[Federal Register Volume 82, Number 249 (Friday, December 29, 2017)]
[Proposed Rules]
[Pages 61703-61724]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2017-27309]


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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.

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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: [email protected]. 
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

[[Page 61704]]

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: [email protected].

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

[[Page 61705]]

``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 \1\ and 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.''
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    \1\ Oil and Gas and Sulfur Operations in the Outer Continental 
Shelf--Blowout Preventer Systems and Well Control, 81 FR 25887 
(April 29, 2016).
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    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.\2\ In addition to the 
free online availability of these standards for viewing on API's 
website, hardcopies and printable versions are available for purchase 
from API. The API website address to purchase standards is: http://www.api.org/publications-standards-and-statistics/publications/government-cited-safety-documents.
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    \2\ To view these standards online, go to the API publications 
website at: http://publications.api.org. You must then log-in or 
create a new account, accept API's ``Terms and Conditions,'' click 
on the ``Browse Documents'' button, and then select the applicable 
category (e.g., ``Exploration and Production'') for the standard(s) 
you wish to review.
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    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 [email protected].

E. Section-by-Section Discussion of Changes

Documents Incorporated by Reference (Sec.  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

[[Page 61706]]

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.

[[Page 61707]]

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.

[[Page 61708]]

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 
H2S-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

[[Page 61709]]

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 
Sec. Sec.  250.198(h)(58) and 250.198(h)(62) to update cross references 
to Sec.  250.842(b) that would change to Sec.  250.842(c) in this 
rulemaking.

What must the DWOP contain? (Sec.  250.292)

    BSEE is proposing to revise Sec.  250.292 paragraph (p)(3) to 
replace the incorporation by reference of API RP 2RD to API STD 2RD.

General (Sec.  250.800)

    BSEE is proposing to revise Sec.  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. (Sec.  
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 Sec.  250.801. Under Sec.  250.873 in the current 
regulations, GLSDVs must meet the requirements in Sec. Sec.  250.835 
and 250.836 for boarding shutdown valves (BSDVs). Further, Sec.  
250.835 requires that BSDVs meet the requirements in Sec. Sec.  250.801 
through 250.803. Since Sec.  250.835 currently requires that BSDVs meet 
the requirements in Sec.  250.801, and GLSDVs must meet the 
requirements for BSDVs in Sec.  250.835 pursuant to Sec.  250.873, it 
follows that GLSDVs are already required to meet the requirements of 
Sec.  250.801. BSEE proposes to revise Sec.  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 (Sec.  250.802)

    Consistent with the proposed revision to Sec.  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 Sec.  250.802(c)(1) and 
redesignate subsequent paragraphs under paragraph (c). Current Sec.  
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 Sec.  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 Sec.  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 Sec.  250.802(d) as clarifying ``when operators must install SPPE 
equipment that conforms to the requirements of Sec.  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 Sec. Sec.  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 Sec.  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? (Sec.  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

[[Page 61710]]

revising how ``failure'' is specified. The current Sec.  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 Sec.  250.803. The documents incorporated by 
reference in Sec.  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 Sec.  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 Sec. Sec.  
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 Sec. Sec.  
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 (Sec.  250.814)

    BSEE would revise Sec.  250.814 paragraph (d) to replace the 
incorporation by reference of API RP 14B with ANSI/API 14B.

Use of SSVs (Sec.  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 (Sec.  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 (Sec.  
250.828)

    BSEE would revise Sec.  250.828 paragraph (c) to replace the 
incorporation by reference of API RP 14B with ANSI/API 14B.

Specification for Underwater Safety Valves (USVs) (Sec.  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 (Sec.  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 (Sec.  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 (Sec.  
250.837)

    BSEE is proposing to revise paragraph (a) of this section to 
clarify that operators must shut in the production

[[Page 61711]]

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 Sec.  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 Sec. Sec.  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 Sec.  250.714. However, Sec.  
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, Sec.  
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 (Sec.  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 Sec.  250.900(b)(2). This is not a new requirement, as 
operators are already required to follow the provisions of Sec.  
250.900(b)(2) for major modifications. This simply provides direction 
to the operator and emphasizes the need to follow Sec.  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 (Sec.  
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 Sec.  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

[[Page 61712]]

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 Sec.  250.842(c)(3), which requires operators 
to perform a hazards analysis in accordance with Sec.  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, Sec.  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 
Sec.  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 Sec.  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 Sec.  250.842(d) regarding PE stamping 
of required drawings.
    The proposed rule would require the diagrams that are submitted to 
BSEE under Sec.  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 (Sec.  
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 (Sec.  250.852)

    BSEE is proposing to revise paragraphs Sec.  250.852(e)(1) and 
(e)(4) to replace the reference to API Spec. 17J with ANSI/API Spec. 
17J.

