by reference of 
API RP 14H, which was withdrawn by API, to API STD 6AV2. 
Use of BSDVs (§ 250.836) 
This section would be revised to 
update the incorporation by reference of 
API RP 14H, which was withdrawn by API, to API STD 6AV2. 
Emergency Action and Safety System 
Shutdown—Subsea Trees (§ 250.837) 
BSEE is proposing to revise paragraph 
(a) of this section to clarify that operators must shut in the production 
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on any facility that ‘‘is impacted or that 
will potentially be impacted by an emergency situation.’’ This revision is consistent with the revision proposed for § 250.821(a) for facilities with dry tress. BSEE includes some examples of emergencies such as named storms, ice events in the Arctic, or earthquakes. It is not BSEE’s intent to specify all emergency events that could trigger this regulation. The operator must determine when there may be potential impacts due to an emergency or if their facility was impacted by an emergency event. The existing regulations do not clearly state that operators must shut in any facility that has been or may be impacted by an impending emergency. BSEE would also add GLSDVs to the list of equipment that is closed during a shut-in. This is consistent with identifying GLSDVs as SPPE in §§ 250.801 through 250.803 and elsewhere in this subpart. 
In addition, BSEE is proposing to 
revise paragraph (b) of this section to clarify the requirements for dropped objects in an area with subsea operations, and to be consistent with the provisions of subpart G on dropped objects. For example, the current subpart H regulations state that the operator must develop and submit a dropped objects plan to the appropriate District Manager, as part of an Application for Permit to Drill (APD) or Application for Permit to Modify (APM). A dropped objects plan is required by § 250.714. However, § 250.714 does not require operators to submit this plan as part of the APD or APM; rather, they must make their dropped object plans available to BSEE upon request. A dropped object plan is not a static plan, § 250.714 requires operators to update their dropped objects plans as the subsea infrastructure changes. 
Throughout this section, BSEE would 
replace ‘‘MODU or other type of workover vessel’’ with ‘‘vessel.’’ The use of the word ‘‘vessel’’ is a more comprehensive term that includes any type of equipment that could be used to perform well operations. 
Platforms (§ 250.841) 
BSEE would add a new paragraph (c) 
to this section to address major 
modifications to a facility, by directing operators to follow the requirements in § 250.900(b)(2). This is not a new requirement, as operators are already required to follow the provisions of § 250.900(b)(2) for major modifications. This simply provides direction to the operator and emphasizes the need to follow § 250.900(b)(2). The existing paragraph (b) of this 
section currently requires operators to 
maintain all piping for platform production processes as specified in API RP 14E Recommended Practice for Design and Installation of Offshore Production Platform Piping Systems (API RP 14E). Section 6.5(a)(1) of API RP 14E addresses painting of steel piping to prevent corrosion. Corrosion prevention is important for safety and pollution prevention, and BSEE is not currently proposing to remove the reference to API RP 14E from this section. However, BSEE is interested in comments on whether other changes may be warranted. BSEE recognizes that there are difficulties accessing some of the piping on existing facilities, and BSEE is aware that operators have asked for extension, after BSEE has issued an incident of noncompliance, to provide additional time to implement this requirement on some facilities. In these cases, BSEE has generally requested that operators submit a departure request that includes an implementation plan to BSEE for complying with this section of API RP 14E. In the implementation plan, BSEE is looking for the operator to: (1) Identify facilities for which extra time is needed for compliance, (2) specify areas of inaccessible piping, (3) address precautions taken until the piping can be accessed for painting, and (4) prioritize high-risk areas for more rapid treatment. 
Approval of Safety Systems Design and 
Installation Features (§ 250.842) 
BSEE proposes to revise some of the 
requirements related to the diagrams and drawings the operators must to submit to BSEE for approval. Currently, operators must submit all of the documents listed in existing paragraph (a) of this section to BSEE for approval and those documents are required to be stamped by a registered professional engineer (PE). BSEE would revise this provision to require operators to submit only the most critical documents to BSEE and have those documents stamped by a PE. However, BSEE has identified some documents that the operator would be required to develop 
and maintain, but that that operator would not be required to submit to BSEE; nor would these documents would be required to be stamped by at PE. BSEE would list these less critical documents in a new paragraph (b). 
BSEE would reorganize this section in 
conjunction with these changes. This proposed rulemaking would also clarify that operators do not need to update existing drawings until a modification request is submitted to BSEE. When an operator submits a modification request, it must include fully updated drawings 
as required in paragraph (a) with all changes stamped by a PE. 
Existing introductory paragraph (a) 
states that before installing or modifying a production safety system the operator must submit a production safety system application to the District Manager for approval. This would be revised to clearly state that the operator must receive approval from the District Manager before commencing production through or utilizing the new or modified system. 
The table in existing paragraph (a) 
identifies specific diagrams and drawings that the operator is required to submit to BSEE as part of the production safety system application and be stamped by a PE. BSEE would revise the table to require operators to submit the safety analysis flow diagram, safety analysis function evaluation (SAFE) chart, electrical one line diagram, and area classification diagram for new facilities and for modifications to existing facilities. In addition revised paragraph (a) would be revised to require operators to submit piping and instrumentation diagrams (P&ID) for new facilities only; the operator would not be required to submit the P&ID modification. The table under paragraph (a) would be reordered as part of this revision. 
Existing paragraph § 250.842(a)(3), 
which addresses electrical system information would be substantially revised. This paragraph would be redesignated as paragraph (a)(2). Some items currently required as part electrical system information would be removed from the scope of required submissions. BSEE would revise this section would now require the operator to submit an electrical diagrams, showing key elements, including generators, circuit breakers, transformers, bus bars, conductors, battery banks, automatic transfer switches, uninterruptable power supply (UPS), dynamic (motor) loads, and static 
(e.g., electrostatic treater grid, lighting 
panels, etc.) loads. Other information required under the current regulations would be moved to paragraph (b)(1) in this proposed revision, such as electrical drawings for cable/tray conduit routing plans and panel board/ junction box location plans. 
The proposed rule would redesignate 
existing paragraph (b) as paragraph (c) and insert a new paragraph (b). Some of the diagrams required in existing paragraph (a) would be moved to the new paragraph (b). The operator would still be required to develop and maintain all of the diagrams included in existing paragraph (a). However, for 
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those diagrams proposed to be moved 
into new paragraph (b), BSEE would only require the operator to develop and maintain them, and provide them to BSEE upon request. The operator would no longer be required to submit these with the production safety system application. These diagrams would include: Additional electrical system information, schematics of the fire and gas-detection systems, and revised P&IDs for existing facilities. The operator would not be required to have the diagrams and drawings listed in proposed new paragraph (b) certified and stamped by a PE. The operator would be required to develop and maintain these diagrams to accurately document any changes made to the production systems; and provide these to BSEE upon request. 
The requirements for schematic P&IDs 
that are currently required under (a)(1) in the table would be moved to (a)(4) and revised to state that the operator is required to submit the P&ID for new facilities to BSEE. The operator would be required to develop and maintain revised P&IDs for modifications to existing facilities, under new (b)(3). 
The safety analysis flow diagram and 
the related SAFE chart currently in section (a)(2) would be moved to (a)(1), with additional details added to clarify what the operator must include on the diagram. 
Current paragraph (a)(3) in the table 
requires the operator to submit electrical system information. The proposed rule would move this to (a)(2) and revise it to require the operator to submit only the electrical one-line diagram. The additional electrical information in the current paragraph (a)(3) would be included in new section (b)(1), with details added to specify what electrical system information the operator must develop, maintain, and make available to BSEE. 
This section would no longer require 
operators to identify all areas where potential ignition sources are located. This requirement is already addressed 
under § 250.842(c)(3), which requires operators to perform a hazards analysis in accordance with § 250.1911 and API RP 14J. API RP 14J specifically addresses ignition sources and minimizing the chances of ignition. API RP 14J directs the operators to consider all ignition sources when designing their facility and provides detailed guidance on designing the facility and equipment to prevent the ignition of hydrocarbons. The requirement for operators to develop and maintain a separate document identifying ignition sources is not necessary because this is inherent to compliance with API RP 14J. In addition, § 250.842(c)(3) requires 
operators to have a hazards analysis program in place to assess potential hazards during the operation of the facility. 
New paragraph (b)(2) would address 
the schematics of the fire and gas- detection systems, which are currently addressed in existing paragraph (a)(4). New paragraph (b)(3) would include revised P&IDs for modifications to existing facilities. 
Redesignated paragraph (c) (existing 
paragraph (b)), would continue to require operators to certify that: (1) The all electrical installations were designed according to API RP 14F or API RP 14FZ, as applicable; (2) a hazards analysis was performed in accordance with § 250.1911 and API RP 14J; and (3) operators have a hazards analysis program in place to assess potential hazards during the operation of the facility. Redesignated (c)(2) of § 250.842 (existing (b)(2)) would be revised to state that the designs for the mechanical and electrical systems that the operator is required to submit under paragraph (a) of this section be reviewed, approved, and stamped by an appropriate registered PE. 
