Oil and Gas and Sulphur Operations on the Outer Continental Shelf-Oil and Gas Production Safety Systems-Revisions, 61703-61724 [2017-27309]
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Federal Register / Vol. 82, No. 249 / Friday, December 29, 2017 / Proposed Rules
553, as any further delays in the process
for issuance of temporary scheduling
orders would be contrary to the public
interest in view of the urgent need to
control fentanyl-related substances to
avoid an imminent hazard to the public
safety.
Since this notice of intent is not a
‘‘rule’’ as defined by 5 U.S.C. 601(2), it
is not subject to the requirements of the
Regulatory Flexibility Act (RFA). The
requirements for the preparation of an
initial regulatory flexibility analysis in 5
U.S.C. 603(a) are not applicable where,
as here, the DEA is not required by
section 553 of the APA or any other law
to publish a general notice of proposed
rulemaking.
Additionally, this action is not a
significant regulatory action as defined
by Executive Order 12866 (Regulatory
Planning and Review), section 3(f), and,
accordingly, this action has not been
reviewed by the Office of Management
and Budget.
This action will not have substantial
direct effects on the States, on the
relationship between the national
government and the States, or on the
distribution of power and
responsibilities among the various
levels of government. Therefore, in
accordance with Executive Order 13132
(Federalism) it is determined that this
action does not have sufficient
federalism implications to warrant the
preparation of a Federalism Assessment.
List of Subjects in 21 CFR Part 1308
Administrative practice and
procedure, Drug traffic control,
Reporting and recordkeeping
requirements.
For the reasons set out above, the DEA
proposes to amend 21 CFR part 1308 as
follows:
PART 1308—SCHEDULES OF
CONTROLLED SUBSTANCES
1. The authority citation for part 1308
continues to read as follows:
■
Authority: 21 U.S.C. 811, 812, 871(b),
956(b), unless otherwise noted.
2. In § 1308.11, add paragraph (h)(30),
to read as follows:
■
§ 1308.11
Schedule I
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*
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(h) * * *
(30) Fentanyl-related substances, their
isomers, esters, ethers, salts and salts of
isomers, esters and ethers . . . 9850
(i) Fentanyl-related substance means
any substance not otherwise listed
under another Administration
Controlled Substance Code Number,
and for which no exemption or approval
is in effect under section 505 of the
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Federal Food, Drug, and Cosmetic Act
[21 U.S.C. 355], that is structurally
related to fentanyl by one or more of the
following modifications:
(A) Replacement of the phenyl
portion of the phenethyl group by any
monocycle, whether or not further
substituted in or on the monocycle;
(B) Substitution in or on the
phenethyl group with alkyl, alkenyl,
alkoxyl, hydroxyl, halo, haloalkyl,
amino or nitro groups;
(C) Substitution in or on the
piperidine ring with alkyl, alkenyl,
alkoxyl, ester, ether, hydroxyl, halo,
haloalkyl, amino or nitro groups;
(D) Replacement of the aniline ring
with any aromatic monocycle whether
or not further substituted in or on the
aromatic monocycle; and/or
(E) Replacement of the N-propionyl
group by another acyl group.
(ii) This definition includes, but is not
limited to, the following substances:
[Reserved]
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Dated: December 21, 2017.
Robert W. Patterson,
Acting Administrator.
[FR Doc. 2017–28114 Filed 12–28–17; 8:45 am]
BILLING CODE 4410–09–P
DEPARTMENT OF THE INTERIOR
Bureau of Safety and Environmental
Enforcement
30 CFR Part 250
[Docket ID: BSEE–2017–0008; 189E1700D2
ET1SF0000.PSB000 EEEE500000]
RIN 1014–AA37
Oil and Gas and Sulphur Operations
on the Outer Continental Shelf—Oil
and Gas Production Safety Systems—
Revisions
Bureau of Safety and
Environmental Enforcement, Interior.
ACTION: Proposed rule.
AGENCY:
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
SUMMARY:
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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: https://
www.regulations.gov. In the entry titled
Enter Keyword or ID, enter BSEE–2017–
0008, then click search. Follow the
instructions to submit public comments
and view supporting and related
materials available for this rulemaking.
The BSEE may post all submitted
comments.
• Mail or hand-carry comments to the
Department of the Interior (Department
or DOI); Bureau of Safety and
Environmental Enforcement; Attention:
Regulations Development Branch; 45600
Woodland Road, VAE–ORP, Sterling VA
20166. Please reference ‘‘Oil and Gas
Production Safety Systems—Revisions,
1014–AA37’’ in your comments and
include your name and return address.
• Send comments on the information
collection in this proposed rule to:
Interior Desk Officer 1014–0003, Office
of Management and Budget; 202–395–
5806 (fax); email: oira_submission@
omb.eop.gov. Please send a copy to
BSEE.
• Public Availability of Comments—
Before including your address, phone
number, email address, or other
personal identifying information in your
comment, you should be aware that
your entire comment—including your
personal identifying information—may
be made publicly available at any time.
In order for BSEE to withhold from
disclosure your personal identifying
information, you must identify any
information contained in the submittal
of your comments that, if released,
would constitute a clearly unwarranted
invasion of your personal privacy. You
must also briefly describe any possible
harmful consequence(s) of the
disclosure of information, such as
embarrassment, injury, or other harm.
While you can ask us in your comment
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Federal Register / Vol. 82, No. 249 / Friday, December 29, 2017 / Proposed Rules
to withhold your personal identifying
information from public review, we
cannot guarantee that we will be able to
do so.
FOR FURTHER INFORMATION CONTACT:
Amy White, Regulations and Standards
Branch, 703–787–1665 or by email:
regs@bsee.gov.
BSEE’s website at: https://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.
Table of Contents
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.
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:
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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
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B. Summary of the Rulemaking
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• Add gas lift shut down valves
(GLSDVs) to the list of safety and
pollution prevention equipment (SPPE).
• Revise requirements for SPPE to
clarify the existing regulations, and
remove the requirement for operators to
certify through an independent third
party that each device is designed to
function in the most extreme conditions
to which it will be exposed and that the
device will function as designed.
Compliance with the various required
standards (including American
Petroleum Institute (API) Spec Q1,
American National Standards Institute
(ANSI)/API Spec. 14A, ANSI/API RP
14B, ANSI/API Spec. 6A, and API Spec.
6AV1) ensures that each device will
function in the conditions for which it
was designed.
• Clarify failure reporting
requirements.
• Clarify and revise some of the
production safety system design
requirements, including revising the
requirements for piping schematics,
simplifying the requirements for
electrical system information, clarifying
when operators must provide certain
documents to BSEE, and clarifying
when operators must update existing
documents.
• Clarify requirements for Class 1
vessels.
• Clarify requirements for inspection
of the fire tube for tube-type heaters.
• Clarify the requirement for
notifying the District Manager before
commencing production.
• Make other conforming changes to
ensure consistency within the
regulations and minor edits.
C. Recent Executive and Secretarial
Orders
Since the start of 2017, the President
issued several Executive Orders (E.O.)
that necessitated the review of BSEE’s
rules. On January 30, 2017, the
President issued E.O. 13771, entitled,
‘‘Reducing Regulation and Controlling
Regulatory Costs,’’ which requires
Federal agencies to take proactive
measures to reduce the costs associated
with complying with Federal
regulations. On March 28, 2017, the
President issued E.O. 13783,
‘‘Promoting Energy Independence and
Economic Growth,’’ (82 FR 16093). This
E.O. directed Federal agencies to review
all existing regulations and other agency
actions and, ultimately, to suspend,
revise, or rescind any such regulations
or actions that unnecessarily burden the
development of domestic energy
resources beyond the degree necessary
to protect the public interest or
otherwise comply with the law. E.O.
13783 also required a review of all
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‘‘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.’’
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.
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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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: https://
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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: https://www.api.org/
publications-standards-and-statistics/
publications/government-cited-safetydocuments.
For the convenience of members of
the viewing public who may not wish
to purchase copies or view these
incorporated documents online, they
may be inspected at BSEE’s office,
45600 Woodland Road, Sterling,
Virginia 20166, or by sending a request
by email to regs@bsee.gov.
E. Section-by-Section Discussion of
Changes
Documents Incorporated by Reference
(§ 250.198)
This proposed rulemaking would
update the incorporation by reference of
superseded standards currently
incorporated in Subpart H to the current
edition of the relevant standard. This
includes incorporating new or recently
reaffirmed editions of a number of
standards referenced in Subpart H, as
well as replacing one standard currently
incorporated in the regulations, that was
withdrawn by API, with a new standard.
However, BSEE is still evaluating the
newer editions of these standards to
analyze the specific changes between
the incorporated editions and the
current editions and to assess the
potential impacts of those changes on
offshore operations. BSEE may decide
not to replace the incorporated edition
of a specific standard before the
publication of the final rule. BSEE is
soliciting comments that will inform our
decision on updating these standards,
including comments on potential risks
and costs associated with the new
editions. BSEE will consider a number
of factors in evaluating the current
editions; primarily focusing how
compliance with the current edition
balances impacts on safety and
protection of the environment and with
costs and burdens. If BSEE decides to
replace the incorporated documents
with new editions in the final rule, the
new editions would apply to all sections
of 30 CFR part 250 where those
documents are incorporated. BSEE may
also make some conforming changes to
the regulatory text in the final rule that
2 To view these standards online, go to the API
publications website at: https://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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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
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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 quickopening closures, (b) updated nozzle
design methods, (c) moved conformity
assessment requirements to the newly
referenced ASME CA–1 standard, (d)
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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 noncircular 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 pressurerelieving devices protecting these
vessels. The intent of API 510 is to
specify the in-service inspection and
condition-monitoring program that is
needed to determine the integrity of
pressure vessels and pressure-relieving
devices. The tenth edition includes
updated normative references, updated
definitions, and new requirements for
inspection programs, corrective actions,
management of change, integrity
operating windows, pressure testing,
corrosion considerations and marking
requirements.
• API STD 2RD, Dynamic Risers for
Floating Production Systems, Second
Edition, September 2013. This would
update the current incorporation of the
First Edition (from 1998; as well as 2009
Errata) of the same standard. API RP
2RD first edition was published in 1998.
In September 2013, the second edition
of the document was issued as a
standard instead of a recommended
practice (RP). The second edition
attempts to address the advancement in
technology and deepwater
environments and addresses a broader
scope of marine risers compared to the
first edition. The design approach has
changed from an allowable stress
criteria to a load and resistance factor
design, also known as limit state design.
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From there, four different methods are
given to evaluate combined loads and
the designer has the flexibility to choose
which one to use. Each method ensures
burst limit states are not exceeded for
the extreme ‘‘Accidental Limit State’’
(survival) case. Other design changes
addressed include both structural and
leak limit states for components,
exceedance of yield, combined load
approach, explicit burst and collapse
checks, temperature de-rating, special
material testing requirements, fatigue
checks, and accidental load
assessments. A requirement to develop
and implement an integrity management
program is also in the second edition,
along with integrity management
activities such as new installation
requirements and monitoring, post
installation surveys, and fatigue damage
analyses.
• API RP 2SK, Recommended
Practice for Design and Analysis of
Stationkeeping Systems for Floating
Structures, Third Edition, October 2005,
Addendum, May 2008, Reaffirmed June
2015. This would update the current
incorporation of this standard to reflect
its reaffirmation in June 2015. The third
edition of API RP 2SK was released in
October 2005 and reaffirmed in 2015.
This document presents a rational
method for analyzing, designing, or
evaluating station-keeping systems used
for floating units. This document
addresses station-keeping system
(mooring, dynamic positioning, or
thruster-assisted mooring) design,
analysis and operation. Different design
requirements for mobile and permanent
moorings are provided. There are no
changes to this document; we are
simply revising to reflect the
reaffirmation of this standard.
• API RP 2SM, Recommended
Practice for Design, Manufacture,
Installation, and Maintenance of
Synthetic Fiber Ropes for Offshore
Mooring, Second Edition, July 2014.
This would update the current
incorporation of the First Edition (from
2001; as well as 2007 Addendum) of the
same standard. API 2SM first edition
was published March 2001 and its
update was published in July 2014. This
document covers recommended
practices for manufacture, installation
and maintenance of synthetic fiber
ropes as offshore moorings for
permanent and temporary offshore
installations. The document also
discusses the difference between steel
catenary moorings and synthetic fiber
moorings. This scope and structure
provides guidance as to the advantages
of utilizing each anchoring methodology
and the logic an operator should use in
selecting mooring systems. The most
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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 nonmarine 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)
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requirements. For users of HIPPS, the
eighth edition references to more
performance based standards, such as
API 521, ‘‘Guide for Pressure-Relieving
and Depressuring Systems.’’ New
annexes in the eighth edition cover
HIPPS, logic solvers, safety system
bypassing, and remote operations.
