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[Federal Register Volume 78, Number 163 (Thursday, August 22, 2013)]
[Proposed Rules]
[Pages 52239-52284]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2013-19861]

[[Page 52239]]

Vol. 78

Thursday,

No. 163

August 22, 2013

Part II

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 Sulphur Operations on the Outer Continental Shelf--Oil 
and Gas Production Safety Systems; Proposed Rule

Federal Register / Vol. 78 , No. 163 / Thursday, August 22, 2013 / 
Proposed Rules

[[Page 52240]]

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DEPARTMENT OF THE INTERIOR

Bureau of Safety and Environmental Enforcement

30 CFR Part 250

[Docket ID: BSEE-2012-0005; 13XE1700DX EX1SF0000.DAQ000 EEEE500000]
RIN 1014-AA10

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

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

ACTION: Proposed rule.

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SUMMARY: The Bureau of Safety and Environmental Enforcement (BSEE) 
proposes to amend and update the regulations regarding oil and natural 
gas production by addressing issues such as: Safety and pollution 
prevention equipment lifecycle analysis, production safety systems, 
subsurface safety devices, and safety device testing. The proposed rule 
would differentiate the requirements for operating dry tree and subsea 
tree production systems on the Outer Continental Shelf (OCS) and divide 
the current subpart H into multiple sections to make the regulations 
easier to read and understand. The changes in this proposed rule are 
necessary to bolster human safety, environmental protection, and 
regulatory oversight of critical equipment involving production safety 
systems.

DATES: Submit comments by October 21, 2013. The BSEE may not fully 
consider comments received after this date. You may submit comments to 
the Office of Management and Budget (OMB) on the information collection 
burden in this proposed rule by September 23, 2013. The deadline for 
comments on the information collection burden does not affect the 
deadline for the public to comment to BSEE on the proposed regulations.

ADDRESSES: You may submit comments on the rulemaking by any of the 
following methods. Please use the Regulation Identifier Number (RIN) 
1014-AA10 as an identifier in your message. See also Public 
Availability of Comments under Procedural Matters.
     Federal eRulemaking Portal: http://www.regulations.gov. In 
the entry titled Enter Keyword or ID, enter BSEE-2012-0005 then click 
search. Follow the instructions to submit public comments and view 
supporting and related materials available for this rulemaking. The 
BSEE may post all submitted comments.
     Mail or hand-carry comments to the Department of the 
Interior (DOI); Bureau of Safety and Environmental Enforcement; 
Attention: Regulations Development Branch; 381 Elden Street, HE3313; 
Herndon, Virginia 20170-4817. Please reference ``Oil and Gas Production 
Safety Systems, 1014-AA10'' in your comments and include your name and 
return address.
     Send comments on the information collection in this rule 
to: Interior Desk Officer 1014-0003, Office of Management and Budget; 
202-395-5806 (fax); email: oira_submission@omb.eop.gov. Please send a 
copy to BSEE.
     Public Availability of Comments--Before including your 
address, phone number, email address, or other personal identifying 
information in your comment, you should be aware that your entire 
comment--including your personal identifying information--may be made 
publicly available at any time. While you can ask us in your comment to 
withhold your personal identifying information from public review, we 
cannot guarantee that we will be able to do so.

FOR FURTHER INFORMATION CONTACT: Kirk Malstrom, Regulations Development 
Branch, 703-787-1751, kirk.malstrom@bsee.gov.

SUPPLEMENTARY INFORMATION: 

Executive Summary

    This proposed rule would amend and update the Subpart H, Oil and 
Gas Production Safety Systems regulations. Subpart H has not had a 
major revision 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 regulations have not kept pace with the technological 
advancements.
    These regulations address issues such as production safety systems, 
subsurface safety devices, and safety device testing. These systems 
play a critical role in protecting workers and the environment. The 
BSEE would make the following changes to Subpart H in this rulemaking:
     Restructure the subpart to have shorter, easier-to-read 
sections based on the following headings:
    [cir] General requirements;
    [cir] Surface and subsurface safety systems--Dry trees;
    [cir] Subsea and subsurface safety systems--Subsea trees;
    [cir] Production safety systems;
    [cir] Additional production system requirements;
    [cir] Safety device testing; and
    [cir] Records and training.
     Update and improve the safety and pollution prevention 
equipment (SPPE) lifecycle analysis in order to increase the overall 
level of certainty that this equipment would perform as intended 
including in emergency situations. The lifecycle analysis involves 
vigilance throughout the entire lifespan of the SPPE, including design, 
manufacture, operational use, maintenance, and eventual decommissioning 
of the equipment. A major component of the lifecycle analysis involves 
the proper documentation of the entire process. The documentation 
allows an avenue for continual improvement throughout the life of the 
equipment by evaluation of mechanical integrity and communication 
between equipment operators and manufacturers.
     Expand the regulations to differentiate the requirements 
for operating dry tree and subsea tree production systems on the OCS.
     Incorporate new industry standards and update the 
incorporation of partially incorporated standards to require compliance 
with the complete standards.
     Add new requirements for, but not limited to, the 
following:
    [cir] SPPE life cycle and failure reporting;
    [cir] Foam firefighting systems;
    [cir] Electronic-based emergency shutdown systems (ESDs);
    [cir] Valve closure timing;
    [cir] Valve leakage rates;
    [cir] Boarding shut down valves (BSDV); and
    [cir] Equipment used for high temperature and high pressure wells.
     Rewrite the subpart in plain language according to:
    [cir] The Plain Writing Act of 2010;
    [cir] Executive Order 12866;
    [cir] Executive Order 12988; and
    [cir] Executive Order 13563, Improving Regulation and Regulatory 
Review.
    In addition to Subpart H revisions, we would revise the regulation 
in Subpart A requiring best available and safest technology (BAST) to 
follow more closely the Outer Continental Shelf Lands Act's (OCSLA, or 
the Act) statutory provision for BAST, 43 U.S.C. 1347(b).

Review of Proposed Rule

    This rulemaking proposes a complete revision of the regulations at 
30 CFR Part 250, Subpart H--Oil and Gas Production Safety Systems. The 
current regulations were originally published on April 1, 1988 (53 FR 
10690). Since that time, various sections were updated, and BSEE has 
issued several Notices to

[[Page 52241]]

Lessees (NTLs) to clarify the regulations and to provide guidance. The 
new version of subpart H would represent a major improvement in the 
structure and readability of the regulation with new changes in the 
requirements.

Organization

    The proposed rule would restructure Subpart H. The new version is 
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 found in each section of the current regulations. 
For example, in the current regulations, all requirements for 
subsurface safety devices are found in one section (Sec.  250.801). In 
the proposed rule, requirements for subsurface safety devices would be 
contained in 27 sections (Sec. Sec.  250.810 through 250.839), with the 
sections organized by general requirements and requirements related to 
the use of either a dry or subsea tree. The groupings in the proposed 
rule would make it easier for an operator to find the information that 
applies to a particular situation. The numbering for proposed Subpart H 
would start at Sec.  250.800, and end at Sec.  250.891. The proposed 
rule would separate Subpart H into the following undesignated headings:
     General Requirements
     Surface and Subsurface Safety Systems--Dry Trees
     Subsea and Subsurface Safety Systems--Subsea Trees
     Production Safety Systems
     Additional Production System Requirements
     Safety Device Testing
     Records and Training

Major Changes to the Rule

    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 casinghead used to control the production and flow of 
oil or gas. Dry tree completions are the standard for OCS shallow water 
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. As 
oil and gas production moved into deeper water, dry tree completions, 
because they are easily accessible, were still used on new types of 
platforms more suitable for deeper waters; such as compliant towers, 
tension-leg platforms, and spars. Starting with Conoco's Hutton 
tension-leg platform installed in the North Sea in 1984 in 
approximately 486 feet of water, 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 now occurs in depths of 9,000 feet 
of water, with many of the wells producing from water depths greater 
than 4,000 feet utilizing ``wet'' or subsea trees. With a subsea tree 
completion the tree is 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, there are 
associated subsurface safety devices designed to prevent uncontrolled 
releases of reservoir fluid or gas.
    Subpart H has not kept pace with industry's use of subsea trees and 
other technologies that have evolved or become more prevalent offshore 
over the last 20 years. This includes items as diverse as foam 
firefighting systems; electronic-based ESDs; subsea pumping, 
waterflooding, and gaslift; and new alloys and equipment for high 
temperature and high pressure wells.
    Another major change to the regulations in this proposed rule 
involves the lifecycle analysis of SPPE. The lifecycle analysis of SPPE 
is not a new concept and its elements are discussed in several industry 
documents incorporated in this rule, such as American Petroleum 
Institute (API) Spec. 6a, API Spec. 14A, API Recommended Practice (RP) 
14B, and corresponding International Organization for Standardization 
(ISO) 10432 and ISO 10417. This proposed rule would codify aspects of 
the lifecycle analysis into the regulations and bring attention to its 
importance. The lifecycle analysis involves careful consideration and 
vigilance throughout SPPE design, manufacture, operational use, 
maintenance, and decommissioning of the equipment. Lifecycle analysis 
is a tool for continual improvement throughout the life of the 
equipment.
    To assist in locating the regulations, the following table shows 
how sections of the proposed rule correspond to provisions of the 
current regulations in Subpart H:

------------------------------------------------------------------------
           Current regulation                     Proposed rule
------------------------------------------------------------------------
Sec.   250.800 General requirements....  Sec.   250.800 General.
Sec.   250.801 Subsurface safety         Sec.   250.810 Dry tree
 devices.                                 subsurface safety devices--
                                          general.
                                         Sec.   250.811 Specifications
                                          for subsurface safety valves
                                          (SSSVs)--dry trees.
                                         Sec.   250.812 Surface-
                                          controlled SSSVs--dry trees.
                                         Sec.   250.813 Subsurface-
                                          controlled SSSVs.
                                         Sec.   250.814 Design,
                                          installation, and operation of
                                          SSSVs--dry trees.
                                         Sec.   250.815 Subsurface
                                          safety devices in shut-in
                                          wells--dry trees.
                                         Sec.   250.816 Subsurface
                                          safety devices in injection
                                          wells--dry trees.
                                         Sec.   250.817 Temporary
                                          removal of subsurface safety
                                          devices for routine
                                          operations.
                                         Sec.   250.818 Additional
                                          safety equipment--dry trees.
                                         Sec.   250.821 Emergency
                                          action.
                                         Sec.   250.825 Subsea tree
                                          subsurface safety devices--
                                          general.
                                         Sec.   250.826 Specifications
                                          for SSSVs--subsea trees.
                                         Sec.   250.827 Surface-
                                          controlled SSSVs--subsea
                                          trees.
                                         Sec.   250.828 Design,
                                          installation, and operation of
                                          SSSVs--subsea trees.
                                         Sec.   250.829 Subsurface
                                          safety devices in shut-in
                                          wells--subsea trees.
                                         Sec.   250.830 Subsurface
                                          safety devices in injection
                                          wells--subsea trees.
                                         Sec.   250.832 Additional
                                          safety equipment--subsea
                                          trees.
                                         Sec.   250.837 Emergency action
                                          and safety system shutdown.