The drawings that would be required 
under new paragraph (b) include additional electrical system information, schematics of the fire and gas-detection systems, and revised P&IDs for existing facilities; would no longer require review, approval, and stamping by an appropriate registered PE. This change would reduce the burden on operators by no longer requiring a PE to certify as many diagrams and drawings. Operators would still be required to develop these diagrams and drawings and provide 
them to BSEE upon request. The operators would also be required to maintain them, ensuring they accurately reflect the current production system. 
BSEE would remove existing 
paragraph (c), which currently requires operators to submit a letter to the District Manager certifying that the mechanical and electrical systems were installed in accordance with the approved designs, before beginning production. This step was intended to ensure the operator properly documented the installation of the mechanical and electrical systems. This submittal was a burdensome step to assure document management and confirm that operator performed the modification as proposed and approved. Because the operators must submit the as-built drawings which BSEE uses for field verification, the certification letter was not needed. 
Under existing paragraph (d), the 
operators are already required to have the as-built diagrams stamped by a PE and to submit the as-built diagrams for the new or modified production safety systems to BSEE. Under the proposed rule, BSEE would no longer require operators to submit a letter to certify that the mechanical and electrical systems were installed in accordance with the approved designs. This letter was primarily used for tracking documentation; it is not needed by either industry or BSEE. 
BSEE would clarify existing 
§ 250.842(d) regarding PE stamping of required drawings. 
The proposed rule would require the 
diagrams that are submitted to BSEE under § 250.842 paragraphs (a)(1), (2), and (3) to be reviewed, approved, and stamped by an appropriate registered PE(s). The requirement from existing paragraph (e), that the operators submit the as-built diagrams within 60 days of commencing production would be included in this section. 
BSEE would redesignate existing 
paragraph (f) as paragraph (e), since the requirements from existing paragraph (e) would be moved to new paragraph (d). Redesignated paragraph (e) addresses the requirements for maintaining the documents required in this section. BSEE is not proposing any revisions to the requirements in this paragraph. 
Pressure Vessels (Including Heat 
Exchangers) and Fired Vessels (§ 250.851) 
BSEE is proposing to remove the dates 
from this section that required that existing uncoded pressure and fired vessels that were in use on November 7, 2016 (the effective date of the previous Subpart H rulemaking), to be code stamped before March 1, 2018. These dates no longer need to be included as they both will have already passed by the time the final rulemaking is issued in this rulemaking. In addition, most pressure vessels and fired vessels were already required to be coded stamped. The previous regulations only added vessels with an operating pressure greater than 15 psig to that requirement. The existing regulations provide that the operator may request approval from the District Manager to continue to use uncoded pressure and fired vessels. 
Flowlines/Headers (§ 250.852) 
BSEE is proposing to revise 
paragraphs § 250.852(e)(1) and (e)(4) to 
replace the reference to API Spec. 17J with ANSI/API Spec. 17J. 
Safety Sensors (§ 250.853) 
This section would be revised to add 
a new paragraph (d) to require that all 
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level sensors are equipped to permit 
testing through an external bridle on all new vessel installations, where possible, depending on the type of vessel for which the level sensor is used. This change was originally included in the previous proposed rulemaking. However, it was not included in the final rule, based on concerns raised by public comments. BSEE has reviewed those comments and is reconsidering its decision to remove this provision from the final rule. The preamble of the previous final rule stated that BSEE removed proposed paragraph (d) from the final rule because BSEE can address level sensors adequately using existing regulatory processes, such as the Deepwater Operations Plan (DWOP), and we do not need to specify uses and conditions of such sensors in this regulation. 
When BSEE reviewed that decision, 
we determined that including this requirement in the regulations is important because it clearly states the expectation to have an external bridle to permit testing. This would ensure that, where possible, the sensor is accessible for testing, which is the accepted approach, at this time. A comment on the previous rulemaking asserted that certain sensor testing technologies (e.g., ultrasonic and capacitance) are not suitable for use in external bridles, and that some proposed or new projects evaluated using ultrasonic, optical, microwave, conductive, or capacitance sensors, and that such sensors do not use bridles. BSEE recognizes that there are sensors that do not use bridles and that other equipment options exist. However, the use of level sensor with an external bridle that allows testing through the bridle remains BSEE’s preferred approach. Sensor testing equipment built according to API standards, which are incorporated by reference into BSEE’s regulations, should be able to meet this provision. We are proposing additional language to recognize other approaches, stating that operators must ensure that all level sensors are equipped to permit testing 
through an external bridle ‘‘where possible, depending on the type of vessel for which the level sensor is used.’’ This language allows BSEE more flexibility in approving a different design, without requiring the operator to apply for an alternate procedure or equipment to test the level sensor under § 250.141. 
Temporary Quarters and Temporary 
Equipment (§ 250.867) 
BSEE is proposing to revise paragraph 
(a) of this section to require District Manager approval of safety systems and safety devices associated with the 
temporary quarters prior to installation. This would apply to all temporary quarters to be installed on OCS production facilities. The existing regulations specify that that operator must receive approval for temporary quarters ‘‘. . . installed in production processing areas or other classified areas on OCS facilities.’’ This proposed would require approval of the safety systems and safety devices, instead of approval of the actual temporary quarters, regardless of where the temporary quarters are located. This proposed change recognizes that risk of a hazard occurring related to production is not restricted to the production areas or classified areas. This change would ensure that temporary quarters have the proper safety systems and devices installed to protect individuals in the temporary quarters, regardless of where they are located on the facility. 
BSEE recognizes the authority of the 
United States Coast Guard (USCG) as the lead agency for living quarters on the OCS. This is recognized in two Memorandums of Agreement (MOAs) between BSEE and USCG related to oil and gas production facilities: MOA OCS–09, Fixed OCS Facilities, dated 
September 19, 2014 and MOA OCS–04, Floating OCS Facilities, dated January 28, 2016. MOA OCS–09 establishes BSEE as the lead for safety systems, specifically for emergency shutdown systems, gas detection, and safety and shutdown systems on fixed OCS facilities. MOA OCS–04 establishes BSEE as the lead for emergency shutdown systems and components on floating OCS facilities. The existing requirement that temporary quarters must be equipped with all safety devices required by API RP 14C, Annex G would not change. This paragraph would ensure operators install the proper safety devices on or in temporary quarters, including fire and gas detection equipment and emergency shut down stations addressed in API RP 14C. BSEE will discuss this proposed change with the USCG to ensure an understanding that the USCG will not approve the installation of the temporary quarters until the operator obtains approval of the safety systems and devices from BSEE. 
BSEE would also add a new 
paragraph (d) to this section that states that operators must receive District Manager approval before installing temporary generators that would require a change to the electrical one-line diagram under § 250.842(a). Time Delays on Pressure Safety Low 
(PSL) Sensors (§ 250.870) 
BSEE is proposing to revise the 
requirement in paragraph (a) of this section regarding the use of Class B, Class C, or Class B/C logic. This section currently states that the operator ‘‘may apply any or all of the industry standard Class B, Class C, or Class B/C logic to all applicable PSL sensors installed on process equipment, as long as the time delay does not exceed 45 seconds.’’ BSEE would delete the phrase ‘‘any or all of the’’ from that sentence, as it is not needed. We would no longer require the operator to seek approval from BSEE for alternative compliance under § 250.141 to use a PSL sensor with a time delay that is greater than 45 seconds. Instead, the section would state that if the device may be bypassed for greater than 45 seconds, the operator must monitor the bypassed devices in accordance with § 250.869(a). The alternative compliance approval is not needed, since monitoring bypassed devices is addressed in the current § 250.869(a), for which no change is proposed. 
Atmospheric Vessels (§ 250.872) 
BSEE would revise paragraph (a) of 
this section to state that atmospheric 
vessels connected to the process system that contain a Class I liquid must be reflected on the corresponding drawings, along with the associated pumps. The current regulations do not specifically require the operator to include the atmospheric vessels on these drawings. However, since these tanks are used to process or store liquid hydrocarbons, it is important to identify where they are located in the processing system and to ensure they are properly protected. 
BSEE is also proposing to revise 
paragraph (b) of this section, adding language that the operator must design the level safety high (LSH) sensor on the atmospheric vessel to prevent pollution as required by § 250.300(b)(3) and (4). This is not a new requirement. BSEE is adding this provision to emphasize the importance that these vessels be designed to prevent pollution. 
In addition, BSEE is proposing to 
change the current requirement that the LSH must be installed to sense the level in the oil bucket, to limit this requirement to newly installed atmospheric vessels with oil buckets. The proposed change is based on questions and departure requests BSEE received during implementation of the Subpart H Rule. BSEE recognizes that the installation of a LSH on the oil bucket is not possible on some existing 
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vessels without extensive modifications 
to the vessels. 
