Oil and Gas and Sulfur Operations on the Outer Continental Shelf-Oil and Gas Production Safety Systems, 61833-61939 [2016-20967]

Agencies

• DEPARTMENT OF THE INTERIOR
• Bureau of Safety and Environmental Enforcement

[Federal Register Volume 81, Number 173 (Wednesday, September 7, 2016)]
[Rules and Regulations]
[Pages 61833-61939]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2016-20967]



[[Page 61833]]

Vol. 81

Wednesday,

No. 173

September 7, 2016

Part III





Department of the Interior





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Bureau of Safety and Environmental Enforcement





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30 CFR Part 250





Oil and Gas and Sulfur Operations on the Outer Continental Shelf--Oil 
and Gas Production Safety Systems; Final Rule

Federal Register / Vol. 81 , No. 173 / Wednesday, September 7, 2016 / 
Rules and Regulations

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DEPARTMENT OF THE INTERIOR

Bureau of Safety and Environmental Enforcement

30 CFR Part 250

[Docket ID: BSEE-2012-0005; 16XE1700DX EX1SF0000.DAQ000 EEEE500000]
RIN 1014-AA10


Oil and Gas and Sulfur Operations on the Outer Continental 
Shelf--Oil and Gas Production Safety Systems

AGENCY: Bureau of Safety and Environmental Enforcement (BSEE), 
Interior.

ACTION: Final rule.

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SUMMARY: The Bureau of Safety and Environmental Enforcement (BSEE) is 
amending and updating the regulations regarding oil and natural gas 
production safety on the Outer Continental Shelf (OCS) by addressing 
issues such as: Safety and pollution prevention equipment design and 
maintenance, production safety systems, subsurface safety devices, and 
safety device testing. The rule differentiates the requirements for 
operating dry tree and subsea tree production systems and divides the 
current BSEE regulations regarding oil and gas production safety 
systems into multiple sections to make the regulations easier to read 
and understand. The changes in this rule are necessary to improve human 
safety, environmental protection, and regulatory oversight of critical 
equipment involving production safety systems.

DATES: This rule becomes effective on November 7, 2016. Compliance with 
certain provisions of the final rule, however, will be deferred until 
the times specified in those provisions and as described in part II.E 
of this document.
    The incorporation by reference of certain publications listed in 
the rule is approved by the Director of the Federal Register as of 
November 7, 2016.

FOR FURTHER INFORMATION CONTACT: Amy White, BSEE, Office of Offshore 
Regulatory Programs, Regulations Development Section, at 571-230-2475 
or at regs@bsee.gov.

SUPPLEMENTARY INFORMATION: 

Executive Summary

    This rule amends and updates BSEE's regulations for oil and gas 
production safety systems. The regulations (30 CFR part 250, subpart H) 
have not, until now, undergone a major revision since they were first 
published in 1988. Since that time, much of the oil and gas production 
on the OCS has moved into deeper waters and the regulations have not 
kept pace with the technological advancements.
    These regulations address issues such as production safety systems, 
subsurface safety devices, safety device testing, and production 
processing systems and areas. These systems play a critical role in 
protecting workers and the environment. In this final rule, BSEE has 
made the following changes to subpart H:
     Restructured subpart H to have shorter, easier-to-read 
sections and clearer, more descriptive headings.
     Updated and improved safety and pollution prevention 
equipment (SPPE) design, maintenance, and repair requirements in order 
to increase the overall level of certainty that this equipment will 
perform as intended, including in emergency situations.
     Expanded the regulations to differentiate the requirements 
for operating dry tree and subsea tree production systems on the OCS.
     Incorporated by reference new industry standards and 
update the previous partial incorporation of other standards to require 
compliance with the complete standards.
     Added new requirements for firefighting systems, shutdown 
valves and systems, valve closure and leakage, and high pressure/high 
temperature (HPHT) well equipment.
     Rewrote the subpart in plain language.
    In addition to revising subpart H, we are revising the existing 
regulation (Sec.  250.107(c)) that requires the use of best available 
and safest technology (BAST) to follow more closely the Outer 
Continental Shelf Lands Act's (OCSLA, or the Act) statutory language 
regarding BAST.

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[GRAPHIC] [TIFF OMITTED] TR07SE16.004


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[GRAPHIC] [TIFF OMITTED] TR07SE16.005

Table of Contents

I. Background
    A. BSEE's Statutory and Regulatory Authority
    B. Incorporation by Reference of Industry Standards
    C. Production Safety Systems
II. Basis and Purpose of This Rule
    A. Developments in Offshore Production
    B. Proposed Revisions to Subpart H
    C. Summary of Documents Incorporated by Reference
    D. Summary of Significant Differences Between the Proposed and 
Final Rules
    1. Best Available and Safest Technology (BAST)--Sec.  250.107(c)
    2. Firefighting Systems--Sec.  250.859
    3. Operating Pressure Ranges--Sec. Sec.  250.851, 250.852, 
250.858, and 250.865
    4. Emergency Shutdown Systems--Sec.  250.855
    E. Deferred Compliance Dates
III. Final Rule Derivation Table
IV. Comments on the Proposed Rule and BSEE's Responses
    A. Overview
    B. Summary of General Comment Topics
    1. Requests for an Extension of the Public Comment Period;
    2. BSEE and USCG Jurisdiction
    3. Arctic Production Safety Systems
    C. Response to Comments and Section-by-Section Summary
    1. General Comments
    2. Economic Analysis Comments
    3. Section-by-Section Summary and Responses to Comments
V. Procedural Matters

I. Background

A. BSEE's Statutory and Regulatory Authority

    OCSLA, 43 U.S.C. 1331 et seq., was first enacted in 1953, and 
substantially amended in 1978, when Congress established a National 
policy of making the OCS ``available for expeditious and orderly 
development, subject to environmental safeguards, in a manner which is 
consistent with the maintenance of competition and other National 
needs.'' (43 U.S.C. 1332(3).) In addition, Congress emphasized the need 
to develop OCS mineral resources in a safe manner ``by well-trained 
personnel using technology, precautions, and techniques sufficient to 
prevent or minimize the likelihood of blowouts, loss of well control, 
fires, spillages, physical obstruction to other users of the waters or 
subsoil and seabed, or other occurrences which may cause damage to the 
environment or to property, or endanger life or health.'' (43 U.S.C. 
1332(6).) The Secretary of the Interior (Secretary) administers the 
OCSLA provisions relating to the leasing of the OCS and regulation of 
mineral exploration and development operations on those leases. The 
Secretary is authorized to prescribe ``such rules and regulations as 
may be necessary to carry out [OCSLA's] provisions . . . and may at any 
time prescribe and amend such rules and regulations as [s]he determines 
to be necessary and proper in order to provide for the prevention of 
waste and conservation of the natural resources of the [OCS] . . .'' 
and that ``shall, as of their effective date, apply to all operations 
conducted under a lease issued or maintained under the provisions of 
[OCSLA].'' (43 U.S.C. 1334(a).)
    The Secretary delegated most of the responsibilities under OCSLA to 
BSEE and the Bureau of Ocean Energy Management (BOEM), both of which 
are charged with administering and regulating aspects of the Nation's 
OCS oil and gas program. BSEE and BOEM work to promote safety, protect 
the

[[Page 61837]]

environment, and conserve offshore resources. BSEE adopts regulations 
and performs offshore regulatory oversight and enforcement. BSEE's 
regulatory oversight includes, among other things, evaluating drilling 
permits, and conducting inspections to ensure compliance with 
applicable laws, regulations, lease terms, and approved plans and 
permits.

B. Incorporation by Reference of Industry Standards

    BSEE frequently uses standards (e.g., codes, Specifications 
(Specs.), and Recommended Practices (RPs)) 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, and 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 Sec.  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 final 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 Web site 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 review its key 
industry standards, including a broad range of technical standards. All 
API standards that are safety-related and all API standards 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 Web site. Several of those standards are incorporated by 
reference in this final rule (as described in parts II.C and IV of this 
document). In addition to the free online availability of these 
standards for viewing on API's Web site, hardcopies and printable 
versions are available for purchase from API. The API Web site address 
is: https://www.api.org/publications-standards-and-statistics/publications/government-cited-safety-documents.\1\
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    \1\ To review these standards online, go to the API publications 
Web site 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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    For the convenience of members of the viewing public who may not 
wish to purchase 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.

C. Production Safety Systems

    BSEE's regulations require operators to design, install, use, 
maintain, and test production safety equipment to ensure safety and the 
protection of the human, marine, and coastal environments.\2\ Operators 
may not commence production until BSEE approves their production safety 
system application and BSEE conducts a preproduction inspection. These 
inspections are necessary to determine whether the operator's proposed 
production activities meet the OCSLA requirements and BSEE's 
regulations governing offshore production. The regulatory requirements 
include, but are not limited to, ensuring that the proposed production 
operations:
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    \2\ The relevant provisions of the existing regulations, and the 
provisions of this final rule, typically apply to ``you,'' defined 
by existing Sec.  250.105 as ``a lessee, the owner or holder of 
operating rights, a designated operator or agent of the lessees(s), 
a pipeline right-of-way holder, or a State lessee granted a right-
of-use and easement.'' For convenience, however, throughout this 
document we refer to the parties required to comply with the 
provisions of the existing regulations and this final rule as the 
``operator'' or ``operators,'' unless explicitly stated otherwise.
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     Conform to OCSLA, as amended, its applicable implementing 
regulations, lease provisions and stipulations, and other applicable 
laws;
     Are safe;
     Conform to sound conservation practices and protect the 
rights of the U.S. in the mineral resources of the OCS;
     Do not unreasonably interfere with other uses of the OCS; 
and
     Do not cause undue or serious harm or damage to the human, 
marine, or coastal environments. (See Sec. Sec.  250.101 and 250.106.)

BSEE will approve the operator's production safety system if it meets 
these criteria.

    Typically, well completions associated with offshore production 
platforms are characterized as either dry tree (surface) or subsea tree 
completions. The ``tree'' is the assembly of valves, gauges, and chokes 
mounted on a well casing head and used to control the production and 
flow of oil or gas. Dry tree completions are typical for OCS shallow 
water production platforms, with the tree in a ``dry'' state located on 
the deck of the production platform. The dry tree arrangement allows 
direct access to valves and gauges to monitor well conditions, such as 
pressure, temperature, and flow rate, as well as direct vertical well 
access. Dry tree completions are easily accessible. Because of their 
easy accessibility, even as oil and gas production moved into deeper 
water, dry trees were still used on new types of production platforms 
more suitable for deeper water, such as compliant towers, tension-leg 
platforms (TLPs), and spars. These platform types gradually extended 
the depth of usage for dry tree completions to over 4,600 feet of water 
depth.
    Production in the Gulf of Mexico (GOM) now occurs in depths of 
9,000 feet of water, however, with many of the wells producing from 
water depths greater than 4,000 feet utilizing ``wet'' or subsea trees. 
Subsea tree completions are done with the tree located on the seafloor. 
These subsea completions are generally tied back to floating production 
platforms, and from there the production moves to shore through 
pipelines. Due to the location on the seafloor, subsea trees or subsea 
completions do not allow for direct access to valves and gauges, but 
the pressure, temperature, and flow rate from the subsea location is 
monitored from the production platform and, in some cases, from onshore 
data centers.
    In conjunction with all production operations and completions, 
including both wet and dry trees, there are associated subsurface 
safety devices designed to prevent uncontrolled releases of reservoir 
fluid or gas.

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    Most of the current regulatory requirements for production safety 
systems are contained in subpart H of part 250 of BSEE's existing 
regulations (existing Sec. Sec.  250.800 through 250.808). Revision of 
those requirements is the primary focus of this rulemaking.

II. Basis and Purpose of This Rule

A. Developments in Offshore Production

    The existing regulations on production safety systems that this 
final rule is amending were first published on April 1, 1988. (See 53 
FR 10690). Since that time, various sections have been updated, and 
BSEE has issued several Notices to Lessees and Operators (NTLs) to 
clarify the regulations and to provide guidance to lessees and 
operators.\3\
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    \3\ This includes NTL-2006-G04, Fire Prevention and Control 
Systems (2006), and NTL-2009-G38, Using Alternate Compliance in 
Safety Systems for Subsea Production Operations (2009). All NTLs can 
be viewed at: https://www.bsee.gov/Regulations-and-Guidance/Notices-to-Lessees/index/.
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    As discussed in part I.C of this document, subsea trees and other 
technologies have evolved, and their use has become more prevalent 
offshore, over the last 28 years, especially as more and more 
production has shifted from shallow waters to deepwater environments. 
This includes significant developments in production-related areas as 
diverse as foam firefighting systems; electronic-based emergency 
shutdown (ESD) systems; subsea pumping, waterflooding, and gas lift; 
and new alloys and equipment for high temperature and high pressure 
wells. The subpart H regulations, however, have not kept pace with 
those developments.

B. Proposed Revisions to Subpart H

    On August 22, 2013, BSEE published a Notice of Proposed Rulemaking 
(the proposed rule) in the Federal Register entitled ``Oil and Gas and 
Sulphur Operations on the Outer Continental Shelf--Oil and Gas 
Production Safety Systems.'' (See 78 FR 52240.) The purpose of that 
proposed rule was to improve worker safety and protection of the marine 
and coastal environment by helping reduce the number of production-
related incidents resulting in oil spills, injuries and fatalities. The 
proposed rule was intended to keep pace with the changing technologies 
that enable the industry to develop resources in deeper waters (which 
often involves placing safety equipment on the seabed rather than on a 
surface platform) by addressing issues such as production safety 
systems, subsurface safety devices, safety device testing, and 
production processing systems and areas, and by incorporating best 
practices currently being deployed by industry leaders.
    The comment period for the proposed rule was originally set to 
close on October 21, 2013. However, in response to several requests, 
BSEE published a notice on September 27, 2013 (78 FR 59632), extending 
the comment period until December 5, 2013.
    As discussed in part IV.C of this document, BSEE received 57 
separate written comments on the proposed rule from a variety of 
interested stakeholders (e.g., industry, environmental groups, and 
other non-governmental organizations).
    After the close of the comment period, BSEE subject matter experts 
and decision-makers carefully considered all of the relevant comments 
in developing this final rule. In part IV of this document, BSEE 
responds to those comments and discusses how several provisions of the 
proposed rule were revised in this final rule to address concerns or 
information raised by commenters.
    As a result of BSEE's consideration of all the relevant comments 
and other relevant information, BSEE has developed this final rule, 
which is intended to improve worker safety and protection of marine and 
coastal ecosystems by helping to reduce the number of production-
related incidents resulting in oil spills, injuries, and fatalities.
    Among other significant changes to the existing regulations, this 
final rule establishes new requirements for the design, testing, 
maintenance, and repair of SPPE, using a lifecycle approach. The 
lifecycle approach involves careful consideration and vigilance 
throughout SPPE design, manufacture, operational use, maintenance, and 
decommissioning of the equipment. It is a tool for continual 
improvement throughout the life of the equipment. The lifecycle 
approach for SPPE is not a new concept, and its elements are discussed 
in several industry documents already incorporated by reference in the 
existing regulations (see Sec.  250.198), such as API Spec. 6A, API 
Spec. 14A, and API RP 14B. This final rule codifies aspects of the 
lifecycle approach into the regulations and brings more attention to 
its importance.
    BSEE's focus in the development of this rule has been, and will 
continue to be, improving worker safety and protection of the 
environment by helping to reduce the number of production-related 
incidents resulting in oil spills, injuries and fatalities. For 
example, there have been multiple incidents, including fatalities, 
injuries, and facility damage related to the mechanical integrity of 
the fire tube for tube-type heaters. BSEE is aware that this type of 
equipment has not been regularly maintained by industry. In the final 
rule, BSEE is requiring that this type of equipment be removed and 
inspected, and then repaired or replaced as needed, every 5 years. This 
requirement will improve equipment reliability to help limit incidents 
associated with the mechanical integrity of the fire tubes.
    Three existing NTLs are directly related to issues addressed in 
this rulemaking:
     NTL No. 2011-N11, Subsea Pumping for Production 
Operations;
     NTL No. 2009-G36, Using Alternate Compliance in Safety 
Systems for Subsea Production Operations; and
     NTL No. 2006-G04, Fire Prevention and Control Systems.
    Most of the elements from these NTLs are codified in this final 
rule. After the final rule is effective, BSEE intends to rescind these 
NTLs and remove them from the BSEE.gov Web site. BSEE may issue new 
NTLs to address any elements of those NTLs that are consistent with but 
not expressly incorporated in the final rule.

C. Summary of Documents Incorporated by Reference

    BSEE is incorporating by reference one new standard in the final 
rule, API 570, Piping Inspection Code: In-service Inspection, Rating, 
Repair, and Alteration of Piping Systems, Third Edition, November 2009. 
As discussed in the standard, API 570 covers inspection, rating, 
repair, and alteration procedures for metallic and fiberglass-
reinforced plastic piping systems and their associated pressure 
relieving devices that have been placed in service. The intent of this 
code is to specify the in-service inspection and condition-monitoring 
program that is needed to determine the integrity of piping systems. 
That program should provide reasonably accurate and timely assessments 
to determine if any changes in the condition of piping could compromise 
continued safe operation. It is also the intent of this code that 
owners/users respond to any inspection results that require corrective 
actions to assure the continued integrity of piping consistent with 
appropriate risk analysis. Items discussed in this standard include 
inspection plans, condition monitoring methods, pressure testing of 
piping systems, and inspection recommendations for repair or 
replacement.
    The other standards referred to in this final rule are already 
incorporated by

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reference in other sections of BSEE's existing regulations. BSEE is 
incorporating more recently reaffirmed versions of those standards in 
this rule, as follows:
     BSEE is incorporating a more recently reaffirmed version 
of American National Standards Institute (ANSI)/API Spec. 6AV1, 
Specification for Verification Test of Wellhead Surface Safety Valves 
and Underwater Safety Valves for Offshore Service, First Edition, 
February 1996; Reaffirmed April 2008. This standard includes the 
minimum acceptable standards for verification testing of surface safety 
valves (SSVs)/underwater safety valves (USVs) for two performance 
requirement levels.
     BSEE is also incorporating a more recently reaffirmed 
version of ANSI/API Spec. 14A, Specification for Subsurface Safety 
Valve Equipment, Eleventh Edition, October 2005, Reaffirmed June 2012. 
This standard provides the minimum acceptable requirements for 
subsurface safety valves (SSSVs), including all components that 
establish tolerances and/or clearances that may affect performance or 
interchangeability of the SSSVs. It includes repair operations and the 
interface connections to the flow control or other equipment, but does 
not cover the connections to the well conduit.
     BSEE is incorporating a recently reaffirmed version of API 
RP 14E, Recommended Practice for Design and Installation of Offshore 
Production Platform Piping Systems, Fifth Edition, October 1991; 
Reaffirmed January 2013. This standard provides minimum requirements 
and guidelines for the design and installation of new piping systems on 
production platforms located offshore. This document covers piping 
systems with a maximum design pressure of 10,000 pounds per square inch 
gauge (psig) and a temperature range of -20 degrees to 650 degrees 
Fahrenheit.
     BSEE is incorporating a more recently reaffirmed version 
of 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, Fifth Edition, July 2008, Reaffirmed April 2013. 
This RP sets minimum requirements for the design, installation, and 
maintenance of electrical systems on fixed and floating petroleum 
facilities located offshore. This RP is not applicable to mobile 
offshore drilling units (MODUs) without production facilities. This 
document is intended to bring together in one place a brief description 
of basic desirable electrical practices for offshore electrical 
systems. The RP recognizes that special electrical considerations exist 
for offshore petroleum facilities, including inherent electrical shock, 
space limitations, corrosive marine environment, and motion and 
buoyancy concerns.
     BSEE is incorporating a recently reaffirmed version of API 
RP 14J, Recommended Practice for Design and Hazards Analysis for 
Offshore Production Facilities, Second Edition, May 2001; Reaffirmed 
January 2013. This standard assembles into one document useful 
procedures for planning, designing, and arranging offshore production 
facilities, and performing a hazards analysis on open-type offshore 
production facilities.
     BSEE is incorporating a more recently reaffirmed version 
of ANSI/API Spec. Q1, Specification for Quality Programs for the 
Petroleum, Petrochemical and Natural Gas Industry, Eighth Edition, 
December 2007, Addendum 1, June 2010. This standard states that the 
adoption of a quality management system should be a strategic decision 
of any organization. The design and implementation of an organization's 
quality management system is influenced by its organizational 
environment, its varying needs, its particular objectives, the product 
it provides, and its size and organizational structure.
    In addition, this rule incorporates API RP 500, Recommended 
Practice for Classification of Locations for Electrical Installations 
at Petroleum Facilities Classified as Class I, Division 1 and Division 
2, Second Edition, November 1997, Reaffirmed November 2002. The purpose 
of this RP is to provide guidelines for classifying locations at 
petroleum facilities as Class I, Division 1 and Class I, Division 2 for 
the selection and installation of electrical equipment.

D. Summary of Significant Differences Between the Proposed and Final 
Rules

    After consideration of all relevant comments, BSEE made a number of 
revisions to the proposed rule language in the final rule. We are 
highlighting several of these changes here because they are 
significant, and because multiple comments addressed these topics. A 
discussion of the relevant comments, including BSEE's specific 
responses, is found in part IV of this document. All of the revisions 
to the proposed rule language made after consideration of relevant 
comments are explained in more detail in that part. The significant 
revisions made in response to comments include:
1. Best Available and Safest Technology (BAST)--Sec.  250.107(c)
    BSEE proposed to revise the BAST provisions in existing Sec.  
250.107 in order to align the regulatory language more closely with the 
statutory BAST language in OCSLA, to clarify BSEE's expectations, and 
to make it easier for operators to understand when they must use BAST. 
BSEE proposed to delete existing paragraph (d) (regarding authority of 
the Director to impose additional BAST measures) and to revise 
paragraph (c) to include more of the statutory language and to provide 
an exception from use of BAST when an operator demonstrates that the 
incremental benefits of using BAST are insufficient to justify its 
incremental costs.
    BSEE received numerous comments on this proposed change. Among 
other issues, some commenters stated that the proposed language failed 
to confirm BSEE's prior position regarding compliance with BSEE's 
regulations being considered the use of BAST. As explained in more 
detail in part IV.C of this document, after consideration of the 
comments and further deliberation, BSEE has revised and reorganized 
final Sec.  250.107(c) to address many of these issues. The revised 
language clarifies BSEE's position that compliance with existing 
regulations is presumed to be use of BAST until (and unless) the 
Director makes a specific BAST determination that other technology is 
required. The final rule also provides that the Director may waive the 
requirement to use BAST on a category of existing operations if the 
Director determines that use of BAST by that category of existing 
operations would not be practicable. In addition, the revised language 
provides a clear path for an operator of an existing facility to 
request a waiver from use of BAST if the operator demonstrates, and the 
Director determines, that use of BAST would not be practicable. These 
revisions are consistent with the statutory language and intent of 
OCSLA, and will further clarify for operators when use of BAST is or is 
not required and when that requirement may be waived.
2. Firefighting Systems--Sec.  250.859
    BSEE proposed to revise the firewater systems requirements for both 
open and totally enclosed platforms. Among other things, BSEE proposed 
requiring that the firefighting systems conform to API RP 14G, 
Recommended Practice for Fire Prevention and Control on Fixed Open-type 
Offshore Production Platforms. This proposed requirement was in 
addition to existing Sec.  250.803(b)(8),

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which only requires firefighting systems to conform to section 5.2 in 
API RP 14G. Many commenters expressed concerns that incorporating the 
entire RP would create conflicts with the regulations and subsequent 
inspection policies because API RP 14G does not include a step-by-step 
method of designing and installing a complete firefighting system. 
Furthermore, the commenters noted that API RP 14G discusses multiple 
types of firefighting systems (e.g., fire water, foam, dry chemical, 
and gaseous extinguishing agent). The commenters suggested various 
alternatives for compliance with API RP 14G, including requiring 
compliance only with applicable firewater system sections of API RP 
14G.
    BSEE understands that there are many different types of 
firefighting systems discussed in API RP 14G. Accordingly, in this 
final rule, BSEE has revised proposed Sec.  250.859(a) to require 
compliance with the firewater system sections of API RP 14G. This 
change will clarify BSEE's expectations for compliance with this 
industry standard. This change will also enhance the overall firewater 
system operability by requiring compliance with provisions in API RP 
14G (e.g., inspection, testing, and maintenance) in addition to section 
5.2, as required by the former regulations.
    BSEE also made other changes to the proposed Sec.  250.859. 
Specifically, as suggested by several commenters, we clarified the 
firefighting requirements to minimize confusion regarding U.S. Coast 
Guard (USCG) jurisdiction and to separate the firewater requirements 
for fixed facilities and floating facilities. In particular, we revised 
Sec.  250.859(a) in the final rule to include requirements for 
firefighting systems on ``fixed facilities,'' and added final paragraph 
(b) to clarify the requirements for firefighting systems on floating 
facilities. Final Sec.  250.859(b) also clarifies that the firewater 
system must protect all areas where production-handling equipment is 
located, that a fixed water spray system must be installed in enclosed 
well-bay areas where hydrocarbon vapors may accumulate, and that the 
firewater system must conform to the USCG requirements for firefighting 
systems on floating facilities.
3. Operating Pressure Ranges--Sec. Sec.  250.851, 250.852, 250.858, and 
250.865
    BSEE received a number of comments on proposed Sec. Sec.  
250.851(b), 250.852(a), 250.858(b), and 250.865(b), regarding the 
operating pressure ranges for certain types of equipment, including the 
pressure safety high and low set points. As discussed in the proposed 
rule, pressure recording devices must be used to establish the new 
operating pressure ranges for specific equipment (i.e., pressure 
vessels, flowlines, gas compressor discharge sensors, and surface pump 
discharge sensors) at any time when the normalized system pressure 
changes by a certain pressure or percentage. An operating range is used 
to establish the safety device set points that would trigger a 
component shut-in. Multiple commenters expressed concerns about the 
proposed change in operating pressures that would trigger a production 
safety system shut-in. Commenters also discussed the need to help 
prevent nuisance shut-ins (i.e., shut-ins that occur under normal 
operating conditions when a safety device's operating pressures are set 
too narrowly).
    BSEE is requiring the operating pressure ranges because we are 
aware that not all operators monitor how the pressure regimes are 
changing. Nonetheless, to help prevent nuisance shut-ins, the final 
rule allows operators to use a more conservative approach by resetting 
the operating pressure at an operating range that is lower than the 
specified change in pressure. To clarify how a new operating pressure 
range can be established, BSEE added language to the appropriate 
locations in final Sec. Sec.  250.851, 250.852, 250.858, and 250.865 
stating that once system pressure has stabilized, pressure recording 
devices must be used to establish new operating pressure ranges. The 
revised language also clarifies that the pressure recording devices 
must document the pressure range over time intervals that are no less 
than 4 hours and no more than 30 days long. Establishing new operating 
ranges based on these parameters will help prevent nuisance shut-ins, 
by basing the shut-in set points on an identified, stabilized baseline. 
BSEE also added a minimum time provision to each of these final 
provisions to ensure that the system pressure is stable before setting 
the operating ranges. The time interval limits were set, in part, 
because pressure spikes and/or surges may not be discernable in a range 
chart if the run time is too long.
4. Emergency Shutdown System--Sec.  250.855
    In proposed Sec.  250.855, BSEE retained the ESD requirements from 
Sec.  250.803(b)(4) in the existing regulations, and clarified that the 
breakable loop in the ESD system is not required to be physically 
located on the facility's boat landing; however, in all instances, the 
breakable loop must be accessible from a vessel adjacent to or attached 
to the facility. A commenter expressed concern that the proposed rule 
referenced only pneumatic-type valves, while current technology 
incorporates electronic switching devices.
    After considering the issues raised in the comment and reviewing 
current technology, BSEE has revised proposed Sec.  250.855(a) in the 
final rule to provide that electric ESD stations should be wired as 
``de-energize to trip'' or as supervised circuits. Since BSEE is now 
allowing electric ESD switches, BSEE wants to ensure that ESD equipment 
is fully functional, because the key role of the ESD system is to shut-
in the facility in an emergency. Therefore, BSEE also added new 
language clarifying that all ESD components should be of high quality 
and corrosion resistant, and that ESD stations should be uniquely 
identified. These revisions are necessary to help ensure that these 
newer types of ESD stations function properly and to assist personnel 
in recognizing the ESD location for activation in an emergency.
    In addition to the differences between the proposed and final rules 
discussed here and in part IV, BSEE also made minor changes to the 
proposed rule language in response to comments suggesting that BSEE 
eliminate redundancy, clarify potentially confusing language, 
streamline the regulatory text, or align the language in the rule more 
closely with accepted industry terminology. BSEE also made other 
revisions to this final rule to correct grammatical or clerical errors, 
eliminate ambiguity, and further clarify the intent of the proposed 
language.

E. Deferred Compliance Dates

    The final rule is effective on November 7, 2016. However, BSEE has 
deferred the compliance dates for certain provisions of the final rule 
until the times specified in those provisions and as discussed in more 
detail in part IV of this document.
    Compliance with Sec.  250.801(a)(2) for requirements related to 
boarding shutdown valves (BSDVs) and their actuators as SPPE is 
deferred until September 7, 2017.
    Compliance with Sec.  250.851(a)(2), regarding District Manager 
approval of existing uncoded pressure and fired vessels that are not 
code stamped according to ANSI/American Society of Mechanical Engineers 
(ASME) Boiler and Pressure Vessel Code, is deferred until March 1, 
2018.
    Compliance with the elements of Sec.  250.859(a)(2) requiring all 
new firewater pump drivers to be equipped

[[Page 61841]]

with automatic starting capabilities upon activation of the ESD, 
fusible loop, or other fire detection system is deferred until 
September 7, 2017.

III. Final Rule Derivation Table

    The final rule restructures the provisions of existing subpart H. 
The new regulations are divided into shorter, easier-to-read sections. 
These sections are more logically organized, as each section focuses on 
a single topic instead of multiple topics, as found in each section of 
the existing regulations. To assist in understanding the revised 
subpart H regulations, the following table shows how sections of the 
final rule correspond to the provisions in former subpart H:

[[Page 61842]]

[GRAPHIC] [TIFF OMITTED] TR07SE16.006


[[Page 61843]]


[GRAPHIC] [TIFF OMITTED] TR07SE16.007

IV. Comments on the Proposed Rule and BSEE's Responses

A. Overview

    In response to the proposed rule, BSEE received 57 separate sets of 
comments from individual entities (companies, industry organizations, 
or private citizens). (One comment included 1,527 individual letters, 
as an attachment, although the content of all of these letters was 
substantially the same.) Some entities submitted comments multiple 
times. All comments are posted at the Federal eRulemaking Portal: 
https://www.regulations.gov. To access the comments, enter ``BSEE-2012-
0005'' in the search box. BSEE reviewed all comments submitted. For the 
complete list of public comments with summaries

[[Page 61844]]

of Responses, refer to the comment-response file located in the 
rulemaking docket.
    In addition to the comments on all provisions of the proposed rule, 
BSEE solicited comments on certain issues related to those proposed 
provisions, including:
     Organization of the rule based on use of subsea trees and 
dry trees;
     Lifecycle approach to other types of critical equipment, 
such as blowout preventers (BOPs);
     Failure Reporting and Information Dissemination; and
     Third-party Certification Organizations.
    BSEE also solicited comments and requested information on other 
topics that were indirectly related to, but outside the specific scope 
of, this rulemaking. These topics included:
     Opportunities to limit emissions of natural gas from OCS 
production equipment; and
     Opportunities to limit flaring of natural gas.
    BSEE requested comments on natural gas emissions and flaring to 
inform future policies and potential rulemakings. Since the information 
provided in response to these topics is not directly related to, and 
was not considered in developing, this final rule, we have not 
discussed those comments or information in this document.

B. Summary of General Comment Topics

    In addition to comments on specific provisions of the proposed 
rule, various commenters raised more general issues, including:
     Extension of the public comment period;
     BSEE and USCG jurisdiction; and
     Arctic production safety systems.
    The following is a summary of, and BSEE's responses to, comments on 
these topics. BSEE's responses to more specific comments on proposed 
provisions are addressed in the ``Section-by-Section'' discussion in 
part IV.C of this document.
1. Requests for an Extension of the Public Comment Period
    BSEE received a number of comments requesting an extension of the 
public comment period. In response to these requests, BSEE extended the 
public comment period by 45 days. Some commenters also requested that 
BSEE hold a public workshop on the proposed rule.
    BSEE determined that the extension of the public comment period was 
sufficient for the public to review, understand, and comment on the 
proposed rule and thus, that a workshop was not necessary. In addition, 
BSEE determined that a public workshop would result in significant 
delays in developing and publishing a final rule, which would also 
delay the improvements in safety and environmental protection intended 
by the final rule with no commensurate benefits to justify that delay.
2. BSEE and USCG Jurisdiction
    BSEE received comments on a number of provisions in the proposed 
rule expressing concerns that BSEE was reaching beyond its authority 
and trying to regulate activities that are under USCG jurisdiction. 
Both BSEE and the USCG have jurisdiction over different aspects and 
components of oil and gas production safety systems. These regulations 
apply only to operations that are under BSEE authority. OCSLA directs 
that the Secretary prescribe regulations necessary to provide that OCS 
operations are ``conducted in a safe manner by well-trained personnel 
using technology, precautions, and techniques sufficient to prevent or 
minimize the likelihood of blowouts, loss of well control, fires, 
spillages,. . . or other occurrences which may cause damage to the 
environment or to property, or endanger life or health.'' (43 U.S.C. 
1332(6).) Those regulations apply to all operations conducted under an 
OCS lease. (43 U.S.C. 1334(a).)
    To promote interagency consistency in the regulation of OCS 
activities, and to describe the agencies' respective and cooperative 
roles, BSEE and USCG have signed formal memoranda of understanding 
(MOUs) and memoranda of agreement (MOAs). Those memoranda recognize 
that, in many respects, BSEE and USCG share responsibility and 
authority over various aspects of safety and environmental protection 
related to oil and gas operations on the OCS. The memoranda reflect 
that BSEE has, and exercises, authority to regulate safety and 
environmental functions related to OCS facilities, including: 
developing regulations governing OCS operations, permitting, conducting 
inspections and investigations, enforcing regulatory requirements, and 
overseeing oil spill response planning and preparedness. Similarly, the 
memoranda reflect USCG's authority to regulate the safety of life, 
property, and navigation and protection of the environment on OCS units 
and vessels engaged in OCS activities, as well as its authority to 
regulate workplace safety and health, workplace activities, conditions 
and equipment on the OCS, and oil spill preparedness and response.
    The various memoranda are intended to minimize duplication of 
effort and promote consistency of regulations and policies where shared 
responsibilities exist (including, for example, issues related to both 
fixed and floating facilities) but do not limit either agency's 
statutory authorities and responsibilities. The USCG-BSEE memoranda are 
available on BSEE's Web site at: https://www.bsee.gov/newsroom/partnerships/interagency.
    Numerous comments were submitted regarding BSEE and USCG 
jurisdiction in connection with multiple sections within the rule. Some 
comments cited jurisdictional concerns as a general reason why a 
section should not have been included in the proposed rule. Other 
commenters expressly noted concern that BSEE's crossing of 
jurisdictional lines with the USCG could lead to confusion or result in 
regulatory burdens on the operators. These commenters noted that the 
USCG has its own rules that govern all or portions of pressurized 
vessels and fixed and floating facilities. All of the comments that 
discussed USCG's rules asserted that BSEE lacked some degree of 
authority concerning the regulation of production safety systems under 
OCSLA.
    Commenters also raised issues concerning BSEE's authority with 
regard to distinctions between floating and fixed platforms. Commenters 
described BSEE's authority as limited to fixed platforms and, due to 
that limitation, they asserted that BSEE does not have the authority to 
regulate issues regarding floating facilities. These issues were often 
raised with regard to specific provisions, such as Sec. Sec.  250.861, 
Foam firefighting systems, and 250.862, Fire and gas-detection systems.
    Some comments raised jurisdictional issues regarding sections of 
the proposed rule dealing with certain technical or safety matters that 
the commenters asserted are within USCG's area of expertise (e.g., fire 
and smoke protection, detection and extinguishing systems, pressure 
vessels, and electrical systems).
    BSEE does not agree with the comments suggesting that the 
provisions in the proposed rule are outside of BSEE's jurisdiction. 
This rulemaking applies to production operations that BSEE has 
historically regulated under longstanding regulations consistent with 
the authority granted by OCSLA to the Secretary and subsequently 
delegated to BSEE. This final rule is consistent with the USCG-BSEE 
MOAs and MOUs. Nothing in the USCG-BSEE MOAs or

[[Page 61845]]

MOUs limits BSEE's statutory authority as consistently exercised 
through BSEE's regulations at part 250.
3. Arctic Production Safety Systems.
    A number of comments requested that BSEE add specific production 
safety requirements for the Arctic OCS environment to the final rule.
    BSEE does not agree that new Arctic-specific provisions, which were 
not included in the proposed rule, should be added to this final rule. 
Prior to approval by BSEE, all proposed oil and gas production 
operations on the OCS, including in the Arctic, are required to have 
production safety equipment that is designed, installed, operated, and 
tested specifically for the surrounding location and environmental 
conditions of operation. In particular, the existing BSEE regulations 
(retained in relevant part by this final rule) require that production 
safety system equipment and procedures for operations conducted in 
subfreezing climates take into account floating ice, icing, and other 
extreme environmental conditions that may occur in the area. (See Sec.  
250.800.) In addition, all production system descriptions included in 
Development and Production Plans (DPPs), submitted for development and 
production activities on a lease or unit in any OCS area other than the 
Western GOM, go through a formal review and comment period by the 
public, which provides an opportunity for any interested stakeholder to 
suggest additional safety measures for production facilities in the 
Arctic.\4\ Moreover, because of the unique Arctic environment, BSEE 
conducts extensive research on enhanced technologies for oil and gas 
development on the Arctic OCS (see www.bsee.gov/Technology-and-Research/Technology-Assessment-Programs/Categories/Arctic-Research). 
These research projects and the knowledge gained from them will inform 
future decisions, rulemaking, and guidance for Arctic OCS operations.
---------------------------------------------------------------------------

    \4\ See 30 CFR 550.267(b). DPPs are reviewed and approved by 
BSEE's sister agency, BOEM, which also considers the public comments 
on submitted DPPs.
---------------------------------------------------------------------------

C. Response to Comments and Section-by-Section Summary

    This discussion summarizes: all of the regulatory sections in the 
final rule; specific comments submitted, if any, on each section in the 
proposed rule; and BSEE's responses to those comments, including 
whether BSEE made any revisions to the proposed regulatory text in this 
final rule in response to the comments. The comments and BSEE's 
responses are organized as follows: General Comments; Economic Analysis 
Comments; and Section-by-Section Summary and Responses to Comments.
1. General Comments
    BSEE received public comments on the following general issues 
related to the proposed rule that were not specific to any proposed 
requirement.
Third-Party Certifications
    Comment--Commenters asserted that, by including so many third-party 
certifications of equipment and processes in the proposed rule, BSEE is 
implying that other proposed requirements that do not call for 
certifications are somehow less important.
    Response--All of the provisions in this final rule are important. 
The certifications required by this rule are just one tool that BSEE 
uses to help ensure that operators meet the level of safety and 
environmental protection mandated under OCSLA. Other provisions of this 
rule also help meet that mandate through requirements placed directly 
on the operators.
Employee Qualifications
    Comment--Commenters asserted that the rule does not ensure operator 
qualification requirements for staff responsible for operating the 
offshore production facility. They suggested that each company 
permitted to conduct offshore production facility operations should 
have a written operator qualification program. They recommended that 
programs should include, at a minimum, an evaluative procedure 
(including reevaluation as appropriate), explicit reasons why 
individuals no longer would be qualified, and record-keeping 
requirements.
    Response--BSEE does not agree that any such requirements should be 
added to this final rule. Operator personnel qualifications are already 
addressed in the Safety and Environmental Management System (SEMS) 
regulations in part 250, subpart S, specifically Sec.  250.1915, What 
training criteria must be in my SEMS program?
Conflicts With Other Regulations
    Comment--A commenter asserted that BSEE needs to ensure that the 
proposed subpart H changes align with the requirements of existing 
regulations in subparts J, S, I, and O, as well as with the regulatory 
requirements of other agencies (i.e., USCG). The commenter suggested 
that many of the conflicts with other subparts in proposed subpart H 
could be resolved through regulatory changes in the other subparts. The 
commenter provided several examples to illustrate the concern--e.g., 
that the subpart J regulations include the BSDV, although there are 
requirements for BSDVs in proposed subpart H that either supplement or 
conflict with the existing requirements in subpart J. The commenter 
also stated that other parts of the proposed rule referred to issues 
that operators would expect to be addressed under a different subpart 
(e.g., proposed Sec.  250.800(c)(3) requirements for stationkeeping 
would be more appropriate in subpart I).
    Response--BSEE does not agree with the suggestion that this final 
rule conflicts with or contradicts any other provision in BSEE's 
regulations. There may be overlapping requirements in the various 
subparts, however, BSEE does not agree that there are conflicts. If 
there is a need for additional clarity, BSEE will issue guidance in the 
future. For example, the suggestion that the BSDV requirements in 
proposed subpart H conflict with BSDV requirements in existing subpart 
J is incorrect. Subpart H applies to any piping downstream of the BSDV, 
while subpart J's requirements apply to piping upstream of the BSDV. 
Similarly, the stationkeeping design requirements for floating 
production facilities in final Sec.  250.800(c)(3) refer to API RP 2SK 
and API RP 2SM, which are also incorporated by reference in the design 
requirements for platforms under Sec.  250.901 of subpart I. While the 
commenter may consider this duplicative, including the same 
requirements in subpart H and subpart I ensures that the facilities are 
designed with the production systems in mind and helps prevent 
conflicts. While BSEE is not aware of any inconsistencies, BSEE will 
monitor implementation of this final rule to assess whether any 
confusion arises from any overlap between subpart H provisions and 
other BSEE regulations. BSEE will consider whether to address any such 
issues, if they arise, in possible future rulemakings or guidance.
    Finally, as previously discussed, this final rule is aligned with 
the responsibilities and regulations of the USCG.
Impacts on Existing Equipment
    Comment--Commenters asserted that the proposed regulations were not 
clear with respect to the impact of the requirements on existing 
equipment (such as non-certified SPPE, BSDVs and single bore production 
risers) that is fit for purpose and performing satisfactorily within 
the established operating window and design conditions.

[[Page 61846]]

    Response--BSEE does not agree that the proposed rule was unclear as 
to any potential impacts on existing equipment. BSEE considered the 
impact on existing equipment designs when specifying the effective 
dates for new provisions and determined whether and when it is 
appropriate for new requirements to apply to existing equipment. For 
example, most existing SPPE is already certified under the existing 
regulations; this final rule adds a requirement for certification of 
BSDVs and their actuators, beginning 1 year after publication of the 
final rule. Also, under the final rule, operators may continue to use 
existing SPPE, such as BSDVs. However, if a BSDV fails or does not meet 
the applicable requirements (e.g., final Sec. Sec.  250.836 and 
250.880(c)(4)), then the operator must replace it with a BSDV that 
meets all of the requirements, including final Sec. Sec.  250.801 and 
250.802.
    Similarly, under final Sec.  250.800(c)(2), operators may continue 
to use single bore production risers that are already installed on 
floating production systems, although they cannot install new single 
bore production risers on floating productions systems after the 
effective date of this final rule (as explained further in part IV.C). 
However, for already-installed single bore production risers, 
additional precautions are necessary for wear protection, wear 
measurement, fatigue analysis, and pressure testing to perform any well 
operations with the tree removed. This is consistent with established 
BSEE policy and approvals for well operations using single bore 
production risers.
Pew Arctic Standards Report
    Comment--A commenter asserted that the Pew Charitable Trusts' 
September 2013 Arctic Standards Report identified a number of 
improvements that could be made in BSEE's regulations. The commenter 
requested that BSEE review and incorporate specific sections of this 
report related to the subpart H rulemaking.\5\
---------------------------------------------------------------------------

    \5\ Examples of the specific topics in the Pew Arctic report 
referenced by the commenter included: Tank Performance Standards; 
Critical Operations Curtailment; and Equipment Design and Operating 
Performance Standards.
---------------------------------------------------------------------------

    Response--BSEE reviewed the information provided in the Pew Arctic 
report, which only addresses Arctic operations. This rulemaking, 
however, applies to production operations in all OCS regions; the 
requirements are not specific to one area of the OCS. As previously 
mentioned, the existing BSEE regulations already require that 
production safety system equipment and procedures for operations 
located in subfreezing climates take into account floating ice, icing, 
and other extreme environmental conditions that may occur in the area. 
This final rule does not change that requirement. The sections of the 
report the commenter cited are outside the scope of this rulemaking and 
address matters not proposed for public notice and comment through the 
proposed rule.
2. Economic Analysis Comments
    BSEE received public comments on the following issues related to 
the initial economic analysis for the proposed rule and the economic 
analysis summary in the proposed rule.
Facility Modifications
    Comment--A commenter asserted that the initial economic analysis 
did not reflect the extensive facility modifications that the proposed 
rule would trigger. The commenter asserted that the agency failed to 
consider the economic impact of codifying numerous NTLs and industry 
practices. One commenter specifically questioned the estimated impact 
on existing fire-fighting systems designed in accordance with the 
existing regulations and previously approved by BSEE.
    Response--BSEE disagrees with the suggestion that we have 
underestimated the potential cost impacts of this rule. Many of the 
provisions in the proposed rule were based on existing policy and 
guidance contained in permit conditions and NTLs. NTLs provide guidance 
to operators on compliance with existing regulations. BSEE included any 
costs associated with existing regulatory policy and guidance and 
industry practices in the baseline of the economic analysis. As 
specified by Executive Order (E.O.) 12866 and Office of Management and 
Budget (OMB) Circular A-4, ``Regulatory Analysis'' (2003), which 
provides guidance to Federal agencies on the preparation of economic 
analyses, BSEE estimates the costs of a rule resulting from 
modifications or new provisions in the rule that cause changes from the 
baseline. Pursuant to OMB Circular A-4, the baseline represents the 
agency's best assessment of what the world would be like without the 
new rule. The baseline includes all practices that are already 
incorporated into industry or regulatory standards, and that would 
continue to exist even if the new rule were not adopted. For economic 
analysis purposes, we assume that operators are already following the 
published NTLs in order to comply with existing regulations; thus, 
there is no change in industry practices, and no additional costs, when 
such practices are codified in the regulations.
    In particular, the requirements for the firefighting systems in the 
final rule are consistent with the requirements in the existing BSEE 
regulations. The costs for the chemical firefighting systems and the 
inspection and testing of foam in the foam firefighting systems are 
addressed in the final economic analysis for this rule.
Impacts on Small Businesses
    Comment--A commenter asserted that the bureau failed to accurately 
determine the impacts on small businesses operating offshore and on 
those businesses supporting the offshore industry through services and 
equipment.
    Response--In the Regulatory Flexibility Act (RFA) determination for 
this final rule (see part V of this document), BSEE estimated that 
there are 99 companies with active operations on the OCS and 
approximately 54 companies operating on the OCS that are considered 
small businesses. However, analyses conducted under the RFA are only 
required to consider the direct impacts of a new regulation. The 
indirect impacts of a regulation, or the effects of the regulation on 
industries that support the directly affected industry, are not 
considered in an RFA determination or analysis.
    As explained in the RFA discussion in part V, BSEE estimated that 
the total annual cost of the rule per small entity would be about 
$18,000, which BSEE determined is not a significant economic impact. 
More details about these estimates are in the RFA discussion in part V 
of this document.
Impacts on Existing Operations
    Comment--A commenter asserted that, while the proposed rule is 
intended primarily to codify standard industry practice and clarify 
existing regulations, BSEE had not acknowledged the impact of the 
proposed rule on existing operations and that the initial economic 
analysis grossly underestimated the actual cost.
    Response--BSEE disagrees with those comments. The initial economic 
analysis adequately addressed the significant new costs that BSEE 
anticipated at the time of the proposed rule. However, as explained in 
more detail in part V of this document, the final economic analysis 
includes several adjustments to the estimated costs of the final rule, 
based on comments on the proposed rule and on changes to existing 
practices that BSEE now expects will occur as a result of the final

[[Page 61847]]

rule. For example, the requirements for the firefighting systems in the 
final rule are consistent with the requirements in the existing BSEE 
regulations. The costs for the chemical firefighting systems and the 
inspection and testing of foam in the foam firefighting systems are 
addressed in the final economic analysis for this rule.
Uncertainty of Regulatory Benefits
    Comment--A commenter asserted that the proposed rule did not 
discuss why the new requirements are necessary and asked what incidents 
may be avoided by the proposed requirements. The commenter noted that 
although the bureau did conduct a break-even analysis for the proposed 
rule, since the regulatory benefits are highly uncertain, neither the 
proposed rule notice nor the initial economic analysis discussed the 
regulatory benefits of the proposed rule.
    Response--BSEE does not agree that the proposed rule did not 
explain why the proposed requirements were necessary. The preamble to 
the proposed rule adequately described the general and specific 
purposes of the proposal. (See 78 FR 52241) In addition, as discussed 
in part V of this document, BSEE follows E.O. 12866 and 13563 and OMB 
Circular A-4 in performing its economic analyses. The costs and 
benefits related to this final rule are presented in the final economic 
analysis, available in the public docket and summarized in part V. The 
final economic analysis includes a break-even analysis, describes the 
types of incidents that could be avoided, and estimates the cost 
savings that would result by implementing the final rule. The full 
economic analysis describes in detail BSEE's data, methodology, and 
results for the benefits analysis. The potential benefits resulting 
from the final rule include the potential reduction in oil spills and 
injuries to workers, which are difficult to quantify and are highly 
dependent on the actual reduction in the probabilities of the incidents 
occurring. Due to this uncertainty, BSEE conducted a break-even 
analysis consistent with the guidance provided in OMB Circular A-4.
Reports of Design Changes or Modifications
    Comment--One commenter questioned the initial economic analysis 
conclusion that there would only be a limited number of reports of 
design changes or modifications. The estimated labor for BSEE to work 
with this information is $68. Given this effort by BSEE to analyze the 
information, the commenter questioned how this new requirement will be 
of any value to BSEE.
    Response--In BSEE's experience, design changes do not happen 
frequently; therefore, we do not anticipate very many reports based on 
this requirement (i.e., BSEE estimated 1 change per year). Since the 
reporting of design changes to BSEE is a new requirement, the number of 
design change reports is only an estimate; BSEE will adjust the 
frequency of design changes based on the actual number when we renew 
the relevant information collection in 3 years. The reporting of design 
changes due to the failure of critical safety equipment, as well as the 
reporting of such failures, is extremely important to the development 
of a knowledge-base that can be used to analyze past equipment failures 
and responses and help to prevent future failures that would jeopardize 
safety and environmental protection on the OCS.
Estimated Costs for Marine Construction
    Comment--A commenter questioned the accuracy of the estimated costs 
for marine construction in the initial economic analysis because the 
estimates did not include any costs (or the time) for transportation on 
the OCS.
    Response--Although the commenter did not explain what it meant by 
``marine construction,'' BSEE assumes it was referring to the cost of 
transportation on the OCS. BSEE does not agree that the total costs of 
transportation on the OCS should be included in the costs of the rule 
because operators can use regularly scheduled trips, coordinating with 
crew boats or helicopter trips, to achieve compliance with the final 
rule. There does not need to be a special, separate trip for this 
purpose. Moreover, trips to and from these facilities already occur 
frequently and are, therefore, part of the baseline. The costs for the 
petroleum technician, labor, shipping and materials are discussed in 
the final economic analysis.
Oil Spill Estimates
    Comment--A commenter asserted that BSEE overestimated the amount of 
spilled oil in the initial economic analysis, and that the estimate of 
57 leakage occurrences appears too high. The commenter requested that a 
list of the incidents considered by BSEE be included in the response to 
comments in the final rulemaking.
    Response--It appears that the commenter assumed that the oil spill 
volumes estimated in the initial analysis were related to the leakage 
occurrences. However, the oil spill estimate is not related to leakage 
incidents or leakage rates. Oil spill volumes refer to oil released 
into the environment. By contrast, the leakage occurrences refer to 
leaking SSSVs, which are part of a closed safety system, designed to 
minimize oil spills by stopping the flow within the tubing if the riser 
is damaged; thus, that oil is not released into the environment. Based 
on BSEE data for June 2003 through May 2013, BSEE issued a total of 57 
Incidents of Noncompliance (INCs) associated with leakage rates (P-280) 
under the category of ``Subsurface Safety Device Testing.''
Impacts of BAST
    Comment--Several commenters questioned the economic feasibility and 
impact of using BAST. They also asserted that the initial economic 
analysis failed to include any costs associated with the proposed 
revisions to Sec.  250.107(c) and that those potential costs should 
have been estimated and analyzed in the economic analysis.
    Response--This rule does not identify any technology as BAST and 
merely clarifies the regulatory language to be more in alignment with 
the statutory language. BSEE disagrees with the suggestions that the 
revisions to Sec.  250.107(c) constitute either a BAST program or a 
BAST determination, and that those revisions will impose new costs on 
operators. As explained in more detail later in this document, the 
revisions to Sec.  250.107(c) are intended to align the language of 
that paragraph more closely with the statutory language and intent of 
the BAST provision in OCSLA (43 U.S.C. 1347(b)). In fact, final Sec.  
250.107(c)(1) uses essentially the same language as the statutory 
provision, although the language in the final regulation is arranged so 
as to be more clear and easier to follow. Similarly, final Sec.  
250.107(c)(2) clarifies and confirms the longstanding principle, stated 
in former Sec.  250.107(c), that conformance with BSEE regulations 
qualifies as the use of BAST, unless or until the BSEE Director makes a 
specific BAST determination that other technologies are required. Thus, 
since final paragraph (c)(1) merely incorporates and clarifies the 
statutory language, and paragraph (c)(2) clarifies and reconfirms the 
existing regulatory language and policy, those provisions do not impose 
any new BAST requirements or create a new BAST program.\6\ Moreover, 
even assuming that

[[Page 61848]]

there were any costs associated with final Sec.  250.107(c)(1) and (2), 
they would be considered part of the economic baseline, as they merely 
reflect existing law and practice.
---------------------------------------------------------------------------

    \6\ In fact, several industry comments acknowledged that BSEE 
has been implementing a BAST program for some time, as discussed 
later in part IV.C with regard to comments on proposed Sec.  
250.107(c).
---------------------------------------------------------------------------

    The only arguably significant addition to existing Sec.  250.107(c) 
is final paragraph (c)(3), which states that the Director may waive the 
requirement to use BAST for a category of existing operations if the 
Director determines that use of BAST by that category of existing 
operations would not be practicable, and that the Director may waive 
the use of BAST at an existing operation if the operator demonstrates, 
and the Director determines, that the use of BAST would not be 
practicable for that operation. However, paragraph (c) in the existing 
regulation already effectively provided for such an exception from the 
required use of BAST,\7\ although it did not provide any explicit 
direction as to how to invoke that exception. Final paragraph (c)(3) 
provides a well-defined path for operators to seek and be granted a 
waiver from BAST requirements. Moreover, both the exception language in 
former paragraph (c) and the waiver language in final paragraph (c)(3) 
are consistent with the statutory BAST language, which states that BAST 
must be used on existing operations ``whenever practicable.'' Final 
paragraph (c)(3) embodies the converse of that requirement, and 
clarifies that use of BAST will not be required on existing facilities 
when the operator demonstrates, and the Director determines, that it is 
not practicable. Thus, final paragraph (c)(3) does not impose any new 
requirements, and any potential costs associated with that provision 
are properly included in the economic baseline, because final paragraph 
(c)(3) is consistent with the exception in existing Sec.  250.107(c) 
and with OCSLA. Nonetheless, BSEE has estimated the minimal potential 
costs associated with BAST waiver requests and included that estimate 
in the final economic analysis and the Paperwork Reduction Act burden 
estimate, as described in part V of this document.\8\
---------------------------------------------------------------------------

    \7\ Existing Sec.  250.107(c) provides that ``You must use the 
best available and safest technology (BAST) whenever practical on 
all exploration, development, and production operations.'' (Emphasis 
added.)
    \8\ The final economic analysis estimates that the total annual 
cost to all of the affected industry from the waiver provision would 
be $910.
---------------------------------------------------------------------------

BAST Process
    Comment--Another commenter asserted that there was no transparent 
process for identifying what technology qualifies as ``BAST'' and that, 
due to the lack of clarity and transparency on what would be required, 
the cost impact was grossly understated.
    Response--BSEE disagrees with this comment. As stated in response 
to the prior comment, neither proposed nor final Sec.  250.107(c) 
involves or affects BSEE's process for determining what specific 
technology is BAST. Revised Sec.  250.107(c) only clarifies, on a non-
technology-specific basis, when use of BAST is or is not required, and 
confirms that conformance with existing BSEE regulations is considered 
use of BAST unless and until the BSEE Director makes specific 
determinations that other technologies are BAST. Thus, as previously 
discussed, there are no costs associated with this section. Further, as 
several industry comments acknowledged, BAST is already an established 
part of BSEE regulations. Thus, since final Sec.  250.107(c) is 
consistent with the statutory requirements of OCSLA and with existing 
Sec.  250.107(c), any costs that might be attributable to the provision 
are part of the economic baseline. To the extent the commenter objects 
to, or wants to suggest improvements to, the process by which BSEE 
makes BAST determinations, the commenter may submit its views to BSEE. 
However, those views are beyond the scope of this rulemaking.
Costs for Sec.  250.800--General
    Comment--A commenter pointed out that the initial economic analysis 
did not include cost estimates for proposed Sec.  250.800--General.
    Response--BSEE disagrees with the suggestion that revised Sec.  
250.800 would impose new costs that should have been included in the 
economic analysis. That section of the final rule contains essentially 
the same requirements as existing Sec.  250.800, except for new 
language added to proposed and final paragraph (c)(2) and new paragraph 
(d). The new language in paragraph (c)(2) prohibits the installation of 
new single bore production risers. However, there are no new costs 
resulting from this new language because BSEE has not approved 
installation of any new single bore production riser for the last 8 
years; BSEE has only approved installation of dual bore risers over 
that time, and this now represents standard and longstanding industry 
practice. Therefore, the prohibition of new single bore risers is not a 
new development, and even assuming there are any costs associated with 
that prohibition, they are properly included in the baseline because 
the prohibition reflects existing industry and BSEE practice.
    Similarly, new paragraph (d), which was added to the final rule 
based on comments received, also does not impose any new costs on 
operators. That paragraph provides general guidance for compliance with 
subpart H; specifically, that in case of any conflicts between any 
incorporated standard and any provision in subpart H, the specific 
regulatory provision controls.
    The only other revisions to existing Sec.  250.800 incorporate or 
clarify the applicability of industry standards, previously 
incorporated in other sections of BSEE's regulations, to production 
safety equipment (e.g., productions safety systems on fixed leg 
platforms). As previously discussed, any costs attributable to 
incorporation of industry standards are properly included in the 
baseline because those standards represent generally accepted practices 
used by the industry in day-to-day operations, particularly those 
already codified in BSEE's regulations.
SPPE Certification
    Comment--A commenter raised the concern that the initial economic 
analysis related to proposed Sec.  250.801 (SPPE certification) did not 
discuss costs associated with BSDV certification. The commenter also 
asserted that the certification requirement was a BAST determination 
that did not comply with the BAST statute because BSEE did not 
demonstrate that certified valves perform better than non-certified 
valves.
    Response--We disagree with the comment suggesting that the proposed 
requirement for certification of SPPE constitutes a BAST determination 
by the bureau and that such determination is deficient. There is no 
connection between the SPPE certification process and BAST 
determinations because, among other reasons, the certification process 
is not a technology; rather, certification is a verification process. 
In addition, BSEE has considered the costs of certification of BSDVs 
and other SPPE in the final economic analysis, as discussed in part V 
of this document.
Cost for Retaining Documentation
    Comment--A commenter stated that costs associated with proposed 
Sec.  250.802(e) (regarding retention of certain documentation on SPPE 
for 1 year after decommissioning) were not discussed or analyzed in the 
initial economic analysis. The commenter did not, however, provide an 
estimate of the potential costs involved with this proposed 
requirement.
    Response--BSEE agrees with the comment, and the SPPE document 
retention requirement under final Sec.  250.802(e) is now addressed in 
the

[[Page 61849]]

final economic analysis as well as in the Paperwork Reduction Act (PRA) 
burden estimates that are discussed in part V of this document.
SPPE Costs
    Comment--A commenter asserted that potential costs under proposed 
Sec.  250.806 were not included in the initial economic analysis.
    Response--BSEE assumes that this comment refers to the existing 
Sec.  250.806, which was reorganized and re-codified in Sec. Sec.  
250.801 and 250.802 of the final rule. Section 250.806 is now reserved. 
The provisions from Sec.  250.806 of the existing regulations, now in 
final Sec. Sec.  250.801 and 250.802, require certification that 
certain SPPE valves were manufactured under a quality assurance program 
standard recognized by BSEE, such as API Spec. Q1. Since those 
provisions were codified in the existing regulations, and rely on 
existing industry standards, any costs associated with those existing 
requirements that are retained in final Sec. Sec.  250.801 and 250.802 
are included in the economic baseline. The additional potential costs 
of complying with the new provisions of the certification requirement 
are included in the final economic analysis, as discussed in part V.
Costs for Floating Production Unit Safety Systems
    Comment--In connection with proposed Sec.  250.854 (Floating 
production units equipped with turrets and turret-mounted systems), a 
commenter asserted that costs associated with new requirements were not 
discussed or analyzed in the economic analysis.
    Response--Section 250.854 addresses floating production units with 
either auto slew systems or swivel stacks. Floating production, 
storage, and offloading facilities (FPSOs) in the GOM are already in 
compliance with this section, so it will not result in new costs for 
existing FPSOs. There are no new costs for floating production units 
with an auto slew system because final Sec.  250.854 does not require 
the installation of new equipment. If an operator uses an auto slew 
system, this provision simply states that the auto slew system must be 
integrated with the process safety system, which does not require any 
new activity or equipment.
    Similarly, the requirement that a floating production unit with a 
swivel stack must have a hydrocarbon leak detection system tied in to 
the process safety system imposes no new costs. These facilities 
already have a leak detection system, as required in their approved 
Deepwater Operations Plans (DWOPs), since the FPSO's swivel stack is a 
critical leak path subject to longstanding DWOP leak detection 
conditions. Further, there are no additional costs resulting from the 
requirement to tie the leak detection systems into the process safety 
system because these requirements are longstanding conditions of 
approval under the DWOP process for floating production units.
Cost for Glycol Dehydration Units
    Comment--A commenter referenced proposed Sec.  250.857(b) and (c) 
(regarding installation of certain valves on glycol dehydration units), 
stating that there was no clarity on whether existing glycol 
dehydration units must comply with this requirement, and noted that if 
they do need to comply, those costs must be considered. The commenter 
requested that the final rule address the status of existing equipment.
    Response--This requirement is based on API RP 14C, which is already 
incorporated into BSEE regulations. The final rule simply clarifies 
that the location of the valves needs to be as close to the glycol 
contact tower as possible. As previously explained, BSEE includes the 
costs for following industry standards and existing regulation as part 
of the economic baseline.
Firefighting Systems
    Comment--A commenter noted that proposed new Sec.  250.859 would 
require that certain firefighting systems comply with all of API RP 
14G, while the corresponding provision in existing Sec.  250.803(b)(8) 
only required firefighting systems to comply with section 5.2 of API RP 
14G. The commenter asserted that the proposed change would have 
significant implications, and that the costs associated with the 
incorporation of the entire document were not considered in the initial 
economic analysis.
    Response--BSEE does not agree that any costs associated with 
firefighting systems meeting any provisions of API RP 14G must be added 
to the costs of the rule. As previously stated, and as explained in the 
final economic analysis, any costs associated with following existing 
industry standards are part of the economic baseline. In addition, as 
previously explained, BSEE has revised final Sec.  250.859(a) to 
require that firewater systems need to comply only with the relevant 
provisions of API RP 14G, which eliminates potential confusion as to 
whether firewater systems would have to meet new requirements under API 
RP 14G that currently do not apply to such systems.
Chemical Firefighting Systems
    Comment--A commenter asserted that proposed Sec.  250.860 
(regarding chemical firefighting systems) included new requirements 
from an existing NTL, and that BSEE should have analyzed the costs of 
those requirements.
    Response--BSEE disagrees. As already stated, any costs associated 
with following the guidance provided in existing NTLs, and now 
contained in this final rule, are part of the economic baseline. 
Consistent with OMB Circular A-4, the baseline includes all practices 
that are already incorporated into industry and regulatory standards, 
and that would continue even if the new regulations were never imposed. 
Since NTLs interpret, and provide guidance on how to comply with, 
existing regulations, BSEE expects that industry already follows the 
NTLs to comply with the relevant existing regulations and to ensure 
safety and reliability of operations.
Pressure Recording Devices
    Comment--A commenter noted that proposed Sec.  250.865(b) contained 
new requirements regarding pressure recording devices, and that there 
was no discussion in the proposed rule's preamble or the initial 
economic analysis concerning the need for and the costs of these new 
requirements.
    Response--BSEE does not agree that there are new costs associated 
with this provision that need to be accounted for as costs in the 
economic analysis because the pressure recording requirements in 
paragraph (b) were already required by Sec.  250.803(b)(1)(iii) of the 
existing regulations and, thus, are part of the economic baseline.
Atmospheric Vessels
    Comment--A commenter asserted that proposed Sec.  250.872(a), 
regarding atmospheric vessels, contained new requirements and that 
there was no discussion in the proposed rule or the initial economic 
analysis concerning the need for or costs of these new requirements.
    Response--BSEE disagrees. Proposed--and now final--Sec.  250.872(a) 
requires compliance with API RP 500 and API RP 505, both of which are 
incorporated in existing BSEE regulations (e.g., Sec. Sec.  250.114, 
250.802 250.803). Therefore, there are no new costs, beyond those 
included in the baseline, associated with this section.
Inspection Costs for Fire and Exhaust Heated Components
    Comment--A commenter asserted that the estimated costs ($5,000) in 
the initial economic analysis for proposed