[[Page 52242]]

 
Sec.   250.802 Design, installation,     Sec.   250.819 Specification
 and operation of surface production-     for surface safety valves
 safety systems.                          (SSVs).
                                         Sec.   250.820 Use of SSVs.
                                         Sec.   250.833 Specification
                                          for underwater safety valves
                                          (USVs).
                                         Sec.   250.834 Use of USVs.
                                         Sec.   250.840 Design,
                                          installation, and maintenance--
                                          general.
                                         Sec.   250.841 Platforms.
                                         Sec.   250.842 Approval of
                                          safety systems design and
                                          installation features.
Sec.   250.803 Additional production     Sec.   250.850 Production
 system requirements.                     system requirements--general.
                                         Sec.   250.851 Pressure vessels
                                          (including heat exchangers)
                                          and fired vessels.
                                         Sec.   250.852 Flowlines/
                                          Headers.
                                         Sec.   250.853 Safety sensors.
                                         Sec.   250.855 Emergency
                                          shutdown (ESD) system.
                                         Sec.   250.856 Engines.
                                         Sec.   250.857 Glycol
                                          dehydration units.
                                         Sec.   250.858 Gas compressors.
                                         Sec.   250.859 Firefighting
                                          systems.
                                         Sec.   250.862 Fire and gas-
                                          detection systems.
                                         Sec.   250.863 Electrical
                                          equipment.
                                         Sec.   250.864 Erosion.
                                         Sec.   250.869 General platform
                                          operations.
                                         Sec.   250.871 Welding and
                                          burning practices and
                                          procedures.
Sec.   250.804 Production safety-system  Sec.   250.880 Production
 testing and records.                     safety system testing.
                                         Sec.   250.890 Records.
Sec.   250.805 Safety device training..  Sec.   250.891 Safety device
                                          training.
Sec.   250.806 Safety and pollution      Sec.   250.801 Safety and
 prevention equipment quality assurance   pollution prevention equipment
 requirements.                            (SPPE) certification.
                                         Sec.   250.802 Requirements for
                                          SPPE.
Sec.   250.807 Additional requirements   Sec.   250.804 Additional
 for subsurface safety valves and         requirements for subsurface
 related equipment installed in high      safety valves (SSSVs) and
 pressure high temperature (HPHT)         related equipment installed in
 environments.                            high pressure high temperature
                                          (HPHT) environments.
Sec.   250.808 Hydrogen sulfide........  Sec.   250.805 Hydrogen
                                          sulfide.
              New Sections               Sec.   250.803 What SPPE
                                          failure reporting procedures
                                          must I follow?
                                         Sec.   250.831 Alteration or
                                          disconnection of subsea
                                          pipeline or umbilical.
                                         Sec.   250.835 Specification
                                          for all boarding shut down
                                          valves (BSDV) associated with
                                          subsea systems.
                                         Sec.   250.836 Use of BSDVs
                                         Sec.   250.838 What are the
                                          maximum allowable valve
                                          closure times and hydraulic
                                          bleeding requirements for an
                                          electro-hydraulic control
                                          system?
                                         Sec.   250.839 What are the
                                          maximum allowable valve
                                          closure times and hydraulic
                                          bleeding requirements for a
                                          direct-hydraulic control
                                          system?
                                         Sec.   250.854 Floating
                                          production units equipped with
                                          turrets and turret mounted
                                          systems.
                                         Sec.   250.860 Chemical
                                          firefighting system.
                                         Sec.   250.861 Foam
                                          firefighting system.
                                         Sec.   250.865 Surface pumps.
                                         Sec.   250.866 Personal safety
                                          equipment.
                                         Sec.   250.867 Temporary
                                          quarters and temporary
                                          equipment.
                                         Sec.   250.868 Non-metallic
                                          piping.
                                         Sec.   250.870 Time delays on
                                          pressure safety low (PSL)
                                          sensors.
                                         Sec.   250.872 Atmospheric
                                          vessels.
                                         Sec.   250.873 Subsea gas lift
                                          requirements.
                                         Sec.   250.874 Subsea water
                                          injection systems.
                                         Sec.   250.875 Subsea pump
                                          systems.
                                         Sec.   250.876 Fired and
                                          Exhaust Heated Components.
------------------------------------------------------------------------

Availability of Incorporated Documents for Public Viewing

    When a copyrighted technical industry standard is incorporated by 
reference into our regulations, BSEE is obligated to observe and 
protect that copyright. The 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. The decision to charge a 
fee is decided by the standard developing organizations. The American 
Petroleum Institute (API) will provide free online public access to 160 
key industry standards, including a broad range of technical standards. 
The standards available for public access represent almost one-third of 
all API standards and include all that are safety-related or have been 
incorporated into Federal regulations, including the standards in this 
rule. These standards are available for review, and hardcopies and 
printable versions will continue to be available for purchase. We are 
proposing to incorporate API standards in this proposed rule, and the 
address to the API Web site is: http://publications.api.org/documentslist.aspx. You may also call the API Standard/Document Contact 
IHS at 1-800-854-7179 or 303-397-7956 local and international.
    For the convenience of the viewing public who may not wish to 
purchase or

[[Page 52243]]

view these proposed documents online, they may be inspected at the 
Bureau of Safety and Environmental Enforcement, 381 Elden Street, Room 
3313, Herndon, Virginia 20170; phone: 703-787-1587; or at the National 
Archives and Records Administration (NARA).
    For information on the availability of this material at NARA, call 
202-741-6030, or go to: http://www.archives.gov/federal_register/code_of_federal_regulations/ibr_locations.html.
    These documents, if incorporated in the final rule, would continue 
to be made available to the public for viewing when requested. Specific 
information on where these documents can be inspected or purchased can 
be found at 30 CFR 250.198, Documents Incorporated by Reference.

Section-by-Section Discussion

    The following is a brief section-by-section description of the 
substantive proposed changes to subpart H, as well as other sections of 
the proposed rule. In several of the section descriptions below, BSEE 
requests comments on particular issues raised by that section.
What must I do to protect health, safety, property, and the 
environment? (Sec.  250.107)
    The proposed rule would revise portions of Sec.  250.107 related to 
the use of best available and safest technology (BAST) by revising 
paragraph (c) and removing paragraph (d). The intent of the change is 
to more closely track the BAST provision in the OCSLA. 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).)

    Existing Sec.  250.107(c) requires the use of BAST ``whenever 
practical'' on ``all exploration, development, and production 
operations.'' Moreover, it provides that compliance with the 
regulations generally is considered to be the use of BAST. The existing 
provision is problematic for a number of reasons. The use of the phrase 
``whenever practical'' provides an operator substantial discretion in 
the use of BAST. The statute, on the other hand, requires the use of 
BAST that DOI determines to be economically feasible on all new 
drilling and production operations. With respect to existing 
operations, the Act requires operators to use BAST ``wherever 
practicable,'' which does not afford the operator complete discretion 
in the use of systems equipment. In addition, although operators must 
comply with BSEE regulations, such compliance does not necessarily 
equate to the use of BAST. Existing paragraph (d) is written in terms 
of additional measures the Director can require under the Act, and 
includes a general requirement that the benefits of such measures 
outweigh the costs.
    The proposed rule would more closely track the Act. Proposed Sec.  
250.107(c) would provide that wherever failure of equipment may have a 
significant effect on safety, health, or the environment, an operator 
must use the BAST that BSEE determines to be economically feasible on 
all new drilling and production operations, and wherever practicable, 
on existing operations. Under this proposed provision, BSEE would 
specify what is economically feasible BAST. This could be accomplished 
generally, for instance, through the use of NTLs, or on a case-specific 
basis. To implement the exception allowed by the Act, proposed Sec.  
250.107(c)(2) would allow an operator to request an exception from the 
use of BAST by demonstrating to BSEE that the incremental benefits of 
using BAST are clearly insufficient to justify the incremental costs of 
utilizing such technologies.
Service Fees (Sec.  250.125)
    This section would be revised to update the service fee citation to 
Sec.  250.842 in paragraphs (a)(10) through (a)(15).
Documents Incorporated by Reference (Sec.  250.198)
    This section would be revised to update cross-references to subpart 
H. The proposed rule would also add by incorporation, ``American 
Petroleum Institute (API) 570, Piping Inspection Code: In-service 
Inspection, Rating, Repair, and Alteration of Piping Systems.''
Tubing and Wellhead Equipment (Sec.  250.517)
    This section would be revised to update the cross-reference to the 
appropriate subpart H sections from Sec.  250.801 in current 
regulations to Sec. Sec.  250.810 through 250.839 in the proposed rule.
Tubing and Wellhead Equipment (Sec.  250.618)
    This section would be revised to update the cross-reference to the 
appropriate subpart H sections from Sec.  250.801 in current 
regulations to Sec. Sec.  250.810 through 250.839 in the proposed rule.

Subpart H--General Requirements

General (Sec.  250.800)
    This section would clarify the design requirements for production 
safety equipment and specify the appropriate industry standards that 
must be followed. A provision would be added that would require 
operators to comply with American Petroleum Institute Recommended 
Practice (API RP) 14J, Recommended Practice for Design and Hazards 
Analysis for Offshore Production Facilities, for all new production 
systems on fixed leg platforms and floating production systems (FPSs). 
This section would clarify requirements for operators to comply with 
the drilling, well completion, well workover, and well production riser 
standards of API RP 2RD, Recommended Practice for Design of Risers for 
Floating Production Systems (FPSs) and Tension-Leg Platforms (TLPs). 
However, this new section would prohibit the installation of single 
bore production risers from floating production facilities, effective 1 
year from publication of the final rule. The BSEE believes that a 
single bore production riser does not provide an acceptable level of 
safety to operate on the OCS when an operator has to perform work 
through the riser. When an operator performs work through a single bore 
production riser, wear on the riser may occur that compromises the 
integrity of the riser. This section would also revise stationkeeping 
system design requirements for floating production facilities by adding 
a reference to API RP 2SM, Recommended Practice for Design, 
Manufacture, Installation, and Maintenance of Synthetic Fiber Ropes for 
Offshore Mooring, in proposed Sec.  250.800(c)(3).
Safety and Pollution Prevention Equipment (SPPE) Certification (Sec.  
250.801)
    Existing Sec.  250.806, pertaining to SPPE certification, would be 
recodified as proposed Sec.  250.801 and rewritten in plain language. 
Additional subsections would be added to clarify that SPPE includes SSV 
and actuators, including those installed on injection wells that are 
capable of natural flow, and, following a 1-year grace period, boarding 
shut down valves (BSDVs). The final rule would specify the end date of 
the grace period. This section would also specify that BSEE would not