BSEE is proposing to remove 
§ 250.872(c) which currently states that operators must ensure that all flame arrestors are maintained to ensure proper design function (installation of a system to allow for ease of inspection should be considered). This requirement is not necessary as it is redundant with § 250.800(a) which requires operators to maintain all production safety equipment in a manner to ensure the safety and protection of the human, marine, and coastal environments. 
Subsea Gas Lift Requirements 
(§ 250.873) 
BSEE is proposing to revise the table 
in paragraph (b) of this section to replace multiple references to API Spec. 6A with ANSI/API Spec. 6A. 
Subsea Water Injection Systems 
(§ 250.874) 
BSEE would revise paragraph (g)(2) of 
this section to replace the reference to API Spec. 6A with ANSI/API Spec. 6A. 
Fired and Exhaust Heated Components 
(§ 250.876) 
BSEE would revise this section to 
delete the requirement that the fire tube be removed during inspection. BSEE recognizes that there are other ways to inspect the fire tube, without removing them. For example, a combination of cameras with thickness sensors could be used to inspect fire tubes that cannot be easily accessed, instead of removing the fire tube completely. This change would allow the operator to determine an appropriate method to inspect the fire tube and is a more flexible, performance-based approach. BSEE recognizes the need for fire tube inspections; however, the process to remove the fire tube for inspection can pose its own safety concerns. In some cases, use of an alternative method for inspections would actually increase safety, since removing the fire tube may present a hazard if the fire tube is located in a place where it is not easy to remove. 
Production Safety System Testing 
(§ 250.880) 
BSEE is proposing to clarify language 
in paragraph (a)(1) of this section to clearly state that the operator must notify BSEE at least 72 hours before commencing initial production on a facility. The current language states that the operator must notify BSEE, ‘‘at least 72 hours before commencing production.’’ It does not specify that this notification is for initial production, leading to possible interpretation that the operator must notify BSEE anytime production on a facility has been shut in and the operator is ready to resume production. This interpretation was not BSEE’s intent. 
In addition, BSEE would revise 
paragraphs (c)(2)(iv) and (c)(4)(iii) to update the incorporation by reference of API RP 14H, which was withdrawn by API, to API STD 6AV2. 
BSEE would also revise § 250.880 
paragraph (c) to replace the incorporation by reference of API RP 14B with ANSI/API 14B. 
What industry standards must your 
platform meet? (§ 250.901) 
BSEE is proposing to revise paragraph 
(a) of § 250.901 and the table in paragraph (d) to update the incorporation by reference of API STD 2RD. 
Design Requirements for DOI Pipelines 
(§ 250.1002) 
BSEE is proposing to revise paragraph 
(b) of § 250.1002 to update the references to ANSI/API Spec. 6A, ANSI/ API Spec. 17J, and API STD 2RD. 
What To Include in Applications 
(§ 250.1007) 
BSEE is proposing to revise 
paragraphs (a) of § 250.1007 to replace the reference to API Spec. 17J with ANSI/API Spec. 17J. 
F. Additional Comments Solicited 
BSEE has identified a number of 
potential revisions to the 30 CFR part 
250 regulations that are not specifically included in this proposed rulemaking. However, BSEE is soliciting comments on these potential revisions, which it may implement in the final rule or a future rulemaking. 
Potential Revisions to § 250.107(c) Best 
Available and Safest Technology (BAST) 
In the 2016 final rule, BSEE revised 
the definition of BAST contained in Section 250.107 based on public comments. BSEE solicits comments on whether this language adequately reflects the statutory mandate concerning the use of BAST on the OCS. 
Potential Revisions to § 250.198 
Documents Incorporated by Reference 
BSEE is considering potential, non- 
substantive revisions to § 250.198, as a whole, for the purposes of reorganizing and revising that section to make it clearer, more user-friendly, and more consistent with the Office of the Federal Register’s (OFR’s) recommendations for incorporations by reference in Federal regulations. BSEE will continue to consult with the OFR regarding its 
suggestions for specific organizational and language changes to § 250.198 and expects to address such revisions in a separate rulemaking as soon as possible. BSEE does not anticipate that those potential revisions would have any substantive impact on the proposed incorporations by reference of industry standards discussed in this notice. 
Considerations for failure reporting 
under § 250.803 what SPPE failure reporting procedures must I follow? 
BSEE is seeking input on clarifying 
when a failure analysis is required under § 250.803. Under what circumstances should BSEE require more failure analysis information? For example, a formal root cause failure analysis conducted by Subject Matter Experts, or the manufacturer? Should BSEE limit the formal failure analysis to cases where SPPE are returned to shore for remedial action to address the cause of the failure? 
Extension of Compliance for Pressure 
Safety Valve (PSV) Testing Under § 250.880 Production Safety System Testing 
BSEE also considered revising the 
requirements regarding PSV testing in § 250.880(c)(2)(i). This existing provision requires operators to test PSVs annually and that the main valve piston must be lifted during this test. The main valve piston is a critical component of the PSV, and this approach will verify it will actually vent when needed. BSEE recognizes that this is a change to the approach used for testing prior to the 2016 rule and that some operators needed time develop new testing procedures. In some cases, operators may need to modify existing equipment or fabricate new equipment to fully comply. BSEE granted departures to this provision, giving operators who requested a departure under § 250.142, until November 7, 2018 to comply with this requirement. BSEE expects that operators will be able to comply by that date and a revision to this requirement is not needed; nevertheless BSEE is considering whether it is appropriate to provide additional time to perform the first required test on those PSVs where it is not possible to lift the piston during the test. BSEE would potentially consider an additional 1 to 2 years beyond the effective of this rulemaking for BSEE seeks comments on this issue, including comments on an appropriate time period for the delay. 
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Potential Revisions Based on the 
Investigation of the Explosion and Fatality on West Delta Block 105 Platform E 
In 2016, BSEE issued a panel report 
entitled Investigation of November 20, 2014, Explosion and Fatality, Lease OCS–00842, West Delta Block 105 Platform E. The incident involved an explosion inside the electrostatic heater treater located on the platform while the contract cleaning crew personnel were engaged in activities related to cleaning the vessel. The report and corresponding memorandum, can be found at https://www.bsee.gov/wd-105- e-panel-report. We are seeking comments on the possibility of revising BSEE’s regulations to address the recommendations in this report, including information on timing, costs, and other considerations. BSEE will consider relevant comments in developing any proposed rulemaking addressing the following topics from the report: 
Safety Device To De-Energize 
Electrostatic Heater Treater 
Should BSEE consider requiring 
facilities to have a safety device able to detect a drop in the level of the coalescing section of electrostatic treaters and have the associated function of tripping the power to the transformer and/or grid if the level drops too low? How are the associated risks for similar equipment managed? 
Safe Cleaning Procedures for Tanks and 
Vessels 
Do the existing BSEE regulations and 
standards provide adequate guidance regarding safety when performing cleaning activities on tanks or vessels that contain, or previously contained, petroleum or petroleum-related products? If not, what revisions to BSEE’s regulations or incorporated standards are needed? 
Implementation of This Rulemaking 
BSEE seeks comments on potential 
obstacles for implementing the 
requirements in this NPRM; including the feasibility of implementation and any hardships operators may encounter during implementation. 
Procedural Matters Regulatory Planning and Review (E.O. 
12866, E.O. 13563, E.O. 13771) 
Executive Order 12866 provides that 
the Office of Information and Regulatory Affairs within OMB will review all significant rules. The Office of Information and Regulatory Affairs has determined that this proposed rule is neither economically significant nor 
significant because it would raise novel legal or policy issues. After reviewing the requirements of this proposed rule, BSEE has determined that it will not have an annual effect on the economy of $100 million or more nor adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, public health or safety, the environment, or state, local, or tribal governments or communities. 
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. Consistent with E.O. 13771 BSEE has evaluated this rulemaking based on the requirements of E.O. 13771. This proposed rule is expected to be an E.O. 13771 deregulatory action. Details on the estimated cost savings of this proposed rule can be found in the rule’s economic analysis. While this rulemaking is not a significant regulatory action under E.O. 12866, the regulatory clarifications, reduction in paperwork burdens, adoption of industry standards, migration to performance standards for select provisions and additional time for operators to meet the production equipment requirements constitutes an E.O. 13771 deregulatory action. BSEE also finds the reduction in regulated entity compliance burden does not increase the safety or environmental risk 
for offshore production operations. 
This rule primarily proposes to revise 
sections of 30 CFR part 250 subpart H—Oil and Gas Production Safety Systems. BSEE has reassessed a number of the provisions in the original (1014– AA10) rulemaking and determined that some provisions should be written as performance standards rather than prescriptive requirements. Other proposed revisions reduce or eliminate 
parts of the paperwork burden of the original rulemaking, while providing the same level of safety and environmental protection. BSEE has reexamined the economic analysis for the 2016 1014–AA10 final rule and now believes that it may have underestimated compliance costs. BSEE is therefore revising some of the compliance cost assumptions in that analysis for this rulemaking. The underestimate of compliance costs in the 1014–AA10 analysis is primarily related to (1) the burden for obtaining PE review and stamping of all drawings on a facility if any production equipment modifications are proposed and (2) duplicative independent third party equipment certifications that would no longer be required under this proposal. BSEE underestimated both the cost and number of PE reviews required under § 250.842. The cost of independent 3rd party testing and certifications required under the § 250.802 paragraph (c)(1) was also underestimated by BSEE. 