[[Page 61850]]

Sec.  250.876, regarding inspection of fired and exhaust heated 
components, were too low. The commenter suggested that a better cost 
estimate would be at least 3 or 4 times that amount, and that the 
ability to obtain a qualified third-party to inspect these components 
in the timeframe required may be difficult.
    Response--BSEE agrees that these costs may be higher than what was 
originally estimated and has adjusted the costs appropriately in the 
final economic analysis.
3. Section-by-Section Summary and Responses to Comments
Definitions (Sec.  250.105)
    Section Summary--This section provides definitions of terms used 
throughout part 250.
    Regulatory text changes from the proposed rule--BSEE did not 
propose any changes to this section of the existing regulations in the 
proposed rule and has made no changes in the final rule.
    Comment--One commenter suggested that BSEE add a definition for the 
term ``platform'' to the final rule.
    Response--BSEE did not propose to define that term, and has decided 
not to add the commenter's suggested definition to the final rule. The 
word ``platform'' can have several meanings within BSEE's regulations, 
depending on where and how it is used. In addition, the suggested 
definition was specifically related to the commenter's concerns about 
future development of the Arctic OCS. BSEE recognizes the importance of 
the concerns related to future Arctic development and recently focused 
on Arctic-related issues in a separate final rulemaking, as already 
discussed in part IV.B.3.
What must I do to protect health, safety, property, and the 
environment? (Sec.  250.107)
    Section summary -This section of the existing regulations lays out 
performance-based and other requirements that operators must meet to 
protect safety, health, property and the environment. Paragraph (c) of 
the existing regulation required the use of BAST whenever practical on 
all exploration, development and production operations, while paragraph 
(d) authorized the Director to require additional measures to ensure 
use of BAST.
    Regulatory text changes from the proposed rule--BSEE proposed 
revisions to paragraph (c), and proposed to remove paragraph (d), in 
order to more closely track the BAST language in OCSLA and to provide 
additional clarity regarding how the BAST requirements would be 
implemented. Many of the comments on the proposed changes to this 
section supported the proposed language, although many industry 
commenters, while acknowledging issues or concerns related to the 
existing language, raised concerns related to the potential impact of 
the proposed language on existing facilities. In the final rule, BSEE 
has removed existing paragraph (d), as proposed.
    However, based on the comments received, BSEE has reorganized and 
revised the proposed changes to paragraph (c). BSEE has revised final 
paragraph (c)(1) to track even more closely the language of the 
relevant OCSLA provision. Final paragraph (c)(2) revises the proposed 
language to further clarify and confirm that compliance with BSEE 
regulations will be presumed to constitute the use of BAST, unless and 
until BSEE's Director determines that other technologies are required 
in accordance with final paragraph (c)(1). In addition, final paragraph 
(c)(3) revises the proposed BAST exception language to clarify that the 
Director may waive the requirement to use BAST for a category of 
existing operations if the Director determines that use of BAST for 
that category of operations would be impracticable. That paragraph also 
clarifies that the Director may waive the requirement to use BAST for 
an existing operation, if the operator demonstrates, and the Director 
determines, that using BAST in that operation would be impracticable.
    Comments and responses--BSEE received public comments on the 
following issues related to the proposed revisions to Sec.  250.107 and 
responds as follows:
Whether Proposed BAST Revision Not Needed/Premature
    Comment--Many comments asserted that the proposed changes to Sec.  
250.107 are premature and should be delayed until BSEE develops a 
detailed process for making and implementing BAST determinations and 
the National Academy of Engineering (NAE) completes a report on BAST.
    Response--BSEE disagrees with these comments. BSEE did not propose 
any changes to or request comments on the internal processes that BSEE 
uses to evaluate technologies in making BAST determinations. The 
primary objective of the proposed changes was to better align the 
regulatory provisions with the statutory mandate.
    That statutory provision requires:
    On all new drilling and production operations and, wherever 
practicable, on existing operations, the use of the best available and 
safest technologies which the Secretary determines to be economically 
feasible, wherever failure of equipment would have a significant effect 
on safety, health, or the environment, except where the Secretary 
determines that the incremental benefits are clearly insufficient to 
justify the incremental costs of utilizing such technologies. (43 
U.S.C. 1347(b).)
    In OCSLA, Congress directed the Secretary to require the use of 
BAST in these circumstances. Over a period of years, the regulatory 
language used to implement this statutory provision was modified as the 
offshore regulations were revised. As noted in the preamble of the 
proposed rule, BSEE believes that the existing regulatory language does 
not give full effect to the BAST obligations contained in the Act. (See 
78 FR 52243.)
    Revision of the BAST language in existing Sec.  250.107 is also 
consistent with the recommendations of the Ocean Energy Safety Advisory 
Committee (OESC), which was formed following the Deepwater Horizon 
incident to provide advice to the Secretary on issues related to 
offshore safety. The OESC, which consisted of representatives from 
industry, Federal government agencies, non-governmental organizations 
and the academic community, specifically recommended that BSEE revise 
the BAST regulations to more accurately reflect the statutory language 
and to ensure the effective implementation of a BAST program.
    Thus, BSEE does not believe that the proposed regulatory changes 
need to be delayed until the internal BAST implementation process is 
fully developed. In any case, since publication of the proposed rule in 
2013, BSEE has developed an internal process defining how technology 
will be evaluated by BSEE using a transparent and data-driven approach. 
This internal process was developed with significant input from many 
industry organizations and was discussed in detail at the BAST 
Conference hosted by the Ocean Energy Safety Institute on November 12, 
2015. Moreover, the NAE final report on BAST, published in January 
2014, was considered by BSEE in the development of this internal 
process. More information about the BAST Conference, NAE final report, 
and the BAST determination process is currently available on BSEE's 
BAST Web page at https://www.bsee.gov/bast/. Pre-publication copies of 
the NAE final report are available through BSEE's BAST Web page which 
links to NAE's Web site, or by going directly to NAE's Web site 
at:https://

[[Page 61851]]

www8.nationalacademies.org/onpinews/newsitem.aspx?RecordID=18545.
Whether Proposed Changes to BAST Language Are Unnecessary
    Comment--Some commenters asserted that regulatory changes are 
unnecessary since BSEE already implements an effective BAST program 
through the combination of regulations, industry standards, plan and 
permit approvals, alternative compliance approvals, departure 
approvals, platform verification, inspection and enforcement, data 
collection, training, and the safety alert program.
    Response--While BSEE agrees that it already maintains an effective 
BAST program, it nevertheless believes that changes to the existing 
regulatory language are necessary. As described in the proposed rule, 
and in prior responses to other comments, the changes to existing Sec.  
250.107(c) provide greater clarity and ensure consistency between the 
regulation and the language contained in OCSLA. BSEE agrees that, in 
many cases, existing regulations (including standards that are 
incorporated by reference in the regulations) will represent BAST. This 
is consistent with the intent of the language in existing Sec.  
250.107(c).\9\ In the final regulations, Sec.  250.107(c)(2) confirms 
and clarifies that compliance with the regulations is presumed to 
constitute BAST unless and until the Director makes a determination 
that other equipment or technology is required as BAST.
---------------------------------------------------------------------------

    \9\ Existing Sec.  250.107(c) states that ``In general, we 
consider your compliance with BSEE regulations to be the use of 
BAST.''
---------------------------------------------------------------------------

Whether Revised BAST Provisions Would Be Disruptive
    Comment--Several commenters stated that the proposed rule changes 
would disrupt an already established BAST process, that they would 
create uncertainty in the established BAST process, and that the impact 
of this uncertainty should be considered. Other commenters asserted 
that industry standards represent BAST.
    Response--BSEE does not agree that the proposed or final revisions 
to Sec.  250.107 would create more uncertainty. The proposed rule 
language essentially mirrored statutory language that has been in place 
since 1978 and eliminated ambiguous language that was perceived as 
potentially inconsistent with the statute. This final rule presents 
that language in an even clearer way and provides additional 
clarification on how BAST will be applied, while maintaining and 
improving alignment with the statutory language. For example, existing 
Sec.  250.107 did not provide any express parameters for identifying 
when compliance with the regulations would no longer be considered the 
use of BAST. The final rule clarifies that this situation would occur 
when the Director makes a formal BAST determination that specific 
technology is required.
    In addition, BSEE does not agree that consensus-based industry 
standards that have not been incorporated in applicable BSEE 
regulations automatically represent BAST. BSEE has incorporated by 
reference many industry standards into its regulations, and they play 
an important role in establishing a minimum baseline for the safety of 
offshore activities and equipment. And compliance with a regulation 
that incorporates a standard will be presumed to be the use of BAST, 
unless and until the Director makes a determination to require other 
technology(ies). However, a determination as to whether a specific, 
non-incorporated standard reflects BAST would need to be made by the 
Director on a case-by-case basis.
Whether BAST Determination Process Is Unclear
    Comment--Several commenters asserted that the proposed rulemaking 
was unclear regarding what factors and thresholds BSEE will use when 
deciding whether it will require an operator to use a certain 
technology as BAST and how long the operator has to come into 
compliance. Other commenters asserted that existing facilities should 
be ``grandfathered'' out of any new BAST requirements.
    Response--BSEE has revised Sec.  250.107(c) of the final rule to 
clarify that the BSEE Director will determine when to apply a 
particular technology as BAST. This change is consistent with the OCSLA 
BAST language (and a prior delegation of the Secretary's authority to 
the Director). Specifically, the Director will:
     Determine when the failure of equipment would have a 
significant effect on safety, health, or the environment;
     Determine the economic feasibility of the technology;
     Decide whether the incremental benefits are clearly 
insufficient to justify the incremental costs of utilizing such 
technologies;
     Decide whether to waive the use of BAST for a category of 
existing operations because the use of BAST would not be practicable 
for those operations; and
     Decide whether to waive the use of BAST for an existing 
operation if the operator of an existing facility requests a waiver and 
demonstrates, and the Director determines, that the use of BAST in that 
existing operation would not be practicable.
    BSEE does not agree, however, that an automatic ``grandfathering'' 
provision for existing facilities is appropriate. The language in OCSLA 
specifically makes BAST applicable to existing operations, provided 
that it is practicable and that the other determinations specified by 
the statute are made. BSEE has, however, clarified in final Sec.  
250.107(c)(3) the process for requesting a waiver from the use of BAST 
on existing facilities based on a demonstration by the operator, and a 
determination by the Director, of impracticability.
Economic Feasibility, Practicability, and Other Considerations in BAST 
Determinations
    Comment--Several comments addressed the criteria and process for 
making BAST determinations with respect to economic feasibility, 
practicability, and cost-benefit analyses regarding BAST. It was 
suggested that BSEE define and publish its determinations for the terms 
``economically feasible'' and ``practicable,'' and designate a pre-
determined length of time for existing operations to come into 
compliance.
    Commenters also suggested that BAST waivers or exceptions should be 
accompanied by a description of how the incremental benefits of using 
BAST were less than the incremental costs and should be subject to 
public review and comment. Commenters asserted that BSEE should 
incorporate the factors and thresholds on which it will determine which 
technology is BAST prior to finalizing the proposed rule, and that BSEE 
should be the ultimate decisionmaker as to BAST requirements.
    Additionally, one commenter stated that the proposed text increases 
uncertainty in that it appears to require operators to demonstrate that 
the incremental benefits of using BAST are insufficient to justify the 
costs in order to obtain an exception, which improperly shifts the 
burden to the operator.
    Response--BSEE agrees that some clarifications and revisions of the 
benefit-cost determination and the proposed exception language are 
appropriate. Consistent with Congress' intent concerning the evaluation 
of costs and benefits, final paragraph (c)(1) now clarifies that the 
Director will determine

[[Page 61852]]

whether the incremental benefits of certain technology are clearly 
insufficient to justify the incremental costs of utilizing BAST.\10\ 
Accordingly, BSEE has removed the cost-benefit language in the 
exception provision of proposed paragraph (c)(2) from the final 
rule.\11\ In addition, final paragraph (c)(3) clarifies that the 
Director may waive a BAST requirement for an existing operation if the 
waiver request demonstrates, and the Director determines, that the use 
of the BAST in question is not practicable. This is also consistent 
with Congress' intent that an operator show that use of BAST is not 
practicable for an existing operation: ``It is, of course, the 
responsibility of an operator on an existing operation to demonstrate 
why application of a new technology would not be `practicable'.'' H.R. 
Rep. No. 95-1474, at 109 (Aug. 10, 1978).
    BSEE does not agree, however, with the comments suggesting that the 
final rule include definitions or specific factors or ``thresholds'' 
for economic feasibility and practicability on which the Director will 
make BAST determinations or waiver decisions, respectively. OCSLA 
requires that BSEE (through a delegation from the Secretary) make BAST 
determinations, and BSEE has developed its formal process for BAST 
determinations in line with that authority. Every BAST determination 
requires a benefit-cost analysis of its own, to demonstrate that the 
BAST candidate technology is economically feasible and that it will 
result in benefits that are not clearly insufficient to justify the 
costs. For any future BAST determinations, BSEE will specify what is 
economically feasible for BAST purposes through rulemaking, except in 
cases involving emergency safety issues. These decisions will be 
largely technology- and fact-specific, and it would be premature to 
specify in this rule how such facts will be considered in particular 
cases.
---------------------------------------------------------------------------

    \10\ See, e.g., Report by the Ad Hoc Select Committee on the 
[OCS], Rep. No. 95-590 at 159 (Aug. 29, 1977) (``A balancing of 
danger and costs is required. The focus of this [BAST] provision is 
to require that operations in the [OCS] on leases are to be the 
safest possible. The regulator is to balance the significance of the 
procedure or piece of equipment on safety. If adoption of new 
techniques or equipment would significantly increase safety, and 
would not be an undue economic hardship on the lessee or permittee, 
he is to require it. In determining whether an undue economic 
hardship is involved, the regulator is to weigh incremental 
benefits, against incremental costs.'') See also H.R. Rep. No. 95-
1474, at 109 (Aug. 10, 1978) (``[C]onsiderations of costs and 
benefits should also be done by the regulating agency . . . .'')
    \11\ Since the final waiver provision does not require the 
operator to make an incremental cost-benefit demonstration, the 
comment suggesting that BSEE make the cost-benefit factors for a 
waiver or exception available for public review is moot.
---------------------------------------------------------------------------

    In any case, the proposed and final revisions of the language in 
Sec.  250.107(c) do not constitute a BAST determination and do not 
address BSEE's internal processes for making specific BAST 
determinations. BSEE revised this section in the final rule in large 
part to clarify that the BSEE Director will determine when to make 
those specific BAST determinations in accordance with the statutory 
criteria.
    Similarly, ``practicability'' demonstrations and decisions for 
waiver requests will depend on the circumstances of the existing 
operations at issue. However, BSEE expects that unique factors, such as 
the types or ages of specific facilities or environmental conditions, 
that make installation of BAST impracticable will be relevant in this 
decisonmaking.
Time Requirements for BAST Determination Process
    Comment--One comment requested that BSEE place a time limit on 
itself to review requests under the proposed provision allowing an 
operator to request an exception from using BAST by demonstrating that 
the incremental benefits are clearly insufficient to justify the 
incremental costs. The commenter said that BSEE's estimate that it 
would take an operator 5 hours to prepare the information to satisfy 
the proposed requirements for an exception is inadequate. The commenter 
asserted that it would take many more hours to compile, analyze and 
prepare information that demonstrates to BSEE that the operator's 
technology fits the exception to BAST. The commenter also asserted that 
BSEE will require far more time than predicted to analyze and review 
the information required by the proposed exception provision. 
Furthermore, the commenter stated that BSEE has not provided any 
guidance or process for implementing this proposed requirement.
    Response--BSEE does not agree with the suggestion that it needs to 
establish a more-detailed BAST exception (waiver) process or provide 
guidance for waivers prior to revising Sec.  250.107(c). BSEE may, 
however, provide guidance on the implementation of the BAST 
requirements, including the waiver process, in the future.
    The commenter's concern that a request for an exception under the 
proposed language would likely take many hours to complete and review 
has been effectively resolved by the revisions in final Sec.  
250.107(c)(3), which now provides that the operator only needs to 
demonstrate that use of BAST is not practicable (i.e., the operator 
does not need to demonstrate that the incremental costs exceed the 
incremental benefits). BSEE's current estimates as to the time needed 
for operators and BSEE to take the actions contemplated under the final 
waiver language are contained in the final economic analysis and the 
PRA portion of part V of this document.
Definition of ``Failure''
    Comment--One commenter requested clarification as to the definition 
of ``failure'' in the context of the proposed Sec.  250.107(c)(1), 
which stated that ``[w]herever failure of equipment may have a 
significant effect on safety, health, or the environment . . . .'' the 
use of BAST is required. The commenter stated that ``failure'' could 
have multiple meanings including mechanical failure, electrical 
failure, or test failure.
    Response--BSEE does not agree that a specific definition of 
``failure'' is necessary. The relevant language is drawn directly from 
OCSLA, which states that BAST must be used ``[w]herever failure of 
equipment would have a significant effect on safety, health, or the 
environment . . .'' BSEE used this language in the proposed and final 
rule to provide parameters for the types of failure that trigger the 
OCSLA requirement to use BAST. The Director would not require the use 
of BAST equipment if failures of that equipment would not result in a 
significant effect on safety, health, or the environment. What 
constitutes failure of equipment depends upon the context of the 
operation and equipment. Under this section, BSEE is addressing 
equipment failure as a general matter. Specific provisions related to 
equipment functionality are addressed in existing regulatory provisions 
and throughout this final rule.
BAST Discretion and Waiver
    Comment--One commenter requested clarification on proposed Sec.  
250.107(c)(1)(ii), which proposed that operators must use economically 
feasible BAST, ``wherever practicable on existing operations.'' The 
commenter requested clarification as to whether, at the discretion of 
BSEE personnel, existing equipment that is properly operating under 
normal conditions would need to be replaced even if it did not pose a 
threat of a malfunction or failure.
    Response--In the final rule, BSEE revised the language of proposed 
Sec.  250.107(c) to clarify that the Director will make the BAST 
determinations regarding economic feasibility and other

[[Page 61853]]

factors listed in final paragraph (c)(1). BSEE has also clarified the 
language in final paragraph (c) on the application of BAST to existing 
operations, consistent with the OCSLA BAST language. Under final Sec.  
250.107(c)(3), the Director may waive the requirement to use BAST for a 
category of existing operations if the Director determines that use of 
BAST would be impracticable for that category.
    In addition, the Director may waive the requirement to use BAST for 
an existing operation if the operator of an existing facility submits a 
waiver request demonstrating, and the Director then determines, ``that 
the use of BAST would not be practicable'' in that operation. For 
example, if an operator demonstrates, and the Director determines, that 
such technology(ies) would be unduly difficult or impossible to 
retrofit at an existing facility, the Director could grant the operator 
a waiver. In the absence of a waiver, however, existing operations must 
comply with BAST. As explained in response to other comments, OCSLA 
expressly requires the use of BAST for existing operations, whenever 
practicable, so Congress did not view existing technologies inherently 
to represent BAST.
Regulatory Flexibility Act Compliance Regarding BAST
    Comment--Several commenters asserted that BSEE had not met its 
obligations under the RFA with regard to the proposed BAST language; 
i.e., that it had not conducted a regulatory flexibility analysis to 
assess the impact of the proposed provision on small entities. 
Commenters also noted that, in the proposed rule, BSEE concluded that 
this rule is not likely to have a significant economic impact and, 
therefore, an initial RFA analysis was not required by the RFA, even 
though BSEE provided a contractor-prepared initial regulatory 
flexibility analysis in support of the certification. The commenters 
asserted, however, that this analysis was inadequate because BSEE 
considered only the estimated impacts of proposed revisions to subpart 
H and the estimated costs of seven provisions of subpart H. The 
analysis--and, by extension, the resulting certification of no 
significant impact--omits any consideration of estimated impacts from 
BSEE's proposed revision to the BAST rule in subpart A. In addition, 
several comments assert that by eliminating the longstanding general 
equivalence of regulatory compliance with BAST, BSEE's proposed 
revisions to the BAST rule would have significant impacts upon 
regulated entities, which BSEE had failed to consider, because that 
change would create uncertainty for regulated entities pertaining to 
whether their planned and ongoing operations meet BAST.
    Response--BSEE does not agree that it failed to comply with the RFA 
regarding the cost impact on small entities of the proposed revisions 
to Sec.  250.107(c). As previously explained in part IV.C.2, the 
proposed and now-final revisions to the BAST language impose no 
significant new costs on any entity, small or otherwise. The final 
revisions to Sec.  250.107(c) clarify the intent of the existing 
regulation and better align the regulatory language with the 
longstanding BAST language in OCSLA. In addition, the commenters' claim 
regarding the costs of the proposed deletion of former language 
equating compliance with BSEE regulations with BAST is moot, since the 
final rule now includes language maintaining that longstanding 
regulatory principle.
    As stated in previous responses, since the revisions to Sec.  
250.107(c) do not establish a new BAST program or new BAST 
requirements, but rather clarify and incorporate existing baseline 
statutory and regulatory principles governing BAST compliance, they 
create no new costs for small entities.\12\
---------------------------------------------------------------------------

    \12\ As explained elsewhere in part IV.C.2, any costs associated 
with BAST waiver requests may be considered part of the economic 
baseline. Nonetheless, BSEE has included those minimal costs in the 
final economic analysis and in the Paperwork Reduction Act burden 
estimate in part V of this document.
---------------------------------------------------------------------------

Whether Proposed BAST Rule Constitutes a ``Significant Regulatory 
Action''
    Comment--Commenters asserted that this rule constitutes a 
``significant regulatory action'' which should trigger a review by the 
Office of Information and Regulatory Affairs (OIRA) of its anticipated 
costs and benefits. The commenters noted that the proposed rule and its 
supporting documentation indicated that both BSEE and OIRA determined 
that this rule is not a significant rulemaking under E.O. 12866. 
Commenters asserted that both the proposed rule and the initial 
economic analysis considered only the potential costs and benefits of 
the proposed regulatory provisions of subpart H. Commenters suggested 
that this analysis--and by extension, the resulting determination that 
the proposed rule would not be significant--omits any consideration of 
estimated impacts from BSEE's proposed revision to the BAST rule in 
subpart A. Commenters also asserted that BSEE omitted the costs arising 
from the significant uncertainty the proposed BAST rule interjects into 
the operations and decision making by regulated entities that have long 
depended upon BSEE's regulations and regulatory process for 
implementing BAST in their offshore planning.
    Response--BSEE does not agree that its and OIRA's determination 
that this is not a significant rulemaking under E.O. 12866 is 
incorrect, especially with regard to the revised BAST language. As 
previously explained in responses to other comments, the revisions to 
Sec.  250.107(c) do not create a new BAST program or reflect any new 
BAST determinations, but rather merely clarify and incorporate 
longstanding baseline statutory and regulatory principles regarding 
BAST compliance, and, thus, impose no new costs on operators. The 
concerns related to the loss of certainty provided by regulatory 
compliance presumptively constituting BAST are likewise mitigated by 
the revisions BSEE made from the proposed to the final rule.
Definition of BAST
    Comment--One commenter suggested that BSEE has acknowledged that 
technologies already in place are BAST. The commenter also proposed 
language that recognizes that existing technologies meet the intent of 
OCSLA.
    Response--BSEE does not agree that the commenter's suggested 
language change is necessary or appropriate. The proposed concept is 
not consistent with OCSLA or its implementing regulations. Existing 
BSEE regulations at Sec.  250.105 define BAST as ``the best available 
and safest technologies that the BSEE Director determines to be 
economically feasible wherever failure of equipment would have a 
significant effect on safety, health, or the environment.'' This 
existing definition is consistent with the language and intent of OCSLA 
and clarifies that the Director may make BAST determinations on an 
industry-wide basis or for different classes or categories of 
operations based on economic feasibility. BSEE revised the BAST 
provisions under Sec.  250.107(c) in the final rule to be consistent 
with OCSLA and, thus, with the existing definition. The revisions also 
clarify that the Director will determine when to deem specific 
technology--not already required by BSEE's regulations--to be BAST, 
using the criteria specified in OCSLA, and that the Director also will 
determine when to waive the application of BAST to existing operations. 
Moreover, since OCSLA expressly requires the use of BAST, as determined 
in accordance with OCSLA, for existing operations whenever

[[Page 61854]]

practicable, we can conclude that Congress did not view all 
``technologies already in place'' or ``existing technologies'' 
inherently to represent BAST.
How must I install, maintain, and operate electrical equipment? (Sec.  
250.114)
    Section summary--This section of the existing regulations requires 
that areas be classified, and electrical systems installed, in 
compliance with certain incorporated electrical standards and that 
employees who maintain such systems have appropriate expertise. BSEE 
did not propose any changes to this section; however, BSEE has revised 
the section heading in the final rule to include ``maintain,'' in order 
to more fully and accurately capture the existing requirements of this 
section.
Service Fees (Sec.  250.125)
    Section summary--This existing section contains fees charged to 
operators for services BSEE provides, such as processing various 
applications. The final rule will revise this section to update the 
cross-references in paragraphs (a)(5) through (a)(10) to conform to the 
recodification of Sec.  250.802(e) to Sec.  250.842, as discussed later 
in this document. The entire table is republished in this final rule 
for completeness.
    Regulatory text changes from the proposed rule--In the final rule, 
BSEE has revised the fees from proposed Sec.  250.842 in order to 
reflect the current fee amounts in existing Sec.  250.802(e), some of 
which have changed since the proposed rule was published. BSEE revised 
final paragraphs (a)(5) and (a)(6) to clarify that facility visits are 
pre-production inspections.
    Comments and responses--BSEE did not receive any comments on this 
service fees section.
Documents Incorporated by Reference (Sec.  250.198)
    Section summary--Section 250.198 of the existing regulations 
contains provisions regarding how BSEE incorporates documents by 
reference in BSEE's regulations, lists all of the documents BSEE 
incorporates by reference in part 250, and confirms BSEE's general 
expectations for compliance with those documents. The requirements for 
complying with a specific incorporated document can be found where the 
document is referenced in the regulations, as specified in Sec.  
250.198. As proposed, the final rule incorporates by reference one 
standard (API 570) that had not previously been incorporated in Sec.  
250.198, and requires compliance with API 570 in various sections of 
the proposed rule (as described in part II.B of this document). As 
proposed and as explained elsewhere, various sections of the final rule 
require compliance with 8 standards that had previously been 
incorporated by reference in existing Sec.  250.198; thus, the final 
rule revises Sec.  250.198, as proposed, by adding the section numbers 
for those new requirements to the appropriate subparagraphs in Sec.  
250.198.
    Regulatory text changes from the proposed rule - In the final rule, 
BSEE has revised proposed paragraph (h)(51) to include references to 
the incorporation by reference of the identified documents at 
Sec. Sec.  250.292 and 250.733. Final paragraph (h)(70) was also 
revised to include references to the incorporation by reference of the 
identified documents at Sec. Sec.  250.730 and 250.833.\13\ The 
references to sections Sec. Sec.  250.292 and 250.833 were 
inadvertently omitted in the proposed rule. Similarly, the final rule 
makes minor, non-substantive punctuation and related changes to 
paragraphs (h)(93) through (h)(95), which were added to Sec.  250.198 
by separate final rules published after this proposed rule.\14\ 
References were also updated in other sections to reflect the most 
recent reaffirmations of relevant documents.
---------------------------------------------------------------------------

    \13\ The references to Sec. Sec.  250.730 and 250.733 are 
necessary because those sections were added to 30 CFR part 250 as 
part of the final rule, ``Blowout Preventer Systems and Well 
Control'' published on April 29, 2016 (81 FR 25888).
    \14\ Those final rules are the Blowout Preventer Systems and 
Well Control Rule, at 81 FR 26015, and the Requirements for 
Exploratory Drilling on the Arctic Outer Continental Shelf Rule, 81 
FR 46478, 46560 (July 15, 2016).
---------------------------------------------------------------------------

    Comments and responses--BSEE received public comments on this 
section and responds to the comments as follows:
Standards Already Incorporated in Other Parts of the Regulations
    Comment--One commenter observed that some of the standards 
incorporated by reference into the proposed rule are already 
incorporated into other parts of the existing regulations.
    Response--Standards may be incorporated into multiple parts of the 
regulations, as when similar equipment may be used for different 
operations subject to different regulatory provisions. For example, 
subparts H and I require similar considerations for design; 
incorporating the same standards in relevant sections of both subparts 
ensures that the production safety system and the platform or structure 
are integrated. In other cases, BSEE has decided that the same 
standards should apply for other reasons. For example, pipelines, which 
are regulated under subpart J, and certain aspects of production safety 
systems related to piping, regulated under subpart H, implicate several 
of the same standards and BSEE has determined that it is important to 
incorporate each relevant standard in all regulatory sections to which 
it applies.
Request of BAST Determination for Incorporated Standards
    Comment--One commenter requested an explanation of how BSEE 
determined that each standard proposed for incorporation in the 
regulations was the best available and safest technology and operating 
practice for the OCS.
    Response--The incorporation of industry standards does not reflect 
a specific BAST determination by BSEE. The authority to incorporate 
industry standards into BSEE regulations is separate from the BAST 
authority. The National Technology Transfer and Advancement Act (NTTAA) 
mandates that Federal agencies use technical standards developed or 
adopted by voluntary consensus standards bodies, as opposed to using 
government-unique standards, where practicable and consistent with 
applicable law. These criteria for rulemaking are different from those 
applicable to BAST determinations under OCSLA and Sec.  250.107(c). 
BSEE follows the requirements of the NTTAA and the relevant guidance in 
OMB Circular A-119 when incorporating standards into its regulations.
Availability of Standards for Public Review
    Comment--Some commenters expressed concern about the availability 
of the standards incorporated by reference in the proposed rule. They 
were concerned that many standards are not easily accessible or 
generally available to the public as part of the rulemaking process or 
thereafter. One commenter estimates that the public's burden for 
purchasing the industry standards that were not made available to the 
public would be approximately $5,900. This amount includes all the 
standards referenced at Sec.  250.198 that are not available to the 
public free-of-charge. Some commenters also stated that the public cost 
burden makes meaningful public participation in rulemaking cost-
prohibitive and proposes that BSEE change its process for incorporating 
standards.
    Response--As discussed in part II.C of this document, all standards 
incorporated by reference in BSEE's regulations are available to view 
for free

[[Page 61855]]

at BSEE offices. In addition, the public may view API documents 
incorporated in BSEE regulations free of charge on API's Web site 
(https://www.api.org/publications-standards-and-statistics/publications/government-cited-safety-documents). Some standards organizations make 
their standards available for viewing on ANSI's Web page (https://ibr.ansi.org/Standards/Default.aspx). In addition, documents from other 
standards organizations may be purchased directly from those 
organizations. Standards may be copyright protected under U.S. and 
international law. Federal law, including the NTTAA, upon which BSEE 
relies to incorporate industry consensus standards by reference, does 
not eliminate the availability of copyright protection for industry-
developed consensus standards incorporated by reference into Federal 
regulations.\15\ While BSEE works to maximize the accessibility of 
incorporated documents, and provides directions to where the materials 
are reasonably available pursuant to Office of Federal Register (OFR) 
requirements, it also must respect the publisher's copyright. OFR's 
regulations state that, if a proposed rule does not meet the applicable 
requirements for incorporation by reference, the OFR Director will 
return the proposed rule to the agency (see 1 CFR 1.3); that did not 
occur here. There is no requirement that such documents be available 
either online or for free. (See 79 FR 66269-72 (Nov. 7, 2014), 
explaining why OFR declined to include such requirements in its 
regulations on incorporation by reference.)
    The estimate provided by the commenter ($5,900 to purchase the 
standards that were not made available to the public for this 
rulemaking) includes standards already incorporated into existing BSEE 
regulations. The commenter stated that the $5,900 estimate includes all 
the standards referenced in Sec.  250.198 that are not available to the 
public free-of-charge. The estimated cost, therefore, includes 
standards that are not incorporated into subpart H or related to this 
rulemaking and overstates the costs associated with this rulemaking.
---------------------------------------------------------------------------

    \15\ See, e.g., Incorporation by Reference final rule, Office of 
the Federal Register, 79 FR 66267, 66273 (Nov. 7, 2014) (``[T]he 
NTTAA [has] not eliminated the availability of copyright protection 
for privately developed codes and standards that are referenced in 
or incorporated into federal regulations. Therefore, we cannot issue 
regulations that could be interpreted as removing copyright 
protection from IBR'd standards.'')
---------------------------------------------------------------------------

Conflicts Between Incorporated Standards and BSEE Regulations
    Comment--Commenters expressed concern that there is a lack of 
clarity regarding precedence when a standard conflicts with a 
regulation. Commenters stated that the regulations should specifically 
state that wherever BSEE's regulations are more specific or provide 
more stringent requirements than those listed in an industry standard, 
BSEE's regulations take precedence.
    Response--BSEE has provided clarification, in final Sec.  
250.800(d), that if there is a conflict between the standards 
incorporated through this rulemaking and other provisions of subpart H, 
the operator must follow the regulations.
Public Review and Comment on Incorporated Standards
    Comment--Commenters asserted that: BSEE should go through the 
process of public review and comment prior to incorporating a new or 
updated standard: There should be at least a 30-day public review and 
comment period on proposed rulemakings to update an industry standard; 
and BSEE should provide a technical support document for that proposed 
rulemaking showing how BSEE determined the updated standard to be the 
best available and safest technology and operating practices and 
explaining why incorporating the industry standard results in a safety 
improvement.
    Response--The commenters' requests as to how BSEE should 
incorporate industry standards in the future is beyond the scope of 
this rulemaking. As previously discussed, in this rulemaking BSEE made 
all of the documents incorporated by reference available for public 
review in connection with the comment period provided for the proposed 
rule and continues to make publicly available at its office all of the 
standards incorporated by reference in the final rule.
    In any event, in its rulemakings, BSEE complies with the NTTAA 
requirement that an agency ``use standards developed or adopted by 
voluntary consensus standards bodies rather than government-unique 
standards, except where inconsistent with applicable law or otherwise 
impractical.'' (OMB Circular A-119 at p. 13). BSEE also complies with 
the OFR regulations governing incorporation by reference. (See 1 CFR 
part 51.) Those regulations also specify the process for updating an 
incorporated standard at Sec.  51.11(a), and BSEE complies with those 
requirements, including seeking approval by OFR for a change to a 
standard incorporated by reference in a final rule. BSEE generally 
provides for public notice and comment through proposed rulemaking when 
incorporating a new standard into its regulations.\16\
---------------------------------------------------------------------------

    \16\ Under certain circumstances, existing Sec.  250.198(a)(2) 
authorizes BSEE to incorporate a newer edition of an industry 
standard through a direct final; however, that authority was not 
exercised in this rulemaking.
---------------------------------------------------------------------------

    Finally, as previously explained, the incorporation of industry 
standards does not reflect a specific BAST determination by BSEE; those 
actions derive from separate authorities and are governed by different 
criteria.
Updating Standards Incorporated in the Regulations
    Comment--Commenters suggested that BSEE should: Review all industry 
standards listed in Sec.  250.198 to eliminate discontinued standards; 
update standards for which newer versions have been published, if BSEE 
determines the updated standard version provides BAST and operating 
practice improvements; and eliminate standards that no longer represent 
BAST and best operating practices.
    Response--This comment, seeking future action by BSEE to amend 
Sec.  250.198, is also outside the scope of this rulemaking. BSEE 
reiterates that a decision to incorporate, or revise an existing 
incorporation of a standard is separate from specific BAST 
determinations. Nonetheless, BSEE engages in retrospective review of 
its regulations in accordance with E.O. 13563 and E.O. 13610 ``to 
ensure, among other things, that regulations incorporating standards by 
reference are updated on a timely basis . . . .'' (OMB Circular A-119 
at p. 4). In fact, BSEE has already begun reviewing many of the 
standards incorporated in the existing regulations and will provide 
additional information regarding its review when appropriate. If BSEE 
decides that some updating of incorporated standards (e.g., by 
referencing new editions of existing standards, or replacing previously 
incorporated standards with different standards, or simply deleting 
outdated standards) is warranted, it will explain its position through 
future rulemakings, as necessary. Of course, BSEE may also decide, for 
appropriate reasons, to keep a previously incorporated edition of a 
standard in the regulations even if there is an updated edition.
Tubing and Wellhead Equipment (Sec.  250.518)
    Section summary--Paragraph (d) of existing Sec.  250.518 requires 
that subsurface safety equipment be installed, maintained, and tested 
in

[[Page 61856]]

compliance with the applicable provisions of subpart H. BSEE proposed 
to revise this section to include updated cross-references to new 
section numbers in subpart H.
    Regulatory text changes from the proposed rule--BSEE corrected the 
section number in the final rule to ``Sec.  250.518,'' since the 
citation (``Sec.  250.517'') used in the proposed rule was in error.
Incorrect Section Number
    Comment--A commenter pointed out that the proposed revision 
actually belongs in existing Sec.  250.518.
    Response--BSEE agrees and has corrected the section number in the 
final rule to Sec.  250.518 (Tubing and wellhead equipment).
Tubing and Wellhead Equipment (Sec.  250.619)
    Section summary--Paragraph (e) of Sec.  250.619 of the existing 
rule requires that subsurface safety equipment be installed, 
maintained, and tested in compliance with the applicable provisions of 
subpart H. BSEE proposed to revise this section to include updated 
cross-references to the new section numbers in subpart H.
    Regulatory text changes from the proposed rule--BSEE updated the 
section number in the final rule to ``Sec.  250.619'' because the 
citation used in the proposed rule (``Sec.  250.618'') was in error.
Incorrect Section Number
    Comment--A commenter pointed out that the proposed revisions 
actually belong in Sec.  250.619, not Sec.  250.618.
    Response--BSEE agrees and has corrected the section number to 
``Sec.  250.619'' in the final rule.
General (Sec.  250.800)
    Section summary--This section of the existing regulations 
established general requirements for the design, installation, use, 
maintenance, and testing of production safety equipment, including 
production safety systems to be used in subfreezing climates, to ensure 
safety and to protect the environment. This section of the final rule 
retains most of those requirements and further clarifies the design 
requirements for production safety equipment. In particular, BSEE added 
a new paragraph (b) to the final rule, as proposed, specifying the 
industry standard--API RP 14J, Recommended Practice for Design of 
Risers for FPSs and TLPs--that operators must follow for new production 
systems on fixed leg platforms. In the final rule, BSEE revised 
existing paragraph (b) and redesignated it as paragraph (c), which 
retains the existing requirement that new floating production systems 
(FPSs) comply with API RP 14J. Existing paragraph (b) also required new 
FPSs to comply with the drilling and production riser standards of API 
RP 2RD, Recommended Practice for Design of Risers for FPSs and TLPs; 
final paragraph (c), as proposed, omits the reference to the drilling 
standards, but retains the requirement for compliance with the 
production riser standards of API RP 2RD.
    Final paragraph (c), as proposed, also provides examples of FPSs 
(e.g., column-stabilized-units (CSUs); FPSOs; TLPs; and spars) and 
revises the existing stationkeeping system requirements for new 
floating facilities by adding a reference to API RP 2SM, Design, 
Manufacture, Installation, and Maintenance of Synthetic Fiber Ropes for 
Offshore Mooring. In addition, BSEE proposed in paragraph (c) to 
prohibit installation of single bore production risers on floating 
production facilities beginning 1 year after the publication date of 
the final rule.
    Regulatory text changes from the proposed rule--After consideration 
of public comments, BSEE removed the proposed provision that would have 
allowed operators 1 year after publication of the final rule to comply 
with the prohibition against installing new single bore production 
risers. Thus, final paragraph (c)(2) now prohibits the installation of 
single bore production risers from floating facilities as of the 
effective date of the final rule.
    BSEE also added the parenthetical ``(i.e., anchoring and mooring)'' 
after the word ``stationkeeping'' to final paragraphs (c)(3) and (c)(4) 
in order to clarify the types of stationkeeping systems for floating 
production facilities to which those paragraphs apply. Those revisions 
also clarify that this provision is not intended to regulate the design 
of the dynamic positioning system (i.e., the propulsion system); 
rather, they will simply ensure that the potential impacts an anchoring 
or mooring system could have on an FPS are considered during design of 
the production process system. (For example, the buoy of a turret-
mounted FPS is a structural element of the production system, while the 
mooring system may also affect the production system.)
    Based on public comments, BSEE also added a new paragraph (d) to 
clarify that if there are differences between the incorporated industry 
standards and the regulations, the operator must follow the 
regulations. Finally, BSEE added new paragraphs (e) and (f) to point 
out that operators may submit requests to use alternate procedures or 
equipment or for a departure from the subpart H regulations under 
existing Sec. Sec.  250.141 and 250.142, respectively.
    Comments and responses--BSEE received comments on several issues 
related to dual bore and single bore risers under this proposed section 
and responds to the comments as follows:
Dual Bore Production Risers/Prohibition on New Installation of Single 
Bore Risers
    Comment--Some commenters took issue with the requirement for dual 
barrier production risers, stating that the term ``production riser'' 
may have several meanings. Commenters asserted that dual barrier 
production risers do not need to be used when subsea trees are in 
place, but accepted that dual barrier production risers are appropriate 
when using dry trees. Commenters also stated that using single barrier 
production risers downstream from subsea trees is a widely-accepted 
industry practice and that ``it has generally been considered safe 
practice to complete wells through [an] outer riser, using mud weight 
and the outer riser to provide two barriers with a surface blow out 
preventer having at least two rams.'' Commenters asserted that 
requiring dual barrier risers downstream from subsea trees would be 
uneconomical or impossible. Commenters stated that where subsea trees 
are used, the tree provides a failsafe barrier to the ocean and, thus, 
that using single barrier risers downstream of subsea trees is a safe 
and acceptable practice. Commenters asserted that ``a blanket ban on 
one particular type of riser configuration and operation does not 
comply with the statutory requirement for BAST or with the industry 
experience'' and urged BSEE to reconsider the proposed rule.
    Response--Final Sec.  250.800(c)(2) only applies to the 
installation of production risers from new FPSs.\17\ The regulations do 
not require operators to discontinue use of single-bore production 
risers that are already in place. The prohibition of installation of 
single bore production risers from new floating production facilities 
does not apply to single bore pipeline or flowline risers. BSEE does 
not consider the pipeline or flowline from a subsea tree to the host 
facility to be a production riser; rather BSEE considers it a pipeline 
or flowline riser. BSEE recognizes that the use of single bore pipeline 
or flowline risers is a

[[Page 61857]]

widely-accepted practice that allows for cost-effective hydrocarbon 
production. If there are any questions about what qualifies as a 
production riser, the operator may contact the appropriate District 
Manager.
---------------------------------------------------------------------------

    \17\ The requirements for non-production risers used during 
drilling and well completion operations are addressed in existing 
Sec.  250.733(b)(2) and are not addressed here.
---------------------------------------------------------------------------

    Comment--Several commenters expressed concern about how the 
prohibition on installation of single bore production risers will 
affect existing single bore production risers. Commenters asserted that 
this technology is acceptable in some applications, and that BSEE 
should allow future uses of single bore production risers in certain 
circumstances given that such risers may allow for production from 
reservoirs that would otherwise be uneconomical. Commenters stated that 
the preamble of the proposed rule did not provide any detail on why 
BSEE believes this situation to be unacceptable and asked that BSEE 
provide justification for prohibiting a technology that has not been 
proven to be problematic. Furthermore, the commenters asked why, if 
BSEE believes this practice to be unsafe, BSEE would allow this 
practice to be available for up to a year after the publication of the 
final rule.
    Commenters also recommended revising the regulatory text to confirm 
that operators can seek relief from the requirements of subpart H where 
appropriate.
    Response--This section of the proposed and final rule does not 
address drilling, flowline, or pipeline risers; it only addresses 
single bore production risers installed on FPSs after the effective 
date of the rule. Moreover, the concerns about the prohibition on 
installation of single bore risers is academic, since it has been more 
than 8 years since BSEE approved the installation of any new single 
bore production risers; thus, in effect, the regulatory prohibition 
reflects longstanding BSEE policy and industry practice.\18\
    As to currently installed single bore risers, neither the proposed 
nor the final rule prohibits their continued use. Operators may 
continue to use single bore production risers that are currently 
installed, although when work is performed through a single bore 
production riser, it causes wear on the riser, compromising its 
integrity. Thus, additional precautions for wear protection, wear 
measurement, fatigue analysis, and pressure testing prior to performing 
any well work with the tree removed are necessary for currently 
installed single bore risers. This is consistent with established BSEE 
policy and past approvals for well operations using currently installed 
single bore production risers. It is possible to do this work safely if 
the existing riser is in good shape, but there is no room for error or 
failures, since a single bore riser has only a single mechanical 
barrier and the consequences of failure of a single bore riser with 
open perforations could be serious; that is why BSEE has long required 
in permitting decisions, and is now codifying the requirement, that 
operators use dual barrier production risers for new installations.
    Regarding the implementation date for the prohibition of single 
bore risers, BSEE agrees with the commenter that making the prohibition 
effective in 1 year was not appropriate under the circumstances; thus, 
BSEE has changed the effective date of this provision in the final rule 
to be the same as the effective date of the rule. If there is a 
question about what a single bore production riser is and how this 
provision applies to a specific situation, the operator may contact the 
appropriate District Manager.
---------------------------------------------------------------------------

    \18\ BSEE also finalized a similar provision as part of the 
Blowout Preventer Systems and Well Control Final Rule, effective 
July 28, 2016. (81 FR 25888 (April 29, 2016.)
---------------------------------------------------------------------------

    Further, as suggested by some commenters, BSEE has added new 
paragraphs (e) and (f) to the final rule to point out that operators 
may seek approval to use alternate equipment or procedures in lieu of, 
or request departures from, the requirements of subpart H in accordance 
with existing Sec. Sec.  250.141 and 250.142, respectively. Several 
provisions of the proposed rule included similar language; however, 
since the alternate compliance and departure provisions apply to all 
sections of part 250, it is not necessary to cite them expressly 
throughout the final rule. By including a single reference to 
Sec. Sec.  250.141 and 250.142 in final Sec.  250.800, BSEE confirms 
that those provisions are applicable to all subpart H requirements.
Hazard Analysis For FPSs
    Comment--Commenters raised an issue related to proposed paragraph 
(c), requiring that all new FPSs comply with API RP 14J. Commenters 
stated that API RP 14J is a guidance document that identifies multiple 
tools for conducting a hazards analysis on offshore facilities, but 
noted that the proposed rule did not specify which tool(s) the operator 
must use to meet BSEE's expectations. Commenters also asserted that 
operators are already required to conduct a hazards analysis using one 
of the tools identified in API RP 14J or another recognized document in 
accordance with subpart S of BSEE's regulations, (i.e., the SEMS 
regulations). Commenters recommended that BSEE first establish design 
and construction criteria for new units and then adjust the regulatory 
language to reflect the multiple tools in API RP 14J. Commenters 
recommended that BSEE either delete the API RP 14J requirement from 
this subpart, or revise the language to require operators to conduct a 
hazards analysis utilizing any one of the methodologies identified in 
API RP 14J.
    Response--BSEE disagrees with the suggested changes to this 
section. API RP 14J, incorporated in final Sec.  250.800(c) (for FPSs), 
was already incorporated by reference in former Sec.  250.800(b) for 
the same types of facilities. Therefore, operators should already be 
complying with the relevant requirements, and this comment actually 
suggests eliminating existing regulatory requirements rather than 
modifying the proposed requirements. The existing and proposed (and now 
final) requirements are consistent with and complementary to those in 
the existing subpart S regulations. The operator may use any hazards 
analysis that satisfies subpart H to meet the requirements under 
existing Sec.  250.1911 of subpart S; however, final Sec.  250.800(c) 
will ensure that operators use an appropriate hazards analysis method 
selected in accordance with the relevant hazards analysis provisions of 
API RP 14J.\19\
---------------------------------------------------------------------------

    \19\ API RP 14J, section 7.1 states: ``[t]he following sections 
describe the principal elements of hazards analysis and the various 
methods available, discuss review procedures to be followed, and 
outline the guidelines for selection of an appropriate method.''
---------------------------------------------------------------------------

Safety and Pollution Prevention Equipment (SPPE) Certification (Sec.  
250.801)
    Section summary--This section of the final rule contains 
requirements that were contained in Sec.  250.806 of the existing 
regulations, requiring the installation of certified SPPE on OCS wells 
or as part of the system associated with the wells. The final rule, as 
proposed, also contains provisions to clarify that SPPE includes SSVs 
and actuators, such as those installed on injection wells capable of 
natural flow as well as BSDVs beginning 1year after the publication 
date of the final rule. (The installation and use of BSDVs was 
previously addressed in NTL No. 2009-G36, which clarified that BSDVs 
have the same function as SSVs and that BSDVs are the most critical 
component of a subsea system; thus, BSDVs that received approval and 
were installed in accordance with that NTL should

[[Page 61858]]

already be in compliance with the requirements in the final rule.)
    This section of the final rule also specifies that BSEE will not 
allow subsurface-controlled SSSVs on subsea wells and omits the 
reference to the ANSI/ASME standards found in existing Sec.  250.806 
because those standards are outmoded or have been withdrawn. The final 
rule also provides that SPPE equipment that is manufactured and marked 
pursuant to API Spec. Q1 will be considered certified SPPE under part 
250. Although SPPE that is not manufactured or stamped pursuant to API 
Spec. Q1 is presumptively non-certified, final Sec.  250.801(c) 
provides that BSEE may exercise its discretion to accept SPPE 
manufactured under quality assurance programs other than API Spec. Q1, 
provided that an operator submits a request to BSEE containing relevant 
information about the alternative program, that an appropriately 
qualified third-party verifies the alternative program as equivalent to 
API Spec. Q1, and that BSEE approves the request. In addition, final 
paragraph (c) authorizes an operator to request that BSEE accept SPPE 
that is marked with a third-party certification mark (other than an API 
monogram).
    Regulatory text changes from the proposed rule--In the final rule, 
BSEE revised proposed paragraph (a)(2) to include BSDV ``and their 
actuators.'' This is consistent with the requirements for other SPPE 
and acknowledges that the actuator is an integral part of the valve. 
BSEE further revised that paragraph to clarify that, for subsea wells, 
a BSDV is the equivalent of an SSV on a surface well. BSEE also revised 
proposed paragraph (c) to provide that any requested alternative 
quality management system must be verified as equivalent by an 
appropriately qualified entity.
    Comments and responses--BSEE received public comments on this 
section and responds to them as follows:
Quality Assurance Programs
    Comment--Commenters expressed concern that proposed Sec.  250.801 
would only recognize the quality assurance program in API Spec. Q1 for 
certified SPPE. Those commenters suggested broadening the coverage of 
the rule to include International Organization for Standardization 
(ISO) 9001, ``Quality Management Standards--Requirements'') (2015). 
Another commenter recommended that the equipment be marked by the 
manufacturer with the API Monogram as proof of conformance with the 
proposed requirement.
    Response--BSEE evaluated this recommendation and has determined 
that the proposed quality assurance program requirements under 
paragraphs (a) and (b) are appropriate and provide sufficient 
flexibility. Nonetheless, BSEE has revised final Sec.  250.801(c) to 
clarify that an operator may submit a request to BSEE to accept SPPE 
manufactured under another quality assurance program as compliant with 
paragraph (a), provided that an appropriately qualified entity (such as 
one that meets the criteria of ISO 17021-3, ``Conformity assessment--
Requirements for bodies providing audit and certification of management 
systems--Part 3: Competence requirements for auditing and certification 
of quality management systems,'' or similar criteria) verifies that the 
other quality assurance program is equivalent to API Spec. Q1. In 
addition, although BSEE has decided that a monogram requirement is not 
necessary, since this provision helps ensure the quality of the SPPE 
during the manufacturing process, BSEE will consider the marking of 
SPPE with the API monogram or a similar third-party certification mark, 
as alternative evidence of conformance with this section.
Definition of BSDV
    Comment--One commenter requested clarification of the definition of 
a BSDV. Another commenter requested that BSEE clarify that only those 
valves associated with subsea systems qualify as BSDVs.
    Response--According to the Barrier Concept (as discussed in BSEE 
NTL No. 2009-G36), for subsea wells, the BSDV is the surface equivalent 
of an SSV on a surface well. BSEE has added text to Sec.  250.801(a)(2) 
in the final rule to clarify this point. Thus, the function of the BSDV 
is similar to the function of the SSV, and since the BSDV is a critical 
component of the subsea system, it is appropriate for BSDVs to be 
subject to the same requirements as SSVs under Sec.  250.801. This also 
ensures the appropriate level of safety for the production facility. 
Final Sec.  250.835 states that BSDVs are associated with subsea 
systems; this point is also emphasized by the revised text in final 
Sec.  250.801(a)(2).
Certification of SPPE
    Comment--Commenters requested clarification as to whether BSEE will 
deem existing SPPE acceptable, despite new certification requirements, 
until such equipment can be replaced. A commenter also requested 
clarification of the estimated impact on the cost and supply of SPPE 
equipment once ANSI/ASME SPPE-1-1994, ``Quality Assurance and 
Certification of Safety and Pollution Prevention Equipment Used in 
Offshore Oil and Gas Operations,'' is no longer acceptable as an SPPE 
certification program.
    Response--Section 250.806 of the existing regulations contained 
requirements similar to those in proposed Sec.  250.802(d) regarding 
the use and installation of certified SPPE. Specifically, existing 
Sec.  250.806 required use of certified SPPE if that SPPE was installed 
on or after April 1, 1998. However, existing Sec.  250.806 also 
provided that non-certified SPPE in use as of that date could continue 
in service unless and until that equipment needed offsite repair, 
remanufacture or hot work (such as welding). Similarly, final Sec.  
250.802(d), as proposed, confirms that operators may continue to use 
any existing non-certified SPPE already in service unless and until it 
needs offsite repair, remanufacture or hot work. In addition, since 
final Sec.  250.801 includes BSDVs as SPPEs (beginning September 7, 
2017), the final rule provides that operators have until that date to 
come into compliance with the certification requirements for any new 
BSDVs; moreover, under final Sec.  250.802(d), currently installed non-
certified BSDVs may remain in service unless and until they require 
offsite repair, remanufacture or hot work.
    The commenter's question about the cost and supply impacts that 
could occur once ANSI/ASME SPPE-1 was no longer recognized is already 
moot. That standard was withdrawn by industry in favor of API Spec. Q1 
in 2013. Thus, the final rule should not adversely affect SPPE costs or 
supplies because industry has already evolved in keeping with the 
change in industry standards from ANSI/ASME SPPE-1 to API Spec. Q1.
Certified vs. Non-Certified SPPE
    Comment--One commenter asserted that a report referred to in the 
proposed rule \20\ demonstrates that a certified valve does not perform 
any better than a non-certified valve, and that BSEE has not 
demonstrated, through statistics and failure data, justification for 
the certification requirement. The commenter asserted that the 
requirement for use of only ``certified'' SPPE is not supported by the 
referenced

[[Page 61859]]

report and will not provide any greater degree of safety or 
dependability. The commenter supported BSEE's efforts to work with 
industry to increase reliability of BSDVs and to promote the use of API 
standards, but noted that the agency does not recognize API Spec. 6D, 
``Specification for Pipeline Valves,'' or ANSI standards used in this 
service.
---------------------------------------------------------------------------

    \20\ The proposed rule cited a 1999 Southwest Research Institute 
report, ``Allowable Leakage Rates and Reliability of Safety and 
Pollution Prevention Equipment'' (Project # 272), funded by MMS in 
connection with proposed safety system testing. (See 78 FR 52250.) 
That report is available at https://www.bsee.gov/research-record/tap-272-allowable-leakage-rates-safety-and-pollution-prevention-equipment.
---------------------------------------------------------------------------

    Response--BSEE disagrees with the suggestion that certification 
provides no additional assurance that critical safety equipment will 
perform as designed. The referenced report was not the only factor 
considered when developing the proposed SPPE certification 
requirements. The existing regulations have required use of certified 
SPPE since April 1, 1998. In developing the new proposed and final 
certification requirements, BSEE considered the effectiveness of this 
longstanding requirement, as well as the existence of industry 
standards (such as ANSI/ASME SSPE-1 and API Spec. Q1) that support the 
requirement for certification to ensure the quality and effectiveness 
of this equipment. The only substantive addition to the final rule 
regarding SPPE certification requirements is that BSDVs will be 
considered SPPE that must be certified and otherwise conform to final 
Sec.  250.801. As stated elsewhere, BSEE considers the BSDV on subsea 
wells to be the equivalent of an SSV on a surface well and it is 
appropriate to include BSDVs as SPPE under Sec.  250.801.
    Moreover, under Sec.  250.804(a)(5) of the existing regulations, 
USVs were required to meet a zero leakage requirement and to be 
replaced or repaired if they failed to do so. However, since BSDVs will 
need to be certified (when required) under final Sec. Sec.  
250.801(a)(2) and 250.802(d), and to meet the zero leakage requirement 
under final Sec.  250.880(c)(4)(iii), USVs used in connection with 
BSDVs will no longer be required to do so.
    In any event, operators may continue to use existing non-certified 
SPPE already in service until it requires offsite repair, re-
manufacturing, or hot work, at which time the operator must replace the 
non-certified SPPE with SPPE that conforms to the requirements of final 
Sec.  250.801.
    Regarding the comment on certain standards that were not referenced 
in the proposed rule, BSEE continually works to review various 
standards for possible incorporation, including those from API, ANSI, 
and other standards development organizations. The standards referred 
to in this comment may be considered in future rulemakings. However, 
the fact that BSEE does not incorporate by reference a particular 
standard does not preclude an operator from voluntarily complying with 
that standard. BSEE presumes that industry follows its own standards, 
regardless of whether BSEE incorporates them in the regulations.
Expand SPPE Certification Requirements
    Comment--A commenter suggested that the proposed SPPE certification 
requirements be expanded to include all SPPE used for any production 
systems on the OCS where flammable petroleum gas or volatile liquids 
are produced, processed, compressed, stored, or transferred, and not be 
limited to the four types of valves listed in Sec.  250.801(a).
    Response--BSEE does not agree that the suggested expansion of the 
certification requirement is appropriate at this time. The particular 
SPPE identified in this section is specifically used for controlling 
the flow of fluids from the wellbore. The other equipment mentioned by 
the commenter is for processing the fluids, and that equipment has 
separate design, installation, and maintenance requirements under other 
subparts of part 250 (e.g., subpart J).
Approval of SPPE not Certified Under API Spec. Q1
    Comment--A commenter requested further information regarding the 
expected duration of BSEE review for SPPE equipment approval based on 
alternate quality assurance programs; the process by which BSEE will 
approve SPPE; and whether recertification will be required on a 
periodic basis.
    Response--The time required for BSEE to evaluate SPPE manufactured 
under other quality assurance programs depends on the type and quality 
of the information submitted. Under final Sec.  250.801(c), only SPPE 
manufactured under quality assurance programs other than ANSI/API Spec. 
Q1 would require approval from BSEE. BSEE will handle each evaluation 
on a case-by-case basis, but because this is expected to happen 
infrequently, this process will not create serious delays in approval 
of such equipment. Recertification of SPPE is not required; however, 
final Sec.  250.802(b) incorporates standards that require for regular 
testing of SPPE, and final Sec.  250.802(d) contains provisions 
addressing when the operator must replace existing equipment with 
certified SPPE.
Requirements for SPPE. (Sec.  250.802)
    Section summary--The final rule recodifies many of the provisions 
in existing Sec.  250.806(a)(3) as new Sec.  250.802(a) and (b). Those 
provisions establish requirements for the valves defined as SPPE in 
final Sec.  250.801, including requiring that all SSVs, BSDVs, USVs, 
SSSVs, and their actuators meet the specifications in certain API 
standards incorporated by reference in the final rule.
    Final Sec.  250.802(c) includes a summary of some of the 
requirements contained in the documents that are incorporated by 
reference in order to provide examples of those types of requirements. 
These requirements cover a range of activities affecting the SPPE over 
the entire lifecycle of the equipment and are intended to increase the 
reliability of the equipment through a lifecycle approach.
    Final Sec.  250.802(c)(1) also requires that each device be 
designed to function and to close in the most extreme conditions to 
which it may be exposed; this includes extreme temperature, pressure, 
flow rates, and environmental conditions. Under the final rule, the 
operator must have a qualified independent third-party review and 
certify that each device will function as designed under the conditions 
to which it may be exposed. Final Sec.  250.802(c) also describes 
particular SPPE specifications and testing requirements.
    BSEE has included a table in final Sec.  250.802(d) to clarify when 
operators must install SPPE equipment that conforms to the requirements 
of Sec.  250.801. Under the final rule, non-certified SPPE already in 
service can remain in service until the equipment requires offsite 
repair, re-manufacturing, or any hot work, in which case it must be 
replaced with SPPE that conforms to the requirements of Sec.  250.801.
    Final Sec.  250.802(e) requires operators to retain all 
documentation related to the manufacture, installation, testing, 
repair, redress, and performance of SPPE until 1 year after the date of 
decommissioning of the equipment.
    Regulatory text changes from the proposed rule--BSEE added 
actuators to the provisions in this section regarding SSVs, BSDVs, 
USVs, and SSSVs in order to be consistent with Sec.  250.801 and to 
emphasize that the actuators are an integral part of the valves; 
therefore, the same requirements will apply to both the valves and the 
actuators. BSEE also slightly revised the language in the table in 
final Sec.  250.802(d) to further clarify the circumstances under which 
certified SPPE must be used.
    Comments and responses--BSEE received public comments on this 
section and responds to the comments as follows:

[[Page 61860]]

Definition of Lifecycle Approach
    Comment--Commenters requested clarification of the meaning of 
``lifecycle approach.''
    Response--Although this term is not used in the regulatory text, 
the lifecycle approach involves vigilance throughout the entire 
lifespan of the SPPE, including design, manufacture, operational use, 
maintenance, and eventual decommissioning of the equipment. This 
approach considers ``cradle-to-grave'' issues for SPPE and is a tool to 
evaluate the operational use, maintenance, and repair of SPPE over its 
lifetime. Addressing the full lifecycle of critical equipment is 
essential to increasing the overall level of confidence that this 
equipment will perform as intended in emergency situations. As 
discussed earlier in part II.B, this concept is currently reflected in 
several industry standards for SPPE (e.g., API Spec. 6A), and 
incorporating that concept in the final rule will ensure that it is 
more consistently followed by operators.
    A major component of the lifecycle approach involves the proper 
documentation of the entire process, from manufacture through the end 
of the operational limits of the SPPE, which allows for continual 
improvement throughout the life of the equipment by evaluating 
mechanical integrity and improving communication between equipment 
operators and manufacturers.
Requirements for Valves
    Comment--A commenter stated that it is dangerous to open a large 
diameter valve with full differential pressure across the valve's gate 
and, thus, revisions should be made to the proposed language to allow 
an arrangement where a smaller valve, at full differential pressure, 
first opens to reduce the pressure across the larger valve.
    Response--BSEE does not agree that the suggested revision is 
necessary. BSEE does not expect the operator to open a large diameter 
valve with full differential pressure across the gate. Nothing in this 
section prohibits use of smaller diameter actuated valves in 
equalization lines, assuming that the smaller actuated valves can be 
isolated with a manual valve. This section provides the basic 
requirements for the functioning of the device, meaning that it has to 
close under the most extreme conditions to which it may be exposed, but 
does not specify precisely how that must be done.
Definition of Traceability
    Comment--A commenter requested clarification on the meaning of the 
``traceability'' requirement in proposed paragraph (c)(5).
    Response--Section 250.802(c)(5) requires operators to comply with 
and document all manufacturing, traceability, quality control, and 
inspection requirements for SPPE subject to subpart H, including the 
standards incorporated by reference in the regulations. Traceability 
refers to the ability to document the installation, maintenance, 
inspection and other significant events during the ``lifecycle'' of the 
particular piece of equipment as they relate to the equipment's proper 
functioning. This includes, for example, documenting the marking of the 
equipment received from the manufacturer, so the operator can 
accurately track each piece of SPPE during its useful life. The 
standards incorporated by reference in final Sec.  250.802(a) and (b) 
contain specific provisions on traceability.
Use of Independent Third-Parties
    Comment--A commenter suggested that independent third-parties may 
not have the expertise required to conduct the lifecycle analysis on 
SPPE that was called for in Sec.  250.802(c)(1) of the proposed rule. 
That commenter also suggested that limiting third-party certifiers to 
API-approved independent third parties would limit the pool of 
expertise, which would delay certification. Another commenter requested 
clarification as to the criteria for establishing whether a third-party 
reviewer has sufficient expertise and experience to perform the review 
and certification. That commenter also asked whether third-party 
reviewers will require periodic reevaluation.
    Response--Final Sec.  250.802(c)(1), as proposed, requires the 
independent third-party to have sufficient expertise and experience to 
perform the SPPE review and certification. Contrary to one commenter's 
assumption, however, Sec.  250.802(c)(1) does not limit the pool to 
API-approved independent third parties.\21\ Rather, that section makes 
operators responsible for ensuring that the third-party reviewers 
possess the appropriate experience and expertise. Operators currently 
have extensive experience in the use of independent third-party 
reviewers to comply with a number of existing regulatory requirements, 
and operators can use that experience to ensure that a third-party has 
the qualifications to perform its duties under Sec.  250.802(c)(1). 
Based on BSEE's experience monitoring compliance with existing third-
party requirements, BSEE believes that there is already a sufficient 
pool of qualified independent third-party reviewers for operators to 
choose from. Although BSEE does not need to approve third-party 
reviewers under this section, BSEE may consider the qualifications of 
independent third-party reviewers, on a case-by-case basis as the final 
rule is implemented and may, if appropriate, provide additional 
guidance in the future regarding third-party reviewer experience and 
expertise.
---------------------------------------------------------------------------