Safety Sensors (Sec.  250.853)

    This section would be revised to add a new paragraph (d) to require 
that all

[[Page 61713]]

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 
Sec.  250.141.

Temporary Quarters and Temporary Equipment (Sec.  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 Sec.  250.842(a).

Time Delays on Pressure Safety Low (PSL) Sensors (Sec.  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 Sec.  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 Sec.  
250.869(a). The alternative compliance approval is not needed, since 
monitoring bypassed devices is addressed in the current Sec.  
250.869(a), for which no change is proposed.

Atmospheric Vessels (Sec.  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 Sec.  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

[[Page 61714]]

vessels without extensive modifications to the vessels.
    BSEE is proposing to remove Sec.  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 Sec.  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 (Sec.  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 (Sec.  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 (Sec.  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 (Sec.  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 Sec.  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? (Sec.  250.901)

    BSEE is proposing to revise paragraph (a) of Sec.  250.901 and the 
table in paragraph (d) to update the incorporation by reference of API 
STD 2RD.

Design Requirements for DOI Pipelines (Sec.  250.1002)

    BSEE is proposing to revise paragraph (b) of Sec.  250.1002 to 
update the references to ANSI/API Spec. 6A, ANSI/API Spec. 17J, and API 
STD 2RD.

What To Include in Applications (Sec.  250.1007)

    BSEE is proposing to revise paragraphs (a) of Sec.  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 Sec.  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 Sec.  250.198 Documents Incorporated by 
Reference

    BSEE is considering potential, non-substantive revisions to Sec.  
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 Sec.  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 Sec.  250.803 what SPPE 
failure reporting procedures must I follow?

    BSEE is seeking input on clarifying when a failure analysis is 
required under Sec.  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 
Sec.  250.880 Production Safety System Testing

    BSEE also considered revising the requirements regarding PSV 
testing in Sec.  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 Sec.  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.

[[Page 61715]]

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 Sec.  250.842. The cost of independent 3rd party testing 
and certifications required under the Sec.  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 (Sec.  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,

[[Page 61716]]

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 Cost Savings Associated With Amendments to Subpart H
                                                    [2016 $]
----------------------------------------------------------------------------------------------------------------
                                                                                   Discounted at   Discounted at
                              Year                                 Undiscounted         3%              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

[[Page 61717]]

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:
     Sec.  250.802(c)(1) is being eliminated and would cause a 
reduction in non-hour costs burdens by -$550,000.
     Sec.  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 Sec.  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 Sec.  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;

[[Page 61718]]

    (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

0
 1. The authority citation for part 250 continues to read as follows:

    Authority:  30 U.S.C. 1751; 31 U.S.C. 9701; 33 U.S.C. 
1321(j)(1)(C); 43 U.S.C. 1334.

0
 2. Amend Sec.  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:


Sec.  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 Sec. Sec.  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 Sec. Sec.  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 
Sec. Sec.  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 
Sec. Sec.  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 Sec. Sec.  
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 Sec. Sec.  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 
Sec. Sec.  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 Sec. Sec.  
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 
Sec. Sec.  250.125(a), 250.292(j), 250.841(a), 250.842(a), 250.850, 
250.852(a), 250.855, 250.856(a), 250.858(a), 250.862(e), 250.865(a), 
250.867(a), 250.869(a) through (c), 250.872(a), 250.873(a), 250.874(a), 
250.880(b) and (c), 250.1002(d), 250.1004(b), 250.1628(c) and (d), 
250.1629(b), and 250.1630(a);
* * * * *
    (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 Sec. Sec.  
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 
Sec. Sec.  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 Sec. Sec.  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 
Sec. Sec.  250.820, 250.834, 250.836, and 250.880(c);
    (62) API RP 14J, Recommended Practice for Design and Hazards

[[Page 61719]]

Analysis for Offshore Production Facilities, Second Edition, May 2001; 
Reaffirmed: January 2013; incorporated by reference at Sec. Sec.  
250.800(b) and (c), 250.842(c), and 250.901(a);
* * * * *
    (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 Sec. Sec.  250.114(a), 250.459, 250.842(a), 250.862(a) 
and (e), 250.872(a), 250.1628(b) and (d), and 250.1629(b);
* * * * *
    (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 
Sec. Sec.  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 
Sec. Sec.  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 Sec. Sec.  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 Sec. Sec.  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 Sec. Sec.  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 Sec.  
250.841(b).
* * * * *
0
3. Amend Sec.  250.292 by revising paragraph (p)(3) to read as follows:


Sec.  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 Sec.  250.198);
* * * * *
0
4. Amend Sec.  250.800 revise paragraph (c)(2) to read as follows:


Sec.  250.800  General.