BSEE expects this proposed rule to 
reduce the regulatory burden on industry. Regulatory compliance cost savings are a result of changes in the proposed rule that reduce burden hours, PE stamping for production safety system components and independent third party equipment certifications. BSEE estimates this rulemaking, if adopted, would reduce industry compliance burdens by $33 million annually. Over 10 years BSEE estimates the reduced compliance burdens and cost savings to be $281 million discounted at 3 percent or $228 million discounted at 7 percent. As discussed in the initial Regulatory Impact Analysis (RIA) the proposed amendments would not negatively impact worker safety or the environment. 
The cost savings for revised 
provisions on PE stamping of production safety system modification documents (§ 250.842) is the single largest single cost savings provision in this proposed rule. The additional PE certifications and stamping will no longer be required for all production safety system documents in an application, only the documents for those components being modified. BSEE estimates the net regulatory cost savings will be $23.1 million in the first year (2018) and $162.0 million over 10 years discounted at 7 percent. The other provision providing substantial regulatory relief is the proposed elimination of the third-party reviews and certifications for select SPEE. 
Compliance with the various required standards (including API Spec Q1, 
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ANSI/API Spec. 14A, ANSI/API RP 14B, 
ANSI/API Spec. 6A, and API Spec. 6AV1) ensures that each device will function in the conditions for which it was designed. The table below summarizes BSEE’s estimate 10-year the compliance cost savings. Additional information on the compliance costs, savings and benefits can be found in the 
initial RIA posted in the docket. 
TOTAL ESTIMATED COSTSAVINGS ASSOCIATED WITHAMENDMENTS TO SUBPART H 
[2016 $] 
Year Undiscounted Discounted 
at 3% Discounted 
at 7% 
Total .......................................................................................................................... ................... $332,630,000 $281,021,257 $228,268,048 
Annualized ..................................................................................................................... .............. 33,263,000 32,944,264 32,500,235 
BSEE has developed this final rule 
consistent with the requirements of E.O. 
12866, E.O. 13563, and E.O. 13771. This proposed rule revises various provisions in the current regulations with performance-based provisions based upon the best reasonably obtainable safety, technical, economic, and other information. BSEE has provided industry flexibility to meet the safety or equipment standards rather than specifying the compliance method when practical. Based on a consideration of the qualitative and quantitative safety and environmental factors related to the proposed rule, BSEE’s assessment is that its promulgation is consistent with the requirements of the applicable E.O.s and the OCSLA and that this rulemaking would impose the least burden on industry and provide the public a net benefit. 
Small Business Regulatory Enforcement 
Fairness Act and Regulatory Flexibility Act 
The proposed rule is not a major rule 
under the Small Business Regulatory Enforcement Fairness Act (5 U.S.C. 801 et seq.). This proposed rule: 
a. Would not have an annual effect on 
the economy of $100 million or more. This proposed rule would revise the requirements for oil and gas production safety systems. The changes would not have any negative impact on the economy or any economic sector, productivity, jobs, the environment, or other units of government. Most of the new requirements are related to inspection, testing, and paperwork requirements, and would not add significant time to development and production processes. 
b. Would not cause a major increase 
in costs or prices for consumers, individual industries, Federal, State, or local government agencies, or geographic regions. 
c. Would not have significant adverse 
effects on competition, employment, investment, productivity, innovation, or the ability of U.S.-based enterprises to compete with foreign-based enterprises. The requirements will apply to all entities operating on the OCS. 
The Regulatory Flexibility Act, 5 
U.S.C. 601–612, requires agencies to analyze the economic impact of proposed 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. The Initial Regulatory Flexibility Analysis (IRFA), which assesses the impact of this proposed rule on small entities, can be found in the Regulatory Impact Analysis within the rulemaking docket. 
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 proposed rule would affect lease operators that are conducting OCS drilling or well operations. BSEE’s analysis shows this could include about 69 companies with active operations. Of the 69 companies, 21 (30 percent) are large and 48 (70 percent) are small. Entities that would operate under this proposed rule primarily fall under the SBA’s North American Industry Classification System (NAICS) codes 211111 (Crude Petroleum and Natural Gas Extraction). For the NAICS code 211111, a small company has 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. All of the operating businesses meeting the SBA classification are potentially impacted; therefore BSEE expects that the proposed rule would affect a substantial number of small entities. 
This proposed rule is a deregulatory 
action and BSEE has estimated the overall associated costs savings. BSEE has estimated the annualized cost savings and allocated those savings to small or large entities based on the number of active or idle OCS production facilities. Using the share of small and large companies’ production facilities, we estimate that small companies would realize 87 percent of the cost savings from this rulemaking and large companies 13 percent. Small companies operate ∼90 percent of the shallow water facilities and are expected to realize most of the benefits in this rulemaking due to the greater number of facilities operated. Additional information can be found in the IRFA in the rulemaking docket. 
Unfunded Mandates Reform Act of 1995 
This proposed rule would not impose 
an unfunded mandate on State, local, or 
tribal governments or the private sector of more than $100 million per year. The proposed rule would not have a significant or unique effect on State, local, or tribal governments or the private sector. A statement containing the information required by 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 
proposed rule does not have significant takings implications. The proposed rule is not a governmental action capable of interference with constitutionally protected property rights. A Takings Implications Assessment is not required. 
Federalism (E.O. 13132) 
Under the criteria in E.O. 13132, this 
proposed rule does not have federalism 
implications. This proposed rule would not substantially and directly affect the relationship between the Federal and State governments. To the extent that 
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State and local governments have a role 
in OCS activities, this proposed rule would not affect that role. A Federalism Assessment is not required. 
The BSEE has the authority to 
regulate offshore oil and gas production. State governments do not have authority over offshore production on the OCS. None of the changes in this proposed rule would affect areas that are under the jurisdiction of the States. It would 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 rule complies with the 
requirements of E.O. 12988. 
Specifically, this rule: 
(a) Meets the criteria of section 3(a) 
requiring that all regulations be reviewed to eliminate errors, ambiguity, and be written to minimize litigation; and 
(b) Meets the criteria of section 3(b)(2) 
requiring that all regulations be written in clear language and contain clear legal standards. 
Consultation With Indian Tribes (E.O. 
13175) 
Under the criteria in E.O. 13175 and 
the DOI Tribal Consultation Policy, we have evaluated this proposed rule and determined that it would have no substantial, direct effects on federally recognized Indian tribes. 
Paperwork Reduction Act (PRA) of 1995 
This proposed rule contains a 
collection of information that will be 
submitted to the OMB for review and approval under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.). As part of our continuing effort to reduce paperwork and respondent burdens, BSEE invites the public and other Federal agencies to comment on any aspect of the proposed reporting and recordkeeping burden. If you wish to comment on the information collection (IC) aspects of this proposed rule, you may send your comments directly to OMB and send a copy of your comments to BSEE’s Regulations and Standards Branch (see the 
ADDRESSES  
section of this proposed rule). Please reference; 30 CFR part 250, subpart H, Oil and Gas Production Safety Systems Revisions, 1014–0003, in your 
comments. BSEE specifically requests comments concerning: the need for the information, its practical utility, the accuracy of the agency’s burden estimate, and ways to minimize the burden. 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. To see a copy of the entire IC Review submitted to OMB, go to http://www.reginfo.gov (select Information 
Collection Review, Currently Under Review). 
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. OMB is required to make a decision concerning the collection of information contained in these proposed regulations 30 to 60 days after publication of this document in the Federal Register. 
Therefore, a comment to OMB is best assured of having its full effect if OMB receives it by January 29, 2018. This does not affect the deadline for the public to comment to BSEE on the proposed regulations. 
The title of the collection of 
information for this rule is 30 CFR part 250, subpart H, Oil and Gas Production Safety Systems Revisions (Proposed 
Rulemaking). The proposed regulations concern oil and gas production requirements, and the information is used in our efforts to protect life and the environment, conserve natural resources, and prevent waste. 
Potential respondents comprise 
Federal OCS oil, gas, and Sulphur operators and lessees. The frequency of response varies depending upon the requirement. Responses to this collection of information are mandatory, or are required to obtain or retain a benefit; they are also submitted on occasion, annually, 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 FOIA (5 U.S.C. 552) and its 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. 
Proposed changes to the information 
collection due to this rulemaking are as follows: 
•§ 250.802(c)(1) is being eliminated 
and would cause a reduction in non- hour costs burdens by ¥$550,000. 
•§ 250.842(c) is being eliminated and 
would cause a reduction in hour burden by ¥192 hours. 