    \21\ The commenter may have confused the requirement in proposed 
paragraph (c)(3) that SPPE valves be tested by ``API-licensed test 
agencies'' with the third-party certification requirement in 
paragraph (c)(1). There is no such limitation in paragraph (c)(1) 
regarding third-party reviewers. Information from the tests 
performed by a licensed testing agency under paragraph (c)(3) may, 
of course, be used by an independent third party in reviewing and 
certifying SPPE under paragraph (c)(1), although additional 
documentation may also be necessary.
---------------------------------------------------------------------------

    Finally, Sec.  250.802(c)(1) does not require periodic revaluation 
of third-party reviewers; however, the operator will be responsible for 
ensuring that any third-party it employs possesses ``sufficient 
expertise and experience'' under Sec.  250.802(c)(1) whenever the 
third-party performs the reviews and certifications required by this 
section.
Verifying Lifecycle Analysis
    Comment--A commenter asserted that it is unclear from the proposed 
language how BSEE would verify lifecycle analysis without imposing an 
unwieldy document review process. The commenter suggested that third-
party certification is one way to conduct such verification and to 
ensure compliance with the rule without BSEE reviewing all of the 
documentation.
    Response--BSEE disagrees with the commenter's premise. Section 
250.802 of the final rule does not require that documents related to 
the lifecycle approach be submitted to or reviewed by BSEE. Paragraph 
(e) of that section requires only that all documents related to the 
manufacture, installation, testing, repair, redress, and performance of 
SPPE be retained until one year after the equipment is decommissioned. 
If BSEE identifies a need to review any specific documentation to 
verify that the lifecycle approach is being followed in a particular 
case, it can request that documentation.
Use of Existing Non-Certified SPPE
    Comment--A commenter noted that the proposed rule would allow non-
certified SPPE to remain in service. The commenter suggested that non-
certified SPPE should be replaced over a specified period of time and 
eventually

[[Page 61861]]

eliminated completely at offshore facilities.
    Response--BSEE does not believe that the commenter's suggested 
requirement is necessary. The regulation (existing Sec.  250.806(b)(2)) 
that is being revised and replaced by final Sec.  250.802(d) already 
required, as of April 1, 1998, that operators replace non-certified 
SPPE that needed offsite repair, re-manufacturing, or any hot work with 
certified SPPE. Thus, most existing SPPE is already certified under the 
existing regulation; this final rule essentially adds BSDVs and their 
actuators to that certification requirement (beginning September 7, 
2017). Moreover, final Sec.  250.802(d) also requires any remaining 
non-certified SPPE that needs offsite repair, remanufacturing or hot 
work to be replaced with certified SPPE. In addition, all SPPE must 
meet specific testing requirements pursuant to final Sec.  250.880. Any 
existing, non-certified SPPE that fails such tests and that is in need 
of offsite repairs, remanufacturing, or hot work, must be replaced with 
certified SPPE pursuant to final Sec.  250.802(d). Existing Sec.  
250.806(b)(2) also permitted installation, prior to April 1, 1998, and 
use of non-certified SPPE only if it was in the operator's inventory as 
of April 1, 1988, and was included in a list of noncertified SPPE 
submitted to BSEE prior to August 29, 1988. Thus, BSEE expects that 
non-certified SPPE will be replaced by certified SPPE over time without 
the need for the additional requirements suggested by the commenter.
Purpose of SPPE Requirements for BSDVs
    Comment--A commenter suggested that the proposed language of Sec.  
250.802(a) and (c) was inaccurate, internally inconsistent, and not in 
agreement with the overall intent of the proposed rule. Specifically, 
the commenter stated that, although BSDVs are included in paragraph 
(a), BSDVs are not specifically addressed in the referenced standards, 
and the rule should instead include a reference to API RP 14H for 
BSDVs. The commenter also asserted that the intent of the independent 
third-party language in proposed paragraph (c)(1) was to require no 
more than a simple certification and marking with the API monogram by 
the manufacturer, and that requiring an independent third-party to 
certify functionality of every individual item of equipment would not 
be achievable.
    Response--BSEE does not agree with the commenter's implied 
assertion that the inclusion of BSDVs in paragraph (a) is inconsistent 
with the language of that paragraph incorporating API Spec. 6AV1 and 
API/ANSI Spec. 6A. Although those standards do not expressly refer to 
BSDVs, their specifications apply to surface valves, which is a term 
broad enough to encompass BSDVs. In any event, if there is any conflict 
between any document incorporated by reference and the regulations, the 
regulations control; thus, the asserted intent of the developer of the 
standard does not constrain the terms of BSEE's regulations.
    Nor does BSEE agree that this section should reference API RP 14H 
for BSDVs, given that final Sec.  250.836 requires all new BSDVs and 
BSDVs that are removed from service for remanufacturing or repair to be 
installed, inspected, maintained, repaired, and tested in accordance 
with API RP 14H's requirements for SSVs. That standard is also 
referenced in Sec.  250.880(c)(4)(iii), which requires operators to 
test BSDVs according to API RP 14H's requirements for SSVs.
    BSEE also does not agree with the commenter's concerns regarding 
the independent third-party requirement in final Sec.  250.802(c)(1). 
The independent third-party does not guarantee permanent functionality 
of the SPPE, as implied by the commenter, but certifies that--at the 
time of certification--the equipment will function as designed under 
the conditions to which it may be exposed.
    Comment--Several commenters requested clarification on the 
requirement for independent third-party review and certification of 
SPPE equipment design under proposed Sec.  250.802(c)(1). Specifically, 
commenters asked whether BSEE will require approval of the use of a 
particular certified verification agent (CVA), and whether BSEE will 
accept wholesale certification by a single supplier of all equipment 
provided by that supplier.
    One commenter also requested clarification as to whether 
requalification testing performed following equipment design changes 
will be required, and whether requalification testing will apply only 
to the manufacturer that makes the design changes.
    One commenter recommended that, if BSEE keeps the certification 
requirement in the final rule, then BSEE should extend the 1-year 
timeframe in Sec.  250.801(a)(2) before BSDVs are considered to be SPPE 
to 2 years, thereby extending the compliance date for use of certified 
BSDVs to 2 years after publication of the final rule. Commenters also 
expressed concern about the costs of replacing, repairing, or 
remanufacturing existing (non-certified) SPPE and maintaining 
documentation for SPPE equipment. In particular, commenters asserted 
that, where no isolation valve exists, installation or replacement of a 
safety valve would require excessive shutdown time and construction 
work on lines that have previously contained hydrocarbons. They also 
suggested that this result would greatly increase the risk of a serious 
incident from arbitrarily replacing a non-certified valve that cannot 
be shown to be inferior to a certified valve.
    Response--With regard to the comment on CVAs, BSEE does not intend 
at this time to limit the pool of independent third-party reviewers by 
approving or requiring particular certification agents. As stated in an 
earlier response, if warranted, BSEE can review the qualifications of 
any independent third-party reviewer and may provide additional 
guidance in the future, if appropriate, regarding third-party 
certifiers' experience, expertise and independence.
    With regard to requalification testing of SPPE, proposed and final 
Sec.  250.802(c)(4) expressly state that, if there are manufacturer 
design changes to a specific piece of equipment, requalification 
testing is required. With regard to whether the proposed 
requalification testing requirement applies only to the manufacturer 
that makes a design change, the answer is ``no.'' When read in 
conjunction with final Sec.  250.802(c)(3), paragraph (c)(4) requires 
that requalification testing be performed by an API-licensed test 
agency. Final paragraph (c)(4) specifies, as proposed, that the 
operator (i.e., ``you''), not the manufacturer, is responsible for 
having requalification testing performed.
    BSEE disagrees with the request to extend the timeframe for BSDVs 
to meet the SPPE requirements, including the certification requirement. 
The 1-year timeframe for BSDVs to be considered SPPE is sufficient, 
especially since paragraph (d)(3) of this section provides that non-
certified SPPE (which will include BSDVs 1 year after publication of 
the final rule) that is already in service need not be replaced with 
certified SPPE until it requires offsite repair, re-manufacturing, or 
any hot work.
Most Extreme Conditions
    Comment--A commenter requested clarification as to the meaning of 
``most extreme conditions'' to which each SPPE device may be exposed 
and who has the authority to define the term. The

[[Page 61862]]

commenter recommended that the operator should be responsible for 
establishing what ``most extreme credible conditions'' means, but that 
the operator's assumptions should also be subject to validation by the 
independent third party. The commenter also requested clarification as 
to how independent third parties should be selected and the timing and 
triggering requirements for SPPE device certifications.
    Response--The operator is responsible for determination and 
application of the specific wellbore conditions. As with other aspects 
of operations, the operator is responsible for making reasonable 
assumptions and must document and explain those assumptions through the 
application process. An operator is not responsible for ensuring that 
SPPE is designed to function at conditions that are not reasonably 
anticipated during production operations. Conversely, an operator is 
responsible for ensuring that its proposed SPPE is designed to function 
properly in the conditions that a qualified and prudent OCS operator 
should reasonably expect to encounter during the production operation.
    For the independent third-party, BSEE will not approve or select 
appropriate parties. However, BSEE may review the qualifications and 
expertise of an independent third-party if there is an issue concerning 
an independent third-party's certifications. Operators must have SPPE 
certified on a per well basis, because each well will have different 
operating and environmental conditions.
Costs
    Comment--BSEE received multiple comments on the costs associated 
with industry standards incorporated by reference, and notations that 
the economic analysis fails to identify those costs. These comments 
included questions on the economic analysis baseline; whether the 
economic analysis accurately portrays the 1988 final rule and agency 
regulations; discussion of the costs of new requirements in API 570 for 
piping system inspection; and the allegation that the agency did not 
include or analyze the costs associated with proposed Sec. Sec.  
250.800(b), 250.802(b), and 250.841(b).
    Response--BSEE included the costs associated with following 
industry standards as part of the baseline of the economic analysis. 
Per OMB Circular A-4, which provides guidance to Federal agencies on 
the preparation of the economic analysis, the baseline represents the 
agency's best assessment of what the world would be like absent the 
action. The 1988 final rule is the starting point, and that rule 
contained a majority of the provisions that are currently found in the 
regulations.
    The baseline should include all practices that reflect existing 
industry standards and regulations, and that would continue to do so 
even if the new regulations were never imposed. Industry standards 
represent generally accepted practices and expectations that are used 
by the offshore oil and gas industry in their day to day operations. 
Such standards are industry-developed documents that are written and 
utilized by industry experts. Thus, even without regulations requiring 
compliance with the standards, we understand and expect that industry 
follows these standards to ensure safety and reliability of operations. 
Therefore, BSEE includes the benefits and costs of utilizing these 
standards (including API 570) in the economic baseline. This is 
consistent not only with the guidance provided by OMB Circular A-4, but 
also with commonly accepted methods within the economic profession and 
BSEE's approach in previous rulemakings.
    The existing subpart H regulations already require compliance with 
API RP 14J for all new FPSs. Accordingly, costs associated with such 
compliance are not attributable to this rule. In addition, compliance 
with API RP 14J is already required in subpart I (Sec.  250.901(a)(14)) 
for all platforms. Subpart S also requires hazard analysis under Sec.  
250.1911. Although API RP 14J is not specified in Sec.  250.1911, it is 
an appropriate document to use for compliance with that section in the 
context of production safety systems. The requirement for hazard 
analysis is not new; BSEE is only specifying which document to use for 
certain situations. By following API RP 14J, as incorporated in subpart 
H, the operator is also complying with the hazard analysis requirement 
in subpart S (the SEMS regulations) for the relevant systems.
    Final Sec.  250.802(b) is based on industry standards (ANSI/API 
Spec. 14A, Specification for Subsurface Safety Valve Equipment and 
ANSI/API RP 14B, Recommended Practice for Design, Installation, and 
Operation of Subsurface Safety Valve Systems). API RP 14C and RP 14E 
are already incorporated in the existing BSEE subpart H regulations and 
are not new requirements.
What SPPE Failure Reporting Procedures Must I Follow? (Sec.  250.803)
    Section summary--Final Sec.  250.803 establishes SPPE failure 
reporting procedures. Section 250.803(a) requires operators to follow 
the failure reporting requirements contained in section 10.20.7.4 of 
API Spec. 6A for SSVs, BSDVs, and USVs, and to follow the requirements 
in section 7.10 of API Spec. 14A and Annex F of API RP 14B for SSSVs. 
It requires operators to provide a written notice of equipment failure 
to BSEE and the manufacturer of such equipment within 30 days after the 
discovery and identification of the failure. The final rule defines a 
failure as, ``any condition that prevents the equipment from meeting 
the functional specification.'' This is intended to ensure that design 
defects are identified and corrected and that equipment is replaced 
before it fails.
    Final Sec.  250.803(b) requires operators to ensure that an 
investigation and a failure analysis are performed within 120 days of 
the failure to determine the cause of the failure and that the results 
and any corrective action are documented. If the investigation and 
analysis is performed by an entity other than the manufacturer, the 
final rule requires operators to ensure that the manufacturer and BSEE 
receive copies of the analysis report.
    Final Sec.  250.803(c) specifies that if an equipment manufacturer 
notifies an operator that it changed the design of the equipment that 
failed, or if the operator changes operating or repair procedures as a 
result of a failure, then the operator must, within 30 days of such 
changes, report the design change or modified procedures in writing to 
the Chief of BSEE's Office of Offshore Regulatory Programs or the 
Chief's designee.
    Final Sec.  250.803(d) provides the address to which reports 
required by this section to be submitted to BSEE must be sent.
    Regulatory text changes from the proposed rule--BSEE updated 
paragraph (a) by changing the required written documentation of 
equipment failure from a ``report'' to a ``notice,'' and adding BSEE as 
a recipient. In paragraph (b), BSEE increased the timeframe for 
investigation and failure analysis to 120 days and added a requirement 
to submit the analysis report to BSEE. The address for BSEE in proposed 
paragraph (c) for submission of reports to BSEE was moved to new 
paragraph (d) in the final rule, which also updates the address to 
reflect BSEE's current location in Sterling, VA. These changes were in 
response to comments received and will help ensure that BSEE is aware 
of equipment failures and corresponding investigations and failure 
analysis.
    Comments and responses--BSEE received public comments on this

[[Page 61863]]

section and responded to the comments as follows:
Timing of Failure Reporting
    Comment--One commenter recommended the submission of all failure 
reporting data to BSEE within 30 days, and that international failures 
should be included in the analysis. Another commenter suggested that 
SPPE failure reports be submitted to a third-party organization for 
review and analysis so that the third party could analyze the 
information in the failure reports and provide BSEE, operators and 
manufacturers with assimilated data that would help develop and improve 
SPPE reliability and SPPE operating best practices.
    Response--BSEE agrees with several of the issues raised by these 
comments and has revised this section in the final rule to require that 
the written notice of equipment failure, a copy of the analysis report, 
and a report of design changes or modified procedures be submitted to 
BSEE as well as to the manufacturer. Specifically, the notice of 
failure and report of design changes or modified procedures must be 
provided to the Chief of BSEE's Office of Offshore Regulatory Programs, 
or to the Chief's designee, and to the equipment manufacturer within 30 
days. However, BSEE does not agree that 30 days is a realistic 
timeframe for the completion of a thorough and meaningful investigation 
and failure analysis report. Once failure reporting is sufficiently 
established, BSEE may consider additional reporting requirements. BSEE 
does not require failure reporting from areas outside the U.S. OCS. 
BSEE may consider information that is available from operations in 
other countries, but since would be extremely difficult to ensure 
consistent reporting of information, at this time, it is unlikely that 
BSEE would consider it appropriate to consider such information in a 
formal analysis. In addition, as suggested by a commenter, BSEE may 
consider designating an appropriate third-party to receive the failure 
notifications and operators' investigation/analysis reports so that the 
third-party could analyze the information and provide aggregated data 
and statistical analyses to industry, BSEE, and the public.
    Comment--Commenters suggested that the proposed 60-day timeframe 
for investigation and failure analysis could be difficult for some 
manufacturers to meet given their workload. They suggested that there 
should be some leeway for instances where failure analyses have been 
requested or are in process, but will not be completed before the 60-
day deadline. The commenters also expressed concern that failure or 
design change reporting may lead BSEE to require all operators to 
replace a particular model of equipment based on isolated failures of 
the equipment.
    Response--The comment regarding possible difficulties with 
equipment manufacturers meeting the proposed deadline for failure 
investigation and analysis is misplaced; the operator is responsible 
for ensuring the investigation and failure analyses are performed, not 
the manufacturer. However, BSEE has increased the timeframe to perform 
the investigation and failure analysis in the final rule to 120 days to 
accommodate concerns regarding the operator's ability to meet the 
shorter proposed timeframe. When BSEE receives notification of a design 
change from the operator, BSEE will work with the operator on a case-
by-case basis to ensure that the appropriate actions are taken, 
including an assessment of whether any equipment changes are warranted 
by the reported failure(s).
Manufacturers and Failure Reporting
    Comment--One commenter stated that the requirement for failure 
reporting to and from SPPE manufacturers fails to address the reality 
that a manufacturer may go out of business or be acquired by another 
firm. The commenter asked what failure reporting procedures must be 
followed in the event an SPPE manufacturer is no longer in business or 
is acquired by a different company.
    Response--The failure reporting requirements only apply to active 
businesses. If a manufacturer is no longer in business, the operator 
may contact BSEE and we will work with the operator on a case-by-case 
basis. If a business is the subject of a merger or is acquired by 
another entity, the operator should perform the necessary reporting 
with the successor company.
Additional Requirements for Subsurface Safety Valves (SSSVs) and 
Related Equipment Installed in High Pressure High Temperature (HPHT) 
Environments (Sec.  250.804)
    Section summary--The final rule recodifies existing Sec.  250.807 
as final Sec.  250.804. BSEE did not propose any significant revisions 
to the existing requirements. This section addresses requirements for 
SSSVs used in HPHT environments. Paragraph (a) specifies the 
information that the operator must submit to demonstrate that the SSSVs 
and related equipment can perform in the HPHT environment. Paragraph 
(b) defines the HPHT environment. Paragraph (c) describes the related 
equipment that must meet these requirements.
    Regulatory text changes from the proposed rule--BSEE updated the 
section to correct minor formatting errors and changed the label on the 
pressure rating specified in paragraphs (b)(1) and (2) from pounds per 
square inch gauge (psig) to pounds per square inch absolute (psia), to 
be consistent with industry practices.
    Comments and responses--BSEE did not receive any comments on this 
section.
Hydrogen Sulfide (Sec.  250.805)
    Section summary--The final rule will move the requirements found at 
former Sec.  250.808 to final Sec.  250.805, and reword them for 
clarity. These provisions pertain to production operations in zones 
known to contain hydrogen sulfide (H2S) or zones where the 
presence of H2S is unknown. The final rule also adds a new 
section requiring that the operator receive approval through the DWOP 
process for production operations in HPHT environments containing 
H2S, or in HPHT environments where the presence of 
H2S is unknown.
    Regulatory text changes from the proposed rule--BSEE did not make 
any significant changes to this section.
    Comments and responses--BSEE received a public comment on this 
section; however, the comment did not include any relevant questions or 
suggested modifications to the rule.
Dry Tree Subsurface Safety Devices--General (Sec.  250.810)
    Section summary--The final rule recodifies the provisions in 
existing Sec.  250.801(a) as final Sec.  250.810 in the context of dry 
tree subsurface safety devices (final Sec.  250.825 accomplishes a 
similar recodification for wet trees) and restructures the section for 
clarity. This section establishes general requirements for subsurface 
safety devices used with dry trees. All tubing installations open to 
hydrocarbon-bearing zones must have safety devices that will shut off 
flow in an emergency situation. It includes a list of subsurface safety 
devices. The final rule also adds a requirement to install flow 
couplings above and below subsurface safety devices.
    Regulatory text changes from the proposed rule--In response to 
comments, BSEE revised this section to remove the designation of flow 
couplings as a safety device, but still requires the installation of 
flow couplings above and below the subsurface safety device. Flow 
couplings prevent wear and reduce the

[[Page 61864]]

effects of turbulence on SSSV performance and are considered to be an 
integral part of the tubing string. However, they must be installed, as 
provided for in API RP 14B, Recommended Practice for Design, 
Installation, Repair and Operation of Subsurface Safety Valve Systems, 
which is incorporated by reference in other provisions of this final 
rule (e.g., Sec. Sec.  250.802(b), 250.803(a), 250.814(d)) and existing 
BSEE regulations.
    Comments and responses--BSEE received public comments on this 
section and responds to the comments as follows:
Fail-Safe Valves
    Comment--A commenter suggested that BSEE should revise the rule 
language to clarify that surface-controlled SSSVs are fail-safe 
automatic valves, and these valves are installed at a fail-safe setting 
depth that allows for automatic closure under worst-case hydrostatic 
conditions.
    Response--No changes are necessary. The regulations require 
operators to follow API RP 14B, Recommended Practice for Design, 
Installation, Repair and Operation of Subsurface Safety Valve Systems. 
This standard is incorporated in existing subpart H regulations, as 
well as in this final rule. The provisions of API RP 14B are consistent 
with the commenter's suggestions. In addition, there are specific 
requirements for SSSVs throughout subpart H and specific testing 
requirements under Sec.  250.880.
Flow Couplings
    Comment--A commenter suggested removing language referencing flow 
couplings from all sections requiring certification of subsurface 
safety devices as flow couplings are not safety devices. The commenter 
also recommended that BSEE incorporate by reference API Spec. 14L, 
Specification for Lock Mandrels and Landing Nipples.
    Response--BSEE agrees with the commenter that flow couplings should 
not be considered a safety device. BSEE updated the section's 
introductory paragraph to clarify that flow couplings must be installed 
above and below the subsurface safety device and removed the reference 
to a flow coupling as part of the subsurface safety device. BSEE 
continually considers relevant standards for incorporation, but does 
not always decide to incorporate a specific standard into the 
regulations. In this case, the design of equipment that the document 
covers (lock mandrels and landing nipples) are addressed with tubing 
design in subparts E and F of the existing regulations. Flow couplings 
prevent wear and reduce the effects of turbulence on SSSV performance 
and are considered an integral part of the tubing string.
Specifications for SSSVs--Dry Trees (Sec.  250.811)
    Section summary--The final rule recodifies former Sec.  250.801(b) 
as Sec.  250.811 with respect to SSSVs used with dry trees. It also 
updates the internal cross-references to the new provisions of subpart 
H. This section establishes general requirements for all SSSVs, safety 
valve locks, and landing nipples, requiring this equipment to conform 
to the requirements in final Sec. Sec.  250.801 through 250.803.
    Regulatory text changes from the proposed rule--BSEE revised this 
section by removing flow couplings from the equipment regulated as part 
of the SSSVs. These changes were made based on comments received to 
clarify that flow couplings are not considered SPPE. BSEE also removed 
the reference to approval of alternate procedures or equipment under 
Sec.  250.141. That provision and its associated procedures are 
generally available with respect to operations under part 250, so it is 
unnecessary to specifically reference it here.
    Comments and responses--BSEE received public comments on this 
section and responds to the comments as follows:
Flow Couplings
    Comment--A commenter suggested that the language indicating that 
``flow couplings'' must conform to the SPPE requirements should be 
revised. The commenter noted that there are no API or industry 
standards for flow couplings as they are not safety devices, but rather 
a manufacturer specific item of equipment. The commenter also stated 
that flow couplings are not identified as SPPE in proposed Sec. Sec.  
250.801 through 250.803 and recommended removal of the reference to 
flow couplings.
    Response--BSEE agrees with the commenter that flow couplings should 
not be considered a safety device. However, they must be installed, as 
provided for in API RP 14B, Recommended Practice for Design, 
Installation, Repair and Operation of Subsurface Safety Valve Systems. 
This document is incorporated by reference in this rulemaking in final 
Sec.  250.802(b) and existing BSEE regulations. Flow couplings prevent 
wear and reduce the effects of turbulence on SSSV performance and are 
considered an integral part of the tubing string. BSEE revised this 
section to remove the reference to flow couplings and suggestion that 
they are a safety device.
Surface-Controlled SSSVs--Dry Trees (Sec.  250.812)
    Section summary--The final rule recodifies existing Sec.  
250.801(c) as final Sec.  250.812 for purposes of establishing 
requirements for surface-controlled SSSVs when using dry trees. A 
change from current regulations will require operators to receive BSEE 
approval for locating the surface controls for SSSVs at a remote 
location. Operators must request and receive BSEE approval to locate 
surface controls at a remote location in accordance with Sec.  250.141, 
regarding alternate procedures or equipment.
    Regulatory text changes from the proposed rule--BSEE did not make 
any changes to this section.
    Comments and responses--BSEE did not receive any comments on this 
section.
Subsurface-Controlled SSSVs (Sec.  250.813)
    Section summary--The final rule recodifies the requirements of 
existing Sec.  250.801(d)--regarding standards for obtaining approval 
of subsurface-controlled SSSVs--as final Sec.  250.813. It rewrites the 
existing provision using plain language and removes one previously 
recognized basis for using subsurface-controlled SSSVs.
    Regulatory text changes from the proposed rule--BSEE updated the 
section with minor formatting changes and replaced BSEE with District 
Manager to clarify where to direct a request for approval to equip a 
dry tree well with an SSSV that is controlled at the subsurface in lieu 
of an SSSV that is controlled at the surface.
    Comments and responses--BSEE received public comments on this 
section and responds to the comments as follows:
Require Surface-Controlled SSSVs
    Comment--A commenter recommended eliminating the portion of Sec.  
250.813 that allows operators to install a subsurface-controlled SSSV 
instead of pulling the well tubing and installing the preferred 
surface-controlled SSSV or, at a minimum, the commenter recommended 
revising the rule to set a time limit for installation of the preferred 
surface-controlled SSSV, rather than allowing the operator to produce 
the well indefinitely without making this change.
    Response--No changes to the regulation are needed. Requiring 
installation of an SSSV that is surface-controlled within a specific 
timeframe

[[Page 61865]]

may cause an increase in the number of wells that are prematurely 
abandoned, due to the costs involved with pulling and replacing tubing. 
This would raise concerns about conservation of resources. The rule 
requires installation of a surface-controlled SSSV if tubing is removed 
and reinstalled.
Design, Installation, and Operation of SSSVs--Dry Trees (Sec.  250.814)
    Section summary--The final rule recodifies existing Sec.  
250.801(e) as Sec.  250.814, perpetuating standards for the design, 
installation, and operation of SSSVs with dry trees. The final rule 
rewords the existing regulation for plain language and clarity. In 
final Sec.  250.814(b), BSEE incorporated the definition of routine 
operations from the definitions section at Sec.  250.601 and added a 
reference to Sec.  250.601 for more examples of routine operations.
    Regulatory text changes from the proposed rule--BSEE reversed the 
order of proposed paragraphs (b) and (c) for greater clarity as to how 
the requirements in those paragraphs complement each other. BSEE 
updated final paragraph (d) to include a reference to SSSV testing at 
Sec.  250.880. This change was based on comments suggesting that BSEE 
clarify that those testing requirements apply to SSSVs. BSEE also 
removed the reference to Sec. Sec.  250.141 and 250.142 from paragraph 
(a). Those provisions and their associated procedures are generally 
available with respect to operations under part 250, so it is 
unnecessary to specifically reference them here. The approval of 
alternate setting depth under final Sec.  250.814(a) will be considered 
on a case-by-case basis.
    Comments and responses--BSEE received public comments on this 
section and responds to the comments as follows:
SSSV Testing
    Comment--A commenter recommended that BSEE revise this section to 
include: A semi-annual SSSV testing interval in the proposed 
requirement at Sec.  250.880; a requirement that no leakage during 
valve testing be detected as evidenced by a stabilized, flat-line 
pressure response verifying that a well is completely shut-in and 
isolated; a requirement that an operator notify BSEE of valve testing 
such that it can send inspectors to observe testing; a requirement that 
the operator report valve failures to BSEE; and immediate shut-in of 
wells after a failed test or indication of a failed SSSV.
    Response--The regulatory testing requirements for SSSVs under Sec.  
250.880, in addition to the testing provisions in API RP 14B, are 
adequate. SSSVs are part of a closed system contained within the 
tubing. This system is designed to minimize oil spills by stopping the 
flow within the tubing in the event that the riser is damaged. BSEE 
revised this section to reference SSSV testing requirements in Sec.  
250.880, clarifying that those testing requirements apply to SSSVs. 
BSEE conducts regular inspections of facilities. During the 
inspections, a full review of all testing and maintenance records is 
usually conducted. BSEE can require the operator to test the SSSV and 
BSEE may witness the testing during routine inspections, however this 
authority does not need to be specified in Sec.  250.814.
Subsurface Safety Devices in Shut-In Wells--Dry Trees (Sec.  250.815)
    Section summary--The final rule recodifies existing Sec.  
250.801(f) as Sec.  250.815 for the context of dry trees, and rewrites 
it in plain language. This section provides operators with options on 
how to isolate a well, whether prior to initial production or after 
being shut-in for a period of 6 months. BSEE did not propose any 
substantive changes to the existing requirements for subsurface safety 
devices in shut-in wells using dry trees.
    Regulatory text changes from the proposed rule--BSEE did not make 
any significant changes to this section in the final rule.
    Comments and responses--BSEE received public comments on this 
section and responds to the comments as follows:
Alternate Setting Depths
    Comment--A commenter recommended revising proposed Sec. Sec.  
250.814 and 250.815 to specify the alternate setting depth requirements 
for wells installed in permafrost areas, or wells subject to unstable 
bottom conditions, hydrate formation, or paraffin problems.
    Response--Setting depth is based on site specific conditions. 
Specifying a single setting depth may not adequately ensure the 
integrity of the well under all applicable scenarios and environmental 
conditions. Final Sec. Sec.  250.814(a) and 250.815(b) allow the 
District Manager to address the particular circumstances presented in 
setting depths for wells in areas of permafrost, unstable bottom 
conditions, hydrate formation, or paraffin problems.
Subsurface Safety Devices in Injection Wells--Dry Trees (Sec.  250.816)
    Section summary--The final rule recodifies existing Sec.  
250.801(g) as final Sec.  250.816, and rewrites it in plain language. 
This section requires operators to install a surface-controlled SSSV or 
an injection valve capable of preventing backflow in all injection 
wells, unless the District Manager determines that the injection well 
is incapable of natural flow. BSEE did not propose any substantive 
changes to the existing requirements for subsurface safety devices in 
injection on dry tree wells.
    Regulatory text changes from the proposed rule--BSEE did not make 
any significant changes to this section in the final rule.
    Comments and responses--BSEE did not receive any comments on this 
section.
Temporary Removal of Subsurface Safety Devices for Routine Operations 
(Sec.  250.817)
    Section summary--The final rule recodifies existing Sec.  
250.801(h) as final Sec.  250.817, with the title of the section 
changed for clarity and the text rewritten for plain language. It 
addresses how operators must ensure safety if they temporarily remove 
certain subsurface safety devices to conduct routine operations, i.e., 
operations that do not require BSEE approval of a Form BSEE-0124, 
Application for Permit to Modify (APM). BSEE did not propose any 
substantive changes to the existing requirements for the temporary 
removal of subsurface safety devices for routine operations.
    Regulatory text changes from the proposed rule--In final Sec.  
250.817(c), BSEE added the term ``support vessel,'' as another option 
for attendance on a satellite structure.
    Comments and responses--BSEE received public comments on this 
section and responds to the comments as follows:
Support Vessel
    Comment--A commenter asserted that is not clear what purpose is 
served by the proposed requirement to have a support vessel in 
attendance if an SSSV is inoperable. The commenter suggested revising 
the language to remove the reference to support vessels.
    Response--No changes are necessary. For a well on a satellite 
structure, the support vessel is intended to give personnel an escape 
route in the event of an emergency. If a support vessel is not on site 
and SSSV is removed, the operator must install a pump-through plug.

[[Page 61866]]

Additional Safety Equipment--Dry Trees (Sec.  250.818)
    Section summary--The final rule recodifies existing Sec.  
250.801(i) as final Sec.  250.818, addressing additional safety 
equipment to be used with dry trees. The final rule rewrites the 
existing provision for plain language, with no significant revisions.
    Regulatory text changes from the proposed rule--BSEE did not make 
any significant changes to this section.
    Comments and responses--BSEE did not receive any comments on this 
section.
Specification for Surface Safety Valves (SSVs) (Sec.  250.819)
    Section summary--The final rule recodifies the portion of former 
Sec.  250.802(c) related to wellhead SSVs and their actuators as final 
Sec.  250.819. The final rule rewrites the provision for plain language 
and updates the cross-referenced provisions, but makes no substantive 
change. BSEE recodified the portion of existing Sec.  250.802(c) 
related to USVs as Sec.  250.833 in the final rule. This section 
requires all wellhead SSVs and their actuators to conform to the 
requirements specified in Sec. Sec.  250.801 through 250.803.
    Regulatory text changes from the proposed rule--BSEE did not make 
any significant changes to this section.
    Comments and responses--BSEE received public comments on this 
section and responds to the comments as follows:
Valve Testing Requirements
    Comment--A commenter recommended that BSEE include or incorporate 
by reference a separate section on valve testing requirements in this 
section. Existing regulations require SSVs for each well that uses a 
dry surface tree. The proposed regulations would require compliance 
with API RP 14H. API RP 14H provides for periodic valve testing at an 
unspecified frequency. The commenter supported the monthly testing 
requirement in Sec.  250.880 for this valve and asserted that such a 
critical valve used to isolate a well in the event of abnormal well 
conditions or an emergency should not leak at all. Additionally, the 
commenter recommended requiring the operator to notify BSEE immediately 
if a valve fails or does not pass a test and to shut in the well until 
the valve is repaired or replaced.
    Response--Section 250.819 in the final rule requires conformance 
with Sec.  250.803, which addresses failure reporting to BSEE for SSVs. 
BSEE may request additional failure data if necessary. To clarify the 
testing requirements for SSVs, BSEE revised the final rule in Sec.  
250.820 to reference Sec.  250.880. There is no need to repeat that 
reference here. The failure reporting requirements follow industry 
standards as required in final Sec.  250.803. Under final Sec.  
250.880(c)(2)(iv), operators must test SSVs monthly and if any gas and/
or liquid fluid flow is observed during the leakage test, the operator 
must immediately repair or replace the valve. API RP 14H allows for 
some leakage during this test, however, in the final rule, BSEE 
requires no gas and/or liquid flow during the leakage test. As 
previously stated, when there is a difference between the regulations 
and the incorporated standards, the operator must follow BSEE's 
regulations.
Use of SSVs (Sec.  250.820)
    Section summary--The final rule recodifies the portion of existing 
Sec.  250.802(d) related to the use of SSVs as Sec.  250.820. The final 
rule rewrites the provision for plain language and clarity, but makes 
no substantive change. This section requires operators to follow API RP 
14H for the installation, maintenance, inspection, repair, and testing 
of all SSVs and includes requirements if the SSV doesn't operate 
properly or if any gas and/or liquid fluid flow occurs during the 
leakage test. The portion of the existing Sec.  250.802(d) related to 
USVs is recodified as final Sec.  250.834.
    Regulatory text changes from the proposed rule--BSEE updated the 
section by adding ``gas and/or liquid'' to clarify the reference to 
fluid flow observed during the leakage test, and by adding a specific 
reference to such testing ``as described in Sec.  250.880.'' BSEE added 
this citation to emphasize that there are specific SSV testing 
requirements in Sec.  250.880.
    Comments and responses--BSEE received public comments on this 
section and responds to the comments as follows:
Testing References
    Comment--A commenter stated that the proposed rule did not refer to 
the testing requirements specified for SSVs as described in proposed 
Sec.  250.880. The commenter recommended that a reference to Sec.  
250.880 should be included in Sec.  250.820.
    Response--BSEE revised this section to include the recommended 
reference to Sec.  250.880.
Emergency Action and Safety System Shutdown--Dry Trees (Sec.  250.821)
    Section summary--The final rule recodifies existing Sec.  
250.801(j) as Sec.  250.821, addressing actions that must be taken in 
response to emergency situations. BSEE clarified the existing reference 
to storms as an example of an emergency by adding a reference to a 
National Weather Service-named tropical storm or hurricane because not 
all impending storms constitute emergencies. BSEE also added a 
requirement that operators shut-in oil wells and gas wells requiring 
compression in the event of an emergency. This final rule also 
incorporates the valve closure times for dry tree emergency shutdowns 
from existing Sec.  250.803(b)(4)(ii), with an added reference to 
Sec. Sec.  250.141 and 250.142 with respect to obtaining District 
Manager approval.
    Regulatory text changes from the proposed rule--BSEE edited 
paragraph (a)(2) to clarify the requirements and to define a shut-in 
well. The content was not otherwise revised but was rearranged. BSEE 
also removed the reference to Sec. Sec.  250.141 and 250.142 from 
paragraph (a)(2)(ii). Those provisions and their associated procedures 
are generally available with respect to operations under part 250, so 
it is unnecessary to reference them here. BSEE also removed the 
reference to the subsea field found in proposed paragraph (b).
    Comments and responses--BSEE received public comments on this 
section and responds to the comments as follows:
Emergency
    Comment--A commenter requested clarification as to what constitutes 
an ``emergency'' that will require oil wells and gas wells requiring 
compression to be shut-in.
    Response--There a number of different types of emergencies that 
could necessitate the shut-in of production. The example provided in 
this section is a specific named storm, and shut-in will be associated 
with the anticipated storm path. Any number of other emergency 
circumstances may likewise preclude the safe continuation of production 
and require shut-in pursuant to this provision. If there are any 
questions or concerns about whether a particular circumstance requires 
shut-in, the operator may contact the appropriate District Manager for 
guidance.
Storm Timers
    Comment--A commenter requested clarification that BSEE will not 
allow oil wells and gas wells requiring compression to flow on 
hurricane or storm timers, and that they must be shut-in before 
personnel evacuate.

[[Page 61867]]

    Response--No changes are necessary based on this comment. The 
regulations set specific requirements for valve closure timing based on 
the actuation of an ESD or the detection of abnormal conditions. The 
regulation does not allow operators to use timers to delay the valve 
closure. In addition, operators must include emergency response and 
control in their SEMS program under Sec.  250.1918; this should include 
evacuation and shut-in procedures.
Impending Named Tropical Storm or Hurricane
    Comment--A commenter requested clarification as to the meaning of 
``impending named tropical storm or hurricane'' and asks whether there 
will be some cases in which a storm or other meteorological event will 
not require shut-in.
    Response--The description of an impending named tropical storm is 
one example of an emergency situation when BSEE would require operators 
to shut-in their wells. In this example, the need for shut-in will be 
determined by the anticipated storm path and whether it threatens to 
impact the relevant production operations. The determination as to 
whether to shut-in a specific facility during a storm event is based on 
a number of factors, including the proximity of the facility to the 
storm path, the anticipated wind strength and waves heights, and the 
design of the facility. The operator must address emergency response 
and control in its SEMS program, under Sec.  250.1918; this should 
include the conditions for shut-in and evacuation.
Subsea Fields
    Comment--A commenter noted that the language in this section is 
specific to dry tree SSVs, but also noted that the proposed text 
mentions ``subsea fields.'' The commenter recommended deleting the 
reference to ``subsea fields.''
    Response--BSEE agrees with the comment, and removed ``or subsea 
field'' from paragraph (b) in the final rule.
Subsea Tree Subsurface Safety Devices--General (Sec.  250.825)
    Section summary--Final Sec.  250.825(a) was derived from existing 
regulations under Sec.  250.801(a) for subsurface safety devices on 
subsea trees. (Final Sec.  250.810 similarly recodifies the existing 
regulatory requirements for dry trees.) This section of the final rule 
restructures the existing requirements and revises them for greater 
clarity and to use plain language. The final rule adds a requirement to 
install flow couplings above and below the subsurface safety devices, 
and removes the exception for wells incapable of flow. The final rule 
also adds a requirement to test all valves and sensors after installing 
a subsea tree and before the rig or installation vessel leaves the 
area.
    Regulatory text changes from the proposed rule--BSEE revised final 
paragraph (a) to require the installation of flow couplings above and 
below the subsurface safety device and to remove the reference to a 
flow coupling that suggested it is part of the subsurface safety 
device. These changes were made based on comments received to clarify 
the use of flow couplings. BSEE also removed the reference to 
Sec. Sec.  250.141 and 250.142. Those provisions and their associated 
procedures are generally available with respect to operations under 
part 250, so it is unnecessary to specifically reference them here.
    Comments and responses--BSEE received public comments on this 
section and responds to the comments as follows:
Subsea Trees in the Arctic
    Comment--A commenter stated that it is unclear whether proposed 
Sec.  250.825 would prohibit subsea trees in Arctic operations due to 
the lack of a provision regarding setting depths in Arctic conditions. 
If allowed, the commenter recommended that BSEE specify in the 
regulation the allowable conditions and BSEE explain why the subsea 
trees would be BAST.
    Response--All proposed oil and gas production operations on the OCS 
are required to have production safety equipment that is designed, 
installed, operated, and tested specifically for the surrounding 
location and environmental conditions of operation prior to approval. 
Under Sec.  250.800(a), the final rule requires all oil and gas 
production safety equipment to be designed, installed, used, 
maintained, and tested to ensure the safety and protection of the 
human, marine, and coastal environments. BSEE understands that the 
Arctic may have unique operating conditions, however this rulemaking is 
not Arctic-specific. Although this final rule is intended to address 
production safety systems in all OCS regions, there are provisions that 
require the operator to address Arctic-related issues. For example, 
Sec.  250.800 of the final rule requires operators to use equipment and 
procedures that account for floating ice, icing, and other extreme 
environmental conditions for production safety systems operated in 
subfreezing climates. In addition, BSEE may address Arctic-specific 
issues through a variety of mechanisms including separate rulemakings, 
guidance documents, or on a case-by-case basis. As previously explained 
in response to comments on Sec.  250.107(c), BSEE is not making a BAST 
determination in this rulemaking, as a whole or for any specific 
provisions.
Departures
    Comment--A commenter recommended that the waiver (departure) 
provisions of Sec.  250.825(b) should be removed from the proposed rule 
as BSEE does not specify under what circumstances it would allow the 
installation of subsea tree valves and sensors without testing all the 
subsea tree valves and sensors. If BSEE does not agree to eliminate the 
waiver language from the proposed rule, the commenter requested that 
BSEE explain under what circumstances it would approve a subsea tree to 
be installed without testing all the subsea tree valves and sensors, 
and what criteria would be used in BSEE's decision making.
    Response--As discussed previously, BSEE has removed the proposed 
language referring to departure requests under Sec.  250.142 from the 
final rule. However, the operator may still submit a departure request 
related to the requirements of this section or any other requirement in 
the regulations. The provision for departure requests applies to any of 
the regulations under part 250, which does not need to be specified in 
individual sections.
Flow Couplings
    Comment--A commenter recommended that BSEE not require ``flow 
couplings'' to conform to SPPE requirements since they are not a safety 
device and there are accordingly no API or industry standards for flow 
couplings. The commenter also noted that flow couplings are not 
identified as SPPE in Sec. Sec.  250.801 through 250.803. The commenter 
asserted that flow couplings are not safety devices, but rather heavy-
walled couplings used in conjunction with some down-hole safety device 
applications.
    Response--BSEE agrees with the commenter that flow couplings should 
not be considered a safety device. However, they must be installed, as 
provided in API RP 14B, Recommended Practice for Design, Installation, 
Repair and Operation of Subsurface Safety Valve Systems. This document 
is incorporated by reference in this rulemaking and existing BSEE 
regulations. Flow couplings prevent wear and reduce the effects of 
turbulence on SSSV performance and are considered an integral part of 
the tubing string. BSEE revised this section

[[Page 61868]]

to remove the inclusion of flow couplings as a safety device, but added 
a requirement to install flow couplings above and below the subsurface 
safety device.
Valve Testing
    Comment--A commenter asserted that it is unclear whether proposed 
paragraph (b) requires the testing of all of the valves and sensors on 
the subsea tree, in addition to the SSSV, or only those valves that are 
designated as USVs, and the related pressure test sensors. The 
commenter noted that Sec.  250.880(c)(4) establishes that these valves 
must pass the applicable leakage test prior to departure of the rig or 
installation vessel.
    Response--Under this section the operator must test all of the 
valves and sensors associated with the subsurface safety devices before 
the rig or installation vessel leaves. If the valve was tested and 
passed after installation of the subsea tree, then that test is valid 
and the operator does not have to test again until required to conduct 
valve testing at regular intervals under Sec.  250.880.
Specifications for SSSVs--Subsea Trees (Sec.  250.826)
    Section summary--Final Sec.  250.826 recodifies provisions from 
existing Sec.  250.801(b) pertaining to surface-controlled SSSVs, 
safety valve locks, and landing nipples for subsea tree wells. Since 
BSEE does not allow subsurface-controlled SSSVs on wells with subsea 
trees, they are not covered by this provision. The final rule also 
updates the internal cross-references to the new provisions of subpart 
H.
    Regulatory text changes from the proposed rule--BSEE revised the 
section by removing ``flow couplings.'' This change was made based on 
comments received and to clarify that flow couplings are not SPPE.
    Comments and responses--BSEE received one comment on this section 
and responds to the comment as follows:
Flow Couplings
    Comment--A commenter asserted that ``flow couplings'' need not 
conform to the SPPE requirements since there are no API or industry 
standards for flow couplings and they are not a safety device. The 
commenter also noted that flow couplings are not identified as SPPE in 
Sec. Sec.  250.801 through 250.803.
    Response--BSEE agrees with the comment that flow couplings should 
not be considered a safety device and revised this section to remove 
the inclusion of flow couplings as a safety device. However, they must 
be installed, as provided for in API RP 14B, Recommended Practice for 
Design, Installation, Repair and Operation of Subsurface Safety Valve 
Systems. This document is incorporated by reference in this rulemaking 
in final Sec.  250.802(b) and existing BSEE regulations. Flow couplings 
prevent wear and reduce the effects of turbulence on SSSV performance 
and are considered an integral part of the tubing string.
Surface-controlled SSSVs--Subsea Trees (Sec.  250.827)
    Section summary--This section was derived from provisions in 
existing Sec.  250.801(c), and rewritten for clarity and plain language 
to address requirements for surface-controlled SSSVs for wells with 
subsea trees. It requires operators to equip all tubing installations 
open to a hydrocarbon-bearing zone that is capable of natural flow with 
a surface-controlled SSSV. The final regulations require that surface 
controls for SSSVs for wells with subsea trees be located on the host 
facility.
    Regulatory text changes from the proposed rule--BSEE revised this 
section for plain language and to clarify that operators must locate 
the surface controls for SSSVs associated with subsea tree wells on the 
host facility instead of on the site or at a remote location.
    Comments and responses--BSEE received one comment on this section 
and responds to the comment as follows:
    Comment--A commenter stated that it is not clear how to interpret 
the proposed ``on site'' requirement with respect to surface controls 
for subsea wells.
    Response--BSEE agrees that the proposed language was potentially 
unclear and revised this section in the final rule to clarify that the 
surface controls must be located on the host facility.
Design, Installation, and Operation of SSSVs--Subsea Trees (Sec.  
250.828)
    Section summary--The final rule recodifies the provisions found at 
existing Sec.  250.801(e) as final Sec.  250.828, with changes made for 
clarity and plain language and to reflect that this section covers 
subsea tree installations. This section requires operators to design, 
install, and operate SSSVs to ensure reliable operation and establishes 
that a well with a subsea tree must not be open to flow while an SSSV 
is inoperable.
    Regulatory text changes from the proposed rule--The final rule 
changed the language in proposed paragraph (a)--regarding alternate 
setting depths--from referring to requests for use of alternate 
procedures under existing Sec.  250.141 to refer instead to approval of 
alternate depths by the District Manager on a case-by-case basis. This 
revision better aligns this section with final Sec.  250.814(a) and 
with the language in the existing regulation.
    BSEE also revised final paragraph (b) to clarify that the well must 
not be open to flow while an SSSV is inoperable, unless specifically 
approved by the District Manager in an APM. The final rule also revised 
paragraph (c) by adding a reference to Sec.  250.880 for additional 
SSSV installation, maintenance, repair, and testing requirements.
    Comments and responses--BSEE received public comments on this 
section and responds to the comments as follows:
Inoperable SSSVs
    Comment--A commenter recommended that BSEE include language 
requiring operators to shut-in a well if an SSSV is inoperable as well 
as language eliminating the possibility of an exception to this 
requirement.
    Response--BSEE does not agree with the suggestion that it should 
never allow exceptions to this shut-in provision. There may be times 
where an exception to this provision is warranted and appropriate. 
However, the operator must request an exception from BSEE in an APM, 
provide justification for that exception, and secure BSEE approval.
Temporary Flow During Routine Operations
    Comment--A commenter suggested that BSEE should add language to 
this section that allows for temporary flow during routine operations 
and well troubleshooting. The commenter recommended revising proposed 
paragraph (b) to read, ``The well must not be open to flow while an 
SSSV is inoperable once the subsea tree is installed or BSEE has 
approved the specific operation that requires flow with an inoperable 
SSSV.''
    Response--No changes are necessary. BSEE does not consider flowback 
of a subsea well through production equipment that has not been 
approved by BSEE to be a routine operation. Existing Sec.  250.605 
statesthat the operator cannot commence any subsea well-workover 
operations, including routine operations, without written approval from 
the District Manager. Temporary flowback of a subsea well may involve 
the use of non-dedicated production equipment, or production

[[Page 61869]]

equipment installed on a drilling rig, neither of which is part of the 
normal production flow path for the well. However, final Sec.  
250.828(b) provides that the operator must request an exception from 
BSEE in an APM and secure BSEE approval.
Measuring Leakage in a Subsea Well
    Comment--A commenter asserted that the formula provided in this 
section cannot be used for any well other than a dry gas well and that 
there is no method to measure the leakage in a subsea well. The 
commenter stated that subsea well leakage must be calculated and may 
vary with tree configuration or tree (USV) valve leakage or failure.
    Response--BSEE does not agree that the formulas required by this 
section, through incorporation of API RP 14B, are inappropriate for 
subsea wells. API RP 14B describes the required testing procedures, 
including any formulas that are needed for calculating leakage rates. 
If the operator has additional questions about calculating a particular 
leakage rate, the operator can contact the appropriate District 
Manager.
SSSV Testing
    Comment--A commenter stated that there are multiple ways to test an 
SSSV in a subsea well, and that it is not necessarily the case that the 
test procedure will be as outlined in Annex E of API RP 14B. The 
commenter recommended modifying the proposed language to indicate that 
there are acceptable alternative test methods. The commenter also 
stated that the proposed rule does not directly refer to the testing 
requirements specified for subsurface safety equipment as described in 
Sec.  250.880 and suggested adding a reference in final Sec.  
250.828(c) to Sec.  250.880.
    Response--BSEE agrees with the suggestion to add a reference to 
Sec.  250.880 for SSSV testing in final Sec.  250.828(c) and has done 
so. However, it is not necessary to add the suggested language 
regarding acceptable alternative methods, since an operator may submit 
a request to the District Manager to use an alternate test procedure 
under existing Sec.  250.141.
Subsurface Safety Devices in Shut-in Wells--Subsea Trees (Sec.  
250.829)
    Section summary--This section recodifies the requirement under 
existing Sec.  250.801(f) for subsurface safety devices on shut-in 
subsea tree wells. Operators must equip new completions that are 
perforated but not placed on production, as well as completions shut-in 
for a period of 6 months, with a pump-through-type tubing plug, an 
injection valve capable of preventing backflow, or a surface-controlled 
SSSV, whenever the surface control has been rendered inoperative. The 
final rule also clarifies when a surface-controlled SSSV is considered 
inoperative. BSEE included this clarification because the hydraulic 
control pressure to an individual subsea well may not be able to be 
isolated due to the complexity of the hydraulic distribution of subsea 
fields.
    Regulatory text changes from the proposed rule--BSEE made minor 
revisions to this section in the final rule, such as removing ``BSEE'' 
from before ``District Manager.'' BSEE also slightly revised the final 
language to be more consistent with the language of final Sec.  
250.815, and removed an unnecessary cross-reference to Sec.  250.141.
    Comments and responses--BSEE received public comments on this 
section and responds to the comments as follows:
Maintaining, Inspecting, Repairing, and Testing SSSVs
    Comment--A commenter recommended revising the proposed language to 
require operators to maintain, inspect, repair, and test all SSSVs in 
accordance with the Deepwater Operations Plan (DWOP) or API RP 14B. The 
commenter also suggested removing proposed Sec.  250.829(a)(3)(ii) 
since the reference pressure sensor is normally internal to the subsea 
control module, used for housekeeping only, and it may not be available 
to the topside system.
    Response--The commenter's first concern is addressed in Sec.  
250.828(c) of the final rule, which requires compliance with the DWOP 
and API RP 14B. It is not necessary to restate those requirements here. 
With respect to the commenter's second concern, BSEE understands that 
there may be situations where another approach would be appropriate 
and, in such cases, the operator may request approval to use an 
alternate procedure under Sec.  250.141.
Subsurface Safety Devices in Injection Wells--Subsea Trees (Sec.  
250.830)
    Section summary--This section was derived from existing Sec.  
250.801(g), rewritten in plain language, and modified to require 
operators to install a surface-controlled SSSV or an injection valve 
capable of preventing backflow in all injection wells, unless the 
District Manager determines that the well is incapable of natural flow. 
The substance of final Sec.  250.830 for subsea tree wells is similar 
to the regulatory sections pertaining to final Sec.  250.816 for dry 
tree wells. BSEE also consolidated similar provisions from existing 
Sec.  250.801 to improve readability and understanding of the final 
rule.
    Regulatory text changes from the proposed rule--BSEE did not make 
any significant changes in the final rule to the proposed section.
    Comments and responses--BSEE did not receive any comments on this 
section.
Alteration or Disconnection of Subsea Pipeline or Umbilical (Sec.  
250.831)
    Section summary--This new section codifies policy and guidance from 
existing BSEE Gulf Of Mexico Region NTL No. 2009-G36, ``Using Alternate 
Compliance in Safety Systems for Subsea Production Operations.'' BSEE 
intends to rescind this NTL and remove it from the BSEE Web page after 
the effective date of the final rule. The final rule states that, if a 
necessary alteration or disconnection of the pipeline or umbilical of 
any subsea well would affect an operator's ability to monitor casing 
pressure or to test any subsea valves or equipment, the operator must 
contact the appropriate District Office at least 48 hours in advance 
and submit a repair or replacement plan to conduct the required 
monitoring and testing.
    Regulatory text changes from the proposed rule--This section was 
revised by removing the word ``BSEE'' before ``District Office'' for 
consistency with other sections of the final rule and because it was 
superfluous.
    Comments and responses--BSEE received public comments on this 
section and responds to the comments as follows:
Pipelines
    Comment--A commenter stated that this section is unnecessary 
because the process to repair or modify a subsea pipeline must be 
approved by BSEE's GOM Regional Pipeline Section.
    Response--BSEE disagrees with the comment. Without an umbilical, 
the operator is unable to monitor casing pressure and test USVs. The 
existing pipeline regulations (subpart J) do not address the issues 
related to testing of the valves or the monitoring of casing pressure 
that are relevant and necessary to this rulemaking under subpart H. The 
operator needs to test these valves for functionality and leakage rate, 
and be able to monitor for sustained casing pressure. The physical 
alteration or disconnection of the subsea flowline system, including 
the umbilical, may require submission of a pipeline permit application 
to the Regional Supervisor. However, those actions address different 
considerations than are addressed by this section.

[[Page 61870]]

System Alterations
    Comment--A commenter suggested removing the proposed prohibition 
against altering or disconnecting the pipeline or umbilical until a 
repair or replacement plan is approved. The commenter also asserted 
that this proposed requirement would affect subsea operations and 
impose new reporting and review requirements on industry.
    Response--BSEE does not agree that the suggested changes are 
necessary. BSEE reviews and approves system alterations to ensure 
compliance with other regulations. Without an umbilical, the operator 
is unable to monitor casing pressure and test USVs as required under 
existing Sec.  250.520; thus, BSEE must have an operator's plans for 
maintaining compliance with this requirement before the operator 
disconnects. If the operator's proposed operation of disconnecting/
removing flowline/umbilical would cause the operator to be unable to 
perform required testing on the subsea well, then the District Manager 
must be involved.
Additional Safety Equipment--Subsea Trees (Sec.  250.832)
    Section summary--This section of the final rule was derived from 
existing Sec.  250.801(i), rewritten for greater clarity and to use 
plain language, and modified to reflect that this section covers subsea 
tree installations. It requires operators to equip all tubing 
installations that have a wireline- or pump down-retrievable subsurface 
safety device with a landing nipple, flow couplings, or other 
protective equipment above and below the SSSV in order to provide for 
the setting of the SSSV. The last sentence of existing Sec.  
250.801(i), generally requiring closure of surface-controlled SSSVs in 
certain circumstances, is no longer needed for wells with subsea trees, 
because this final rule establishes more specific surface-controlled 
SSSV closure requirements in final Sec. Sec.  250.838 and 250.839.
    Regulatory text changes from the proposed rule--BSEE made only 
minor changes to the proposed language in order to be more consistent 
with final Sec.  250.818 and existing regulations.
    Comments and responses--BSEE did not receive any public comments on 
this section.
Specification for Underwater Safety Valves (USVs) (Sec.  250.833)
    Section summary--Final Sec.  250.833 derives in part from existing 
Sec.  250.802(c), rewritten for greater clarity and use of plain 
language, with references to SSVs in the existing regulation deleted in 
order to differentiate the requirements for the use of dry trees and 
subsea trees. The portions of the existing rule concerning SSVs for dry 
trees are codified in final Sec.  250.819. This section now requires 
all USVs, and their actuators, to conform to the requirements specified 
in Sec. Sec.  250.801 through 250.803. Final Sec.  250.833 also 
clarifies the designations of the primary USV (USV1) and the secondary 
USV (USV2), and clarifies that an alternate isolation valve (AIV) may 
qualify as a USV. Final Sec.  250.833(a) requires that operators 
install at least one USV on a subsea tree and designate it as the 
primary USV, and that the operator inform BSEE if the primary USV 
designation changes. Final Sec.  250.833(a) also provides that the 
primary USV must be located upstream of the choke valve.
    Regulatory text changes from the proposed rule--BSEE updated the 
proposed section to include references to API Spec. 6A and API Spec. 
6AV1. In final paragraph (b), ``BSEE'' was removed before ``District 
Office'' for consistency and because it was unnecessary.
    Comments and responses--BSEE received public comments on this 
section and responds to the comments as follows:
Alternate Isolation Valves
    Comment--A commenter recommended that BSEE define the term 
``Alternate Isolation Valve (AIV),'' as it is not a term generally used 
in the industry or defined in any of the relevant standards, such as 
API Spec. 6A or API Spec. 17D. The commenter stated that the BSEE 
regulations need to fully define the term in the regulations so that it 
is clear which valves the operator must describe.
    Response--An AIV is any valve, in addition to the primary and 
secondary USVs, that acts as the USV. There are multiple names for an 
AIV, including ``flowline isolation valve.'' This term was used to 
emphasize that any valve in the subsea system that may act as a USV 
must meet the same requirements as the primary and secondary USV. BSEE 
did not make any significant changes to the proposed regulation with 
respect to this issue so as not to artificially limit the scope of the 
term ``flowline isolation valve.''
Redundant USVs
    Comment--A commenter recommended revising the language of this 
proposed section to reflect that there are cases in which redundant 
USVs are installed. The commenter recommended revising the proposed 
language to require operators installing redundant USVs to designate 
one USV on a subsea tree as the primary USV and to install that valve 
upstream of the choke valve.
    Response--No changes are necessary. This provision in the proposed 
rule, as carried forward into the final rule, already addressed the 
situation in the manner described by the commenter. Final Sec.  
250.833(b) addresses the requirements for redundant USVs.
Use of USVs (Sec.  250.834)
    Section summary--Final Sec.  250.834, establishing basic 
requirements for the inspection, installation, maintenance, and testing 
of USVs, is derived from existing Sec.  250.802(d). BSEE revised the 
existing provision to provide greater clarity, to use more plain 
language, and to remove references to SSVs in order to separate the 
requirements applicable to dry trees from those applicable to subsea 
trees. This final section also adds language to expressly include USVs 
designated as primary or secondary as well as any AIV that acts as a 
USV, and to clarify that all USVs must be installed, maintained, 
inspected, repaired, and tested in accordance with applicable DWOPs.
    Regulatory text changes from the proposed rule--This section was 
revised to clarify that these requirements apply to any valve 
designated as the primary USV and to include a cross-reference to final 
Sec.  250.880 for additional USV testing requirements. The reference to 
Sec.  250.880 was added based on comments received and to clarify that 
USV testing requirements are also found in final Sec.  250.880.
    Comments and responses--BSEE received public comments on this 
section and responds as follows:
Primary and Secondary USVs
    Comment--A commenter recommended that the new regulation be 
consistent with the intent of the existing NTL No. 2009-G36, which 
requires only the primary USV (USV1) to pass the leak test criteria, 
given that secondary valves are not required by the regulations. The 
commenter asserted that testing secondary USVs to the same standard as 
the primary USV should not be required until a secondary USV becomes a 
primary USV. The commenter also recommended that BSEE include a 
reference to Sec.  250.880 in Sec.  250.834, as the proposed regulatory 
language did not directly refer to the testing requirements specified 
for USVs described in Sec.  250.880.
    Response--BSEE agrees with the commenter and has revised final 
Sec.  250.834 to require the operator to

[[Page 61871]]

install, maintain, inspect, repair, and test only the valve designated 
as the primary USV in accordance with this subpart, the applicable 
DWOP, and API RP 14H. BSEE also agrees with the commenter with respect 
to the reference to Sec.  250.880 and has added that reference in the 
final section.
Specification for All Boarding Shutdown Valves (BSDVs) Associated With 
Subsea Systems (Sec.  250.835)
    Section summary--Final Sec.  250.835 is a new section that 
establishes minimum design and other requirements for BSDVs and their 
actuators. This section sets out the requirements for use of a BSDV, 
which for subsea systems assumes the role of the SSV required for a 
traditional dry tree. The BSDV is intended to ensure the maximum level 
of safety for the production facility and the people aboard the 
facility. Because the BSDV is the most critical component of the subsea 
system, it is necessary to subject this valve to rigorous design and 
testing criteria.
    Regulatory text changes from the proposed rule--BSEE revised this 
section in the final rule by replacing the initial reference to 
``BSDVs'' with the phrase ``new BSDVs and any BSDVs removed from 
service for remanufacturing or repair.'' This was added to address the 
applicability of the new requirements for BSDVs by clarifying that the 
provision is only applicable to new BSDVs and those removed from 
service for remanufacturing or repair.
    Comments and responses--BSEE received public comments on this 
section and responds to the comments as follows:
BSDV Location
    Comment--A commenter requested clarification on the BSDV location 
requirement for floating facilities. Another commenter recommended 
using the current draft language from API 14C for BSDV location and 
allowing engineering discretion in determining the appropriate location 
with respect to FPSs. The commenter stated that the prescriptive 
language of the proposed rule would limit flexibility in the DWOP 
process and proposed alternate language regarding the BSDV's location.
    Response--No changes are necessary. The location of the BSDV was 
specified in the proposed rule, and is included in the final rule, to 
ensure the safety of the facility. Under Sec.  250.835(c), when the 
pipeline riser boards the facility, it must be equipped with a BSDV 
installed within 10 feet of the first point of access to that riser. 
Because the BSDV is crucial to the facility's safety, the final 
regulations (Sec. Sec.  250.836 and 250.880) seek to ensure its 
reliability by requiring more stringent testing (i.e., zero allowable 
leak-rate) than other valves. Similarly, because of the critical role 
of the BSDV, it is the first valve that must close in order to isolate 
production from the facility during an abnormal event or emergency. 
This provision decreases the possible exposure of the pipeline upstream 
of the BSDV to dropped objects, fire and other hazards. The shutdown 
valve needs to be as close as possible to where the pipeline riser 
boards the facility, so that the source of flow is shut-in before the 
area of damage, if there an emergency on the facility. The DWOP process 
is designed to allow for some flexibility in design, but the operator 
must comply with the regulations by demonstrating that its DWOP 
provides the same level of safety and environmental protection as 
provided by the regulations.
    Use of BSDVs (Sec.  250.836)
    Section summary--Final Sec.  250.836 establishes a new requirement 
that operators must install, inspect, maintain, repair and test all new 
BSDVs and BSDVs removed for repair or remanufacture according to the 
provisions of API RP 14H. This section also specifies what the operator 
must do if a BSDV does not operate properly or if fluid flow is 
observed during the leakage test.
    Regulatory text changes from the proposed rule--BSEE revised this 
section of the final rule for clarity and to align more closely with 
Sec.  250.820. Final Sec.  250.836 also clarifies that it is applicable 
to new BSDVs and to any BSDV removed from service for remanufacturing 
or repair. BSEE also added language in this section to clarify that 
operators must install and repair (as well as inspect, maintain, and 
test) BSDVs in accordance with API RP 14H, as incorporated in this 
section. This is also consistent with similar language used in final 
Sec. Sec.  250.820 and 250.834 for SSVs and USVs, respectively. BSEE 
also updated the section to refer expressly to the testing requirements 
of Sec.  250.880 and to state that if there is any gas fluid and/or 
liquid fluid flow observed during testing, operators must shut-in all 
sources to the BSDV and immediately repair or replace the valve. BSEE 
made these changes for consistency and clarity to ensure operators take 
proper actions in the specific situation.
    Comments and responses--BSEE received public comments on this 
section and responds to the comments as follows:
Repair or Replacement of Leaking BSDVs
    Comment--Commenters stated that the proposed requirement to repair 
or replace a leaking BSDV before resuming production is not consistent 
with the requirement to immediately repair or replace the valve, as 
stated in proposed Sec.  250.880(c)(4)(iii). Also, given the potential 
safety implications associated with a leaking BSDV, commenters 
recommended that a leaking BSDV should be required to be repaired or 
replaced before resuming production on any manned facility. The 
commenters recommended that the language be consistent with proposed 
Sec.  250.880(c)(4)(iii).
    Response--BSEE agrees with the comment that this provision should 
be consistent with Sec.  250.880(c)(4)(iii) and has revised the final 
rule to require that the operator immediately repair or replace a BSDV 
if it does not operate properly.
Emergency Action and Safety System Shutdown--Subsea Trees (Sec.  
250.837)
    Section summary--Final Sec.  250.837, regarding emergency actions 
and safety system shutdowns for subsea tree installations, replaces 
existing Sec.  250.801(j). It also addresses the use of a MODU or other 
type of workover vessel in an area with producing subsea wells. In 
addition, this section of the final rule adds new requirements to 
clarify allowances for valve closing sequences for subsea installations 
and specifies actions required for certain situations. Final Sec. Sec.  
250.837(c) and (d) describe a number of emergency situations requiring 
the operator to shut-in and to close the safety valves and, in certain 
situations, to bleed the hydraulic systems.
    Regulatory text changes from the proposed rule--Throughout this 
section, ``BSEE'' was removed from before ``District Manager'' for 
consistency and because it was superfluous. The final rule also 
incorporates several minor, non-substantive formatting and clarifying 
edits. BSEE revised paragraph (b)(2) to clarify that real-time 
communication must be established between the MODU or other type of 
workover vessel and the production facility control room. BSEE also 
replaced ``MODU'' with ``MODU or other type of workover vessel'' 
throughout paragraph (b). In addition, BSEE clarified that the driller 
or other authorized rig personnel must secure the well using the ESD 
station located near the driller's console. BSEE removed the phrase 
``on the host platform'' from paragraph (c)(3) because