Finally, all subsea requirements were
removed and relocated to the new
standard API 17V, ‘‘Recommended
Practice for Analysis, Design,
Installation, and Testing of Safety
Systems for Subsea Applications,’’
while API 14C addresses topside safety
systems.
• API RP 14FZ, Recommended
Practice for Design and Installation of
Electrical Systems for Fixed and
Floating Offshore Petroleum Facilities
for Unclassified and Class I, Zone 0,
Zone 1 and Zone 2 Locations, Second
Edition, May 2013. This would update
the current incorporation of the first
Edition (from 2001, reaffirmed 2007) of
the same standard. API RP 14FZ first
edition was published September 2001
and reaffirmed March 2007. The second
edition of API RP 14FZ was published
May 2013 and contains substantial
changes from the first edition. The
second edition establishes minimum
requirements and guidelines for design
and installation of electrical systems on
fixed and floating petroleum facilities
located offshore when hazardous
locations are classified as Zone 0, Zone
1, or Zone 2. As revised, API RP 14FZ
applies to both permanent and
temporary electrical installations and is
intended to describe basic desirable
electrical practices for offshore electrical
systems.
• API RP 14G, Recommended
Practice for Fire Prevention and Control
on Fixed Open-type Offshore
Production Platforms, Fourth Edition,
April 2007; reaffirmed January 2013.
This would update the current
incorporation of this standard to reflect
its reaffirmation in 2013. This
publication includes provisions for
minimizing the likelihood of having an
accidental fire, and for designing,
inspecting, and maintaining fire control
systems. It emphasizes the need to train
personnel in firefighting, to conduct
routine drills, and to establish methods
and procedures for safe evacuation. The
fire control systems in this publication
are intended to provide an early
response to incipient fires to prevent
their growth. However, this
recommended practice is not intended
to preclude the application of more
extensive practices to meet special
situations or the substitution of other
systems which will provide an
equivalent or greater level of protection.
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This publication is applicable to fixed
open-type offshore production platforms
which are generally installed in
moderate climates and which have
sufficient natural ventilation to
minimize the accumulation of vapors.
Enclosed areas, such as quarters
buildings and equipment enclosures,
normally installed on this type platform,
are addressed. Totally enclosed
platforms installed for extreme weather
conditions or other reasons are beyond
the scope of this RP.
• API RP 500, Recommended Practice
for Classification of Locations for
Electrical Installations at Petroleum
Facilities Classified as Class I, Division
1 and Division 2, Third Edition,
December 2012; Errata January 2014.
This would update the current
incorporation of the second edition
(from 1997, reaffirmed in 2002) of the
same standard. The purpose of this
recommended practice is to provide
guidelines for classifying locations Class
I, Division 1 and Class I, Division 2 at
petroleum facilities for the selection and
installation of electrical equipment.
Basic definitions given in the 2011
edition of National Fire Protection
Association (NFPA) 70, National
Electrical Code (NEC), have been
followed in developing this RP.
• ANSI/API Specification Q1 (ANSI/
API Spec. Q1), Specification for Quality
Programs for the Petroleum,
Petrochemical and Natural Gas Industry,
Ninth Edition, June 2013; effective date
June 1, 2014; Errata, February 2014;
Errata 2, March 2014; Addendum 1,
June 2016. This would update the
current incorporation of the eighth
edition (from 2007) of the same
standard. API Specification Q1, ninth
edition was published June 2013, and
supersedes API Specification Q1, eighth
edition 2007. This revision features over
85 new clauses and 5 new sections,
creating a major shift in quality
management as it applies to the oil and
gas industry. A thematic change is the
approach to quality through risk
assessment and risk management. The
five new sections include risk
assessment and management,
contingency planning, product quality
plan, preventative maintenance, and
management of change. Another
motivation for the ninth edition revision
is alignment with the 2011 publication
API Specification Q2, Specification for
Quality Management System
Requirements for Service Supply
Organizations for the Petroleum and
Natural Gas Industries, first edition.
Overall, the goal of API Q1 ninth edition
is to further enhance the minimum
baseline requirements of quality
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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 H2Scontaining 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.
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• 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: Inservice Inspection, Rating, Repair, and
Alteration of Piping Systems, Fourth
Edition, February 2016; Addendum 1:
May 2017. This would update the
current incorporation of the third
edition (from 2009) of the same
standard. API 570 covers inspection,
rating, repair, and alteration procedures
for metallic and fiberglass-reinforced
plastic (FRP) piping systems and their
associated pressure relieving devices
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that have been placed in service. This
inspection Code applies to all
hydrocarbon and chemical process
piping covered in section 1.2.1 that have
been placed in service unless
specifically designated as optional per
section 1.2.2. This publication does not
cover inspection of specialty equipment
including instrumentation, exchanger
tubes and control valves. Process piping
systems that have been retired from
service and abandoned in place are no
longer covered by this ‘‘in service
inspection’’ Code. However abandoned
in place piping may still need some
amount of inspection and/or risk
mitigation to assure that it does not
become a process safety hazard because
of continuing deterioration. Process
piping systems that are temporarily out
of service but have been mothballed
(preserved for potential future use) are
still covered by this Code. BSEE is also
proposing to revise §§ 250.198(h)(58)
and 250.198(h)(62) to update cross
references to § 250.842(b) that would
change to § 250.842(c) in this
rulemaking.
What must the DWOP contain?
(§ 250.292)
BSEE is proposing to revise § 250.292
paragraph (p)(3) to replace the
incorporation by reference of API RP
2RD to API STD 2RD.
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General (§ 250.800)
BSEE is proposing to revise § 250.800
paragraph (c)(2) to replace the
incorporation by reference of API RP
2RD to API STD 2RD.
Safety and Pollution Prevention
Equipment (SPPE) Certification.
(§ 250.801)
This section would be revised to
explicitly state that GLSDVs are
included in SPPE. This is merely a
clarification, since GLSDVs already
must follow § 250.801. Under § 250.873
in the current regulations, GLSDVs must
meet the requirements in §§ 250.835 and
250.836 for boarding shutdown valves
(BSDVs). Further, § 250.835 requires
that BSDVs meet the requirements in
§§ 250.801 through 250.803. Since
§ 250.835 currently requires that BSDVs
meet the requirements in § 250.801, and
GLSDVs must meet the requirements for
BSDVs in § 250.835 pursuant to
§ 250.873, it follows that GLSDVs are
already required to meet the
requirements of § 250.801. BSEE
proposes to revise § 250.801 to expressly
include GLSDVs in the list of equipment
that BSEE considers to be SPPE to make
this requirement more clear. BSEE also
considered identifying water injection
shutdown valves (WISDVs) as SPPE.
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However, under normal operation
WISDVs do not handle hydrocarbons, so
they do not serve the same function as
other equipment identified as SPPE.
BSEE is proposing to revise the
introductory sentence in paragraph (a)
of this section to remove the phrase,
‘‘[i]n wells located on the OCS.’’ BSEE
does not need to specify the location of
the SPPE, since all of the equipment
that is considered SPPE, is either
located in a well or a riser.
Requirements for SPPE (§ 250.802)
Consistent with the proposed revision
to § 250.801, BSEE would revise this
section to add GLSDVs to the list of
equipment in this section, as well.
BSEE would also remove the
provision at § 250.802(c)(1) and
redesignate subsequent paragraphs
under paragraph (c). Current
§ 250.802(c)(1), is redundant with
industry standards incorporated in
BSEE’s regulations. This section
currently requires that a qualified
independent third-party certify that
SPPE will function as designed,
including under the most extreme
conditions to which it may be exposed.
Operators raised concerns that it may
not be possible for independent third
parties to certify that specific SPPE will
perform under the most extreme
conditions to which it will be exposed.
Compliance with the various required
standards (including API Spec Q1,
ANSI/API Spec. 14A, ANSI/API RP 14B,
ANSI/API Spec. 6A, and API Spec.
6AV1) ensures that each device will
function in the conditions for which it
was designed. In addition, the thirdparty 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
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not require highly specialized expertise.
Using these valves as intended reduces
the risk associated with oil and natural
gas production operations. Therefore,
after review and consideration of the
current requirements, BSEE concluded
that requiring independent third party
review and certification of these valves
is not necessary, because ANSI/API
Spec. 14A and ANSI/API Spec. Q1
provide for independent testing to
ensure the devices will function as
designed.
During the implementation of the
original final rule, a number of operators
inquired about using existing inventory
of BSDVs that meet the requirements of
§ 250.802, but are not certified. BSEE is
considering an approach that would
allow operators to use this existing
inventory. We are requesting comments
on how to allow this, including
information on the size of existing
inventory and timing for use of that
inventory, as well as comments on an
approach to allow for this.
Consistent with the proposed change
in § 250.801(a), BSEE would revise
paragraph (d)(2) to remove the phrase,
‘‘on that well.’’ BSEE does not need to
specify the location of the SPPE, since
all of the equipment that is considered
SPPE, is either located in a well or a
riser. The preamble to the 2016 final
rule describes the current table in
§ 250.802(d) as clarifying ‘‘when
operators must install SPPE equipment
that conforms to the requirements of
§ 250.801’’ and makes no mention of
whether the SPPE is located in the well
or riser (81 FR 61859). Consistently
throughout, that preamble describes the
requirements of existing §§ 250.800
through 250.802 without any reference
to the location of the SPPE as on a well
or riser, (e.g., (81 FR 61846), describing
the existing § 250.800(c)(2) as allowing
operators to continue using BDSV and
single bore production risers already
installed on floating production
systems).
What SPPE failure reporting procedures
must I follow? (§ 250.803)
In addition to the specific proposals
described below, BSEE is seeking input
about how to revise the current language
specifying what constitutes ‘‘failure’’
used in this regulation. In response to
comments received on the previous
proposed rulemaking, BSEE included
this language in the previous Subpart H
rulemaking. During implementation of
the current rule, BSEE received a
number of questions from industry
asking for additional clarification of this
language and of what specific
equipment issues operators must report.
BSEE is requesting comments on
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revising how ‘‘failure’’ is specified. The
current § 250.803 states, ‘‘[a] failure is
any condition that prevents the
equipment from meeting the functional
specification or purpose.’’
Operators are required to follow the
failure reporting requirements from
ANSI/API Spec. 6A for SSVs, BSDVs,
and USVs and to follow ANSI/API Spec.
14A and ANSI/API RP 14B for SSSVs.
BSEE seeks input on specifying what
constitutes ‘‘failure’’ for the purposes of
the reporting requirements under
§ 250.803. The documents incorporated
by reference in § 250.803 have different
definitions of failure or may not include
a definition of failure at all. Given these
various definitions of failure, BSEE is
inquiring as to if it is appropriate to
include a single description of what
constitutes failure that applies to all of
the SPPE covered in § 250.803? Or is it
more useful to include various
descriptions, based on the type of
equipment?
BSEE reviewed the definition of
failure in various industry standards
related to production systems, and
found the following definitions:
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API Spec 6AV1, Specification for
Verification Test of Wellhead Surface Safety
Valves and Underwater Safety Valves for
Offshore Service, Second Edition
(incorporated by reference at §§ 250.802(a),
250.833, 250.873(b), and 250.874(g)), defines
failure as: [i]mproper performance of a device
or equipment item that prevents completion
of its design function.’’
ANSI/API Spec. 14A, Specification for
Subsurface Safety Valve Equipment, Twelfth
Edition (incorporated by reference at
§§ 250.802(b) and 250.803(a)), defines failure
as: [a]ny equipment condition that prevents
it from performing to the requirements of the
functional specification.
ABS 281, Guide for Classification and
Certification of Subsea Production Systems,
Equipment and Components, August 2017,
defines failure as: [a]n event causing an
undesirable condition (e.g., loss of
component or system function) or
deterioration of functional capability to such
an extent that the safety of the unit,
personnel, or environment is significantly
reduced.