•During the 1014–AA10 rulemaking 
(original Subpart H rewrite), BSEE inadvertently omitted costs for Professional Engineers required to stamp documents in § 250.842. This revision to the collection requests approval of an additional $23,470,000 non-hour costs (PE Costs). We are adding this category of costs in this rulemaking but note that this rulemaking reduces the amount of information a PE must stamp from the 2016 rule. 
Current subpart H regulations have 
95,997 hours and $5,582,481 non-hour cost burdens (cost recovery fees) approved by OMB. Due to this rulemaking, the revisions to the collection would result in a total of 95,805 hours and $28,502,481 non-hour cost burdens. 
Once this rule becomes effective, the 
changes in hour burdens and non-hour cost burdens will be adjusted in the current OMB approved collection (1014–0003). 
National Environmental Policy Act of 
1969 
BSEE has prepared a draft 
environmental assessment (EA) to determine whether this proposed rule would 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.). If the final EA supports 
the issuance of a Finding of No Significant Impact (FONSI) for the rule, the preparation of an environmental impact statement pursuant to the NEPA would not be required. 
The draft EA was placed in the file for 
BSEE’s Administrative Record for the rule at the address specified in the 
ADDRESSES section. A copy of the draft 
EA can be viewed at the Federal eRulemaking Portal: https://www.regulations.gov (use the keyword/ 
ID ‘‘BSEE–2017–0008’’). 
Data Quality Act 
In developing this rule we did not 
conduct or use a study, experiment, or 
survey requiring peer review under the Data Quality Act (Pub. L. 106–554, app. C § 515, 114 Stat. 2763, 2763A–153– 154). 
Effects on the Nation’s Energy Supply 
(E.O. 13211) 
This proposed rule is not a significant 
energy action under the definition in E.O. 13211. A Statement of Energy Effects is not required. 
Clarity of This Regulation (E.O. 12866) 
We are required by E.O. 12866, E.O. 
12988, and by the Presidential 
Memorandum of June 1, 1998, to write all rules in plain language. This means that each rule we publish must: 
(a) Be logically organized; 
(b) Use the active voice to address 
readers directly; 
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(c) Use clear language rather than 
jargon; 
(d) Be divided into short sections and 
sentences; and 
(e) Use lists and tables wherever 
possible. 
If you feel that we have not met these 
requirements, send us comments by one 
of the methods listed in the ADDRESSES  
section. To better help us revise the 
rule, your comments should be as specific as possible. For example, you should tell us the numbers of the sections or paragraphs that you find unclear, which sections or sentences are too long, the sections where you feel lists or tables would be useful, etc. 
Public Availability of Comments 
Before including your address, phone 
number, email address, or other 
personal identifying information in your comment, you should be aware that your entire comment—including your 
personal identifying information—may be made publicly available at any time. While you can ask us in your comment to withhold your personal identifying information from public review, we cannot guarantee that we will be able to do so. 
Severability 
If a court holds any provisions of a 
subsequent final rule or their 
applicability to any person 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, 
Environmental impact statements, Environmental protection, Government contracts, Incorporation by reference, Investigations, Oil and gas exploration, Penalties, Pipelines, Public lands— mineral resources, Public lands—rights- of-way, Reporting and recordkeeping requirements, Sulphur. 
Dated: December 7, 2017. 
Katharine S. MacGregor, 
Deputy Assistant Secretary—Land and 
Minerals Management, Exercising the authority of the 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) proposes to amend 30 CFR part 250 as follows: PART 250—OIL AND GAS AND 
SULPHUR OPERATIONS IN THE OUTER CONTINENTAL SHELF 
■1. The authority citation for part 250 
continues to read as follows: 
Authority: 30 U.S.C. 1751; 31 U.S.C. 9701; 
33 U.S.C. 1321(j)(1)(C); 43 U.S.C. 1334. 
■2. Amend § 250. 198 by revising 
paragraphs (g)(1),(2), and (3), (h)(1), (51), (52), (53), (55), (56), (58), (59), (60), (61), (62), (65), (68), (70), (71), (73), (74), and (96) to read as follows: 
§ 250.198 Documents incorporated by 
reference. 
* * * * * 
(g) * * * 
(1) ANSI/ASME Boiler and Pressure 
Vessel Code, Section I, Rules for 
Construction of Power Boilers; including Appendices, 2017 Edition; and July 2017 Addenda, and all Section I Interpretations Volume 55, incorporated by reference at §§ 250.851(a), and 250.1629(b). 
(2) ANSI/ASME Boiler and Pressure 
Vessel Code, Section IV, Rules for Construction of Heating Boilers; including Appendices 1, 2, 3, 5, 6, and Non-mandatory Appendices B, C, D, E, F, H, I, K, L, and M, and the Guide to Manufacturers Data Report Forms, 2017 Edition; July 2017 Addenda, and all Section IV Interpretations Volume 55, incorporated by reference at §§ 250.851(a) and 250.1629(b). 
(3) ANSI/ASME Boiler and Pressure 
Vessel Code, Section VIII, Rules for Construction of Pressure Vessels; Divisions 1 and 2, 2017 Edition; July 2017 Addenda, Divisions 1, 2, and 3 and all Section VIII Interpretations Volumes 54 and 55, incorporated by reference at §§ 250.851(a) and 250.1629(b). 
* * * * * 
(h) * * * 
(1) API 510, Pressure Vessel 
Inspection Code: In-Service Inspection, 
Rating, Repair, and Alteration, Downstream Segment, Tenth Edition, May 2014; Addendum 1, May 2017; incorporated by reference at §§ 250.851(a) and 250.1629(b); 
* * * * * 
(51) API STD 2RD, Dynamic Risers for 
Floating Production Systems, Second 
Edition, September 2013; incorporated by reference at §§ 250.292, 250.733, 250.800(c), 250.901(a), (d), and 250.1002(b); 
(52) API RP 2SK, Recommended 
Practice for Design and Analysis of Stationkeeping Systems for Floating Structures, Third Edition, October 2005, Addendum, May 2008, Reaffirmed June 2015; incorporated by reference at §§ 250.800(c) and 250.901(a) and (d); (53) API RP 2SM, Recommended 
Practice for Design, Manufacture, Installation, and Maintenance of Synthetic Fiber Ropes for Offshore Mooring, Second Edition, July 2014; incorporated by reference at §§ 250.800(c) and 250.901; 
* * * * * 
(55) ANSI/API RP 14B, Recommended 
Practice for Design, Installation, Repair 
and Operation of Subsurface Safety Valve Systems, Sixth Edition, September 2015; incorporated by reference at §§ 250.802(b), 250.803(a), 250.814(d), 250.828(c), and 250.880(c); 
(56) API RP 14C, Recommended 
Practice for Analysis, Design, Installation, and Testing of Safety Systems for Offshore Production Facilities, Eight Edition, February 2017; incorporated by reference at §§ 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); 
* * * * * 
(58) 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 §§ 250.114(c), 250.842(c), 250.862(e), and 250.1629(b); 
(59) API RP 14FZ, Recommended 
Practice for Design and Installation 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 §§ 250.114(c), 250.842(c), 250.862(e), and 250.1629(b); 
(60) API RP 14G, Recommended 
Practice for Fire Prevention and Control on Fixed Open-type Offshore Production Platforms, Fourth Edition, April 2008, reaffirmed January 2013; incorporated by reference at §§ 250.859(a), 250.862(e), 250.880(c), and 250.1629(b); 
(61) 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 §§ 250.820, 250.834, 250.836, and 250.880(c); 
(62) API RP 14J, Recommended 
Practice for Design and Hazards 
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Analysis for Offshore Production 
Facilities, Second Edition, May 2001; Reaffirmed: January 2013; incorporated by reference at §§ 250.800(b) and (c), 250.842(c), and 250.901(a); 
* * * * * 
(65) 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, API Stock No. C50002; incorporated by reference at §§ 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); 
* * * * * 
(68) ANSI/API Specification Q1 
(ANSI/API Spec. Q1), Specification for 
Quality Programs for the Petroleum, Petrochemical and Natural Gas Industry, Ninth Edition, June 1, 2014; Errata, February 2014; Errata 2, March 2014; Addendum 1, June 2016; incorporated by reference at §§ 250.730, 250.801(b) and (c); 
* * * * * 
(70) ANSI/API Specification 6A 
(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 §§ 250.730, 250.802(a), 250.803(a), 250.833, 250.873(b), 250.874(g), and 250.1002(b); 
(71) 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 §§ 250.802(a), 250.833, 250.873(b), and 250.874(g); 
* * * * * 
(73) ANSI/API Spec. 14A, 
Specification for Subsurface Safety Valve Equipment, 12th Ed. January 
2015; Errata, July 2015; Addendum, June 2017; incorporated by reference at §§ 250.802(b) and 250.803(a); 
(74) ANSI/API Spec. 17J, 
Specification for Unbonded Flexible Pipe, Fourth Edition, May 2014; Errata 1, September 2016; Errata 2, May 2017; incorporated by reference at §§ 250.852(e), 250.1002(b), and 250.1007(a). 