[[Page 61872]]

it was superfluous in the context it was used. In addition, BSEE 
revised final paragraph (c)(5) by adding a reference to ``other 
workover vessel'' for consistency with paragraph (b)(2).
    Comments and responses--BSEE received public comments on this 
section and responds to the comments as follows:
Emergency Planning
    Comment--A commenter stated that no amount of detail in the 
regulations will address all concerns, and that rules cannot be revised 
or updated in a timely manner. The commenter suggested that BSEE hold 
operators accountable for emergency planning consistent with their 
management systems and the types of facilities they operate.
    Response--BSEE agrees that no amount of detail in the regulations 
will cover all concerns; however, that does not negate our obligation 
to continuously improve the regulations in order to protect personnel 
safety and the environment. BSEE included this provision to provide 
direction and clarity for operators with regard to certain reoccurring 
events. BSEE's existing regulations contain other provisions for 
emergency planning, including a requirement that operators address 
emergency response and control in their SEMS plans under subpart S of 
this part (see Sec.  250.1918 for more information). These 
complementary provisions will work together to advance safety and 
environmental protection in OCS operations.
Geographic Impact of Storms
    Comment--A commenter suggested that the process for establishing 
the geographic impact of an emergency requiring shut-in for oil and 
compression gas wells is unclear.
    Response--The geographic impact of any given emergency will be 
highly dependent on the fact-specific nature of that emergency. As used 
in this section, tropical storms are just one example of an emergency; 
there may be other types of emergencies that require shut-in. In the 
event of a specific (e.g., a named) storm, any required shut-ins will 
be determined by the applicable storm path. This final rule will 
require the operator to shut-in all subsea wells in that path, not just 
oil and gas compression wells. If an operator has any questions or 
concerns about whether or when to shut-in, the operator may contact the 
appropriate District Manager for guidance.
Impending Named Tropical Storm or Hurricane
    Comment--Several commenters suggested that the term ``impending 
named tropical storm or hurricane'' needs to be better defined because 
some named storms would not necessarily require shutting in. Commenters 
stated that, if the term is meant only as an example of an emergency 
and is not meant to be all-inclusive, then the language and title of 
the proposed rule should be clarified or changed. The comment suggested 
regulatory language providing that BSEE would not need to require 
operators to shut-in some subsea wells (such as wells with a subsurface 
safety device) during a storm.
    Response--BSEE does not agree with the commenters' suggestions. 
Changing the title would potentially confuse the scope of this 
regulation since tropical storms and hurricanes are only examples of 
emergencies that could require shut-ins; other, non-storm emergencies 
could also require shut-ins. If an operator has any questions or 
concerns about whether or when to shut-in as a result of a specific 
storm or other emergency, the operator may contact the appropriate 
District Manager for guidance. BSEE also disagrees with the suggestion 
that wells with subsurface safety devices need not be shut-in during a 
storm when other wells are shut-in. In fact, all producing wells have 
subsurface safety devices of some kind, so the commenter's suggestion 
could result in no wells being shut-in during a storm. This would be 
contrary to longstanding and accepted safety practices.
Responsibilities for Wells
    Comment--A commenter stated that the proposed language presupposes 
that the company under whose direction a MODU or workover vessel is 
operating is the operator responsible for any wells that may be subject 
to suspension of production. The commenter asserted that such 
responsibility should only be placed with the lease operator, 
notwithstanding the proposed rule's apparent assignment of 
responsibility with the MODU operator. The commenter suggested that 
BSEE revise the proposed wording in order to place the burden on the 
operator of producing subsea wells to take action when a MODU or other 
type of workover vessel is in the area.
    Response--BSEE does not agree that the suggested changes are 
needed. This regulation is primarily directed at the lease operator. 
However, under Sec.  250.146(c), those persons actually performing an 
activity subject to part 250 are jointly and severally responsible for 
compliance with those requirements; this includes the lessee, the 
operator, and the person actually performing the activity. This would 
include a MODU operator if that MODU operator is performing activities 
subject to regulation under part 250. Thus, it is important that the 
relevant parties coordinate their activities, as well as their 
communication and control procedures, to ensure compliance with the 
applicable regulatory requirements.
Drilling
    Comment--A commenter asserted that the term ``driller'' as used in 
the proposed language is ambiguous and requires further clarification. 
The commenter stated that ``driller'' is not defined in the BSEE's 
regulations, is overly prescriptive, and is subject to multiple 
interpretations, including either the drilling contractor or the person 
serving in the position known as the ``driller'' on the MODU. The 
commenter suggested that the wording could also be interpreted as 
precluding an ``assistant driller,'' ``toolpusher,'' or others, from 
taking action to initiate the needed shutdown.
    Response--BSEE agrees with the commenter and has revised this 
section of the final rule to add ``(or other authorized rig floor 
personnel)'' after ``driller.''
ESD Location
    Comment--A commenter suggested that, for consistency with existing 
Sec. Sec.  250.406(a), 250.503, and 250.603, the reference to ``ESD on 
the well control panel located on the rig floor'' be changed to ``ESD 
station near the driller's console or well-servicing unit or operator's 
work station.'' The commenter noted the importance of communicating 
with others in order to shut-in other potentially affected wells, and 
stated that such information should be identified in the plan submitted 
to BSEE for approval in advance of operations. The commenter also noted 
that the proposed wording presupposes that only a single facility's 
wells could be affected and seemingly fails to place an obligation on 
that facility's operator (or the operator of any potentially affected 
wells on other facilities) to shut-in the wells under their control 
upon receiving notification from the MODU or workover vessel.
    Response--BSEE agrees with the commenter's suggestion regarding 
placement of the ESD station and has changed the text in final Sec.  
250.837(b)(2) to refer to the ESD station near the driller's console. 
For securing the other wells on the platform, the operator

[[Page 61873]]

needs to establish direct, real-time communication between the MODU or 
other workover vessel and the production facility. According to Sec.  
250.837(b)(2), operators must immediately secure the well directly 
under the MODU using the ESD station near the driller's console while 
simultaneously communicating with the platform to shut-in all affected 
wells.
MODU or Vessel
    Comment--A commenter recommended that wherever the term ``MODU'' 
appears in proposed Sec.  250.837, it should be replaced by the term 
``MODU or vessel.'' The commenter also stated that it is not clear that 
the requirement to shut-in all wells could be triggered by a dropped 
object in the event that communication is lost between the MODU or 
vessel and the platform for twenty minutes or longer. The commenter 
asserted that the shut-in needs to be implemented from the platform, 
and suggested that the shut-in requirement does not need to be applied 
to a well that is under the direct control of the MODU/vessel itself. 
The commenter also indicated that the requirement to shut-in should be 
reversed as soon as reliable communication is re-established between 
the MODU/vessel and the platform.
    Response--BSEE agrees with the commenter's suggestion for changing 
the references to ``MODU,'' and has replaced that term throughout this 
section with ``MODU or other type of workover vessel,'' as used in the 
introductory sentence in proposed paragraph (b). BSEE also agrees that 
the shut-in needs to be implemented from the facility; however, that 
fact does not support the commenter's suggestion that the shut-in 
requirements should not apply to a well under direct control of a MODU. 
(In fact, such a well should be shut-in already, since the MODU would 
be there to work on the well.) As stated in paragraph (b)(2), all wells 
that could be affected by the dropped object--whether under control of 
a MODU or other workover vessel or of a platform--must be shut-in to 
prevent a spill.
    With regard to the comment regarding reversal of a shut-in, BSEE 
agrees that a shut-in can be reversed once communication is restored 
and the District Manager approves resumption of operations.
What are the maximum allowable valve closure times and hydraulic 
bleeding requirements for an electro-hydraulic control system? (Sec.  
250.838)
    Section summary--Section 250.838 in the final rule establishes 
maximum allowable valve closure times and hydraulic system bleeding 
requirements for electro-hydraulic control systems. Final paragraph (b) 
applies to electro-hydraulic control systems when an operator has not 
lost communication with its rig or platform. Final paragraph (c) 
applies to electro-hydraulic control systems when an operator loses 
communication with its rig or platform. Each paragraph includes a table 
containing valve closure times and hydraulic system bleeding times for 
BSDVs, USVs, and surface-controlled SSSVs under various scenarios. BSEE 
derived the tables from Appendices to NTL No. 2009-G36. (Since this 
final rule codifies the provisions from NTL No. 2009-G36, BSEE plans to 
rescind the NTL and remove it from the BSEE Web page after the 
effective date of the final rule.)
    Regulatory text changes from the proposed rule--Paragraphs (b) and 
(d) were updated to reflect comments received, as discussed later, and 
to be consistent with the language of NTL No. 2009 G-36. In addition, 
throughout the section, ``BSEE'' was removed before ``District 
Manager'' and ``District Office'' for consistency and because it was 
superfluous.
    Comments and responses--BSEE received public comments on this 
section and responds to the comments as follows:
MODU or Vessel
    Comment--A commenter recommended that the word ``rig'' and the term 
``MODU'' be replaced by ``MODU/offshore support vessel'' throughout 
this section.
    Response--BSEE generally agrees with this comment and has replaced 
the terms ``rig'' and ``MODU'' with ``MODU or other type of workover 
vessel'' throughout this section of the final rule. This revision is 
also consistent with the terminology in final Sec.  250.839.
Closure and Bleed Requirements When Communication is Maintained
    Comment--A commenter asserted that proposed paragraph (b) was 
confusing in that it would require an operator that has not lost 
communication with its rig or platform to comply with the maximum 
allowable valve closure and hydraulic system bleed requirements listed 
in that paragraph's table. The commenter recommended revising the 
language to require compliance with the valve closure times and 
hydraulic bleed requirements listed in either the table or in an 
operator's approved DWOP, as long as communication is maintained.
    Response--BSEE agrees with the commenter's suggested language, 
which is consistent with BSEE's original intent. Accordingly, BSEE has 
revised paragraph (b) in the final rule to require that the operator 
must comply with the maximum allowable valve closure times and 
hydraulic system bleeding requirements listed in the table or the 
operator's approved DWOP, as long as communication is maintained.
Valve Closure Timing
    Comment--A commenter suggested revising the language in proposed 
Sec.  250.838(b)(2) (Pipeline pressure safety high and low (PSHL)) to 
provide the same requirements for bleeding both high pressure (HP) and 
low pressure (LP) hydraulic systems. The commenter also suggested 
adding language to proposed Sec.  250.838(b)(4) in order to prevent a 
surface-controlled SSV from closing on a flowing well, since the HP 
system will vent faster than the LP system.
    Another commenter suggested revising the language in proposed Sec.  
250.838(d)(2)--(Pipeline PSHL) to require a shut-down time that is 
determined by hydraulic analysis and confirmed during commissioning 
instead of using the times specified in that paragraph. The commenter 
asserted that it is difficult to close valves in 5 minutes on most 
deepwater, long step-out systems.
    In addition, the commenter suggested revising the proposed 
requirement in Sec.  250.838(d)(5) (Dropped Object--subsea ESD (MODU)) 
to ``initiate unrestricted bleed immediately'' upon communication loss 
for both LP and HP systems because that action would almost always 
result in the surface-controlled SSV closing on a flowing well. 
Specifically, the commenter requested that BSEE add language to this 
paragraph specifying that the LP hydraulic system must be vented and 
valves closed before the HP system is vented.
    A commenter asserted that the table of valve closure and hydraulic 
bleeding requirements in proposed paragraph (b) should be consistent 
with the table in NTL No. 2009-G36, which explains what to do in case 
an operator cannot meet valve closure times when it has a loss of 
communications. The commenter stated that the table in Sec.  250.838(d) 
requires immediate closure of tree valves upon Subsea ESD (MODU), and 
asserted that some control systems cannot meet that timing requirement, 
especially with regard to the LP system.
    Response--BSEE agrees with the suggestion to revise the table to be 
consistent with NTL No. 2009 G-36 and

[[Page 61874]]

has included those revisions in the final rule. BSEE disagrees, 
however, with the other changes to the tables in paragraphs (b) and (d) 
recommended by the commenters. The closure times in those tables are 
based on the best practices that are established at this time. These 
are reasonable, but conservative, limits that conform to the concept of 
having redundant and verified (i.e., tested) mechanical barriers in 
place in the event of an emergency or abnormal condition requiring 
isolation of hydrocarbon flow. If communication between the operator 
and the production facility, or the MODU or other type of workover 
vessel, is lost, the system must then operate the same as a direct 
hydraulic system. If the system cannot meet the shut-in timing 
requirements in the table when communication is lost, then the operator 
needs to shut-in the facility. For a host facility that is a 
significant distance from the subsea wells, it may take an unacceptable 
amount of time to bleed the hydraulic lines should an event occur 
requiring that the hydraulic system be bled. Because the operator needs 
to be able to shut-in the facility as soon as possible during that type 
of event, the system must be able to comply with the timing 
requirements of the regulation. Thus, BSEE does not agree that the 
closure times in the tables should be replaced with a requirement that 
closure times be determined by hydraulic analysis and confirmed during 
commissioning for specific facilities. However, specific subsea valve 
closure timing and hydraulic bleed capability for individual facilities 
may be submitted for review and potential approval by BSEE in a DWOP.
What are the maximum allowable valve closure times and hydraulic 
bleeding requirements for a direct-hydraulic control system? (Sec.  
250.839)
    Section summary--Final Sec.  250.839 establishes maximum allowable 
valve closure times and hydraulic system bleeding requirements for 
direct-hydraulic control systems. It contains a table of valve closure/
hydraulic bleed timing requirements comparable to those in final Sec.  
250.838(b).
    Regulatory text changes from the proposed rule--Throughout this 
section, ``BSEE'' was removed before ``District Manager'' for 
consistency and because it was superfluous. Paragraph (b) was updated 
to reflect comments received and to be consistent with the language of 
NTL No. 2009 G-36 and final Sec.  250.838.
    Comments and responses--BSEE received public comments on this 
section and responds to the comments as follows:
MODU or Vessel
    Comment--A commenter recommended that the term ``MODU'' be replaced 
by ``MODU/offshore support vessel'' throughout this section.
    Response--BSEE agrees and has changed the term ``MODU'' to ``MODU 
or other type of workover vessel'' in final paragraph (b)(5). This 
revision is also consistent with the terminology in final Sec. Sec.  
250.837 and 250.838.
Design, Installation, and Maintenance--General (Sec.  250.840)
    Section summary--The final rule includes the requirements 
previously found in existing Sec.  250.802(a). It establishes basic 
requirements for the design, installation, and maintenance of all 
production facilities and equipment. BSEE revised the existing language 
to improve clarity and to use plain language and added several new 
production components (e.g., pumps, heat exchangers) to this section 
that were not included in existing Sec.  250.802(a).
    Regulatory text changes from the proposed rule--BSEE did not make 
any significant changes to this proposed section in the final rule.
    Comments and responses--BSEE did not receive any comments on this 
section.
Platforms (Sec.  250.841)
    Section summary--The section includes the requirements previously 
found in existing Sec.  250.802(b). BSEE also added new requirements 
for facility process piping in final Sec.  250.841(b). The new 
paragraph requires adherence to existing industry standards (i.e., API 
RP 14E and API 570), which are incorporated by reference in final Sec.  
250.198. The final rule also specifies that the District Manager may 
approve temporary repairs to facility piping on a case-by-case basis 
for a period not to exceed 30 days.
    Regulatory text changes from the proposed rule--BSEE did not make 
any significant changes to this section in the final rule.
    Comments and responses--BSEE received public comments on this 
section and responds to the comments as follows:
Crewing for Arctic Facilities
    Comment--A commenter stated that the OCS Platform requirements in 
the proposed section did not specify any manning requirements and 
asserted that the regulations should include specific manning 
requirements for Arctic OCS facilities and should prohibit unmanned 
facilities.
    Response--Appropriate crewing is a facility--and operation-specific 
issue. As previously stated in part IV.B.3, BSEE understands that the 
Arctic OCS presents unique operating conditions and other challenges. 
BSEE recently addressed exploratory drilling requirements for the 
Arctic OCS in a final rule published on July 15, 2016 (81 FR 46477), 
and BSEE may address other Arctic-specific issues in future 
rulemakings, guidance documents, or on a case-by-case basis.
Piping Repairs
    Comment--A commenter asserted that limiting the duration of 
temporary piping repairs to 30 days could be problematic since a 
significant fabrication or construction backlog could hinder final 
repairs. The commenter also stated that weather and logistics will play 
a key role when the permanent repair is actually being conducted; thus, 
it may take more than 30 days to complete the permanent repair. The 
commenter suggested adding language to this provision to allow the 
District Manager to approve extensions to the duration of a temporary 
repair in 30-day increments. Another commenter requested clarification 
on whether the 30-day limit on approvals of the duration of temporary 
repairs to facility piping is only for piping in hydrocarbon service or 
for all facility piping.
    Response--BSEE does not agree that the suggested changes are 
appropriate. BSEE considers pressures, type of systems, and other 
factors in considering requests for approval of temporary repairs to 
piping. The longer the temporary repair is in place, the greater the 
risk that the repair will fail, given that the temporary repair 
material is generally not designed for long-term use in accordance with 
industry standards for permanent piping (e.g., API RP 14E, API 570). 
Moreover, the temporary repair materials are often not fire-rated, 
which also increases risks. Based on BSEE's experience, 30 days is 
typically enough time to make permanent repairs. If there are concerns 
about the length of the 30-day period for temporary repairs, the 
operator should contact the appropriate District Manager. The time 
limit on approval of temporary repairs applies to all facility piping, 
not just piping in hydrocarbon service.
Platform Definition
    Comment--A commenter stated that although this proposed section 
would require compliance with specific standards for OCS platforms, the 
term

[[Page 61875]]

``platform'' is not defined in the regulations. The commenter requested 
that a definition of ``platform'' be added to the final regulations. 
The commenter added that, in the Arctic, OCS facilities are currently 
built on gravel islands and may be installed on bottom-founded offshore 
structures in the future. The commenter suggested that the final 
regulations should clarify whether Sec.  250.841 will apply to Arctic 
OCS operations conducted on gravel islands or bottom-founded offshore 
structures, or whether an additional Arctic-specific section will be 
added to address these facility types.
    Response--As previously explained, BSEE understands that the Arctic 
presents some unique situations, and BSEE may address Arctic-specific 
issues in future rulemakings, guidance documents, or on a case-by-case 
basis. In the meantime, adding a definition of ``platform,'' 
particularly one addressing Arctic-specific circumstances, is beyond 
the scope of this rulemaking. However, when BSEE reviews a permit, it 
considers the specific operating and environmental conditions. Gravel 
islands are different from platforms in several ways, and may need to 
meet different requirements or permit conditions. If there are any 
questions concerning the applicability of this final rule to gravel 
islands, the operator should contact the appropriate District Manager 
for evaluation on a case-by-case basis. (For activities on the Arctic 
OCS, any reference in this part to District Manager means the BSEE 
Regional Supervisor for the Alaska region.)
API 570
    Comment--One commenter stated that this section should not refer to 
API 570 because that standard was developed for downstream operations, 
not offshore oil and gas upstream operations. Thus, the commenter 
asserted that there would be many potential conflicts if that document 
were applied to offshore operations as proposed. The commenter 
recommended that, before the document is incorporated in its entirety, 
BSEE review the document and determine what sections are applicable to 
offshore production operations.
    Response--BSEE disagrees with the comment. API 570 is the industry 
standard for piping. Although API 570 was developed primarily for the 
petroleum refining and chemical process industries, it states that it 
may be used for any piping system. Moreover, the commenter did not 
assert any specific conflicts related to using API 570 for offshore 
production operations. In fact, this document is extensively cited and 
widely used by the offshore oil and gas industry, especially with 
respect to inspection of piping (e.g., inspection methods, inspection 
frequency, non-destructive testing, and corrosion rates for determining 
the life expectancy of the piping). These issues are as applicable to 
offshore operations as they are to onshore operations, and are critical 
for ensuring the mechanical integrity of the piping. If any operator 
believes there is a specific conflict between API 570 and that 
operator's offshore operations, the operator should contact the 
appropriate District Manager for guidance.
    Comment--A commenter suggested adding language to proposed Sec.  
250.841(b) to clarify that API 570 applies downstream of the boarding 
valve for design requirements and to clarify the types of facility 
piping to which the provisions regarding temporary repairs will apply.
    Response--BSEE does not agree that the suggested additions are 
necessary. The proposed and final regulatory text for Sec.  250.841(b) 
refers to ``production process piping.'' Subpart H applies to any 
piping confined to a production platform that is downstream of the 
BSDV. Piping upstream of the BSDV is covered by the pipeline 
regulations, under subpart J. In addition, as previously stated, the 
provisions regarding temporary repairs apply to all facility piping.
Jurisdiction
    Comment--A commenter asserted that BSEE should limit the 
requirements under paragraph (b), as applied to floating facilities, to 
equipment/systems and piping over which BSEE has jurisdiction.
    Response--BSEE does not need to revise paragraph (b) as suggested. 
These regulations apply only to operations that are under BSEE 
authority. This regulation ensures that operations with respect to 
platform production facilities and platform production process piping 
are conducted in a manner that prevents or minimizes the likelihood of 
fires (e.g., from leaking pipes carrying produced hydrocarbons) and 
other occurrences that may cause damage to property or the environment, 
or endanger life or health. Thus, BSEE's regulation of these operations 
is within the scope of its legal authority to regulate platforms 
erected on the OCS and engaged in the production of oil or gas.
Approval of Safety Systems Design and Installation Features (Sec.  
250.842)
    Section summary--Final Sec.  250.842 recodifies the requirements of 
existing Sec.  250.802(e), regarding applications for approval of 
production safety systems, including the service fee associated with 
the submittal of those applications. This section outlines the 
requirements of a production safety system application and requires 
adherence to several API standards pertaining to the design of 
production safety systems and related piping and electrical systems 
(i.e., API RP 14C, API RP 14E, API RP 14F or RP 14FZ, API RP 14J, API 
RP 500 or RP 505).
    The final rule also requires completion of a hazards analysis 
during the production safety system design process and requires a 
hazards analysis program to assess potential hazards during the 
operation of the platform. The final rule also requires that the 
designs for mechanical and electrical systems be reviewed, approved, 
and stamped by a registered professional engineer (PE). It also 
requires that a registered PE certify the as-built piping and 
instrumentation diagrams (P&IDs). This section also specifies that the 
PE must be registered in a State or Territory of the U. S. and have 
sufficient expertise and experience to perform the applicable 
functions.
    Final Sec.  250.842 requires that operators certify that all listed 
diagrams (including P&IDs) are correct and accessible to BSEE upon 
request, and that the required as-built diagrams outlined are submitted 
to the District Manager within 60 days after production commences.
    In addition, final Sec.  250.842(b)(3) includes a reference to the 
hazards analysis requirement of Sec.  250.1911 and, as discussed in the 
proposed rule, imposes a requirement that the operator certify that it 
performed a hazard analysis during the design process in accordance 
with API RP 14J and that a hazards analysis program is in place to 
assess potential hazards during the operation of the platform.
    Regulatory text changes from the proposed rule--Throughout this 
section, BSEE removed the word ``BSEE'' from before ``District 
Manager.'' In addition, based on consideration of public comments, BSEE 
revised paragraphs (b)(2) and (d) to add ``an appropriate'' before 
``registered professional engineer.'' Paragraph (b)(3) was 
substantially revised to, among other things, clarify that the required 
hazards analysis must be performed in accordance with the existing SEMS 
hazards analysis requirement and with APR RP 14J. Paragraph (d) was 
revised to clarify that a registered PE must certify the as-built 
diagrams, outlined in paragraphs (a)(1) and (2), for the new or 
modified production safety system.

[[Page 61876]]

BSEE also made several minor, non-substantive edits to improve clarity 
and to use plain language.
    Comments and responses--BSEE received public comments on this 
section and responds to the comments as follows:
BSEE Jurisdiction
    Comment--A commenter raised questions about BSEE and USCG 
jurisdictional areas of responsibility over electrical systems.
    Response--The comment was unclear. The requirements of Sec.  
250.842 address what information must be included in a production 
system safety application. These regulations apply only to operations 
and systems that are under the authority granted to the Department by 
OCSLA. More detailed discussion of BSEE's and USCG's jurisdiction is 
found in part IV.B.2 of this document.
Professional Engineers
    Comment--One commenter suggested that the final rule should 
specifically require a U.S.-registered professional mechanical engineer 
to stamp all mechanical system designs, and require a U.S.-registered 
professional electrical engineer to stamp all electrical system 
designs.
    Two commenters, however, suggested revising proposed Sec.  
250.842(b)(2) to allow chartered engineers or other non-U.S. engineers 
to design, review and approve mechanical and electrical systems because 
a large number of floating structures are engineered and built outside 
the U.S. The commenter asserted that the proposed wording could 
introduce significant legal issues when applied to modifications on 
existing facilities. The commenters recommended that BSEE revise 
paragraph (b)(2) to address these issues. Another commenter supported 
the proposed requirement that PEs be registered by a State or 
Territory, but requested that BSEE expressly state that the term 
``sufficient expertise and experience'' for PEs includes experience 
with Arctic and harsh environments for systems used in the Arctic 
region.
    Response--With regard to the first commenter's suggestions, BSEE 
agrees that proposed Sec.  250.842(d) was potentially overbroad. 
Therefore, in the final rule, we have revised Sec.  250.842 by 
inserting the words ``an appropriate'' before ``registered professional 
engineer'' to clarify BSEE's intention that the registered professional 
engineer be qualified in the particular discipline relevant to the 
certification, (e.g., an electrical engineer to certify electrical 
system designs or a mechanical engineer to certify mechanical system 
designs).
    With regard to the suggestions to allow non-U.S. registered 
engineers to perform tasks under paragraph (b)(2), no changes are 
necessary based on these comments. A reliable verification, with 
stamping, by a registered PE of the designs for the mechanical and 
electrical systems is important to BSEE's decisions regarding the 
suitability of a proposed production safety system, and BSEE has no way 
of verifying a registered PE stamp from a foreign country.
    With respect to the commenter's assertions about existing 
facilities, this regulation is tailored to improve production process 
safety without unreasonably burdening the industry. In addition, 
although the commenter indicated that the proposed rule could create 
significant legal issues when applied to existing facilities, the 
commenter failed to specify what those legal issues might be, and it is 
not clear why application of this regulation to existing facilities 
would raise any significant legal issues. The relevant portion of 
proposed Sec.  250.842(b)(2), to which this comment was directed, 
requires that the production safety system application include a 
certification that the mechanical and electrical systems designs were 
reviewed, approved, and stamped by an ``appropriate'' registered PE. 
Given the importance of the certifications required by final Sec.  
250.842(b), BSEE did not make any significant changes to this proposed 
regulation based on this commenter's suggestions.
    BSEE did not revise paragraph (b)(2) to add language regarding 
experience with Arctic environments. BSEE intends that the requirement 
that an appropriate PE have ``sufficient expertise and experience'' 
will include experience with conditions where the operations will take 
place, including the Arctic environment for Arctic operations. As 
discussed earlier, BSEE may address specific Arctic-related issues in 
separate rulemakings, guidance or documents in the future.
Shut-in Tubing Pressure Changes
    Comment--A commenter asserted that the requirement in proposed 
paragraph (a)(1), to include a schematic piping and instrumentation 
diagram in the operator's production safety system application, would 
add unwarranted burdens to keep such diagrams updated. To reduce the 
asserted burden, the commenter recommended deleting proposed paragraphs 
(a)(1)(i) and (a)(1)(iii) regarding well shut-in tubing pressure and 
pressure safety valve (PSV) set points, respectively. The commenter 
stated that shut-in tubing pressure and PSV set points change often, 
and thus would require resubmitting updated drawings to BSEE 
frequently. The commenter suggested that this reporting burden would 
not provide additional value.
    Response--BSEE does not agree that the suggested change is 
necessary. BSEE does not expect operators to submit drawings every time 
the shut-in tubing pressures or PSV set points change, unless the 
production safety system changes as a result (e.g., by installation or 
removal of equipment or safety devices). Operators will need to submit 
drawings to BSEE whenever they plan to modify the production process 
safety system, to make sure the system is acceptable and complies with 
the regulations. If an operator has any question as to whether a 
specific change would require resubmission of a process safety system 
application, the operator should contact the District Manager. As BSEE 
gains experience implementing this regulation, BSEE may provide 
additional guidance on when process safety system applications must be 
updated or resubmitted.
Piping Specification Breaks
    Comment--One commenter noted that proposed Sec.  250.842(a)(1)(ii) 
would have required that piping specification breaks be included on a 
schematic piping and instrumentation diagram, whereas BSEE District 
Engineers currently accept system pressure specification breaks, as 
opposed to individual ``piping'' specification breaks, for Safety 
Analysis Flow Diagrams (SAFDs). A commenter provided an example 
involving the compressor skid. According to the commenter, using piping 
specification breaks would yield a wide variety of breaks (e.g., from 
inlet scrubbers to compressor suction and discharge bottles), while 
using system specification breaks would minimize the number of 
specification breaks that must be included in the diagram under 
paragraph (a)(1). The commenter implied that this would eliminate 
numerous unimportant details from the diagram and would simplify 
normalized operating systems, for a more robust analytical result.
    Response--BSEE does not agree with the commenter's suggested 
change. The piping specification breaks provide BSEE with important 
information for its review of the schematics and diagrams to ensure 
that the safety system has been properly designed to account for 
changes in the piping design (e.g., different pipe sizes resulting in 
pressure

[[Page 61877]]

changes). The P&ID is a more detailed drawing than the SAFD. BSEE needs 
the individual pipe specification breaks to thoroughly analyze the 
system.
Safety Analysis Flow Diagrams
    Comment--One commenter noted that, under proposed Sec.  
250.842(a)(1)(ii) and (a)(2), the Appendix E requirements of API RP 14C 
for the SAFD reflect the need for maximum pressures to be shown for 
pressure vessels, pipelines and heat exchangers. The commenter 
questioned whether, since this new requirement applies to piping and 
instrumentation diagrams, combining the two documents (i.e., the P&ID 
and the SAFD) would be acceptable for submittal and approval. The 
commenter also asserted that all items listed in proposed Sec.  
250.842(a)(1) and (2) could be included on the combined document.
    Response--BSEE does not agree with the commenter's suggestion for 
combining these two documents. The operator needs to submit both P&IDs 
and SAFDs. Industry already has standards in place for both documents 
and each document includes valuable information that is not found in 
the other. BSEE may consider a combined document in the future, as 
suggested, if industry establishes a standard process safety flow 
diagram that contains all of the information that BSEE otherwise would 
receive in P&IDs and SAFDs.
Maintaining Drawings
    Comment--A commenter stated that he requirement in proposed 
paragraphs (a)(1) and (2) to maintain two sets of drawings would be 
burdensome and create opportunities for errors and omissions to occur. 
A commenter noted that the preamble of the proposed rule referred to 
the Atlantis investigation in justifying the new requirements for 
drawings; however, the commenter asserted that the recommendations in 
the Atlantis report did not identify a need for revisions to the 
drawing(s) requirements of existing subpart H and that those 
recommendations actually addressed issues covered in existing subpart 
I. The commenter recommended combining proposed paragraphs (a)(1) and 
(2) into a single requirement.
    Response--BSEE does not agree with this suggestion. The importance 
of correct as-built documents and professional engineer stamps was 
highlighted in the Atlantis incident investigation report, prepared by 
BSEE's predecessor agency, the Bureau of Ocean Energy Management, 
Regulation and Enforcement in 2011.\22\ The Atlantis report addressed 
the scope of the existing regulatory requirements related to 
engineering documents and hazard analyses, and pointed out the 
difficulties in identifying, organizing and tracking proper ``as-
built'' drawings from other documents, such as ``issued for design'' or 
``issued for construction'' drawings. At the time of the report, 
operators were not required to submit the engineering documents, 
including ``as-built'' diagrams referenced in hazard analysis 
documents.
---------------------------------------------------------------------------

    \22\ See ``BP's Atlantis Oil and Gas Production Platform: An 
Investigation of Allegations That Operations Personnel Did Not Have 
Access to Engineer[hyphen]Approved Drawings'' (March 4, 2011). A 
copy of this report is available online at: https://www.bsee.gov/sites/bsee.gov/files/panel-investigation/incident-and-investigations/03-03-11-boemre-atlantis-report-final.pdf.
---------------------------------------------------------------------------

    Although the Atlantis report did not make specific recommendations 
for revisions to subpart H, several of the important issues identified 
in the report, including the need for operators to have a document 
management system to ensure accurate sets of drawings, are relevant to 
and addressed by this final rule. In particular, the issues discussed 
in the Atlantis report related to ``as-built'' P&IDs and to other 
diagram requirements are addressed by this section's requirements for:
     Stamping of engineering documents by a registered PE;
     Certification by the operator that all listed diagrams, 
including P&IDs, are correct and accessible to BSEE upon request; and
     Submittal of a certification to the District Manager, 
within 60 days after production begins, that the ``as-built'' diagrams, 
as described in final Sec.  250.842(a)(1) and (2) are on file and have 
been stamped by an appropriate PE.
Potential Ignition Sources
    Comment--A commenter recommended removing proposed paragraph 
(a)(3)(ii) from the final rule, asserting that the term ``potential 
ignition sources'' is ambiguous and that the value of the additional 
information is not apparent.
    Response--BSEE disagrees. This information (e.g., identification of 
areas where potential ignition sources are to be installed) is 
necessary to ensure that the operator identifies possible hazards and 
for BSEE to ensure that those hazards are identified, addressed, and 
mitigated. The final rule, as proposed, provides specific details on 
what the operator needs to include.
One-Line Electrical Drawings
    Comment--One commenter asserted that the requirement in proposed 
paragraph (a)(3)(iii) for one-line electrical drawings for all 
electrical systems would be an expansion of existing requirements and 
requested that BSEE limit final paragraph (a)(3)(iii) to submittals for 
new facilities only.
    Response--BSEE disagrees. Proposed and final Sec.  
250.842(a)(3)(iii) retains, and does not expand the scope of, the 
information required by existing Sec.  250.802(e)(4)(ii), and operators 
are already complying with that longstanding requirement. This section 
of the final rule only moves the current requirements to a new section. 
BSEE did not propose, and has not made, any substantive revisions to 
the existing regulatory requirement.
Whether To Limit Requirement for Certain Schematics to New Facilities
    Comment--A commenter recommended that BSEE limit the expanded 
requirement under proposed paragraph (a)(4) (schematics of fire and 
gas-detection systems) to submittals for new facilities only.
    Response--BSEE disagrees with the requested limitation. This 
information is already required by existing Sec.  250.802(e)(6), and 
this final rule simply moves that longstanding requirement to a new 
section, with no substantive changes. Operators are already complying 
with the existing requirement and BSEE sees no need or justification 
for limiting its scope to new facilities.
Definition of ``Designs''
    Comment--One commenter noted that proposed paragraph (b) would 
require ``designs for the mechanical and electrical systems . . . [to 
be] reviewed, approved, and stamped by a registered professional 
engineer(s).'' The commenter asserted that a vital component of the 
process safety system is the implementation of appropriate safety and 
control programming logic in either pneumatic panels or programmable 
logic controller (PLC) processors, much of which is carried out by 
equipment suppliers and/or programmers not directly supervised by 
registered engineers. The commenter recommended adding a definition for 
``designs'' in the final rule.
    Response--BSEE disagrees with that recommendation. Adding a 
definition of ``designs'' in this section is not necessary and would 
not substantially clarify the content of the regulation. The terms used 
in paragraph (b), including ``designs,'' are well-established and 
commonly used in the affected industry, and have long been used in the 
existing regulations in the same context as they are used in this 
rulemaking.

[[Page 61878]]

Electronic PE Reviews
    Comment--A commenter recommended rewording paragraph (b)(2) to 
allow for an electronic review by a PE in lieu of requiring that hard 
copies be stamped. The commenter asserted that the proposed wording of 
paragraph (b)(2) could also create significant ambiguity when applied 
to modifications on existing facilities. The commenter suggested that 
stamping and/or certification be limited to new systems/designs that 
are ``to be installed.''
    Response--No changes are necessary. Electronic stamps of a 
registered PE are acceptable under this section, as long as they 
provide the same authentic verifiable information as a PE stamp applied 
to paper. For example, the electronic stamp could be a jpeg of the PE 
stamp, depending on what each state allows its registered engineers to 
do. Regarding the assertion of potential ambiguity if the PE review 
requirement is applied to modifications of existing equipment, the 
commenter failed to provide any support for that assertion, and BSEE is 
not aware of any ambiguity that warrants changing the applicability of 
this requirement to modifications to existing equipment in addition to 
installation of new equipment.
Independent Third-Parties
    Comment--A commenter proposed that BSEE change proposed paragraph 
(b)(2) to require that the designs for the mechanical and electrical 
systems be reviewed, approved, and stamped by an independent third-
party. The commenter suggested that independent third-party 
organizations have the multi-disciplinary knowledge to fully evaluate 
the safety of a complete production system and can demonstrate to 
regulators that they have comprehensive quality and work processes and 
training and qualification programs for their employees.
    The commenter also asserted that, as BSEE moves to incorporate risk 
principles into its safety regime, DNV GL's Offshore Service 
Specification DSS-OSS-300, Risk Based Verification, may help BSEE and 
industry achieve their safety objectives. The commenter noted that, in 
general, verification based on risk is founded on the premise that the 
risk of failure can be assessed in relation to an acceptable risk level 
and that the verification process can be used to manage that risk, thus 
making the verification process a tool to maintain the risk below the 
acceptance limit. The commenter also suggested that verification based 
on risk helps to minimize additional work and cost, while maximizing 
risk management effectiveness.
    Response--No changes are necessary. Paragraphs (b)(2) and (d) 
require certification that an appropriate registered PE has stamped the 
design documents, which is intended to implement one of the 
recommendations in the Atlantis report. Having a registered PE review, 
approve, and stamp those documents provides BSEE with an additional 
review tool to ensure the documents are correct and confirmed by 
someone with the experience and expertise to do so. BSEE is aware that 
some independent third-parties may lack the same relevant experience 
and expertise that an appropriate registered PE possesses. For example, 
BSEE is aware that some engineering firms may allow engineers who are 
not registered PEs to perform design reviews and use the firm's stamp; 
therefore, BSEE does not agree at this time that use of an engineering 
firm to perform those tasks would provide the same level of verifiable 
assurance that the reviews of these critical systems have been 
conducted by appropriately qualified engineers. However, BSEE intends 
to monitor and evaluate implementation of this requirement and may 
consider, based on that experience, whether an alternative review 
process, such as use of independent third-parties, should be provided 
under this regulation. In the meantime, if an operator believes that an 
alternative review and verification process would be at least as 
effective as the regulatory requirement, it can request BSEE's approval 
of such an alternative under Sec.  250.141 on a case-by-case basis.
    As to the commenter's second suggestion, the requirements in 
paragraph (b)(2) represent a practical and effective means of verifying 
that the mechanical and electrical systems have been designed properly 
to perform their critical functions in a manner similar to the 
longstanding requirement under existing Sec.  250.802(e)(5). Thus, BSEE 
does not agree with the commenter's suggestion that the approach taken 
by this final regulation may cost too much or fails to manage risks 
appropriately. BSEE also does not agree that the commenter's suggested 
``risk-based'' approach would minimize costs and maximize risk 
management. However, BSEE is continually evaluating risk-based methods 
to improve safety and environmental protection, and BSEE may consider 
at a later date whether an alternative risk-based approach to system 
design verification is warranted.
Classification Societies and Certification Authorities
    Comment--A commenter requested, for purposes of proposed paragraph 
(b)(2), that BSEE accept the review and approval by a classification 
society of the mechanical and electrical systems as equivalent to the 
review, approval and stamping of systems designs by a registered PE. 
The commenter based this request on BSEE's existing regulations at 
Sec.  250.905(k), which provide for review, approval and certification 
by a ``classification society'' as an alternative to the same functions 
performed by a registered PE under that section. The commenter asserted 
that the USCG also recognizes review and approval by classification 
societies as equivalent to the certification by a registered 
professional engineer. A second commenter made similar statements and 
requested that BSEE revise this section to allow ``certification 
authorities,'' in lieu of registered PEs, to review, approve and stamp 
mechanical and electrical system designs. The commenter provided no 
examples or criteria for identifying any certification authorities.
    Response--No changes are necessary. A classification society or a 
``certification authority'' could be used by an operator to review and 
approve the relevant design documents as long as the classification 
society or certification authority provides a qualified, registered PE 
to review, approve, and stamp the documents. However, for the same 
reasons discussed in response to the preceding comment (regarding 
independent third-parties), BSEE does not have reason to believe at 
this time that review and approval by a classification society or 
certification authority, without use of an appropriate registered PE, 
would provide the necessary level of confidence that the mechanical and 
electrical systems are properly designed to perform their critical 
roles in the production process safety system. However, if an operator 
believes that an alternative review and verification process involving 
a classification society or certification authority would be at least 
as effective as the regulatory requirement for use of a registered PE, 
it may request BSEE's approval of such an alternate procedure on a 
case-by-case basis under Sec.  250.141.
Applicability of PE Review and Approval
    Comment--A commenter suggested that proposed paragraph (b)(2) 
should be revised to clarify whether these provisions apply to all 
electrical and

[[Page 61879]]

mechanical systems or just to those related to safety systems. The 
commenter also suggested that the final rule should make provisions for 
monogrammed mechanical and electrical systems or equipment.
    Response--BSEE does not agree that the suggested changes are 
necessary. Paragraph (b)(2), as proposed, clearly applies to all 
mechanical or electrical systems that are included in the operator's 
production safety system application for approval. Monograms are not a 
substitute for PE review and verification because monograms only 
represent that the system was in compliance with the standard at the 
time of manufacture; they do not provide any information about any 
post-manufacture changes made to the system. BSEE needs to verify, 
however, that the drawings are accurate for the systems and equipment 
that are actually installed on the facility. Thus, final paragraphs 
(b)(2) and (d) require certification that a registered PE stamped the 
actual documents.
    Comment--A commenter asserted that the hazards analysis specified 
by proposed paragraph (b)(3) would require more detail than a similar 
requirement for the operator's SEMS program. The commenter suggested 
that BSEE clarify how paragraph (b)(3) and the SEMS hazards analysis 
requirements complement or differ from each other, with the ultimate 
goal of establishing one standard for hazards analysis.
    Another commenter asserted that the placement of the hazards 
analysis requirement in Sec.  250.482(b)(3) is confusing given that 
hazards analyses are covered by the subpart S (SEMS) regulations, API 
RP 75, and API RP 14J, and suggested that any alterations to hazards 
analysis requirements should be made through revision of subpart S or 
the industry standards. The commenter also asserted that the reference 
to ``during the design process'' in proposed paragraph (b)(3) is vague 
and potentially confusing with respect to whether it is referring to 
the original design process or to the design process of a modification. 
The commenter recommended removing ``the ``design process'' from the 
final rule. The commenter also recommended that BSEE delete paragraph 
(b)(3) entirely or revise paragraph (b)(3) to read: ``You must certify 
that a hazard analysis was performed in accordance with subpart S 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 platform.''
    Response--BSEE agrees, in part, with these comments and has revised 
final paragraph (b)(3) to state that the operator must certify that its 
hazards analysis was performed in accordance with Sec.  250.1911 and 
API RP 14J, and to clarify that the operator must have a hazards 
analysis program in place to assess potential hazards during the 
operation of the facility. BSEE also deleted the proposed requirement 
to perform the analysis ``during the design process.'' These revisions 
clarify that the hazards analysis required by this paragraph must 
satisfy the SEMS requirement, with respect to the relevant safety 
systems, as well as the more specific analysis required by API RP 14J. 
This will result in hazards analyses under subpart H that are 
consistent with the subpart S requirements, but that likely will 
provide more specific details regarding the relevant safety systems 
than subpart S alone might require.
Certification of Mechanical and Electrical Systems Installations
    Comment--A commenter recommended that BSEE allow certification of 
mechanical and electrical systems installation through other means than 
a letter from the operator.
    Response--No changes are necessary. Final Sec.  250.842(d) calls 
for the operator to submit a letter certifying the accuracy of the as-
built drawings. The letter provides documentation to assist BSEE in 
verifying that the drawings are consistent with the mechanical and 
electrical systems. Within 60 days of first production, the operator 
must submit updated as-built drawings along with a certification that a 
PE reviewed and stamped these drawings. These written documents will 
help BSEE ensure that the system was built according to the original 
plan submitted to BSEE. However, an operator may submit the 
certification letter electronically, if it chooses, or through BSEE's 
e-facility safety system permitting system.
Notification of Safety System Testing
    Comment--A commenter suggested that BSEE revise proposed Sec.  
250.842(c) to clarify the type of approval or acknowledgement that the 
District Manager will issue following submission of the required 
documents. The commenter also suggested that BSEE revise proposed 
paragraph (c) by adding a requirement that a separate notification be 
submitted to the District Manager, as required by Sec.  250.880, at 
least 72 hours before commencing production safety system testing.
    Response--In response to the first comment, paragraph (c) only 
requires that the operator notify BSEE that the mechanical and 
electrical systems were installed in accordance with the designs 
previously approved by the PE; there is no BSEE approval or response 
required under paragraph (c).
    Regarding the second comment, BSEE is not adding a reference to the 
production system testing notice required by Sec.  250.880(a)(1) to 
Sec.  250.842(c) as suggested. Section 250.842(c) deals with the 
certification required to be submitted prior to production, while the 
production safety system testing notification required by final Sec.  
250.880 may and generally will take place after production begins. 
Referring to the testing notification requirement from Sec.  250.880 in 
Sec.  250.842 is unnecessary and potentially confusing.
Certification of As-Built P&ID
    Comment--A commenter asserted that certification of as-built P&ID 
under proposed paragraph (d) would be more appropriately done by a CVA 
surveyor than by a registered PE. The commenter also asserted that the 
proposed rule does not address the issues in the Atlantis report.
    Response--No changes are necessary. As previously discussed, this 
rule addresses a number of the recommendations discussed in the 
Atlantis report (which, among other issues, evaluated complaints about 
the operator's access to certain engineering documents), and applies 
them in the context of production operations under subpart H. In 
particular, Sec.  250.842(d) requires operators to provide as-built 
diagrams to BSEE and that operators certify that all listed diagrams, 
including P&IDs, are correct and accessible. The rule also addresses 
other issues identified in the Atlantis report by requiring a specific 
stamp by a PE on both the designs and the as-built diagrams, verifying 
their correctness, and by requiring the operator to certify that the 
equipment was installed in accordance with the approved designs. These 
measures provide BSEE with additional verification that the equipment 
on the facility was designed, built, and installed properly. Similarly, 
since some piping may be changed during construction, due to the actual 
layout, once the facility is fabricated and production begins, Sec.  
250.842(d) requires operators to submit the as-built drawings to ensure 
that any changes are documented.
    Comment--One commenter asserted that the requirement in proposed 
Sec.  250.842(d) for certification by an

[[Page 61880]]

operator, within 60 days after production begins, that the as-built 
P&IDs and SAFDs have been certified correct and stamped by a registered 
PE would conflict with the engineering laws of many States. The 
commenter stated that engineers may only seal documents which they have 
verified as being correct and, thus, cannot legally certify as-built 
drawings because such certification would imply that all of the 
construction satisfies the applicable codes and standards. The 
commenter asserted that this further implies that the certifying 
engineer must be in charge of all of the construction quality 
assurance/quality control activities that verify compliance with 
construction codes and standards.
    Response--BSEE does not agree that this comment warrants any 
changes and is not aware of any specific conflicts between these 
regulations and any State law. However, if any operator believes there 
is any potential conflict the operator should notify the District 
Manager so BSEE can review the situation and respond appropriately on a 
case-by-case basis. In the event an actual or potential conflict 
arises, the operator could also seek approval for an alternative 
process or a departure under Sec. Sec.  250.141 and 250.142, 
respectively.
As-Built P&ID Timeframe and Field Verification
    Comment--A commenter recommended that all references to ``piping 
and instrument diagrams'' be replaced with references to ``process 
safety flow diagrams.'' The same commenter asserted that 60 days is not 
sufficient to validate the drawings as correct, certify the drawings as 
correct, and submit the as-built diagrams and the certification to the 
bureau. The commenter recommended that BSEE revise paragraph (d) to 
require the operator to provide BSEE with a copy of the as-built P&IDs 
within 180 days after production begins.
    Another commenter stated that it did not understand the need for 
the rule to state that all approvals are subject to field verification. 
The commenter asserted that such verification is a standard practice 
with any inspection and enforcement process. That commenter and another 
commenter recommended that BSEE revise paragraph (f) to remove the 
requirement for field verification of all approvals of design and 
installation features.
    Response--No changes are necessary. P&IDs, SAFDs, and SAFE charts 
are required, as provided in paragraph (a), before BSEE will approve 
the safety system. After the platform is producing, BSEE requires the 
operator to submit these documents again to ensure that any minor 
changes made during the construction phase are captured. The 60-day 
timeframe in paragraph (e) for submitting the as-built diagrams to BSEE 
is sufficient for that purpose; since the facility is built before 
production begins, the operator will have more than the 60 days after 
production begins to make these corrections and have the drawings 
certified. BSEE needs these documents for inspection purposes. The 
original drawings are used during pre-production, while the as-built 
drawings are necessary for any BSEE inspection conducted after the 
platform is on-line and to notify the operator if there are any 
concerns with the as-built diagrams. The P&IDs are a critical element 
of this final rulemaking and industry standards (such as API RP 14C, 
API RP 14J, and API RP 14F) and are separate and distinct from SAFDs.
    In addition, removing the sentence pertaining to field 
verifications from paragraph (f), as suggested by the commenters, would 
serve no useful purpose, since the regulation also provides that those 
documents must be made available to BSEE upon request and since, as 
with all similar documents, the P&IDs and SAFDs are subject to field 
verification by BSEE during the inspection process.
As-Built Diagrams
    Comment--A commenter asserted that paragraphs (d) and (e) might 
conflict with some State requirements under which construction issued 
documents are sealed while as-built documents are not. The commenter 
also stated that State requirements also require that the ``sealing 
engineer'' be the responsible engineer in charge of the design phase.
    Response--No changes are necessary. BSEE does not regulate how 
operators create the diagrams. As previously explained, BSEE needs to 
ensure that the diagrams are properly reviewed by qualified PEs and 
that they meet the standards incorporated in this section. This 
regulation does not require PEs to be involved in anything that they 
are not already authorized to do. In the event an actual or potential 
conflict between this rule and any applicable State law arises, 
however, the operator should contact the District Manager for guidance. 
The operator may also seek approval for an alternate process or a 
departure under Sec. Sec.  250.141 and 250.142, respectively, on a 
case-by-case basis.
Paperwork Burden and As-Built Diagrams
    Comment--A commenter asserted that proposed paragraph (e) of this 
section would create a new requirement (to submit as-built P&IDs and 
SAFDs to BSEE within 60 days after production commences) and that the 
commenter did not understand the purpose of that requirement. The 
commenter noted that BSEE will have the original design diagrams as 
part of the application process, and that BSEE will also receive a 
certification that the installation was done in accordance with the 
approved diagrams. The commenter asserted that this requirement creates 
an undue paperwork burden on both the company and the bureau and added 
that BSEE had severely underestimated the costs for maintaining the 
``as-built'' drawings for the life of the facility (as required by 
paragraph (f)). The commenter recommended that this requirement be 
deleted.
    Response--BSEE disagrees with these comments. As previously 
explained, BSEE must have up to date as-built diagrams, which 
accurately reflect the actual systems in place, for review and 
inspection purposes, including providing notification to the operator 
of any BSEE concerns about differences between the original approved 
diagrams and the as-built diagrams. Modifications are often made to 
systems during construction or during initial operations, potentially 
rendering the approved drawings that accompanied the application 
obsolete. If no changes are made to the system after approval, however, 
an operator should be able to submit the same drawings that were 
originally stamped by the PE at little or no extra cost. BSEE's 
estimates for determining the costs and burdens related to as-built 
diagrams were based upon BSEE's best professional judgment.
Applicability to Existing Facilities
    Comment--A commenter noted that proposed paragraph (f) requires 
that as-built P&IDs be maintained for the life of the facility. The 
commenter asserted, however, that the proposed rule did not specify 
whether paragraph (f) applies only to facilities installed/approved 
after publication of the final rule or whether it also applies to 
existing facilities. The commenter suggested that the rule and the 
related information collection approval should clearly state that 
paragraph (f) applies only to facilities installed and approved after 
publication of the final rule. The commenter asserted that the costs 
and information collection burdens would

[[Page 61881]]

be considerable if as-built diagrams are required for existing 
facilities.
    Response--No changes are necessary. The requirement for as-built 
diagrams will apply to all production facilities installed or modified 
after the effective date of the final rule. All safety system 
submittals made after the effective date of the final rule must comply 
with the requirements of final paragraphs (a) through (e). All 
production safety system design and installation documents approved 
under this section will need to be maintained and readily available as 
required by paragraph (f).
Production System Requirements--General (Sec.  250.850)
    Section summary--The final rule moves the contents of existing 
Sec.  250.803 into a number of new sections (final Sec. Sec.  250.850 
through 250.872). The provisions of existing Sec.  250.803 were 
rewritten and reorganized in the new sections to improve readability by 
making each section shorter and focused on a specific issue. In 
particular, the contents of existing Sec.  250.803(a) have been moved 
to final Sec.  250.850, which establishes general requirements for 
production safety systems, including requiring operators to comply with 
API RP 14C.
    Regulatory text changes from the proposed rule--BSEE did not make 
any significant changes to this section. BSEE slightly revised the 
reference to API RP 14C to clarify that operators must also comply with 
the production safety system requirements of that standard.
    Comments and responses--BSEE did not receive any comments on this 
section.
Pressure Vessels (Including Heat Exchangers) and Fired Vessels (Sec.  
250.851)
    Section summary--The contents of existing Sec.  250.803(b)(1), 
establishing requirements for pressure vessels (including heat 
exchangers) and fired vessels, have been moved to final Sec.  250.851. 
A table in paragraph (a) establishes basic requirements for production 
systems; paragraph (b) addresses operating pressure ranges; and 
paragraph (c) addresses pressure shut-in sensor settings.
    Regulatory text changes from the proposed rule--The text of this 
section has been revised for clarity and plain language, and language 
has been added for completeness (e.g., approval of uncoded vessels and 
operating pressure changes). Paragraph (a) has been revised to conform 
better to the MOA-OCS-04 between BSEE and the USCG, the referenced 
industry standards, and existing regulations, and to respond to 
comments received. The final rule clarifies that paragraph (a) of this 
section applies to pressure vessels and fired vessels that support 
production operations. In final paragraph (a), BSEE removed provisions 
from the proposed rule that related to existing pressure and fired 
vessels with operating pressures of less than 15 psig. In final 
paragraph (a)(2), BSEE provided a period of time (540 days from 
publication of the final rule) after which BSEE approval is required 
for continued use of certain uncoded pressure and fired vessels. In 
final paragraph (a)(3), BSEE added an exception for pressure vessels 
where staggered set pressures are required for configurations using 
multiple relief valves or redundant valves installed and designated for 
operator use only.
    BSEE also revised final paragraph (b), based on comments received, 
to clarify the requirements for the establishment of new operating 
pressure ranges. This includes clarifying that the operator must 
establish the new operating pressure range after the system pressure 
has stabilized, and that pressure recording devices must document the 
pressure range over time intervals that are no less than 4 hours and no 
longer than 30 days.
    Paragraph (c) was revised to include clarification that initial set 
points for pressure shut-in sensors must be set utilizing gauge 
readings and engineering design.
    Comments and responses--BSEE received public comments on this 
section and responds to those comments as follows:
Tank Design and Operation
    Comment--One commenter asserted that the regulations should be 
revised to state that these sections are not applicable to the design 
or operation of tanks inside the hull of a floating facility, as USCG 
requirements for tanks inside the hull of a unit may differ from BSEE 
requirements. Alternatively, the commenter suggested that the MOA 
should be revised to give USCG jurisdiction over the design of tanks 
that are integral to the hull and to give BSEE jurisdiction over non-
integral tanks in the hull and over the operation of both integral and 
non-integral tanks in the hull of the unit that are for produced 
hydrocarbons, fuel and flow assurance fluids.
    Response--The commenter is referring to tanks in the hull of a 
floating facility. BSEE agrees that the USCG has jurisdiction over the 
design and operation of tanks in the hull. However, under MOA OCS-04, 
BSEE has responsibility for regulation of the level safety systems on 
all product storage tanks, including those in the hull of a floating 
facility. These tanks are upstream of the production meters. BSEE does 
not regulate the tank design or how the operator loads the product. 
However, BSEE needs to ensure there is a safety system in place to 
ensure the tanks do not overflow. To clarify this issue, BSEE revised 
paragraph (a) in the final rule by deleting the proposed requirements 
for tanks with operating pressures less than 15 psig and by adding a 
specific reference to pressure vessels and fired vessels that are used 
to support production operations. Further discussion of BSEE's 
jurisdiction is found in part IV.B.2 of this document.
Pressure Vessels
    Comment--One commenter noted that USCG has its own regulations 
regarding pressure vessels utilized in emergency and ship service 
systems for floating platforms. The commenter suggested that, for 
floating facilities, BSEE should state that the proposed regulations do 
not apply to pressure vessels, waste heat recovery, water heaters, 
piping or machinery that are associated with the unit's emergency and 
ship-service systems.
    Response--As previously stated, this final rule applies only to 
operations that are under BSEE authority. Nonetheless, BSEE has revised 
final paragraph (a) to better delineate the scope of these provisions 
in relation to BSEE's authority.
    Pressure Monitoring
    Comment--A commenter questioned the need for continual monitoring 
in order to observe when the real time system pressure changes by 5 
percent. The commenter asserted that most platforms are not equipped 
with a supervisory control and data acquisition/PLC (SCADA/PLC) type 
real-time monitoring system that could be programed to monitor and 
alarm a 5 percent change in operating pressure, although pressure 
safety high (PSH) and pressure safety low (PSL) safety devices 
constantly monitor pressure variables and are set to properly respond 
to an automatic detection of an abnormal condition. The commenter 
asserted that existing BSEE regulations allow the setting of PSHLs at 
15 percent above/below the highest/lowest operating ranges in the 
production process and that installing equipment to monitor for a 
change of 5 percent would render the PSHLs redundant. The commenter 
stated that, currently, whenever PSHLs automatically detect abnormal 
conditions, the operating range at that time is evaluated to learn if a 
new range needs to be established. The commenter also asserted that the 
proposed rule did

[[Page 61882]]

not offer a timeframe for establishing a new pressure range, and that 
such a timeframe should account for weather, schedules and other 
factors. The commenter expressed concern that the proposed requirement 
could result in nuisance shut-ins.
    Response--BSEE does not agree with the suggestion that operators 
would need to acquire new real-time monitoring capabilities in order to 
implement the requirements of this provision. Section 250.851(b) does 
not require continuous real-time monitoring of pressure range; it only 
requires the use of pressure recording devices to establish new 
operating pressure ranges when an observed pressure change exceeds the 
limits specified in the rule. BSEE expects that operators are already 
using equipment that measures pressure changes in accordance with the 
existing regulations and industry standards and that is capable of 
being used under final Sec.  250.851.
    This provision does not preclude operators from setting new 
operating ranges based on a more conservative approach; that is, 
avoiding potentially unnecessary shut-ins by setting new pressure 
ranges when normalized system pressure changes by less than 50 psig or 
5 percent. In addition, BSEE has clarified the final rule's 
requirements for resetting the pressure range, by adding language 
providing that once system pressure has stabilized, the operator must 
use pressure recording devices to establish the new operating pressure 
ranges. The final rule also specifies that the time interval for 
documenting the pressure range must be no shorter than 4 hours and no 
longer than 30 days. BSEE added the minimum time provision to ensure 
that the system pressure is stable before setting the operating ranges. 
In addition, the time period limitations were set, in part, because 
pressure spikes and/or surges may not be discernible in a range chart 
if the run time is too long. These revisions should also alleviate the 
commenter's concern regarding potential nuisance shut-ins.
Consistency With ASME Codes
    Comment--A commenter stated that portions of proposed paragraph (a) 
were inconsistent with ASME's Boiler and Pressure Vessel Code and 
recommended revising the proposed rule to align with established codes. 
The commenter recommended specific language for revising proposed 
paragraphs (a)(1) and (a)(4).
    Response--BSEE has revised this section in the final rule, as 
previously described, and the language the commenter suggested revising 
is no longer in the regulatory text.
Redundant Relief Valves
    Comment--One commenter stated that, while this proposal attempts to 
account for the need to stagger relief valve set pressures, it could 
potentially create an unsafe condition, depending on the meaning of the 
term ``completely redundant relief valve'' in the proposed rule. The 
commenter noted that some equipment can have multiple causes for high 
pressure, each of which may produce different amounts of vapor that 
need to be relieved through the relief valve(s), and that it is not 
uncommon for some equipment to need multiple relief valves to meet 
various contingencies, while other equipment may only need a single 
relief valve. The commenter stated that making all the set pressures 
the same could lead to ``relief valve chatter'' (i.e., the rapid 
opening and closing of the relief valve), with effects ranging from 
valve seal damage to valve or piping failure. The commenter suggested, 
in the case of a completely redundant or spare relief valve, that the 
set pressure should be the same as the valve it replaces and that the 
spare relief valve should be fitted with an inlet block valve. The 
commenter also suggested that if the primary relief valve needs to be 
isolated or removed, the spare relief valve/inlet block valve should be 
opened and the primary relief valve/inlet block valve closed for 
continuous protection. For those reasons, the commenter provided 
recommended revised language to provide for exceptions where staggered 
set pressures are required for configurations using multiple relief 
valves or redundant valves installed and designated for operator use 
only.
    Response--BSEE agrees with the commenter's reasoning for revising 
the exceptions language in proposed paragraph (a)(3) and has added the 
language suggested by the commenter as final paragraph (a)(3)(ii). The 
exceptions include cases where staggered set pressures are required for 
configurations using multiple relief valves or redundant valves 
installed and designated for operator use only.
Operating Ranges
    Comment--A commenter asserted that most operators do not monitor 
the operating ranges to see if pressures fluctuate by 5 percent, since 
such fluctuations do not typically indicate a change in the maximum 
operating pressure. The commenter opined that current industry 
practices for ensuring that pressures are below the maximum operating 
pressure are sufficient. To implement the proposed new requirement, the 
commenter asserted, industry would need to institute new field 
protocols, requiring additional resources, which would provide 
uncertain value. The commenter recommended revising the proposed 
provision to require establishment of new pressure ranges when the 
normal system pressure changes by the greater of 15 percent or 5 pounds 
per square inch (psi).
    Response--BSEE revised paragraph (b) of this section to be 
consistent with similar requirements in other sections of the final 
rule (e.g., final Sec.  250.852), which also require the operator to 
establish new operating pressure ranges when the operating pressure 
changes by a specified threshold amount or percentage. BSEE disagrees 
with the commenter's suggestion for revising the proposed threshold for 
establishing new pressure ranges under this section. BSEE has 
determined that a 5 percent change in normalized system pressure is an 
appropriate threshold for requiring establishment of a new operating 
pressure range, since that threshold will help minimize nuisance shut-
ins and provide operators with reasonable advance notice of potentially 
abnormal pressure changes that could pose safety or environmental 
risks. By using a 5 percent threshold, it is likely that operators will 
establish new operating pressure ranges more frequently than they would 
under a higher threshold (such as that suggested by the commenter). 
This should lead to fewer shut-ins that are due to pressure 
fluctuations that do not actually reflect a dangerous condition, but 
that would be above or below the pressure range that would have existed 
if it had not been reset under this provision. Conversely, the 5 
percent threshold will provide operators with earlier warnings of 
potentially abnormal conditions, which could indicate an actual 
developing problem, and provide additional time and opportunity for the 
operator to take any appropriate steps to prevent a safety or 
environmental incident from occurring. The commenter's suggested 
threshold, by contrast, would not provide such opportunities, and 
therefore would not achieve the purposes of this provision.
    For the same reasons (i.e., minimization of nuisance shut-ins and 
early warning of potentially dangerous abnormalities), BSEE disagrees 
with the commenter's suggestion that the 5 percent threshold would not 
provide any value. In addition, to help clarify the requirements for 
establishing a new pressure range, BSEE added language to Sec.  
250.851(b) requiring that, after system