BSEE would revise paragraph (a) of
this section to include GLSDVs in the
list of equipment that are subject to the
failure reporting requirements. In
addition, BSEE is proposing to revise
this paragraph to require operators to
submit their SPPE failure information to
BSEE through the Chief, Office of
Offshore Regulatory Programs, unless
BSEE has designated a third-party. If
BSEE has designated a third party, then
operators would be required to submit
it to that party. Currently, operators
submit this information through
www.SafeOCS.gov, where it is received
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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/latestnews/statements-and-releases/pressreleases/bsee-expands-safeocsprogram). 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/bseebts-mou-08-18-2016_0.pdf.
Reporting instructions are on the
SafeOCS website at: https://
www.SafeOCS.gov. Reports submitted
through www.SafeOCS.gov are collected
and analyzed by BTS and protected
from release under the Confidential
Information Protection and Statistical
Efficiency Act (CIPSEA). BTS operates
under this Federal law, the CIPSEA,
which requires that the program, under
strict criminal and civil penalties for
noncompliance, treats and stores reports
confidentially. Information submitted
under this statute also is protected from
release to other government agencies,
Freedom of Information Act (FOIA)
requests, and subpoena. If the
information were to be submitted to
BSEE, BSEE could only protect its
confidentiality as allowed by Federal
law. Accordingly, while BSEE could
keep certain information confidential, it
would likely need to release much of
the information related to the failure of
SPPE. Were BSEE to reconsider its
agreement with BTS to collect these
reports, BSEE would look for
arrangements with other agencies or
non-governmental organizations that
could provide the same degree of
confidentiality as that provided by BTS
under CIPSEA.
BSEE proposes to revise paragraph (d)
to address the use of a BSEE-designated
third party to receive the failure
reporting information.
Design, Installation, and Operation of
SSSVs—Dry Trees (§ 250.814)
BSEE would revise § 250.814
paragraph (d) to replace the
incorporation by reference of API RP
14B with ANSI/API 14B.
Use of SSVs (§ 250.820)
This section would be revised to
replace the incorporation by reference of
API RP 14H, which was withdrawn by
API, to API STD 6AV2.
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Emergency Action and Safety System
Shutdown—Dry Trees (§ 250.821)
BSEE is proposing to revise paragraph
(a) of this section to clarify that
operators must shut in the production
on any facility that ‘‘is impacted or that
will potentially be impacted by an
emergency situation.’’ BSEE includes
some examples of emergencies such as
named storms, ice events in the Arctic,
or earthquakes. It was not BSEE’s intent
to specify all emergency events that
could trigger this regulation. The
operator must determine when their
facility is impacted or will potentially
be impacted due to an emergency
situation. The existing regulations do
not clearly state that operators must
shut in any facility that has been or may
potentially be impacted by an
impending emergency. The proposed
clarification is to ensure that operators
understand that they have an obligation
to properly secure wells before the
platform is evacuated in the event of an
emergency. For example, if a well is
capable of flowing and does not have a
subsurface safety device, one must be
installed. The current regulations
require that this activity be done as soon
as possible. BSEE requests comments on
whether the phrase ‘‘as soon as
possible’’ provides sufficient regulatory
certainty or if there are more objective
criteria, such as a before the facility is
evacuated, that could be used to define
these obligations.
Design, Installation, and Operation of
SSSVs—Subsea Trees (§ 250.828)
BSEE would revise § 250.828
paragraph (c) to replace the
incorporation by reference of API RP
14B with ANSI/API 14B.
Specification for Underwater Safety
Valves (USVs) (§ 250.833)
BSEE is proposing to revise the
introductory paragraph in this section to
replace API Spec. 6A with ANSI/API
Spec. 6A.
Use of USVs (§ 250.834)
This section would be revised to
update the incorporation by reference of
API RP 14H, which was withdrawn by
API, to API STD 6AV2.
Use of BSDVs (§ 250.836)
This section would be revised to
update the incorporation by reference of
API RP 14H, which was withdrawn by
API, to API STD 6AV2.
Emergency Action and Safety System
Shutdown—Subsea Trees (§ 250.837)
BSEE is proposing to revise paragraph
(a) of this section to clarify that
operators must shut in the production
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on any facility that ‘‘is impacted or that
will potentially be impacted by an
emergency situation.’’ This revision is
consistent with the revision proposed
for § 250.821(a) for facilities with dry
tress. BSEE includes some examples of
emergencies such as named storms, ice
events in the Arctic, or earthquakes. It
is not BSEE’s intent to specify all
emergency events that could trigger this
regulation. The operator must determine
when there may be potential impacts
due to an emergency or if their facility
was impacted by an emergency event.
The existing regulations do not clearly
state that operators must shut in any
facility that has been or may be
impacted by an impending emergency.
BSEE would also add GLSDVs to the list
of equipment that is closed during a
shut-in. This is consistent with
identifying GLSDVs as SPPE in
§§ 250.801 through 250.803 and
elsewhere in this subpart.
In addition, BSEE is proposing to
revise paragraph (b) of this section to
clarify the requirements for dropped
objects in an area with subsea
operations, and to be consistent with the
provisions of subpart G on dropped
objects. For example, the current
subpart H regulations state that the
operator must develop and submit a
dropped objects plan to the appropriate
District Manager, as part of an
Application for Permit to Drill (APD) or
Application for Permit to Modify
(APM). A dropped objects plan is
required by § 250.714. However,
§ 250.714 does not require operators to
submit this plan as part of the APD or
APM; rather, they must make their
dropped object plans available to BSEE
upon request. A dropped object plan is
not a static plan, § 250.714 requires
operators to update their dropped
objects plans as the subsea
infrastructure changes.
Throughout this section, BSEE would
replace ‘‘MODU or other type of
workover vessel’’ with ‘‘vessel.’’ The use
of the word ‘‘vessel’’ is a more
comprehensive term that includes any
type of equipment that could be used to
perform well operations.
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Platforms (§ 250.841)
BSEE would add a new paragraph (c)
to this section to address major
modifications to a facility, by directing
operators to follow the requirements in
§ 250.900(b)(2). This is not a new
requirement, as operators are already
required to follow the provisions of
§ 250.900(b)(2) for major modifications.
This simply provides direction to the
operator and emphasizes the need to
follow § 250.900(b)(2).
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The existing paragraph (b) of this
section currently requires operators to
maintain all piping for platform
production processes as specified in API
RP 14E Recommended Practice for
Design and Installation of Offshore
Production Platform Piping Systems
(API RP 14E). Section 6.5(a)(1) of API
RP 14E addresses painting of steel
piping to prevent corrosion. Corrosion
prevention is important for safety and
pollution prevention, and BSEE is not
currently proposing to remove the
reference to API RP 14E from this
section. However, BSEE is interested in
comments on whether other changes
may be warranted. BSEE recognizes that
there are difficulties accessing some of
the piping on existing facilities, and
BSEE is aware that operators have asked
for extension, after BSEE has issued an
incident of noncompliance, to provide
additional time to implement this
requirement on some facilities. In these
cases, BSEE has generally requested that
operators submit a departure request
that includes an implementation plan to
BSEE for complying with this section of
API RP 14E. In the implementation
plan, BSEE is looking for the operator
to: (1) Identify facilities for which extra
time is needed for compliance, (2)
specify areas of inaccessible piping, (3)
address precautions taken until the
piping can be accessed for painting, and
(4) prioritize high-risk areas for more
rapid treatment.
Approval of Safety Systems Design and
Installation Features (§ 250.842)
BSEE proposes to revise some of the
requirements related to the diagrams
and drawings the operators must to
submit to BSEE for approval. Currently,
operators must submit all of the
documents listed in existing paragraph
(a) of this section to BSEE for approval
and those documents are required to be
stamped by a registered professional
engineer (PE). BSEE would revise this
provision to require operators to submit
only the most critical documents to
BSEE and have those documents
stamped by a PE. However, BSEE has
identified some documents that the
operator would be required to develop
and maintain, but that that operator
would not be required to submit to
BSEE; nor would these documents
would be required to be stamped by at
PE. BSEE would list these less critical
documents in a new paragraph (b).
BSEE would reorganize this section in
conjunction with these changes. This
proposed rulemaking would also clarify
that operators do not need to update
existing drawings until a modification
request is submitted to BSEE. When an
operator submits a modification request,
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it must include fully updated drawings
as required in paragraph (a) with all
changes stamped by a PE.
Existing introductory paragraph (a)
states that before installing or modifying
a production safety system the operator
must submit a production safety system
application to the District Manager for
approval. This would be revised to
clearly state that the operator must
receive approval from the District
Manager before commencing production
through or utilizing the new or modified
system.
The table in existing paragraph (a)
identifies specific diagrams and
drawings that the operator is required to
submit to BSEE as part of the
production safety system application
and be stamped by a PE. BSEE would
revise the table to require operators to
submit the safety analysis flow diagram,
safety analysis function evaluation
(SAFE) chart, electrical one line
diagram, and area classification diagram
for new facilities and for modifications
to existing facilities. In addition revised
paragraph (a) would be revised to
require operators to submit piping and
instrumentation diagrams (P&ID) for
new facilities only; the operator would
not be required to submit the P&ID
modification. The table under paragraph
(a) would be reordered as part of this
revision.
Existing paragraph § 250.842(a)(3),
which addresses electrical system
information would be substantially
revised. This paragraph would be
redesignated as paragraph (a)(2). Some
items currently required as part
electrical system information would be
removed from the scope of required
submissions. BSEE would revise this
section would now require the operator
to submit an electrical diagrams,
showing key elements, including
generators, circuit breakers,
transformers, bus bars, conductors,
battery banks, automatic transfer
switches, uninterruptable power supply
(UPS), dynamic (motor) loads, and static
(e.g., electrostatic treater grid, lighting
panels, etc.) loads. Other information
required under the current regulations
would be moved to paragraph (b)(1) in
this proposed revision, such as
electrical drawings for cable/tray
conduit routing plans and panel board/
junction box location plans.
The proposed rule would redesignate
existing paragraph (b) as paragraph (c)
and insert a new paragraph (b). Some of
the diagrams required in existing
paragraph (a) would be moved to the
new paragraph (b). The operator would
still be required to develop and
maintain all of the diagrams included in
existing paragraph (a). However, for
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those diagrams proposed to be moved
into new paragraph (b), BSEE would
only require the operator to develop and
maintain them, and provide them to
BSEE upon request. The operator would
no longer be required to submit these
with the production safety system
application. These diagrams would
include: Additional electrical system
information, schematics of the fire and
gas-detection systems, and revised
P&IDs for existing facilities. The
operator would not be required to have
the diagrams and drawings listed in
proposed new paragraph (b) certified
and stamped by a PE. The operator
would be required to develop and
maintain these diagrams to accurately
document any changes made to the
production systems; and provide these
to BSEE upon request.
The requirements for schematic P&IDs
that are currently required under (a)(1)
in the table would be moved to (a)(4)
and revised to state that the operator is
required to submit the P&ID for new
facilities to BSEE. The operator would
be required to develop and maintain
revised P&IDs for modifications to
existing facilities, under new (b)(3).
The safety analysis flow diagram and
the related SAFE chart currently in
section (a)(2) would be moved to (a)(1),
with additional details added to clarify
what the operator must include on the
diagram.
Current paragraph (a)(3) in the table
requires the operator to submit electrical
system information. The proposed rule
would move this to (a)(2) and revise it
to require the operator to submit only
the electrical one-line diagram. The
additional electrical information in the
current paragraph (a)(3) would be
included in new section (b)(1), with
details added to specify what electrical
system information the operator must
develop, maintain, and make available
to BSEE.
This section would no longer require
operators to identify all areas where
potential ignition sources are located.
This requirement is already addressed
under § 250.842(c)(3), which requires
operators to perform a hazards analysis
in accordance with § 250.1911 and API
RP 14J. API RP 14J specifically
addresses ignition sources and
minimizing the chances of ignition. API
RP 14J directs the operators to consider
all ignition sources when designing
their facility and provides detailed
guidance on designing the facility and
equipment to prevent the ignition of
hydrocarbons. The requirement for
operators to develop and maintain a
separate document identifying ignition
sources is not necessary because this is
inherent to compliance with API RP 14J.
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In addition, § 250.842(c)(3) requires
operators to have a hazards analysis
program in place to assess potential
hazards during the operation of the
facility.
New paragraph (b)(2) would address
the schematics of the fire and gasdetection systems, which are currently
addressed in existing paragraph (a)(4).
New paragraph (b)(3) would include
revised P&IDs for modifications to
existing facilities.