* * * * * 
(96) 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 § 250.841(b). 
* * * * * 
■3. Amend § 250.292 by revising 
paragraph (p)(3) to read as follows: 
§ 250.292 What must the DWOP contain? 
* * * * * 
(p) * * * 
(3) A description of how you met the 
design requirements, load cases, and 
allowable stresses for each load case according to API STD 2RD (as incorporated by reference in § 250.198); 
* * * * * 
■4. Amend § 250.800 revise paragraph 
(c)(2) to read as follows: 
§ 250.800 General. 
* * * * * 
(c) * * * 
(2) Meet the production riser 
standards of API STD 2RD (incorporated 
by reference as specified in § 250.198), provided that you may not install single bore production risers from floating production facilities; 
* * * * * 
■5. Amend § 250.801 by revising 
paragraph (a) to read as follows: 
§ 250.801 Safety and pollution prevention 
equipment (SPPE) certification. 
(a) SPPE equipment. You must install 
only safety and pollution prevention 
equipment (SPPE) considered certified under paragraph (b) of this section or accepted under paragraph (c) of this section. BSEE considers the following 
equipment to be types of SPPE: (1) Surface safety valves (SSV) and 
actuators, including those installed on injection wells capable of natural flow; 
(2) Boarding shutdown valves (BSDV) 
and their actuators. For subsea wells, the BSDV is the surface equivalent of an SSV on a surface well; 
(3) Underwater safety valves (USV) 
and actuators; 
(4) Subsurface safety valves (SSSV) 
and associated safety valve locks and landing nipples; and 
(5) Gas lift shutdown valves (GLSDV) 
and their actuators. 
* * * * * 
■6. Amend § 250.802 paragraphs (a), 
(c), and (d) to read as follows: 
§ 250.802 Requirements for SPPE. 
(a) All SSVs, BSDVs, USVs, and 
GLSDVs and their actuators must meet 
all of the specifications contained in ANSI/API Spec. 6A and API Spec. 6AV1 (both incorporated by reference as specified in § 250.198). 
* * * * * 
(c) Requirements derived from the 
documents incorporated in this section 
for SSVs, BSDVs, USVs, USVs, GLSDVs, and their actuators, include, but are not limited to, the following: 
(1) All materials and parts must meet 
the original equipment manufacturer specifications and acceptance criteria. 
(2) The device must pass applicable 
validation tests and functional tests performed by an API-licensed test agency. 
(3) You must have requalification 
testing performed following manufacture design changes. 
(4) You must comply with and 
document all manufacturing, traceability, quality control, and inspection requirements. 
(5) You must follow specified 
installation, testing, and repair protocols. 
(6) You must use only qualified parts, 
procedures, and personnel to repair or redress equipment. 
(d) You must install and use SPPE 
according to the following table. 
If . . . Then . . . 
(1) You need to install any SPPE ............................................................ You must install SPPE that conforms to § 250.801. 
(2) A non-certified SPPE is already in service ......................................... It may remain in service. 
(3) A non-certified SPPE requires offsite repair, re-manufacturing, or 
any hot work such as welding.You must replace it with SPPE that conforms to § 250.801. 
* * * * * 
■7. Revise § 250.803 to read as follows: § 250.803 What SPPE failure reporting 
procedures must I follow? 
(a) You must follow the failure 
reporting requirements contained in section 10.20.7.4 of ANSI/API Spec. 6A 
SSVs, BSDVs, GLSDVs and USVs and section 7.10 of ANSI/API Spec. 14A and Annex F of API RP 14B for SSSVs (all 
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incorporated by reference in § 250.198). 
Within 30 days after the discovery and identification of the failure, you must provide a written notice of equipment failure to the manufacturer of such equipment and to BSEE through the Chief, Office of Offshore Regulatory Programs, unless BSEE has designated a third party as provided in paragraph (d) of this section. A failure is any condition that prevents the equipment from meeting the functional specification or purpose. 
(b) You must ensure that an 
investigation and a failure analysis are performed within 120 days of the failure to determine the cause of the failure. If the investigation and analyses are performed by an entity other than the manufacturer, you must ensure that the analysis report is submitted to the manufacturer and to BSEE through the Chief, Office of Offshore Regulatory Programs, unless BSEE has designated a third party as provided in paragraph (d) of this section. You must also ensure that the results of the investigation and any corrective action are documented in the analysis report. 
(c) 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 BSEE through the Chief, Office of Offshore Regulatory Programs, unless BSEE has designated a third party as provided in paragraph (d) of this section. 
(d) BSEE may designate a third party 
to receive this data on behalf of BSEE. If BSEE designates a third party, you must submit the information required in this section to the designated third party, as directed by BSEE. 
■8. Amend § 250.814 by revising 
paragraph (d) to read as follows: 
§ 250.814 Design, installation, and 
operation of SSSVs—dry trees. 
* * * * * 
(d) You must design, install, maintain, 
inspect, repair, and test all SSSVs in 
accordance with ANSI/API RP 14B (incorporated by reference as specified in § 250.198). For additional SSSV testing requirements, refer to § 250.880. 
■9. Revise § 250.820 to read as follows: 
§ 250.820 Use of SSVs. 
You must install, maintain, inspect, 
repair, and test all SSVs in accordance with API STD 6AV2 (incorporated by reference as specified in § 250.198). If any SSV does not operate properly, or if any gas and/or liquid fluid flow is observed during the leakage test as described in § 250.880, then you must 
shut-in all sources to the SSV and repair or replace the valve before resuming production. 
■10. Amend § 250.821 by revising 
paragraph (a) to read as follows: 
§ 250.821 Emergency action and safety 
system shutdown—dry trees. 
(a) If your facility is impacted or will 
potentially be impacted by an 
emergency situation (e.g., an impending 
National Weather Service-named tropical storm or hurricane, ice events in the Arctic, or post-earthquake), you must: 
(1) Properly install a subsurface safety 
device on any well that is not yet equipped with a subsurface safety device and that is capable of natural flow, as soon as possible, with due consideration being given to personnel 
safety. 
* * * * * 
■11. Amend § 250.828 by revising 
paragraph (c) to read as follows: 
§ 250.828 Design, installation, and 
operation of SSSVs—subsea trees. 
* * * * * 
(c) You must design, install, maintain, 
inspect, repair, and test all SSSVs in 
accordance with your Deepwater Operations Plan (DWOP) and ANSI/API RP 14B (incorporated by reference as specified in § 250.198). For additional SSSV testing requirements, refer to § 250.880. 
■12. Amend § 250.833, by revising the 
introductory text to read as follows: 
§ 250.833 Specification for underwater 
safety valves (USVs). 
All USVs, including those designated 
as primary or secondary, and any 
alternate isolation valve (AIV) that acts as a USV, if applicable, and their actuators, must conform to the requirements specified in §§ 250.801 through 250.803. A production master or wing valve may qualify as a USV under ANSI/API Spec. 6A and API Spec. 6AV1 (both incorporated by reference as specified in § 250.198). 
* * * * * 
■13. Revise § 250.834 to read as 
follows: 
§ 250.834 Use of USVs. 
You must install, maintain, inspect, 
repair, and test any valve designated as 
the primary USV in accordance with this subpart, your DWOP (as specified in §§ 250.286 through 250.295), and API STD 6AV2 (incorporated by reference as specified in § 250.198). For additional USV testing requirements, refer to § 250.880. 
■14. Revise § 250.836 to read as 
follows: § 250.836 Use of BSDVs. 
You must install, inspect, maintain, 
repair, and test all new BSDVs and BSDVs that you remove from service for remanufacturing or repair in accordance with API STD 6AV2 (incorporated by reference as specified in § 250.198) for SSVs. If any BSDV does not operate properly or if any gas fluid and/or liquid fluid flow is observed during the leakage test, as described in § 250.880, you must shut-in all sources to the BSDV and immediately repair or replace the valve. 
■15. Amend § 250.837 by revising 
paragraphs (a), (b), and (c)(5) to read as follows: 
§ 250.837 Emergency action and safety 
system shutdown—subsea trees. 
(a) If your facility is impacted or will 
potentially be impacted by an 
emergency situation (e.g., an impending 
National Weather Service-named tropical storm or hurricane, ice events in the Arctic, or post-earthquake), you must shut-in all subsea wells unless otherwise approved by the District Manager. A shut-in is defined as a closed BSDV, USV, GLSDV, and surface-controlled SSSV. 
(b) When operating a vessel (e.g., 
mobile offshore drilling unit (MODU) or other type of workover or intervention vessel) in an area with subsea infrastructure, you must: 
(1) Suspend production from all such 
wells that could be affected by a dropped object, including upstream wells that flow through the same pipeline; or 
(2) Establish direct, real-time 
communications between the vessel and the production facility control room and develop a dropped objects plan, as required in § 250.714. If an object is dropped, you must immediately secure the well directly under the vessel while simultaneously communicating with the platform to shut-in all affected wells. You must also maintain without disruption, and continuously verify, communication between the production facility and the vessel. If communication is lost between the vessel and the platform for 20 minutes or more, you must shut-in all wells that could be affected by a dropped object. 