[[Page 61883]]

pressure has stabilized, the operator use pressure recording devices to 
establish the new operating pressure ranges, and that the pressure 
range must be documented over time intervals that are no less than 4 
hours and no more than 30 days long. This clarification will help 
minimize this commenter's concern that the 5 percent threshold will 
require new field protocols. In addition, contrary to the commenter's 
suggestion, setting sensors to monitor for a 5 percent change in 
pressure is not a new concept, since API RP 14 C, which is incorporated 
by reference in several sections of this final rule, already specifies 
that PSHL sensors be set with a pressure tolerance of 5 percent.
PSL Settings
    Comment--A commenter noted that the proposed rule would require 
approval from the District Manager for activation limits on pressure 
vessels that have a PSL sensor set less than 5 psi, although some 
pressure vessels currently operate below 5 psi. The commenter suggested 
that BSEE delete this requirement because it would create an 
unnecessary administrative burden.
    Response--BSEE did not make any significant changes to the final 
rule. Setting the PSL sensor below 5 psig requires approval from the 
District Manager because, in BSEE's experience, pneumatic-type sensors 
are generally less accurate when pressure is below 5 psig. While the 
commenter asserts that the requirement would create an unnecessary 
administrative burden, the commenter did not provide any further 
information about this asserted burden. If the commenter was referring 
to burdens on BSEE's District Managers, BSEE does not agree that any 
such burden would be unnecessary or unwarranted given BSEE's need to 
ensure that pressure vessels are operating safely. If the commenter was 
referring to an administrative burden on operators, the commenter did 
not provide any estimate of that burden.
Flowlines/Headers (Sec.  250.852)
    Section summary--The final rule moves the content of existing Sec.  
250.803(b)(2), which establishes requirements for flowlines and 
headers, to final Sec.  250.852. The existing regulations require the 
establishment of new operating pressure ranges at any time a 
``significant'' change in operating pressures occurs. The final rule 
specifies instead that the operator needs to set new operating pressure 
ranges for flowlines any time the normalized system pressure changes by 
50 psig or 5 percent, whichever is greater. The final rule also 
specifies relevant timing and procedures. BSEE also added requirements 
for wells that flow directly to a pipeline without prior separation and 
for the closing of SSVs by safety sensors, as well as requirements for 
choking devices, and for the use of single valves and sensors to 
protect multiple subsea pipelines or wells that tie into a single 
pipeline riser.
    Regulatory text changes from the proposed rule--Proposed paragraph 
(a)(2) was revised in the final rule to clarify the requirements for 
establishing new operating pressure ranges in response to comments on 
similar provisions in proposed Sec.  250.851 and other sections. Final 
paragraph (b) was revised to clarify that initial set points for 
pressure sensors must be set using gauge readings and engineering 
design. In final paragraph (c)(1), the word ``liquid'' was removed 
after the phrase ``maximum-anticipated flow of'' so as not to 
improperly limit the scope of the requirement.
    Comments and responses--BSEE received public comments on this 
section and responds to those comments as follows:
Nuisance Shut-Ins
    Comment--A commenter asserted, as an example, that under the 
proposed regulations, a flowline that has a normalized operating range 
of 50 psig would have a PSH setting of 57 psig and a PSL setting of 43 
psig. The commenter then explained that if the operating range normally 
changes to 40 psig, due to a naturally depleting well, the PSL will 
actuate and shut-in the well unnecessarily. The commenter also asserted 
that the operator would not be able to establish a new pressure range 
since the change was not ``50 psig or 5 percent, whichever is higher.'' 
Therefore, the well would remain shut-in until the range changed by the 
greater of 50 psig or 5 percent. Thus, the commenter concluded that the 
proposed regulation would not provide for normalized operating ranges 
that are below 1,000 psig (since 5 percent of 1,000 psig is 50 psig). 
The commenter also asserted that BSEE currently permits operators to 
establish new operating ranges at less than the proposed change 
requirements of 50 psig or 5 percent, whichever is greater,'' to help 
prevent nuisance shut-ins.
    Response--As discussed in regard to similar comments on proposed 
Sec.  250.851, operators may use a more conservative approach to help 
prevent nuisance shut-ins, by using a lower change in pressure than 
that specified in this section (i.e., the greater of 50 psig or 5 
percent) as a threshold for establishing a new operating pressure 
range. The thresholds established by Sec. Sec.  250.851 and 250.852 
represent pressure changes at which an operator must establish new 
operating pressure ranges; they do not preclude an operator from 
establishing new operating pressure ranges based on pressure changes 
below those thresholds. BSEE has added language to the final that 
states that once system pressure has stabilized, the operator must 
establish the new operating pressure ranges using pressure recording 
devices that document the pressure range during time intervals no less 
than 4 hours and no more than 30 days long.
Consistency With Subpart J
    Comment--A commenter asserted that the proposed language conflicts 
with the current language in subpart J, and also with the recommended 
guidance in API RP 14C. The commenter recommended deleting the 
requirement for the PSV when the shut-in tubing pressure is greater 
than 1.5 times the maximum allowable working pressure (MAWP) of the 
pipeline or flowline. The commenter stated that, currently, with the 
two SSVs with independent PSHs, a safety integrity level (SIL) of 2 is 
achieved when both SSVs are required to hold bubble tight (zero 
leakage). The second SSV serves as an alternate safety device to 
prevent over pressurization of the pipeline.
    Response--No changes are necessary, since this section covers only 
the safety systems on the pipeline, which are part of the production 
safety system. BSEE regulations do not address or rely on the SIL 
approach. Although BSEE does not agree that there is a conflict between 
API RP 14C, as referenced in this section of the final rule, and 
subpart J, if there is any conflict between any industry standard and 
any regulation in subparts H or J, operators must follow the 
regulations. In addition, if there is any conflict between the 
requirements of subparts J and H, operator must follow the more 
rigorous requirement, which generally will found in subpart H. . 
Although BSEE is not aware of a conflict between these final subpart H 
requirements, API 14C, and subpart J, BSEE will continue to monitor the 
implementation of both sets of requirements to ensure there are no 
conflicts. Further, if an operator believes there may be a conflict in 
a particular situation, the operator may contact the District Manager 
for advice.
Applicability to Subsea Installations
    Comment--A commenter suggested revising the section title of 
proposed Sec.  250.852 so that the section applies only to dry trees on 
floating facilities

[[Page 61884]]

and expressly limiting this section to surface trees and dry well 
jumper flowlines to avoid confusion with subsea installation which 
requires different equipment.
    Response--BSEE disagrees with the suggestions for revising the 
section title and for limiting this section to surface trees and dry 
well jumper flowlines. The requirements in this section apply to all 
dry trees, except for paragraph (e), which applies to dry trees on 
floating facilities, and paragraph (g), which applies to pipeline 
risers on floating production facilities. The requirements for other 
safety devices that are used for subsea installations are addressed in 
Sec. Sec.  250.873 through 250.875 of the final rule. Thus, BSEE does 
not agree that the organization of the sections in the final rule is 
likely to cause any confusion as to requirements for dry trees and 
subsea installations.
Normal Variations in Operating Pressures
    Comment--A commenter suggested revising the language of proposed 
Sec.  250.852(a)(2), since slugging and other dynamic phenomenon that 
may be associated with normal flow can often cause the pressure to 
fluctuate by 5 percent or more. The commenter noted that normalized 
operating pressure may include variations that are associated with 
transient or dynamic conditions, such as gas surge from multi-phase 
slugging during normal operations. The commenter requested 
clarification as to the requirement to reestablish an operating 
pressure range when normalized operating pressure changes by 5 percent. 
The commenter also recommended modifying Sec.  250.852(a)(2) to require 
pressure recording devices to be used to establish new operating 
pressure ranges for required flowline or header PSH/PSL sensors at any 
time the normalized operating pressure changes are outside the 
parameters of Sec.  250.852(b)(1).
    Response--As previously discussed, BSEE has determined that the 5 
percent (or 50 psig, whichever is greater) threshold is appropriate 
because it will both help prevent nuisance shut-ins (through more 
frequent resetting of operating pressure ranges) and provide earlier 
warning of potentially dangerous conditions that may require action to 
prevent a safety or environmental incident. In addition, the 5 percent 
threshold is consistent with the 5 percent level pressure tolerance 
levels for PSHL sensors under API RP 14C. (However, if any operator 
believes that its operating pressures may change by more that 5 percent 
under normal flow conditions, and that it should use a different 
threshold for establishing a new pressure range, it may request 
approval for use of an alternate procedure under existing Sec.  
250.141.) As requested by the commenter, however, BSEE has clarified 
the revised final paragraph (a)(2) to provide additional clarity 
regarding the use of pressure recording devices to establish new 
operating pressure ranges.
Relief Valves
    Comment--A commenter suggested revising the language of proposed 
Sec.  250.852(c)(1) to allow for a relief valve which vents into the 
platform flare scrubber or some other location approved by the District 
Manager that is designed to handle, without liquid-hydrocarbon carry-
over to the flare, the maximum anticipated flow of hydrocarbons that 
may be relieved to the vessel.
    Response--BSEE agrees with this comment and has revised the final 
regulation, by removing the word ``liquid'' to ensure the flare 
scrubber is designed to handle the maximum anticipated flow of all 
hydrocarbons.
Qualification Tests
    Comment--A commenter suggested revising the language in proposed 
Sec.  250.852(e)(1) to allow designs to be verified through 
qualification tests since flexible design methodology is proprietary 
and the manufacturers will not release the design methodology to an 
independent verification agent (IVA).
    Response--The suggested changes are not necessary. The design 
methodology is contained in API Spec. 17J, Specification for Unbonded 
Flexible Pipe, which has already been incorporated in existing Sec.  
250.803 for flowlines on floating platforms, and which is nearly 
identical to the requirements contained in final Sec.  250.852(e)(1). 
The existing regulation, like this final rule, specifies the type of 
manufacturer documentation, such as design reports and IVA 
certificates, that operators must review. BSEE is not aware that the 
concern raised by the commenter has been a significant issue under the 
existing regulations.
Pipeline Risers
    Comment--A commenter requested clarification on this section, 
asserting that the proposed requirements in paragraphs (g) and (h) were 
somewhat unclear since they first refer to a ``single pipeline riser'' 
on the platform and then refer to ``each riser'' on the platform.
    Response--No changes are necessary. Both paragraphs (g) and (h) 
address situations involving multiple subsea sources (wells or 
pipelines) that tie into a single pipeline riser or multiple risers on 
a platform. If a single flow safety valve (FSV) on the platform to 
protect multiple subsea pipelines or wells that tie into a single 
pipeline riser, each riser may have its own FSV (as provided by 
paragraph (g)) and its own PSHL (as provided by paragraph (h)).
Safety Sensors (Sec.  250.853)
    Section summary--The contents of existing Sec.  250.803(b)(3), 
pertaining to safety sensors, have been moved to final Sec.  250.853, 
and revised for clarity and to use plain language. This section 
requires that all shutdown devices, valves, and pressure sensors 
function in a manual reset mode; that sensors with integral automatic 
resets be equipped with appropriate devices to override the automatic 
reset mode; and that all pressure sensors be equipped to permit testing 
with an external pressure source.
    Regulatory text changes from the proposed rule--BSEE deleted the 
proposed requirement that all level sensors on new vessel installations 
be equipped to permit testing through an external bridle.
    Comments and responses--BSEE received public comments on this 
section and responds to those comments as follows:
Level Sensors on External Bridles
    Comment--A commenter asserted that the proposed requirement, in 
paragraph (d), that level sensors be located on an external bridle 
(rather than directly on the vessel) is unnecessary, as long as a means 
of testing the sensor without a level bridle is available. The 
commenter stated that fouling or foaming services may cause external 
bridle sensors to misread levels in some services. The commenter added 
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 are evaluating using ultrasonic, optical, 
microwave, conductive, or capacitance sensors. However, the commenter 
asserted, that these sensors do not utilize bridles. The commenter 
requested that BSEE remove paragraph (d) from the new regulations or 
revise this section to allow for new sensor technology that does not 
utilize bridles.
    Response--BSEE disagrees with the commenter. Sensor testing 
equipment built according to API standards, which are incorporated by 
reference into BSEE's regulations, should be able to meet this 
provision. Moreover, an operator that wants to use alternate technology 
that is incompatible with bridles can propose alternate approaches 
through the DWOP process

[[Page 61885]]

or seek approval from BSEE under Sec.  250.141. BSEE does not need to 
refer to those options in this section. However, BSEE has removed 
proposed paragraph (d) from the final rule because BSEE can address 
level sensors adequately using existing regulatory processes, such as 
the DWOP, and we do not need to specify uses and conditions of such 
sensors in this regulation.
Floating Production Units Equipped With Turrets and Turret-Mounted 
Systems (Sec.  250.854)
    Section summary--Final Sec.  250.854 establishes a new requirement 
for floating production units equipped with turrets and turret-mounted 
systems. The operator will be required to integrate the auto slew 
system with the safety system, such that the production processes 
automatically shut-in and release the buoy. Specifically, the safety 
system must immediately initiate a process system shut-in, in 
accordance with final Sec. Sec.  250.838 and 250.839, and release a 
buoy to prevent a spill and damage to the subsea infrastructure when 
the auto slew mode is activated and there is a ship heading/position 
failure or the rotational limits of the clamped buoy are exceeded.
    This new section will also require floating production units with 
swivel stack arrangements to be equipped with a leak detection system 
for the portion of the swivel stack containing hydrocarbons. The leak 
detection system will be required to be tied into the production 
process surface safety system allowing for automatic shut-in of the 
system.
    Regulatory text changes from the proposed rule--BSEE did not make 
any significant changes to this section in the final rule.
    Comments and responses--BSEE received public comments on this 
section and responds to those comments as follows:
Performance Standards for Leak Detection
    Comment--A commenter acknowledged that leak detection requirements 
for floating productions units are an improvement, but asserted that 
BSEE should prohibit the use of floating production units for long-term 
production in the Arctic OCS.
    Response--BSEE disagrees with prohibiting the use of floating 
production units for long-term production in the Arctic as this would 
prematurely, and potentially unnecessarily, limit long-term options for 
development in the Arctic. Moreover, an operator must demonstrate that 
any proposed production unit is suitable for its operating environment. 
Under final Sec.  250.800(a), all oil and gas production safety 
equipment must be designed, installed, used, maintained, and tested to 
ensure the safety and protection of the human, marine, and coastal 
environments. Final Sec.  250.800(a) also requires that, for production 
safety systems operated in subfreezing climates, the operator must 
account for floating ice, icing, and other extreme environmental 
conditions that may occur. In addition, as previously discussed, BSEE 
may address Arctic-specific issues in future rulemakings, guidance or 
other documents.
Riser Disconnects
    Comment--A commenter stated that the mooring is designed to retain 
a vessel on location and protect the risers, which should be flushed 
and/or purged prior to disconnect during a planned process. The 
commenter then asserted that the proposed requirements in this section 
could reduce the safety of that system.
    Response--BSEE does not agree with the suggestion that the 
requirements in this section could make the disconnect system less 
safe. However, BSEE recognizes that, for each floating production 
system with disconnectable turrets and a turret-mounted system, the 
system configuration and disconnect process will be unique. BSEE also 
understands that there are distinctions between an emergency disconnect 
and a planned disconnect, and that there are personnel safety concerns 
during any disconnect that the operator must address. Accordingly, BSEE 
will continue to evaluate the disconnect process on a case-by-case 
basis as part of the initial planning and review of a facility's plans 
and systems under a DWOP. In addition, as a condition of approval in 
the DWOP, BSEE may require the operator to demonstrate the disconnect 
system once per year.
Leak Detection
    Comment--A commenter suggested revising the language of proposed 
Sec.  250.854(b), asserting that, on many swivel stacks with leak 
detection systems, the rate of a hydrocarbon leak, not the detection of 
a hydrocarbon leak, is the criterion for an automatic shut-in.
    Response--BSEE does not agree that the commenter's recommended 
changes are necessary. While BSEE agrees that the use of some type of 
system to detect and contain a leak is appropriate, a catastrophic 
failure must initiate a process system shut-in. However, a seal failure 
that causes a leak into the production system, which is contained, will 
not require an automatic shut-in. This provision protects against a 
scenario in which those internal seals have failed in such a way that a 
leak external to the production system (i.e., a containment failure) 
occurs. This is an abnormal condition and, to protect safety and the 
environment, the system needs to automatically sense such a leak and 
shut-in.
Emergency Shutdown (ESD) System (Sec.  250.855)
    Section summary--The contents of existing Sec.  250.803(b)(4), 
pertaining to ESD systems, have been moved to final Sec.  250.855. 
Existing Sec.  250.803(b)(4) provides that only ESD stations at a boat 
landing may utilize a loop of breakable synthetic tubing in lieu of a 
valve. The final rule clarifies that the breakable loop in the ESD 
system is not required to be physically located on the boat landing; 
however, in all instances it must be accessible from a vessel adjacent 
to or attached to the facility. The final rule also requires that a 
schematic of the ESD, indicating the control functions of all safety 
devices for the platforms, must be kept on the platform, at the field 
office nearest the OCS facility, or at another location conveniently 
available to the District Manager for the life of the facility.\23\ The 
final rule also introduces requirements for electronic ESD stations and 
ESD components.
---------------------------------------------------------------------------

    \23\ The purpose of the full ESD schematic is to enable BSEE to 
confirm the design. This detailed schematic is not the same as the 
safety equipment and layout drawing that indicates the locations of 
the ESD stations and that is submitted to BSEE with production 
system applications. BSEE expects that a copy of the safety 
equipment and layout drawing will continue to be retained on the 
floating production facility for potential use by first responders 
or others in an emergency.
---------------------------------------------------------------------------

    Regulatory text changes from the proposed rule--BSEE revised 
paragraph (a) in the final rule to clarify requirements of the ESD 
stations, to ensure the stations function and are identified properly. 
BSEE also revised this paragraph to respond to comments and to better 
align the regulation with incorporated standards. As provided in 
section C.1 of API RP 14C, incorporated in this section, the final rule 
also requires that: the electric ESD stations be wired as ``de-energize 
to trip'' circuits or as supervised circuits; all ESD components be 
high quality and corrosion resistant; and ESD stations be uniquely 
identified. BSEE also clarified the proposed requirement that a 
breakable loop, if one is used, be accessible ``from a boat;'' the 
final regulation requires that the breakable loop must be accessible 
``from a vessel adjacent to or attached to the facility.''

[[Page 61886]]

    Comments and responses--BSEE received one comment on this section 
and responds as follows:
ESD on Boat Landings
    Comment--A commenter stated the proposed rule references only 
pneumatic-type valves, while current technology incorporates electronic 
switching devices. The commenter asserted that an ESD device on a boat 
landing can be either a breakable loop for pneumatic systems or a 
stiffen ring on an electronic switch that can be actuated using a boat 
hook.
    Response--BSEE agrees with the commenter's observation that the 
proposed rule was limited to pneumatic-type valves and did not address 
the boat landing ESD. In the final rule, BSEE has revised this section 
to better reflect relevant language in the incorporated API RP 14C 
(section C.1) and to require that the ESD stations be uniquely 
identified. Because it is critical that the ESD stations be clearly 
recognizable and functional during an emergency, BSEE wants to 
emphasize this requirement.
Engines (Sec.  250.856)
    Section summary--The requirements in existing Sec.  250.803(b)(5), 
pertaining to engine exhaust and diesel engine air intake and shutdown 
devices, have been moved to final Sec.  250.856 and rewritten for 
clarity and plain language. BSEE also clarified this section of the 
final rule by listing the types of diesel engines that do not require a 
shutdown device .
    Regulatory text changes from the proposed rule--BSEE added the 
parenthetical ``(i.e., overspeed)'' after the word ``runaway'' in final 
paragraph (b) to clarify what is meant by a runaway, since the term 
``overspeed'' is commonly used and understood in the marine industry.
    Comments and responses--BSEE received public comments on this 
section and responds to those comments as follows:
Mechanical Air Intake Device
    Comment--A commenter stated that diesel engines usually have an 
overspeed device that will shut down the run-away engines except when a 
firewater pump and emergency generator is started due to an emergency 
shutdown or confined entry air supply. The commenter then asked whether 
this section would require use of a mechanical air intake device in 
addition to the overspeed sensor.
    Response--Overspeed sensors are always required,. In addition, 
under final Sec.  250.856, the operator must equip diesel engine air 
intakes with a device to shutdown the engine in the event of a runaway 
(i.e., overspeed), except for certain identified categories of diesel 
engines. The final rule also requires that diesel engines that are 
continuously attended be equipped with either remotely-operated manual 
or automatic shutdown devices and that diesel engines that are not 
continuously attended be equipped with automatic shutdown devices.
Jurisdiction
    Comment--A commenter recommended that paragraph (b) of this section 
be limited to fixed platforms only. According to the commenter, under 
item 12 of MOA OCS-04 between the Minerals Management Service (MMS) 
(now BSEE) and the USCG, firefighting safety equipment and systems on 
floating offshore facilities are under the responsibility of the USCG, 
as are requirements for emergency power sources on floating offshore 
facilities.
    Response--As previously explained, these regulations only apply to 
operations that are under BSEE authority. In addition, paragraph (b) is 
essentially a recodification of longstanding BSEE regulations, under 
which the commenter's jurisdictional questions have not proven to be an 
issue.
Glycol Dehydration Units (Sec.  250.857)
    Section summary--The final rule moves the contents of existing 
Sec.  250.803(b)(6), pertaining to safe operations of glycol 
dehydration units, to final Sec.  250.857. The final rule adds new 
requirements for FSVs and shutdown valves (SDVs) on the glycol 
dehydration unit.
    Regulatory text changes from the proposed rule--BSEE did not make 
any significant changes to this section.
    Comments and responses--BSEE received public comments on this 
section and responds to those comments as follows:
Venting the Glycol Regenerator
    Comment--One commenter noted that the proposed regulations require 
the installation of a pressure relief valve on the glycol regenerator 
(reboiler) to prevent over-pressurization, and require that valve to be 
vented in a non-hazardous manner. The commenter suggested that the 
regulation should provide specific instructions on how the operator can 
vent the glycol regenerator in a non-hazardous manner. The commenter 
also noted that BSEE requested additional comments on opportunities to 
limit emissions from OCS production equipment. The commenter 
recommended that BSEE require emission control systems to be installed 
on OCS glycol dehydration units or require the use of desiccant 
dehydrators (where technically feasible). The commenter also 
recommended that the regulations be revised to require OCS operators to 
install flash tank separators, optimize the glycol circulation rate, 
and reroute the skimmer gas.
    Response--The provision of the final rule requiring that the relief 
valve discharge must be vented in a non-hazardous manner is a 
recodification of longstanding BSEE regulations. The commenter is 
asking instead for a prescriptive requirement on how the operator 
should vent the glycol regenerator in a non-hazardous manner. There are 
many ways this can be accomplished. The commenter itself described 
three different approaches to achieving this. However, BSEE does not 
want to limit the options to just a few approaches; rather, the final 
rule sets a performance goal and allows the operator to decide the best 
approach to achieve the required goal. This performance-based approach, 
involving the same standards, has worked under the existing regulation.
    BSEE appreciates the commenter's recommendations regarding 
emissions controls and will consider them. BSEE may also consider 
additional measures, such as emission control systems, in the future to 
ensure safety and protect the environment; however, those measures are 
outside the scope of this rulemaking.
Safety Devices
    Comment--One commenter stated that the proposed rule listed some, 
although not all, safety devices for equipment specified in API RP 14C, 
which allows operators to rebut the need for some safety devices 
according to safety analysis checklists The commenter asserted that the 
requirements in this proposed regulation may restrict that option. The 
commenter suggested deleting these requirements and referencing the 
requirements in API RP 14C, as in proposed Sec.  250.865(a). The 
commenter also suggested that the requirement in proposed Sec.  
250.857(c) regarding installation of the SDV should be required only 
for new designs or modifications to glycol dehydration units.
    Response--No changes to the final rule are necessary. Requiring two 
valves on the glycol dehydration units, as proposed, helps ensure 
safety of the operations. The requirements of this section are in 
addition to API RP 14C, which requires a shutdown valve, but

[[Page 61887]]

does not specify the location of the shutdown valve. The final rule 
requires that the shutdown valve be installed as near as practical to 
the glycol tower, to ensure safety and protect the environment. Placing 
the shutdown valve closer to the glycol tower reduces the amount of 
product that may be released to the environment in the event of damage 
to the system.
Gas Compressors (Sec.  250.858)
    Section summary--BSEE moved the contents of existing Sec.  
250.803(b)(7), pertaining to gas compressor operations, to final Sec.  
250.858. BSEE also revised those provisions for clarity and plain 
language. Final paragraph (a) establishes certain equipment 
requirements consistent with API RP 14C for gas compressors. Paragraph 
(b) requires the use of pressure recording devices to establish a new 
operating pressure range after an operating pressure change greater 
than 5 percent or 50 psig, whichever is higher. Final paragraph (c) 
contains a table of pressure sensor shut-in settings.
    Regulatory text changes from the proposed rule--Based on comments 
received, BSEE revised final paragraph (a)(2) to clarify that the 
temperature safety high (TSH) must be equipped in the discharge piping 
of each compressor cylinder or case discharge. BSEE also revised final 
paragraph (b) to clarify the requirements for establishing new 
operating pressure ranges after specified pressure changes, consistent 
with other sections of the final rule, in response to comments seeking 
clarification on the subject.
    After consideration of various issues raised by commenters, BSEE 
omitted proposed paragraph (c), which would have provided an exception 
to the installation of PSHs and PSLs for vapor recovery units (VRUs) 
when the system is capable of being vented to the atmosphere, from the 
final rule.
    BSEE added a new paragraph (c) to the final rule that includes the 
contents of proposed paragraphs (b)(1) through (b)(3). New paragraph 
(c) also clarifies that initial set points for pressure sensors must be 
set utilizing gauge readings and engineering design. These changes were 
made to make the requirements for operating pressure ranges and 
pressure sensors consistent with similar provisions in other sections 
of the final rule.
    Comments and responses--BSEE received public comments on this 
section and responds to those comments as follows:
Temporary Flaring of Gas-Well Gas
    Comment--A commenter suggested revising the language in proposed 
Sec.  250.858(a)(3) to allow temporary flaring of gas-well gas in the 
event of an upset condition within allowable flare limits. The 
commenter suggested that gas-well gas affected by the compressor's 
closure of the automatic SDV could be shut-in manually or temporarily 
diverted to a flare if compliant with Sec. Sec.  250.1160 through 
250.1161.
    Response--As the commenter noted, temporary flaring of gas-well gas 
is directly addressed in part 250, subpart K (Sec. Sec.  250.1160 and 
250.1161), which sets the conditions for flaring or venting gas-well 
gas. However, after consideration of issues related to this comment, 
BSEE agrees with the commenter that allowing gas-well gas to be flared 
or vented in the event of an upset condition with a gas compressor can 
be done consistently with existing Sec. Sec.  250.1160 and 250.1161. 
Accordingly, BSEE has changed the language in final Sec.  250.858(a)(3) 
to clarify that gas-well gas can be diverted to flare or vent in 
accordance with the requirements Sec. Sec.  250.1160 and 250.1161.
    However, BSEE has deleted proposed paragraph (c), which would have 
created a general exception to the installation of PSHs and PSLs for 
VRUs when the system is capable of being vented to the atmosphere. BSEE 
deleted that proposed exception because, after considering all the 
issues raised by commenters, BSEE realized that, for some VRUs, the 
volume of gas from the tank could create a suction pressure exceeding 5 
psig, resulting in an over-pressure that could cause the VRU to burst. 
Therefore, BSEE decided that it needs to confirm that the system is 
operating at 5 psig before approving a system that could be vented to 
the atmosphere without a PSH and PSL installed.
Compressor Skids
    Comment--A commenter noted that the proposed regulation did not 
compensate for lower operating ranges throughout the compressor skid, 
especially when considering VRUs. The commenter noted that it is highly 
unlikely that a VRU would have an operating change of 50 psig or 
greater and expressed concern that the proposed requirement for 
compressor discharge sensors did not provide for normalized operating 
ranges. The commenter questioned the purpose of the proposed rule, 
since the commenter asserted that operators are currently permitted by 
BSEE to establish new operating ranges at less than the proposed 
pressure change threshold of 50 psig or 5 percent, whichever is 
greater, to help prevent nuisance shut-ins.
    Response--BSEE disagrees with the suggestion that this regulation 
will not help prevent nuisance shut-ins. As previously discussed in 
response to similar comments, establishing new normalized operating 
pressure ranges, whenever actual operating pressure changes by the 
amounts specified in this provision, will help prevent nuisance shut-
ins. Operating pressure ranges need to be re-established periodically, 
and sensors need to be reset to reflect normal changes in operating 
pressures. If not, shut-ins are more likely to occur because the 
unadjusted pressure range and sensors could indicate an abnormal 
condition when a pressure change would otherwise be considered routine 
and within the adjusted pressure range. In addition, as previously 
explained, BSEE has set the threshold for requiring the establishment 
of new pressure ranges at levels that provide a reasonable safety 
cushion. However, BSEE agrees with the commenter in that an operator 
may choose to set a pressure change threshold below 50 psig or 5 
percent in order to re-set the normalized operating pressure range more 
frequently (and thus further reduce the possibility of a nuisance shut-
in) than would otherwise be required under this regulation.
Centrifugal Compressors
    Comment--A commenter noted that the proposed section used language 
suggesting that it would apply to devices on reciprocating compressors 
and recommended that BSEE include an additional section for centrifugal 
compressors since they appear to comply with API RP 14C as well.
    Response--BSEE revised this section to better conform to the 
language of API RP 14C which does not distinguish between the different 
types (i.e., centrifugal or reciprocating) of compressors. The 
determination as to the types of protective equipment required under 
API RP 14C applies regardless of the type of compressors. If a specific 
installation does not meet the criteria for a defined gas compressor 
component under API RP 14C, the operator should consult the District 
Manager to determine what equipment under API RP 14C is required.
Firefighting Systems (Sec.  250.859)
    Section summary--BSEE moved the contents of existing Sec.  
250.803(b)(8), pertaining to firefighting systems, to final Sec. Sec.  
250.859, 250.860, and 250.861

[[Page 61888]]

and revised the existing requirements to include a number of additional 
requirements, including several provisions contained in NTL No. 2006-
G04, ``Fire Prevention and Control Systems.''
    Final Sec.  250.859(a) clarifies the requirements for firefighting 
systems on fixed facilities only, and includes requirements from 
existing Sec.  250.803(b)(8)(i) and (ii), as proposed. Final paragraph 
(a) also requires, as proposed, that within 1 year after publication of 
the final rule, operators must equip all new firewater pump drivers 
with capabilities for automatic starting upon activation of the ESD, 
fusible loop, or other fire detection systems. Final paragraph (a) also 
requires that, for electric-driven firewater pump drivers, operators 
must install an automatic transfer switch to cross over to an emergency 
power source in order to maintain at least 30 minutes of run time in 
the event of a loss of primary power. The final rule also specifies 
requirements for routing power cables, or conduits with wires 
installed, between the fire water pump drivers and the automatic 
transfer switch away from hazardous-classified locations that can cause 
flame impingement.
    Final paragraphs (a)(3) and (4) include the requirements of former 
Sec.  250.803(b)(8)(iv) and (v) regarding firefighting system diagrams 
and subfreezing climate suitability, respectively. Final paragraph 
(a)(5) requires operators to obtain approval from the District Manager 
before installing any firefighting system. Final paragraph (a)(6) 
requires that all firefighting equipment located on a facility be in 
good working order.
    Final paragraph (b) was added to clarify the requirements for 
firewater systems to protect all areas where production-handling 
equipment is located on floating facilities. This section also requires 
the operator to install a fixed water spray system in enclosed well-bay 
areas where hydrocarbon vapors may accumulate and provides that the 
firewater system must conform to applicable USCG requirements.
    Final paragraph (c) specifies that if an operator is required to 
maintain a firewater system which becomes inoperable, the operator 
either must shut-in its production operations while making the 
necessary repairs or, for fixed facilities, request that the 
appropriate District Manager grant a departure under Sec.  250.142 to 
use a firefighting system using chemicals on a temporary basis for a 
period up to 7 days while the necessary repairs to the firewater system 
are made. This paragraph also clarifies that, for fixed facilities, if 
the operator is unable to complete repairs during the approved time 
period because of circumstances beyond its control, the District 
Manager may grant extensions to the approved departure for periods up 
to 7 days.
    Regulatory text changes from the proposed rule--This section was 
revised, based on comments received, to clarify that it applies to 
facilities and areas subject to BSEE authority, as explained in the 
following responses to specific comments. In addition, the word 
``BSEE'' was removed before the ``District Manager'' throughout the 
section for consistency and because it was superfluous. BSEE also 
reworded and reorganized several provisions for greater clarity and to 
avoid ambiguity and potential confusion.
    Comments and responses--BSEE received public comments on this 
section and responds to those comments as follows:
Redundancy in Firefighting Systems
    Comment--A commenter noted that firefighting systems have 
redundancy and that they can be fully functional, and redundant, even 
when some equipment is down for repair. The commenter asserted that 
this rule should make provisions for this to avoid a facility being 
deemed out of compliance when some components of the firewater system 
are being repaired, even though the system as a whole is still 
functional.
    Response--BSEE disagrees. To safely conduct operations the 
firefighting systems must be fully functional. Redundancy is required 
in case the system fails when needed, not to provide coverage for 
repairs.
Jurisdiction for Fire Protection and Firefighting Systems
    Comment--A commenter asserted that, for both fixed and floating 
facilities, USCG has jurisdiction over most of the fire protection, 
detection, and extinguishing system areas, except for the production 
handling area. The commenter suggested that the regulations should be 
limited to this area only, and that any proposed requirements for 
firefighting in other areas, including well bays, should be removed, 
along with requirements for fire water pumps. The commenter also 
requested that all discussion of firewater systems, chemical 
firefighting systems, and foam systems should be clarified to state 
that they apply only to the production-handling area. The commenter 
asserted that USCG has jurisdiction for fire and smoke detection, so 
those requirements should be limited to interfaces with BSEE systems 
(such as the ESD system).
    Response--This comment was also made in reference to Sec. Sec.  
250.842 and 250.861. As discussed in response to other comments, BSEE's 
regulations apply only to operations and systems that are under BSEE's 
authority. (See discussion in part IV.B.2 of this document regarding 
BSEE's jurisdiction under the heading ``BSEE and U.S. Coast Guard 
(USCG) Jurisdiction,'' including discussion of BSEE-USCG MOAs 
describing situations in which BSEE and USCG share responsibility for 
various aspects of firefighting.)
    To further clarify this point, BSEE has revised paragraph (a) in 
the final rule so that the requirements expressly apply to areas where 
production-handling equipment is located on fixed facilities. BSEE also 
revised final paragraph (b) to clarify that the requirements in that 
paragraph apply to areas on floating facilities where production-
handling equipment is located. In addition, final paragraph (b) 
requires the firewater system to conform to USCG requirements for 
firefighting systems on floating facilities. Further, BSEE revised 
final paragraph (c) to clarify that the provision allowing an operator 
to request permission from BSEE to temporarily use a chemical 
firefighting system, in the event the firewater system becomes 
inoperable, applies to fixed facilities only. In addition, as discussed 
in part IV.C, BSEE has revised the firefighting-related requirements of 
final Sec. Sec.  250.859 through 250.862 to further clarify that they 
apply to areas and systems under BSEE's authority, and to confirm that 
operators must also comply with applicable USCG regulations. Section 
250.842 already clearly states that it applies to the production safety 
system.
Arctic Requirements
    Comment--A commenter suggested that BSEE work with Arctic 
firefighting experts to develop firefighting system regulations to 
address suppression of hazardous material, electrical, flammable 
liquid, and combustible liquid fires that may occur at Arctic OCS 
operations and that BSEE should include those requirements in the 
regulation. The commenter noted that BSEE proposed a number of 
improvements to firefighting systems for OCS operations, including a 
proposed improvement at Sec.  250.859 that requires OCS facilities to 
be shut-in if the firewater system becomes inoperable. However, the 
commenter asserted that the regulations do not appear to address 
specific firefighting requirements

[[Page 61889]]

needed for the Arctic. The commenter stated, as an example, that wet 
pipe fire water systems (i.e., systems continuously charged with fire 
water) are not used in Arctic operations because of the risk of 
freezing and pipe burst. The commenter also discussed the potential 
advantages of dry pipe, dry chemical, and dry powder fire extinguishing 
systems.
    Response--BSEE understands that the Arctic may present unique 
operating conditions. Final Sec.  250.859(a)(4) includes firewater 
system requirements for operations in subfreezing climates, including a 
requirement to submit evidence demonstrating that the firefighting 
system is suitable for subfreezing conditions. Any permit application 
must address the specific operating conditions where the activity is 
taking place, and BSEE considers those conditions when reviewing a 
permit application. Any firefighting system proposed for use in the 
Arctic OCS, must be able to perform in the environmental conditions 
found in the Arctic. Specific requirements for chemical firefighting 
systems are found in Sec.  250.860 of this rulemaking. However, as 
already explained in response to other comments, BSEE expects to 
address other Arctic-specific issues in the future through a variety of 
mechanisms, potentially including separate rulemakings, guidance, or 
other documents.
Redundant Power Source
    Comment--A commenter asserted that BSEE would be correct to require 
an alternative power source for firefighting systems because, if the 
main engine room, the main engines, or associated power cables are 
disrupted by fire, the firefighting systems may become inoperable. The 
commenter asserted that an alternative power source, preferably placed 
in a location separate from the main engine room should be available to 
provide alternative power to firefighting equipment during an 
emergency.
    Response--BSEE generally agrees with the comment and has finalized 
paragraph (a)(2) with only minor wording and organizational changes. 
BSEE notes that, if an electric firewater pump is based on a fuel gas 
system, the personnel on the facility may not have adequate time for 
egress if they need to shut down the generator. Accordingly, the final 
rule requires an emergency power source with an automatic transfer 
switch and requires that fuel or power for firewater pump drivers must 
be available for at least 30 minutes of run time during a platform 
shut-in. The operator must also install an alternate fuel or power 
supply to provide for this pump operating time, if needed. This is 
consistent with the provisions in the proposed rule.
API RP 14G and Floating Facilities
    Comment--A commenter agreed that the inclusion of certain proposed 
provisions would enhance safety, but asserted that the incremental 
benefits of incorporating all of API RP 14G standard would not justify 
the increased costs. The commenter stated that API RP 14G does not 
offer a ``cookbook'' method of designing and installing a complete 
firefighting system; instead, API RP 14G offers recommended criteria 
for whatever firefighting system the operator chooses to install. The 
commenter asserted that the proposed rule did not account for existing 
systems that were approved under the current regulations and under 
current approval and inspection policies. The commenter also asserted 
that the proposed rule did not take into account potential conflicts 
with USCG firefighting requirements for floating facilities.
    The commenter recommended that BSEE separate firefighting 
requirements for fixed facilities from those for floating facilities 
since the latter are driven mainly by the USCG. The commenter also 
recommended revisions to clarify the separate requirements for fixed 
facilities and floating facilities and to account for currently 
approved systems in service.
    Response--BSEE agrees with several of the commenter's recommended 
changes and has revised this section accordingly. BSEE also revised 
final paragraph (a) to state that the ``firewater system'' on fixed 
facilities must conform to API RP 14G, in order to clarify that 
compliance with API RP 14G is required only for the firewater systems 
and not for all firefighting systems, as implied by the proposed 
language. (This revision is also consistent with the existing 
regulations.)
    As suggested by the commenter, BSEE also revised the final rule to 
clarify the separate requirements for firefighting systems on fixed 
facilities and floating facilities. These changes help ensure that 
there are no conflicts with the USCG for firefighting systems by 
focusing this final section on areas where production-handling 
equipment is located and on enclosed well-bay areas where hydrocarbon 
vapors may accumulate, and by referring to the need to comply with USCG 
requirements for floating facilities.
Chemical Firefighting System (Sec.  250.860)
    Section summary--Existing Sec.  250.803(b)(8)(iii) allows the use 
of a chemical firefighting system in lieu of a water-based system if 
the District Manager determines that the use of a chemical system 
provides equivalent fire-protection control. Final Sec.  250.860 
recodifies this concept and includes a number of additional details 
from NTL No. 2006-G04 in order to update BSEE's regulations pertaining 
to firefighting. This final rule specifies requirements regarding the 
use of chemical-only systems on fixed platforms; specifically, major 
platforms, minor manned platforms, or minor unmanned platforms. The 
final rule also defines the terms ``major,'' ``minor,'' ``unmanned,'' 
and ``manned'' platforms.
    Final Sec.  250.860(a) addresses the potential use of a chemical-
only firefighting system, in lieu of a water-based system, on any fixed 
platform that is both minor and unmanned. Final paragraph (a) 
authorizes the use on such platforms of either of two types of portable 
dry chemical units, as long as the operator ensures that the unit is 
available on the platform when personnel are on board. A facility-
specific authorization from BSEE would not be required under this 
paragraph.
    Paragraph (b) of the final rule allows use of a chemical 
firefighting system, in lieu of a water-based system, on any fixed 
major platform or minor manned platform, if the District Manager 
determines that the use of a chemical-only system provides equivalent 
fire-protection control and would not increase the risk to human 
safety. To provide a basis for the District Manager's determination 
that the use of a chemical system provides equivalent fire-protection 
control, final paragraph (c) requires an operator to submit a 
justification addressing the elements of fire prevention, fire 
protection, fire control, and firefighting on the platform. Final 
paragraph (c) also requires the operator to submit a risk assessment 
demonstrating that a chemical-only system would not increase the risk 
to human safety. That paragraph lists the items that the operator must 
include in the risk assessment.
    Final Sec.  250.860(d) addresses the documentation that an operator 
must maintain or submit for the chemical firefighting system. This 
paragraph also clarifies that, after the District Manager approves the 
use of a chemical-only fire suppressant system, if the operator intends 
to make any significant change to the platform (such as placing a 
storage vessel with a capacity of 100

[[Page 61890]]

barrels or more on the facility, adding production equipment, or 
planning to man an unmanned platform), the operator must seek BSEE 
District Manager approval.
    Regulatory text changes from the proposed rule--BSEE revised this 
section to clarify that it applies only to fixed platforms. Throughout 
this section, ``BSEE'' was removed before ``District Manager'' for 
consistency. In addition, BSEE reorganized and restructured the final 
rule to make it clearer and easier to understand.
    Comments and responses--BSEE received public comments on this 
section and responds to those comments as follows:
Limit to Fixed Platforms
    Comment--A commenter recommended that this paragraph be limited to 
fixed platforms only because, in accordance with item 12 of the MOA 
OCS-04 between MMS (now BSEE) and the USCG, firefighting safety 
equipment and systems on floating offshore facilities are the 
responsibility of the USCG.
    Response--As already explained in response to other comments, 
BSEE's regulations only apply to operations that are under BSEE 
authority. However, BSEE has added language to the beginning of this 
section in the final rule to clarify that it applies to fixed platforms 
only. (See part IV.B.2 for a more detailed discussion of BSEE's and 
USCG's jurisdiction.)
Risk Assessment Criteria
    Comment--A commenter asserted that BSEE was proposing to codify 
existing NTL No. 2006-G04, but that the proposed rule did not indicate 
how the proposed risk assessment criteria will be evaluated. The 
commenter understands that BSEE developed a risk matrix for use in 
evaluating an operator's risk assessment. The commenter recommended 
that BSEE include the risk matrix with the risk assessment criteria in 
the final rule in order to save both the operator and BSEE time in 
preparing and reviewing, the request.
    Response--No changes are necessary. The final rule includes the 
categories of information required for BSEE's risk assessment from NTL 
No. 2006-G04, ``Fire Prevention and Control Systems.'' The operator 
must address those categories; however, BSEE does not believe it is 
necessary or appropriate to include the requested details in this final 
rule. Such details may be better addressed in an internal BSEE guidance 
document, which may be revised as circumstances warrant.
Foam Firefighting Systems (Sec.  250.861)
    Section summary--Final Sec.  250.861 establishes requirements for 
the use of foam firefighting systems. Under the final rule, when foam 
firefighting systems are installed as part of a firefighting system, 
the operator must annually: (1) Conduct an inspection of the foam 
concentrates and their tanks or storage containers for evidence of 
excessive sludging or deterioration; and (2) send tested samples of the 
foam concentrate to the manufacturer or authorized representative for 
quality condition testing and certification. The final rule specifies 
that the certification document must be readily accessible for field 
inspection. In lieu of sampling and certification, the final rule 
allows operators to replace the total inventory of foam with suitable 
new stock. The rule requires that the quantity of concentrate must meet 
design requirements, and that tanks or containers must be kept full but 
with additional space allowed for expansion.
    Regulatory text changes from the proposed rule--BSEE revised this 
section in the final rule to clarify that it is applicable to 
firefighting systems that protect production handling areas. This 
revision is based upon comments received about jurisdictional concerns.
    Comments and responses--BSEE received public comments on this 
section and responds to those comments as follows:
Limit to Fixed Platforms
    Comment--A commenter recommended that this paragraph be limited to 
fixed platforms only. The commenter asserted that item 12 of the MOA 
OCS-04 between MMS (now BSEE) and the USCG provides that firefighting 
safety equipment and systems on floating offshore facilities are the 
responsibility of the USCG.
    Response--BSEE does not agree that the recommended change is 
necessary. As previously explained, these regulations apply only to 
those operations, whether on fixed or floating platforms, that are 
covered by BSEE authority. However, BSEE has revised the final rule to 
clarify that it applies only to production handling areas, which are 
subject to BSEE's authority.
Sample Testing
    Comment--A commenter stated that proposed paragraphs (a) and (b) 
would impose new requirements for sending in samples for testing. The 
commenter asserted that this would require additional costs and 
resources to comply but would not add significant value. The commenter 
also stated that other requirements in paragraph (a) would be 
sufficient to ensure the suitability of the foam.
    Response--BSEE does not agree that the testing requirements of this 
section will not add value. Regular testing of the foam concentrate 
will ensure that it does not deteriorate and that it will be effective 
in the event of a fire. If an operator plans for sampling and testing 
in accordance with this section, that process should not add 
significant new costs. For example, the sampling can be arranged to 
coincide with already scheduled trips to and from the facility.
Fire and Gas-Detection Systems (Sec.  250.862)
    Section summary--The contents of existing Sec.  250.803(b)(9) have 
been revised and moved to Sec.  250.862 in the final rule. This section 
establishes requirements pertaining to fire and gas-detection systems. 
Operators must install fire (flame, heat, or smoke) sensors in all 
enclosed classified areas and must install gas sensors in all 
inadequately ventilated, enclosed classified areas. All detection 
systems must be capable of continuous monitoring. A fuel-gas odorant or 
an automatic gas-detection and alarm system is required in enclosed, 
continuously manned areas of the facility which are provided with fuel 
gas. This section incorporates several API standards that operators 
must follow for these systems.
    Regulatory text changes from the proposed rule--BSEE revised this 
section to clarify that it applies only to production processing areas. 
BSEE also clarified that, to the extent compliance with the identified 
industry standards would conflict with an applicable USCG regulation, 
the USCG requirement controls.
    Comments and responses--BSEE received public comments on this 
section and responds to those comments as follows:
Limit to BSEE-Regulated Systems
    Comment--A commenter recommended that this paragraph be limited to 
BSEE regulated safety systems only. The commenter asserted that item 12 
of the MOA OCS-04 between MMS (now BSEE) and the USCG provides that 
fire and smoke detection systems on floating offshore facilities are 
responsibility of the USCG, except where those detection systems 
interface with BSEE regulated safety systems.
    Response--As previously discussed, these regulations apply only to 
operations that are under BSEE's authority. Proposed Sec.  250.862, in 
effect, merely proposed to recodify, with

[[Page 61891]]

limited alterations, longstanding requirements of BSEE regulation that 
existed at the time of the MOA cited by the commenter,\24\ and the 
application of which has not presented jurisdictional issues. 
Nevertheless, BSEE has revised this section of the final rule to 
clarify that it applies only to production processing areas, which are 
under BSEE's authority. BSEE also has revised final paragraph (e) to 
clarify that, in the event compliance with any provision of the 
standards referenced in this section would conflict with any provision 
of an applicable USCG regulation, compliance with the USCG regulation 
controls. BSEE and USCG authority was discussed previously in part 
IV.B.2.
---------------------------------------------------------------------------

    \24\ MOA OCS-04 was revised by BSEE and USCG in January 2016, 
after the proposed rule was published and comments submitted. The 
revised MOA is available at https://www.bsee.gov/sites/bsee.gov/files/memos/internal-guidance/010-2016-moa.pdf.
---------------------------------------------------------------------------

Applicability
    Comment--A commenter suggested revising the requirement for ``gas 
detection systems'' in proposed Sec.  250.862(e) to ``gas detectors,'' 
asserting that there is ``type approval'' in place for gas detectors 
but not for gas detection systems. The commenter also stated that some 
legacy gas detectors do not have approval because they were 
manufactured prior to the approval standard issue date, and recommended 
that BSEE apply the proposed requirement only to new installations. The 
commenter also asserted that the proposed rule could conflict with USCG 
requirements for fire and gas detection systems on floating offshore 
installations.
    Response--The relevant provisions in the final rule are consistent 
with current regulations. The distinction identified by the commenter 
between ``gas detection systems'' and ``gas detectors'' does not 
present an issue under these longstanding requirements; nor should the 
recodification of the existing requirements apply only to new 
installations. In addition, as previously discussed, these regulations 
apply only to operations that are under BSEE's authority. Nonetheless, 
BSEE has revised the final rule to clarify that it applies only to 
production processing areas and that, in the event compliance with any 
provision of the standards would be in conflict with any applicable 
USCG regulation, compliance with the USCG regulation controls.
Electrical Equipment (Sec.  250.863)
    Section summary--The final rule recodifies existing Sec.  
250.803(b)(10) as Sec.  250.863, which pertains to basic requirements 
for electrical equipment and systems. BSEE has revised this provision 
for clarity and plain language.
    Regulatory text changes from the proposed rule--BSEE did not make 
any significant changes to this section.
    Comments and responses--BSEE received public comments on this 
section and responds to those comments as follows:
Limit to BSEE-Regulated Electrical Systems
    Comment--A commenter recommended that this paragraph be limited to 
BSEE-regulated electrical systems only. The commenter asserted that 
item 14 of the MOA OCS-04 between MMS (now BSEE) and the USCG provides 
that electrical systems--other than production, drilling, completion 
well servicing and workover operations--on floating offshore facilities 
are the shared responsibility of BSEE and the USCG, except for 
emergency lighting, power generation and distribution systems, which 
the commenter stated are the sole responsibility of the USCG.
    Response--Final Sec.  250.863, in effect, merely recodifies the 
longstanding requirements of existing Sec.  250.803(b)(10), which was 
in effect at the time the MOA referred to by the commenter was 
developed and the application of which has not presented jurisdictional 
issues. This final rule is not a substantive change to the existing 
regulations, and only applies to operations under BSEE's authority. 
Thus, there is no reason to adopt the commenter's suggested revision.
Erosion (Sec.  250.864)
    Section summary--The final rule moves the contents of existing 
Sec.  250.803(b)(11), pertaining to erosion control, to new Sec.  
250.864.
    Regulatory text changes from the proposed rule--BSEE did not make 
any significant changes to this section in the final rule.
    Comments and responses--BSEE received public comments on this 
section and responds to those comments as follows:
Corrosion Management
    Comment--A commenter observed that this section would be clearer if 
it addressed corrosion monitoring and corrosion control as two separate 
aspects of a corrosion management program. The commenter recommended 
that BSEE require that operators implement erosion monitoring programs 
for wells or fields that have a history of (or could reasonably be 
expected to encounter) erosion due to sand production. The commenter 
asserted that, with this revision, not all fields/wells/leases would 
require an erosion control program.
    Response--The proposed rule did not propose any substantive changes 
to the requirements in the existing regulation. By contrast, the 
commenter's suggested revision would impose new requirements for 
corrosion monitoring and control and erosion monitoring that were not 
part of the proposed rulemaking and are outside the scope of this final 
rule.
Surface Pumps (Sec.  250.865)
    Section summary--Final Sec.  250.865, pertaining to surface pumps, 
contains material from existing Sec.  250.803(b)(1)(iii) related to 
pressure and fired vessels and adds new requirements for pump 
installations. Final paragraph (a) includes a specific requirement to 
equip all pump installations with the protective equipment recommended 
by API RP 14C, Appendix A, section A.7, and final paragraph (b) 
includes a new requirement to use pressure recording devices to 
establish new operating pressure ranges for pump discharge sensors when 
operating pressures change by a specified amount. As noted in the 
proposed rule, the final rule also adds provisions related to the 
operation of PSL and PSH sensors, temperature safety element (TSE), and 
pump pressures.
    Regulatory text changes from the proposed rule--In response to 
comments on similar provisions in other sections of the proposed rule, 
BSEE revised paragraph (b) of the final rule to clarify the 
requirements for establishing a new operating pressure range following 
a change in normalized system pressure. These revisions make final 
paragraph (b) consistent with similar provisions in other sections of 
the final rule.
    BSEE also added new paragraph (c) in the final rule to improve the 
presentation and clarity of the information contained in proposed 
paragraph (b), reformatting that information as a table to be 
consistent with the structure in other sections related to PSLs and 
PSHs, and to clarify that initial set points for pressure sensors must 
be set using gauge readings and engineering design. Final paragraph (c) 
is consistent with the requirements for operating pressure ranges and 
pressure sensors in other sections of the final rule.
    In light of the other revisions made to the proposed section, the 
remaining paragraphs of the proposed rule were redesignated as 
paragraphs (d) through

[[Page 61892]]

(g). BSEE also revised final paragraph (d) to clarify that the PSL must 
be placed into service when the pump discharge pressure has risen above 
the PSL sensing point, or within 45 seconds of the pump coming into 
service, whichever is sooner. In addition, BSEE revised final paragraph 
(g) to insert the phrase ``as appropriate for pump type and service'' 
for additional clarification.
    Comments and responses--BSEE received public comments on this 
section and responds to those comments as follows:
Normalized System Pressure Threshold
    Comment--One commenter declared that a pressure change of 50 psig 
or 5 percent is too low a threshold to require re-running a pressure 
chart and suggested raising the pressure change threshold 100 psig or 
15 percent.
    Response--No changes are necessary. As discussed in response to 
similar comments on other sections, the proposed--and now final--
threshold is consistent with similar requirements in other sections of 
the final rule, and is intended to both reduce the number of nuisance 
shut-ins and to provide a safety ``cushion'' that will give operators 
more time to act in the event the pressure change indicates an actual 
abnormal condition. The commenter's suggestion for a higher threshold, 
by contrast, would not accomplish those goals, as previously discussed, 
and could result in higher risk that an incident will occur.
Applicable Pumps
    Comment--One commenter noted that it was unclear as to what 
``pumps'' the requirement in proposed paragraph (a) would apply. The 
commenter assumed that this provision would apply only to those pumps 
in the production process and to pipeline transfer, small volume 
produced hydrocarbon transfer, or other process fluids transfer pumps 
recognized in API RP 14C. The commenter recommended that BSEE clarify 
this requirement to apply only to those pumps specifically recognized 
in API RP 14C.
    Response--No changes are necessary. This section, by its terms, is 
applicable to the types of surface pumps specified in the section 
heading and addressed by API RP 14C, which is already incorporated in 
longstanding BSEE regulations. BSEE is not requiring operators to 
follow API RP 14C for any surface pumps other than those specified in 
that standard.
Threshold for Pressure Monitoring
    Comment--A commenter claimed that continuous monitoring for a 5 
percent pressure change threshold would be problematic and asserted 
that the proposed regulation would not compensate for lower operating 
ranges, especially when considering pumps that discharge to pressure 
vessels that operate at just above atmospheric service. The commenter 
included an example scenario for a sump pump discharging to a pressure 
vessel, and discussed the effects the proposed requirement would have 
under that scenario.
    Response--No changes are necessary. As previously stated, the 5 
percent pressure change threshold is consistent with the API RP 14C 
pressure tolerance setting for PSHL sensors. Moreover, the thresholds 
established by the rule represent pressure changes at which an operator 
must establish new operating pressure ranges; however, operators may 
use a more conservative approach, by resetting their operating pressure 
ranges following a pressure change that is less than 5 percent or 50 
psig, to account for situations like that raised by the commenter. If 
there are additional concerns about the operating range in a specific 
situation, operators may contact the District Manager for guidance. 
BSEE also added language to final paragraph (b) to clarify the 
requirements for establishing the new pressure range.
    Comment--According to a commenter, most operators do not monitor 
the operating ranges to see if they fluctuate by 5 percent because such 
fluctuations do not typically indicate a change in the maximum 
operating pressure. The commenter stated that current practices for 
ensuring pressures are below the maximum operating pressure are 
sufficient to ensure proper operation, that industry would need to 
institute new field protocols, which would require additional resources 
by the operator, to comply with the proposed requirement, and that it 
is not clear that this new requirement would add value beyond current 
requirements. The commenter recommended specific revisions to paragraph 
(b) that would increase the proposed 5 percent pressure change 
threshold to 15 percent.
    Response--No changes are necessary. As discussed in prior responses 
to similar comments, the thresholds in this section of the proposed and 
final rule are intended to help prevent nuisance shut-ins as well as 
safety and environmental incidents, while the commenter's suggested 
higher thresholds would not satisfy the safety and environmental 
protection goals of this section and would not help prevent nuisance 
shut-ins through more frequent re-setting of operating pressure ranges. 
If an operator has additional concerns about the specified threshold 
for re-setting the operating pressure range under specific 
circumstances, the operator can contact the District Manager for 
guidance or seek approval for an alternate procedure under the DWOP 
process or existing Sec.  250.141. However, BSEE added language to the 
final rule (consistent with similar provisions in other sections) that 
specifies a time interval for recording pressure as a basis for a new 
operating pressure range. This clarification should help mitigate the 
commenter's asserted concern about the need for new field protocols.
    Comment--A commenter suggested revising the language of proposed 
Sec.  250.865(b), since the highest operating pressure of the discharge 
line should include the transient pressure spike associated with 
starting up or shutting down system pumps, provided that the pressure 
spike is within the system MAWP; otherwise, the commenter asserted, the 
PSH sensor will trip whenever an additional pump is started, forcing 
operations to temporarily bypass the PSH sensor. The commenter stated 
that it is very difficult to completely design away transient pressure 
spikes for liquid-filled systems. The commenter also requested that 
BSEE clarify the proposed requirement for re-establishing operating 
pressure range when normalized operating pressure changes by 5 percent. 
The commenter also asserted that proposed Sec.  250.865(b) would only 
prohibit setting PSH/PSL trip points that are more than 15 percent 
above/below the established pressure range, so that a 5 percent change 
in pressure that moves the operating pressure closer to the trip point 
would not violate this requirement. The commenter suggested that, to 
avoid conflicts, re-running the range charts should only be required if 
the change exceeds the parameters of Sec.  250.865(b). The commenter 
also recommended specific revisions to paragraph (b) to address the 
commenter's concerns.
    Response--No changes are necessary. With regard to the commenter's 
concern about transient pressure spikes (during start-ups or shutdowns) 
causing the PSH sensor to trip, BSEE revised final paragraph (b) by 
adding minimum and maximum time periods (i.e., no less than 4 hours and 
no more than 30 days) for recording pressures to be used in setting a 
new operating pressure range. The minimum time period is intended to 
ensure that the system pressure is stable during the recording period 
used to set a new operating range. The time period limits were also 
set, in part, in order to allow operators to discern repeatability, 
including pressure spikes

[[Page 61893]]

and/or surges, during the time period. These time period limits should 
reduce, if not eliminate, the commenter's concern about transient 
pressure spikes during pump startup and shutdown. In addition, the 
pressure recording time period limits and other revisions to final 
paragraph (b), as discussed in prior responses to similar comments, 
clarify the requirement for recording pressures and resetting the 
normal operating pressure range, as requested by the commenter.
    With regard to the commenter's assertions regarding the proposed 
PSH/PSL trip points (which BSEE moved from paragraph (b) to paragraph 
(c) in the final rule), BSEE agrees that this provision does not 
preclude an operator from setting a PSH or PSL trip point below the 
specified maximum of 15 percent (or 5 psi, whichever is higher) above 
the highest operating pressure of the discharge line. Thus, as the 
commenter observed, a trip point that is 5 percent above the highest 
operating pressure of the discharge line would not violate this 
requirement. However, BSEE notes that, as proposed, final paragraph (c) 
specifies that the trip point for a PSH sensor must be set at least 5 
percent (or 5 psi, whichever is greater) below the set pressure of the 
PSV; not 15 percent below the pressure range, which the commenter 
incorrectly implied was part of the proposal. The 5 percent limit in 
this provision is intended to improve safety and environmental 
protection by assuring that the pressure source is shut-in before the 
PSV activates; while the 15 percent limit suggested by the commenter 
would not be as effective in meeting those goals. If an operator has 
any additional concerns about its operating pressure range, it they can 
contact the District Manager for guidance.
Maximum Discharge Pressure
    Comment--One commenter noted that, under proposed paragraph (f), 
the pump maximum discharge pressure must be determined using the 
maximum possible suction pressure and the maximum power output of the 
driver. The commenter asserted that the maximum discharge pressure for 
centrifugal pumps typically is determined by the maximum suction 
pressure at the shutoff head and, for positive displacement pumps, by 
the set pressure of the PSV at the discharge.
    Response--BSEE agrees with the commenter and has revised final 
paragraph (g) of this section to clarify the appropriate method to 
determine the pump maximum discharge pressure, using the maximum 
possible suction pressure and the maximum power output of the driver as 
appropriate for the pump type and service.
Personnel Safety Equipment (Sec.  250.866)
    Section summary--Final Sec.  250.866 is a new section that requires 
the operator to maintain all personnel safety equipment located on a 
facility in good working condition, without regard to whether the 
equipment is required.
    Regulatory text changes from the proposed rule--BSEE did not make 
any significant changes to this section.
    Comments and responses--BSEE received public comments on this 
section and responds to those comments as follows:
Move Section to Subpart A
    Comment--A commenter asserted that this proposed requirement is out 
of place in this section of subpart H, stating that it is a general 
duty statement that belongs in subpart A at Sec.  250.107. The 
commenter recommended deleting this requirement from subpart H.
    Response--BSEE does not agree that it would be appropriate to move 
this provision to subpart A at this time. BSEE agrees with the 
commenter that this requirement might be an appropriate addition to 
subpart A at a future date through a separate rulemaking. Moving this 
section to subpart A in this final rule, however, would be outside the 
scope of this rulemaking. Nor is it inappropriate to include this 
requirement in subpart H, since it is certainly applicable to personnel 
safety equipment located on facilities subject to this final rule.
BSEE Responsibilities
    Comment--Several comments requested clarification on BSEE's 
responsibilities for personnel safety equipment requirements on the OCS 
compared to USCG's responsibilities. The commenters expressed their 
opinion that USCG, not BSEE, should have oversight for required and 
non-required personnel safety equipment on the OCS. They recommended 
that BSEE remove this requirement from subpart H.
    Response--BSEE is not requiring any new additional personnel safety 
equipment under this provision, but only requiring that this equipment, 
if located on a facility, be maintained in good working condition. As 
previously discussed, this final regulation applies to operations and 
systems, including safety issues, on facilities under BSEE's 
jurisdiction.
Temporary Quarters and Temporary Equipment (Sec.  250.867)
    Section summary--Final Sec.  250.867 is a new section that requires 
that all temporary quarters to be installed in production processing 
areas or other classified areas on OCS facilities be approved by BSEE 
and be equipped with all safety devices required by API RP 14C, 
Appendix C. It also clarifies that the District Manager may require the 
installation of a temporary firewater system. This new section also 
requires that temporary equipment in production processing areas or 
other classified areas used for well testing and/or well clean-up be 
approved by the District Manager. These temporary equipment 
requirements are based on a number of incidents involving the 
unsuccessful use of such equipment and will help ensure that BSEE has a 
more complete understanding of all operations associated with such 
temporary quarters and temporary equipment.
    Regulatory text changes from the proposed rule--BSEE revised 
paragraph (a) of this section in the final rule to state that the 
District Manager must approve the installation of all temporary 
quarters installed in production processing areas or other classified 
areas on OCS facilities. BSEE also revised paragraph (b) to clarify 
that the District Manager may require temporary firewater systems 
``for'' (rather than ``in'') temporary quarters in such areas, and 
revised final paragraph (c) to clarify that the District Manager must 
approve temporary equipment associated with the production processing 
system, including equipment used for well testing and/or well clean up. 
These changes were made to clarify that these requirements apply to 
areas or equipment under BSEE's authority.
    Comments and responses--BSEE received public comments on this 
section and responds to those comments as follows:
BSEE Authority
    Comment--A commenter asserted that the proposed rule exceeded 
BSEE's authority as fire-fighting requirements for accommodations and 
machinery spaces are the responsibility of the USCG. Additionally, the 
commenter stated that there are no BSEE requirements in either the 
existing regulations or the proposed regulations that require firewater 
systems in permanent quarters or temporary quarters. The commenter 
recommended that BSEE delete this section from the proposed rule.
    Response--As previously discussed, these regulations apply only to

[[Page 61894]]

operations under BSEE's authority. These requirements are based on 
several past incidents involving unsuccessful use of temporary 
equipment. Currently, BSEE receives limited information regarding 
temporary equipment. This final rule will help ensure that BSEE has a 
more complete understanding of operations associated with temporary 
quarters and temporary equipment in production processing or other 
classified areas, which in turn will help BSEE ensure that such 
operations are conducted in a manner that prevents or minimizes the 
likelihood of fires and other incidents that may damage property or the 
environment or endanger life or health.
    In addition, BSEE expects operators to address the impacts of the 
temporary quarters and temporary equipment in their SEMS plans. This 
could include, for example, conducting a hazards analysis (see Sec.  
250.1911) for the installation of temporary quarters or evaluating safe 
work practices (see Sec.  250.1914) for temporary equipment.
Non-Metallic Piping (Sec.  250.868)
    Section summary--Section 250.868 is a new section that was proposed 
to limit the use of non-metallic piping to atmospheric, primarily non-
hydrocarbon service (such as open atmospheric drains) and thereby 
preclude the use of non-metallic piping in other situations, such as 
production process piping (i.e., piping that handles produced 
hydrocarbons).
    Regulatory text changes from the proposed rule--In response to 
comments, BSEE revised this section to clarify that it applies only to 
non-metallic piping on fixed OCS facilities and to refer to the 
requirements for piping in final Sec.  250.841(b), which incorporates 
API RP 14E, Recommended Practice for Design and Installation of 
Offshore Production Platform Piping Systems. Section 250.841(b) 
specifically addresses the installation, repair, testing, and 
maintenance of production process piping, while API RP 14E includes 
comprehensive provisions for surface piping systems, including non-
metallic piping.
    Comments and responses--BSEE received public comments on this 
section and responds to those comments as follows:
Non-Metallic Piping
    Comment--A commenter suggested that this section should be revised 
to prohibit non-metallic piping for hydrocarbons. The commenter 
asserted that firefighting piping can be made out of fiberglass 
reinforced plastic, provided that it does not penetrate a bulkhead and 
is always wet inside. The commenter asserted that polyvinyl chloride 
firefighting piping is not good practice and should never be allowed. 
The commenter also stated that non-metallic piping should not be 
allowed to penetrate bulkheads or decks, even if atmospheric. The 
commenter also suggested that BSEE's rules for non-metallic piping 
should take into consideration the USCG's rules.
    Response--BSEE agrees that the proposed section did not fully 
address all situations in which use of non-metallic piping would or 
would not be allowed, and that there could be potential confusion about 
the proposed rule's relation to USCG regulations. Accordingly, BSEE 
revised this section in the final rule to require that the use of non-
metallic piping on fixed facilities be in accordance with the 
requirements of Sec.  250.841(b), which specifically addresses platform 
production process piping and which incorporates API RP 14E, including 
provisions for non-metallic piping. This revision will provide greater 
clarity to operators while achieving the original purpose of the 
proposed rule.
Jurisdiction
    Comment--A commenter recommended that BSEE limit the proposed 
requirement in accordance with MOA OCS-04 between MMS (now BSEE) and 
the USCG. The commenter asserted that piping in galleys and living 
quarters, as well as firewater systems piping, on floating offshore 
facilities is the responsibility of the USCG. The commenter added that 
USCG has specific requirements for the use of non-metallic piping in 
USCG-regulated systems on such facilities.
    Response--As stated in prior responses, BSEE's regulations apply 
only to operations and systems that are under BSEE authority. However, 
to further clarify this point, BSEE has revised this section to specify 
that it only applies on fixed OCS facilities, and to refer back to 
Sec.  250.841(b), which specifically addresses production process 
piping and which also incorporates API RP 14E's provisions for non-
metallic piping. These revisions limit the scope and applicability of 
final Sec.  250.868 so as to avoid concerns about its consistency with 
MOA OCS-04 (as updated on January 28, 2016).
Atmospheric and Pressurized Piping
    Comment--One commenter asserted that the proposed regulatory text 
is confusing in its use of the term ``atmospheric,'' in that the 
examples given in the proposal implied pressurized piping greater than 
atmospheric pressure. The commenter said that typical freshwater piping 
in galleys and living quarters operates at 75 psig and 
firewater systems piping operates at 200 psig.
    Response--BSEE agrees with the commenter that the piping in galleys 
and living quarters and firewater system piping is pressurized piping. 
BSEE has revised this section in the final rule and eliminated the 
proposed references to piping in galleys and living quarters and in 
firewater systems, thus eliminating the potential confusion noted by 
the commenter. Instead, the final rule now refers to the more 
comprehensive requirements of Sec.  250.841(b).
New Technology
    Comment--A commenter suggested revising the language of proposed 
Sec.  250.868, since it would cover new technology such as non-metallic 
HPHT pipe (e.g., Magma's M-pipe) and would preclude the use of M-pipe 
for future weight-saving in areas such as topside water injection (WI) 
piping and subsea jumpers. The commenter also suggested that the 
requirement should be clarified so that it only applies to new 
installations and does not implicitly require removal of existing 
approved installations.
    Response--As previously stated, BSEE revised this section in the 
final rule to limit it to fixed OCS facilities and to cross-reference 
the requirements of final Sec.  250.841(b). Topside WI piping is only 
found on floating facilities, which are outside the scope of this final 
provision. The design of subsea jumpers is covered in subpart J of 
BSEE's regulations and is likewise not within the scope of this 
section.
General Platform Operations (Sec.  250.869)
    Section summary--BSEE has moved the contents of existing Sec.  
250.803(c), pertaining to general platform operations, to final Sec.  
250.869, and revised the language for improved clarity. The final rule 
also includes, as proposed, a new requirement (Sec.  250.869(e)) that 
prohibits use, on new installations, of the same sensing points for 
process control devices and component safety devices.
    In addition, as proposed, final paragraph (a) requires that a 
designated visual indicator be used to identify a bypassed safety 
device and establishes required monitoring procedures for bypassed 
safety systems. Final paragraph (a)(1) also sets forth the monitoring 
requirements for non-computer-based safety systems, while paragraph 
(a)(2) sets forth the monitoring requirements for computer-based 
technology systems. More

[[Page 61895]]

specifically, final paragraph (a)(2)(i) requires computer-based 
technology system control stations to show the status of operating 
conditions and to be capable of displaying those conditions, provided 
that if the computer-based system is not capable of displaying 
operating conditions, the operator must use field personnel to monitor 
the level and pressure gauges.
    In addition, final paragraph (a)(3) specifies that operators must 
not bypass, for startup, any element of the emergency support system 
(ESS) or other support system required by Appendix C of API RP 14C 
without first receiving approval from BSEE for a departure.
    Regulatory text changes from the proposed rule--BSEE revised the 
proposed rule by adding a new paragraph (f) to clarify that control 
panels and control stations must be marked consistently with each other 
using consistent nomenclature as provided in API RP 14C.
    Comments and responses--BSEE received public comments on this 
section and responds to those comments as follows:
Pressure and Temperature-Take Points
    Comment--A commenter requested that BSEE revise this section to 
clarify whether it would require additional pressure and temperature-
take points on subsea trees and other subsea equipment. The commenter 
asserted that it is usually desirable to minimize these leak paths.
    Response--No changes are necessary. This regulation does not 
introduce additional leak paths; it only separates process controls 
from safety controls in order to ensure the sensing line is only 
performing a single function. If the process controls and safety 
controls were not separate, a problem with one system could result in a 
problem with both systems, thus creating a greater risk that a failure 
in a process control would also cause a safety system malfunction. 
Requiring separate systems is also consistent with API RP 14C, which 
states that the safety system should provide 2 levels of protection, 
independent of and in addition to the control devices.
Time Delays on Pressure Safety Low (PSL) Sensors (Sec.  250.870)
    Section summary--Final Sec.  250.870, related to time delays on PSL 
sensors, is a new provision that codifies guidance from NTL No. 2009-
G36. The final rule specifies that operators may apply any or all of 
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. It also requires that operators 
document on their field test records any use of a PSL sensor with a 
time delay greater than 45 seconds. Final Sec.  250.870 also describes 
how PSL sensors fit under Class B, Class C, or Class B/C.
    The final rule also provides that if an operator does not install 
time delay circuitry that bypasses activation of PSL sensor shutdown 
logic for a specified time period on process and product transport 
equipment during startup and idle operations, the operator must 
manually bypass (pin out or disengage) the PSL sensor, with a time 
delay not to exceed 45 seconds.
    Regulatory text changes from the proposed rule--Throughout this 
section, the word ``BSEE'' was removed before the ``District Manager'' 
for consistency with other sections and because it was unnecessary. In 
response to comments, BSEE revised final paragraph (a) to state that 
the operator ``may apply'' industry standard class logic to applicable 
PSL sensors, rather than stating that the operator ``must apply'' such 
logic, as proposed. Similarly, BSEE replaced the phrase ``apply any or 
all of the industry standard Class B, Class C and Class B/C logic'' 
with ``apply industry standard Class B, Class C or Class B/C logic'' in 
order to clarify that the operator may choose to use any one (or more) 
of those classes rather than all three of the classes. In addition, 
BSEE removed proposed references to alternate procedures under Sec.  
250.141 from the final rule because Sec.  250.141 is potentially 
applicable to all requirements under part 250 and does not need to be 
expressly cited in this section.
    Comments and responses--BSEE received public comments on this 
section and responds to those comments as follows:
BSEE Role
    Comment--One commenter stated that BSEE should not be involved in 
these day-to-day operational decisions regarding pressure safety 
devices, as proposed in this section.
    Response--Appropriate use of pressure safety devices is critical to 
ensuring safety and protection of the environment. However, BSEE 
revised this section in the final rule to state that the operator may 
apply the class logic, but is not required to use it. This revision 
gives the operator greater flexibility in meeting this safety goal by 
allowing for time delays, instead of requiring the operator to bypass 
the PSL sensors.