* * * * *
    (c) * * *
    (2) Meet the production riser standards of API STD 2RD 
(incorporated by reference as specified in Sec.  250.198), provided 
that you may not install single bore production risers from floating 
production facilities;
* * * * *
0
5. Amend Sec.  250.801 by revising paragraph (a) to read as follows:


Sec.  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.
* * * * *
0
6. Amend Sec.  250.802 paragraphs (a), (c), and (d) to read as follows:


Sec.  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 Sec.  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 Sec.   250.801.
(2) A non-certified SPPE is already in   It may remain in service.
 service.
(3) A non-certified SPPE requires        You must replace it with SPPE
 offsite repair, re-manufacturing, or     that conforms to Sec.
 any hot work such as welding.            250.801.
------------------------------------------------------------------------

* * * * *
0
7. Revise Sec.  250.803 to read as follows:


Sec.  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

[[Page 61720]]

incorporated by reference in Sec.  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.
0
8. Amend Sec.  250.814 by revising paragraph (d) to read as follows:


Sec.  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 Sec.  250.198). For additional SSSV testing 
requirements, refer to Sec.  250.880.
0
9. Revise Sec.  250.820 to read as follows:


Sec.  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 
Sec.  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 Sec.  250.880, then you must shut-in all sources to the 
SSV and repair or replace the valve before resuming production.
0
10. Amend Sec.  250.821 by revising paragraph (a) to read as follows:


Sec.  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.
* * * * *
0
11. Amend Sec.  250.828 by revising paragraph (c) to read as follows:


Sec.  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 Sec.  
250.198). For additional SSSV testing requirements, refer to Sec.  
250.880.
0
12. Amend Sec.  250.833, by revising the introductory text to read as 
follows:


Sec.  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 
Sec. Sec.  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 Sec.  250.198).
* * * * *
0
13. Revise Sec.  250.834 to read as follows:


Sec.  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 Sec. Sec.  250.286 through 250.295), and API STD 
6AV2 (incorporated by reference as specified in Sec.  250.198). For 
additional USV testing requirements, refer to Sec.  250.880.
0
14. Revise Sec.  250.836 to read as follows:


Sec.  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 
Sec.  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 Sec.  250.880, you must shut-in all sources to 
the BSDV and immediately repair or replace the valve.
0
15. Amend Sec.  250.837 by revising paragraphs (a), (b), and (c)(5) to 
read as follows:


Sec.  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 Sec.  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 Sec. Sec.  
250.838 and 250.839. You must notify the

[[Page 61721]]

appropriate District Manager before resuming production.
* * * * *
0
16. Amend Sec.  250.841, by adding paragraph (c) to read as follows:


Sec.  250.841  Platforms.

* * * * *
    (c) If you plan to make a major modification to any facility you 
must follow the requirements in Sec.  250.900(b)(2). A major 
modification is defined in Sec.  250.900(b)(2).
0
17. Amend Sec.  250. 842 by:
0
a. Revising paragraph (a);
0
b. Removing paragraph (c);
0
c. Redesignating paragraph (b) as paragraph (c);
0
d. Adding a new paragraph (b);
0
e. Revising paragraph (d);
0
f. Removing paragraph (e); and
0
g. Redesignating existing paragraph (f) as (e) to read as follows:


Sec.  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:

------------------------------------------------------------------------
                                            Details and/or additional
            You must submit:                      requirements:
------------------------------------------------------------------------
(1) Safety analysis flow diagram (API    Your safety analysis flow
 RP 14C, Annex B) and Safety Analysis     diagram must show the
 Function Evaluation (SAFE) chart (API    following:
 RP 14C, section 6.3.3) (incorporated    (i) Well shut-in tubing
 by reference in 2500.198).               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-handling 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 Sec.
                                            250.198); and
                                         (vii) Size and maximum
                                          allowable working pressures as
                                          determined in accordance with
                                          API RP 14E (incorporated by
                                          reference as specified in Sec.
                                            250.198).
(2) Electrical one-line diagram........  Showing 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.
                                          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 incorporated by
                                          reference as specified in Sec.
                                            250.198). The plan must
                                          contain:
                                         (i) All major production
                                          equipment, wells, and other
                                          significant hydrocarbon 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               A detailed diagram which shows
 instrumentation diagram, for new         the piping and vessels in the
 facilities.                              process flow, together with
                                          the instrumentation and
                                          control devices.
(5) The service fee listed in Sec.       The fee you must pay will be
 250.125.                                 determined by the number of
                                          components involved in the
                                          review and approval process.
------------------------------------------------------------------------