(c) * * * 
(5) Subsea ESD (vessel). In the event 
of an ESD activation that is initiated by 
a dropped object from a vessel, you must secure all wells in the proximity of the vessel by closing the USVs and surface-controlled SSSVs in accordance with the applicable tables in §§ 250.838 and 250.839. You must notify the 
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appropriate District Manager before 
resuming production. 
* * * * * 
■16. Amend § 250.841, by adding 
paragraph (c) to read as follows: 
§ 250.841 Platforms. 
* * * * * 
(c) If you plan to make a major 
modification to any facility you must 
follow the requirements in § 250.900(b)(2). A major modification is defined in § 250.900(b)(2). ■17. Amend § 250. 842 by: 
■a. Revising paragraph (a); 
■b. Removing paragraph (c); 
■c. Redesignating paragraph (b) as 
paragraph (c); 
■d. Adding a new paragraph (b); 
■e. Revising paragraph (d); 
■f. Removing paragraph (e); and 
■g. Redesignating existing paragraph (f) 
as (e) to read as follows: § 250.842 Approval of safety systems 
design and installation features. 
(a) Before you install or modify a 
production safety system, you must 
submit a production safety system application to the District Manager. The District Manager must approve your production safety system application before you commence production through or utilize the new or modified system. The application must include the information prescribed in the following table: 
You must submit: Details and/or additional requirements: 
(1) Safety analysis flow diagram (API RP 14C, Annex B) and Safety 
Analysis Function Evaluation (SAFE) chart (API RP 14C, section 
6.3.3) (incorporated by reference in 2500.198).Your safety analysis flow diagram must show the following: (i) Well shut-in tubing pressure; (ii) Piping specification breaks, piping sizes; 
(iii) Pressure relieving device set points; 
(iv) Size, capacity, and design working pressures of separators, flare 
scrubbers, heat exchangers, treaters, storage tanks, compressors and metering devices; 
(v) Size, capacity, design working pressures, and maximum discharge 
pressure of hydrocarbon-handling pumps; 
(vi) Size, capacity, and design working pressures of hydrocarbon-han-
dling vessels, and chemical injection systems handling a material having a flash point below 100 degrees Fahrenheit for a Class I flammable liquid as described in API RP 500 and API RP 505 (both incorporated by reference as specified in § 250.198); and 
(vii) Size and maximum allowable working pressures as determined in 
accordance with API RP 14E (incorporated by reference as specified in § 250.198). 
(2) Electrical one-line diagram ................................................................. Showing elements, including gen erators, circuit breakers, transformers, 
bus bars, conductors, battery banks, automatic transfer switches, uninterruptable power supply (UPS), dynamic (motor) loads, and static (e.g., electrostatic treater grid, lighting panels, etc.) loads. You 
must also include a functional legend. 
(3) Area classification diagram ................................................................. A plan for each platform deck and outlining all classified areas. You 
must classify areas according to API RP 500 or API RP 505 (both in-corporated by reference as specified in § 250.198). The plan must contain: 
(i) All major production equipment, wells, and other significant hydro-
carbon and class 1 flammable sources, and a description of the type of decking, ceiling, walls (e.g., grating or solid), and firewalls; and 
(ii) The location of generators, control rooms, motor control center 
(MCC) buildings, and any other building or major structure on the platform. 
(4) A schematic piping and instrumentation diagram, for new facilities .. A detailed diagram which shows the piping and vessels i n the process 
flow, together with the instrumentation and control devices. 
(5) The service fee listed in § 250.125 ..................................................... The fee you must pay will be determined by the number of compo-
nents involved in the review and approval process. 
(b) You must develop and maintain 
the following diagrams and make them 
available to BSEE upon request: 
Diagram: Details and/or additional requirements: 
(1) Additional electrical system information, ............................................ (i) Cable tray/conduit routing plan which identifies the primary wiring 
method (e.g., type cable, conduit, wire); 
(ii) Cable schedule; and 
(iii) Panel board/junction box location plan. 
(2) Schematics of the fire and gas-detection systems ............................. Showing a functional block diagram of the dete ction system, including 
the electrical power supply and also including the type, location, and 
number of detection sensors; the type and kind of alarms, including emergency equipment to be activated; the method used for detec-tion; and the method and frequency of calibration. 
(3) Revised P&ID for existing facilities ..................................................... A detailed diagram which shows the  piping and vessels in the process 
flow, together with the instrumentation and control devices. 
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(c) In the production safety system 
application, you must also certify the 
following: 
(1) That all electrical installations 
were designed according to API RP 14F or API RP 14FZ, as applicable (incorporated by reference as specified in § 250.198); 
(2) That the designs for the 
mechanical and electrical systems that you are required to submit under paragraph (a) of this section were reviewed, approved, and stamped by an appropriate registered professional engineer(s). For modified systems, only the modifications are required to be approved and stamped by an appropriate registered professional engineer(s). The registered professional engineer must be registered in a State or Territory of the United States and have sufficient expertise and experience to perform the duties; and 
(3) That a hazards analysis was 
performed in accordance with § 250.1911 and API RP 14J (incorporated by reference as specified in § 250.198), and that you have a hazards analysis program in place to assess potential hazards during the operation of the facility. 
(d) Within 60 days after production 
commences, you must submit to the District Manager the as-built diagrams for the new or modified production safety systems outlined in paragraphs (a)(1), (2), and (3) of this section, the diagrams must be reviewed, approved, and stamped by an appropriate registered professional engineer(s). The registered professional engineer must be registered in a State or Territory in the United States and have sufficient expertise and experience to perform the duties. 
■18. Amend § 250.851 by revising 
paragraph (a)(2) to read as follows: 
§ 250.851 Pressure vessels (including heat 
exchangers) and fired vessels. 
(a) * * * 
Item name Applicable codes and requirements 
*******  
(2) Existing uncoded pressure and fired vessels; (i) with an operating pressure 
greater than 15 psig; and (ii) that are not code stamped in accordance with the ANSI/ASME Boiler and Pressure Vessel Code.Must be justified and approval obtained from the District 
Manager for their continued use. 
*******  
* * * * * 
■19. Amend § 250.852 by revising 
paragraphs (e)(1) and (e)(4) to read as 
follows: 
§ 250.852 Flowlines/Headers. 
* * * * * 
(e) * * * 
(1) Review the manufacturer’s Design 
Methodology Verification Report and 
the independent verification agent’s (IVA’s) certificate for the design methodology contained in that report to ensure that the manufacturer has complied with the requirements of ANSI/API Spec. 17J (incorporated by reference as specified in § 250.198); 
***  
(4) Submit to the District Manager a 
statement certifying that the pipe is 
suitable for its intended use and that the manufacturer has complied with the IVA requirements of ANSI/API Spec. 17J (incorporated by reference as specified in § 250.198). 
* * * * * 
■20. Amend § 250.853 by adding 
paragraph (d) to read as follows: 
§ 250.853 Safety sensors. 
* * * * * 
(d) All level sensors are equipped to 
permit testing through an external bridle 
on all new vessel installations where possible, depending on the type of vessel for which the level sensor is used. 
■21. Amend § 250.867 by revising 
paragraph (a) and adding paragraph (d) to read as follows: § 250.867 Temporary quarters and 
temporary equipment. 
(a) You must equip temporary 
quarters with all safety devices required 
by API RP 14C, Annex G (incorporated by reference as specified in § 250.198). The District Manager must approve the safety system/safety devices associated with the temporary quarters prior to installation. 
* * * * * 
(d) The District Manager must 
approve temporary generators that 
would require a change to the electrical one-line diagram in § 250.842(a). 
■22. Amend § 250.870 by revising 
paragraph (a) to read as follows: 
§ 250.870 Time delays on pressure safety 
low (PSL) sensors. 
(a) You may apply industry standard 
Class B, Class C, or Class B/C logic to 
applicable PSL sensors installed on process equipment. If the device may be bypassed for greater than 45 seconds, you must monitor the bypassed devices in accordance with § 250.869(a). You must document on your field test records any use of a PSL sensor with a time delay greater than 45 seconds. For purposes of this section, PSL sensors are categorized as follows: 
* * * * * 
■23. Revise § 250.872 to read as 
follows: 
§ 250.872 Atmospheric vessels. 
(a) You must equip atmospheric 
vessels used to process and/or store 
liquid hydrocarbons or other Class I liquids as described in API RP 500 or 505 (both incorporated by reference as specified in § 250.198) with protective equipment identified in API RP 14C, section A.6 (incorporated by reference as specified in § 250.198). Transport tanks approved by the U.S. Department of Transportation, that are sealed and not connected via interconnected piping to the production process train and that are used only for storage of refined liquid hydrocarbons or Class I liquids, are not required to be equipped with the protective equipment identified in API RP 14C, section A.5. The atmospheric vessels connected to the process system that contains a Class I liquid and the associated pumps must be reflected on the corresponding drawings. 