Redesignated paragraph (c) (existing
paragraph (b)), would continue to
require operators to certify that: (1) The
all electrical installations were designed
according to API RP 14F or API RP
14FZ, as applicable; (2) a hazards
analysis was performed in accordance
with § 250.1911 and API RP 14J; and (3)
operators have a hazards analysis
program in place to assess potential
hazards during the operation of the
facility. Redesignated (c)(2) of § 250.842
(existing (b)(2)) would be revised to
state that the designs for the mechanical
and electrical systems that the operator
is required to submit under paragraph
(a) of this section be reviewed,
approved, and stamped by an
appropriate registered PE.
The drawings that would be required
under new paragraph (b) include
additional electrical system information,
schematics of the fire and gas-detection
systems, and revised P&IDs for existing
facilities; would no longer require
review, approval, and stamping by an
appropriate registered PE. This change
would reduce the burden on operators
by no longer requiring a PE to certify as
many diagrams and drawings. Operators
would still be required to develop these
diagrams and drawings and provide
them to BSEE upon request. The
operators would also be required to
maintain them, ensuring they accurately
reflect the current production system.
BSEE would remove existing
paragraph (c), which currently requires
operators to submit a letter to the
District Manager certifying that the
mechanical and electrical systems were
installed in accordance with the
approved designs, before beginning
production. This step was intended to
ensure the operator properly
documented the installation of the
mechanical and electrical systems. This
submittal was a burdensome step to
assure document management and
confirm that operator performed the
modification as proposed and approved.
Because the operators must submit the
as-built drawings which BSEE uses for
field verification, the certification letter
was not needed.
Under existing paragraph (d), the
operators are already required to have
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the as-built diagrams stamped by a PE
and to submit the as-built diagrams for
the new or modified production safety
systems to BSEE. Under the proposed
rule, BSEE would no longer require
operators to submit a letter to certify
that the mechanical and electrical
systems were installed in accordance
with the approved designs. This letter
was primarily used for tracking
documentation; it is not needed by
either industry or BSEE.
BSEE would clarify existing
§ 250.842(d) regarding PE stamping of
required drawings.
The proposed rule would require the
diagrams that are submitted to BSEE
under § 250.842 paragraphs (a)(1), (2),
and (3) to be reviewed, approved, and
stamped by an appropriate registered
PE(s). The requirement from existing
paragraph (e), that the operators submit
the as-built diagrams within 60 days of
commencing production would be
included in this section.
BSEE would redesignate existing
paragraph (f) as paragraph (e), since the
requirements from existing paragraph
(e) would be moved to new paragraph
(d). Redesignated paragraph (e)
addresses the requirements for
maintaining the documents required in
this section. BSEE is not proposing any
revisions to the requirements in this
paragraph.
Pressure Vessels (Including Heat
Exchangers) and Fired Vessels
(§ 250.851)
BSEE is proposing to remove the dates
from this section that required that
existing uncoded pressure and fired
vessels that were in use on November 7,
2016 (the effective date of the previous
Subpart H rulemaking), to be code
stamped before March 1, 2018. These
dates no longer need to be included as
they both will have already passed by
the time the final rulemaking is issued
in this rulemaking. In addition, most
pressure vessels and fired vessels were
already required to be coded stamped.
The previous regulations only added
vessels with an operating pressure
greater than 15 psig to that requirement.
The existing regulations provide that the
operator may request approval from the
District Manager to continue to use
uncoded pressure and fired vessels.
Flowlines/Headers (§ 250.852)
BSEE is proposing to revise
paragraphs § 250.852(e)(1) and (e)(4) to
replace the reference to API Spec. 17J
with ANSI/API Spec. 17J.
Safety Sensors (§ 250.853)
This section would be revised to add
a new paragraph (d) to require that all
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level sensors are equipped to permit
testing through an external bridle on all
new vessel installations, where possible,
depending on the type of vessel for
which the level sensor is used. This
change was originally included in the
previous proposed rulemaking.
However, it was not included in the
final rule, based on concerns raised by
public comments. BSEE has reviewed
those comments and is reconsidering its
decision to remove this provision from
the final rule. The preamble of the
previous final rule stated that BSEE
removed proposed paragraph (d) from
the final rule because BSEE can address
level sensors adequately using existing
regulatory processes, such as the
Deepwater Operations Plan (DWOP),
and we do not need to specify uses and
conditions of such sensors in this
regulation.
When BSEE reviewed that decision,
we determined that including this
requirement in the regulations is
important because it clearly states the
expectation to have an external bridle to
permit testing. This would ensure that,
where possible, the sensor is accessible
for testing, which is the accepted
approach, at this time. A comment on
the previous rulemaking asserted that
certain sensor testing technologies (e.g.,
ultrasonic and capacitance) are not
suitable for use in external bridles, and
that some proposed or new projects
evaluated using ultrasonic, optical,
microwave, conductive, or capacitance
sensors, and that such sensors do not
use bridles. BSEE recognizes that there
are sensors that do not use bridles and
that other equipment options exist.
However, the use of level sensor with an
external bridle that allows testing
through the bridle remains BSEE’s
preferred approach. Sensor testing
equipment built according to API
standards, which are incorporated by
reference into BSEE’s regulations,
should be able to meet this provision.
We are proposing additional language to
recognize other approaches, stating that
operators must ensure that all level
sensors are equipped to permit testing
through an external bridle ‘‘where
possible, depending on the type of
vessel for which the level sensor is
used.’’ This language allows BSEE more
flexibility in approving a different
design, without requiring the operator to
apply for an alternate procedure or
equipment to test the level sensor under
§ 250.141.
Temporary Quarters and Temporary
Equipment (§ 250.867)
BSEE is proposing to revise paragraph
(a) of this section to require District
Manager approval of safety systems and
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safety devices associated with the
temporary quarters prior to installation.
This would apply to all temporary
quarters to be installed on OCS
production facilities. The existing
regulations specify that that operator
must receive approval for temporary
quarters ‘‘. . . installed in production
processing areas or other classified areas
on OCS facilities.’’ This proposed would
require approval of the safety systems
and safety devices, instead of approval
of the actual temporary quarters,
regardless of where the temporary
quarters are located. This proposed
change recognizes that risk of a hazard
occurring related to production is not
restricted to the production areas or
classified areas. This change would
ensure that temporary quarters have the
proper safety systems and devices
installed to protect individuals in the
temporary quarters, regardless of where
they are located on the facility.
BSEE recognizes the authority of the
United States Coast Guard (USCG) as
the lead agency for living quarters on
the OCS. This is recognized in two
Memorandums of Agreement (MOAs)
between BSEE and USCG related to oil
and gas production facilities: MOA
OCS–09, Fixed OCS Facilities, dated
September 19, 2014 and MOA OCS–04,
Floating OCS Facilities, dated January
28, 2016. MOA OCS–09 establishes
BSEE as the lead for safety systems,
specifically for emergency shutdown
systems, gas detection, and safety and
shutdown systems on fixed OCS
facilities. MOA OCS–04 establishes
BSEE as the lead for emergency
shutdown systems and components on
floating OCS facilities. The existing
requirement that temporary quarters
must be equipped with all safety
devices required by API RP 14C, Annex
G would not change. This paragraph
would ensure operators install the
proper safety devices on or in temporary
quarters, including fire and gas
detection equipment and emergency
shut down stations addressed in API RP
14C. BSEE will discuss this proposed
change with the USCG to ensure an
understanding that the USCG will not
approve the installation of the
temporary quarters until the operator
obtains approval of the safety systems
and devices from BSEE.
BSEE would also add a new
paragraph (d) to this section that states
that operators must receive District
Manager approval before installing
temporary generators that would require
a change to the electrical one-line
diagram under § 250.842(a).
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Time Delays on Pressure Safety Low
(PSL) Sensors (§ 250.870)
BSEE is proposing to revise the
requirement in paragraph (a) of this
section regarding the use of Class B,
Class C, or Class B/C logic. This section
currently states that the operator ‘‘may
apply any or all of the industry standard
Class B, Class C, or Class B/C logic to
all applicable PSL sensors installed on
process equipment, as long as the time
delay does not exceed 45 seconds.’’
BSEE would delete the phrase ‘‘any or
all of the’’ from that sentence, as it is not
needed. We would no longer require the
operator to seek approval from BSEE for
alternative compliance under § 250.141
to use a PSL sensor with a time delay
that is greater than 45 seconds. Instead,
the section would state that if the device
may be bypassed for greater than 45
seconds, the operator must monitor the
bypassed devices in accordance with
§ 250.869(a). The alternative compliance
approval is not needed, since
monitoring bypassed devices is
addressed in the current § 250.869(a),
for which no change is proposed.
Atmospheric Vessels (§ 250.872)
BSEE would revise paragraph (a) of
this section to state that atmospheric
vessels connected to the process system
that contain a Class I liquid must be
reflected on the corresponding
drawings, along with the associated
pumps. The current regulations do not
specifically require the operator to
include the atmospheric vessels on
these drawings. However, since these
tanks are used to process or store liquid
hydrocarbons, it is important to identify
where they are located in the processing
system and to ensure they are properly
protected.
BSEE is also proposing to revise
paragraph (b) of this section, adding
language that the operator must design
the level safety high (LSH) sensor on the
atmospheric vessel to prevent pollution
as required by § 250.300(b)(3) and (4).
This is not a new requirement. BSEE is
adding this provision to emphasize the
importance that these vessels be
designed to prevent pollution.
In addition, BSEE is proposing to
change the current requirement that the
LSH must be installed to sense the level
in the oil bucket, to limit this
requirement to newly installed
atmospheric vessels with oil buckets.
The proposed change is based on
questions and departure requests BSEE
received during implementation of the
Subpart H Rule. BSEE recognizes that
the installation of a LSH on the oil
bucket is not possible on some existing
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vessels without extensive modifications
to the vessels.
BSEE is proposing to remove
§ 250.872(c) which currently states that
operators must ensure that all flame
arrestors are maintained to ensure
proper design function (installation of a
system to allow for ease of inspection
should be considered). This requirement
is not necessary as it is redundant with
§ 250.800(a) which requires operators to
maintain all production safety
equipment in a manner to ensure the
safety and protection of the human,
marine, and coastal environments.
Subsea Gas Lift Requirements
(§ 250.873)
BSEE is proposing to revise the table
in paragraph (b) of this section to
replace multiple references to API Spec.
6A with ANSI/API Spec. 6A.
Subsea Water Injection Systems
(§ 250.874)
BSEE would revise paragraph (g)(2) of
this section to replace the reference to
API Spec. 6A with ANSI/API Spec. 6A.
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Fired and Exhaust Heated Components
(§ 250.876)
BSEE would revise this section to
delete the requirement that the fire tube
be removed during inspection. BSEE
recognizes that there are other ways to
inspect the fire tube, without removing
them. For example, a combination of
cameras with thickness sensors could be
used to inspect fire tubes that cannot be
easily accessed, instead of removing the
fire tube completely. This change would
allow the operator to determine an
appropriate method to inspect the fire
tube and is a more flexible,
performance-based approach. BSEE
recognizes the need for fire tube
inspections; however, the process to
remove the fire tube for inspection can
pose its own safety concerns. In some
cases, use of an alternative method for
inspections would actually increase
safety, since removing the fire tube may
present a hazard if the fire tube is
located in a place where it is not easy
to remove.
Production Safety System Testing
(§ 250.880)
BSEE is proposing to clarify language
in paragraph (a)(1) of this section to
clearly state that the operator must
notify BSEE at least 72 hours before
commencing initial production on a
facility. The current language states that
the operator must notify BSEE, ‘‘at least
72 hours before commencing
production.’’ It does not specify that this
notification is for initial production,
leading to possible interpretation that
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the operator must notify BSEE anytime
production on a facility has been shut
in and the operator is ready to resume
production. This interpretation was not
BSEE’s intent.
In addition, BSEE would revise
paragraphs (c)(2)(iv) and (c)(4)(iii) to
update the incorporation by reference of
API RP 14H, which was withdrawn by
API, to API STD 6AV2.
BSEE would also revise § 250.880
paragraph (c) to replace the
incorporation by reference of API RP
14B with ANSI/API 14B.
consult with the OFR regarding its
suggestions for specific organizational
and language changes to § 250.198 and
expects to address such revisions in a
separate rulemaking as soon as possible.
BSEE does not anticipate that those
potential revisions would have any
substantive impact on the proposed
incorporations by reference of industry
standards discussed in this notice.