    (b) You must develop and maintain the following diagrams and make 
them available to BSEE upon request:

------------------------------------------------------------------------
                                            Details and/or additional
                Diagram:                          requirements:
------------------------------------------------------------------------
(1) Additional electrical system         (i) Cable tray/conduit routing
 information,.                            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-      Showing a functional block
 detection systems.                       diagram of the detection
                                          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
                                          detection; and the method and
                                          frequency of calibration.
(3) Revised P&ID for existing            A detailed diagram which shows
 facilities.                              the piping and vessels in the
                                          process flow, together with
                                          the instrumentation and
                                          control devices.
------------------------------------------------------------------------


[[Page 61722]]

    (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 Sec.  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 Sec.  
250.1911 and API RP 14J (incorporated by reference as specified in 
Sec.  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.
0
18. Amend Sec.  250.851 by revising paragraph (a)(2) to read as 
follows:


Sec.  250.851  Pressure vessels (including heat exchangers) and fired 
vessels.

    (a) * * *

------------------------------------------------------------------------
                                                Applicable codes and
                 Item name                          requirements
------------------------------------------------------------------------
 
                              * * * * * * *
(2) Existing uncoded pressure and fired     Must be justified and
 vessels; (i) with an operating pressure     approval obtained from the
 greater than 15 psig; and (ii) that are     District Manager for their
 not code stamped in accordance with the     continued use.
 ANSI/ASME Boiler and Pressure Vessel Code.
 
                              * * * * * * *
------------------------------------------------------------------------

* * * * *
0
19. Amend Sec.  250.852 by revising paragraphs (e)(1) and (e)(4) to 
read as follows:


Sec.  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 Sec.  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 Sec.  250.198).
* * * * *
0
20. Amend Sec.  250.853 by adding paragraph (d) to read as follows:


Sec.  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.
0
21. Amend Sec.  250.867 by revising paragraph (a) and adding paragraph 
(d) to read as follows:


Sec.  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 Sec.  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 Sec.  
250.842(a).
0
22. Amend Sec.  250.870 by revising paragraph (a) to read as follows:


Sec.  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 Sec.  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:
* * * * *
0
23. Revise Sec.  250.872 to read as follows:


Sec.  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 Sec.  250.198) 
with protective equipment identified in API RP 14C, section A.6 
(incorporated by reference as specified in Sec.  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 
Sec.  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.
0
24. Amend Sec.  250.873 by revising paragraph (b)(3) to read as 
follows:


Sec.  250.873  Subsea gas lift requirements.

* * * * *
    (b) * * *

[[Page 61723]]



--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                     Then you must install a
                                  ---------------------------------------------------------------------------------------------
                                    ANSI/API Spec 6A and API
  If your subsea gas lift system        Spec 6AV1 (both
 introduces the lift gas to the .  incorporated by reference   FSV on the gas-lift                        ANSI/API Spec 6A and    In addition, you must
               . .                    as specified in Sec.     supply pipeline . .  PSHL on the gas-lift  API Spec 6AV1 manual
                                       250.198) gas-lift                .               supply . . .       isolation valve . .
                                    shutdown valve (GLSDV),                                                         .
                                           and . . .
--------------------------------------------------------------------------------------------------------------------------------------------------------
 