(b) You must ensure that all 
atmospheric vessels are designed and maintained to ensure the proper working conditions for LSH sensors. The LSH must be designed in such a way to prevent pollution as required by § 250.300(b)(3) and (4). The LSH sensor bridle must be designed to prevent different density fluids from impacting sensor functionality. For newly installed atmospheric vessels that have oil buckets, the LSH sensor must be installed to sense the level in the oil bucket. 
■24. Amend § 250.873 by revising 
paragraph (b)(3) to read as follows: 
§ 250.873 Subsea gas lift requirements. 
* * * * * 
(b) * * * 
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If your subsea gas 
lift system introduces the lift gas to the . . . Then you must install a 
In addition, you must ANSI/API Spec 6A and API Spec 6AV1 (both incorporated by reference as specified in § 250.198) gas-lift shutdown valve (GLSDV), and . . . FSV on the gas-lift supply pipeline ...  PSHL on the gas- lift supply . . . ANSI/API Spec 6A and API Spec 6AV1 manual iso-lation valve . . . 
*******  
(3) Pipeline risers 
via a gas-lift line 
contained within the pipeline riser.Meet all of the requirements for the 
GLSDV described in §§ 250.835(a), (b), and (d) and 250.836 on the gas-lift supply pipeline. Attach the GLSDV by flanged connection di-rectly to the ANSI/API Spec. 6A component used to suspend and seal the gas-lift line contained with-in the production riser. To facilitate the repair or replacement of the GLSDV or production riser BSDV, you may install a manual isolation valve between the GLSDV and the ANSI/API Spec. 6A component used to suspend and seal the gas- lift line contained within the produc-tion riser, or outboard of the pro-duction riser BSDV and inboard of the ANSI/API Spec. 6A component used to suspend and seal the gas- lift line contained within the produc-tion riser.upstream (in- 
board) of the GLSDV.flowline upstream 
(in-board) of the FSV.downstream (out 
board) of the GLSDV.(i) Ensure that the gas-lift supply 
flowline from the gas-lift com-pressor to the GLSDV is pressure- rated for the MAOP of the pipeline riser. 
(ii) Ensure that any surface equipment 
associated with the gas-lift system 
is rated for the MAOP of the pipe-line riser. 
(iii) Ensure that the gas-lift com-
pressor discharge pressure never 
exceeds the MAOP of the pipeline riser. 
(iv) Suspend and seal the gas-lift 
flowline contained within the pro-duction riser in a flanged ANSI/API Spec. 6A component such as an ANSI/API Spec. 6A tubing head and tubing hanger or a component designed, constructed, tested, and installed to the requirements of ANSI/API Spec. 6A. 
(v) Ensure that all potential leak paths 
upstream or near the production riser BSDV on the platform provide the same level of safety and envi-ronmental protection as the produc-tion riser BSDV. 
(vi) Ensure that this complete assem-
bly is fire-rated for 30 minutes. 
* * * * * 
■25. Amend § 250.874 by revising 
paragraph (g)(2) to read as follows: 
§ 250.874 Subsea water injection systems. 
* * * * * 
(g) * * * 
(2) If a designated USV on a water 
injection well fails the applicable test 
under § 250.880(c)(4)(ii), you must notify the appropriate District Manager and request approval to designate another ANSI/API Spec 6A and API Spec. 6AV1 (both incorporated by reference as specified in § 250.198) certified subsea valve as your USV. 
* * * * * 
■26. Revise § 250.876 to read as 
follows: § 250.876 Fired and exhaust heated 
components. 
No later than September 7, 2018, and 
at least once every 5 years thereafter, 
you must have a qualified third-party inspect, and then you must repair or replace, as needed, the fire tube for tube-type heaters that are equipped with either automatically controlled natural or forced draft burners installed in either atmospheric or pressure vessels that heat hydrocarbons and/or glycol. If inspection indicates tube-type heater deficiencies, you must complete and document repairs or replacements. You must document the inspection results, retain such documentation for at least 5 years, and make the documentation 
available to BSEE upon request. ■27. Amend § 250.880 by revising 
paragraphs (a) introductory text, (a)(1) 
(c)(1)(i), (c)(2)(iv), (c)(4)(i) and (iii) to read as follows: 
§ 250.880 Production safety system 
testing. 
(a) Notification. You must: 
(1) Notify the District Manager at least 
72 hours before you commence initial 
production on a facility, so that BSEE may conduct a preproduction inspection of the integrated safety system. 
* * * * * 
(c) * * * 
(1) * * * 
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Item name Testing frequency, allowable leakage rates, and other requirements 
(i) Surface-controlled SSSVs (including 
devices installed in shut-in and injec-
tion wells.Semi-annually, not to exceed 6 calendar months between tests. Also test in place when first installed 
or reinstalled. If the device does not operate properly, or if a liquid leakage rate >400 cubic centi-meters per minute or a gas leakage rate >15 standard cubic feet per minute is observed, the de-vice must be removed, repaired, and reinstalled or replaced. Testing must be according to ANSI/ API RP 14B (incorporated by reference as specified in § 250.198) to ensure proper operation. 
*******  
* * * * * (2) * * * 
Item name Testing frequency and requirements 
*******  
(iv) SSVs .................................................. Once each calendar month, not to exceed 6 weeks between tests. Valves must be tested for both 
operation and leakage. You must test according to API STD 6AV2 (incorporated by reference as specified in § 250.198). If an SSV does not operate properly or if any gas and/or liquid fluid flow is observed during the leakage test, the valve must be immediately repaired or replaced. 
*******  
* * * * * (4) * * * 
Item name Testing frequency, allowable leakage rates, and other requirements 
(i) Surface-controlled SSSVs (including 
devices installed in shut-in and injec-tion wells).Tested semiannually, not to exceed 6 months between tests. If the device does not operate properly, 
or if a liquid leakage rate >400 cubic centimeters per minute or a gas leakage rate >15 standard cubic feet per minute is observed, the device must be removed, repaired, and reinstalled or re-placed. Testing must be according to ANSI/API RP 14B (incorporated by reference as specified in § 250.198) to ensure proper operation, or as approved in your DWOP. 
*******  
(iii) BSDVs ............................................... Tested at least once each calendar month, not to exceed 6 weeks between tests. Valves must be 
tested for both operation and leakage. You must test according to API STD 6AV2 for SSVs (incor-porated by reference as specified in § 250.198). If a BSDV does not operate properly or if any fluid flow is observed during the leakage test, the valve must be immediately repaired or replaced. 
*******  
* * * * * 
■28. Amend § 250.901 by revising 
paragraph (a)(10) and (d)(19) to read as 
follows: 
§ 250.901 What industry standards must 
your platform meet? 
(a) * * * 
(10) API STD 2RD, Design of Risers 
for Floating Production Systems (FPSs) 
and Tension-Leg Platforms (TLPs), (as incorporated by reference in § 250.198); 
* * * * * 
(d) * * * 
(19) API STD 2RD, Design of Risers 
for Floating Production Systems (FPSs) 
and Tension-Leg Platforms (TLPs); 
* * * * * 
■29. Amend § 250.1002 by revising 
paragraphs (b)(1), (2), (4) and (5) to read 
as follows: 
§ 250.1002 Design requirements for DOI 
pipelines. 
* * * * * 
(b)(1) Pipeline valves shall meet the 
minimum design requirements of ANSI/ API Spec 6A (as incorporated by 
reference in § 250.198), API Spec 6D (as incorporated by reference in § 250.198), or the equivalent. A valve may not be used under operating conditions that exceed the applicable pressure- temperature ratings contained in those standards. 
(2) Pipeline flanges and flange 
accessories shall meet the minimum design requirements of ANSI B16.5, 
ANSI/API Spec 6A, or the equivalent (as incorporated by reference in 30 CFR 250.198). Each flange assembly must be able to withstand the maximum pressure at which the pipeline is to be operated and to maintain its physical and chemical properties at any temperature to which it is anticipated that it might be subjected in service. 
* * * * * 
(4) If you are installing pipelines 
constructed of unbonded flexible pipe, 
you must design them according to the standards and procedures of ANSI/API Spec 17J, as incorporated by reference 
in 30 CFR 250.198. 
(5) You must design pipeline risers for 
tension leg platforms and other floating platforms according to the design standards of API STD 2RD, Design of Risers for Floating Production Systems (FPSs) and Tension Leg Platforms (TLPs) (as incorporated by reference in § 250.198). 
* * * * * 
■30. Amend § 250.1007 by revising 
paragraph (a)(4)(i)(D) to read as follows: 
§ 250.1007 What to include in applications. 
(a) * * * 
(4) * * * (i) * * * (D) A review by a third-party 
independent verification agent (IVA) 
according to ANSI/API Spec 17J (as incorporated by reference in § 250.198), if applicable. 
* * * * * 
[FR Doc. 2017–27309 Filed 12–28–17; 8:45 am] 
BILLING CODE 4310–VH–P 
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