What industry standards must your
platform meet? (§ 250.901)
BSEE is seeking input on clarifying
when a failure analysis is required
under § 250.803. Under what
circumstances should BSEE require
more failure analysis information? For
example, a formal root cause failure
analysis conducted by Subject Matter
Experts, or the manufacturer? Should
BSEE limit the formal failure analysis to
cases where SPPE are returned to shore
for remedial action to address the cause
of the failure?
BSEE is proposing to revise paragraph
(a) of § 250.901 and the table in
paragraph (d) to update the
incorporation by reference of API STD
2RD.
Design Requirements for DOI Pipelines
(§ 250.1002)
BSEE is proposing to revise paragraph
(b) of § 250.1002 to update the
references to ANSI/API Spec. 6A, ANSI/
API Spec. 17J, and API STD 2RD.
What To Include in Applications
(§ 250.1007)
BSEE is proposing to revise
paragraphs (a) of § 250.1007 to replace
the reference to API Spec. 17J with
ANSI/API Spec. 17J.
F. Additional Comments Solicited
BSEE has identified a number of
potential revisions to the 30 CFR part
250 regulations that are not specifically
included in this proposed rulemaking.
However, BSEE is soliciting comments
on these potential revisions, which it
may implement in the final rule or a
future rulemaking.
Potential Revisions to § 250.107(c) Best
Available and Safest Technology
(BAST)
In the 2016 final rule, BSEE revised
the definition of BAST contained in
Section 250.107 based on public
comments. BSEE solicits comments on
whether this language adequately
reflects the statutory mandate
concerning the use of BAST on the OCS.
Potential Revisions to § 250.198
Documents Incorporated by Reference
BSEE is considering potential, nonsubstantive revisions to § 250.198, as a
whole, for the purposes of reorganizing
and revising that section to make it
clearer, more user-friendly, and more
consistent with the Office of the Federal
Register’s (OFR’s) recommendations for
incorporations by reference in Federal
regulations. BSEE will continue to
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Considerations for failure reporting
under § 250.803 what SPPE failure
reporting procedures must I follow?
Extension of Compliance for Pressure
Safety Valve (PSV) Testing Under
§ 250.880 Production Safety System
Testing
BSEE also considered revising the
requirements regarding PSV testing in
§ 250.880(c)(2)(i). This existing
provision requires operators to test PSVs
annually and that the main valve piston
must be lifted during this test. The main
valve piston is a critical component of
the PSV, and this approach will verify
it will actually vent when needed. BSEE
recognizes that this is a change to the
approach used for testing prior to the
2016 rule and that some operators
needed time develop new testing
procedures. In some cases, operators
may need to modify existing equipment
or fabricate new equipment to fully
comply. BSEE granted departures to this
provision, giving operators who
requested a departure under § 250.142,
until November 7, 2018 to comply with
this requirement. BSEE expects that
operators will be able to comply by that
date and a revision to this requirement
is not needed; nevertheless BSEE is
considering whether it is appropriate to
provide additional time to perform the
first required test on those PSVs where
it is not possible to lift the piston during
the test. BSEE would potentially
consider an additional 1 to 2 years
beyond the effective of this rulemaking
for BSEE seeks comments on this issue,
including comments on an appropriate
time period for the delay.
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Potential Revisions Based on the
Investigation of the Explosion and
Fatality on West Delta Block 105
Platform E
In 2016, BSEE issued a panel report
entitled Investigation of November 20,
2014, Explosion and Fatality, Lease
OCS–00842, West Delta Block 105
Platform E. The incident involved an
explosion inside the electrostatic heater
treater located on the platform while the
contract cleaning crew personnel were
engaged in activities related to cleaning
the vessel. The report and
corresponding memorandum, can be
found at https://www.bsee.gov/wd-105e-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.
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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
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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
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proposed revisions reduce or eliminate
parts of the paperwork burden of the
original rulemaking, while providing
the same level of safety and
environmental protection. BSEE has
reexamined the economic analysis for
the 2016 1014–AA10 final rule and now
believes that it may have
underestimated compliance costs. BSEE
is therefore revising some of the
compliance cost assumptions in that
analysis for this rulemaking. The
underestimate of compliance costs in
the 1014–AA10 analysis is primarily
related to (1) the burden for obtaining
PE review and stamping of all drawings
on a facility if any production
equipment modifications are proposed
and (2) duplicative independent third
party equipment certifications that
would no longer be required under this
proposal. BSEE underestimated both the
cost and number of PE reviews required
under § 250.842. The cost of
independent 3rd party testing and
certifications required under the
§ 250.802 paragraph (c)(1) was also
underestimated by BSEE.
BSEE expects this proposed rule to
reduce the regulatory burden on
industry. Regulatory compliance cost
savings are a result of changes in the
proposed rule that reduce burden hours,
PE stamping for production safety
system components and independent
third party equipment certifications.
BSEE estimates this rulemaking, if
adopted, would reduce industry
compliance burdens by $33 million
annually. Over 10 years BSEE estimates
the reduced compliance burdens and
cost savings to be $281 million
discounted at 3 percent or $228 million
discounted at 7 percent. As discussed in
the initial Regulatory Impact Analysis
(RIA) the proposed amendments would
not negatively impact worker safety or
the environment.
The cost savings for revised
provisions on PE stamping of
production safety system modification
documents (§ 250.842) is the single
largest single cost savings provision in
this proposed rule. The additional PE
certifications and stamping will no
longer be required for all production
safety system documents in an
application, only the documents for
those components being modified. BSEE
estimates the net regulatory cost savings
will be $23.1 million in the first year
(2018) and $162.0 million over 10 years
discounted at 7 percent. The other
provision providing substantial
regulatory relief is the proposed
elimination of the third-party reviews
and certifications for select SPEE.
Compliance with the various required
standards (including API Spec Q1,
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ANSI/API Spec. 14A, ANSI/API RP 14B,
ANSI/API Spec. 6A, and API Spec.
6AV1) ensures that each device will
function in the conditions for which it
was designed. The table below
summarizes BSEE’s estimate 10-year the
compliance cost savings. Additional
information on the compliance costs,
savings and benefits can be found in the
initial RIA posted in the docket.
TOTAL ESTIMATED COST SAVINGS ASSOCIATED WITH AMENDMENTS TO SUBPART H
[2016 $]
Year
Undiscounted
Total .............................................................................................................................................
Annualized ...................................................................................................................................
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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.
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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
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$332,630,000
33,263,000
Discounted
at 3%
Discounted
at 7%
$281,021,257
32,944,264
$228,268,048
32,500,235
proposed rule would affect a substantial
number of small entities.
This proposed rule is a deregulatory
action and BSEE has estimated the
overall associated costs savings. BSEE
has estimated the annualized cost
savings and allocated those savings to
small or large entities based on the
number of active or idle OCS
production facilities. Using the share of
small and large companies’ production
facilities, we estimate that small
companies would realize 87 percent of
the cost savings from this rulemaking
and large companies 13 percent. Small
companies operate ∼90 percent of the
shallow water facilities and are
expected to realize most of the benefits
in this rulemaking due to the greater
number of facilities operated.
Additional information can be found in
the IRFA in the rulemaking docket.
Unfunded Mandates Reform Act of 1995
This proposed rule would not impose
an unfunded mandate on State, local, or
tribal governments or the private sector
of more than $100 million per year. The
proposed rule would not have a
significant or unique effect on State,
local, or tribal governments or the
private sector. A statement containing
the information required by Unfunded
Mandates Reform Act (2 U.S.C. 1531 et
seq.) is not required.
Takings Implication Assessment (E.O.
12630)
Under the criteria in E.O. 12630, this
proposed rule does not have significant
takings implications. The proposed rule
is not a governmental action capable of
interference with constitutionally
protected property rights. A Takings
Implications Assessment is not
required.
Federalism (E.O. 13132)
Under the criteria in E.O. 13132, this
proposed rule does not have federalism
implications. This proposed rule would
not substantially and directly affect the
relationship between the Federal and
State governments. To the extent that
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State and local governments have a role
in OCS activities, this proposed rule
would not affect that role. A Federalism
Assessment is not required.
The BSEE has the authority to
regulate offshore oil and gas production.
State governments do not have authority
over offshore production on the OCS.
None of the changes in this proposed
rule would affect areas that are under
the jurisdiction of the States. It would
not change the way that the States and
the Federal government interact, or the
way that States interact with private
companies.
Civil Justice Reform (E.O. 12988)
This rule complies with the
requirements of E.O. 12988.
Specifically, this rule:
(a) Meets the criteria of section 3(a)
requiring that all regulations be
reviewed to eliminate errors, ambiguity,
and be written to minimize litigation;
and
(b) Meets the criteria of section 3(b)(2)
requiring that all regulations be written
in clear language and contain clear legal
standards.
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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
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Bureau’s Information Collection
Clearance Officer at (703) 787–1607. To
see a copy of the entire IC Review
submitted to OMB, go to https://
www.reginfo.gov (select Information
Collection Review, Currently Under
Review).
The PRA provides that an agency may
not conduct or sponsor, and a person is
not required to respond to, a collection
of information unless it displays a
currently valid OMB control number.
OMB is required to make a decision
concerning the collection of information
contained in these proposed regulations
30 to 60 days after publication of this
document in the Federal Register.
Therefore, a comment to OMB is best
assured of having its full effect if OMB
receives it by January 29, 2018. This
does not affect the deadline for the
public to comment to BSEE on the
proposed regulations.
The title of the collection of
information for this rule is 30 CFR part
250, subpart H, Oil and Gas Production
Safety Systems Revisions (Proposed
Rulemaking). The proposed regulations
concern oil and gas production
requirements, and the information is
used in our efforts to protect life and the
environment, conserve natural
resources, and prevent waste.
Potential respondents comprise
Federal OCS oil, gas, and Sulphur
operators and lessees. The frequency of
response varies depending upon the
requirement. Responses to this
collection of information are mandatory,
or are required to obtain or retain a
benefit; they are also submitted on
occasion, annually, and as a result of
situations encountered depending upon
the requirement. The IC does not
include questions of a sensitive nature.
The BSEE will protect proprietary
information according to the FOIA (5
U.S.C. 552) and its implementing
regulations (43 CFR part 2), 30 CFR part
252, OCS Oil and Gas Information
Program, and 30 CFR 250.197, Data and
Information to be made available to the
public or for limited inspection.
Proposed changes to the information
collection due to this rulemaking are as
follows:
• § 250.802(c)(1) is being eliminated
and would cause a reduction in nonhour costs burdens by ¥$550,000.
• § 250.842(c) is being eliminated and
would cause a reduction in hour burden
by ¥192 hours.
• During the 1014–AA10 rulemaking
(original Subpart H rewrite), BSEE
inadvertently omitted costs for
Professional Engineers required to
stamp documents in § 250.842. This
revision to the collection requests
approval of an additional $23,470,000
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61717
non-hour costs (PE Costs). We are
adding this category of costs in this
rulemaking but note that this
rulemaking reduces the amount of
information a PE must stamp from the
2016 rule.
Current subpart H regulations have
95,997 hours and $5,582,481 non-hour
cost burdens (cost recovery fees)
approved by OMB. Due to this
rulemaking, the revisions to the
collection would result in a total of
95,805 hours and $28,502,481 non-hour
cost burdens.
Once this rule becomes effective, the
changes in hour burdens and non-hour
cost burdens will be adjusted in the
current OMB approved collection
(1014–0003).
National Environmental Policy Act of
1969
BSEE has prepared a draft
environmental assessment (EA) to
determine whether this proposed rule
would have a significant impact on the
quality of the human environment
under the National Environmental
Policy Act of 1969 (NEPA) (42 U.S.C.
4321 et seq.). If the final EA supports
the issuance of a Finding of No
Significant Impact (FONSI) for the rule,
the preparation of an environmental
impact statement pursuant to the NEPA
would not be required.
The draft EA was placed in the file for
BSEE’s Administrative Record for the
rule at the address specified in the
ADDRESSES section. A copy of the draft
EA can be viewed at the Federal
eRulemaking Portal: https://
www.regulations.gov (use the keyword/
ID ‘‘BSEE–2017–0008’’).
Data Quality Act
In developing this rule we did not
conduct or use a study, experiment, or
survey requiring peer review under the
Data Quality Act (Pub. L. 106–554, app.
C § 515, 114 Stat. 2763, 2763A–153–
154).
Effects on the Nation’s Energy Supply
(E.O. 13211)
This proposed rule is not a significant
energy action under the definition in
E.O. 13211. A Statement of Energy
Effects is not required.
Clarity of This Regulation (E.O. 12866)
We are required by E.O. 12866, E.O.