                                                                      * * * * * * *
(3) Pipeline risers via a gas-     Meet all of the            upstream (in-board)   flowline upstream     downstream (out       (i) Ensure that the gas-
 lift line contained within the     requirements for the       of the GLSDV.         (in-board) of the     board) of the GLSDV.  lift supply flowline
 pipeline riser.                    GLSDV described in Sec.                          FSV.                                        from the gas-lift
                                    Sec.   250.835(a), (b),                                                                      compressor to the GLSDV
                                    and (d) and 250.836 on                                                                       is pressure-rated for
                                    the gas-lift supply                                                                          the MAOP of the
                                    pipeline. Attach the                                                                         pipeline riser.
                                    GLSDV by flanged                                                                            (ii) Ensure that any
                                    connection directly to                                                                       surface equipment
                                    the ANSI/API Spec. 6A                                                                        associated with the gas-
                                    component used to                                                                            lift system is rated
                                    suspend and seal the gas-                                                                    for the MAOP of the
                                    lift line contained                                                                          pipeline riser.
                                    within the production                                                                       (iii) Ensure that the
                                    riser. To facilitate the                                                                     gas-lift compressor
                                    repair or replacement of                                                                     discharge pressure
                                    the GLSDV or production                                                                      never exceeds the MAOP
                                    riser BSDV, you may                                                                          of the pipeline riser.
                                    install a manual                                                                            (iv) Suspend and seal
                                    isolation valve between                                                                      the gas-lift flowline
                                    the GLSDV and the ANSI/                                                                      contained within the
                                    API Spec. 6A component                                                                       production riser in a
                                    used to suspend and seal                                                                     flanged ANSI/API Spec.
                                    the gas-lift line                                                                            6A component such as an
                                    contained within the                                                                         ANSI/API Spec. 6A
                                    production riser, or                                                                         tubing head and tubing
                                    outboard of the                                                                              hanger or a component
                                    production riser BSDV                                                                        designed, constructed,
                                    and inboard of the ANSI/                                                                     tested, and installed
                                    API Spec. 6A component                                                                       to the requirements of
                                    used to suspend and seal                                                                     ANSI/API Spec. 6A.
                                    the gas-lift line                                                                           (v) Ensure that all
                                    contained within the                                                                         potential leak paths
                                    production riser.                                                                            upstream or near the
                                                                                                                                 production riser BSDV
                                                                                                                                 on the platform provide
                                                                                                                                 the same level of
                                                                                                                                 safety and
                                                                                                                                 environmental
                                                                                                                                 protection as the
                                                                                                                                 production riser BSDV.
                                                                                                                                (vi) Ensure that this
                                                                                                                                 complete assembly is
                                                                                                                                 fire-rated for 30
                                                                                                                                 minutes.
--------------------------------------------------------------------------------------------------------------------------------------------------------

* * * * *
0
25. Amend Sec.  250.874 by revising paragraph (g)(2) to read as 
follows:


Sec.  250.874  Subsea water injection systems.

* * * * *
    (g) * * *
    (2) If a designated USV on a water injection well fails the 
applicable test under Sec.  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 Sec.  250.198) certified subsea valve as your USV.
* * * * *
0
26. Revise Sec.  250.876 to read as follows:


Sec.  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.
0
27. Amend Sec.  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:


Sec.  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) * * *

[[Page 61724]]



------------------------------------------------------------------------
                                          Testing frequency, allowable
              Item name                     leakage rates, and other
                                                  requirements
------------------------------------------------------------------------
(i) Surface-controlled SSSVs           Semi-annually, not to exceed 6
 (including devices installed in shut-  calendar months between tests.
 in and injection wells.                Also test in place when first
                                        installed or reinstalled. 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 replaced. Testing
                                        must be according to ANSI/API RP
                                        14B (incorporated by reference
                                        as specified in Sec.   250.198)
                                        to ensure proper operation.
 
                              * * * * * * *
------------------------------------------------------------------------

* * * * *
    (2) * * *

------------------------------------------------------------------------
                                             Testing frequency and
              Item name                           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 Sec.   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) * * *

------------------------------------------------------------------------
                                          Testing frequency, allowable
              Item name                     leakage rates, and other
                                                  requirements
------------------------------------------------------------------------
(i) Surface-controlled SSSVs           Tested semiannually, not to
 (including devices installed in shut-  exceed 6 months between tests.
 in and injection wells).               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 replaced. Testing
                                        must be according to ANSI/API RP
                                        14B (incorporated by reference
                                        as specified in Sec.   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
                                        (incorporated by reference as
                                        specified in Sec.   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.
 
                              * * * * * * *
------------------------------------------------------------------------

* * * * *
0
28. Amend Sec.  250.901 by revising paragraph (a)(10) and (d)(19) to 
read as follows:


Sec.  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 Sec.  250.198);
* * * * *
    (d) * * *
    (19) API STD 2RD, Design of Risers for Floating Production Systems 
(FPSs) and Tension-Leg Platforms (TLPs);
* * * * *
0
29. Amend Sec.  250.1002 by revising paragraphs (b)(1), (2), (4) and 
(5) to read as follows:


Sec.  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 Sec.  250.198), 
API Spec 6D (as incorporated by reference in Sec.  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 Sec.  
250.198).
* * * * *
0
30. Amend Sec.  250.1007 by revising paragraph (a)(4)(i)(D) to read as 
follows:


Sec.  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 Sec.  
250.198), if applicable.
* * * * *
[FR Doc. 2017-27309 Filed 12-28-17; 8:45 am]
BILLING CODE 4310-VH-P