[[Page 52244]]

allow subsurface-controlled subsurface safety valves on subsea wells.
    The existing regulations recognize two quality assurance programs: 
(1) API Spec. Q1 and (2) American National Standards Institute/American 
Society of Mechanical Engineers (ANSI/ASME) SPPE-1-1994 and SPPE-1d-
1996 Addenda. The proposed rule would remove the reference to the ANSI/
ASME standards because they are defunct, but would continue to provide 
that SPPE equipment, which is manufactured and marked pursuant to API 
Spec. Q1, Specification for Quality Programs for the Petroleum, 
Petrochemical and Natural Gas Industry (ISO TS 29001:2007), would be 
considered certified SPPE under part 250. The BSEE presumptively 
considers all other SPPE as noncertified. Notwithstanding this 
presumption, under proposed Sec.  250.801(c), BSEE may exercise its 
discretion to accept SPPE manufactured under quality assurance programs 
other than API Spec. Q1 (ISO TS 29001:2007), provided an operator 
submits a request to BSEE containing relevant information about the 
alternative program, and receives BSEE approval under Sec.  250.141.
Requirements for SPPE (Sec.  250.802)
    Existing Sec.  250.806(a)(3), cross-referencing API requirements 
for SPPE, would be recodified as proposed Sec. Sec.  250.802(a) and 
(b).
    Proposed Sec.  250.802(c) would include a summary of some of the 
requirements that are contained in documents that are currently 
incorporated by reference to provide examples of the types of 
requirements that are contained in these documents. These requirements 
would address a range of activities over the entire lifecycle of the 
equipment that are intended to increase the reliability of the 
equipment through lifecycle analysis. These include:
     Independent third party review and certification;
     Manufacturing controls;
     Design verification and testing;
     Traceability requirements;
     Installation and testing protocols; and
     Requirements for the use of qualified parts and personnel 
to perform repairs.
    The lifecycle analysis for SPPE would consider the ``cradle-to-
grave'' implications of the associated equipment. Lifecycle analysis 
would also be a tool to evaluate the operational use, maintenance, and 
repair of SPPE from an equipment lifecycle perspective. Requirements 
that address the full lifecycle of critical equipment are essential to 
increase the overall level of certainty that this equipment would 
perform in emergency situations and would provide documentation from 
manufacture through the end of the operational limits of the SPPE 
equipment.
    Proposed Sec.  250.802(c)(1) would require that each device be 
designed to function and to close at the most extreme conditions to 
which it may be exposed. This includes extreme temperature, pressure, 
flow rates, and environmental conditions. Under the proposed rule, an 
operator would be required to 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 
would be required to have sufficient expertise and experience to 
perform the review and certification.
    A table would be added in proposed Sec.  250.802(d) to clarify when 
operators must install certified SPPE equipment. Under the proposed 
rule, non-certified SPPE already in service at a well could remain in 
service, but if the equipment requires offsite repair, re-
manufacturing, or any hot work such as welding, it must be replaced 
with certified SPPE.
    Proposed Sec.  250.802(e) would require that operators must retain 
all documentation related to the manufacture, installation, testing, 
repair, redress, and performance of SPPE equipment until 1 year after 
the date of decommissioning of the equipment.
What SPPE failure reporting procedures must I follow? (Sec.  250.803)
    Proposed Sec.  250.803 would establish SPPE failure reporting 
procedures. Proposed Sec.  250.803(a) would require operators to 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, and to provide a written 
report of equipment failure to the manufacturer of such equipment 
within 30 days after the discovery and identification of the failure. 
The proposed rule would define a failure as any condition that prevents 
the equipment from meeting the functional specification. This is 
intended to assure that design defects are identified and corrected and 
to assure that equipment is replaced before it fails.
    Proposed Sec.  250.803(b) would require operators to ensure that an 
investigation and a failure analysis are performed within 60 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 
proposed rule would require operators to ensure that the manufacturer 
receives a copy of the analysis report.
    Proposed Sec.  250.803(c) would specify that if an equipment 
manufacturer notifies an operator that it has changed the design of the 
equipment that failed, or if the operator has changed 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 BSEE.
Additional Requirements for Subsurface Safety Valves (SSSVs) and 
Related Equipment Installed in High Pressure High Temperature (HPHT) 
Environments (Sec.  250.804)
    Existing Sec.  250.807 would be recodified as proposed Sec.  
250.804, with no significant revisions proposed.
Hydrogen Sulfide (Sec.  250.805)
    Existing Sec.  250.808, pertaining to production operations in 
zones known to contain hydrogen sulfide (H2S) or in zones 
where the presence of H2S is unknown, as defined in Sec.  
250.490, would be recodified as proposed Sec.  250.805. This section 
would also clarify that the operator must receive approval through the 
Deepwater Operations Plan (DWOP) process for production operations in 
HPHT environments containing H2S, or in HPHT environments 
where the presence of H2S is unknown.
[RESERVED] Sec. Sec.  250.806--250.809

Surface and Subsurface Safety Systems--Dry Trees

Dry Tree Subsurface Safety Devices--General (Sec.  250.810)
    Existing Sec.  250.801(a) would be recodified as proposed Sec.  
250.810, and restructured for clarity. This section would also add the 
equipment flow coupling above and below to the list of devices 
associated with subsurface safety devices.
Specifications for Subsurface Safety Valves (SSSVs)--Dry Trees (Sec.  
250.811)
    Existing Sec.  250.801(b) would be recodified as proposed Sec.  
250.811. This section would also add the equipment flow coupling above 
and below to the list of devices associated with subsurface safety 
devices. Section 250.811 would permit BSEE to approve non-certified 
SSSVs in accordance with the process specified in 250.141 regarding 
alternative procedures or equipment.

[[Page 52245]]

Surface-Controlled SSSVs--Dry Trees (Sec.  250.812)
    Existing Sec.  250.801(c) would be recodified as proposed Sec.  
250.812. A change from current regulations would require BSEE approval 
for locating the surface controls at a remote location. The request and 
approval to locate surface controls at a remote location would be made 
in accordance with 250.141, regarding alternative procedures or 
equipment.
Subsurface-Controlled SSSVs (Sec.  250.813)
    Existing Sec.  250.801(d) would be recodified as proposed Sec.  
250.813, and rewritten using plain language.
Design, Installation, and Operation of SSSVs--Dry Trees (Sec.  250.814)
    Existing Sec.  250.801(e) would be recodified as proposed Sec.  
250.814. Proposed Sec.  250.814(c) would also add a definition of 
routine operation similarly to what is found under the definitions 
section at Sec.  250.601.
Subsurface Safety Devices in Shut-in Wells--Dry Trees (Sec.  250.815)
    Existing Sec.  250.801(f) would be recodified as proposed Sec.  
250.815, and rewritten in plain language.
Subsurface Safety Devices in Injection Wells--Dry Trees (Sec.  250.816)
    Existing Sec.  250.801(g) would be recodified as proposed Sec.  
250.816, and rewritten in plain language.
Temporary Removal of Subsurface Safety Devices for Routine Operations 
(Sec.  250.817)
    Existing Sec.  250.801(h) would be recodified as proposed Sec.  
250.817. The title of the section would be changed for clarity. In 
proposed Sec.  250.817(c), the term ``support vessel'' would be added 
as another option for attendance on a satellite structure.
Additional Safety Equipment--Dry Trees (Sec.  250.818)
    Existing Sec.  250.801(i) would be recodified as proposed Sec.  
250.818, with no significant revisions proposed.
Specification for Surface Safety Valves (SSVs) (Sec.  250.819)
    The portion of existing Sec.  250.802(c) related to wellhead SSVs 
and their actuators would be included in proposed Sec.  250.819. The 
portion of the existing Sec.  250.802(c) related to underwater safety 
valves would be placed in proposed Sec.  250.833.
Use of SSVs (Sec.  250.820)
    The portion of existing Sec.  250.802(d) related to SSVs would be 
included in proposed Sec.  250.820. The portion of the existing Sec.  
250.802(d) related to underwater safety valves would be placed in 
proposed Sec.  250.834.
Emergency Action (Sec.  250.821)
    Existing Sec.  250.801(j) would be recodified as proposed Sec.  
250.821. The example of an emergency would be revised to refer to a 
National Weather Service-named tropical storm or hurricane because not 
all impending storms constitute emergencies. A requirement would be 
added that oil and gas wells requiring compression must be shut-in in 
the event of an emergency unless otherwise approved by the District 
Manager. This section would also include, from existing Sec.  
250.803(b)(4)(ii), the valve closure times for dry tree emergency 
shutdowns.
[RESERVED] Sec. Sec.  250.822--250.824

Subsea and Subsurface Safety Systems--Subsea Trees

Subsea Tree Subsurface Safety Devices--General (Sec.  250.825)
    Proposed Sec.  250.825(a) is derived from existing Sec.  
250.801(a). This section would provide clarification on subsurface 
safety devices on subsea trees. Requirements for dry trees subsea 
safety systems can be found at Sec. Sec.  250.810 through 250.821. This 
section would also add the equipment flow coupling above and below to 
the list of devices associated with subsurface safety devices. Proposed 
Sec.  250.825(a) would also permit operators to seek BSEE approval to 
use alternative procedures or equipment in accordance with 250.141 if 
the subsea safety systems proposed for use vary from the regulatory 
requirements, including those pertaining to dry subsea safety systems 
found at Sec. Sec.  250.810 through 250.821.
    Proposed Sec.  250.825(b) would provide that, after installing the 
subsea tree, but before the rig or installation vessel leaves the area, 
an operator must test all valves and sensors to ensure that they are 
operating as designed and meet all the conditions specified in subpart 
H. Proposed Sec.  250.825(b) would permit an operator to seek BSEE 
approval of a departure under 250.142 in the event the operator cannot 
perform these tests.
Specifications for SSSVs--Subsea Trees (Sec.  250.826)
    Proposed Sec.  250.826 would be developed from existing Sec.  
250.801(b). The portions of Sec.  250.801(b) pertaining to subsurface-
controlled SSSVs for dry tree wells would be moved to proposed Sec.  
250.811. Subsurface-controlled SSSVs are not allowed on wells with 
subsea trees.
Surface-Controlled SSSVs--Subsea Trees (Sec.  250.827)
    This section would be derived from existing Sec.  250.801(c). A 
change from the existing provision would require BSEE approval for 
locating the surface controls at a remote location.
Design, Installation, and Operation of SSSVs--Subsea Trees (Sec.  
250.828)
    Existing Sec.  250.801(e) would be recodified as proposed Sec.  
250.828, with changes made to reflect that this section covers subsea 
tree installations. One change from existing regulations would 
establish that a well with a subsea tree must not be open to flow while 
an SSSV is inoperable. The BSEE would not allow exceptions.
Subsurface Safety Devices in Shut-in Wells--Subsea Trees (Sec.  
250.829)
    Existing Sec.  250.801(f) would be recodified as proposed Sec.  
250.829. The BSEE would also clarify when a surface-controlled SSSV is 
considered inoperative. This explanation would be added because the 
hydraulic control pressure to an individual subsea well may not be able 
to be isolated due to the complexity of the subsea hydraulic 
distribution of subsea fields.
Subsurface Safety Devices in Injection Wells--Subsea Trees (Sec.  
250.830)
    This section would be derived from existing Sec.  250.801(g). The 
substance of proposed Sec.  250.830 for subsea tree wells would be 
substantially similar to the regulatory sections pertaining to proposed 
Sec.  250.816 for dry tree wells. This is one example in which BSEE has 
consolidated similar provisions for easier public understanding.
Alteration or Disconnection of Subsea Pipeline or Umbilical (Sec.  
250.831)
    This is a new section that would be added to codify policy and 
guidance from an existing BSEE Gulf of Mexico Region NTL, ``Using 
Alternate Compliance in Safety Systems for Subsea Production 
Operations,'' NTL No. 2009-G36. The proposed provision would provide 
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 BSEE District Office at least 48 
hours in advance and submit a repair or