12988, and by the Presidential
Memorandum of June 1, 1998, to write
all rules in plain language. This means
that each rule we publish must:
(a) Be logically organized;
(b) Use the active voice to address
readers directly;
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(c) Use clear language rather than
jargon;
(d) Be divided into short sections and
sentences; and
(e) Use lists and tables wherever
possible.
If you feel that we have not met these
requirements, send us comments by one
of the methods listed in the ADDRESSES
section. To better help us revise the
rule, your comments should be as
specific as possible. For example, you
should tell us the numbers of the
sections or paragraphs that you find
unclear, which sections or sentences are
too long, the sections where you feel
lists or tables would be useful, etc.
Public Availability of Comments
Before including your address, phone
number, email address, or other
personal identifying information in your
comment, you should be aware that
your entire comment—including your
personal identifying information—may
be made publicly available at any time.
While you can ask us in your comment
to withhold your personal identifying
information from public review, we
cannot guarantee that we will be able to
do so.
Severability
If a court holds any provisions of a
subsequent final rule or their
applicability to any person or
circumstances invalid, the remainder of
the provisions and their applicability to
other people or circumstances will not
be affected.
List of Subjects in 30 CFR Part 250
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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—rightsof-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:
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PART 250—OIL AND GAS AND
SULPHUR OPERATIONS IN THE
OUTER CONTINENTAL SHELF
1. The authority citation for part 250
continues to read as follows:
■
Authority: 30 U.S.C. 1751; 31 U.S.C. 9701;
33 U.S.C. 1321(j)(1)(C); 43 U.S.C. 1334.
2. Amend § 250. 198 by revising
paragraphs (g)(1),(2), and (3), (h)(1), (51),
(52), (53), (55), (56), (58), (59), (60), (61),
(62), (65), (68), (70), (71), (73), (74), and
(96) to read as follows:
■
§ 250.198 Documents incorporated by
reference.
*
*
*
*
*
(g) * * *
(1) ANSI/ASME Boiler and Pressure
Vessel Code, Section I, Rules for
Construction of Power Boilers;
including Appendices, 2017 Edition;
and July 2017 Addenda, and all Section
I Interpretations Volume 55,
incorporated by reference at
§§ 250.851(a), and 250.1629(b).
(2) ANSI/ASME Boiler and Pressure
Vessel Code, Section IV, Rules for
Construction of Heating Boilers;
including Appendices 1, 2, 3, 5, 6, and
Non-mandatory Appendices B, C, D, E,
F, H, I, K, L, and M, and the Guide to
Manufacturers Data Report Forms, 2017
Edition; July 2017 Addenda, and all
Section IV Interpretations Volume 55,
incorporated by reference at
§§ 250.851(a) and 250.1629(b).
(3) ANSI/ASME Boiler and Pressure
Vessel Code, Section VIII, Rules for
Construction of Pressure Vessels;
Divisions 1 and 2, 2017 Edition; July
2017 Addenda, Divisions 1, 2, and 3 and
all Section VIII Interpretations Volumes
54 and 55, incorporated by reference at
§§ 250.851(a) and 250.1629(b).
*
*
*
*
*
(h) * * *
(1) API 510, Pressure Vessel
Inspection Code: In-Service Inspection,
Rating, Repair, and Alteration,
Downstream Segment, Tenth Edition,
May 2014; Addendum 1, May 2017;
incorporated by reference at
§§ 250.851(a) and 250.1629(b);
*
*
*
*
*
(51) API STD 2RD, Dynamic Risers for
Floating Production Systems, Second
Edition, September 2013; incorporated
by reference at §§ 250.292, 250.733,
250.800(c), 250.901(a), (d), and
250.1002(b);
(52) API RP 2SK, Recommended
Practice for Design and Analysis of
Stationkeeping Systems for Floating
Structures, Third Edition, October 2005,
Addendum, May 2008, Reaffirmed June
2015; incorporated by reference at
§§ 250.800(c) and 250.901(a) and (d);
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(53) API RP 2SM, Recommended
Practice for Design, Manufacture,
Installation, and Maintenance of
Synthetic Fiber Ropes for Offshore
Mooring, Second Edition, July 2014;
incorporated by reference at
§§ 250.800(c) and 250.901;
*
*
*
*
*
(55) ANSI/API RP 14B, Recommended
Practice for Design, Installation, Repair
and Operation of Subsurface Safety
Valve Systems, Sixth Edition,
September 2015; incorporated by
reference at §§ 250.802(b), 250.803(a),
250.814(d), 250.828(c), and 250.880(c);
(56) API RP 14C, Recommended
Practice for Analysis, Design,
Installation, and Testing of Safety
Systems for Offshore Production
Facilities, Eight Edition, February 2017;
incorporated by reference at
§§ 250.125(a), 250.292(j), 250.841(a),
250.842(a), 250.850, 250.852(a),
250.855, 250.856(a), 250.858(a),
250.862(e), 250.865(a), 250.867(a),
250.869(a) through (c), 250.872(a),
250.873(a), 250.874(a), 250.880(b) and
(c), 250.1002(d), 250.1004(b),
250.1628(c) and (d), 250.1629(b), and
250.1630(a);
*
*
*
*
*
(58) API RP 14F, Recommended
Practice for Design, Installation, and
Maintenance of Electrical Systems for
Fixed and Floating Offshore Petroleum
Facilities for Unclassified and Class 1,
Division 1 and Division 2 Locations,
Upstream Segment, Fifth Edition, July
2008, Reaffirmed: April 2013;
incorporated by reference at
§§ 250.114(c), 250.842(c), 250.862(e),
and 250.1629(b);
(59) API RP 14FZ, Recommended
Practice for Design and Installation of
Electrical Systems for Fixed and
Floating Offshore Petroleum Facilities
for Unclassified and Class I, Zone 0,
Zone 1 and Zone 2 Locations, Second
Edition, May 2013; incorporated by
reference at §§ 250.114(c), 250.842(c),
250.862(e), and 250.1629(b);
(60) API RP 14G, Recommended
Practice for Fire Prevention and Control
on Fixed Open-type Offshore
Production Platforms, Fourth Edition,
April 2008, reaffirmed January 2013;
incorporated by reference at
§§ 250.859(a), 250.862(e), 250.880(c),
and 250.1629(b);
(61) API STD 6AV2, Installation,
Maintenance, and Repair of Surface
Safety Valves and Underwater Safety
Valves Offshore; First Edition, March
2014; Errata 1, August 2014;
incorporated by reference at §§ 250.820,
250.834, 250.836, and 250.880(c);
(62) API RP 14J, Recommended
Practice for Design and Hazards
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Analysis for Offshore Production
Facilities, Second Edition, May 2001;
Reaffirmed: January 2013; incorporated
by reference at §§ 250.800(b) and (c),
250.842(c), and 250.901(a);
*
*
*
*
*
(65) API RP 500, Recommended
Practice for Classification of Locations
for Electrical Installations at Petroleum
Facilities Classified as Class I, Division
1 and Division 2, Third Edition,
December 2012; Errata January 2014,
API Stock No. C50002; incorporated by
reference at §§ 250.114(a), 250.459,
250.842(a), 250.862(a) and (e),
250.872(a), 250.1628(b) and (d), and
250.1629(b);
*
*
*
*
*
(68) ANSI/API Specification Q1
(ANSI/API Spec. Q1), Specification for
Quality Programs for the Petroleum,
Petrochemical and Natural Gas Industry,
Ninth Edition, June 1, 2014; Errata,
February 2014; Errata 2, March 2014;
Addendum 1, June 2016; incorporated
by reference at §§ 250.730, 250.801(b)
and (c);
*
*
*
*
*
(70) ANSI/API Specification 6A
(ANSI/API Spec. 6A), Specification for
Wellhead and Christmas Tree
Equipment, Twentieth Edition, October
2010; Addendum 1, November 2011;
Errata 2, November 2011; Addendum 2,
November 2012; Addendum 3, March
2013; Errata 3, June 2013; Errata 4,
August 2013; Errata 5, November 2013;
Errata 6, March 2014; Errata 7,
December 2014; Errata 8, February 2016;
Addendum 4: June 2016; Errata 9, June
2016; Errata 10, August 2016;
incorporated by reference at §§ 250.730,
250.802(a), 250.803(a), 250.833,
250.873(b), 250.874(g), and 250.1002(b);
(71) API Spec. 6AV1, Specification for
Verification Test of Wellhead Surface
Safety Valves and Underwater Safety
Valves for Offshore Service, Second
Edition, February 2013; incorporated by
reference at §§ 250.802(a), 250.833,
250.873(b), and 250.874(g);
*
*
*
*
*
(73) ANSI/API Spec. 14A,
Specification for Subsurface Safety
Valve Equipment, 12th Ed. January
2015; Errata, July 2015; Addendum,
June 2017; incorporated by reference at
§§ 250.802(b) and 250.803(a);
(74) ANSI/API Spec. 17J,
Specification for Unbonded Flexible
Pipe, Fourth Edition, May 2014; Errata
1, September 2016; Errata 2, May 2017;
incorporated by reference at
§§ 250.852(e), 250.1002(b), and
250.1007(a).
*
*
*
*
*
(96) API 570 Piping Inspection Code:
In-service Inspection, Rating, Repair,
and Alteration of Piping Systems,
Fourth Edition, February 2016;
Addendum 1: May 2017; incorporated
by reference at § 250.841(b).
*
*
*
*
*
■ 3. Amend § 250.292 by revising
paragraph (p)(3) to read as follows:
§ 250.292
What must the DWOP contain?
*
*
*
*
*
(p) * * *
(3) A description of how you met the
design requirements, load cases, and
allowable stresses for each load case
according to API STD 2RD (as
incorporated by reference in § 250.198);
*
*
*
*
*
■ 4. Amend § 250.800 revise paragraph
(c)(2) to read as follows:
§ 250.800
General.
*
*
*
*
*
(c) * * *
(2) Meet the production riser
standards of API STD 2RD (incorporated
by reference as specified in § 250.198),
provided that you may not install single
bore production risers from floating
production facilities;
*
*
*
*
*
■ 5. Amend § 250.801 by revising
paragraph (a) to read as follows:
§ 250.801 Safety and pollution prevention
equipment (SPPE) certification.
(a) SPPE equipment. You must install
only safety and pollution prevention
equipment (SPPE) considered certified
under paragraph (b) of this section or
accepted under paragraph (c) of this
section. BSEE considers the following
equipment to be types of SPPE:
(1) Surface safety valves (SSV) and
actuators, including those installed on
injection wells capable of natural flow;
(2) Boarding shutdown valves (BSDV)
and their actuators. For subsea wells,
the BSDV is the surface equivalent of an
SSV on a surface well;
(3) Underwater safety valves (USV)
and actuators;
(4) Subsurface safety valves (SSSV)
and associated safety valve locks and
landing nipples; and
(5) Gas lift shutdown valves (GLSDV)
and their actuators.
*
*
*
*
*
■ 6. Amend § 250.802 paragraphs (a),
(c), and (d) to read as follows:
§ 250.802
Requirements for SPPE.
(a) All SSVs, BSDVs, USVs, and
GLSDVs and their actuators must meet
all of the specifications contained in
ANSI/API Spec. 6A and API Spec. 6AV1
(both incorporated by reference as
specified in § 250.198).
*
*
*
*
*
(c) Requirements derived from the
documents incorporated in this section
for SSVs, BSDVs, USVs, USVs, GLSDVs,
and their actuators, include, but are not
limited to, the following:
(1) All materials and parts must meet
the original equipment manufacturer
specifications and acceptance criteria.
(2) The device must pass applicable
validation tests and functional tests
performed by an API-licensed test
agency.
(3) You must have requalification
testing performed following
manufacture design changes.
(4) You must comply with and
document all manufacturing,
traceability, quality control, and
inspection requirements.
(5) You must follow specified
installation, testing, and repair
protocols.
(6) You must use only qualified parts,
procedures, and personnel to repair or
redress equipment.
(d) You must install and use SPPE
according to the following table.
If . . .
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Then . . .
(1) You need to install any SPPE ............................................................
(2) A non-certified SPPE is already in service .........................................
(3) A non-certified SPPE requires offsite repair, re-manufacturing, or
any hot work such as welding.
You must install SPPE that conforms to § 250.801.
It may remain in service.
You must replace it with SPPE that conforms to § 250.801.
*
■
*
*
*
*
7. Revise § 250.803 to read as follows:
§ 250.803 What SPPE failure reporting
procedures must I follow?