Bypasses

    Comment--A commenter recommended that PSL sensors should not be 
required to have timed or pressure build-up bypasses for startup 
activities. The commenter also asserted that the proposed rule implied 
that all three industry standard Class logics must be applied 
simultaneously. Therefore, the commenter recommended that the first 
sentence be reworded as follows: ``You may apply industry standard 
Class B, Class C, or Class B/C logic to applicable PSL sensors 
installed on process equipment. . . .'' The commenter also asserted 
that the proposed time limit of 45 seconds for delaying the PSL sensor 
bypass could be unreasonable during a startup scenario and could cause 
startup operations to be rushed unnecessarily. The commenter 
recommended that the time delay be extended to several minutes to 
account for this.
    Response--BSEE agrees with the commenter regarding the proposed 
class logic language and revised paragraph (a) of this section to state 
that the operator may apply any or all of the Class B, C or B/C logic, 
but is not required to use any of those choices. This gives the 
operator flexibility by allowing for time delays, instead of requiring 
the operator to bypass the PSL sensors. If BSEE had required the 
operator to apply class logic, some existing facilities would need to 
be retrofitted. This revision is consistent with the intent of the 
proposed rule, which provided in paragraph (b) that an operator that 
does not use a class logic approach must manually bypass the PSL 
sensor.
    However, BSEE disagrees with the suggestion for extending the time 
limit on delays to several minutes. Based on BSEE's experience, and 
consistent with NTLNo. 2009-G36, 45 seconds is typically a reasonable 
period for pressure to fluctuate before it becomes necessary to alert 
the operator to an abnormal condition that must be addressed. By 
contrast, allowing the pressure to remain low for several minutes 
before the sensor alerts the operator could significantly increase the 
potential safety risk from the abnormal condition. Thus, BSEE must 
approve any request to extend the delay period beyond 45 seconds in a 
specific case.
Welding and Burning Practices and Procedures (Sec.  250.871)
    Section summary--BSEE moved the content of existing Sec.  
250.803(d), pertaining to welding and burning practices and procedures, 
to final Sec.  250.871. BSEE revised the existing language for clarity 
and plain language

[[Page 61896]]

and updated the regulatory cross-references.
    Regulatory text changes from the proposed rule--BSEE did not make 
any significant changes to this section. BSEE deleted the proposed 
cross-reference to the alternate procedures approval process under 
Sec.  250.141 since that provision is applicable to all requirements in 
part 250 and does not need to be expressly referenced.
    Comments and responses--BSEE received one comment on this section 
and responds to that comment as follows:
Alternate Compliance and Departures (Variances)
    Comment--The commenter asserted that operators should be required 
to obtain BSEE approval for any variance from a regulatory requirement, 
including industry standards incorporated by reference into the 
regulations, and from any approval, permit, or authorization issued by 
BSEE for an OCS oil and gas production facility.
    Response--These types of requests are already covered by existing 
Sec. Sec.  250.141 and 250.142 in the form of alternate compliance and 
departure requests, respectively; therefore, no revision to the 
regulation is needed in response to this comment.
Atmospheric Vessels (Sec.  250.872)
    Section summary--Final Sec.  250.872 is a new section that requires 
atmospheric vessels used to process and/or store liquid hydrocarbons or 
other Class I liquids, as described in API RP 500 or 505, to be 
equipped with protective equipment identified in API RP 14C. It also 
includes requirements for level safety high (LSH) sensors) and 
clarifies that, for atmospheric vessels that have oil buckets, the LSH 
sensor must be installed to sense the level in the oil bucket. In 
addition, paragraph (c) requires that all flame arrestors be maintained 
to ensure proper design function.
    Regulatory text changes from the proposed rule--BSEE revised 
proposed paragraph (a) to list types of tanks that are not required to 
be equipped with protective equipment.
    Comments and responses--BSEE received public comments on this 
section and responds to those comments as follows:
Authority
    Comment--A commenter recommended that BSEE revise this section to 
state that it is not applicable to the design or operation of tanks 
inside the hull of a floating facility. The commenter asserted that 
USCG requirements may be different from BSEE requirements for tanks 
inside the hull of a unit. Alternatively, the commenter suggested that 
BSEE-USCG MOA OCS-04 should be revised to give USCG jurisdiction over 
the design of any tanks that are integral to the hull and to give BSEE 
jurisdiction over any non-integral tanks in the hull of the unit and 
over the operation of both integral and non-integral tanks in the hull 
of the unit that are for produced hydrocarbons, fuel and flow assurance 
fluids.
    Response--BSEE disagrees. This section relates to atmospheric 
vessels that are a component of drilling, completion, well servicing, 
and workover operations and that are under BSEE jurisdiction. BSEE is 
not regulating the design or operation of the tanks; rather, this 
regulation only requires sensors to ensure safety in the operations 
BSEE oversees. This is consistent with MOA OCS-04, which was updated in 
January 2016, and which applies only to floating facilities.
Non-Permanent Storage
    Comment--A commenter asked whether it was BSEE's intent to include 
non-permanent storage of chemicals and other substances used for 
ancillary operations such as well work, painting, etc. The commenter 
asserted that, if that was BSEE's intent, compliance would be difficult 
since many products are stored in transporters, drums and buckets. The 
commenter stated that inclusion of devices such as LSH sensors would 
serve no useful purpose since they would not have a ``source'' to shut 
in, and connecting them to facility safety systems would impose a major 
burden since they are moved frequently. The commenter asserted that the 
proposed requirements for venting and/or flame arrestors for drums and 
transporters are understandable, but requiring full compliance with API 
RP 14C atmospheric vessel requirements would impose additional burdens 
that provide no tangible benefits. The commenter provided recommended 
revisions to the proposed language.
    Response--BSEE does not intend to include non-permanent storage of 
chemicals and other substances used for ancillary operations such as 
well work, painting, etc., within the scope of this requirement. The 
relevant tanks are sealed, with no venting or inlet-outlet valves, and 
they are not connected to the production process train. To clarify this 
point, BSEE revised this section to exclude U.S. Department of 
Transportation-approved transport tanks that are sealed and not 
connected via interconnected piping to the production process train and 
that are used for storage only of refined liquid hydrocarbons or Class 
I liquids.
    However, BSEE does not agree with the suggestion for requiring the 
TSE on atmospheric tanks that are not connected via interconnected 
piping to the production process train because these tanks are sealed, 
i.e., there is no venting and no inlets or outlets. BSEE does agree 
that the TSE is needed if the tank is connected to the production 
process chain for fire protection.
    Comment--A commenter asserted that proposed paragraph (b) would 
have a huge impact for manufactured ``standard'' designs currently in 
service that do not have nozzles for moving level sensors. The 
commenter asserted that placing LSH sensors in oil buckets may not 
necessarily reduce risk of pollution, depending on individual equipment 
design. The commenter added that many systems are configured for the 
oil bucket level to be much lower than the main compartment level (to 
prevent overflow of the oil into water) so an LSH sensor in an oil 
bucket would not sense true ``high'' levels in the component, requiring 
two LSH sensors to be installed rather than just relocating the LSH 
sensor. The commenter claimed that it would be difficult to retrofit 
vessel oil buckets with an LSH sensor if they do not have the 
appropriate nozzles and asked whether exceptions would be made for 
existing equipment currently in service. The commenter provided 
recommended language to address its concerns.
    Response--BSEE agrees with the commenter that the operator must 
ensure that all atmospheric vessels, whether existing or new, are 
designed and maintained to ensure the proper working conditions for LSH 
sensors. Specifically, to ensure proper working conditions for the LSH 
sensor, the LSH sensor bridle must be designed to prevent different 
density fluids from impacting sensor functionality. Similarly, for 
atmospheric vessels that have oil buckets, proper working conditions 
means the LSH sensor must be installed to sense the level in the oil 
bucket. This requirement is not just to protect against overflow but 
also to prevent oily-water interface from going out the water outlet, 
thus protecting safety and the environment. Thus, for those reasons, 
BSEE does not agree with the commenter's suggestion to limit the 
requirements for atmospheric vessels with oil buckets only to new 
equipment (i.e., that comes into service after this rule takes effect). 
BSEE expects that most existing equipment will already be in compliance 
with this requirement, and for those that are not, compliance

[[Page 61897]]

would only require the relocation of the LSH sensor. However, if an 
operator requests approval of alternate equipment or a departure from 
this requirement for the equipment currently in service, BSEE will 
consider such requests on a case-by-case basis.
Subsea Gas Lift Requirements (Sec.  250.873)
    Section summary--This is a new section that codifies existing 
policy and guidance from the DWOP process. Under DWOPs, BSEE has 
approved the use of gas lift equipment and methodology in subsea wells, 
pipelines, and risers and has imposed conditions to ensure that the 
necessary safety mitigation measures are in place. While the basic 
requirements of API RP 14C will apply for surface applications, certain 
clarifications are made in this section to ensure regulatory compliance 
when gas lift for recovery for subsea production operations is used. 
Specifically, final Sec.  250.873 requires that: Gas lift supply 
pipelines be designed according to API RP 14C; installation of 
specified safety valves, including a gas-lift shutdown valve and a gas-
lift isolation valve, be tailored to operational circumstances; valve 
closure times and hydraulic bleed time requirements be in accordance 
with the approved DWOP; and gas lift valve systems be periodically 
tested to ensure that they do not exceed specified allowable leakage 
rates.
    Regulatory text changes from the proposed rule--The table in 
proposed paragraph (b) was revised in the final rule to reflect 
comments received and to be consistent with the guidance of NTL No. 
2009 G-36. BSEE also deleted an extraneous phrase that was 
inadvertently included in proposed paragraph (b)(1)(i).
    Comments and responses--BSEE received public comments on this 
section and responds to those comments as follows:
Consistency With NTL No. 2011-N11
    Comment--A commenter asserted that the tables in proposed 
Sec. Sec.  250.873, 250.874 and 250.875 are inconsistent with the 
tables issued in NTLs, guidance provided via DWOP approvals, and 
discussions with BSEE GOM Region's Technical Assessment Section. The 
commenter recommended that BSEE revisit and revise the tables according 
to NTL No. 2011-N11 and previous guidance issued to operators as part 
of the DWOP process.
    Response--BSEE agrees with the commenter and has revised the tables 
to be more consistent with the referenced NTL and BSEE guidance 
provided to operators during the DWOP process. However, not every 
detail relevant to subsea gas lift systems can be included in the final 
rule. There are three different gas lift situations, each using a 
different system, and the nuances for these systems are better 
addressed in guidance. BSEE plans to revise the referenced NTL to 
address those details that are not covered in this final rule.
Gas Lift System
    Comment--A commenter requested that, for clarity, the word 
``system'' should be added after ``gas lift'' in the first sentence of 
paragraph (d). The commenter asked why there was no allowable leakage 
rate specified for the valve in proposed paragraph (d)(1), given that a 
gas lift isolation valve (GLIV) is required when gas lifting a subsea 
pipeline, pipeline riser, or manifold via an external gas lift 
pipeline, as described in proposed paragraph (b)(1).
    Response--BSEE agrees with the commenter's suggestions for revising 
paragraph (d) by adding the word ``system'' after ``gas lift'' in the 
first sentence. No other changes are necessary, however. Under 
paragraph (b)(1), the GLIV must be installed downstream of the USV(s) 
and/or AIV(s). The GLIV prevents flow back to the facility. For gas 
lift of a subsea pipeline, pipeline riser, or manifold via an external 
gas lift pipeline, the USV is the primary barrier and is leak tested; 
the GLIV is not the primary barrier, so a leak test is not required.
Subsea Water Injection Systems (Sec.  250.874)
    Section summary--This is a new section that codifies existing 
policy and guidance from the DWOP process, related to water flood 
injection via subsea wellheads. This is similar to the subsea gas lift 
situation discussed in the previous section. The basic requirements of 
API RP 14C apply for water flooding from the surface, but BSEE made 
some clarifications in this section regarding the use of water flood 
systems for recovery in subsea production operations. Final Sec.  
250.874 requires operators to meet the following requirements: Adhere 
to the WI provisions in API RP 14C for the WI equipment located on the 
platform; equip the WI system with certain safety valves, including 
water injection valve (WIV) and a water injection shutdown valve 
(WISDV); establish valve closure times and hydraulic bleed requirements 
according to the approved DWOP; and conduct WIV testing in accordance 
with the rule.
    Regulatory text changes from the proposed rule--BSEE revised the 
introductory paragraph to clarify that the regulations are the minimum 
requirements for the subsea WI system, that the operator's DWOP must 
address the applicable requirements, and that the operator must comply 
with the approved DWOP. BSEE also restructured the section, creating 
shorter, easier to follow paragraphs.
    BSEE revised final paragraph (g) to clarify the testing 
requirements. In particular, BSEE revised proposed paragraph (g)(2) to 
address the actions that an operator must take if a designated USV on a 
WI well fails its test. BSEE retained in the final paragraph the 
proposed requirement that the operator must designate another certified 
subsea valve as a USV, in place of the USV that failed its test. 
However, BSEE added language to clarify that this designation requires 
District Manager approval. In addition, BSEE removed language from 
proposed paragraph (g)(2) that would have given the operator the 
option, in lieu of designating a new certified subsea valve as a USV, 
to modify the valve closure time of the surface-controlled SSSV or WIV 
after sensor activation. That situation has never occurred in BSEE's 
experience; thus, that option is not needed in this regulation.
    In consideration of a comment received, the final rule omits 
language from proposed paragraph (g)(3) that addressed function testing 
the WISDV in cases where the operator had BSEE's approval not to leak 
test the WISDV. BSEE has decided that the function testing requirements 
for WISDVs in such circumstances would be more effectively addressed 
through other means, such as through a departure approval under Sec.  
250.142.
    In final paragraph (h)(2), BSEE removed the proposed language 
stating that the District Manager may order a shut-in when there is a 
loss of communication during WI operations. The deleted sentences were 
intended only for informative purposes, not as a regulatory 
requirement, and thus are not needed in the regulation.
    Comments and responses--BSEE received public comments on this 
section and responds to those comments as follows:
Zero-Leak Criteria
    Comment--A commenter asked whether the proposed regulations apply 
to all WI wells and all WI systems. The commenter asserted that these 
are `departing pipelines' from the platform, and that the proposed 
requirement would be inconsistent with API RP 14C.

[[Page 61898]]

The commenter also asserted that some WI wells are not connected 
directly to the reservoir and will not flow back under hydrostatic 
pressure or would take many years to do so. The commenter, therefore, 
questioned whether a `zero-leak' criterion for these wells would be 
appropriate. The commenter also asserted that the proposed regulations 
imply that the consequence of any fluid by-pass is similar or identical 
to that of a hydrocarbon production system and well, while in many 
instances the bypasses of WI fluids have neither safety nor 
environmental consequences. Thus, the commenter questioned whether this 
same valve leakage criterion should apply.
    Response--BSEE disagrees with the commenter, and has determined 
that no changes are necessary based on this comment. These provisions 
apply to all WI wells and WI systems. Consistent with existing BSEE 
policy and guidance previously provided to the operators through the 
DWOP process, the zero-leak rate for these wells is appropriate, and if 
the well is capable of natural flow to the surface, then the operator 
needs to test these valves. Any operator that has concerns with its 
specific subsea WI system should contact the appropriate District 
Manager, who will review the concerns on a case-by-case basis.
WIV Testing
    Comment--A commenter asserted that, because a WIV is defined in 
Sec.  250.874(a) as a ``water injection valve,'' and because this 
definition does not include WISDVs (as defined in Sec.  250.874(b)), 
the acronym ``WIV'' as used in proposed paragraphs (g) and (g)(1) 
should be replaced with the words ``water injection system valve.'' The 
commenter also suggested, for clarity, that BSEE add the word ``leak'' 
to the first sentence of paragraph (g)(3). The commenter questioned 
whether the requirement that USVs meet the allowable leakage criteria 
(in the event that the WISDV cannot be tested because the shut-in 
tubing pressure of the water injection well is less than the external 
hydrostatic pressure) means that the USVs are to be tested in the 
direction of the water injection flow. If that is so, the commenter 
questioned why the WISDV cannot be tested similarly, i.e., in the 
direction of the flow. The commenter also suggested that BSEE consider 
the applicability of the proposed requirements and regulations to 
subsea water injection systems that do not have positive well flowback 
capability and whether the proposed production valve leakage criteria 
are necessary for all WI wells and systems.
    Response--BSEE agrees with the comment that the acronym ``WIV'' is 
not appropriate for use in paragraph (g), as proposed, and has replaced 
the acronym with ``injection valve'' in the introductory sentence of 
paragraph (g) and in subparagraph (g)(1) of the final rule. In 
addition, based on the commenter's questions and concerns related to 
the requirement in proposed paragraph (g)(3) for testing a USV in the 
event that a WISDV cannot be tested, BSEE has decided that there are a 
number of technical issues related to such testing that require further 
consideration by BSEE and that potentially would be better addressed 
through guidance rather than by regulations at this time. Accordingly, 
BSEE has removed the relevant language in proposed paragraph (g)(3) 
from the final rule. BSEE may issue additional guidance on WISDV 
testing at a later date.
Subsea Pump Systems (Sec.  250.875)
    Section summary--This new section codifies policy and guidance from 
existing NTL No. 2011-N11, ``Subsea Pumping for Production 
Operations,'' and the DWOP process. Final Sec.  250.875 outlines subsea 
pump system requirements, including: The installation and location of 
specific safety valves and sensors, operational considerations under 
circumstances where the maximum possible discharge pressure of the 
subsea pump operating in a dead head situation could be greater than 
the maximum allowable operating pressure (MAOP) of the pipeline, valve 
closure times and hydraulic bleed times, and subsea pump testing.
    Regulatory text changes from the proposed rule--BSEE revised this 
section to clarify that the operator must ensure that the subsea pump 
system complies with the approved DWOP, and that the requirements in 
this section are the minimum requirements for the subsea pump system. 
BSEE revised the wording in several places to clarify the requirements; 
however BSEE did not make any substantive changes to the requirements 
in this section.
    Comments and responses--BSEE received public comments on this 
section and responds to those comments as follows:
Previous Guidance
    Comment--A commenter asserted that the tables in the proposed rule 
are different from previous guidance provided through DWOPs by BSEE GOM 
Region's Technical Assistance section or NTL No. 2011-N11 (``Subsea 
Pumping for Producing Operations--Considerations for Using Subsea Gas 
Lift and Water Flood as Secondary Recovery Methods for Production 
Operations).'' The commenter recommended revising the rule to align 
with previous guidance issued to operators. The commenter also noted 
that the proposed rule does not provide the valve closure timing table 
included as Table 1 in NTL No. 2011-N11 and recommended including the 
table in the regulation to avoid confusion during the DWOP approval 
process. The commenter asserted that the ``loss of communications'' 
case is addressed in NTL No. 2011-N11, but that the proposed rule did 
not provide details of how and when to execute an immediate shutdown of 
a well or subsea boost system. Thus, the commenter requested 
clarification regarding the shutdown sequence and timing. The commenter 
also recommended that the tables in the proposed rule be revised to 
align better with the tables published in the current NTLs.
    Response--No changes to this section are necessary in response to 
these comments. Table 1 from NTL No. 2011-N11, referred to in the 
comment, is associated with the approval of a specific DWOP. However, 
the issues associated with that table and these systems are complex, 
with too many nuances to effectively address in this regulation. Those 
issues are better addressed through the DWOP process on a case-by-case 
basis, especially since production systems are site-specific and 
currently there is no industry standard on subsea pumping. Similarly, 
under paragraph (d), operators must follow the valve closure times and 
hydraulic bleed requirements established by their approved DWOPs. 
Accordingly, BSEE reviews each subsea pumping system individually 
through the DWOP process. BSEE will review NTL No. 2011-N11 and expects 
to publish a new NTL consistent with this final rule after the 
effective date of the final rule.
Subsea Pump Testing
    Comment--One commenter indicated that the proposed requirement 
potentially could be too broad. The commenter acknowledged that certain 
intervention activities or changes to software and equipment may 
justify a complete subsea pump function test--including shutdown, but 
that other, less significant changes might not warrant such a test. The 
commenter recommended adding the word ``significant'' to proposed 
paragraph (e)(1) so that it reads: ``Performing a complete subsea pump 
function test, including full shutdown after any

[[Page 61899]]

significant intervention, or changes to the software and equipment 
affecting the subsea pump; and . . .''
    Response--BSEE believes that the requirements set forth in 
paragraph (e)(1) are appropriate and not overbroad under the 
circumstances; therefore, no changes are necessary at this time. This 
section deals with newer technology that is still uncommon, and there 
are currently no well-established industry standards that address how 
and when function testing of subsea pumps should be conducted. Thus, at 
present, it is appropriate to require a function test of the subsea 
pump after any change to software or equipment affecting the subsea 
pump, whether or not the operator considers the change to be 
``significant,'' in order to ensure that the pump will still function 
as planned after the change. As BSEE and the industry gain experience 
under this new requirement, BSEE may consider developing further 
guidance on when function testing is required under this provision.
Fired and Exhaust Heated Components (Sec.  250.876)
    Section summary--This new section requires certain tube-type 
heaters to be removed and inspected, and repaired or replaced as 
necessary, every 5 years by a qualified third-party. This section also 
requires that the operator document the inspection results, retain them 
for at least 5 years, and make them available to BSEE upon request. 
This new section was added, in part, due to the BSEE investigation 
report into the Vermillion 380 platform fire of September 2010,\25\ 
which determined that ``the immediate cause of the fire was that the 
heater-treater's weakened fire tube became malleable and collapsed, 
creating openings through which hydrocarbons escaped, came into contact 
with a hot burner, and then produced flames.'' The report also stated 
that a possible contributing cause of the fire was a lack of routine 
inspections of the fire tube. Since 2011, there have been other similar 
incidents involving tube-type heaters resulting in potential safety 
issues for offshore personnel and infrastructure. This new requirement 
will ensure tube-type heaters are inspected routinely to minimize the 
risk of tube-type heater incidents.
---------------------------------------------------------------------------

    \25\ BSEE's investigation report, ``Vermillion Block, Production 
Platform A: An Investigation of the September 2, 2010 Incident in 
the Gulf of Mexico, May 23, 2011,'' is available at https://www.bsee.gov/sites/bsee.gov/files/vermilion-investigation.pdf.
---------------------------------------------------------------------------

    Regulatory text changes from the proposed rule--In response to 
comments, BSEE revised the first sentence of this section to clarify 
that an operator must have the fire tube for tube-type heaters 
inspected within 2 years after the date of publication of this final 
rule, and at least once every 5 years thereafter, and then repaired or 
replaced as needed.
    Comments and responses--BSEE received public comments on this 
section and responds to those comments as follows:
Timing of Initial Inspections
    Comment--A commenter asked whether the ``every 5 years'' clock 
begins the day the proposed regulation is amended or whether the 
regulation would be retroactive and cause equipment that has not been 
inspected within the last 5 years to be pulled and inspected.
    Response--BSEE revised this section to require the initial 
inspection within 2 years after the publication of the final rule. The 
requirement for third-party inspections every 5 years begins to run at 
the time the initial inspection is completed. This provision is not 
retroactive.
Safety, Costs, and Benefits for Fire Tube for Inspection
    Comment--BSEE received comments that expressed concern about the 
safety, costs, and benefits related to removing the fire tube for 
inspection. Commenters indicated that removing the fire tube for 
inspection requires removing the components and may require a crane, 
which the commenters asserted would be a potential safety hazard, as 
well as very costly, and would not add material value to the inspection 
process. The commenters suggested that BSEE consider alternatives to 
removing the tube, such as a visual inspection with the tube in place 
and an option of removing the tube at the qualified third-party 
inspector's discretion. They recommended that the fired components be 
inspected at the same interval as their host equipment. They also 
stated that expected costs of compliance may exceed BSEE's initial 
projections, since removing the fire tube may require additional 
equipment and staff and lead to lost production.
    Response--No changes to the regulatory text are necessary. These 
new requirements are based, in part upon BSEE's investigation of the 
Vermillion 380 heater-treater ``fire tube'' incident and a related 
Safety Alert issued after the investigation.\26\
---------------------------------------------------------------------------

    \26\ Safety Alert 009 (May 25, 2011) summarized the results of 
the Vermillion 380 investigation and recommended, among other 
things, that operators evaluate, and where necessary, update or 
develop their inspection plans for heater-treaters and regularly 
inspect heater-treaters. The Safety Alert is available at https://www.bsee.gov/Regulations-and-Guidance/Safety-Alerts/009-Safety-Alert/.
---------------------------------------------------------------------------

    BSEE's investigation into the Vermillion 380 platform fire of 
September 2010 determined that the immediate cause of the fire was that 
the heater-treater's weakened fire tube became malleable and collapsed, 
creating openings through which hydrocarbons escaped, came into contact 
with a hot burner, and then produced flames. The report also stated 
that a possible contributing cause of the fire was a lack of routine 
inspections of the fire tube. Since 2011, there have been other similar 
incidents involving tube-type heaters resulting in potential safety 
issues for offshore personnel and infrastructure. This new requirement 
will ensure tube-type heaters are inspected routinely to minimize the 
risk of such tube-type heater incidents. BSEE does not believe that the 
alternatives suggested by the commenter, such as to removing the tube 
or inspecting on the same interval as host equipment, would accomplish 
the purposes of this provision.
    BSEE agrees, however, that the costs associated with the inspection 
of fired and exhaust-heated components may be higher than the initial 
economic analysis estimated and has adjusted those costs in the final 
economic impact analysis, as discussed in part V of this document. 
After considering those costs, however, BSEE has concluded that the 
balance of relevant safety considerations, and other costs and 
benefits, justify promulgating this final rule.
Production Safety System Testing (Sec.  250.880)
    Section summary--BSEE moved the contents of existing Sec.  
250.804(a), pertaining to production safety system testing, to final 
Sec.  250.880, and revised those provisions for clarity and plain 
language. BSEE also added several tables to this section to further 
clarify its requirements.
    Final Sec.  250.880(a) includes the notification requirements from 
existing Sec.  250.804(a)(12) and requires the operator to notify the 
District Manager at least 72 hours prior to commencing production so 
that BSEE may conduct a preproduction inspection of the integrated 
safety system. The final rule retains the existing requirement to 
notify the District Manager upon actual commencement of production, and 
adds a new requirement to notify the District Manager and receive 
approval before certain types of subsea intervention.
    The final rule also retains existing testing and inspection 
requirements,

[[Page 61900]]

with certain alterations. The final rule also adjusts the existing 
requirements by increasing certain liquid leakage rates from 200 cubic 
centimeters per minute to 400 cubic centimeters per minute and 
increasing gas leakage rates from 5 cubic feet per minute to 15 cubic 
feet per minute. These changes are consistent with industry standards 
and account for accessibility of equipment in deepwater/subsea 
applications. In 1999, the former MMS funded the Technology Assessment 
and Research Project #272, ``Allowable Leakage Rates and Reliability of 
Safety and Pollution Prevention Equipment,'' to review increased 
leakage rates for safety and pollution prevention equipment. One of the 
recommendations from this study by the Southwest Research Institute 
(SWRI) states that: ``There appears to be preliminary evidence 
indicating that more stringent leakage requirements specified in part 
250 may not significantly increase the level of safety when compared to 
the leakage rates recommended by API. However, a complete hazards 
analysis should be conducted, and industry safety experts should be 
consulted.'' (See n. 20, supra.) In the past, BSEE has allowed a higher 
leakage rate than that prescribed in existing Sec.  250.804 as an 
approved alternate compliance measure in the DWOP because of BSEE's and 
industry's acceptance of the ``barrier concept,'' which moves the SSV 
from the well to the BSDV, and which has been proven to be as safe as 
or safer than what was required by the existing regulations.
    The following table compares existing allowable leakage rates to 
the final increased allowable leakage rates for various safety devices:
[GRAPHIC] [TIFF OMITTED] TR07SE16.008

    Additionally, final Sec.  250.880 contains new requirements for 
BSDVs, changes the testing frequency for underwater safety valves, and 
adds requirements for the testing of ESD systems, flame, spark, and 
detonation arrestors, as well as pneumatic/electronic switch LSH and 
level safety low (LSL) controls. This final section also adds testing 
and repair/replacement requirements for subsurface safety devices and 
associated systems on subsea trees and for subsea wells shut-in and 
disconnected from monitoring capability for greater than 6 months.
    Regulatory text changes from the proposed rule--BSEE revised 
paragraph (a)(1) to clarify that notification to BSEE is required 
before production begins so that BSEE can conduct a preproduction 
inspection. BSEE revised the proposed requirements in the tables under 
paragraph (c) to express the allowable leakage rates in ``standard 
cubic feet per minute'' instead of ``cubic feet per minute.'' This is 
consistent with industry practice and with API RP 14B, which is 
referenced in paragraph (c). BSEE also revised several sentences in 
paragraph (c) for clarity and to provide consistency in the language 
regarding timing of the tests. In addition, BSEE revised paragraph 
(c)(2)(i) to clarify that the main valve piston must be lifted during 
the required test.
    Paragraph (c)(2)(iv) was revised to add ``gas and/or liquid'' 
before ``fluid flow'' for consistency with other provisions of the 
final rule and to clarify that the reference applies to all fluid flow.
    Based on consideration of relevant comments, BSEE also revised 
final paragraph (c)(2)(v) to clarify the meaning of ``flowline'' FSVs 
and to remove the references to appendix D, section D4, table D2, and 
subsection D of API RP 14C (while retaining the requirement to use the 
test procedure in API RP 14C).

[[Page 61901]]

    As suggested by comments, BSEE revised paragraph (c)(3)(ii) to 
include ``gas'' detection systems. BSEE added a statement in final 
paragraph (c)(3)(iii)(A) to clarify that the operator must test all 
stations for functionality at least once each calendar month, not to 
exceed 6 weeks between tests, and that no station may be reused until 
all stations have been tested. This revision ensures proper testing of 
the ESD stations. Similar changes were made, with different timeframes, 
to paragraphs (c)(3)(iii)(B) and (C).
    BSEE restructured proposed paragraph (c)(5), renumbered it as 
paragraph (d), and revised and reworded many of the subordinate 
paragraphs for clarity.
    BSEE also moved the provision that limits the time (i.e., 24 
months) that a completed subsea well may be disconnected from 
monitoring capability from proposed paragraph (c)(5)(vi) to final 
paragraph (d)(1).
    Subsequent paragraphs were renumbered and revised for 
clarification. Several paragraphs were also separated into short 
subparagraphs. BSEE made these changes to make the requirements easier 
to read and understand. However, BSEE did not make any substantive 
changes to the requirements in this section.
    Comments and responses--BSEE received public comments on this 
section and responds to the comments as follows:
Allowable Leakage Rate for Undersea Production Systems
    Comment--BSEE received comments concerning changes to the allowable 
leakage rate for undersea production systems and BSEE's reasoning for 
proposing to raise those rates. Multiple commenters mentioned that BSEE 
based its proposed decision to raise the allowable leakage rate partly 
on the SWRI report on Project #272. (See n. 20, supra). The commenters 
asserted that the report recommended conducting a full hazard study, 
but that the proposed rule did not provide results of that study or 
indicate that it had been completed. The commenters requested 
additional technical justification for BSEE's decision. Other 
commenters suggested that a safety system with leaks should not be 
allowed at all, asserting that ``[p]roduction safety systems that leak 
should not pass a safety test'' and ``[c]ritical production safety 
systems should not leak.''
    Response--BSEE disagrees with the suggestion that the proposed 
decision on leakage rates was based solely on SWRI report #272. BSEE 
based its decision to increase allowable leakage rates in production 
systems on several factors, including industry standards (such as API 
RP 14B), consistency with prior DWOP approvals, and the SWRI report 
#272.
    BSEE also disagrees with the suggestion that it should not allow 
any leaking valves as part of an approved safety system. This section 
specifies the allowable leakage rates for valves that are part of a 
closed system within the production safety system. There are certain 
critical valves, such as the BSDV, that cannot have any leakage. There 
are other valves, however, for which some leakage is allowable. For 
example, BSEE is increasing the allowable leakage rates on SSSVs, as 
they are part of a closed safety system, designed to diminish the risk 
of oil spills by stopping the flow within the system in the event that 
the riser is damaged. The allowable leakage from SSSVs is contained 
within the closed system; it is not released into the environment. In 
addition, these new rates are consistent with accepted industry 
standards.
Testing Flowline FSVs
    Comment--A commenter noted that proposed Sec.  250.880(c)(2) 
included testing requirements for surface valves. In particular, 
proposed paragraph (c)(2)(v) would have required testing once each 
calendar month, not to exceed 6 weeks between tests, and would have 
also required that all FSVs be tested in accordance with the test 
procedure specified in API RP 14C, Appendix D, section D4, table D2 
subsection D. The commenter asserted that, while this section in API RP 
14C appears to apply to flowline FSVs, the proposed regulation was not 
clear, since it stated that the testing requirements would apply to 
``surface valves,'' including PSVs, Automatic inlet SDVs actuated by a 
sensor on a vessel or compressor, SDVs in liquid discharge lines and 
actuated by vessel low-level sensors, and SSVs. Thus, the commenter 
asserted that this proposed provision would have applied the specific 
API RP 14C procedure to surface valves throughout the production 
process and not just valves covered by section A-1 of API RP, 14C which 
pertains to ``Wellheads and Flowlines.'' The commenter suggested that, 
if BSEE intended the proposed testing requirements to apply to 
``flowline'' FSVs, then BSEE should insert ``flowline'' before ``FSVs'' 
in paragraph (c)(2)(v).
    Response--BSEE agrees with the substance of this comment and has 
revised final paragraph (c)(2)(v) to clarify that it applies to 
flowline FSVs and that flowline FSVs are the only FSVs that must be 
leak tested under this provision.
Fire- (Flame, Heat, or Smoke) Detection System Testing
    Comment--A commenter suggested that BSEE revise proposed Sec.  
250.880(c)(3) requirements for fire detections systems to refer to: 
``Fire (flame, heat, or smoke) and Gas (combustible) detection 
systems'' or that BSEE include a separate item (ix) for combustible gas 
detection. In addition, the commenter suggested that BSEE remove the 
proposed requirement that all combustible gas-detection systems must be 
calibrated every 3 months from proposed paragraph (c)(3)(ii) and move 
that provision to a separate paragraph on combustible gas detection.
    Response--BSEE agrees with the commenter's point that there could 
have been some confusion between the item names and the testing 
requirements in paragraph (c)(3)(ii) with regard to gas detection 
systems. However, instead of adopting all of the changes suggested by 
the commenter, BSEE revised the item name for final paragraph 
(c)(3)(ii) to include ``gas detection.'' This is consistent with API 
RP14C; and BSEE added the reference to gas detection systems in this 
paragraph of the final rule to emphasize the need to test those 
systems.
3-Barrier Concept for Undersea Valves
    Comment--BSEE received multiple comments regarding the 3-barrier 
concept for undersea valves. The commenters expressed concern that the 
proposed language would not allow sufficient flexibility for 
compliance. They asserted that some subsea well may not be equipped 
with more than one USV or an additional tree valve that could serve in 
that capacity and that not all tree designs can test multiple barriers.
    Response--No changes are necessary. BSEE is not aware of any subsea 
trees that do not have a second USV. Under final paragraph (d) of this 
section, the 3 pressure barriers are only required in subsea wells that 
are shut-in and disconnected from monitoring capability for more than 6 
months.
Pumps for Firewater Systems
    Comment--A commenter stated that the proposed rule referred to an 
inspection requirement that is not included in the existing 
regulations. The commenter asserted that, under the existing 
regulations, pumps for firewater systems were required to run and be 
tested for operation and pressure on a weekly basis, while the proposed 
rule

[[Page 61902]]

would add an annual inspection for pump performance (flow volume and 
delivery pressure) to ensure the pump system satisfies the system 
design requirements. The commenter asserted that BSEE had not 
identified the rationale for this added inspection or any benefit that 
it would produce. The commenter recommended that this section be 
deleted in its entirety until BSEE fully evaluated the content of API 
RP 14G and the potential value of this requirement.
    Response--No changes are necessary based on this comment. In this 
section, BSEE is not referencing the entire API RP 14G standard; this 
provision only refers to section 7.2 of the standard. This annual 
inspection requirement was added to ensure that the firewater pumps are 
in good working condition since they are a crucial part of the fire 
safety system. API RP 14G, section 7.2 provides the appropriate details 
to ensure that the pump inspection is adequate.
Drilling Vessel in the Field or Readily Accessible
    Comment--A commenter asserted that proposed paragraph (c)(5)(v) was 
confusing and seemed excessive since BSEE had not identified the need 
for having a drilling vessel ``readily available or in the field.'' The 
commenter suggested that BSEE clarify the intent of this proposed rule. 
The commenter also suggested that BSEE clarify the definition of ``in 
the field or readily accessible'' in paragraph (c)(5)(v) and that BSEE 
should determine that rigs should not have to be under direct contract 
to be considered ``readily accessible.'' In addition, the commenter 
asserted that it is also unclear under what circumstances a ``drilling 
vessel'' would be required to intervene in a shut-in well that is 
disconnected from monitoring capability. The commenter stated that 
maintaining a rig on standby would not be cost-effective (although the 
commenter provided no details to support that assertion). The commenter 
recommended revising paragraph (c)(5)(v) to read: ``The designated 
operator/lessee must ensure that a drilling vessel capable of 
intervention into the disconnected well must be available to the 
operator for use should the need arise until the wells are brought on 
line.''
    Response--No changes are necessary based on this comment. The 
regulation states that the drilling vessel must be ``in the field or 
readily accessible.'' This means that a rig needs to be reasonably 
available; the rule does not state or imply that the drilling vessel 
must be under direct contract to be considered readily accessible. The 
regulation is intended to require that an operator have a rig 
reasonably available that can respond in a reasonable timeframe, and 
this is only required for subsea wells that are shut-in and 
disconnected from monitoring capability for periods greater than 6 
months. This provision requires this precaution in order to reduce the 
risks that a prudent operator is reasonably likely to encounter in the 
event that other safety systems on the well fail.
BSDV Leakage Rates
    Comment--A commenter suggested clarifying proposed Sec.  
250.880(c)(4)(iii), regarding testing of BSDVs, by inserting the words 
``and BSDVs'' in the third sentence in that paragraph so that it reads: 
``You must test according to API RP 14H for SSVs and BSDVs 
(incorporated by reference as specified in Sec.  250.198).'' The 
commenter also suggested revising the next sentence in that paragraph 
by replacing the phrase ``if any fluid flow is observed during the 
leakage test'' with ``if fluid leakage exceeding the criteria specified 
in API RP 14H is observed during the leakage test . . .''.
    Response--No changes are necessary based on this comment. The BSDV 
is the surface equivalent of an SSV on a surface well and is critical 
to ensuring the safety of personnel on the facility as well as 
protection of the environment. Because the BSDV is a critical component 
of the subsea system, it is necessary that this valve has rigorous 
testing criteria. Thus, the BSDV cannot have any fluid flow during the 
leakage test.
Records (Sec.  250.890)
    Section summary--BSEE has moved the contents of existing Sec.  
250.804(b), specifying the records for installed safety devices that 
operators must maintain, to final Sec.  250.890 and revised the 
contents for greater clarity and use of plain language. The final rule 
also codifies new information requirements, as proposed, to assist BSEE 
in contacting operators.
    Regulatory text changes from the proposed rule--The term 
``platforms'' was changed to ``facilities'' in paragraph (c), and the 
term ``person in charge'' was changed to ``primary point of contact for 
the facility'' in paragraph (c)(2).
    Comments and responses--BSEE received public comments on this 
section and responds to those comments as follows:
Designated Person in Charge
    Comment--One commenter questioned whether the proposed rule would 
require a facility owner to report a change in the ``designated person 
in charge'' of welding--as specified in Sec. Sec.  250.111 and 
250.113--or a change of the ``designated person in charge'' as required 
by USCG regulations. The commenter also asked whether the proposed rule 
would require a facility owner who designates a separate ``person in 
charge'' for each of the day and night shifts to submit two reports 
daily.
    Response--BSEE agrees that the proposed language in paragraph (c) 
was somewhat unclear, and has revised this provision in the final rule 
to clarify that the person referred to is the ``primary point of 
contact'' for the facility, who must be included on the facility's 
contact list. This section ensures that BSEE has a way to contact the 
facility, when needed, and does not require daily reporting to BSEE. 
The operator is required to update this list annually and whenever the 
contact information changes.
Facility Instead of Platform
    Comment--A commenter requested clarification of the term 
``platform'' as used in proposed paragraph (c). The commenter asked 
whether that term includes FPSs, FPSOs, TLPs, and MODUs. The commenter 
also requested clarification on the responsibilities for MODU owners 
and lease operators for submitting the required contact information if 
this section does consider MODUs to be platforms.
    Response--BSEE agrees that the use of the word ``platforms'' in 
paragraph (c) could cause some confusion, so we replaced that term with 
the word ``facilities'' in the final rule. For purposes of this 
paragraph, facilities include FPSs, FPSOs, and TLPs.
Confirming Compliance
    Comment--A commenter asserted that this proposed section included 
no method for BSEE to confirm compliance. The commenter recommended 
that BSEE consider third-party oversight in the form of an annual 
inspection of records or spot-checks of material maintenance and 
management programs. The commenter suggested that BSEE could use the 
proposed rule section to create positive reinforcement mechanisms.
    Response--No changes are necessary based on this comment. BSEE has 
confidence in its inspection program's ability to confirm compliance. 
BSEE's inspectors confirm that the operators are in compliance with 
BSEE regulations through a number of methods, including verifying 
records and documentation. (See, e.g., Sec.  250.132(b)(3).) Thus, the

[[Page 61903]]

third-party approach recommended by the commenter would appear to be 
less thorough than BSEE's current inspection program. In the future, 
BSEE may consider additional ways to verify documentation and confirm 
compliance.
Safety Device Training (Sec.  250.891)
    Section summary--The final rule recodifies existing Sec.  250.805, 
pertaining to training for personnel who install, inspect, test, and 
maintain safety devices and for personnel who operate production 
facilities as final Sec.  250.891. The wording of this section was 
changed to more accurately capture the scope of subpart S training 
requirements.
    Regulatory text changes from the proposed rule--BSEE added a 
reference to subpart O, in addition to the reference to subpart S.
    Comments and responses--BSEE received public comments on this 
section and responds to those comments as follows:
Referencing Subparts O and S
    Comment--A commenter questioned whether it was BSEE's intent to 
remove the prescriptive training requirements of subpart O and replace 
them with the performance-based requirements of subpart S. If so, the 
commenter suggested that portions of subpart O should be revoked; if 
not, the commenter suggested that subpart O as well as subpart S should 
be referenced.
    Response--BSEE agrees with the commenter's suggestion about 
referring to subpart O in this section. Accordingly, BSEE has changed 
the section to require that personnel installing, repairing, testing, 
maintaining, and operating surface and subsurface safety devices, and 
personnel operating production platforms, be trained according to the 
procedures in subpart O and subpart S. The requirements of subpart O 
are not affected by this rule; likewise subpart S neither replaces nor 
supersedes the requirements in subpart O. Rather, those two subparts 
complement each other. Subpart S provides the general requirements for 
training, and subpart O provides more detailed training requirements 
for well control and production safety. If the operator complies with 
subpart O, then that operator also meets some of the training 
requirements for subpart S.
Mandatory Training
    Comment--One commenter asserted that it is important to human and 
environmental health that oil and gas production companies understand 
all the requirements and components associated with drilling, and have 
an effective quality management system in place. The commenter 
suggested that initial and periodic training sessions be mandatory for 
all oil and gas production operations employees, and that personnel be 
properly trained and qualified to perform their assigned functions, in 
accordance with subpart O.
    Response--No changes to this section are needed in response to this 
comment. Given the multitude of different jobs associated with offshore 
production, it is impractical for this rule to establish specific 
training requirements for each job. However, BSEE regulations under 
subpart S require operators to address appropriate personnel training 
through their SEMS plans. SEMS requires everyone who works offshore to 
be ``trained in accordance with their duties and responsibilities to 
work safely and are aware of potential environmental impacts.'' Sec.  
250.1915. In addition, subpart O provides some specific requirements 
for training. Among other subpart O requirements, Sec.  250.1503(a) 
requires operators to implement training programs so that all employees 
can competently perform their assigned duties, including well control 
and production safety duties. By requiring operators to ensure that 
their personnel are trained in accordance with the procedures in 
subparts O and S, final Sec.  250.891 substantially satisfies the 
commenter's concern that only qualified personnel perform production 
operations functions.
Subpart O
    Comment--While recognizing the intent behind the proposal to move 
training from the subpart O requirements to subpart S, one commenter 
asserted that subpart O is still valid, since it has not been withdrawn 
from the regulations. The commenter stated that subpart O offers more 
detail on training program requirements, compared to subpart S, and it 
is an established basis for all operators' production safety systems 
and well control training programs. The commenter also asserted that 
the proposed rule would impose detailed requirements on the operator 
that are neither specifically required under subpart S nor recommended 
in API RP 75 (Recommended Practice for Development of a Safety and 
Environmental Management Program for Offshore Operations and 
Facilities). The commenter recommended that BSEE revise this section to 
reflect subpart O and not subpart S.
    Response--BSEE largely agrees with the commenter's statements 
concerning the continued applicability of subpart O training 
requirements for personnel performing functions covered by this final 
rule. Proposed Sec.  250.891 was not intended to override subpart O; 
nor does subpart S replace or supersede the requirements in subpart O. 
As already discussed, the two subparts complement each other, in 
general and as applied to subpart H. For that reason, BSEE disagrees 
with the commenter's suggestion that Sec.  250.891 should not refer to 
subpart S. To provide additional clarity on these point, BSEE revised 
final Sec.  250.891 to expressly refer to subpart O as well as subpart 
S.

V. Procedural Matters

Regulatory Planning and Review (E.O. 12866 and E.O. 13563)
    E.O. 12866 provides that the Office of Information and Regulatory 
Affairs (OIRA) will review all significant regulatory actions. A 
significant regulatory action is one that is likely to result in a rule 
that:
     Has an annual effect on the economy of $100 million or 
more, or adversely affects in a material way the economy, a sector of 
the economy, productivity, competition, jobs, the environment, public 
health or safety, or state, local, or tribal governments or 
communities;
     Creates serious inconsistency or otherwise interferes with 
an action taken or planned by another agency;
     Materially alters the budgetary impacts of entitlement 
grants, user fees, loan programs, or the rights and obligations of 
recipients thereof; or
     Raises novel legal or policy issues arising out of legal 
mandates, the President's priorities, or the principles set forth in 
E.O. 12866.
    BSEE has concluded, and OIRA has determined, that this rule is not 
a significant action under E.O. 12866. In particular, BSEE has 
concluded, and OIRA has determined, that this final rule will not have 
an annual economic impact of $100 million or more and will not have a 
material adverse effect on the economy, the environment, public health 
or safety, or governmental communities. In support of that 
determination, BSEE prepared an economic analysis to assess the 
anticipated costs and potential benefits of the rulemaking. The 
following discussions summarize the final economic analysis; a complete 
copy of the final economic analysis can be viewed at 
www.Regulations.gov (use the keyword/ID ``BSEE-2012-0005'').

[[Page 61904]]

1. Need for Regulation
    As discussed in part II of this document, BSEE identified a need to 
amend and update the oil and gas production safety system regulations 
in subpart H. The regulations address such issues as production safety 
systems, subsurface safety devices, and safety device testing. These 
systems play a critical role in protecting workers and the environment.
    Subpart H has not had a major overhaul since it was first published 
in 1988. Since that time, much of the oil and gas production on the OCS 
has moved into deeper waters, and the industry has developed and begun 
employing new technologies, including: Foam firefighting systems; 
subsea pumping, water flooding, and gas lift; and new alloys and 
equipment for high temperature and high pressure wells. The subpart H 
regulations, however, have not kept pace with the technological 
advancements. Many of the new provisions in the final rule serve to 
incorporate and codify current industry practices. In addition, the 
final rule restructures and reorganizes subpart H into shorter, easier-
to-read sections and highlights important information for regulated 
entities. Thus, the final rule will greatly improve the readability and 
understanding of the production safety system regulations.
2. Regulatory Alternatives Considered by BSEE
    In developing this final rule, BSEE considered two major 
alternatives (in addition to the numerous specific choices previously 
described in parts III and IV): (1) Make the regulatory changes 
contained in this final rule; or (2) take no regulatory action and 
continue to rely on the current regulations, first promulgated in 1988, 
in combination with the conditions imposed by subsequent permits and 
plans (i.e., DWOPs), guidance provided to operators in NTLs and other 
documents, and voluntary compliance by operators with relevant industry 
standards. However, relying on specific plan and permit decisions and 
on guidance documents does not optimize regulatory certainty for the 
regulated industry. In addition, relying on voluntary compliance with 
industry standards does not ensure, or provide BSEE with adequate means 
to ensure, that all operators are performing adequately.
    BSEE has elected to move forward with alternative 1 and finalize 
this rule, which codifies existing guidance and relevant standards and 
best industry practices. This alternative will provide industry with 
regulatory certainty, as well as with an appropriate balance of 
prescriptive and flexible, performance-based requirements. It will also 
provide BSEE with the necessary means to ensure that production safety 
systems will improve safety and environmental protection on the OCS, 
resulting in the other benefits described in this summary and the full 
economic analysis. Alternative 2 would be less costly, but would not 
provide those benefits to industry or the public.
3. Summary of Economic Analysis
    BSEE derived its estimates by comparing the costs and benefits of 
the new provisions in the final rule to the baseline in accordance with 
the guidance provided in OMB Circular A-4. In the baseline, BSEE 
includes costs and benefits of the final rule that already occur as a 
result of the existing BSEE regulations, industry guidance documents, 
industry-developed standards and other accepted industry practices with 
which industry already complies.\27\
---------------------------------------------------------------------------

    \27\ BSEE's approach to setting the economic baseline in this 
final rule is consistent with the approach used for the economic 
analysis of the recent Well Control and Blowout Preventer Systems 
final rule. (See, e.g., 81 FR 25985.) The economic analysis for the 
recent Exploratory Drilling on the Arctic OCS final rule used a 
similar but more conservative approach to determine baseline costs 
because of the unique characteristics and remote nature of 
exploratory drilling operation on the Arctic OCS. (See, e.g., 81 FR 
46543.)
    Accordingly, the cost estimate in the final economic analysis 
for the Arctic rule included costs related to some requirements that 
otherwise could have been included in the economic baseline. (See 81 
FR 46543-46550.).
---------------------------------------------------------------------------

    The analysis identified a total of 18 provisions that will result 
in changes from the baseline, which are listed in Table 1 below, 
categorized by the size of the cost that they impose on industry. The 
size categories were defined as follows: ``Major Costs'' being costs of 
at least $1,000 per firm per year, on average as estimated; ``Minor 
Costs'' being less than $1,000 and greater than $100 per firm per year; 
and ``Inconsequential Costs'' being less than $100 per firm per year. 
The number of offshore operators is 99. The cost per firm does not 
include costs to BSEE (which accounted for only about 0.5 percent of 
all costs of all provisions). As shown in Table 1, the distribution of 
costs by provision is extremely skewed, with one of the 18 provisions 
(specifically, Sec.  250.876, ``Fired and Exhaust Heated Components'') 
accounting for over 96 percent of all costs to industry from the rule 
(about $45,000 per firm per year).
    Thus, there is only 1 major cost provision of the final rule. There 
are 7 minor cost provisions (ranging, on average, from $110 to $576 per 
firm per year), and 10 inconsequential cost provisions (ranging from $2 
to $77 per firm per year). The inconsequential costs, in total, account 
for only $185 per firm per year, or less than 0.4 percent of the cost 
of the rule to industry.

[[Page 61905]]

[GRAPHIC] [TIFF OMITTED] TR07SE16.009

    The single major cost provision, Sec.  250.876, will require the 
fire tube for certain tube-type heaters to be removed and inspected, 
every 5 years by a qualified third-party. In addition, if removal and 
inspection indicate tube-type heater deficiencies, operators must 
complete and document repairs or replacements. Inspection results must 
be documented, retained for at least 5 years, and made available to 
BSEE upon request.
    BSEE estimates that there are approximately 1,500 fired and exhaust 
heated components on the OCS that will need to be inspected every 5 
years. Based on comments submitted on the proposed rule and the 
experience of BSEE subject matter experts, the cost associated with 
each component inspection is estimated to be approximately $15,000. We 
estimated the average number of component inspections to be 300 per 
year, resulting in an annual cost to industry of $4.5 million for 
inspection of fired and exhaust heated components.
    Table 2 summarizes the total cost for the final rule over 10 years 
(2016-25) by types of costs, both undiscounted and discounted (using 3 
and 7 percent rates).

[[Page 61906]]

[GRAPHIC] [TIFF OMITTED] TR07SE16.010

    The final rule will benefit society (including both the general 
public and the industry) in two ways: (1) By reducing the probability 
of incidents resulting in oil spills and worker injuries, and the 
severity of such incidents if they occur; and (2) by generating cost 
savings through an increase in allowable leakage rates for certain 
safety valves under final Sec.  250.880, which reduces the need (and 
therefore the costs) to replace or repair such valves, (without 
resulting in oil released into the environment, as previously explained 
in part IV.C of this document). BSEE has also determined that this 
provision poses no economic costs to the regulated industry, so its 
potential economic impact on that industry is only beneficial (due to 
the potential costs savings).
    With respect to oil spills and injuries, however, the magnitude of 
the potential benefits is uncertain and highly dependent on the actual 
reductions in the probability and severity of oil spills and injuries 
that the final rule will achieve.
    Due to this uncertainty, BSEE could not perform a standard cost-
benefit analysis to estimate the net benefits of the final rule. As is 
common in situations where regulatory benefits are highly uncertain, we 
conducted a break-even analysis following OMB guidance in Circular A-4. 
Break-even analysis estimates the minimum risk reduction that the final 
rule will need to achieve for the rule to be cost-beneficial. This 
minimum risk reduction is calculated by dividing the total net costs of 
a regulation by the costs of incidents the regulation is expected to 
avoid. For this analysis, the total net costs are calculated by 
subtracting the equipment cost savings associated with increased 
allowable leakage rates and safety valves from the total cost of the 
rule. BSEE divided the total net costs by the costs associated with oil 
spills and injuries that the regulation might prevent to calculate the 
break-even risk reduction level.
    To analyze potential reductions in oil spills that might result 
from the final rule, BSEE used data on spill incidences on OCS 
facilities from the BOEM OCS Case Study.\28\ BSEE's analysis resulted 
in a potential avoided cost from the final rule of $14.9 million (3,995 
barrels x $3,720 per barrel of oil spilled).
---------------------------------------------------------------------------

    \28\ Source: United States Department of the Interior, Bureau of 
Ocean Energy Management, 2012. ``Economic Analysis Methodology for 
the Five Year OCS Oil and Gas Leasing Program for 2012-2017.'' BOEM 
OCS Study 2012-2022. https://tinyurl.com/zqr68kq.
---------------------------------------------------------------------------

    A similar procedure was used to estimate the level of benefits 
resulting from potentially avoided injuries. (Avoided fatalities were 
not considered because BSEE determined that there were no past 
fatalities that could be directly connected to the provisions related 
to the final rule.) Table 3 presents estimated injury levels (for all 
BSEE Regions where there has been production activity from 2007 through 
2013), which we then used to calculate an annual estimated average 
number of injuries (214). These injury levels were estimated based on 
the numbers of past injuries reported to BSEE (or MMS) by facilities 
that would be affected by the rule. (These estimates are explained in 
greater detail in the final economic analysis document in the 
regulatory docket.)

[[Page 61907]]

[GRAPHIC] [TIFF OMITTED] TR07SE16.011

    We then used that annual average to estimate the number of injuries 
that could potentially be avoided by the final rule. BSEE then 
estimated the corresponding benefits by multiplying the average annual 
number of avoided injuries (214) by the values ascribed to injuries in 
previous BSEE regulatory analyses (about $47,000 per injury). These 
calculations resulted in an annual average of potential avoided cost of 
injuries of $10.1 million, and potential avoided costs from both spills 
and injuries of roughly $25.0 million. (See Table 4.)
[GRAPHIC] [TIFF OMITTED] TR07SE16.012

    In addition to estimating the break-even risk reduction level (see 
discussion and Table 5 below), BSEE used a risk-based approach to cost-
benefit analysis to estimate the potential net benefits of the final 
rule over a range of possible risk reduction levels. Risk-based cost-
benefit analysis involves estimating net benefits over a range of risk 
reduction levels that the regulation could achieve.
    Using the estimated costs, cost savings, and potential benefits (in 
terms of avoided costs of oil spill incidents) of the final rule, BSEE 
calculated the break-even risk reduction level using discount rates of 
3 and 7 percent over a period of 10 years.
    As presented in Table 5, the break-even risk reduction level is 
12.7 percent (undiscounted), 12.2 percent (3 percent discount rate), 
and 11.6 percent (7 percent discount rate). At these levels of risk 
reduction, there would be between 25 and 27 fewer injuries each year. 
This result demonstrates that a relatively small reduction in the risk 
of oil spill incidents on affected OCS facilities will be needed for 
the final rule to be cost-beneficial.

[[Page 61908]]

[GRAPHIC] [TIFF OMITTED] TR07SE16.013

    For the second set of benefits, identified as a cost savings to 
industry, BSEE estimated a net cost (total cost minus total savings) 
for the final rule. To estimate the potential cost savings to operators 
from no longer needing to repair or replace certain safety valves as 
often as under the existing rules, due to higher allowable leakage 
rates under the final rule, BSEE used data from inspection records for 
OCS facilities affected by the rule. Of the active wells on the OCS, 
there have been, on average, 57 occurrences per year of valve repair or 
replacement associated with the existing allowable leakage rates that 
could be affected by the increased allowable leakage rates under the 
final rule. Based on comments submitted on the proposed rule and on the 
experience of BSEE subject matter experts, we estimated that the 
potential costs from the repair or replacement of the safety valves 
would be $22,000 in labor costs and an additional $5,000 in equipment 
replacement costs per repair/replacement. Thus, BSEE estimated the 
annual avoided costs from increasing the allowable leakage rates for 
certain valves to be approximately $1.54 million, based on an estimated 
average of 57 repairs or replacements avoided per year.
    After consideration of all of the potential impacts of this final 
rule, as described here and in the final economic analysis, BSEE has 
concluded that the societal benefits of the final rule justify the 
societal costs.

A. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA), 5 U.S.C. 601-612, requires 
agencies to analyze the economic impact of regulations when there is 
likely to be a significant economic impact on a substantial number of 
small entities and to consider regulatory alternatives that will 
achieve the agency's goals while minimizing the burden on small 
entities. Section 605 of the RFA allows an agency to certify a rule, in 
lieu of preparing an analysis, if the regulation will not have a 
significant economic impact on a substantial number of small entities. 
Further, the Small Business Regulatory Enforcement Fairness Act of 1996 
(SBREFA), Public Law 104-121, (March 29, 1996), as amended, requires 
agencies to produce compliance guidance for small entities if the rule 
has a significant economic impact on a substantial number of small 
entities.
    For the reasons explained in this section, BSEE has determined that 
the rule is not likely to have a significant economic impact on a 
substantial number of small entities and, therefore, that a regulatory 
flexibility analysis for the final rule is not required by the RFA. 
Nonetheless, we have included the equivalent of a final regulatory 
flexibility analysis to assess the impact of this rule on small 
entities, which is included in the full economic analysis available in 
the public docket for this rulemaking at www.regulations.gov.
Small Business Regulatory Enforcement Fairness Act
    The rule is not a major rule under the Small Business Regulatory 
Enforcement Fairness Act, Public Law 104-121, (March 29, 1996), as 
amended. This rule:
    1. Will not have an annual effect on the economy of $100 million or 
more. This rule revises the requirements for oil and gas production 
safety systems. The changes will not have a significant 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 will not add 
significant time to development and production processes. The complete 
annual compliance cost for each affected small entity is estimated at 
$8,183.
    2. Will not cause a major increase in costs or prices for 
consumers, individual industries, Federal, State, or local government 
agencies, or geographic regions.
    3. Will 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 undertake oil and gas 
production operations on the OCS.
    Your comments are important. The Small Business and Agriculture 
Regulatory Enforcement Ombudsman and 10 Regional Fairness Boards were 
established to receive comments from small businesses about Federal 
agency enforcement actions. The Ombudsman will annually evaluate the 
enforcement activities and rate each agency's responsiveness to small 
business. If you wish to comment on the actions of BSEE, call 1-888-
734-3247. You may comment to the Small Business Administration (SBA) 
without fear of retaliation. Allegations of discrimination/retaliation 
filed with the SBA will be investigated for appropriate action.
Unfunded Mandates Reform Act of 1995
    This rule will not impose an unfunded mandate that may result in 
State, local, or tribal governments or in private sector expenditures, 
in the aggregate, of $100 million or more in any one year. The rule 
will not have a significant or unique effect on State, local, or tribal 
governments. A statement containing the information required by the 
Unfunded Mandates Reform Act (2 U.S.C. 1531 et seq.) is not required.

[[Page 61909]]

Takings Implication Assessment (E.O. 12630)
    Under the criteria in E.O. 12630, this rule does not have 
significant takings implications. The rule is not a governmental action 
capable of interfering with constitutionally protected property rights. 
A Takings Implications Assessment is not required.
Federalism (E.O. 13132)
    Under the criteria in E.O. 13132, this rule does not have 
federalism implications. This rule will not substantially and directly 
affect the relationship between the Federal and State governments. To 
the extent that State and local governments have a role in OCS 
activities, this rule will not affect that role. A Federalism 
Assessment is not required.
    BSEE has the authority to regulate offshore oil and gas production. 
State governments do not have authority over offshore oil and gas 
production on the OCS. None of the changes in this rule will affect 
areas that are under the jurisdiction of the States. It will not change 
the way that the States and the Federal government interact, or the way 
that States interact with private companies.
Civil Justice Reform (E.O. 12988)
    This rule complies with the requirements of E.O. 12988. 
Specifically, this rule:
    1. Meets the criteria of section 3(a) requiring that all 
regulations be reviewed to eliminate errors, ambiguity, and be written 
to minimize litigation; and
    2. Meets the criteria of section 3(b)(2) requiring that all 
regulations be written in clear language and contains clear legal 
standards.
Consultation With Indian Tribes (E.O. 13175)
    Under the Department's tribal consultation policy and under the 
criteria in E.O. 13175, we have evaluated this rule and determined that 
it has no substantial direct effects on federally recognized Indian 
tribes and that consultation under the Department's tribal consultation 
policy is not required.
Paperwork Reduction Act (PRA) of 1995
    This rule contains a collection of information that was submitted 
to the Office of Management and Budget (OMB) for review and approval 
under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.). The 
title of the collection of information for this rule is 30 CFR 250, 
subpart H, Oil and Gas Production Safety Systems. The OMB approved the 
collection under Control Number 1014-0003, expiration August 31, 2019, 
containing 95,997 hours and $5,582,481 non-hour cost burdens. Potential 
respondents comprise Federal OCS oil, gas, and sulfur operators and 
lessees. Responses to this collection of information are mandatory or 
are required to obtain or retain a benefit. The frequency of responses 
submitted varies depending upon the requirement; but are usually on 
occasion, annually, and as a result of situations encountered. The ICR 
does not include questions of a sensitive nature. BSEE will protect 
proprietary information according to the Freedom of Information Act (5 
U.S.C. 552) and DOI's implementing regulations (43 CFR part 2), 30 CFR 
250.197, Data and information to be made available to the public or for 
limited inspection, and 30 CFR part 252, OCS Oil and Gas Information 
Program.
    As previously stated, BSEE received 57 sets of comments from 
individual entities (companies, industry organizations, or private 
citizens). BSEE's responses to comments pertaining to the PRA can be 
found in IV.C. (Response to Comments and Section-by-Section Summary) of 
this document.
    Since the original publication of the proposed rule, the ICR for 
subpart H has been renewed and as a result some of the burden hours and 
non-hour cost burdens have increased/decreased based on outreach 
performed during the renewal process. We have accounted for the revised 
burdens in this final rule as follows:
    Sec. Sec.  250.814(a), 250.815(b), 250.828(a), and 250.829(b)--NEW: 
Alternate setting depth requests was identified as information 
collection (+1 hour);
    Sec. Sec.  250.827 and 250.869(a)(3)--NEW: Alternative Procedures 
is covered under subpart A (-3 hours);
    Sec.  250.837(b)(2)--Submit plan to shut-in wells affected by a 
dropped object is covered under APD or APM (-2 hours);
    Sec.  250.841(b)--NEW: Temporary repairs to facility piping 
requests was identified as information collection (+780 hour);
    Sec.  250.852(c)(2)--NEW: Request a different sized PSV was listed 
as 1 hour, 1 response, 5 total burden hours, while it should have been 
1 hour, 1 response, 1 total burden hour (-4 hours);
    Sec.  250.855(a)--NEW: Uniquely identify all ESD stations (Note: 
while this is considered usual and customary business practice, not all 
companies have done this correctly. The burden listed is only for those 
who have new floating facilities) (+32 hours);
    Sec.  250.876--NEW: Document and retain, for at least 5 years, all 
tube-type heater information/requirements; make available to BSEE upon 
request (+300 hours);
    Sec.  250.880(a)(3)--NEW: Notify BSEE and receive approval before 
performing modifications to existing subsea infrastructure (+10 hours);
    Sec.  250.802(c)(1)--NEW: Independent third-party for reviewing and 
certifying various statements (+$550,000);
    Sec.  250.861(b)--NEW: Send foam concentrate sample(s) to 
authorized representative for quality condition testing (+$209,000); 
and
    Sec.  250.876--NEW: Have qualified third party remove and inspect, 
and repair or replace as needed, fire tube (+$4,500,000).
    Also, between the proposed and final rulemaking, the cost recovery 
fees under 30 CFR 250.125 increased based on a final rule published on 
October 1, 2013 (78 FR 60208), which affects several of the 
applications subject to this final rule. The most current approved fees 
and burden hours pertaining to subpart H are listed in the following 
burden table. While the fees for each affected application increased, 
the number of applications went down and the remainder of the 
regulatory requirement burdens in the ICR increased. These changes 
resulted in a net decrease for non-hour cost burdens (-$20,313) and a 
net increase for burden hours (+29,218).
    As stated previously, this final rule also applies to one 
regulation under 30 CFR part 250, subpart A, General (Sec.  
250.107(c)). Once this final rule becomes effective, the paperwork 
burden associated with subpart A will be removed from this collection 
of information and consolidated with the IC burdens under OMB Control 
Number 1014-0022.

[[Page 61910]]

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[[Page 61912]]


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[[Page 61913]]


[GRAPHIC] [TIFF OMITTED] TR07SE16.017


[[Page 61914]]


[GRAPHIC] [TIFF OMITTED] TR07SE16.018


[[Page 61915]]


[GRAPHIC] [TIFF OMITTED] TR07SE16.019

    An agency may not conduct or sponsor, and you are not required to 
respond to, a collection of information unless it displays a currently 
valid OMB control number. The public may comment, at any time, on the 
accuracy of the IC burden in this rule and may submit any comments to 
DOI/BSEE; ATTN: Regulations and Standards Branch; VAE-ORP; 45600 
Woodland Road, Sterling, VA 20166; email kye.mason@bsee.gov, or fax 
(703) 787-1093.
National Environmental Policy Act of 1969 (NEPA)
    We prepared a final environmental assessment to determine whether 
this final rule will have a significant impact on the quality of the 
human environment under NEPA and have concluded that it will not have 
such an impact. This rule does not constitute a major Federal action 
significantly affecting the quality of the human environment. A 
detailed statement under NEPA is not required because we reached a 
Finding of No Significant Impact. A copy of the Environmental 
Assessment and Finding of No Significant Impact can be viewed at 
www.regulations.gov (use the keyword/ID BSEE-2012-0005).
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 rule is not likely to have a significant adverse effect on the 
supply, distribution, or use of energy, and therefore it is not a 
significant energy action under the definition in E.O. 13211. A 
Statement of Energy Effects is not required.

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, Outer Continental Shelf--mineral 
resources, Outer Continental Shelf--rights-of-way, Reporting and 
recordkeeping requirements, Sulfur.

    Dated: August 24, 2016.
Amanda Leiter,
Acting Assistant Secretary--Land and Minerals Management.
    For the reasons stated in the preamble, the Bureau of Safety and 
Environmental Enforcement (BSEE) amends 30 CFR part 250 as follows:

PART 250--OIL AND GAS AND SULFUR OPERATIONS IN THE OUTER 
CONTINENTAL SHELF

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

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

0
2. Amend Sec.  250.107 by revising paragraph (c), removing paragraph 
(d), and redesignating paragraph (e) as paragraph (d) to read as 
follows:


Sec.  250.107  What must I do to protect health, safety, property, and 
the environment?

* * * * *
    (c) Best available and safest technology. (1) On all new drilling 
and production operations and, except as provided in paragraph (c)(3) 
of this section, on existing operations, you must use the best 
available and safest technologies (BAST) which the Director determines 
to be economically feasible whenever the Director determines that 
failure of equipment would have a significant effect on safety, health, 
or the environment, except where the Director determines that the 
incremental benefits are clearly insufficient to justify the 
incremental costs of utilizing such technologies.
    (2) Conformance with BSEE regulations will be presumed to 
constitute the use of BAST unless and until the Director determines 
that other technologies are required pursuant to paragraph (c)(1) of 
this section.

[[Page 61916]]

    (3) The Director may waive the requirement to use BAST on a 
category of existing operations if the Director determines that use of 
BAST by that category of existing operations would not be practicable. 
The Director may waive the requirement to use BAST on an existing 
operation at a specific facility if you submit a waiver request 
demonstrating that the use of BAST would not be practicable.
* * * * *

0
3. Revise the Sec.  250.114 section heading to read as follows:


Sec.  250.114  How must I install, maintain, and operate electrical 
equipment?

* * * * *

0
4. In Sec.  250.125, revise the table in paragraph (a) to read as 
follows:


Sec.  250.125  Service fees.

    (a) * * *

------------------------------------------------------------------------
  Service--processing of the
          following:                  Fee amount         30 CFR citation
------------------------------------------------------------------------
(1) Suspension of Operations/   $2,123................  Sec.
 Suspension of Production (SOO/                          250.171(e).
 SOP) Request.
(2) Deepwater Operations Plan   $3,599................  Sec.
 (DWOP).                                                 250.292(q).
(3) Application for Permit to   $2,113 for initial      Sec.
 Drill (APD); Form BSEE-0123.    applications only; no   250.410(d);
                                 fee for revisions.      Sec.
                                                         250.513(b);
                                                         Sec.
                                                         250.1617(a).
(4) Application for Permit to   $125..................  Sec.
 Modify (APM); Form BSEE-0124.                           250.465(b);
                                                         Sec.
                                                         250.513(b);
                                                         Sec.
                                                         250.613(b);
                                                         Sec.
                                                         250.1618(a);
                                                         Sec.
                                                         250.1704(g).
(5) New Facility Production     $5,426................  Sec.   250.842.
 Safety System Application for  $14,280 additional fee
 facility with more than 125     will be charged if
 components.                     BSEE conducts a pre-
                                 production inspection
                                 of a facility
                                 offshore, and $7,426
                                 for an inspection of
                                 a facility while in a
                                 shipyard.
                                A component is a piece
                                 of equipment or
                                 ancillary system that
                                 is protected by one
                                 or more of the safety
                                 devices required by
                                 API RP 14C (as
                                 incorporated by
                                 reference in Sec.
                                 250.198).
(6) New Facility Production     $1,314................  Sec.   250.842.
 Safety System Application for  $8,967 additional fee
 facility with 25-125            will be charged if
 components.                     BSEE conducts a pre-
                                 production inspection
                                 of a facility
                                 offshore, and $5,141
                                 for an inspection of
                                 a facility while in a
                                 shipyard.
(7) New Facility Production     $652..................  Sec.   250.842.
 Safety System Application for
 facility with fewer than 25
 components.
(8) Production Safety System    $605..................  Sec.   250.842.
 Application--Modification
 with more than 125 components
 reviewed.
(9) Production Safety System    $217..................  Sec.   250.842.
 Application--Modification
 with 25-125 components
 reviewed.
(10) Production Safety System   $92...................  Sec.   250.842.
 Application--Modification
 with fewer than 25 components
 reviewed.
(11) Platform Application--     $22,734...............  Sec.
 Installation--Under the                                 250.905(l).
 Platform Verification Program.
(12) Platform Application--     $3,256................  Sec.
 Installation--Fixed Structure                           250.905(l).
 Under the Platform Approval
 Program.
(13) Platform Application--     $1,657................  Sec.
 Installation--Caisson/Well                              250.905(l)
 Protector.
(14) Platform Application--     $3,884................  Sec.
 Modification/Repair.                                    250.905(l).
(15) New Pipeline Application   $3,541................  Sec.
 (Lease Term).                                           250.1000(b).
(16) Pipeline Application--     $2,056................  Sec.
 Modification (Lease Term).                              250.1000(b).
(17) Pipeline Application--     $4,169................  Sec.
 Modification (ROW).                                     250.1000(b).
(18) Pipeline Repair            $388..................  Sec.
 Notification.                                           250.1008(e).
(19) Pipeline Right-of-Way      $2,771................  Sec.
 (ROW) Grant Application.                                250.1015(a).
(20) Pipeline Conversion of     $236..................  Sec.
 Lease Term to ROW.                                      250.1015(a).
(21) Pipeline ROW Assignment..  $201..................  Sec.
                                                         250.1018(b).
(22) 500 Feet From Lease/Unit   $3,892................  Sec.
 Line Production Request.                                250.1156(a).
(23) Gas Cap Production         $4,953................  Sec.   250.1157.
 Request.
(24) Downhole Commingling       $5,779................  Sec.
 Request.                                                250.1158(a).
(25) Complex Surface            $4,056................  Sec.
 Commingling and Measurement                             250.1202(a);
 Application.                                            Sec.
                                                         250.1203(b);
                                                         Sec.
                                                         250.1204(a).

[[Page 61917]]

 
(26) Simple Surface             $1,371................  Sec.
 Commingling and Measurement                             250.1202(a);
 Application.                                            Sec.
                                                         250.1203(b);
                                                         Sec.
                                                         250.1204(a).
(27) Voluntary Unitization      $12,619...............  Sec.
 Proposal or Unit Expansion.                             250.1303(d).
(28) Unitization Revision.....  $896..................  Sec.
                                                         250.1303(d).
(29) Application to Remove a    $4,684................  Sec.   250.1727.
 Platform or Other Facility.
(30) Application to             $1,142................  Sec.
 Decommission a Pipeline                                 250.1751(a) or
 (Lease Term).                                           Sec.
                                                         250.1752(a).
(31) Application to             $2,170................  Sec.
 Decommission a Pipeline (ROW).                          250.1751(a) or
                                                         Sec.
                                                         250.1752(a).
------------------------------------------------------------------------

* * * * *

0
5. Amend Sec.  250.198 as follows:
0
a. Revise paragraphs (g)(1) through (3);
0
b. Remove paragraphs (g)(6) and (7);
0
c. Redesignate paragraph (g)(8) as (g)(6);
0
d. Revise paragraphs, (h)(1), (51) through (53), (55) through (62), 
(65), (66), (68), (70), (71), (73), (74), and (93) through (95);
0
e. Add paragraph (h)(96).
    The revisions and addition 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, 2004 Edition; and 
July 1, 2005 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, 2004 Edition; July 1, 
2005 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, 2004 Edition; 
July 1, 2005 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, Ninth 
Edition, June 2006; incorporated by reference at Sec. Sec.  250.851(a) 
and 250.1629(b);
* * * * *
    (51) API RP 2RD, Recommended Practice for Design of Risers for 
Floating Production Systems (FPSs) and Tension-Leg Platforms (TLPs), 
First Edition, June 1998; reaffirmed, May 2006, Errata, June 2009; 
incorporated by reference at Sec. Sec.  250.292, 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; incorporated by reference at Sec. Sec.  
250.800(c) and 250.901(a), (d);
    (53) API RP 2SM, Recommended Practice for Design, Manufacture, 
Installation, and Maintenance of Synthetic Fiber Ropes for Offshore 
Mooring, First Edition, March 2001, Addendum, May 2007; incorporated by 
reference at Sec. Sec.  250.800(c) and 250.901;
* * * * *
    (55) ANSI/API RP 14B, Recommended Practice for Design, 
Installation, Repair and Operation of Subsurface Safety Valve Systems, 
Fifth Edition, October 2005; 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 Basic Surface Safety Systems for Offshore 
Production Platforms, Seventh Edition, March 2001, Reaffirmed: March 
2007; incorporated by reference at Sec. Sec.  250.125(a), 250.292(j), 
250.841(a), 250.842(a), 250.850, 250.852(a), 250.855, 250.856(a), 
250.858(a), 250.862(e), 250.865(a), 250.867(a), 250.869(a) through (c), 
250.872(a), 250.873(a), 250.874(a), 250.880(b) and (c), 250.1002(d), 
250.1004(b), 250.1628(c) and (d), 250.1629(b), and 250.1630(a);
    (57) API RP 14E, Recommended Practice for Design and Installation 
of Offshore Production Platform Piping Systems, Fifth Edition, October 
1991; Reaffirmed, January 2013; incorporated by reference at Sec. Sec.  
250.841(b), 250.842(a), and 250.1628(b) and (d);
    (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(b), 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, First Edition, September 2001, Reaffirmed: March 2007; 
incorporated by reference at Sec. Sec.  250.114(c), 250.842(b), 
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 2007; incorporated by reference at Sec. Sec.  
250.859(a), 250.862(e), 250.880(c), and 250.1629(b);
    (61) API RP 14H, Recommended Practice for Installation, Maintenance 
and Repair of Surface Safety Valves and Underwater Safety Valves 
Offshore, Fifth Edition, August 2007; 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 
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(b), 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, Second Edition, 
November 1997; Errata (August 17, 1998), Reaffirmed November 2002; 
incorporated by reference at

[[Page 61918]]

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);
    (66) API RP 505, Recommended Practice for Classification of 
Locations for Electrical Installations at Petroleum Facilities 
Classified as Class I, Zone 0, Zone 1, and Zone 2, First Edition, 
November 1997; Reaffirmed, August 2013; incorporated by reference at 
Sec. Sec.  250.114(a), 250.459, 250.842(a), 250.862(a) and (e), 
250.872(a), 250.1628(b) and (d), and 250.1629(b);
* * * * *
    (68) ANSI/API Specification Q1 (ANSI/API Spec. Q1), Specification 
for Quality Programs for the Petroleum, Petrochemical and Natural Gas 
Industry, Eighth Edition, December 2007, Addendum 1, June 2010; 
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, Nineteenth Edition, July 
2004; Errata 1 (September 2004), Errata 2 (April 2005), Errata 3 (June 
2006) Errata 4 (August 2007), Errata 5 (May 2009), Addendum 1 (February 
2008), Addenda 2, 3, and 4 (December 2008); 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, First Edition, February 1, 1996; reaffirmed April 
2008; 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, Eleventh Edition, October 2005, Reaffirmed, June 2012; 
incorporated by reference at Sec. Sec.  250.802(b) and 250.803(a);
    (74) ANSI/API Spec. 17J, Specification for Unbonded Flexible Pipe, 
Third Edition, July 2008, incorporated by reference at Sec. Sec.  
250.852(e), 250.1002(b), and 250.1007(a).
* * * * *
    (93) ANSI/API Specification 17D, Design and Operation of Subsea 
Production Systems--Subsea Wellhead and Tree Equipment, Second Edition, 
May 2011, incorporated by reference at Sec.  250.730;
    (94) ANSI/API Recommended Practice 17H, Remotely Operated Vehicle 
Interfaces on Subsea Production Systems, First Edition, July 2004, 
Reaffirmed January 2009, incorporated by reference at Sec.  250.734;
    (95) ANSI/API RP 2N, Third Edition, ``Recommended Practice for 
Planning, Designing, and Constructing Structures and Pipelines for 
Arctic Conditions'', Third Edition, April 2015; incorporated by 
reference at Sec.  250.470(g); and
    (96) API 570 Piping Inspection Code: In-service Inspection, Rating, 
Repair, and Alteration of Piping Systems, Third Edition, November 2009; 
incorporated by reference at Sec.  250.841(b).
* * * * *

0
6. Revise Sec.  250.518(d) to read as follows:


Sec.  250.518  Tubing and wellhead equipment.

* * * * *
    (d) Subsurface safety equipment must be installed, maintained, and 
tested in compliance with the applicable sections in Sec. Sec.  250.810 
through 250.839.
* * * * *

0
7. Revise Sec.  250.619(d) to read as follows:


Sec.  250.619  Tubing and wellhead equipment.

* * * * *
    (d) Subsurface safety equipment must be installed, maintained, and 
tested in compliance with the applicable sections in Sec. Sec.  250.810 
through 250.839.
* * * * *

0
8. Revise subpart H to read as follows:
Subpart H--Oil and Gas Production Safety Systems

General Requirements

Sec.
250.800 General.
250.801 Safety and pollution prevention equipment (SPPE) 
certification.
250.802 Requirements for SPPE.
250.803 What SPPE failure reporting procedures must I follow?
250.804 Additional requirements for subsurface safety valves (SSSVs) 
and related equipment installed in high pressure high temperature 
(HPHT) environments.
250.805 Hydrogen sulfide.
250.806-250.809 [Reserved]

Surface and Subsurface Safety Systems--Dry Trees

250.810 Dry tree subsurface safety devices--general.
250.811 Specifications for SSSVs--dry trees.
250.812 Surface-controlled SSSVs--dry trees.
250.813 Subsurface-controlled SSSVs.
250.814 Design, installation, and operation of SSSVs--dry trees.
250.815 Subsurface safety devices in shut-in wells--dry trees.
250.816 Subsurface safety devices in injection wells--dry trees.
250.817 Temporary removal of subsurface safety devices for routine 
operations.
250.818 Additional safety equipment--dry trees.
250.819 Specification for surface safety valves (SSVs).
250.820 Use of SSVs.
250.821 Emergency action and safety system shutdown--dry trees.
250.822-250.824 [Reserved]

Subsea and Subsurface Safety Systems--Subsea Trees

250.825 Subsea tree subsurface safety devices--general.
250.826 Specifications for SSSVs--subsea trees.
250.827 Surface-controlled SSSVs--subsea trees.
250.828 Design, installation, and operation of SSSVs--subsea trees.
250.829 Subsurface safety devices in shut-in wells--subsea trees.
250.830 Subsurface safety devices in injection wells--subsea trees.
250.831 Alteration or disconnection of subsea pipeline or umbilical.
250.832 Additional safety equipment--subsea trees.
250.833 Specification for underwater safety valves (USVs).
250.834 Use of USVs.
250.835 Specification for all boarding shutdown valves (BSDVs) 
associated with subsea systems.
250.836 Use of BSDVs.
250.837 Emergency action and safety system shutdown--subsea trees.
250.838 What are the maximum allowable valve closure times and 
hydraulic bleeding requirements for an electro-hydraulic control 
system?
250.839 What are the maximum allowable valve closure times and 
hydraulic bleeding requirements for a direct-hydraulic control 
system?

Production Safety Systems

250.840 Design, installation, and maintenance--general.
250.841 Platforms.
250.842 Approval of safety systems design and installation features.
250.843-250.849 [Reserved]

Additional Production System Requirements

250.850 Production system requirements--general.
250.851 Pressure vessels (including heat exchangers) and fired 
vessels.
250.852 Flowlines/Headers.
250.853 Safety sensors.
250.854 Floating production units equipped with turrets and turret-
mounted systems.
250.855 Emergency shutdown (ESD) system.
250.856 Engines.
250.857 Glycol dehydration units.
250.858 Gas compressors.
250.859 Firefighting systems.
250.860 Chemical firefighting system.
250.861 Foam firefighting systems.
250.862 Fire and gas-detection systems.
250.863 Electrical equipment.
250.864 Erosion.
250.865 Surface pumps.
250.866 Personnel safety equipment.
250.867 Temporary quarters and temporary equipment.

[[Page 61919]]

250.868 Non-metallic piping.
250.869 General platform operations.
250.870 Time delays on pressure safety low (PSL) sensors.
250.871 Welding and burning practices and procedures.
250.872 Atmospheric vessels.
250.873 Subsea gas lift requirements.
250.874 Subsea water injection systems.
250.875 Subsea pump systems.
250.876 Fired and exhaust heated components.
250.877-250.879 [Reserved]

Safety Device Testing

250.880 Production safety system testing.
250.881-250.889 [Reserved]

Records and Training

250.890 Records.
250.891 Safety device training.
250.892-250.899 [Reserved]

Subpart H--Oil and Gas Production Safety Systems

General Requirements


Sec.  250.800  General.

    (a) You must design, install, use, maintain, and test production 
safety equipment in a manner to ensure the safety and protection of the 
human, marine, and coastal environments. For production safety systems 
operated in subfreezing climates, you must use equipment and procedures 
that account for floating ice, icing, and other extreme environmental 
conditions that may occur in the area. You must not commence production 
until BSEE approves your production safety system application and you 
have requested a preproduction inspection.
    (b) For all new production systems on fixed leg platforms, you must 
comply with API RP 14J (incorporated by reference as specified in Sec.  
250.198);
    (c) For all new floating production systems (FPSs) (e.g., column-
stabilized-units (CSUs); floating production, storage and offloading 
facilities (FPSOs); tension-leg platforms (TLPs); and spars), you must:
    (1) Comply with API RP 14J;
    (2) Meet the production riser standards of API RP 2RD (incorporated 
by reference as specified in Sec.  250.198), provided that you may not 
install single bore production risers from floating production 
facilities;
    (3) Design all stationkeeping (i.e., anchoring and mooring) systems 
for floating production facilities to meet the standards of API RP 2SK 
and API RP 2SM (both incorporated by reference as specified in Sec.  
250.198); and
    (4) Design stationkeeping (i.e., anchoring and mooring) systems for 
floating facilities to meet the structural requirements of Sec. Sec.  
250.900 through 250.921.
    (d) If there are any conflicts between the documents incorporated 
by reference and the requirements of this subpart, you must follow the 
requirements of this subpart.
    (e) You may use alternate procedures or equipment during operations 
after receiving approval from the District Manager. You must present 
your proposed alternate procedures or equipment as required by Sec.  
250.141.
    (f) You may apply for a departure from the operating requirements 
of this subpart as provided by Sec.  250.142. Your written request must 
include a justification showing why the departure is necessary and 
appropriate.


Sec.  250.801  Safety and pollution prevention equipment (SPPE) 
certification.

    (a) SPPE equipment. In wells located on the OCS, 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, as of 
September 7, 2017. For subsea wells, the BSDV is the surface equivalent 
of an SSV on a surface well;
    (3) Underwater safety valves (USV) and actuators; and
    (4) Subsurface safety valves (SSSV) and associated safety valve 
locks and landing nipples.
    (b) Certification of SPPE. SPPE that is manufactured and marked 
pursuant to ANSI/API Spec. Q1 (incorporated by reference as specified 
in Sec.  250.198), is considered as certified SPPE under this part. All 
other SPPE is considered as not certified, unless approved in 
accordance with paragraph (c) of this section.
    (c) Accepting SPPE manufactured under other quality assurance 
programs. BSEE may exercise its discretion to accept SPPE manufactured 
under a quality assurance program other than ANSI/API Spec. Q1, 
provided that the alternative quality assurance program is verified as 
equivalent to API Spec. Q1 by an appropriately qualified entity and 
that the operator submits a request to BSEE containing relevant 
information about the alternative program and receives BSEE approval. 
In addition, an operator may request that BSEE accept SPPE that is 
marked with a third-party certification mark other than the API 
monogram. All requests under this paragraph should be submitted to the 
Chief, Office of Offshore Regulatory Programs; Bureau of Safety and 
Environmental Enforcement; VAE-ORP; 45600 Woodland Road, Sterling, VA 
20166.


Sec.  250.802  Requirements for SPPE.

    (a) All SSVs, BSDVs, and USVs 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).
    (b) All SSSVs and their actuators must meet all of the 
specifications and recommended practices of ANSI/API Spec. 14A and 
ANSI/API RP 14B, including all annexes (both incorporated by reference 
as specified in Sec.  250.198). Subsurface-controlled SSSVs are not 
allowed on subsea wells.
    (c) Requirements derived from the documents incorporated in this 
section for SSVs, BSDVs, USVs, and SSSVs and their actuators, include, 
but are not limited to, the following:
    (1) Each device must be designed to function and to close in the 
most extreme conditions to which it may be exposed, including 
temperature, pressure, flow rates, and environmental conditions. You 
must have an independent third-party review and certify that each 
device will function as designed under the conditions to which it may 
be exposed. The independent third-party must have sufficient expertise 
and experience to perform the review and certification.
    (2) All materials and parts must meet the original equipment 
manufacturer specifications and acceptance criteria.
    (3) The device must pass applicable validation tests and functional 
tests performed by an API-licensed test agency.
    (4) You must have requalification testing performed following 
manufacture design changes.
    (5) You must comply with and document all manufacturing, 
traceability, quality control, and inspection requirements.
    (6) You must follow specified installation, testing, and repair 
protocols.
    (7) 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.

[[Page 61920]]



------------------------------------------------------------------------
                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 on
 service . . ..                           that well.
(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.
------------------------------------------------------------------------

    (e) You must retain all documentation related to the manufacture, 
installation, testing, repair, redress, and performance of the SPPE 
until 1 year after the date of decommissioning of the equipment.


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 API Spec. 6A for SSVs, BSDVs, and USVs and section 
7.10 of API Spec. 14A and Annex F of API RP 14B for SSSVs (all 
incorporated by reference in Sec.  250.198). You must provide a written 
notice of equipment failure to the Chief, Office of Offshore Regulatory 
Programs or to the Chief's designee and to the manufacturer of such 
equipment within 30 days after the discovery and identification of the 
failure. A failure is any condition that prevents the equipment from 
meeting the functional specification 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 manufacturer 
and the Chief, Office of Offshore Regulatory Programs or the Chief's 
designee receives a copy of the analysis report. 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 the Chief, Office of Offshore Regulatory 
Programs or the Chief's designee.
    (d) Any notifications or reports submitted to the Chief, Office of 
Offshore Regulatory Programs under paragraphs (a), (b), and (c) of this 
section must be sent to: Bureau of Safety and Environmental 
Enforcement; VAE-ORP, 45600 Woodland Road, Sterling, VA 20166.


Sec.  250.804  Additional requirements for subsurface safety valves 
(SSSVs) and related equipment installed in high pressure high 
temperature (HPHT) environments.

    (a) If you plan to install SSSVs and related equipment in an HPHT 
environment, you must submit detailed information with your Application 
for Permit to Drill (APD) or Application for Permit to Modify (APM), 
and Deepwater Operations Plan (DWOP) that demonstrates the SSSVs and 
related equipment are capable of performing in the applicable HPHT 
environment. Your detailed information must include the following:
    (1) A discussion of the SSSVs' and related equipment's design 
verification analyses;
    (2) A discussion of the SSSVs' and related equipment's design 
validation and functional testing processes and procedures used; and
    (3) An explanation of why the analyses, processes, and procedures 
ensure that the SSSVs and related equipment are fit-for-service in the 
applicable HPHT environment.
    (b) For this section, HPHT environment means when one or more of 
the following well conditions exist:
    (1) The completion of the well requires completion equipment or 
well control equipment assigned a pressure rating greater than 15,000 
psia or a temperature rating greater than 350 degrees Fahrenheit;
    (2) The maximum anticipated surface pressure or shut-in tubing 
pressure is greater than 15,000 psia on the seafloor for a well with a 
subsea wellhead or at the surface for a well with a surface wellhead; 
or
    (3) The flowing temperature is equal to or greater than 350 degrees 
Fahrenheit on the seafloor for a well with a subsea wellhead or at the 
surface for a well with a surface wellhead.
    (c) For this section, related equipment includes wellheads, tubing 
heads, tubulars, packers, threaded connections, seals, seal assemblies, 
production trees, chokes, well control equipment, and any other 
equipment that will be exposed to the HPHT environment.


Sec.  250.805  Hydrogen sulfide.

    (a) In zones known to contain hydrogen sulfide (H2S) or 
in zones where the presence of H2S is unknown, as defined in 
Sec.  250.490, you must conduct production operations in accordance 
with that section and other relevant requirements of this subpart.
    (b) You must receive approval through the DWOP process (Sec. Sec.  
250.286 through 250.295) for production operations in HPHT environments 
known to contain H2S or in HPHT environments where the 
presence of H2S is unknown.


Sec. Sec.  250.806--250.809   [Reserved]

Surface and Subsurface Safety Systems--Dry Trees


Sec.  250.810  Dry tree subsurface safety devices--general.

    For wells using dry trees or for which you intend to install dry 
trees, you must equip all tubing installations open to hydrocarbon-
bearing zones with subsurface safety devices that will shut off the 
flow from the well in the event of an emergency unless, after you 
submit a request containing a justification, the District Manager 
determines the well to be incapable of natural flow. You must install 
flow couplings above and below the subsurface safety devices. These 
subsurface safety devices include the following devices and any 
associated safety valve lock and landing nipple:
    (a) An SSSV, including either:
    (1) A surface-controlled SSSV; or
    (2) A subsurface-controlled SSSV.
    (b) An injection valve.
    (c) A tubing plug.
    (d) A tubing/annular subsurface safety device.


Sec.  250.811  Specifications for SSSVs--dry trees.

    All surface-controlled and subsurface-controlled SSSVs, safety 
valve locks, and landing nipples installed in the OCS must conform to 
the requirements specified in Sec. Sec.  250.801 through 250.803.


Sec.  250.812  Surface-controlled SSSVs--dry trees.

    You must equip all tubing installations open to a hydrocarbon-
bearing zone that is capable of natural flow with a surface-controlled 
SSSV, except as specified in Sec. Sec.  250.813, 250.815, and 250.816.
    (a) The surface controls must be located on the site or at a BSEE-
approved remote location. You may request District Manager approval to

[[Page 61921]]

situate the surface controls at a remote location.
    (b) You must equip dry tree wells not previously equipped with a 
surface-controlled SSSV, and dry tree wells in which a surface-
controlled SSSV has been replaced with a subsurface-controlled SSSV, 
with a surface-controlled SSSV when the tubing is first removed and 
reinstalled.


Sec.  250.813  Subsurface-controlled SSSVs.

    You may submit an APM or a request to the District Manager for 
approval to equip a dry tree well with a subsurface-controlled SSSV in 
lieu of a surface-controlled SSSV, if the subsurface-controlled SSSV is 
installed in a well equipped with a surface-controlled SSSV that has 
become inoperable and cannot be repaired without removal and 
reinstallation of the tubing. If you remove and reinstall the tubing, 
you must equip the well with a surface-controlled SSSV.


Sec.  250.814  Design, installation, and operation of SSSVs--dry trees.

    You must design, install, and operate (including repair, maintain, 
and test) an SSSV to ensure its reliable operation.
    (a) You must install the SSSV at a depth at least 100 feet below 
the mudline within 2 days after production is established. When 
warranted by conditions such as permafrost, unstable bottom conditions, 
hydrate formation, or paraffin problems, the District Manager may 
approve an alternate setting depth on a case-by-case basis.
    (b) The well must not be open to flow while the SSSV is inoperable, 
except when flowing the well is necessary for a particular operation 
such as cutting paraffin or performing other routine operations as 
defined in Sec.  250.601.
    (c) Until the SSSV is installed, the well must be attended in the 
immediate vicinity so that any necessary emergency actions can be taken 
while the well is open to flow. During testing and inspection 
procedures, the well must not be left unattended while open to 
production unless you have installed a properly operating SSSV in the 
well.
    (d) You must design, install, maintain, inspect, repair, and test 
all SSSVs in accordance with API RP 14B (incorporated by reference as 
specified in Sec.  250.198). For additional SSSV testing requirements, 
refer to Sec.  250.880.


Sec.  250.815  Subsurface safety devices in shut-in wells--dry trees.

    (a) You must equip all new dry tree completions (perforated but not 
placed on production) and completions that are shut-in for a period of 
6 months with one of the following:
    (1) A pump-through-type tubing plug;
    (2) A surface-controlled SSSV, provided the surface control has 
been rendered inoperative; or
    (3) An injection valve capable of preventing backflow.
    (b) When warranted by conditions such as permafrost, unstable 
bottom conditions, hydrate formation, and paraffin problems, the 
District Manager must approve the setting depth of the subsurface 
safety device for a shut-in well on a case-by-case basis.


Sec.  250.816  Subsurface safety devices in injection wells--dry trees.

    You must install a surface-controlled SSSV or an injection valve 
capable of preventing backflow in all injection wells. This requirement 
is not applicable if the District Manager determines that the well is 
incapable of natural flow. You must verify the no-flow condition of the 
well annually.


Sec.  250.817  Temporary removal of subsurface safety devices for 
routine operations.

    (a) You may remove a wireline- or pumpdown-retrievable subsurface 
safety device without further authorization or notice, for a routine 
operation that does not require BSEE approval of a Form BSEE-0124, 
Application for Permit to Modify (APM). For a list of these routine 
operations, see Sec.  250.601. The removal period must not exceed 15 
days.
    (b) Prior to removal, you must identify the well by placing a sign 
on the wellhead stating that the subsurface safety device was removed. 
You must note the removal of the subsurface safety device in the 
records required by Sec.  250.890. If the master valve is open, you 
must ensure that a trained person (see Sec.  250.891) is in the 
immediate vicinity to attend the well and take any necessary emergency 
actions.
    (c) You must monitor a platform well when a subsurface safety 
device has been removed, but a person does not need to remain in the 
well-bay area continuously if the master valve is closed. If the well 
is on a satellite structure, it must be attended by a support vessel, 
or a pump-through plug must be installed in the tubing at least 100 
feet below the mudline and the master valve must be closed, unless 
otherwise approved by the appropriate District Manager.
    (d) You must not allow the well to flow while the subsurface safety 
device is removed, except when it is necessary for the particular 
operation for which the SSSV is removed. The provisions of this 
paragraph are not applicable to the testing and inspection procedures 
specified in Sec.  250.880.


Sec.  250.818  Additional safety equipment--dry trees.

    (a) You must equip all tubing installations that have a wireline- 
or pumpdown-retrievable subsurface safety device with a landing nipple, 
with flow couplings or other protective equipment above and below it to 
provide for the setting of the device.
    (b) The control system for all surface-controlled SSSVs must be an 
integral part of the platform emergency shutdown system (ESD).
    (c) In addition to the activation of the ESD by manual action on 
the platform, the system may be activated by a signal from a remote 
location. Surface-controlled SSSVs must close in response to shut-in 
signals from the ESD and in response to the fire loop or other fire 
detection devices.


Sec.  250.819  Specification for surface safety valves (SSVs).

    All wellhead SSVs and their actuators must conform to the 
requirements specified in Sec. Sec.  250.801 through 250.803.


Sec.  250.820  Use of SSVs.

    You must install, maintain, inspect, repair, and test all SSVs in 
accordance with API RP 14H (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.


Sec.  250.821  Emergency action and safety system shutdown--dry trees.

    (a) In the event of an emergency, such as an impending National 
Weather Service-named tropical storm or hurricane:
    (1) Any well not yet equipped with a subsurface safety device and 
that is capable of natural flow must have the subsurface safety device 
properly installed as soon as possible, with due consideration being 
given to personnel safety.
    (2) You must shut-in (by closing the SSV and the surface-controlled 
SSSV) the following types of wells:
    (i) All oil wells, and
    (ii) All gas wells requiring compression.
    (b) Closure of the SSV must not exceed 45 seconds after automatic 
detection of an abnormal condition or actuation of an ESD. The surface-
controlled SSSV must close within 2 minutes after the shut-in signal 
has closed the SSV. The District Manager must approve any alternative 
design-delayed closure time of greater than 2

[[Page 61922]]

minutes based on the mechanical/production characteristics of the 
individual well.


Sec. Sec.  250.822--250.824  [Reserved]

Subsea and Subsurface Safety Systems--Subsea Trees


Sec.  250.825  Subsea tree subsurface safety devices--general.

    (a) For wells using subsea (wet) trees or for which you intend to 
install subsea trees, you must equip all tubing installations open to 
hydrocarbon-bearing zones with subsurface safety devices that will shut 
off the flow from the well in the event of an emergency. You must also 
install flow couplings above and below the subsurface safety devices. 
For instances where the well at issue is incapable of natural flow, you 
may seek District Manager approval for using alternative procedures or 
equipment, if you propose to use a subsea safety system that is not 
capable of shutting off the flow from the well in the event of an 
emergency. Subsurface safety devices include the following and any 
associated safety valve lock and landing nipple:
    (1) A surface-controlled SSSV;
    (2) An injection valve;
    (3) A tubing plug; and
    (4) A tubing/annular subsurface safety device.
    (b) After installing the subsea tree, but before the rig or 
installation vessel leaves the area, you must test all valves and 
sensors to ensure that they are operating as designed and meet all the 
conditions specified in this subpart.


Sec.  250.826  Specifications for SSSVs--subsea trees.

    All SSSVs, safety valve locks, and landing nipples installed on the 
OCS must conform to the requirements specified in Sec. Sec.  250.801 
through 250.803 and any Deepwater Operations Plan (DWOP) required by 
Sec. Sec.  250.286 through 250.295.


Sec.  250.827  Surface-controlled SSSVs--subsea trees.

    You must equip all tubing installations open to a hydrocarbon-
bearing zone that is capable of natural flow with a surface-controlled 
SSSV, except as specified in Sec. Sec.  250.829 and 250.830. The 
surface controls must be located on the host facility.


Sec.  250.828  Design, installation, and operation of SSSVs--subsea 
trees.

    You must design, install, and operate (including repair, maintain, 
and test) an SSSV to ensure its reliable operation.
    (a) You must install the SSSV at a depth at least 100 feet below 
the mudline. When warranted by conditions, such as unstable bottom 
conditions, permafrost, hydrate formation, or paraffin problems, the 
District Manager may approve an alternate setting depth on a case-by-
case basis.
    (b) The well must not be open to flow while an SSSV is inoperable, 
unless specifically approved by the District Manager in an APM.
    (c) You must design, install, maintain, inspect, repair, and test 
all SSSVs in accordance with your Deepwater Operations Plan (DWOP) and 
API RP 14B (incorporated by reference as specified in Sec.  250.198). 
For additional SSSV testing requirements, refer to Sec.  250.880.


Sec.  250.829  Subsurface safety devices in shut-in wells--subsea 
trees.

    (a) You must equip all new subsea tree completions (perforated but 
not placed on production) and completions shut-in for a period of 6 
months with one of the following:
    (1) A pump-through-type tubing plug;
    (2) An injection valve capable of preventing backflow; or
    (3) A surface-controlled SSSV, provided the surface control has 
been rendered inoperative. For purposes of this section, a surface-
controlled SSSV is considered inoperative if, for a direct hydraulic 
control system, you have bled the hydraulics from the control line and 
have isolated it from the hydraulic control pressure. If your controls 
employ an electro-hydraulic control umbilical and the hydraulic control 
pressure to the individual well cannot be isolated, a surface-
controlled SSSV is considered inoperative if you perform the following:
    (i) Disable the control function of the surface-controlled SSSV 
within the logic of the programmable logic controller which controls 
the subsea well;
    (ii) Place a pressure alarm high on the control line to the 
surface-controlled SSSV of the subsea well; and
    (iii) Close the USV and at least one other tree valve on the subsea 
well.
    (b) When warranted by conditions, such as unstable bottom 
conditions, permafrost, hydrate formation, and paraffin problems, the 
District Manager must approve the setting depth of the subsurface 
safety device for a shut-in well on a case-by-case basis.


Sec.  250.830  Subsurface safety devices in injection wells--subsea 
trees.

    You must install a surface-controlled SSSV or an injection valve 
capable of preventing backflow in all injection wells. This requirement 
is not applicable if the District Manager determines that the well is 
incapable of natural flow. You must verify the no-flow condition of the 
well annually.


Sec.  250.831   Alteration or disconnection of subsea pipeline or 
umbilical.

    If a necessary alteration or disconnection of the pipeline or 
umbilical of any subsea well would affect your ability to monitor 
casing pressure or to test any subsea valves or equipment, you must 
contact the appropriate District Office at least 48 hours in advance 
and submit a repair or replacement plan to conduct the required 
monitoring and testing. You must not alter or disconnect until the 
repair or replacement plan is approved.


Sec.  250.832   Additional safety equipment--subsea trees.

    (a) You must equip all tubing installations that have a wireline- 
or pump down-retrievable subsurface safety device installed after May 
31, 1988, with a landing nipple, with flow couplings, or other 
protective equipment above and below it to provide for the setting of 
the device.
    (b) The control system for all surface-controlled SSSVs must be an 
integral part of the platform ESD.
    (c) In addition to the activation of the ESD by manual action on 
the platform, the system may be activated by a signal from a remote 
location.


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 API Spec. 6A and API Spec. 6AV1 (both 
incorporated by reference as specified in Sec.  250.198).
    (a) Primary USV (USV1). You must install and designate one USV on a 
subsea tree as the USV1. The USV1 must be located upstream of the choke 
valve. As provided in paragraph (b) of this section, you must inform 
BSEE if the primary USV designation changes.
    (b) Secondary USV (USV2). You may equip your tree with two or more 
valves qualified to be designated as a USV, one of which may be 
designated as the USV2. If the USV1 fails to operate properly or 
exhibits a leakage rate greater than allowed in Sec.  250.880, you must 
notify the appropriate District Office and designate the USV2 or 
another qualified valve (e.g., an AIV) that meets all the requirements 
of this subpart for USVs as the USV1. The

[[Page 61923]]

USV2 must be located upstream of the choke.


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 RP 
14H (incorporated by reference as specified in Sec.  250.198). For 
additional USV testing requirements, refer to Sec.  250.880.


Sec.  250.835  Specification for all boarding shutdown valves (BSDVs) 
associated with subsea systems.

    You must install a BSDV on the pipeline boarding riser. All new 
BSDVs and any BSDVs removed from service for remanufacturing or repair 
and their actuators installed on the OCS must meet the requirements 
specified in Sec. Sec.  250.801 through 250.803. In addition, you must:
    (a) Ensure that the internal design pressure(s) of the pipeline(s), 
riser(s), and BSDV(s) is fully rated for the maximum pressure of any 
input source and complies with the design requirements set forth in 
subpart J, unless BSEE approves an alternate design.
    (b) Use a BSDV that is fire rated for 30 minutes, and is pressure 
rated for the maximum allowable operating pressure (MAOP) approved in 
your pipeline application.
    (c) Locate the BSDV within 10 feet of the first point of access to 
the boarding pipeline riser (i.e., within 10 feet of the edge of 
platform if the BSDV is horizontal, or within 10 feet above the first 
accessible working deck, excluding the boat landing and above the 
splash zone, if the BSDV is vertical).
    (d) Install a temperature safety element (TSE) and locate it within 
5 feet of each BSDV.


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 RP 14H (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.


Sec.  250.837  Emergency action and safety system shutdown--subsea 
trees.

    (a) In the event of an emergency, such as an impending named 
tropical storm or hurricane, you must shut-in all subsea wells unless 
otherwise approved by the District Manager. A shut-in is defined as a 
closed BSDV, USV, and surface-controlled SSSV.
    (b) When operating a mobile offshore drilling unit (MODU) or other 
type of workover vessel in an area with producing subsea wells, 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 MODU or 
other type of workover vessel and the production facility control room 
and prepare a plan to be submitted to the appropriate District Manager 
for approval, as part of an Application for Permit to Drill (BSEE-0123) 
or an Application for Permit to Modify (BSEE-0124), to shut-in any 
wells that could be affected by a dropped object. If an object is 
dropped, the driller (or other authorized rig floor personnel) must 
immediately secure the well directly under the MODU or other type of 
workover vessel using the ESD station near the driller's console while 
simultaneously communicating with the platform to shut-in all affected 
wells. You must also maintain without disruption, and continuously 
verify, communication between the platform and the MODU or other type 
of workover vessel. If communication is lost between the MODU or other 
type of workover vessel and the platform for 20 minutes or more, you 
must shut-in all wells that could be affected by a dropped object.
    (c) In the event of an emergency, you must operate your production 
system according to the valve closure times in the applicable tables in 
Sec. Sec.  250.838 and 250.839 for the following conditions:
    (1) Process upset. In the event an upset in the production process 
train occurs downstream of the BSDV, you must close the BSDV in 
accordance with the applicable tables in Sec. Sec.  250.838 and 
250.839. You may reopen the BSDV to blow down the pipeline to prevent 
hydrates, provided you have secured the well(s) and ensured adequate 
protection.
    (2) Pipeline pressure safety high and low (PSHL) sensor. In the 
event that either a high or a low pressure condition is detected by a 
PSHL sensor located upstream of the BSDV, you must secure the affected 
well and pipeline, and all wells and pipelines associated with a dual 
or multi pipeline system, by closing the BSDVs, USVs, and surface-
controlled SSSVs in accordance with the applicable tables in Sec. Sec.  
250.838 and 250.839. You must obtain approval from the appropriate 
District Manager to resume production in the unaffected pipeline(s) of 
a dual or multi pipeline system. If the PSHL sensor activation was a 
false alarm, you may return the wells to production without contacting 
the appropriate District Manager.
    (3) ESD/TSE (platform). In the event of an ESD activation that is 
initiated because of a platform ESD or platform TSE not associated with 
the BSDV, you must close the BSDV, USV, and surface-controlled SSSV in 
accordance with the applicable tables in Sec. Sec.  250.838 and 
250.839.
    (4) Subsea ESD (platform) or BSDV TSE. In the event of an emergency 
shutdown activation that is initiated by the host platform due to an 
abnormal condition subsea, or a TSE associated with the BSDV, you must 
close the BSDV, USV, and surface-controlled SSSV in accordance with the 
applicable tables in Sec. Sec.  250.838 and 250.839.
    (5) Subsea ESD (MODU). In the event of an ESD activation that is 
initiated by a dropped object from a MODU or other type of workover 
vessel, you must secure all wells in the proximity of the MODU or other 
type of workover 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 appropriate District Manager before 
resuming production.
    (d) Following an ESD or fire, you must bleed your low pressure (LP) 
and high pressure (HP) hydraulic systems in accordance with the 
applicable tables in Sec. Sec.  250.838 and 250.839 to ensure that the 
valves are locked out of service and cannot be reopened inadvertently.


Sec.  250.838  What are the maximum allowable valve closure times and 
hydraulic bleeding requirements for an electro-hydraulic control 
system?

    (a) If you have an electro-hydraulic control system, you must:
    (1) Design the subsea control system to meet the valve closure 
times listed in paragraphs (b) and (d) of this section or your approved 
DWOP; and
    (2) Verify the valve closure times upon installation. The District 
Manager may require you to verify the closure time of the USV(s) 
through visual authentication by diver or ROV.
    (b) You must comply with the maximum allowable valve closure times 
and hydraulic system bleeding requirements listed in the following 
table or your approved DWOP as long as communication is maintained with 
the platform or with the MODU or other type of workover vessel:

[[Page 61924]]



                                                 Valve Closure Timing, Electro-Hydraulic Control System
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                            Your LP          Your HP
 If you have the following. .    Your pipeline    Your USV1 must.   Your USV2 must.   Your alternate    Your surface-      hydraulic        hydraulic
              .                 BSDV must. . .          . .               . .         isolation valve  controlled SSSV   system must. .   system must. .
                                                                                         must. . .        must. . .            .                .
--------------------------------------------------------------------------------------------------------------------------------------------------------
(1) Process upset............  Close within 45   [no requirements]                                     [no              [no              [no
                                seconds after                                                           requirements].   requirements].   requirements].
                                sensor
                                activation.
(2) Pipeline PSHL............  Close within 45   Close one or more valves within 2 minutes and 45      Close within 60  [no              Initiate
                                seconds after     seconds after sensor activation. Close the            minutes after    requirements].   unrestricted
                                sensor            designated USV1 within 20 minutes after sensor        sensor                            bleed within
                                activation.       activation.                                           activation. If                    24 hours after
                                                                                                        you use a 60-                     sensor
                                                                                                        minute manual                     activation.
                                                                                                        resettable
                                                                                                        timer, you may
                                                                                                        continue to
                                                                                                        reset the time
                                                                                                        for closure up
                                                                                                        to a maximum
                                                                                                        of 24 hours
                                                                                                        total.
(3) ESD/TSE (Platform).......  Close within 45   Close within 5    Close within 20 minutes after ESD   Close within 20  Initiate         Initiate
                                seconds after     minutes after     or sensor activation.               minutes after    unrestricted     unrestricted
                                ESD or sensor     ESD or sensor                                         ESD or sensor    bleed within     bleed within
                                activation.       activation. If                                        activation. If   60 minutes       60 minutes
                                                  you use a 5-                                          you use a 20-    after ESD or     after ESD or
                                                  minute                                                minute manual    sensor           sensor
                                                  resettable                                            resettable       activation. If   activation. If
                                                  timer, you may                                        timer, you may   you use a 60-    you use a 60-
                                                  continue to                                           continue to      minute manual    minute manual
                                                  reset the time                                        reset the time   resettable       resettable
                                                  for closure up                                        for closure up   timer you must   timer you must
                                                  to a maximum of                                       to a maximum     initiate         initiate
                                                  20 minutes                                            of 60 minutes    unrestricted     unrestricted
                                                  total.                                                total.           bleed within     bleed within
                                                                                                                         24 hours.        24 hours.
(4) Subsea ESD (Platform) or   Close within 45   Close one or more valves within 2 minutes and 45      Close within 10  Initiate         Initiate
 BSDV TSE.                      seconds after     seconds after ESD or sensor activation. Close all     minutes after    unrestricted     unrestricted
                                ESD or sensor     tree valves within 10 minutes after ESD or sensor     ESD or sensor    bleed within     bleed within
                                activation.       activation                                            activation.      60 minutes       60 minutes
                                                                                                                         after ESD or     after ESD or
                                                                                                                         sensor           sensor
                                                                                                                         activation.      activation.
(5) Subsea ESD (MODU or other  [no               Initiate valve closure immediately. You may allow for closure of the   Initiate         Initiate
 type of workover vessel,       requirements].    tree valves immediately prior to closure of the surface-controlled     unrestricted    unrestricted
 Dropped object).                                 SSSV if desired.                                                       bleed            bleed within
                                                                                                                         immediately.     10 minutes
                                                                                                                                          after ESD
                                                                                                                                          activation.
--------------------------------------------------------------------------------------------------------------------------------------------------------

    (c) If you have an electro-hydraulic control system and experience 
a loss of communications (EH Loss of Comms), you must comply with the 
following:
    (1) If you can meet the EH Loss of Comms valve closure timing 
conditions specified in the table in paragraph (d) of this section, you 
must notify the appropriate District Office within 12 hours of 
detecting the loss of communication.
    (2) If you cannot meet the EH Loss of Comms valve closure timing 
conditions specified in the table in paragraph (d) of this section, you 
must notify the appropriate District Office immediately after detecting 
the loss of communication. You must shut-in production by initiating a 
bleed of the low pressure (LP) hydraulic system or the high pressure 
(HP) hydraulic system within 120 minutes after loss of communication. 
You must bleed the other hydraulic system within 180 minutes after loss 
of communication.
    (3) You must obtain approval from the appropriate District Manager 
before continuing to produce after loss of communication when you 
cannot meet the EH Loss of Comms valve closure times specified in the 
table in paragraph (d) of this section. In your request, include an 
alternate valve closure timing table that your system is able to 
achieve. The appropriate District Manager may also approve an alternate 
hydraulic bleed schedule to allow for hydrate mitigation and orderly 
shut-in.
    (d) If you experience a loss of communications, you must comply 
with the maximum allowable valve closure times and hydraulic system 
bleeding requirements listed in the following table or your approved 
DWOP:

[[Page 61925]]



                                    Valve Closure Timing, Electro-Hydraulic Control System With Loss of Communication
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                            Your LP          Your HP
 If you have the following. .    Your pipeline    Your USV1 must.   Your USV2 must.   Your alternate    Your surface-      hydraulic        hydraulic
              .                 BSDV must. . .          . .               . .         isolation valve  controlled SSSV   system must. .   system must. .
                                                                                         must. . .        must. . .            .                .
--------------------------------------------------------------------------------------------------------------------------------------------------------
(1) Process upset............  Close within 45   [no requirements]                                     [no              [no              [no
                                seconds after                                                           requirements].   requirements].   requirements].
                                sensor
                                activation.
(2) Pipeline PSHL............  Close within 45   Initiate closure when LP hydraulic system is bled     Initiate         Initiate         Initiate
                                seconds after     (close valves within 5 minutes after sensor           closure when     unrestricted     unrestricted
                                sensor            activation).                                          HP hydraulic     bleed            bleed within
                                activation.                                                             system is bled   immediately,     24 hours after
                                                                                                        (close within    concurrent       sensor
                                                                                                        24 hours after   with sensor      activation.
                                                                                                        sensor           activation.
                                                                                                        activation).
(3) ESD/TSE (Platform).......  Close within 45   Initiate closure when LP hydraulic system is bled     Initiate         Initiate         Initiate
                                seconds after     (close valves within 20 minutes after ESD or sensor   closure when     unrestricted     unrestricted
                                ESD or sensor     activation).                                          HP hydraulic     bleed            bleed within
                                activation.                                                             system is bled   concurrent       60 minutes
                                                                                                        (close within    with BSDV        after ESD or
                                                                                                        60 minutes       closure (bleed   sensor
                                                                                                        after ESD or     within 20        activation.
                                                                                                        sensor           minutes after
                                                                                                        activation).     ESD or sensor
                                                                                                                         activation).
(4) Subsea ESD (Platform) or   Close within 45   Initiate closure when LP hydraulic system is bled     Initiate         Initiate         Initiate
 BSDV TSE.                      seconds after     (close valves within 5 minutes after ESD or sensor    closure when     unrestricted     unrestricted
                                ESD or sensor     activation).                                          HP hydraulic     bleed            bleed
                                activation.                                                             system is bled   immediately.     immediately,
                                                                                                        (close within                     allowing for
                                                                                                        20 minutes                        surface-
                                                                                                        after ESD or                      controlled
                                                                                                        sensor                            SSSV closure.
                                                                                                        activation).
(5) Subsea ESD (MODU or other  [no               Initiate closure immediately. You may allow for closure of the tree    Initiate         Initiate
 type of workover vessel),      requirements].    valves immediately prior to closure of the surface-controlled SSSV     unrestricted     unrestricted
 Dropped object.                                  if desired.                                                            bleed            bleed
                                                                                                                         immediately.     immediately.
--------------------------------------------------------------------------------------------------------------------------------------------------------

Sec.  250.839  What are the maximum allowable valve closure times and 
hydraulic bleeding requirements for a direct-hydraulic control system?

    (a) If you have a direct-hydraulic control system, you must:
    (1) Design the subsea control system to meet the valve closure 
times listed in this section or your approved DWOP; and
    (2) Verify the valve closure times upon installation. The District 
Manager may require you to verify the closure time of the USV(s) 
through visual authentication by diver or ROV.
    (b) You must comply with the maximum allowable valve closure times 
and hydraulic system bleeding requirements listed in the following 
table or your approved DWOP:

                                                  Valve Closure Timing, Direct-Hydraulic Control System
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                            Your LP          Your HP
 If you have the following. .    Your pipeline    Your USV1 must.   Your USV2 must.   Your alternate    Your surface-      hydraulic        hydraulic
              .                 BSDV must. . .          . .               . .         isolation valve  controlled SSSV   system must. .   system must. .
                                                                                         must. . .        must. . .            .                .
--------------------------------------------------------------------------------------------------------------------------------------------------------
(1) Process upset............  Close within 45   [no requirements]                                     [no              [no              [no
                                seconds after                                                           requirements].   requirements].   requirements]
                                sensor
                                activation.
(2) Flowline PSHL............  Close within 45   Close one or more valves within 2 minutes and 45      Close within 24  Complete bleed   Complete bleed
                                seconds after     seconds after sensor activation. Close the            hours after      of USV1, USV2,   within 24
                                sensor            designated USV1 within 20 minutes after sensor        sensor           and the AIV      hours after
                                activation.       activation.                                           activation.      within 20        sensor
                                                                                                                         minutes after    activation.
                                                                                                                         sensor
                                                                                                                         activation.

[[Page 61926]]

 
(3) ESD/TSE (Platform).......  Close within 45   Close all valves within 20 minutes after ESD or       Close within 60  Complete bleed   Complete bleed
                                seconds after     sensor activation.                                    minutes after    of USV1, USV2,   within 60
                                ESD or sensor                                                           ESD or sensor    and the AIV      minutes after
                                activation.                                                             activation.      within 20        ESD or sensor
                                                                                                                         minutes after    activation.
                                                                                                                         ESD or sensor
                                                                                                                         activation.
(4) Subsea ESD (Platform) or   Close within 45   Close one or more valves within 2 minutes and 45      Close within 10  Complete bleed   Complete bleed
 BSDV TSE.                      seconds after     seconds after ESD or sensor activation. Close all     minutes after    of USV1, USV2,   within 10
                                ESD or sensor     tree valves within 10 minutes after ESD or sensor     ESD or sensor    and the AIV      minutes after
                                activation.       activation.                                           activation.      within 10        ESD or sensor
                                                                                                                         minutes after    activation.
                                                                                                                         ESD or sensor
                                                                                                                         activation.
(5) Subsea ESD (MODU or other  [no               Initiate closure immediately. If desired, you may allow for closure    Initiate         Initiate
 type of workover vessel),      requirements].    of the tree valves immediately prior to closure of the surface-        unrestricted     unrestricted
 Dropped object.                                  controlled SSSV.                                                       bleed            bleed
                                                                                                                         immediately.     immediately.
--------------------------------------------------------------------------------------------------------------------------------------------------------

PRODUCTION SAFETY SYSTEMS


Sec.  250.840  Design, installation, and maintenance--general.

    You must design, install, and maintain all production facilities 
and equipment including, but not limited to, separators, treaters, 
pumps, heat exchangers, fired components, wellhead injection lines, 
compressors, headers, and flowlines in a manner that is efficient, 
safe, and protects the environment.


Sec.  250.841  Platforms.

    (a) You must protect all platform production facilities with a 
basic and ancillary surface safety system designed, analyzed, 
installed, tested, and maintained in operating condition in accordance 
with the provisions of API RP 14C (incorporated by reference as 
specified in Sec.  250.198). If you use processing components other 
than those for which Safety Analysis Checklists are included in API RP 
14C, you must utilize the analysis technique and documentation 
specified in API RP 14C to determine the effects and requirements of 
these components on the safety system. Safety device requirements for 
pipelines are contained in Sec.  250.1004.
    (b) You must design, install, inspect, repair, test, and maintain 
in operating condition all platform production process piping in 
accordance with API RP 14E and API 570 (both incorporated by reference 
as specified in Sec.  250.198). The District Manager may approve 
temporary repairs to facility piping on a case-by-case basis for a 
period not to exceed 30 days.


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 for approval. The application must include the information 
prescribed in the following table:

------------------------------------------------------------------------
                                            Details and/or additional
            You must submit:                      requirements:
------------------------------------------------------------------------
(1) A schematic piping and               Showing the following:
 instrumentation diagram.                (i) Well shut-in tubing
                                          pressure;
                                         (ii) Piping specification
                                          breaks, piping sizes;
                                         (iii) Pressure relief valve 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 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).