[[Page 52246]]

replacement plan to conduct the required monitoring and testing.
Additional Safety Equipment--Subsea Trees (Sec.  250.832)
    This section would be derived from existing Sec.  250.801(i), with 
changes made to reflect that this section covers subsea tree 
installations. The last sentence of existing Sec.  250.801(i), 
generally requiring closure of surface-controlled SSSVs in certain 
circumstances, would not be needed for wells with subsea trees, because 
more specific surface-controlled SSSV closure requirements would be 
established in proposed Sec. Sec.  250.838 and 250.839, described 
later.
Specification for Underwater Safety Valves (USVs) (Sec.  250.833)
    Proposed Sec.  250.833 derives in part from existing Sec.  
250.802(c) with references to surface safety valves removed to separate 
out requirements for the use of dry or subsea trees. The portions of 
the existing rule concerning surface safety valves for dry trees would 
be contained in proposed Sec.  250.819. Proposed Sec.  250.833 would 
also clarify the designations of the primary USV (USV1), the secondary 
USV (USV2), and that an alternate isolation valve (AIV) may qualify as 
a USV. Proposed Sec.  250.833(a) would require that operators must 
install at least one USV on a subsea tree and designate it as the 
primary USV, and that BSEE must be kept informed if the primary USV 
designation changes.
    Much of the material included in proposed Sec. Sec.  250.833 
through 250.839 derives from existing NTL No. 2009-G36, and is 
currently implemented through the DWOP process described under 
Sec. Sec.  250.286 through 250.295. Inclusion of this material in 
subpart H would better inform the regulated community of BSEE's 
expectations, and seeking public comment through this rulemaking will 
allow for possible improvements.
Use of USVs (Sec.  250.834)
    Proposed Sec.  250.834, pertaining to the inspection, installation, 
maintenance, and testing of USVs, derives from existing Sec.  
250.802(d) with references to surface safety valves removed to separate 
out requirements for the use of dry or subsea trees. This section would 
add references to USVs designated as primary, secondary, and any 
alternate isolation valve (AIV) that acts as a USV and also would add a 
reference to DWOPs.
Specification for All Boarding Shut Down Valves (BSDVs) Associated With 
Subsea Systems (Sec.  250.835)
    Proposed Sec.  250.835 would be a new section which would establish 
minimum design and other requirements for BSDVs and their actuators. 
This section would impose the requirements for the use of a BSDV, which 
assumes the role of the SSV required by 30 CFR Part 250, Subpart H for 
a traditional dry tree. This would 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 that this valve be subject to rigorous design and testing 
criteria.
Use of BSDVs (Sec.  250.836)
    Proposed Sec.  250.836 would establish a new requirement that all 
BSDVs must be inspected, maintained, and tested according to the 
provisions of API RP 14H. This section also specifies what the operator 
would do if a BSDV does not operate properly or if fluid flow is 
observed during the leakage test.
Emergency Action and Safety System Shutdown (Sec.  250.837)
    Proposed Sec.  250.837 would replace existing Sec.  250.801(j) for 
subsea tree installations. New requirements would be added to clarify 
allowances for valve closing sequences for subsea installations and 
specify actions required for certain situations. Proposed Sec.  
250.837(c) and (d) would describe a number of emergency situations 
requiring that shutdowns occur and safety valves be closed, and in 
certain situations that hydraulic systems be bled.
What are the Maximum Allowable Valve Closure Times and Hydraulic 
Bleeding Requirements for an Electro-hydraulic Control System? (Sec.  
250.838)
    Proposed Sec.  250.838 would establish maximum allowable valve 
closure times and hydraulic system bleeding requirements for electro-
hydraulic control systems. Proposed paragraph (b) would apply to 
electro-hydraulic control systems when an operator has not lost 
communication with its rig or platform. Proposed paragraph (c) would 
apply to electro-hydraulic control systems when an operator has lost 
communication with its rig or platform. Each paragraph would include a 
table containing valve closure times for BSDVs, USVs, and surface-
controlled SSSVs under the various scenarios described in proposed 
Sec.  250.837(c). The tables derive from Appendices to NTL No. 2009-
G36.
What are the maximum allowable valve closure times and hydraulic 
bleeding requirements for direct-hydraulic control system? (Sec.  
250.839)
    Proposed Sec.  250.839 would establish maximum allowable valve 
closure times and hydraulic system bleeding requirements for direct-
hydraulic control systems. It would contain a valve closure table 
comparable to those contained in proposed Sec.  250.838.

Production Safety Systems

Design, Installation, and Maintenance--General (Sec.  250.840)
    Existing Sec.  250.802(a) would be recodified as proposed Sec.  
250.840. Several new production components (pumps, heat exchangers, 
etc.) would be added to this section.
Platforms (Sec.  250.841)
    Existing Sec.  250.802(b) would be recodified as proposed Sec.  
250.841. New requirements for facility process piping would be added in 
proposed Sec.  250.841(b). The new paragraph would require adherence to 
existing industry documents, API RP 14E, Design and Installation of 
Offshore Production Platform Piping Systems and API 570, Piping 
Inspection Code: In-service Inspection, Rating, Repair, and Alteration 
of Piping Systems. Both of these documents would be incorporated by 
reference in Sec.  250.198. The proposed rule would also specify that 
the BSEE District Manager could approve temporary repairs to facility 
piping on a case-by-case basis for a period not to exceed 30 days.
Approval of Safety Systems Design and Installation Features (Sec.  
250.842)
    Existing Sec.  250.802(e) would be recodified as proposed Sec.  
250.842, including the service fee associated with the submittal of the 
production safety system application. The proposed rule would require 
adherence to API Recommended Practice documents pertaining to the 
design of electrical installations. The proposed rule would also 
require completion of a hazard analysis during the design process and 
require that a hazards analysis program be in place to assess potential 
hazards during the operation of the platform. A table would be placed 
in the proposed rule for clarity, amplifying some of the current 
requirements. This section would also add the requirements that the 
designs for the mechanical and electrical systems were reviewed, 
approved, and stamped by a registered professional engineer. Also, it 
would add a requirement that the as-built piping and instrumentation 
diagrams

[[Page 52247]]

(P&IDs) must be certified correct and stamped by a registered 
professional engineer. This section would also specify that the 
registered professional engineer, in both instances, must be registered 
in a State or Territory of the United States and have sufficient 
expertise and experience to perform the duties. The importance of these 
new provisions were highlighted in the Atlantis investigation report 
``BP'S Atlantis Oil And Gas Production Platform: An Investigation of 
Allegations that Operations Personnel Did Not Have Access to 
Engineer[hyphen]Approved Drawings,'' published March 4, 2011, prepared 
by BSEE's predecessor agency, the Bureau of Ocean Energy Management, 
Regulation and Enforcement. A copy of this report is available online 
at the following address: http://www.bsee.gov/uploadedFiles/03-0311%20BOEMRE%20Atlantis%20Report%20-%20FINAL.pdf. To clarify some of 
the issues discussed in the Atlantis investigation report related to 
as-built P&IDs and to clarify other diagram requirements, proposed 
Sec.  250.842 would require the following:
     Engineering documents to be stamped by a registered 
professional engineer;
     Operators to certify that all listed diagrams, including 
P&IDs are correct and accessible to BSEE upon request; and
     All as-built diagrams outlined in Sec.  250.842(a)(1) and 
(2) to be submitted to the District Managers.
    The proposed Sec.  250.842(b)(3) would impose a requirement that 
the operator certify in its application that it has performed a hazard 
analysis during the design process in accordance with API RP 14J, 
Recommended Practice for Design and Hazards Analysis for Offshore 
Production Facilities, and that it has a hazards analysis program in 
place to assess potential hazards during the operation of the platform. 
Although the regulations pertaining to an operator's safety and 
environmental management systems (SEMS) program already require a 
hazards analysis under Sec.  250.1911, the hazards analysis for the 
production platform required under the proposed rule would contain more 
detail under the incorporated API Recommended Practice than is 
currently required under the SEMS regulation.
    The operator must comply with both hazards analysis requirements 
from each respective subpart; however, these requirements for subpart H 
may also be used to satisfy a portion of the hazards analysis 
requirements in subpart S.
[RESERVED] Sec. Sec.  250.843-250.849

Additional Production System Requirements

Production System Requirements--General (Sec.  250.850)
    The proposed rule would split existing Sec.  250.803 into a number 
of sections (proposed Sec. Sec.  250.850 through 250.872) to make the 
regulations shorter, and thus more readable. Existing Sec.  250.803(a) 
would be codified as proposed Sec.  250.850.
Pressure Vessels (Including Heat Exchangers) and Fired Vessels (Sec.  
250.851)
    Existing Sec.  250.803(b)(1), establishing requirements for 
pressure and fired vessels, would be codified as proposed Sec.  
250.851. Tables would be placed in the proposed rule for clarity.
Flowlines/Headers (Sec.  250.852)
    Existing Sec.  250.803(b)(2), which establishes requirements for 
flowlines and headers, would be codified as proposed 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 proposed rule would specify instead that new 
operating pressure ranges of flowlines would be required at any time 
when the normalized system pressure changes by 50 psig (pounds per 
square inch gauge) or 5 percent, whichever is higher. New requirements 
also would be added for wells that flow directly to a pipeline without 
prior separation and for the closing of SSVs by safety sensors. A table 
would be placed in the proposed rule for clarity.
Safety Sensors (Sec.  250.853)
    Existing Sec.  250.803(b)(3), pertaining to safety sensors, would 
be codified as proposed Sec.  250.853 with the addition that all level 
sensors would have to be equipped to permit testing through an external 
bridle on new vessel installations.
Floating Production Units Equipped With Turrets and Turret Mounted 
Systems (Sec.  250.854)
    Proposed Sec.  250.854 would contain a new requirement for floating 
production units equipped with turrets and turret mounted systems. The 
operator would have to integrate the auto slew system with the safety 
system allowing for automatic shut-in of the production process 
including the sources (subsea wells, subsea pumps, etc.) and releasing 
of the buoy. The safety system would be required to 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 buoy is clamped, the auto 
slew mode is activated, and there is a ship heading/position failure or 
an exceedance of the rotational tolerances of the clamped buoy.
    This new section would also require floating production units 
equipped 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 would be required to be tied 
into the production process surface safety system allowing for 
automatic shut-in of the system. Upon seal system failure and detection 
of a hydrocarbon leak, the surface safety system would be required to 
immediately initiate a process system shut-in according to Sec. Sec.  
250.838 and 250.839. These new requirements are needed because they are 
not addressed in the currently incorporated API RP 14C and would help 
protect against hydrocarbon discharge in the event of failures.
Emergency Shutdown (ESD) System (Sec.  250.855)
    Existing Sec.  250.803(b)(4), pertaining to emergency shutdown 
systems, would be recodified as proposed Sec.  250.855. The existing 
regulation provides that only ESD stations at a boat landing may 
utilize a loop of breakable synthetic tubing in lieu of a valve. The 
proposed rule would clarify 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 boat.
Engines (Sec.  250.856)
    Existing Sec.  250.803(b)(5), pertaining to engine exhaust and 
diesel engine air intake, would be recodified as proposed Sec.  
250.856. A listing of diesel engines that do not require a shutdown 
device would be added to the proposed rule for clarification.
Glycol Dehydration Units (Sec.  250.857)
    Existing Sec.  250.803(b)(6), pertaining to glycol dehydration 
units, would be recodified as proposed Sec.  250.857. New requirements 
for flow safety valves and shut down valves on the glycol dehydration 
unit would be added to the proposed rule.
Gas Compressors (Sec.  250.858)
    Existing Sec.  250.803(b)(7), pertaining to gas compressors, would 
be recodified as proposed Sec.  250.858. New proposed requirements 
would be added to require the use of pressure recording devices to