(a) You must follow the failure
reporting requirements contained in
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section 10.20.7.4 of ANSI/API Spec. 6A
SSVs, BSDVs, GLSDVs and USVs and
section 7.10 of ANSI/API Spec. 14A and
Annex F of API RP 14B for SSSVs (all
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incorporated by reference in § 250.198).
Within 30 days after the discovery and
identification of the failure, you must
provide a written notice of equipment
failure to the manufacturer of such
equipment and to BSEE through the
Chief, Office of Offshore Regulatory
Programs, unless BSEE has designated a
third party as provided in paragraph (d)
of this section. A failure is any
condition that prevents the equipment
from meeting the functional
specification or purpose.
(b) You must ensure that an
investigation and a failure analysis are
performed within 120 days of the failure
to determine the cause of the failure. If
the investigation and analyses are
performed by an entity other than the
manufacturer, you must ensure that the
analysis report is submitted to the
manufacturer and to BSEE through the
Chief, Office of Offshore Regulatory
Programs, unless BSEE has designated a
third party as provided in paragraph (d)
of this section. You must also ensure
that the results of the investigation and
any corrective action are documented in
the analysis report.
(c) If the equipment manufacturer
notifies you that it has changed the
design of the equipment that failed or if
you have changed operating or repair
procedures as a result of a failure, then
you must, within 30 days of such
changes, report the design change or
modified procedures in writing to BSEE
through the Chief, Office of Offshore
Regulatory Programs, unless BSEE has
designated a third party as provided in
paragraph (d) of this section.
(d) BSEE may designate a third party
to receive this data on behalf of BSEE.
If BSEE designates a third party, you
must submit the information required in
this section to the designated third
party, as directed by BSEE.
■ 8. Amend § 250.814 by revising
paragraph (d) to read as follows:
§ 250.814 Design, installation, and
operation of SSSVs—dry trees.
*
*
*
*
(d) You must design, install, maintain,
inspect, repair, and test all SSSVs in
accordance with ANSI/API RP 14B
(incorporated by reference as specified
in § 250.198). For additional SSSV
testing requirements, refer to § 250.880.
■ 9. Revise § 250.820 to read as follows:
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§ 250.820
Use of SSVs.
You must install, maintain, inspect,
repair, and test all SSVs in accordance
with API STD 6AV2 (incorporated by
reference as specified in § 250.198). If
any SSV does not operate properly, or
if any gas and/or liquid fluid flow is
observed during the leakage test as
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described in § 250.880, then you must
shut-in all sources to the SSV and repair
or replace the valve before resuming
production.
■ 10. Amend § 250.821 by revising
paragraph (a) to read as follows:
§ 250.821 Emergency action and safety
system shutdown—dry trees.
(a) If your facility is impacted or will
potentially be impacted by an
emergency situation (e.g., an impending
National Weather Service-named
tropical storm or hurricane, ice events
in the Arctic, or post-earthquake), you
must:
(1) Properly install a subsurface safety
device on any well that is not yet
equipped with a subsurface safety
device and that is capable of natural
flow, as soon as possible, with due
consideration being given to personnel
safety.
*
*
*
*
*
■ 11. Amend § 250.828 by revising
paragraph (c) to read as follows:
§ 250.828 Design, installation, and
operation of SSSVs—subsea trees.
*
*
*
*
*
(c) You must design, install, maintain,
inspect, repair, and test all SSSVs in
accordance with your Deepwater
Operations Plan (DWOP) and ANSI/API
RP 14B (incorporated by reference as
specified in § 250.198). For additional
SSSV testing requirements, refer to
§ 250.880.
■ 12. Amend § 250.833, by revising the
introductory text to read as follows:
§ 250.833 Specification for underwater
safety valves (USVs).
All USVs, including those designated
as primary or secondary, and any
alternate isolation valve (AIV) that acts
as a USV, if applicable, and their
actuators, must conform to the
requirements specified in §§ 250.801
through 250.803. A production master
or wing valve may qualify as a USV
under ANSI/API Spec. 6A and API
Spec. 6AV1 (both incorporated by
reference as specified in § 250.198).
*
*
*
*
*
■ 13. Revise § 250.834 to read as
follows:
§ 250.834
Use of USVs.
You must install, maintain, inspect,
repair, and test any valve designated as
the primary USV in accordance with
this subpart, your DWOP (as specified
in §§ 250.286 through 250.295), and API
STD 6AV2 (incorporated by reference as
specified in § 250.198). For additional
USV testing requirements, refer to
§ 250.880.
■ 14. Revise § 250.836 to read as
follows:
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§ 250.836
Use of BSDVs.
You must install, inspect, maintain,
repair, and test all new BSDVs and
BSDVs that you remove from service for
remanufacturing or repair in accordance
with API STD 6AV2 (incorporated by
reference as specified in § 250.198) for
SSVs. If any BSDV does not operate
properly or if any gas fluid and/or liquid
fluid flow is observed during the
leakage test, as described in § 250.880,
you must shut-in all sources to the
BSDV and immediately repair or replace
the valve.
■ 15. Amend § 250.837 by revising
paragraphs (a), (b), and (c)(5) to read as
follows:
§ 250.837 Emergency action and safety
system shutdown—subsea trees.
(a) If your facility is impacted or will
potentially be impacted by an
emergency situation (e.g., an impending
National Weather Service-named
tropical storm or hurricane, ice events
in the Arctic, or post-earthquake), you
must shut-in all subsea wells unless
otherwise approved by the District
Manager. A shut-in is defined as a
closed BSDV, USV, GLSDV, and
surface-controlled SSSV.
(b) When operating a vessel (e.g.,
mobile offshore drilling unit (MODU) or
other type of workover or intervention
vessel) in an area with subsea
infrastructure, you must:
(1) Suspend production from all such
wells that could be affected by a
dropped object, including upstream
wells that flow through the same
pipeline; or
(2) Establish direct, real-time
communications between the vessel and
the production facility control room and
develop a dropped objects plan, as
required in § 250.714. If an object is
dropped, you must immediately secure
the well directly under the vessel while
simultaneously communicating with the
platform to shut-in all affected wells.
You must also maintain without
disruption, and continuously verify,
communication between the production
facility and the vessel. If
communication is lost between the
vessel and the platform for 20 minutes
or more, you must shut-in all wells that
could be affected by a dropped object.
(c) * * *
(5) Subsea ESD (vessel). In the event
of an ESD activation that is initiated by
a dropped object from a vessel, you
must secure all wells in the proximity
of the vessel by closing the USVs and
surface-controlled SSSVs in accordance
with the applicable tables in §§ 250.838
and 250.839. You must notify the
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appropriate District Manager before
resuming production.
*
*
*
*
*
■ 16. Amend § 250.841, by adding
paragraph (c) to read as follows:
§ 250.841
17. Amend § 250. 842 by:
■ a. Revising paragraph (a);
■ b. Removing paragraph (c);
■ c. Redesignating paragraph (b) as
paragraph (c);
■ d. Adding a new paragraph (b);
■ e. Revising paragraph (d);
■ f. Removing paragraph (e); and
■ g. Redesignating existing paragraph (f)
as (e) to read as follows:
■
Platforms.
*
*
*
*
*
(c) If you plan to make a major
modification to any facility you must
follow the requirements in
§ 250.900(b)(2). A major modification is
defined in § 250.900(b)(2).
61721
§ 250.842 Approval of safety systems
design and installation features.
(a) Before you install or modify a
production safety system, you must
submit a production safety system
application to the District Manager. The
District Manager must approve your
production safety system application
before you commence production
through or utilize the new or modified
system. The application must include
the information prescribed in the
following table:
You must submit:
Details and/or additional requirements:
(1) Safety analysis flow diagram (API RP 14C, Annex B) and Safety
Analysis Function Evaluation (SAFE) chart (API RP 14C, section
6.3.3) (incorporated by reference in 2500.198).
Your safety analysis flow diagram must show the following:
(i) Well shut-in tubing pressure;
(ii) Piping specification breaks, piping sizes;
(iii) Pressure relieving device set points;
(iv) Size, capacity, and design working pressures of separators, flare
scrubbers, heat exchangers, treaters, storage tanks, compressors
and metering devices;
(v) Size, capacity, design working pressures, and maximum discharge
pressure of hydrocarbon-handling pumps;
(vi) Size, capacity, and design working pressures of hydrocarbon-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 § 250.198); and
(vii) Size and maximum allowable working pressures as determined in
accordance with API RP 14E (incorporated by reference as specified
in § 250.198).
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.
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 § 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.
A detailed diagram which shows the piping and vessels in the process
flow, together with the instrumentation and control devices.
The fee you must pay will be determined by the number of components involved in the review and approval process.
(2) Electrical one-line diagram .................................................................
(3) Area classification diagram .................................................................
(4) A schematic piping and instrumentation diagram, for new facilities ..
(5) The service fee listed in § 250.125 .....................................................
(b) You must develop and maintain
the following diagrams and make them
available to BSEE upon request:
Details and/or additional requirements:
(1) Additional electrical system information, ............................................
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Diagram:
(i) Cable tray/conduit routing plan which identifies the primary wiring
method (e.g., type cable, conduit, wire);
(ii) Cable schedule; and
(iii) Panel board/junction box location plan.
Showing a functional block 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.
A detailed diagram which shows the piping and vessels in the process
flow, together with the instrumentation and control devices.
(2) Schematics of the fire and gas-detection systems .............................
(3) Revised P&ID for existing facilities .....................................................
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(c) In the production safety system
application, you must also certify the
following:
(1) That all electrical installations
were designed according to API RP 14F
or API RP 14FZ, as applicable
(incorporated by reference as specified
in § 250.198);
(2) That the designs for the
mechanical and electrical systems that
you are required to submit under
paragraph (a) of this section were
reviewed, approved, and stamped by an
appropriate registered professional
engineer(s). For modified systems, only
the modifications are required to be
approved and stamped by an
appropriate registered professional
engineer(s). The registered professional
engineer must be registered in a State or
Territory of the United States and have
sufficient expertise and experience to
perform the duties; and
(3) That a hazards analysis was
performed in accordance with
§ 250.1911 and API RP 14J (incorporated
by reference as specified in § 250.198),
and that you have a hazards analysis
program in place to assess potential
hazards during the operation of the
facility.
(d) Within 60 days after production
commences, you must submit to the
District Manager the as-built diagrams
for the new or modified production
safety systems outlined in paragraphs
(a)(1), (2), and (3) of this section, the
diagrams must be reviewed, approved,
and stamped by an appropriate
registered professional engineer(s). The
registered professional engineer must be
registered in a State or Territory in the
United States and have sufficient
expertise and experience to perform the
duties.
■ 18. Amend § 250.851 by revising
paragraph (a)(2) to read as follows:
§ 250.851 Pressure vessels (including heat
exchangers) and fired vessels.
(a) * * *
Item name
Applicable codes and requirements
*
*
*
*
(2) Existing uncoded pressure and fired vessels; (i) with an operating pressure
greater than 15 psig; and (ii) that are not code stamped in accordance with the
ANSI/ASME Boiler and Pressure Vessel Code.
*
*
*
Must be justified and approval obtained from the District
Manager for their continued use.
*
*
*
*
*
*
*
19. Amend § 250.852 by revising
paragraphs (e)(1) and (e)(4) to read as
follows:
■
Flowlines/Headers.
*
*
*
*
*
(e) * * *
(1) Review the manufacturer’s Design
Methodology Verification Report and
the independent verification agent’s
(IVA’s) certificate for the design
methodology contained in that report to
ensure that the manufacturer has
complied with the requirements of
ANSI/API Spec. 17J (incorporated by
reference as specified in § 250.198);
* * *
(4) Submit to the District Manager a
statement certifying that the pipe is
suitable for its intended use and that the
manufacturer has complied with the
IVA requirements of ANSI/API Spec.
17J (incorporated by reference as
specified in § 250.198).
*
*
*
*
*
■ 20. Amend § 250.853 by adding
paragraph (d) to read as follows:
§ 250.853
Safety sensors.
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*
*
*
*
*
(d) All level sensors are equipped to
permit testing through an external bridle
on all new vessel installations where
possible, depending on the type of
vessel for which the level sensor is
used.
■ 21. Amend § 250.867 by revising
paragraph (a) and adding paragraph (d)
to read as follows:
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*
§ 250.867 Temporary quarters and
temporary equipment.