[[Page 61927]]

 
(2) A safety analysis flow diagram (API  If processing components are
 RP 14C, Appendix E) and the related      used, other than those for
 Safety Analysis Function Evaluation      which Safety Analysis
 (SAFE) chart (API RP 14C, subsection     Checklists are included in API
 4.3.3) (incorporated by reference as     RP 14C, you must use the same
 specified in Sec.   250.198).            analysis technique and
                                          documentation to determine the
                                          effects and requirements of
                                          these components upon the
                                          safety system.
(3) Electrical system information,       (i) A plan for each platform
 including.                               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).
                                         (ii) Identification of all
                                          areas where potential ignition
                                          sources, including non-
                                          electrical ignition sources,
                                          are to be installed showing:
                                         (A) All major production
                                          equipment, wells, and other
                                          significant hydrocarbon
                                          sources, and a description of
                                          the type of decking, ceiling,
                                          walls (e.g., grating or
                                          solid), and firewalls and;
                                         (B) The location of generators,
                                          control rooms, panel boards,
                                          major cabling/conduit routes,
                                          and identification of the
                                          primary wiring method (e.g.,
                                          type cable, conduit, wire)
                                          and;
                                         (iii) One-line electrical
                                          drawings of all electrical
                                          systems including the safety
                                          shutdown system. You must also
                                          include a functional legend.
(4) 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.
(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) 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 
under paragraph (a) of this section were reviewed, 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.
    (c) Before you begin production, you must certify, in a letter to 
the District Manager, that the mechanical and electrical systems were 
installed in accordance with the approved designs.
    (d) Within 60 days after production commences, you must certify, in 
a letter to the District Manager, that the as-built diagrams for the 
new or modified production safety systems outlined in paragraphs (a)(1) 
and (2) of this section and the piping and instrumentation diagrams are 
on file and have been certified correct 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.
    (e) All as-built diagrams outlined in paragraphs (a)(1) and (2) of 
this section must be submitted to the District Manager within 60 days 
after production commences.
    (f) You must maintain information concerning the approved designs 
and installation features of the production safety system at your 
offshore field office nearest the OCS facility or at other locations 
conveniently available to the District Manager. As-built piping and 
instrumentation diagrams must be maintained at a secure onshore 
location and readily available offshore. These documents must be made 
available to BSEE upon request and be retained for the life of the 
facility. All approvals are subject to field verifications.


Sec. Sec.  250.843-250.849  [Reserved]

Additional Production System Requirements


Sec.  250.850  Production system requirements--general.

    You must comply with the production safety system requirements in 
Sec. Sec.  250.851 through 250.872, in addition to the practices 
contained in API RP 14C (incorporated by reference as specified in 
Sec.  250.198).


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

    (a) Pressure vessels (including heat exchangers) and fired vessels 
supporting production operations must meet the requirements in the 
following table:

------------------------------------------------------------------------
                                               Applicable codes and
               Item name                           requirements
------------------------------------------------------------------------
(1) Pressure and fired vessels.........  (i) Must be designed,
                                          fabricated, and code stamped
                                          according to applicable
                                          provisions of sections I, IV,
                                          and VIII of the ANSI/ASME
                                          Boiler and Pressure Vessel
                                          Code (incorporated by
                                          reference as specified in Sec.
                                            250.198).
                                         (ii) Must be repaired,
                                          maintained, and inspected in
                                          accordance with API 510
                                          (incorporated by reference as
                                          specified in Sec.   250.198).
(2) Existing uncoded pressure and fired  Must be justified and approval
 vessels (i) in use on November 7,        obtained from the District
 2016; (ii) with an operating pressure    Manager for their continued
 greater than 15 psig; and (iii) that     use after March 1, 2018.
 are not code stamped in accordance
 with the ANSI/ASME Boiler and Pressure
 Vessel Code.

[[Page 61928]]

 
(3) Pressure relief valves.............  (i) Must be designed and
                                          installed according to
                                          applicable provisions of
                                          sections I, IV, and VIII of
                                          the ASME Boiler and Pressure
                                          Vessel Code (incorporated by
                                          reference as specified in Sec.
                                            250.198).
                                         (ii) Must conform to the valve
                                          sizing and pressure-relieving
                                          requirements specified in
                                          these documents, but must be
                                          set no higher than the maximum-
                                          allowable working pressure of
                                          the vessel (except for cases
                                          where staggered set pressures
                                          are required for
                                          configurations using multiple
                                          relief valves or redundant
                                          valves installed and
                                          designated for operator use
                                          only).
                                         (iii) Vents must be positioned
                                          in such a way as to prevent
                                          fluid from striking personnel
                                          or ignition sources.
(4) Steam generators operating at less   Must be equipped with a level
 than 15 psig.                            safety low (LSL) sensor which
                                          will shut off the fuel supply
                                          when the water level drops
                                          below the minimum safe level.
(5) Steam generators operating at 15     (i) Must be equipped with a
 psig or greater.                         level safety low (LSL) sensor
                                          which will shut off the fuel
                                          supply when the water level
                                          drops below the minimum safe
                                          level.
                                         (ii) Must be equipped with a
                                          water-feeding device that will
                                          automatically control the
                                          water level except when closed
                                          loop systems are used for
                                          steam generation.
------------------------------------------------------------------------

    (b) Operating pressure ranges. You must use pressure recording 
devices to establish the new operating pressure ranges of pressure 
vessels at any time that the normalized system pressure changes by 50 
psig or 5 percent. Once system pressure has stabilized, pressure 
recording devices must be utilized to establish the new operating 
pressure ranges. The pressure recording devices must document the 
pressure range over time intervals that are no less than 4 hours and no 
more than 30 days long. You must maintain the pressure recording 
information you used to determine current operating pressure ranges at 
your field office nearest the OCS facility or at another location 
conveniently available to the District Manager for as long as the 
information is valid.
    (c) Pressure shut-in sensors must be set according to the following 
table (initial set points for pressure sensors must be set utilizing 
gauge readings and engineering design):

------------------------------------------------------------------------
                                                         Additional
        Type of sensor               Settings           requirements
------------------------------------------------------------------------
(1) High pressure shut-in       Must be set no     Must also be set
 sensor,.                        higher than 15     sufficiently below
                                 percent or 5 psi   (5 percent or 5 psi,
                                 (whichever is      whichever is
                                 greater) above     greater) the relief
                                 the highest        valve's set pressure
                                 operating          to assure that the
                                 pressure of the    pressure source is
                                 vessel.            shut-in before the
                                                    relief valve
                                                    activates.
(2) Low pressure shut-in        Must be set no     You must receive
 sensor,.                        lower than 15      specific approval
                                 percent or 5 psi   from the District
                                 (whichever is      Manager for
                                 greater) below     activation limits on
                                 the lowest         pressure vessels
                                 pressure in the    that have a pressure
                                 operating range.   safety low (PSL)
                                                    sensor set less than
                                                    5 psi.
------------------------------------------------------------------------

Sec.  250.852  Flowlines/Headers.

    (a) You must:
    (1) Equip flowlines from wells with both PSH and PSL sensors. You 
must locate these sensors in accordance with section A.1 of API RP 14C 
(incorporated by reference as specified in Sec.  250.198).
    (2) Use pressure recording devices to establish the new operating 
pressure ranges of flowlines at any time when the normalized system 
pressure changes by 50 psig or 5 percent, whichever is higher. The 
pressure recording devices must document the pressure range over time 
intervals that are no less than 4 hours and no more than 30 days long.
    (3) Maintain the most recent pressure recording information you 
used to determine operating pressure ranges at your field office 
nearest the OCS facility or at another location conveniently available 
to the District Manager for as long as the information is valid.
    (b) Flowline shut-in sensors must meet the requirements in the 
following table (initial set points for pressure sensors must be set 
using gauge readings and engineering design):

------------------------------------------------------------------------
        Type of flowline sensor                      Settings
------------------------------------------------------------------------
(1) PSH sensor,........................  Must be set no higher than 15
                                          percent or 5 psi (whichever is
                                          greater) above the highest
                                          operating pressure of the
                                          flowline. In all cases, the
                                          PSH must be set sufficiently
                                          below the maximum shut-in
                                          wellhead pressure or the gas-
                                          lift supply pressure to ensure
                                          actuation of the SSV. Do not
                                          set the PSH sensor above the
                                          maximum allowable working
                                          pressure of the flowline.
(2) PSL sensor,........................  Must be set no lower than 15
                                          percent or 5 psi (whichever is
                                          greater) below the lowest
                                          operating pressure of the
                                          flowline in which it is
                                          installed.
------------------------------------------------------------------------


[[Page 61929]]

    (c) If a well flows directly to a pipeline before separation, the 
flowline and valves from the well located upstream of and including the 
header inlet valve(s) must have a working pressure equal to or greater 
than the maximum shut-in pressure of the well unless the flowline is 
protected by one of the following:
    (1) A relief valve which vents into the platform flare scrubber or 
some other location approved by the District Manager. You must design 
the platform flare scrubber to handle, without liquid-hydrocarbon 
carryover to the flare, the maximum-anticipated flow of hydrocarbons 
that may be relieved to the vessel; or
    (2) Two SSVs with independent PSH sensors connected to separate 
relays and sensing points and installed with adequate volume upstream 
of any block valve to allow sufficient time for the SSVs to close 
before exceeding the maximum allowable working pressure. Each 
independent PSH sensor must close both SSVs along with any associated 
flowline PSL sensor. If the maximum shut-in pressure of a dry tree 
satellite well(s) is greater than 1\1/2\ times the maximum allowable 
pressure of the pipeline, a pressure safety valve (PSV) of sufficient 
size and relief capacity to protect against any SSV leakage or fluid 
hammer effect may be required by the District Manager. The PSV must be 
installed upstream of the host platform boarding valve and vent into 
the platform flare scrubber or some other location approved by the 
District Manager.
    (d) If a well flows directly to the pipeline from a header without 
prior separation, the header, the header inlet valves, and pipeline 
isolation valve must have a working pressure equal to or greater than 
the maximum shut-in pressure of the well unless the header is protected 
by the safety devices as outlined in paragraph (c) of this section.
    (e) If you are installing flowlines constructed of unbonded 
flexible pipe on a floating platform, you must:
    (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 API Spec. 17J 
(incorporated by reference as specified in Sec.  250.198);
    (2) Determine that the unbonded flexible pipe is suitable for its 
intended purpose;
    (3) Submit to the District Manager the manufacturer's design 
specifications for the unbonded flexible pipe; and
    (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 API Spec. 17J (incorporated by 
reference as specified in Sec.  250.198).
    (f) Automatic pressure or flow regulating choking devices must not 
prevent the normal functionality of the process safety system that 
includes, but is not limited to, the flowline pressure safety devices 
and the SSV.
    (g) You may install a single flow safety valve (FSV) on the 
platform to protect multiple subsea pipelines or wells that tie into a 
single pipeline riser provided that you install an FSV for each riser 
on the platform and test it in accordance with the criteria prescribed 
in Sec.  250.880(c)(2)(v).
    (h) You may install a single PSHL sensor on the platform to protect 
multiple subsea pipelines that tie into a single pipeline riser 
provided that you install a PSHL sensor for each riser on the platform 
and locate it upstream of the BSDV.


Sec.  250.853  Safety sensors.

    You must ensure that:
    (a) All shutdown devices, valves, and pressure sensors function in 
a manual reset mode;
    (b) Sensors with integral automatic reset are equipped with an 
appropriate device to override the automatic reset mode; and
    (c) All pressure sensors are equipped to permit testing with an 
external pressure source.


Sec.  250.854  Floating production units equipped with turrets and 
turret-mounted systems.

    (a) For floating production units equipped with an auto slew 
system, you must integrate the auto slew control system with your 
process safety system allowing for automatic shut-in of the production 
process, including the sources (subsea wells, subsea pumps, etc.) and 
releasing of the buoy. Your safety system must immediately initiate a 
process system shut-in according to Sec. Sec.  250.838 and 250.839 and 
release the buoy to prevent hydrocarbon discharge and damage to the 
subsea infrastructure when the following are encountered:
    (1) Your buoy is clamped,
    (2) Your auto slew mode is activated, and
    (3) You encounter a ship heading/position failure or an exceedance 
of the rotational tolerances of the clamped buoy.
    (b) For floating production units equipped with swivel stack 
arrangements, you must equip the portion of the swivel stack containing 
hydrocarbons with a leak detection system. Your leak detection system 
must be tied into your production process surface safety system 
allowing for automatic shut-in of the system. Upon seal system failure 
and detection of a hydrocarbon leak, your surface safety system must 
immediately initiate a process system shut-in according to Sec. Sec.  
250.838 and 250.839.


Sec.  250.855  Emergency shutdown (ESD) system.

    The ESD system must conform to the requirements of Appendix C, 
section C1, of API RP 14C (incorporated by reference as specified in 
Sec.  250.198), and the following:
    (a) The manually operated ESD valve(s) must be quick-opening and 
non-restricted to enable the rapid actuation of the shutdown system. 
Electronic ESD stations must be wired as de-energize to trip circuits 
or as supervised circuits. Because of the key role of the ESD system in 
the platform safety system, all ESD components must be of high quality 
and corrosion resistant and stations must be uniquely identified. Only 
ESD stations at the boat landing may utilize a loop of breakable 
synthetic tubing in lieu of a valve or electric switch. This breakable 
loop is not required to be physically located on the boat landing, but 
must be accessible from a vessel adjacent to or attached to the 
facility.
    (b) You must maintain a schematic of the ESD that indicates the 
control functions of all safety devices for the platforms on the 
platform, at your field office nearest the OCS facility, or at another 
location conveniently available to the District Manager, for the life 
of the facility.


Sec.  250.856  Engines.

    (a) Engine exhaust. You must equip all engine exhausts to comply 
with the insulation and personnel protection requirements of API RP 
14C, section 4.2 (incorporated by reference as specified in Sec.  
250.198). You must equip exhaust piping from diesel engines with spark 
arresters.
    (b) Diesel engine air intake. You must equip diesel engine air 
intakes with a device to shut down the diesel engine in the event of 
runaway (i.e., overspeed). You must equip diesel engines that are 
continuously attended with either remotely operated manual or automatic 
shutdown devices. You must equip diesel engines that are not 
continuously attended with automatic shutdown devices. The following 
diesel engines do not require a shutdown device: Engines for fire water 
pumps;

[[Page 61930]]

engines on emergency generators; engines that power BOP accumulator 
systems; engines that power air supply for confined entry personnel; 
temporary equipment on non-producing platforms; booster engines whose 
purpose is to start larger engines; and engines that power portable 
single cylinder rig washers.


Sec.  250.857  Glycol dehydration units.

    (a) You must install a pressure relief system or an adequate vent 
on the glycol regenerator (reboiler) to prevent over pressurization. 
The discharge of the relief valve must be vented in a nonhazardous 
manner.
    (b) You must install the FSV on the dry glycol inlet to the glycol 
contact tower as near as practical to the glycol contact tower.
    (c) You must install the shutdown valve (SDV) on the wet glycol 
outlet from the glycol contact tower as near as practical to the glycol 
contact tower.


Sec.  250.858  Gas compressors.

    (a) You must equip compressor installations with the following 
protective equipment as required in API RP 14C, sections A.4 and A.8 
(incorporated by reference as specified in Sec.  250.198).
    (1) A pressure safety high (PSH) sensor, a pressure safety low 
(PSL) sensor, a pressure safety valve (PSV), a level safety high (LSH) 
sensor, and a level safety low (LSL) sensor to protect each interstage 
and suction scrubber.
    (2) A temperature safety high (TSH) sensor in the discharge piping 
of each compressor cylinder or case discharge.
    (3) You must design the PSH and PSL sensors and LSH controls 
protecting compressor suction and interstage scrubbers to actuate 
automatic SDVs located in each compressor suction and fuel gas line so 
that the compressor unit and the associated vessels can be isolated 
from all input sources. All automatic SDVs installed in compressor 
suction and fuel gas piping must also be actuated by the shutdown of 
the prime mover. Unless otherwise approved by the District Manager, 
gas-well gas affected by the closure of the automatic SDV on the 
suction side of a compressor must be diverted to the pipeline, diverted 
to a flare or vent in accordance with Sec. Sec.  250.1160 or 250.1161, 
or shut-in at the wellhead.
    (4) You must install a blowdown valve on the discharge line of all 
compressor installations that are 1,000 horsepower (746 kilowatts) or 
greater.
    (b) Once system pressure has stabilized, you must use pressure 
recording devices to establish the new operating pressure ranges for 
compressor discharge sensors whenever the normalized system pressure 
changes by 50 psig or 5 percent, whichever is higher. The pressure 
recording devices must document the pressure range over time intervals 
that are no less than 4 hours and no more than 30 days long. You must 
maintain the most recent pressure recording information that you used 
to determine operating pressure ranges at your field office nearest the 
OCS facility or at another location conveniently available to the 
District Manager.
    (c) Pressure shut-in sensors must be set according to the following 
table (initial set points for pressure sensors must be set utilizing 
gauge readings and engineering design):

----------------------------------------------------------------------------------------------------------------
         Type of sensor                               Settings                         Additional requirements
----------------------------------------------------------------------------------------------------------------
(1) PSH sensor,                   Must be set no higher than 15 percent or 5 psi    Must also be set
                                   (whichever is greater) above the highest          sufficiently below (5
                                   operating pressure of the discharge line and      percent or 5 psi, whichever
                                   sufficiently below the maximum discharge          is greater) the set
                                   pressure to ensure actuation of the suction SDV.  pressure of the PSV to
                                                                                     assure that the pressure
                                                                                     source is shut-in before
                                                                                     the PSV activates.
(2) PSL sensor,                   Must be set no lower than 15 percent or 5 psi     ............................
                                   (whichever is greater) below the lowest
                                   operating pressure of the discharge line in
                                   which it is installed.
----------------------------------------------------------------------------------------------------------------

Sec.  250.859  Firefighting systems.

    (a) On fixed facilities, to protect all areas where production-
handling equipment is located, you must install firefighting systems 
that meet the requirements of this paragraph. You must install a 
firewater system consisting of rigid pipe with fire hose stations and/
or fixed firewater monitors to protect all areas where production-
handling equipment is located. Your firewater system must include 
installation of a fixed water spray system in enclosed well-bay areas 
where hydrocarbon vapors may accumulate.
    (1) Your firewater system must conform to API RP 14G (incorporated 
by reference as specified in Sec.  250.198).
    (2) Fuel or power for firewater pump drivers must be available for 
at least 30 minutes of run time during a platform shut-in. If 
necessary, you must install an alternate fuel or power supply to 
provide for this pump operating time unless the District Manager has 
approved an alternate firefighting system. In addition:
    (i) As of September 7, 2017, you must have equipped all new 
firewater pump drivers with automatic starting capabilities upon 
activation of the ESD, fusible loop, or other fire detection system.
    (ii) For electric-driven firewater pump drivers, to provide for a 
potential loss of primary power, you must install an automatic transfer 
switch to cross over to an emergency power source in order to maintain 
at least 30 minutes of run time. The emergency power source must be 
reliable and have adequate capacity to carry the locked-rotor currents 
of the fire pump motor and accessory equipment.
    (iii) You must route power cables or conduits with wires installed 
between the fire water pump drivers and the automatic transfer switch 
away from hazardous-classified locations that can cause flame 
impingement. Power cables or conduits with wires that connect to the 
fire water pump drivers must be capable of maintaining circuit 
integrity for not less than 30 minutes of flame impingement.
    (3) You must post, in a prominent place on the facility, a diagram 
of the firefighting system showing the location of all firefighting 
equipment.
    (4) For operations in subfreezing climates, you must furnish 
evidence to the District Manager that the firefighting system is 
suitable for those conditions.
    (5) You must obtain approval from the District Manager before 
installing any firefighting system.
    (6) All firefighting equipment located on a facility must be in 
good working order whether approved as the primary, secondary, or 
ancillary firefighting system.
    (b) On floating facilities, to protect all areas where production-
handling equipment is located, you must install a firewater system 
consisting of rigid pipe with fire hose stations and/or fixed firewater 
monitors. You must install a fixed water spray system in enclosed well-
bay areas where hydrocarbon vapors may accumulate. Your firewater 
system must conform to the USCG requirements for firefighting systems 
on floating facilities.

[[Page 61931]]

    (c) Except as provided in paragraph (c)(1) and (2) of this section, 
on fixed and floating facilities, if you are required to maintain a 
firewater system and the system becomes inoperable, you must shut-in 
your production operations while making the necessary repairs. For 
fixed facilities only, you may continue your production operations on a 
temporary basis while you make the necessary repairs, provided that:
    (1) You request that the appropriate District Manager approve the 
use of a chemical firefighting system on a temporary basis (for a 
period up to 7 days) while you make the necessary repairs;
    (2) If you are unable to complete repairs during the approved time 
period because of circumstances beyond your control, the District 
Manager may grant multiple extensions to your previously approved 
request to use a chemical firefighting system for periods up to 7 days 
each.


Sec.  250.860  Chemical firefighting system.

    For fixed platforms:
    (a) On minor unmanned platforms, you may use a U.S. Coast Guard 
type and size rating ``B-II'' portable dry chemical unit (with a 
minimum UL Rating (US) of 60-B:C) or a 30-pound portable dry chemical 
unit, in lieu of a water system, as long as you ensure that the unit is 
available on the platform when personnel are on board.
    (1) A minor platform is a structure with zero to five completions 
and no more than one item of production processing equipment.
    (2) An unmanned platform is one that is not attended 24 hours a day 
or one on which personnel are not quartered overnight.
    (b) On major platforms and minor manned platforms, you may use a 
firefighting system using chemicals-only in lieu of a water-based 
system if the District Manager determines that the use of a chemical 
system provides equivalent fire-protection control and would not 
increase the risk to human safety.
    (1) A major platform is a structure with either six or more 
completions or zero to five completions with more than one item of 
production processing equipment.
    (2) A minor platform is a structure with zero to five completions 
and no more than one item of production processing equipment.
    (3) A manned platform is one that is attended 24 hours a day or one 
on which personnel are quartered overnight.
    (c) On major platforms and minor manned platforms, to obtain 
approval to use a chemical-only fire prevention and control system in 
lieu of a water system under paragraph (b) of this section, you must 
submit to the District Manager:
    (1) A justification for asserting that the use of a chemical system 
provides equivalent fire-protection control. The justification must 
address fire prevention, fire protection, fire control, and 
firefighting on the platform; and
    (2) A risk assessment demonstrating that a chemical-only system 
would not increase the risk to human safety. You must provide the 
following and any other important information in your risk assessment:

------------------------------------------------------------------------
     For the use of a chemical
 firefighting system on major and
 minor manned platforms, you must              Including . . .
provide the following in your risk
         assessment . . .
------------------------------------------------------------------------
(i) Platform description..........  (A) The type and quantity of
                                     hydrocarbons (i.e., natural gas,
                                     oil) that are produced, handled,
                                     stored, or processed at the
                                     facility.
                                    (B) The capacity of any tanks on the
                                     facility that you use to store
                                     either liquid hydrocarbons or other
                                     flammable liquids.
                                    (C) The total volume of flammable
                                     liquids (other than produced
                                     hydrocarbons) stored on the
                                     facility in containers other than
                                     bulk storage tanks. Include
                                     flammable liquids stored in paint
                                     lockers, storerooms, and drums.
                                    (D) If the facility is manned,
                                     provide the maximum number of
                                     personnel on board and the
                                     anticipated length of their stay.
                                    (E) If the facility is unmanned,
                                     provide the number of days per week
                                     the facility will be visited, the
                                     average length of time spent on the
                                     facility per visit, the mode of
                                     transportation, and whether or not
                                     transportation will be available at
                                     the facility while personnel are on
                                     board.
                                    (F) A diagram that depicts: quarters
                                     location, production equipment
                                     location, fire prevention and
                                     control equipment location,
                                     lifesaving appliances and equipment
                                     location, and evacuation plan
                                     escape routes from quarters and all
                                     manned working spaces to primary
                                     evacuation equipment.
(ii) Hazard assessment (facility    (A) Identification of all likely
 specific).                          fire initiation scenarios
                                     (including those resulting from
                                     maintenance and repair activities).
                                     For each scenario, discuss its
                                     potential severity and identify the
                                     ignition and fuel sources.
                                    (B) Estimates of the fire/radiant
                                     heat exposure that personnel could
                                     be subjected to. Show how you have
                                     considered designated muster areas
                                     and evacuation routes near fuel
                                     sources and have verified proper
                                     flare boom sizing for radiant heat
                                     exposure.
(iii) Human factors assessment      (A) Descriptions of the fire-related
 (not facility specific).            training your employees and
                                     contractors have received. Include
                                     details on the length of training,
                                     whether the training was hands-on
                                     or classroom, the training
                                     frequency, and the topics covered
                                     during the training.
                                    (B) Descriptions of the training
                                     your employees and contractors have
                                     received in fire prevention,
                                     control of ignition sources, and
                                     control of fuel sources when the
                                     facility is occupied.
                                    (C) Descriptions of the instructions
                                     and procedures you have given to
                                     your employees and contractors on
                                     the actions they should take if a
                                     fire occurs. Include those
                                     instructions and procedures
                                     specific to evacuation. State how
                                     you convey this information to your
                                     employees and contractors on the
                                     platform.
(iv) Evacuation assessment          (A) A general discussion of your
 (facility specific).                evacuation plan. Identify your
                                     muster areas (if applicable), both
                                     the primary and secondary
                                     evacuation routes, and the means of
                                     evacuation for both.
                                    (B) Description of the type,
                                     quantity, and location of
                                     lifesaving appliances available on
                                     the facility. Show how you have
                                     ensured that lifesaving appliances
                                     are located in the near vicinity of
                                     the escape routes.
                                    (C) Description of the types and
                                     availability of support vessels,
                                     whether the support vessels are
                                     equipped with a fire monitor, and
                                     the time needed for support vessels
                                     to arrive at the facility.
                                    (D) Estimates of the worst case time
                                     needed for personnel to evacuate
                                     the facility should a fire occur.
(v) Alternative protection          (A) Discussion of the reasons you
 assessment.                         are proposing to use an alternative
                                     fire prevention and control system.

[[Page 61932]]

 
                                    (B) Lists of the specific standards
                                     used to design the system, locate
                                     the equipment, and operate the
                                     equipment/system.
                                    (C) Description of the proposed
                                     alternative fire prevention and
                                     control system/equipment. Provide
                                     details on the type, size, number,
                                     and location of the prevention and
                                     control equipment.
                                    (D) Description of the testing,
                                     inspection, and maintenance program
                                     you will use to maintain the fire
                                     prevention and control equipment in
                                     an operable condition. Provide
                                     specifics regarding the type of
                                     inspection, the personnel who
                                     conduct the inspections, the
                                     inspection procedures, and
                                     documentation and recordkeeping.
(vi) Conclusion...................  A summary of your technical
                                     evaluation showing that the
                                     alternative system provides an
                                     equivalent level of personnel
                                     protection for the specific hazards
                                     located on the facility.
------------------------------------------------------------------------

    (d) On major or minor platforms, if BSEE has approved your request 
to use a chemical-only fire suppressant system in lieu of a water 
system under paragraphs (b) and (c) of this section, and if you make an 
insignificant change to your platform subsequent to that approval, you 
must document the change and maintain the documentation for the life of 
the facility at either the facility or nearest field office for BSEE 
review and/or inspection. Do not submit this documentation to the 
District Manager. However, if you make a significant change to your 
platform (e.g., placing a storage vessel with a capacity of 100 barrels 
or more on the facility, adding production equipment), or if you plan 
to man an unmanned platform temporarily, you must submit a new request 
for approval, including an updated risk assessment if previously 
required, to the appropriate District Manager. You must maintain, for 
the life of the facility, the most recent documentation that you 
submitted to BSEE at the facility or nearest field office.


Sec.  250.861  Foam firefighting systems.

    When you install foam firefighting systems as part of a 
firefighting system that protects production handling areas, you must:
    (a) Annually conduct an inspection of the foam concentrates and 
their tanks or storage containers for evidence of excessive sludging or 
deterioration;
    (b) Annually send samples of the foam concentrate to the 
manufacturer or authorized representative for quality condition 
testing. You must have the sample tested to determine the specific 
gravity, pH, percentage of water dilution, and solid content. Based on 
these results, the foam must be certified by an authorized 
representative of the manufacturer as suitable firefighting foam 
consistent with the original manufacturer's specifications. The 
certification document must be readily accessible for field inspection. 
In lieu of sampling and certification, you may choose to replace the 
total inventory of foam with suitable new stock;
    (c) Ensure that the quantity of concentrate meets design 
requirements, and that tanks or containers are kept full, with space 
allowed for expansion.


Sec.  250.862  Fire and gas-detection systems.

    For production processing areas only:
    (a) You must install fire (flame, heat, or smoke) sensors in all 
enclosed classified areas. You must install gas sensors in all 
inadequately ventilated, enclosed classified areas.
    (1) Adequate ventilation is defined as ventilation that is 
sufficient to prevent accumulation of significant quantities of vapor-
air mixture in concentrations over 25 percent of the lower explosive 
limit. An acceptable method of providing adequate ventilation is one 
that provides a change of air volume each 5 minutes or 1 cubic foot of 
air-volume flow per minute per square foot of solid floor area, 
whichever is greater.
    (2) Enclosed areas (e.g., buildings, living quarters, or doghouses) 
are defined as those areas confined on more than 4 of their 6 possible 
sides by walls, floors, or ceilings more restrictive to air flow than 
grating or fixed open louvers and of sufficient size to allow entry of 
personnel.
    (3) A classified area is any area classified Class I, Group D, 
Division 1 or 2, following the guidelines of API RP 500 (incorporated 
by reference as specified in Sec.  250.198), or any area classified 
Class I, Zone 0, Zone 1, or Zone 2, following the guidelines of API RP 
505 (incorporated by reference as specified in Sec.  250.198).
    (b) All detection systems must be capable of continuous monitoring. 
Fire-detection systems and portions of combustible gas-detection 
systems related to the higher gas-concentration levels must be of the 
manual-reset type. Combustible gas-detection systems related to the 
lower gas-concentration level may be of the automatic-reset type.
    (c) A fuel-gas odorant or an automatic gas-detection and alarm 
system is required in enclosed, continuously manned areas of the 
facility which are provided with fuel gas. A gas detection system is 
not required for living quarters and doghouses that do not contain a 
gas source and that are not located in a classified area.
    (d) The District Manager may require the installation and 
maintenance of a gas detector or alarm in any potentially hazardous 
area.
    (e) Fire- and gas-detection systems must be an approved type, and 
designed and installed in accordance with API RP 14C, API RP 14G, API 
RP 14F, API RP 14FZ, API RP 500, and API RP 505 (all incorporated by 
reference as specified in Sec.  250.198), provided that, if compliance 
with any provision of those standards would be in conflict with 
applicable regulations of the U.S. Coast Guard, compliance with the 
U.S. Coast Guard regulations controls.


Sec.  250.863  Electrical equipment.

    You must design, install, and maintain electrical equipment and 
systems in accordance with the requirements in Sec.  250.114.


Sec.  250.864  Erosion.

    You must have a program of erosion control in effect for wells or 
fields that have a history of sand production. The erosion-control 
program may include sand probes, X-ray, ultrasonic, or other 
satisfactory monitoring methods. You must maintain records for each 
lease that indicate the wells that have erosion-control programs in 
effect. You must also maintain the results of the programs for at least 
2 years and make them available to BSEE upon request.


Sec.  250.865   Surface pumps.

    (a) You must equip pump installations with the protective equipment 
required in API RP 14C, Appendix A--A.7, Pumps (incorporated by 
reference as specified in Sec.  250.198).

[[Page 61933]]

    (b) You must use pressure recording devices to establish the new 
operating pressure ranges for pump discharge sensors at any time when 
the normalized system pressure changes by 50 psig or 5 percent, 
whichever is higher. Once system pressure has stabilized, pressure 
recording devices must be utilized to establish the new operating 
pressure ranges. The pressure recording devices must document the 
pressure range over time intervals that are no less than 4 hours and no 
more than 30 days long. You must only maintain the most recent pressure 
recording information that you used to determine operating pressure 
ranges at your field office nearest the OCS facility or at another 
location conveniently available to the District Manager.
    (c) Pressure shut-in sensors must be set according to the following 
table (initial set points for pressure sensors must be set utilizing 
gauge readings and engineering design):

------------------------------------------------------------------------
                                                         Additional
      Type of sensor               Settings             requirements
------------------------------------------------------------------------
(1) PSH sensor............  Must be no higher      Must be set
                             than 15 percent or 5   sufficiently below
                             psi (whichever is      the maximum
                             greater) above the     allowable working
                             highest operating      pressure of the
                             pressure of the        discharge piping.
                             discharge line.        The PSH must also be
                                                    set at least 5
                                                    percent or 5 psi
                                                    (whichever is
                                                    greater) below the
                                                    set pressure of the
                                                    PSV to assure that
                                                    the pressure source
                                                    is shut-in before
                                                    the PSV activates.
(2) PSL sensor............  Must be set no lower
                             than 15 percent or 5
                             psi (whichever is
                             greater) below the
                             lowest operating
                             pressure of the
                             discharge line in
                             which it is
                             installed.
------------------------------------------------------------------------

    (d) The PSL must be placed into service when the pump discharge 
pressure has risen above the PSL sensing point, or within 45 seconds of 
the pump coming into service, whichever is sooner.
    (e) You may exclude the PSH and PSL sensors on small, low-volume 
pumps such as chemical injection-type pumps. This is acceptable if such 
a pump is used as a sump pump or transfer pump, has a discharge rating 
of less than \1/2\ gallon per minute (gpm), discharges into piping that 
is 1 inch or less in diameter, and terminates in piping that is 2 
inches or larger in diameter.
    (f) You must install a TSE in the immediate vicinity of all pumps 
in hydrocarbon service or those powered by platform fuel gas.
    (g) The pump maximum discharge pressure must be determined using 
the maximum possible suction pressure and the maximum power output of 
the driver as appropriate for the pump type and service.


Sec.  250.866  Personnel safety equipment.

    You must maintain all personnel safety equipment located on a 
facility, whether required or not, in good working condition.


Sec.  250.867  Temporary quarters and temporary equipment.

    (a) The District Manager must approve all temporary quarters to be 
installed in production processing areas or other classified areas on 
OCS facilities. You must equip such temporary quarters with all safety 
devices required by API RP 14C, Appendix C (incorporated by reference 
as specified in Sec.  250.198).
    (b) The District Manager may require you to install a temporary 
firewater system for temporary quarters in production processing areas 
or other classified areas.
    (c) Temporary equipment associated with the production process 
system, including equipment used for well testing and/or well clean-up, 
must be approved by the District Manager.


Sec.  250.868  Non-metallic piping.

    On fixed OCS facilities, you may use non-metallic piping (such as 
that made from polyvinyl chloride, chlorinated polyvinyl chloride, and 
reinforced fiberglass) only in accordance with the requirements of 
Sec.  250.841(b).


Sec.  250.869  General platform operations.

    (a) Surface or subsurface safety devices must not be bypassed or 
blocked out of service unless they are temporarily out of service for 
startup, maintenance, or testing. You may take only the minimum number 
of safety devices out of service. Personnel must monitor the bypassed 
or blocked-out functions until the safety devices are placed back in 
service. Any surface or subsurface safety device which is temporarily 
out of service must be flagged. A designated visual indicator must be 
used to identify the bypassed safety device. You must follow the 
monitoring procedures as follows:
    (1) If you are using a non-computer-based system, meaning your 
safety system operates primarily with pneumatic supply or non-
programmable electrical systems, you must monitor bypassed safety 
devices by positioning monitoring personnel at either the control panel 
for the bypassed safety device, or at the bypassed safety device, or at 
the component that the bypassed safety device would be monitoring when 
in service. You must also ensure that monitoring personnel are able to 
view all relevant essential operating conditions until all bypassed 
safety devices are placed back in service and are able to initiate 
shut-in action in the event of an abnormal condition.
    (2) If you are using a computer-based technology system, meaning a 
computer-controlled electronic safety system such as supervisory 
control and data acquisition and remote terminal units, you must 
monitor bypassed safety devices by maintaining instantaneous 
communications at all times among remote monitoring personnel and the 
personnel performing maintenance, testing, or startup. Until all 
bypassed safety devices are placed back in service, you must also 
position monitoring personnel at a designated control station that is 
capable of the following:
    (i) Displaying all relevant essential operating conditions that 
affect the bypassed safety device, well, pipeline, and process 
component. If electronic display of all relevant essential conditions 
is not possible, you must have field personnel monitoring the level 
gauges (sight glass) and pressure gauges in order to know the current 
operating conditions. You must be in communication with all field 
personnel monitoring the gauges;
    (ii) Controlling the production process equipment and the entire 
safety system;
    (iii) Displaying a visual indicator when safety devices are placed 
in the bypassed mode; and
    (iv) Upon command, overriding the bypassed safety device and 
initiating shut-in action in the event of an abnormal condition.
    (3) You must not bypass for startup any element of the emergency 
support system or other support system required by API RP 14C, Appendix 
C (incorporated by reference as specified in Sec.  250.198) without 
first receiving BSEE approval to depart from this

[[Page 61934]]

operating procedure. These systems include, but are not limited to:
    (i) The ESD system to provide a method to manually initiate 
platform shutdown by personnel observing abnormal conditions or 
undesirable events. You do not have to receive approval from the 
District Manager for manual reset and/or initial charging of the 
system;
    (ii) The fire loop system to sense the heat of a fire and initiate 
platform shutdown, and other fire detection devices (flame, thermal, 
and smoke) that are used to enhance fire detection capability. You do 
not have to receive approval from the District Manager for manual reset 
and/or initial charging of the system;
    (iii) The combustible gas detection system to sense the presence of 
hydrocarbons and initiate alarms and platform shutdown before gas 
concentrations reach the lower explosive limit;
    (iv) Adequate ventilation;
    (v) The containment system to collect escaped liquid hydrocarbons 
and initiate platform shutdown;
    (vi) Subsurface safety valves, including those that are self-
actuated (subsurface-controlled SSSVs) or those that are activated by 
an ESD system and/or a fire loop (surface-controlled SSSV). You do not 
have to receive approval from the District Manager for routine 
operations in accordance with Sec.  250.817;
    (vii) The pneumatic supply system; and
    (viii) The system for discharging gas to the atmosphere.
    (4) In instances where components of the ESD, as listed in 
paragraph (a)(3) of this section, are bypassed for maintenance, 
precautions must be taken to provide the equivalent level of protection 
that existed prior to the bypass.
    (b) When wells are disconnected from producing facilities and blind 
flanged, or equipped with a tubing plug, or the master valves have been 
locked closed, you are not required to comply with the provisions of 
API RP 14C (incorporated by reference as specified in Sec.  250.198) or 
this regulation concerning the following:
    (1) Automatic fail-close SSVs on wellhead assemblies, and
    (2) The PSH and PSL sensors in flowlines from wells.
    (c) When pressure or atmospheric vessels are isolated from 
production facilities (e.g., inlet valve locked closed or inlet blind-
flanged) and are to remain isolated for an extended period of time, 
safety device testing in accordance with API RP 14C (incorporated by 
reference as specified in Sec.  250.198), or this subpart is not 
required, with the exception of the PSV, unless the vessel is open to 
the atmosphere.
    (d) All open-ended lines connected to producing facilities and 
wells must be plugged or blind-flanged, except those lines designed to 
be open-ended such as flare or vent lines.
    (e) On all new production safety system installations, component 
process control devices and component safety devices must not be 
installed utilizing the same sensing points.
    (f) All pneumatic control panels and computer based control 
stations must be labeled according to API RP 14C nomenclature.


Sec.  250.870  Time delays on pressure safety low (PSL) sensors.

    (a) You 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. Use of a PSL sensor with a time delay greater than 45 seconds 
requires BSEE approval in accordance with Sec.  250.141. 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:
    (1) Class B safety devices have logic that allows for the PSL 
sensors to be bypassed for a fixed time period (typically less than 15 
seconds, but not more than 45 seconds). Examples include sensors used 
in conjunction with the design of pump and compressor panels such as 
PSL sensors, lubricator no-flows, and high-water jacket temperature 
shutdowns.
    (2) Class C safety devices have logic that allows for the PSL 
sensors to be bypassed until the component comes into full service 
(i.e., the time at which the startup pressure equals or exceeds the set 
pressure of the PSL sensor, the system reaches a stabilized pressure, 
and the PSL sensor clears).
    (3) Class B/C safety devices have logic that allows for the PSL 
sensors to incorporate a combination of Class B and Class C circuitry. 
These devices are used to ensure that the PSL sensors are not 
unnecessarily bypassed during startup and idle operations, (e.g., Class 
B/C bypass circuitry activates when a pump is shut down during normal 
operations). The PSL sensor remains bypassed until the pump's start 
circuitry is activated and either:
    (i) The Class B timer expires no later than 45 seconds from start 
activation, or
    (ii) The Class C bypass is initiated until the pump builds up 
pressure above the PSL sensor set point and the PSL sensor comes into 
full service.
    (b) If you do not install time delay circuitry that bypasses 
activation of PSL sensor shutdown logic for a specified time period on 
process and product transport equipment during startup and idle 
operations, you must manually bypass (pin out or disengage) the PSL 
sensor, with a time delay not to exceed 45 seconds.


Sec.  250.871  Welding and burning practices and procedures.

    All welding, burning, and hot-tapping activities must be conducted 
according to the specific requirements in Sec.  250.113.


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.5 
(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.
    (b) You must ensure that all atmospheric vessels are designed and 
maintained to ensure the proper working conditions for LSH sensors. The 
LSH sensor bridle must be designed to prevent different density fluids 
from impacting sensor functionality. For atmospheric vessels that have 
oil buckets, the LSH sensor must be installed to sense the level in the 
oil bucket.
    (c) You 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).


Sec.  250.873  Subsea gas lift requirements.

    If you choose to install a subsea gas lift system, you must design 
your system as approved in your DWOP or as follows:
    (a) Design the gas lift supply pipeline in accordance with API RP 
14C (incorporated by reference as specified in Sec.  250.198) for the 
gas lift supply system located on the platform.
    (b) Meet the applicable requirements in the following table:

[[Page 61935]]



--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                     Then you must install a
                                  ---------------------------------------------------------------------------------------------
                                    API Spec 6A and API Spec
  If your subsea gas lift system    6AV1 (both incorporated
 introduces the  lift gas to  the       by  reference as      FSV on the  gas-lift                         API Spec 6A and API    In addition, you must
              . . .                    specified in Sec.      supply  pipeline . .  PSHL on the gas-lift    Spec 6AV1 manual
                                       250.198) gas-lift                .               supply . . .      isolation  valve . .
                                    shutdown valve (GLSDV),                                                         .
                                           and . . .
--------------------------------------------------------------------------------------------------------------------------------------------------------
(1) Subsea pipelines, pipeline     Meet all of the            on the platform       pipeline on the       downstream (out       (i) Ensure that the MAOP
 risers, or manifolds via an        requirements for the       upstream (in-board)   platform downstream   board) of the PSHL    of a subsea gas lift
 external gas lift pipeline or      BSDV described in Sec.     of the GLSDV.         (out board) of the    and above the         supply pipeline is
 umbilical.                         Sec.   250.835 and                               GLSDV.                waterline. This       equal to the MAOP of
                                    250.836 on the gas-lift                                                valve does not have   the production
                                    supply pipeline. Locate                                                to be actuated.       pipeline.
                                    the GLSDV within 10 feet                                                                    (ii) Install an actuated
                                    of the first point of                                                                        fail-safe close gas-
                                    access to the gas-lift                                                                       lift isolation valve
                                    riser or topsides                                                                            (GLIV) located at the
                                    umbilical termination                                                                        point of intersection
                                    assembly (TUTA) (i.e.,                                                                       between the gas lift
                                    within 10 feet of the                                                                        supply pipeline and the
                                    edge of the platform if                                                                      production pipeline,
                                    the GLSDV is horizontal,                                                                     pipeline riser, or
                                    or within 10 feet above                                                                      manifold.
                                    the first accessible                                                                        (iii) Install the GLIV
                                    working deck, excluding                                                                      downstream of the
                                    the boat landing and                                                                         underwater safety
                                    above the splash zone,                                                                       valve(s) (USV) and/or
                                    if the GLSDV is in the                                                                       AIV(s).
                                    vertical run of a riser,
                                    or within 10 feet of the
                                    TUTA if using an
                                    umbilical).
(2) Subsea well(s) through the     Meet all of the            on the platform       pipeline on the       downstream (out       (i) Install an actuated,
 casing string via an external      requirements for the       upstream (in-board)   platform down-        board) of the PSHL    fail-safe-closed GLIV
 gas lift pipeline or umbilical.    GLSDV described in Sec.    of the GLSDV.         stream (out board)    and above the         on the gas lift supply
                                    Sec.   250.835 and                               of the GLSDV.         waterline. This       pipeline near the
                                    250.836 on the gas-lift                                                valve does not have   wellhead to provide the
                                    supply pipeline. Locate                                                to be actuated..      dual function of
                                    the GLSDV within 10 feet                                                                     containing annular
                                    of the first point of                                                                        pressure and shutting
                                    access to the gas-lift                                                                       off the gas lift supply
                                    riser or topsides                                                                            gas.
                                    umbilical termination                                                                       (ii) If your subsea tree
                                    assembly (TUTA) (i.e.,                                                                       or tubing head is
                                    within 10 feet of the                                                                        equipped with an
                                    edge of the platform if                                                                      annulus master valve
                                    the GLSDV is horizontal,                                                                     (AMV) or an annulus
                                    or within 10 feet above                                                                      wing valve (AWV), one
                                    the first accessible                                                                         of these may be
                                    working deck, excluding                                                                      designated as the GLIV.
                                    the boat landing and                                                                        (iii) Consider
                                    above the splash zone,                                                                       installing the GLIV
                                    if the GLSDV is in the                                                                       external to the subsea
                                    vertical run of a riser,                                                                     tree to facilitate
                                    or within 10 feet of the                                                                     repair and or
                                    TUTA if using an                                                                             replacement if
                                    umbilical).                                                                                  necessary.
(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 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 API                                                                        contained within the
                                    Spec. 6A component used                                                                      production riser in a
                                    to suspend and seal the                                                                      flanged API Spec. 6A
                                    gas-lift line contained                                                                      component such as an
                                    within the production                                                                        API Spec. 6A tubing
                                    riser, or outboard of                                                                        head and tubing hanger
                                    the production riser                                                                         or a component
                                    BSDV and inboard of the                                                                      designed, constructed,
                                    API Spec. 6A component                                                                       tested, and installed
                                    used to suspend and seal                                                                     to the requirements of
                                    the gas-lift line                                                                            API Spec. 6A.
                                    contained within the                                                                        (v) Ensure that all
                                    production riser.                                                                            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.
--------------------------------------------------------------------------------------------------------------------------------------------------------

    (c) Follow the valve closure times and hydraulic bleed requirements 
according to your approved DWOP for the following:
    (1) Electro-hydraulic control system with gas lift,
    (2) Electro-hydraulic control system with gas lift with loss of 
communications,
    (3) Direct-hydraulic control system with gas lift.
    (d) Follow the gas lift system valve testing requirements according 
to the following table:

----------------------------------------------------------------------------------------------------------------
      Type of gas lift system              Valve           Allowable leakage rate         Testing frequency
----------------------------------------------------------------------------------------------------------------
(1) Gas lifting a subsea pipeline,   GLSDV              Zero leakage...............  Monthly, not to exceed 6
 pipeline riser, or manifold via an                                                   weeks.
 external gas lift pipeline.

[[Page 61936]]

 
                                     GLIV               N/A........................  Function tested quarterly,
                                                                                      not to exceed 120 days.
(2) Gas lifting a subsea well        GLSDV              Zero leakage...............  Monthly, not to exceed 6
 through the casing string via an                                                     weeks.
 external gas lift pipeline.
                                     GLIV               400 cc per minute of liquid  Function tested quarterly,
                                                         or 15 scf per minute of      not to exceed 120 days
                                                         gas..
(3) Gas lifting the pipeline riser   GLSDV              Zero leakage...............  Monthly, not to exceed 6
 via a gas lift line contained                                                        weeks.
 within the pipeline riser.
----------------------------------------------------------------------------------------------------------------

Sec.  250.874  Subsea water injection systems.

    If you choose to install a subsea water injection system, your 
system must comply with your approved DWOP, which must meet the 
following minimum requirements:
    (a) Adhere to the water injection requirements described in API RP 
14C (incorporated by reference as specified in Sec.  250.198) for the 
water injection equipment located on the platform. In accordance with 
Sec.  250.830, either a surface-controlled SSSV or a water injection 
valve (WIV) that is self-activated and not controlled by emergency 
shut-down (ESD) or sensor activation must be installed in a subsea 
water injection well.
    (b) Equip a water injection pipeline with a surface FSV and water 
injection shutdown valve (WISDV) on the surface facility.
    (c) Install a PSHL sensor upstream (in-board) of the FSV and WISDV.
    (d) Use subsea tree(s), wellhead(s), connector(s), and tree valves, 
and surface-controlled SSSV or WIV associated with a water injection 
system that are rated for the maximum anticipated injection pressure.
    (e) Consider the effects of hydrogen sulfide (H2S) when designing 
your water flood system, as required by Sec.  250.805.
    (f) Follow the valve closure times and hydraulic bleed requirements 
according to your approved DWOP for the following:
    (1) Electro-hydraulic control system with water injection,
    (2) Electro-hydraulic control system with water injection with loss 
of communications, and
    (3) Direct-hydraulic control system with water injection.
    (g) Comply with the following injection valve testing requirements:
    (1) You must test your injection valves as provided in the 
following table:

 
------------------------------------------------------------------------
                                   Allowable leakage
              Valve                      rate          Testing frequency
------------------------------------------------------------------------
(i) WISDV.......................  Zero leakage......  Monthly, not to
                                                       exceed 6 weeks
                                                       between tests.
(ii) Surface-controlled SSSV or   400 cc per minute   Semiannually, not
 WIV.                              of liquid or.       to exceed
                                  15 scf per minute   6 calendar months
                                   of gas.             between tests.
------------------------------------------------------------------------

    (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 
API Spec 6A and API Spec. 6AV1 (both incorporated by reference as 
specified in Sec.  250.198) certified subsea valve as your USV.
    (3) If a USV on a water injection well fails the test and the 
surface-controlled SSSV or WIV cannot be tested as required under 
(g)(1)(ii) of this section because of low reservoir pressure, you must 
submit a request to the appropriate District Manager with an 
alternative plan that ensures subsea shutdown capabilities.
    (h) If you experience a loss of communications during water 
injection operations, you must comply with the following:
    (1) Notify the appropriate District Manager within 12 hours after 
detecting loss of communication; and
    (2) Obtain approval from the appropriate District Manager to 
continue to inject during the loss of communication.


Sec.  250.875  Subsea pump systems.

    If you choose to install a subsea pump system, your system must 
comply with your approved DWOP, which must meet the following minimum 
requirements:
    (a) Include the installation of an isolation valve at the inlet of 
your subsea pump module.
    (b) Include a PSHL sensor upstream of the BSDV, if the maximum 
possible discharge pressure of the subsea pump operating in a dead head 
condition (that is the maximum shut-in tubing pressure at the pump 
inlet and a closed BSDV) is less than the MAOP of the associated 
pipeline.
    (c) If the maximum possible discharge pressure of the subsea pump 
operating in a dead head situation could be greater than the MAOP of 
the pipeline:
    (1) Include, at minimum, 2 independent functioning PSHL sensors 
upstream of the subsea pump and 2 independent functioning PSHL sensors 
downstream of the pump, that:
    (i) Are operational when the subsea pump is in service; and
    (ii) Will, when activated, shut down the subsea pump, the subsea 
inlet isolation valve, and either the designated USV1, the USV2, or the 
alternate isolation valve.
    (iii) If more than 2 PSHL sensors are installed both upstream and 
downstream of the subsea pump for operational flexibility, then 2 out 
of 3 voting logic may be implemented in which the subsea pump remains 
operational provided a minimum of 2 independent PSHL sensors are 
functional both upstream and downstream of the pump.
    (2) Interlock the subsea pump motor with the BSDV to ensure that 
the pump cannot start or operate when the BSDV is closed, incorporate 
at a minimum the following permissive signals into the control system 
for your subsea pump, and ensure that the subsea pump is not able to be 
started or re-started unless:
    (i) The BSDV is open;
    (ii) All automated valves downstream of the subsea pump are open;

[[Page 61937]]

    (iii) The upstream subsea pump isolation valve is open; and
    (iv) All parameters associated with the subsea pump operation 
(e.g., pump temperature high, pump vibration high, pump suction 
pressure high, pump discharge pressure high, pump suction flow low) 
must be cleared (i.e., within operational limits) or continuously 
monitored by personnel who observe visual indicators displayed at a 
designated control station and have the capability to initiate shut-in 
action in the event of an abnormal condition.
    (3) Monitor the separator for seawater.
    (4) Ensure that the subsea pump systems are controlled by an 
electro-hydraulic control system.
    (d) Follow the valve closure times and hydraulic bleed requirements 
according to your approved DWOP for the following:
    (1) Electro-hydraulic control system with a subsea pump;
    (2) A loss of communication with the subsea well(s) and not a loss 
of communication with the subsea pump control system without an ESD or 
sensor activation;
    (3) A loss of communication with the subsea pump control system, 
and not a loss of communication with the subsea well(s);
    (4) A loss of communication with the subsea well(s) and the subsea 
pump control system.
    (e) For subsea pump testing:
    (1) Perform a complete subsea pump function test, including full 
shutdown, after any intervention or changes to the software and 
equipment affecting the subsea pump; and
    (2) Test the subsea pump shutdown, including PSHL sensors both 
upstream and downstream of the pump, each quarter (not to exceed 120 
days between tests). This testing may be performed concurrently with 
the ESD function test required by Sec.  250.880(c)(4)(v).


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 remove and 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 removal and 
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.


Sec. Sec.  250.877--250.879   [Reserved]

Safety Device Testing


Sec.  250.880  Production safety system testing.

    (a) Notification. You must:
    (1) Notify the District Manager at least 72 hours before commencing 
production, so that BSEE may conduct a preproduction inspection of the 
integrated safety system.
    (2) Notify the District Manager upon commencement of production so 
that BSEE may conduct a complete inspection.
    (3) Notify the District Manager and receive BSEE approval before 
you perform any subsea intervention that modifies the existing subsea 
infrastructure in a way that may affect the casing monitoring 
capabilities and testing frequencies specified in the table set forth 
in paragraph (c)(4) of this section.
    (b) Testing methodologies. You must:
    (1) Test safety valves and other equipment at the intervals 
specified in the tables set forth in paragraph (c) of this section or 
more frequently if operating conditions warrant; and
    (2) Perform testing and inspections in accordance with API RP 14C, 
Appendix D (incorporated by reference as specified in Sec.  250.198), 
and the additional requirements specified in the tables of this section 
or as approved in the DWOP for your subsea system.
    (c) Testing frequencies. You must:
    (1) Comply with the following testing requirements for subsurface 
safety devices on dry tree wells:

----------------------------------------------------------------------------------------------------------------
                                                                     Testing frequency, allowable leakage rates,
                             Item name                                          and other requirements
----------------------------------------------------------------------------------------------------------------
(i) Surface-controlled SSSVs (including devices installed in shut-   Semi-annually, not to exceed 6 calendar
 in and injection wells.                                              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 API RP 14B
                                                                      (incorporated by reference as specified in
                                                                      Sec.   250.198) to ensure proper
                                                                      operation.
(ii) Subsurface-controlled SSSVs...................................  Semi-annually, not to exceed 6 calendar
                                                                      months between tests for valves not
                                                                      installed in a landing nipple and 12
                                                                      months for valves installed in a landing
                                                                      nipple. The valve must be removed,
                                                                      inspected, and repaired or adjusted, as
                                                                      necessary, and reinstalled or replaced.
(iii) Tubing plug..................................................  Semi-annually, not to exceed 6 calendar
                                                                      months between tests. Test by opening the
                                                                      well to possible flow. If a liquid leakage
                                                                      rate > 400 cubic centimeters per minute or
                                                                      a gas leakage rate > 15 standard cubic
                                                                      feet per minute is observed, the plug must
                                                                      be removed, repaired, and reinstalled or
                                                                      replaced. An additional tubing plug may be
                                                                      installed in lieu of removal.
(iv) Injection valves..............................................  Semi-annually, not to exceed 6 calendar
                                                                      months between tests. Test by opening the
                                                                      well to possible flow. If a liquid leakage
                                                                      rate > 400 cubic centimeters per minute or
                                                                      a gas leakage rate > 15 standard cubic
                                                                      feet per minute is observed, the valve
                                                                      must be removed, repaired and reinstalled
                                                                      or replaced.
----------------------------------------------------------------------------------------------------------------

    (2) Comply with the following testing requirements for surface 
valves:

----------------------------------------------------------------------------------------------------------------
                             Item name                                    Testing frequency and requirements
----------------------------------------------------------------------------------------------------------------
(i) PSVs...........................................................  Annually, not to exceed 12 calendar months
                                                                      between tests. Valve must either be bench-
                                                                      tested or equipped to permit testing with
                                                                      an external pressure source. Weighted disc
                                                                      vent valves used as PSVs on atmospheric
                                                                      tanks may be disassembled and inspected in
                                                                      lieu of function testing. The main valve
                                                                      piston must be lifted during this test.

[[Page 61938]]

 
(ii) Automatic inlet SDVs that are actuated by a sensor on a vessel  Once each calendar month, not to exceed 6
 or compressor.                                                       weeks between tests.
(iii) SDVs in liquid discharge lines and actuated by vessel low-     Once each calendar month, not to exceed 6
 level sensors.                                                       weeks between tests.
(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 RP 14H (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.
(v) Flowline FSVs..................................................  Once each calendar month, not to exceed 6
                                                                      weeks between tests. All flowline FSVs
                                                                      must be tested, including those installed
                                                                      on a host facility in lieu of being
                                                                      installed at a satellite well. You must
                                                                      test flowline FSVs for leakage in
                                                                      accordance with the test procedure
                                                                      specified in API RP 14C (incorporated by
                                                                      reference as specified in Sec.   250.198).
                                                                      If leakage measured exceeds a liquid flow
                                                                      of 400 cubic centimeters per minute or a
                                                                      gas flow of 15 standard cubic feet per
                                                                      minute, the FSV must be repaired or
                                                                      replaced.
----------------------------------------------------------------------------------------------------------------

    (3) Comply with the following testing requirements for surface 
safety systems and devices:

----------------------------------------------------------------------------------------------------------------
                             Item name                                    Testing frequency and requirements
----------------------------------------------------------------------------------------------------------------
(i) Pumps for firewater systems....................................  Must be inspected and operated according to
                                                                      API RP 14G, Section 7.2 (incorporated by
                                                                      reference as specified in Sec.   250.198).
(ii) Fire- (flame, heat, or smoke) and gas detection systems.......  Must be tested for operation and
                                                                      recalibrated every 3 months, not to exceed
                                                                      120 days between tests, provided that
                                                                      testing can be performed in a non-
                                                                      destructive manner. Open flame or devices
                                                                      operating at temperatures that could
                                                                      ignite a methane-air mixture must not be
                                                                      used. All combustible gas-detection
                                                                      systems must be calibrated every 3 months.
(iii) ESD systems..................................................  (A) Pneumatic based ESD systems must be
                                                                      tested for operation at least once each
                                                                      calendar month, not to exceed 6 weeks
                                                                      between tests. You must conduct the test
                                                                      by alternating ESD stations monthly to
                                                                      close at least one wellhead SSV and verify
                                                                      a surface-controlled SSSV closure for that
                                                                      well as indicated by control circuitry
                                                                      actuation. All stations must be checked
                                                                      for functionality at least once each
                                                                      calendar month, not to exceed 6 weeks
                                                                      between tests. No station may be reused
                                                                      until all stations have been tested.
                                                                     (B) Electronic based ESD systems must be
                                                                      tested for operation at least once every 3
                                                                      calendar months, not to exceed 120 days
                                                                      between tests. The test must be conducted
                                                                      by alternating ESD stations to close at
                                                                      least one wellhead SSV and verify a
                                                                      surface-controlled SSSV closure for that
                                                                      well as indicated by control circuitry
                                                                      actuation. All stations must be checked
                                                                      for functionality at least once every 3
                                                                      calendar months, not to exceed 120 days
                                                                      between checks. No station may be reused
                                                                      until all stations have been tested.
                                                                     (C) Electronic/pneumatic based ESD systems
                                                                      must be tested for operation at least once
                                                                      every 3 calendar months, not to exceed 120
                                                                      days between tests. The test must be
                                                                      conducted by alternating ESD stations to
                                                                      close at least one wellhead SSV and verify
                                                                      a surface-controlled SSSV closure for that
                                                                      well as indicated by control circuitry
                                                                      actuation. All stations must be checked
                                                                      for functionality at least once every 3
                                                                      calendar months, not to exceed 120 days
                                                                      between checks. No station may be reused
                                                                      until all stations have been used.
(iv) TSH devices...................................................  Must be tested for operation annually, not
                                                                      to exceed 12 calendar months between
                                                                      tests, excluding those addressed in
                                                                      paragraph (c)(3)(v) of this section and
                                                                      those that would be destroyed by testing.
                                                                      Those that could be destroyed by testing
                                                                      must be visually inspected and the circuit
                                                                      tested for operations at least once every
                                                                      12 months.
(v) TSH shutdown controls installed on compressor installations      Must be tested every 6 months and repaired
 that can be nondestructively tested.                                 or replaced as necessary.
(vi) Burner safety low.............................................  Must be tested annually, not to exceed 12
                                                                      calendar months between tests.
(vii) Flow safety low devices......................................  Must be tested annually, not to exceed 12
                                                                      calendar months between tests.
(viii) Flame, spark, and detonation arrestors......................  Must be visually inspected annually, not to
                                                                      exceed 12 calendar months between
                                                                      inspections.
(ix) Electronic pressure transmitters and level sensors: PSH and     Must be tested at least once every 3
 PSL; LSH and LSL.                                                    months, not to exceed 120 days between
                                                                      tests.
(x) Pneumatic/electronic switch PSH and PSL; pneumatic/electronic    Must be tested at least once each calendar
 switch/electric analog with mechanical linkage LSH and LSL           month, not to exceed 6 weeks between
 controls.                                                            tests.
----------------------------------------------------------------------------------------------------------------

    (4) Comply with the following testing requirements for subsurface 
safety devices and associated systems on subsea tree wells:

[[Page 61939]]



----------------------------------------------------------------------------------------------------------------
                                                                     Testing frequency, allowable leakage rates,
                             Item name                                          and other requirements
----------------------------------------------------------------------------------------------------------------
(i) Surface-controlled SSSVs (including devices installed in shut-   Tested semiannually, not to exceed 6 months
 in and injection wells).                                             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
                                                                      API RP 14B (incorporated by reference as
                                                                      specified in Sec.   250.198) to ensure
                                                                      proper operation, or as approved in your
                                                                      DWOP.
(ii) USVs..........................................................  Tested at least once every 3 calendar
                                                                      months, not to exceed 120 days between
                                                                      tests. If the device does not function
                                                                      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 valve must be
                                                                      removed, repaired, and reinstalled or
                                                                      replaced.
(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 RP 14H 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.
(iv) Electronic ESD logic..........................................  Tested at least once each calendar month,
                                                                      not to exceed 6 weeks between tests.
(v) Electronic ESD function........................................  Tested at least once every 3 calendar
                                                                      months, not to exceed 120 days between
                                                                      tests. Shut-in at least one well during
                                                                      the ESD function test. If multiple wells
                                                                      are tied back to the same platform, a
                                                                      different well should be shut-in with each
                                                                      quarterly test.
----------------------------------------------------------------------------------------------------------------

    (d) Subsea wells. (1) Any subsea well that is completed and 
disconnected from monitoring capability may not be disconnected for 
more than 24 months, unless authorized by BSEE.
    (2) Any subsea well that is completed and disconnected from 
monitoring capability for more than 6 months must meet the following 
testing and other requirements:
    (i) Each well must have 3 pressure barriers:
    (A) A closed and tested surface-controlled SSSV,
    (B) A closed and tested USV, and
    (C) One additional closed and tested tree valve.
    (ii) For new completed wells, prior to the rig leaving the well, 
the pressure barriers must be tested as follows:
    (A) The surface-controlled SSSV must be tested for leakage in 
accordance with Sec.  250.828(c);
    (B) The USV and other pressure barrier must be tested to confirm 
zero leakage rate.
    (iii) A sealing pressure cap must be installed on the flowline 
connection hub until the flowline is installed and connected. The 
pressure cap must be designed to accommodate monitoring for pressure 
between the production wing valve and cap. The pressure cap must also 
be designed so that a remotely operated vehicle can bleed pressure off, 
monitor for buildup, and confirm barrier integrity.
    (iv) Pressure monitoring at the sealing pressure cap on the 
flowline connection hub must be performed in each well at intervals not 
to exceed 12 months from the time of initial testing of the pressure 
barrier (prior to demobilizing the rig from the field).
    (v) You must have a drilling vessel capable of intervention into 
the disconnected well in the field or readily accessible for use until 
the wells are brought on line.


Sec. Sec.  250.881--250.889  [Reserved]

Records and Training


Sec.  250.890  Records.

    (a) You must maintain records that show the present status and 
history of each safety device. Your records must include dates and 
details of installation, removal, inspection, testing, repairing, 
adjustments, and reinstallation.
    (b) You must maintain these records for at least 2 years. You must 
maintain the records at your field office nearest the OCS facility and 
a secure onshore location. These records must be available for review 
by a representative of BSEE.
    (c) You must submit to the appropriate District Manager a contact 
list for all OCS facilities at least annually or when contact 
information is revised. The contact list must include:
    (1) Designated operator name;
    (2) Designated primary point of contact for the facility;
    (3) Facility phone number(s), if applicable;
    (4) Facility fax number, if applicable;
    (5) Facility radio frequency, if applicable;
    (6) Facility helideck rating and size, if applicable; and
    (7) Facility records location if not contained on the facility.


Sec.  250.891  Safety device training.

    You must ensure that personnel installing, repairing, testing, 
maintaining, and operating surface and subsurface safety devices, and 
personnel operating production platforms (including, but not limited 
to, separation, dehydration, compression, sweetening, and metering 
operations), are trained in accordance with the procedures in subpart O 
and subpart S of this part.


Sec. Sec.  250.892-250.899  [Reserved]

[FR Doc. 2016-20967 Filed 9-6-16; 8:45 am]
 BILLING CODE 4310-VH-P