[[Page 52248]]

establish any new operating pressure range changes greater than 5 
percent or 50 psig, whichever is higher. For pressure sensors on vapor 
recovery units, proposed Sec.  250.858(c) would provide that when the 
suction side of the compressor is operating below 5 psig and the system 
is capable of being vented to atmosphere, an operator is not required 
to install PSH and PSL sensors on the suction side of the compressor.
Firefighting Systems (Sec.  250.859)
    Existing Sec.  250.803(b)(8), pertaining to firefighting systems, 
would be recodified in proposed Sec. Sec.  250.859, 250.860, and 
250.861 and expanded. A number of the proposed additional features were 
included in an earlier NTL No. 2006-G04, ``Fire Prevention and Control 
Systems,'' and are necessary to update the agency regulations 
pertaining to firefighting.
    Proposed Sec.  250.859(a)(2) would include additional requirements. 
Existing Sec.  250.803(b)(8)(i) and (ii) would be included in proposed 
Sec.  250.859(a)(1) and (2). This paragraph would specify that within 1 
year after the publication date of a final rule, operators must equip 
all new firewater pump drivers with automatic starting capabilities 
upon activation of the ESD, fusible loop, or other fire detection 
system. For electric driven firewater pump drivers, in the event of a 
loss of primary power, operators would be required to 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 would have to be reliable and have adequate capacity to carry 
the locked-rotor currents of the fire pump motor and accessory 
equipment. Operators would be required to 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 would have to be capable of 
maintaining circuit integrity for not less than 30 minutes of flame 
impingement.
    Proposed Sec.  250.859(a)(5) would require that all firefighting 
equipment located on a facility be in good working order. Existing 
Sec.  250.803(b)(8)(iv) and (v) would be included in proposed Sec.  
250.859(a)(3) and (4).
    Proposed Sec.  250.859(b) would address inoperable firewater 
systems. It would specify that if an operator is required to maintain a 
firewater system and it becomes inoperable, the operator either must 
shut-in its production operations while making the necessary repairs, 
or request that the appropriate BSEE 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 
occur. It would provide further that if the operator is unable to 
complete repairs during the approved time period because of 
circumstances beyond its control, the BSEE District Manager may grant 
extensions to the approved departure for periods up to 7 days.
Chemical Firefighting System (Sec.  250.860)
    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. A number of the additional details 
were included from NTL 2006-G04, and are necessary to update the 
agency's regulations pertaining to firefighting. This proposed section 
would specify requirements regarding the use of chemical-only systems 
on major platforms, minor manned platforms, or minor unmanned 
platforms. The proposed rule would define the terms of major and manned 
platforms. It would also require a determination by the BSEE District 
Manager that the use of a chemical-only system 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, the proposed rule would require an operator to submit a 
justification addressing the elements of fire prevention, fire 
protection, fire control, and firefighting on the platform. As a 
further basis, the operator would need to submit a risk assessment 
demonstrating that a chemical-only system would not increase the risk 
to human safety. The rule would contain a table listing the items that 
must be included in the risk assessment.
    We are currently considering applying the proposed requirements, 
for approval of chemical-only firefighting systems, to major and manned 
minor platforms that already have agency approval, as well as to new 
platforms. We solicit comments as to whether including already-approved 
platforms would be feasible and would provide an additional level of 
safety and protection so as to justify the cost and effort.
    Proposed Sec.  250.860(b) would address what an operator must 
maintain or submit for the chemical firefighting system. This section 
would also clarify that once 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 barrels or more on the facility, adding 
production equipment, or planning to man an unmanned platform, it must 
seek BSEE District Manager approval.
    Proposed Sec.  250.860(c) would address the use of chemical-only 
firefighting systems on platforms that are both minor and unmanned. The 
rule would authorize the use of 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, on all platforms that are both minor and unmanned, as long as 
the operator ensures that the unit is available on the platform when 
personnel are on board. A facility-specific authorization would not be 
required.
Foam Firefighting System (Sec.  250.861)
    Proposed Sec.  250.861 would establish requirements for the use of 
foam firefighting systems. Under the proposed rule, when foam 
firefighting systems are installed as part of a firefighting system, 
the operator would be required annually to (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 
rule would specify that the certification document must be readily 
accessible for field inspection. In lieu of sampling and certification, 
the proposed rule would allow operators to replace the total inventory 
of foam with suitable new stock. The rule would also require that the 
quantity of concentrate must meet design requirements, and tanks or 
containers must be kept full with space allowed for expansion.
Fire and Gas-Detection Systems (Sec.  250.862)
    Existing Sec.  250.803(b)(9), pertaining to fire and gas-detection 
systems, would be recodified as proposed Sec.  250.862.
Electrical Equipment (Sec.  250.863)
    Existing Sec.  250.803(b)(10) pertaining to electrical equipment, 
would be recodified as proposed Sec.  250.863.
Erosion (Sec.  250.864)
    Existing Sec.  250.803(b)(11) pertaining to erosion control, would 
be recodified as proposed Sec.  250.864.

[[Page 52249]]

Surface Pumps (Sec.  250.865)
    Proposed Sec.  250.865, pertaining to surface pumps, would contain 
material from existing Sec.  250.803(b)(1)(iii), pressure and fired 
vessels, as well as new requirements for pump installations. This would 
include a requirement to use pressure recording devices to establish 
new operating pressure ranges for pump discharge sensors, and a 
specific requirement to equip all pump installations with the 
protective equipment recommended by API RP 14C, Appendix A--A.7, Pumps.
Personnel Safety Equipment (Sec.  250.866)
    Proposed Sec.  250.866 is a new section that would require that all 
personnel safety equipment be maintained in good working order.
Temporary Quarters and Temporary Equipment (Sec.  250.867)
    Proposed Sec.  250.867 is a new section that would require that all 
temporary quarters installed on OCS facilities be approved by BSEE and 
that temporary quarters be equipped with all safety devices required by 
API RP 14C, Appendix C. It would also clarify that the District Manager 
could require the installation of a temporary firewater system. This 
new section would also require that temporary equipment used for well 
testing and/or well clean-up would have to be approved by the District 
Manager.
    The temporary equipment requirements are needed based on a number 
of incidents involving the unsuccessful use of such equipment. 
Currently, BSEE receives limited information regarding temporary 
equipment. These changes would help ensure that BSEE has a more 
complete understanding of all operations associated with temporary 
quarters and temporary equipment.
Non-metallic Piping (Sec.  250.868)
    Proposed Sec.  250.868 is a new section that would require that 
non-metallic piping be used only in atmospheric, primarily non-
hydrocarbon service such as piping in galleys and living quarters, open 
atmospheric drain systems, overboard water piping for atmospheric 
produced water systems, and firewater system piping.
General Platform Operations (Sec.  250.869)
    Existing Sec.  250.803(c), pertaining to general platform 
operations, would be codified as proposed Sec.  250.869, with a new 
requirement in the proposed rule (Sec.  250.869(e)) that would prohibit 
utilization of the same sensing points for both process control devices 
and component safety devices on new installations. This section would 
also establish monitoring procedures for bypassed safety devices and 
support systems.
    A new provision in paragraph (2)(i) would require the computer-
based technology system control stations to not only show the status 
of, but be capable of displaying, operating conditions. It also 
clarifies that if the electronic systems are not capable of displaying 
operating conditions, then industry would have to have field personnel 
monitor the level and pressure gauges and be in communication with the 
field personnel.
    A new provision, proposed Sec.  250.869(a)(3), would be added that 
would specify that operators must not bypass, for maintenance or 
startup, any element of the emergency support system (ESS) or other 
support system required by API RP 14C, Appendix C, without first 
receiving approval from BSEE to use alternative procedures or equipment 
in accordance with 250.141. These are essential systems that provide a 
level of protection to a facility by initiating shut-in functions or 
reacting to minimize the consequences of released hydrocarbons. The 
rule would contain a non-exclusive list of these systems.
Time Delays on Pressure Safety Low (PSL) Sensors (Sec.  250.870)
    Proposed Sec.  250.870, another new provision, would be added to 
incorporate guidance of existing NTL 2009-G36, related to time delays 
on PSL sensors. The proposed rule would specify that operators must 
apply industry standard Class B, Class C, and 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 would require BSEE approval of a request 
under Sec.  250.141. Operators would be required to document on their 
field test records any use of a PSL sensor with a time delay greater 
than 45 seconds.
    For purposes of proposed Sec.  250.870, PSL sensors would be 
categorized as follows:
    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). These sensors are mostly used in 
conjunction with the design of pump and compressor panels and include 
PSL sensors, lubricator no-flows, and high-water jacket temperature 
shutdowns.
    Class C safety devices have logic that allows for the PSL sensors 
to be bypassed until the component comes into full service (i.e., at 
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).
    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, such as, 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 the Class B timer expires no later than 45 seconds 
from start activation or 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.
    The proposed rule would also provide 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. Use of a manual bypass that involves a 
time delay greater than 45 seconds would require approval of a request 
made under Sec.  250.141 from the appropriate BSEE District Manager.
Welding and Burning Practices and Procedures (Sec.  250.871)
    Existing Sec.  250.803(d), pertaining to welding and burning 
practices and procedures, would be recodified as proposed Sec.  
250.871, with a proposed new requirement that would prohibit variance 
from the approved welding and burning practices and procedures unless 
such variance were approved by BSEE as an acceptable alternative 
procedure or equipment in accordance with Sec.  250.141.
Atmospheric Vessels (Sec.  250.872)
    Proposed Sec.  250.872 is a new section that would require 
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. Requirements for 
level safety high sensors (LSHs) would also be added. There would also 
be clarification added that for atmospheric vessels that have oil 
buckets, the LSH sensor would have to

[[Page 52250]]

be installed to sense the level in the oil bucket.
Subsea Gas Lift Requirements (Sec.  250.873)
    This is a new section that would be added to codify existing policy 
and guidance from the DWOP process. The BSEE has approved the use of 
gas lift equipment and methodology in subsea wells, pipelines, and 
risers via the DWOP approval process and imposed conditions to ensure 
that the necessary safety mitigations are in place. While the basic 
requirements of API RP 14C still apply for surface applications, 
certain clarifications need to be made to ensure regulatory compliance 
when gas lift for recovery for subsea production operations is used. 
Proposed Sec.  250.873 would add the following new requirements: design 
of the gas lift supply pipeline according to API 14C; installation of 
specific safety valves, including a gas-lift shutdown valve and a gas-
lift isolation valve; outlining the valve closure times and hydraulic 
bleed requirements according to the DWOP; and gas lift valve testing 
requirements.
Subsea Water Injection Systems (Sec.  250.874)
    This is a new section that would be added to codify existing policy 
and guidance from the DWOP process, related to water flood injection 
via subsea wellheads. This is similar to the subsea gas lift as 
discussed in the previous section. The basic requirements of API RP 14C 
still apply for surface applications, yet certain clarifications need 
to be made to ensure regulatory compliance for the use of water flood 
systems for recovery for subsea production operations. Proposed Sec.  
250.874 would add the following new requirements: adhere to the water 
injection requirements described in API RP 14C for the water injection 
equipment located on the platform; equip the water injection system 
with certain safety valves, including water injection valve (WIV) and a 
water injection shutdown valve (WISDV); establish the valve closure 
times and hydraulic bleed requirements according to the DWOP; and 
establish WIV testing requirements.
Subsea Pump Systems (Sec.  250.875)
    This is a new section that would be added to codify policy and 
guidance from an existing National NTL, ``Subsea Pumping for Production 
Operations,'' NTL No. 2011-N11 and the DWOP. Proposed Sec.  250.875 
would outline subsea pump system requirements, including: the 
installation and location of specific safety valves, operational 
considerations under circumstances if 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, the reference to desired valve closure times contained within 
the DWOP, and subsea pump testing.
Fired and Exhaust Heated Components (Sec.  250.876)
    This is a new section that would require certain tube-type heaters 
to be removed, inspected, repaired, or replaced every 5 years by a 
qualified third party. This new section would also add that the 
inspection results must be documented, retained for at least 5 years, 
and made available to BSEE upon request. This new section was added in 
part due to the BSEE investigation report into the Vermillion 380 
platform fire ``Vermilion Block, Production Platform A: An 
Investigation of the September 2, 2010 Incident in the Gulf of Mexico, 
May 23, 2011.'' The report states that ``The immediate cause of the 
fire was that the Heater-Treater's weakened fire tube became malleable 
and collapsed in a `canoeing' configuration, ripping its steel apart 
and creating openings through which hydrocarbons escaped, came into 
contact with the Heater-Treater's hot burner, and then produced 
flames.'' The report states that a possible contributing cause of the 
fire was a lack of routine inspections of the fire tube. From the 
report, ``we found that a possible contributing cause of the fire was 
the company's failure to follow the [BSEE] regulations related to API 
510 that require an inspection plan for Heater-Treaters and its failure 
to regularly inspect and maintain the Heater-Treater. [BSEE] 
regulations require the operator to routinely maintain and inspect the 
pressure vessel. While the regulations do not specifically address the 
fire tube inside of the Heater-Treater, weaknesses in the fire tube and 
temperature-related issued would likely have been identified if the 
operator routinely inspected the Heater-Treater.''
    The Vermillion 380 platform fire is one of the recently documented 
incidents involving fires or hazards caused by fire tube failures. 
Since 2011, there have been other similar incidents involving tube-type 
heaters. These types of incidents involving tube-type heaters are a 
concern for BSEE due to the potential safety issues of offshore 
personnel and infrastructure. The BSEE determined that this new 
requirement would help ensure tube-type heaters are inspected routinely 
to minimize the risk of tube-type heater incidents.
[RESERVED] Sec. Sec.  250.877-250.879