*
§ 250.852
*
(a) You must equip temporary
quarters with all safety devices required
by API RP 14C, Annex G (incorporated
by reference as specified in § 250.198).
The District Manager must approve the
safety system/safety devices associated
with the temporary quarters prior to
installation.
*
*
*
*
*
(d) The District Manager must
approve temporary generators that
would require a change to the electrical
one-line diagram in § 250.842(a).
■ 22. Amend § 250.870 by revising
paragraph (a) to read as follows:
§ 250.870 Time delays on pressure safety
low (PSL) sensors.
(a) You may apply industry standard
Class B, Class C, or Class B/C logic to
applicable PSL sensors installed on
process equipment. If the device may be
bypassed for greater than 45 seconds,
you must monitor the bypassed devices
in accordance with § 250.869(a). You
must document on your field test
records any use of a PSL sensor with a
time delay greater than 45 seconds. For
purposes of this section, PSL sensors are
categorized as follows:
*
*
*
*
*
■ 23. Revise § 250.872 to read as
follows:
§ 250.872
Atmospheric vessels.
(a) You must equip atmospheric
vessels used to process and/or store
liquid hydrocarbons or other Class I
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*
*
liquids as described in API RP 500 or
505 (both incorporated by reference as
specified in § 250.198) with protective
equipment identified in API RP 14C,
section A.6 (incorporated by reference
as specified in § 250.198). Transport
tanks approved by the U.S. Department
of Transportation, that are sealed and
not connected via interconnected piping
to the production process train and that
are used only for storage of refined
liquid hydrocarbons or Class I liquids,
are not required to be equipped with the
protective equipment identified in API
RP 14C, section A.5. The atmospheric
vessels connected to the process system
that contains a Class I liquid and the
associated pumps must be reflected on
the corresponding drawings.
(b) You must ensure that all
atmospheric vessels are designed and
maintained to ensure the proper
working conditions for LSH sensors.
The LSH must be designed in such a
way to prevent pollution as required by
§ 250.300(b)(3) and (4). The LSH sensor
bridle must be designed to prevent
different density fluids from impacting
sensor functionality. For newly installed
atmospheric vessels that have oil
buckets, the LSH sensor must be
installed to sense the level in the oil
bucket.
■ 24. Amend § 250.873 by revising
paragraph (b)(3) to read as follows:
§ 250.873
*
Subsea gas lift requirements.
*
*
(b) * * *
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61723
Then you must install a
If your subsea gas
lift system
introduces the
lift gas to the . . .
ANSI/API Spec 6A and API Spec
6AV1 (both incorporated by reference
as specified in § 250.198) gas-lift
shutdown valve (GLSDV), and . . .
*
(3) Pipeline risers
via a gas-lift line
contained within
the pipeline riser.
*
*
Meet all of the requirements for the upstream (inGLSDV described in §§ 250.835(a),
board) of the
(b), and (d) and 250.836 on the
GLSDV.
gas-lift supply pipeline. Attach the
GLSDV by flanged connection directly to the ANSI/API Spec. 6A
component used to suspend and
seal the gas-lift line contained within the production riser. To facilitate
the repair or replacement of the
GLSDV or production riser BSDV,
you may install a manual isolation
valve between the GLSDV and the
ANSI/API Spec. 6A component
used to suspend and seal the gaslift line contained within the production riser, or outboard of the production riser BSDV and inboard of
the ANSI/API Spec. 6A component
used to suspend and seal the gaslift line contained within the production riser.
*
*
*
*
25. Amend § 250.874 by revising
paragraph (g)(2) to read as follows:
■
Subsea water injection systems.
*
*
*
*
(g) * * *
(2) If a designated USV on a water
injection well fails the applicable test
under § 250.880(c)(4)(ii), you must
notify the appropriate District Manager
and request approval to designate
another ANSI/API Spec 6A and API
Spec. 6AV1 (both incorporated by
reference as specified in § 250.198)
certified subsea valve as your USV.
*
*
*
*
*
■ 26. Revise § 250.876 to read as
follows:
ethrower on DSK3G9T082PROD with PROPOSALS
*
VerDate Sep<11>2014
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Jkt 244001
ANSI/API Spec 6A
and API Spec
6AV1 manual isolation valve . . .
PSHL on the gaslift supply . . .
*
*
flowline upstream
(in-board) of the
FSV.
*
downstream (out
board) of the
GLSDV.
§ 250.876 Fired and exhaust heated
components.
*
§ 250.874
FSV on the gas-lift
supply pipeline
. . .
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.
PO 00000
Frm 00026
Fmt 4702
Sfmt 4702
In addition, you must
*
(i) Ensure that the gas-lift supply
flowline from the gas-lift compressor to the GLSDV is pressurerated for the MAOP of the pipeline
riser.
(ii) Ensure that any surface equipment
associated with the gas-lift system
is rated for the MAOP of the pipeline riser.
(iii) Ensure that the gas-lift compressor discharge pressure never
exceeds the MAOP of the pipeline
riser.
(iv) Suspend and seal the gas-lift
flowline contained within the production riser in a flanged ANSI/API
Spec. 6A component such as an
ANSI/API Spec. 6A tubing head
and tubing hanger or a component
designed, constructed, tested, and
installed to the requirements of
ANSI/API Spec. 6A.
(v) Ensure that all potential leak paths
upstream or near the production
riser BSDV on the platform provide
the same level of safety and environmental protection as the production riser BSDV.
(vi) Ensure that this complete assembly is fire-rated for 30 minutes.
27. Amend § 250.880 by revising
paragraphs (a) introductory text, (a)(1)
(c)(1)(i), (c)(2)(iv), (c)(4)(i) and (iii) to
read as follows:
■
§ 250.880
testing.
Production safety system
(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) * * *
E:\FR\FM\29DEP1.SGM
29DEP1
61724
Federal Register / Vol. 82, No. 249 / Friday, December 29, 2017 / Proposed Rules
Item name
Testing frequency, allowable leakage rates, and other requirements
(i) Surface-controlled SSSVs (including
devices installed in shut-in and injection wells.
Semi-annually, not to exceed 6 calendar months between tests. Also test in place when first installed
or reinstalled. If the device does not operate properly, or if a liquid leakage rate >400 cubic 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 § 250.198) to ensure proper operation.
*
*
*
*
*
*
*
*
*
*
*
*
(2) * * *
Item name
Testing frequency and requirements
*
*
(iv) SSVs ..................................................
*
*
*
*
*
Once each calendar month, not to exceed 6 weeks between tests. Valves must be tested for both
operation and leakage. You must test according to API STD 6AV2 (incorporated by reference as
specified in § 250.198). If an SSV does not operate properly or if any gas and/or liquid fluid flow is
observed during the leakage test, the valve must be immediately repaired or replaced.
*
*
*
*
*
*
*
*
*
*
*
*
(4) * * *
Item name
Testing frequency, allowable leakage rates, and other requirements
(i) Surface-controlled SSSVs (including
devices installed in shut-in and injection wells).
Tested semiannually, not to exceed 6 months between tests. If the device does not operate properly,
or if a liquid leakage rate >400 cubic centimeters per minute or a gas leakage rate >15 standard
cubic feet per minute is observed, the device must be removed, repaired, and reinstalled or replaced. Testing must be according to ANSI/API RP 14B (incorporated by reference as specified in
§ 250.198) to ensure proper operation, or as approved in your DWOP.
*
*
(iii) BSDVs ...............................................
*
*
*
*
*
Tested at least once each calendar month, not to exceed 6 weeks between tests. Valves must be
tested for both operation and leakage. You must test according to API STD 6AV2 for SSVs (incorporated by reference as specified in § 250.198). If a BSDV does not operate properly or if any fluid
flow is observed during the leakage test, the valve must be immediately repaired or replaced.
*
*
*
*
*
*
*
*
28. Amend § 250.901 by revising
paragraph (a)(10) and (d)(19) to read as
follows:
■
ethrower on DSK3G9T082PROD with PROPOSALS
§ 250.901 What industry standards must
your platform meet?
(a) * * *
(10) API STD 2RD, Design of Risers
for Floating Production Systems (FPSs)
and Tension-Leg Platforms (TLPs), (as
incorporated by reference in § 250.198);
*
*
*
*
*
(d) * * *
(19) API STD 2RD, Design of Risers
for Floating Production Systems (FPSs)
and Tension-Leg Platforms (TLPs);
*
*
*
*
*
■ 29. Amend § 250.1002 by revising
paragraphs (b)(1), (2), (4) and (5) to read
as follows:
§ 250.1002
pipelines.
Design requirements for DOI
*
*
*
*
*
(b)(1) Pipeline valves shall meet the
minimum design requirements of ANSI/
VerDate Sep<11>2014
15:55 Dec 28, 2017
Jkt 244001
*
*
API Spec 6A (as incorporated by
reference in § 250.198), API Spec 6D (as
incorporated by reference in § 250.198),
or the equivalent. A valve may not be
used under operating conditions that
exceed the applicable pressuretemperature 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
PO 00000
Frm 00027
Fmt 4702
Sfmt 9990
*
*
Spec 17J, as incorporated by reference
in 30 CFR 250.198.
(5) You must design pipeline risers for
tension leg platforms and other floating
platforms according to the design
standards of API STD 2RD, Design of
Risers for Floating Production Systems
(FPSs) and Tension Leg Platforms
(TLPs) (as incorporated by reference in
§ 250.198).
*
*
*
*
*
■ 30. Amend § 250.1007 by revising
paragraph (a)(4)(i)(D) to read as follows:
§ 250.1007
What to include in applications.
(a) * * *
(4) * * *
(i) * * *
(D) A review by a third-party
independent verification agent (IVA)
according to ANSI/API Spec 17J (as
incorporated by reference in § 250.198),
if applicable.
*
*
*
*
*
[FR Doc. 2017–27309 Filed 12–28–17; 8:45 am]
BILLING CODE 4310–VH–P
E:\FR\FM\29DEP1.SGM
29DEP1
Agencies
- DEPARTMENT OF THE INTERIOR
- Bureau of Safety and Environmental Enforcement
[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]
=======================================================================
-----------------------------------------------------------------------
DEPARTMENT OF THE INTERIOR
Bureau of Safety and Environmental Enforcement
30 CFR Part 250
[Docket ID: BSEE-2017-0008; 189E1700D2 ET1SF0000.PSB000 EEEE500000]
RIN 1014-AA37
Oil and Gas and Sulphur Operations on the Outer Continental
Shelf--Oil and Gas Production Safety Systems--Revisions
AGENCY: Bureau of Safety and Environmental Enforcement, Interior.
ACTION: Proposed rule.
-----------------------------------------------------------------------
SUMMARY: The Bureau of Safety and Environmental Enforcement (BSEE)
proposes to amend the regulations regarding oil and natural gas
production to reduce certain unnecessary regulatory burdens imposed
under the existing regulations, while correcting errors and clarifying
current requirements. Accordingly, after thoroughly reexamining the
current regulations, and based on experiences from the implementation
process, and BSEE policy, BSEE proposes to amend, revise, or remove
current regulatory provisions that create unnecessary burdens on
stakeholders while maintaining or advancing the level of safety and
environmental protection.
DATES: Submit comments by January 29, 2018. BSEE may not fully consider
comments received after this date. You may submit comments to the
Office of Management and Budget (OMB) on the information collection
burden in this proposed rule by January 29, 2018. The deadline for
comments on the information collection burden does not affect the
deadline for the public to comment to BSEE on the proposed regulations.
ADDRESSES: You may submit comments on the rulemaking by any of the
following methods. Please use the Regulation Identifier Number (RIN)
1014-AA37 as an identifier in your message. See also Public
Availability of Comments under Procedural Matters.
Federal eRulemaking Portal: https://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: https://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.''
---------------------------------------------------------------------------
\1\ Oil and Gas and Sulfur Operations in the Outer Continental
Shelf--Blowout Preventer Systems and Well Control, 81 FR 25887
(April 29, 2016).
---------------------------------------------------------------------------
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: https://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: https://www.api.org/publications-standards-and-statistics/publications/government-cited-safety-documents.
---------------------------------------------------------------------------
\2\ To view these standards online, go to the API publications
website at: https://publications.api.org. You must then log-in or
create a new account, accept API's ``Terms and Conditions,'' click
on the ``Browse Documents'' button, and then select the applicable
category (e.g., ``Exploration and Production'') for the standard(s)
you wish to review.
---------------------------------------------------------------------------
For the convenience of members of the viewing public who may not
wish to purchase 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 https://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