Safety Device Testing

Production Safety System Testing (Sec.  250.880)
    Existing Sec.  250.804(a), pertaining to production safety system 
testing, would be recodified as proposed Sec.  250.880. A table would 
be inserted to help to clarify requirements and make them easier to 
find.
    Proposed Sec.  250.880(a) would include the notification 
requirement from existing Sec.  250.804(a)(12) and would clarify that 
an operator must give BSEE 72 hours notice prior to commencing 
production so that BSEE may witness a preproduction test and conduct a 
preproduction inspection of the integrated safety system.
    In proposed Sec.  250.880, BSEE would revise existing requirements 
to increase certain liquid leakage rates from 200 cubic centimeters per 
minute to 400 cubic centimeters per minute and gas leakage rates from 5 
cubic feet per minute to 15 cubic feet per minute. These proposed 
changes reflect consistency with industry standards and account for 
accessibility of equipment in deepwater/subsea applications. In 1999, 
the former Minerals Management Service 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. 
The recommendations section of this study states, ``there appears to be 
preliminary evidence indicating that more stringent leakage 
requirements specified in 30 CFR 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.'' You may 
view the complete report at http://bsee.gov/Research-and-Training/Technology-Assessment-and-Research/Project-272.aspx. 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''. 
The barrier concept moves the SSV from the well to the BSDV that has 
been proven to be as safe as, or safer than, what is required by the 
current regulations.
    The following table compares existing allowable leakage rates to 
the proposed increased allowable leakage rates for various safety 
devices:

[[Page 52251]]

------------------------------------------------------------------------
                                                        The increased
                                Allowable leakage     allowable leakage
          Item name               rate testing          rate testing
                               requirements under   requirements for the
                               current regulations      proposed rule
------------------------------------------------------------------------
Surface-controlled SSSVs      liquid leakage rate   liquid leakage rate
 (including devices            electronic switch LSH and level safety low (LSL) controls. 
This section would also add 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. Many of these requirements would 
be included in a series of proposed tables.
[RESERVED] (Sec. Sec.  250.881-250.889)

Records and Training

Records (Sec.  250.890)
    Existing Sec.  250.804(b), pertaining to maintaining records of 
installed safety devices, would be recodified as proposed Sec.  
250.890, with new information submittal requirements that are meant to 
assist BSEE in contacting operators.
Safety Device Training (Sec.  250.891)
    Existing Sec.  250.805, pertaining to personnel training, would be 
recodified as proposed Sec.  250.891. The wording of this section would 
be changed to more accurately capture the scope of subpart S training 
requirements.
[RESERVED] (Sec. Sec.  250.892-250.899)

Additional Comments Solicited

    In additional to the input requested above, BSEE requests public 
comment on the following:

Organization of Rule Based on Use of Subsea Trees and Dry Trees

    The BSEE requests general public comments on whether the proposed 
reorganization of the regulations by type of facility (subsea tree and 
dry tree) is helpful.

Lifecycle Analysis Approach to Other Types of Critical Equipment Such 
as Blowout Preventers (BOPs)

    The BSEE is considering applying a lifecycle analysis approach to 
other types of critical equipment that we regulate. We are specifically 
requesting comments on how this approach could be used to assist in 
increasing the reliability of critical equipment such as BOPs. The BSEE 
currently relies on pressure testing to demonstrate BOP performance and 
reliability. Can a lifecycle approach replace or supplement these 
requirements? Are there other types of critical equipment that are good 
candidates for the life cycle approach? Are there industry standards 
that can serve as the basis for BSEE's increased focus on the life 
cycle of critical equipment?

Failure Reporting and Information Dissemination

    Industry standards such as API Spec. 14A include processes and 
procedures for addressing the reporting and subsequent review of the 
failure of critical equipment. This information is extremely important 
in ensuring continuous improvement in the design and reliability of the 
equipment. Based on recent experiences in the GOM and input from 
industry, BSEE believes there are a variety of factors that discourage 
the timely and voluntary exchange of this type of information with the 
rest of the industry and BSEE. The BSEE believes that a more 
comprehensive and formalized reporting and review system would increase 
the exchange of data and allow the industry and BSEE to identify trends 
and issues that impact offshore safety. The BSEE requests comments on 
whether these failure reports should be submitted directly to BSEE or 
provided to an appropriate third party organization that would be 
responsible for reviewing and analyzing the data and notifying the 
industry of potential problems. The BSEE also requests comments on how 
this type of system could be broaden to include international offshore 
operations.

Third Party Certification Organizations

    In various sections of the regulations, BSEE requires third party 
verification of the design of systems and equipment. The design, 
installation, inspection, maintenance, and repair of subsea equipment 
and systems presents a variety of unique technical challenges to the 
industry and BSEE. The BSEE solicits comments on the use of third party 
certification organizations to assist BSEE in ensuring that these 
systems are designed and maintained during its entire service life with 
an acceptable degree of risk. The BSEE also solicits comments on the 
use of a single lifecycle certification program that covers SPPE, 
risers, platforms, and production systems.

Information Requested on Opportunities To Limit Emissions of Natural 
Gas From OCS Production Equipment

    Throughout the production process, certain volumes of natural gas 
are lost to the atmosphere through fugitive emissions and flaring or 
venting. The BSEE is evaluating opportunities to reduce methane and 
other air emissions through use of the best available production 
equipment technology and practices. We are seeking additional 
information on these opportunities. Information obtained through public 
comments on this topic may be used to support a Regulatory Impact 
Analysis.

[[Page 52252]]

We are not proposing new production equipment requirements to limit 
emissions in this rulemaking, but are seeking additional information on 
technologies and costs for emissions-limiting equipment that can be 
used on OCS production facilities. This information will be considered 
consistent with applicable statutes and E.O. 12866/13563 during BSEE's 
evaluation of future regulatory options.
    The GAO issued a report on this topic in October 2010: http://www.gao.gov/new.items/d1134.pdf, Opportunities Exist To Capture Vented 
and Flared Natural Gas, Which Would Increase Royalty Payments and 
Reduce Greenhouse Gases. As part of Interior's response to that report, 
BSEE is further evaluating opportunities to limit natural gas emissions 
on existing production facilities.
    Venting, flaring, and small fugitive releases of natural gas are 
often a necessary part of production; however, the lost gas has safety, 
economic, and environmental implications. It represents a loss of 
revenue for lessees, loss of royalty revenue for the Federal 
government, and adds to greenhouse gases in the atmosphere. 
Implementation of available emissions-limiting equipment and venting 
and flaring reduction technologies could increase sales volumes, 
revenue, and improve the environment.
    Routine preventive maintenance and certain technologies are applied 
to capture or flare much of this lost gas. The technologies' 
feasibility varies and heavily depends on the characteristics of the 
OCS production facility. The following emissions-limiting equipment may 
provide for prevention, capture, or flaring of released natural gas:
    (1) Gas dehydration: A flash tank separator and vapor recovery unit 
that reduces the amount of gas that is vented into the atmosphere.
    (2) Pneumatic devices: Replacing pneumatic devices at all stages of 
production that release, or ``bleed,'' gas at a high rate (high-bleed 
pneumatics) with devices that bleed gas at a lower rate (low-bleed 
pneumatics), or installing an air pneumatic system and converting to 
instrument air instead.
    (3) Losses from flashing (reciprocating compressors): Replace cup 
ring, cups, and cases. How often is this preventive maintenance 
performed on reciprocating compressors?
    (4) Losses from flashing (centrifugal compressors): Replace wet 
seals with dry seals or install a gas recovery system.
    We are seeking additional information on the cost, economic 
viability and estimated effectiveness of equipment and these actions or 
others on OCS production facilities. If your OCS production facilities 
already employ the best available emissions limiting technology and 
equipment, or if there are other equipment or practices that limit 
emissions on OCS production facilities, we welcome that information 
also. Does your company have a leak detection (infrared/acoustic 
detection equipment) or maintenance program for OCS production 
facilities? What has your company found regarding the cost-
effectiveness and benefits of such a program? Comments from the public 
are also welcome.

Flaring

    We are seeking additional information similar to that provided by 
the Offshore Operators Committee (OOC) at the then Bureau of Ocean 
Energy Management Regulation and Enforcement, March 2011, workshop on 
venting and flaring. The profiles of operator's production facilities 
vary widely and BSEE welcomes additional facility information from 
operators beyond that provided at the workshop.
    The workshop (75 FR 81950) regulations.gov docket BOEM-2010-0042 
resulted in some information for the installation of flare equipment on 
GOM shelf facilities. The cost information in the following table was 
provided by OOC for a single operator's GOM production facilities. 
Furthermore we would like to get similar information from other 
operators. We are specifically seeking your company count of the 
facility types listed in the table below, and if the associated 
estimated cost for each facility type is appropriate.

------------------------------------------------------------------------
                                                         Estimated cost
                    Facility type                          for flare
                                                          installation
------------------------------------------------------------------------
Gas already flared...................................                 $0
Satellite facilities with no significant venting.....                  0
Facilities with adequate vent boom to support flare..          1,629,000
Facilities with inadequate vent boom, but structure            2,639,000
 can support flare boom installation.................
Facilities with inadequate vent boom, structure                6,664,000
 cannot support flare boom installation..............
------------------------------------------------------------------------

Procedural Matters

Regulatory Planning and Review (Executive Orders 12866 and 13563)

    Executive Order 12866 provides that the Office of Information and 
Regulatory Affairs (OIRA) will review all significant rules. The OIRA 
determined that that this rule is not a significant rulemaking under 
E.O. 12866. Nevertheless, BSEE had an outside contractor prepare an 
economic analysis to assess the anticipated costs and potential 
benefits of the proposed rulemaking. The following discussions 
summarize the economic analysis; however, a complete copy of the 
economic analysis can be viewed at www.Regulations.gov (use the 
keyword/ID ``BSEE-2012-0005'').
    This proposed rule largely codifies standard industry practice and 
clarifies existing BSEE regulations and guidance. The requirements 
under the proposed rule align with those under the 1988 rule and other 
existing documents that regulate and guide the industry (e.g., 
Deepwater Operations Plans (DWOPs), Notices to Lessees (NTLs), and 
American Petroleum Institute (API) industry standards). The economic 
effect of the proposed rule is confined to certain reporting, 
certification, inspection, and documentation requirements, which have 
an estimated incremental cost for offshore oil and natural gas 
production facilities in aggregate of approximately $170,000 per year 
(see Table 1 below) without taking into consideration the potential 
benefits associated with the potential reduction in oil spills and 
injuries. The following Table provides a summary of the economic 
analysis.

                   Table 1--Economic Analysis Summary
------------------------------------------------------------------------
 
------------------------------------------------------------------------
$ costs of proposed rule =........  -($1.71 million).
Potential $ benefits of proposed    $1.54 million.
 rule due to increased leakage
 rates =.
(Potential $ benefits of increased  -($172,027).
 leakage rates - $ costs) =.

[[Page 52253]]

 
Potential benefits in $ due to      $19.4 million.
 potential incident avoidance of
 oil spills and injuries =.
Break-even risk reduction level =.  8.07 percent.
------------------------------------------------------------------------

    The proposed rule is intended to address, among other things, 
issues that have developed since publication in 1988 (53 FR 10690) of 
the existing Subpart H rule. Since that time, oil and gas production on 
the OCS has moved into deeper waters, introducing new challenges for 
industry and BSEE. For example, industry has shown interest in 
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. Many of the new provisions in 
the proposed rule would codify BSEE's policies pertaining to production 
safety systems. This proposed rule would codify essential elements 
included in existing guidance documents, make clear BSEE's basic 
expectations, and provide industry with a balance of predictability and 
flexibility to address concerns related to offshore oil and natural gas 
production.
    The BSEE is requesting comment on other options to consider, 
including alternatives to the specific provisions contained in the 
proposed rule, with the goal of ensuring a full discussion of these 
issues in advance of the final rule stage.
    The BSEE retained a contractor to estimate the annual economic 
effect of this proposed rule on the offshore oil and natural gas 
production industry by comparing the costs and potential benefits of 
the new provisions in the proposed rule to the baseline (i.e., current 
practice in accordance with the 1988 rule, existing guidance documents, 
and industry standards). Existing impacts from the 1988 rule, DWOPs, 
NTLs, and API standards were not considered as costs and benefits of 
this proposed rule because they are part of the baseline. The analysis 
covered 10 years (2012 through 2021) to capture all major costs and 
potential benefits that could result from this proposed rule and 
presents the estimated annual effects, as well as the 10-year 
discounted totals using discount rates of 3 and 7 percent.
    The BSEE welcomes comments on this analysis, including potential 
sources of data or information on the costs and potential benefits of 
this proposed rule. In summary, the contractor monetized the costs of 
the proposed rule for all the following provisions determined to result 
in a change from baseline: Reporting after a failure of SPPE equipment; 
notifying BSEE of production safety issues; certification for designs 
of mechanical and electrical systems; certification letter for 
mechanical and electrical systems installed in accordance with approved 
designs; certification of as-built diagrams of schematic piping and 
instrumentation diagrams and the safety analysis flow diagram; As-built 
piping and instrumentation diagrams to be maintained at a secure 
onshore location; inspection, testing, and certification of foam 
firefighting systems; inspection of fired and exhaust heated 
components; and submission of a contact list for OCS platforms. The 
analysis also considered the time required for industry staff to read 
and familiarize themselves with the new regulation. The total expected 
cost over 10 years of complying with these provisions is $16.87 
million, or on average $1.7 million annually.
    In addition, the analysis valued the expected potential benefits of 
the proposed rule by evaluating the increase of the allowable leakage 
rates for certain safety valves and by evaluating oil spills and 
injuries as a whole. This proposed rule intends to address the 
unnecessary repair or replacement of certain safety valves due to a 
higher allowable leakage rate and reduce the number of incidents 
resulting in oil spills and injuries. Thus, the total benefits of the 
rule consist of potential benefits for increasing the allowable leakage 
rates of certain safety devices and avoided damages. The potential 
benefit of allowing a higher leakage rate for certain safety valves is 
approximately $1.54 million annually. Using avoided cost factors 
developed for rulemaking in the wake of the Deepwater Horizon oil 
spill, the contractor estimated OCS facilities addressed by this rule 
account for an annual average of $19.4 million dollars in damages due 
to potential spills and injuries, for a total maximum potential benefit 
amount of $20.9 million. While the proposed rule is aimed at preventing 
oil spills and injuries, the actual reduction in the probability of 
incidents that the proposed rule would achieve is uncertain. Due to 
this uncertainty, BSEE was not able to perform a standard cost-benefit 
analysis estimating the net benefits of the proposed rule. As is common 
in situations where regulatory benefits are highly uncertain, a break-
even analysis, which estimates the minimum risk reduction the proposed 
rule would need to achieve for the rule to be cost-beneficial. However, 
the potential benefits of the proposed rule only need to reduce these 
baseline adverse effects by between 8 and 9 percent to be considered 
cost-effective. This break-even analysis result suggests that the 
proposed rule would be beneficial even if it resulted in only one or 
two fewer typical incidents annually than the average of about 200 per 
year that happen under the baseline conditions.
    Thus, BSEE has concluded that the proposed rule would produce 
substantial benefits that justify the compliance costs that it would 
impose.
    Executive Order 13563 reaffirms the principles of E.O. 12866 while 
calling for improvements in the Nation's regulatory system to promote 
predictability, to reduce uncertainty, and to use the best, most 
innovative, and least burdensome tools for achieving regulatory ends. 
The executive order directs agencies to consider regulatory approaches 
that reduce burdens and maintain flexibility and freedom of choice for 
the public where these approaches are relevant, feasible, and 
consistent with regulatory objectives. E.O. 13563 emphasizes further 
that regulations must be based on the best available science and that 
the rulemaking process must allow for public participation and an open 
exchange of ideas. The BSEE works closely with engineers and technical 
staff to ensure this rulemaking utilizes sound engineering principles 
and options through research, standards development, and interaction 
with industry. Thus, we have developed this rule in a manner consistent 
with these requirements.

Regulatory Flexibility Act

    The DOI certifies that this proposed rule would not have a 
significant economic effect on a substantial number of small entities 
as defined under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.).
    The Regulatory Flexibility Act (RFA) at 5 U.S.C. 603 requires 
agencies to prepare a regulatory flexibility analysis to determine 
whether a regulation would have a significant economic impact on a 
substantial number of small entities. Section 605 of the RFA allows an 
agency to certify a rule in lieu of preparing an analysis if the 
regulation is not expected to have a significant economic impact on a 
substantial

[[Page 52254]]

number of small entities. Further, under the Small Business Regulatory 
Enforcement Fairness Act of 1996, 5 U.S.C. 801 (SBREFA), an agency is 
required to produce compliance guidance for small entities if the rule 
has a significant economic impact. For the reasons explained in this 
section, BSEE believes this rule is not likely to have a significant 
economic impact and, therefore, an initial regulatory flexibility 
analysis is not required by the RFA. However, in the interest of 
transparency, BSEE had a contractor prepare an Initial Regulatory 
Flexibility Analysis (IRFA) to assess the impact of this proposed rule 
on small entities, as defined by the applicable Small Business 
Administration (SBA) size standards. The following discussions 
summarize the IRFA; however, a copy of the complete IRFA can be viewed 
at www.Regulations.gov (use the keyword/ID ``BSEE-2012-0005'').

a. Reasons BSEE Is Considering Action

    The BSEE identified a need to revise Subpart H, Oil and Gas 
Production Safety Systems, which addresses production safety systems, 
subsurface safety devices, and safety device testing used in oil and 
natural gas production on the OCS, among other issues. These systems 
play a critical role in protecting workers and the environment. 
However, BSEE has not revised the regulation since its publication in 
1988 (53 FR 10690). Since that time, oil and gas production on the OCS 
has moved into deeper waters, introducing new challenges for industry 
and BSEE. Many of the new provisions in the proposed rule would codify 
BSEE guidance and incorporate current industry practice. In addition, 
the wording and structure of the 1988 rule creates confusion about the 
requirements. The BSEE has rewritten and reorganized the rule to 
clarify existing requirements and highlight important information. 
These revisions would significantly improve readability of the 
regulation.

b. Description and Estimated Number of Small Entities Regulated

    A small entity is one that is ``independently owned and operated 
and which is not dominant in its field of operation.'' The definition 
of small business varies from industry to industry in order to properly 
reflect industry size differences.
    The proposed rule would affect operators and holders of Federal oil 
and gas leases, as well as pipeline right-of-way holders, on the OCS. 
The BSEE's analysis shows that this includes about 130 companies with 
active operations. Entities that operate under this rule fall under the 
SBA's North American Industry Classification System (NAICS) codes 
211111 (Crude Petroleum and Natural Gas Extraction) and 213111 
(Drilling Oil and Gas Wells). For these NAICS classifications, a small 
company is defined as one with fewer than 500 employees. Based on this 
criterion, approximately 90 (69 percent) of the companies operating on 
the OCS are considered small and the rest are considered large 
businesses. Therefore, BSEE estimates that the proposed rule would 
affect a substantial number of small entities.

c. Description and Estimate of Compliance Requirements

    The BSEE has estimated the incremental costs for small operators, 
lease holders, and right-of-way holders in the offshore oil and natural 
gas production industry. Costs that already existed as a result of the 
1988 rule, DWOPs, and currently-incorporated API standards were not 
considered as costs of this rule because they are part of the baseline. 
We have estimated the costs of the following provisions of the proposed 
rule: Reporting after a failure of SPPE equipment; notifying BSEE about 
production technical issues; certification, submission, and maintenance 
of designs and diagrams; inspection, testing, and certification of foam 
firefighting systems; inspection of fired and exhaust heated 
components; submission of contact list for OCS platforms; and 
familiarization with the new regulation.
    Table 2 below shows the annual costs per small entity. Because most 
small entities would not be subject to all of the rule provisions, we 
also calculated the most likely impact on small entities, or the impact 
associated with only incurring the cost for the provisions for foam 
firefighting systems, inspection of fired and exhaust heated 
components, submission of contact list, and familiarization with the 
new regulations. This calculation resulted in a most likely average 
annual cost per affected small entity of $5,906 as shown in Table 2. In 
addition, we calculated a ``complete compliance scenario'' impact for 
an entity that would incur the costs of all of the rule provisions. As 
shown in Table 2, this complete compliance scenario impact is $8,183 
per affected entity.
    We then calculated the impact on small entities for these three 
scenarios as a percentage of the average revenues for small entities in 
the affected industries.

                  Table 2--Annual Cost per Small Entity
                          [10-Year average] \1\
------------------------------------------------------------------------
                                                              10-Year
                                                              average
------------------------------------------------------------------------
(1) Reporting after a failure of SPPE equipment.........            $168
(2) Notifying BSEE about technical issues...............             378
(3) Certification, submission, and maintenance of                  1,730
 designs and diagrams...................................
(4) Inspection, testing, and certification of foam                   757
 firefighting systems...................................
(5) Five-year inspection of fired and exhaust heated               5,000
 components.............................................
(6) Submission of contact list for OCS platforms........             127
(7) Familiarization with new regulation.................              22
Most likely average annual cost per small entity (4 + 5            5,906
 + 6 + 7)...............................................
Complete compliance scenario average annual cost per               8,183
 small entity...........................................
------------------------------------------------------------------------
\1\ Totals may not add because of rounding.

    As shown in Table 3, the average costs of the two scenarios 
represent far less than 1 percent of average annual revenues for small 
entities in the affected industries.

                Table 3--Cost as a Percentage of Revenue
------------------------------------------------------------------------
 
------------------------------------------------------------------------
   Average revenue of a small business              45,700,000
------------------------------------------------------------------------
                                               Cost        Cost/revenue
                                                             (percent)
------------------------------------------------------------------------
Most likely total (4 + 5 + 6 + 7).......          $5,906           0.013
Complete compliance scenario cost total.           8,183           0.018
------------------------------------------------------------------------

[[Page 52255]]

    Based on this analysis, BSEE believes that this proposed rule would 
have a limited net direct cost impact on small operators, lease 
holders, and pipeline right-of-way holders beyond the baseline costs 
currently imposed by regulations with which industry already complies. 
The BSEE concludes that this proposed rule would not have a significant 
economic impact on a substantial number of small entities.

d. Description of Significant Alternatives to the Proposed Rule

    The operating risk for small companies to incur safety or 
environmental accidents is not necessarily lower than it is for larger 
companies. Offshore operations are highly technical and can be 
hazardous. Adverse consequences in the event of incidents are the same 
regardless of the operator's size. The proposed rule would reduce risk 
for entities of all sizes. Nonetheless, BSEE is requesting comment on 
the costs of these proposed policies on small entities, with the goal 
of ensuring thorough consideration and discussion at the final rule 
stage. We specifically request comments on the burden estimates 
discussed above as well as information on regulatory alternatives that 
would reduce the burden on small entities (e.g., different compliance 
requirements for small entities, alternative testing requirements and 
periods, and exemption from regulatory requirements).
    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 without 
fear of retaliation. Allegations of discrimination/retaliation filed 
with the Small Business Administration will be investigated for 
appropriate action.

Small Business Regulatory Enforcement Fairness Act

    The proposed rule is not a major rule under the Small Business 
Regulatory Enforcement Fairness Act (5 U.S.C. 801 et seq.). This 
proposed rule:
    a. Would not have an annual effect on the economy of $100 million 
or more. This proposed rule would revise the requirements for oil and 
gas production safety systems. The changes would not have an impact on 
the economy or any economic sector, productivity, jobs, the 
environment, or other units of government. Most of the new requirements 
are related to inspection, testing, and paperwork requirements, and 
would not add significant time to development and production processes. 
The complete annual compliance cost for each affected small entity is 
estimated at $8,183.
    b. Would not cause a major increase in costs or prices for 
consumers, individual industries, Federal, State, or local government 
agencies, or geographic regions.
    c. Would not have significant adverse effects on competition, 
employment, investment, productivity, innovation, or the ability of 
U.S.-based enterprises to compete with foreign-based enterprises. The 
requirements will apply to all entities operating on the OCS.

Unfunded Mandates Reform Act of 1995

    This proposed rule would not impose an unfunded mandate on State, 
local, or tribal governments or the private sector of more than $100 
million per year. The proposed rule would not have a significant or 
unique effect on State, local, or tribal governments or the private 
sector. A statement containing the information required by Unfunded 
Mandates Reform Act (2 U.S.C. 1531 et seq.) is not required.

Takings Implication Assessment (Executive Order 12630)

    Under the criteria in E.O. 12630, this proposed rule does not have 
significant takings implications. The proposed rule is not a 
governmental action capable of interference with constitutionally 
protected property rights. A Takings Implications Assessment is not 
required.

Federalism (Executive Order 13132)

    Under the criteria in E.O. 13132, this proposed rule does not have 
federalism implications. This proposed rule would not substantially and 
directly affect the relationship between the Federal and State 
governments. To the extent that State and local governments have a role 
in OCS activities, this proposed rule would not affect that role. A 
Federalism Assessment is not required.
    The BSEE has the authority to regulate offshore oil and gas 
production. State governments do not have authority over offshore 
production in Federal waters. None of the changes in this proposed rule 
would affect areas that are under the jurisdiction of the States. It 
would not change the way that the States and the Federal government 
interact, or the way that States interact with private companies.

Civil Justice Reform (Executive Order 12988)

    This rule complies with the requirements of E.O. 12988. 
Specifically, this rule:
    (a) Meets the criteria of section 3(a) requiring that all 
regulations be reviewed to eliminate errors, ambiguity, and be written 
to minimize litigation; and
    (b) meets the criteria of section 3(b)(2) requiring that all 
regulations be written in clear language and contain clear legal 
standards.

Consultation With Indian Tribes (Executive Order 13175)

    Under the criteria in E.O. 13175, we have evaluated this proposed 
rule and determined that it has no potential effects on federally 
recognized Indian tribes.

Paperwork Reduction Act (PRA) of 1995

    This proposed rule contains a collection of information that will 
be submitted to the Office of Management and Budget (OMB) for review 
and approval under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 
et seq.). As part of our continuing effort to reduce paperwork and 
respondent burdens, BSEE invites the public and other Federal agencies 
to comment on any aspect of the reporting and recordkeeping burden. If 
you wish to comment on the information collection (IC) aspects of this 
proposed rule, you may send your comments directly to OMB and send a 
copy of your comments to the Regulations and Standards Branch (see the 
ADDRESSES section of this proposed rule). Please reference; 30 CFR Part 
250, Subpart H, Oil and Gas Production Safety Systems, 1014-0003, in 
your comments. You may obtain a copy of the supporting statement for 
the new collection of information by contacting the Bureau's 
Information Collection Clearance Officer at (703) 787-1607. To see a 
copy of the entire ICR submitted to OMB, go to http://www.reginfo.gov 
(select Information Collection Review, Currently Under Review).
    The PRA provides that an agency may not conduct or sponsor, and a 
person is not required to respond to, a collection of information 
unless it displays a currently valid OMB control number. OMB is 
required to make a decision concerning the collection of information 
contained in these proposed regulations 30 to 60 days after publication 
of this document in the Federal Register.

[[Page 52256]]

Therefore, a comment to OMB is best assured of having its full effect 
if OMB receives it by September 23, 2013. This does not affect the 
deadline for the public to comment to BSEE on the proposed regulations.
    The title of the collection of information for this rule is 30 CFR 
Part 250, Subpart H, Oil and Gas Production Safety Systems (Proposed 
Rulemaking). The proposed regulations concern oil and gas production 
requirements, and the information is used in our efforts to protect 
life and the environment, conserve natural resources, and prevent 
waste.
    Potential respondents comprise Federal OCS oil, gas, and sulphur 
operators and lessees. The frequency of response varies depending upon 
the requirement. Responses to this collection of information are 
mandatory, or are required to obtain or retain a benefit; they are also 
submitted on occasion, annually, and as a result of situations 
encountered depending upon the requirement. The IC does not include 
questions of a sensitive nature. The BSEE will protect proprietary 
information according to the Freedom of Information Act (5 U.S.C. 552) 
and its implementing regulations (43 CFR part 2), 30 CFR part 252, OCS 
Oil and Gas Information Program, and 30 CFR 250.197, Data and 
information to be made available to the public or for limited 
inspection.
    As discussed earlier in the preamble, the proposed rule is a 
complete revision of the current subpart H. It incorporates guidance 
from several NTLs that respondents currently follow, and would codify 
various conditions that BSEE imposes when approving production safety 
systems to ensure that they are installed and operated in a safe and 
environmentally sound manner. OMB approved the IC burden of the current 
30 CFR part 250, subpart H regulations under control number 1014-0003 
(62,963 burden hours; and $343,794 non-hour cost burdens). When the 
final revised subpart H regulations take effect, the IC burden approved 
for this rulemaking will replace the collection under 1014-0003 in its 
entirety.
    There is also a revised paragraph (c)(2) proposed for 30 CFR 
250.107 that would impose a new IC requirement. The paperwork burden 
for this proposed regulation is included in the submission to OMB for 
approval of the proposed IC for subpart H. When this rulemaking becomes 
final, the 30 CFR Part 250, Subpart A, paperwork burden would be 
removed from this collection of information and consolidated with the 
IC burden under OMB Control Number 1014-0022, 30 CFR Part 250, Subpart 
A, General.
    The following table provides a breakdown of the paperwork and non-
hour cost burdens for this proposed rulemaking. For the current 
requirements retained in the proposed rule, we used the approved 
estimated hour burdens and the average number of annual responses where 
discernible. However, there are several new requirements in the 
proposed rule as follows:
     Under subpart A, (Sec.  250.107(c)), we have added 
proposed BAST requirements (+10 hours).
     Under General Requirements (Sec.  250.802-803), we have 
added proposed SPPE life cycle analysis requirements (+132 hours).
     A proposed new section, Subsea and Subsurface Safety 
Systems--Subsea Trees (Sec. Sec.  250.825-833) would add new burden 
requirements (+24 hours).
     Under Production Safety Systems (Sec.  250.842), we added 
proposed certification requirements as well as documentation of these 
requirements (+608 hours).
     In various proposed requirements, requests for unique, 
specific approvals (+61 hours).
     A proposed new section, (Sec.  250.861(b)) would add new 
requirements pertaining to submission of foam samples annually for 
testing (+1,000 hours).
     A proposed new section, (Sec.  250.867) would add new 
requirements pertaining to submittals for temporary quarters, firewater 
systems, or equipment (+307 hours).
     A proposed new section, (Sec.  250.870) added 
documentation requirements (+3 hours).
     In Sec.  250.860, we proposed submittal notification and/
or recordkeeping of minor and major changes using chemical only fire 
prevention system (+7 hours).
     Proposed new, (Sec.  250.890) added an annual contact list 
submittal (+550 hours).
    Current subpart H regulations have 62,963 hours and $343,794 non-
hour cost burdens approved by OMB. This revision to the collection 
requests a total of 65,665 hours which is a burden hour net increase of 
2,702 hours. The non-hour cost burdens are unchanged. With the 
exception of items identified as NEW in the following chart, the burden 
estimates shown are those that are estimated for the current subpart H 
regulations.

----------------------------------------------------------------------------------------------------------------
                                   Reporting and
Citation 30 CFR 250,  subpart      recordkeeping        Hour burden    Average number of annual   Annual  burden
              A                     requirement                                responses               hours
----------------------------------------------------------------------------------------------------------------
107(c)(2)....................  NEW: Demonstrate to                 5  2 justifications..........              10
                                us that by using
                                BAST the benefits
                                are insufficient to
                                justify the cost.
----------------------------------------------------------------------------------------------------------------
    Subtotal.................                                         2 responses...............              10
----------------------------------------------------------------------------------------------------------------
Citation 30 CFR 250 Subpart H      Reporting and        Hour Burden    Average number of annual    Annual burden
          and NTL(s)                Recordkeeping                              responses                   hours
                                     Requirement
                                                     -----------------------------------------------------------
                                                                        Non-Hour Cost Burdens*
----------------------------------------------------------------------------------------------------------------
                                              General Requirements
----------------------------------------------------------------------------------------------------------------
800(a).......................  Requirements for your  Burden included with specific requirements               0
                                production safety                       below.
                                system application.
----------------------------------------------------------------------------------------------------------------
800(a); 880(a)...............  Prior to production,                1  76 requests...............              76
                                request approval of
                                pre-production
                                inspection; notify
                                BSEE 72 hours before
                                commencement so we
                                may witness
                                preproduction test
                                and conduct
                                inspection.
----------------------------------------------------------------------------------------------------------------

[[Page 52257]]

 
801(c).......................  Request evaluation                  2  1 request.................               2
                                and approval [OORP]
                                of other quality
                                assurance programs
                                covering manufacture
                                of SPPE.
----------------------------------------------------------------------------------------------------------------
802(c)(1); 852(e)(4); 861(b).  NEW: Submit statement/        Not considered IC under 5 CFR                     0
                                certification for:                   1320.3(h)(1).
                                exposure
                                functionality; pipe
                                is suitable and
                                manufacturer has
                                complied with IVA;
                                suitable
                                firefighting foam
                                per original
                                manufacturer
                                specifications.
----------------------------------------------------------------------------------------------------------------
802(c)(5)....................  NEW: Document all                   2  30 documents..............              60
                                manufacturing,
                                traceability,
                                quality control, and
                                inspection
                                requirements. Retain
                                required
                                documentation until
                                1 year after the
                                date of
                                decommissioning the
                                equipment.
----------------------------------------------------------------------------------------------------------------
803(a).......................  NEW: Within 30 days                 2  10 reports................              20
                                of discovery and
                                identification of
                                SPPE failure,
                                provide a written
                                report of equipment
                                failure to
                                manufacturer.
----------------------------------------------------------------------------------------------------------------
803(b).......................  NEW: Document and                   5  10 documents..............              50
                                determine the
                                results of the SPPE
                                failure within 60-
                                days and corrective
                                action taken.
----------------------------------------------------------------------------------------------------------------
803(c).......................  NEW: Submit [OORP]                  2  1 submittal...............               2
                                modified procedures
                                you made if notified
                                by manufacturer of
                                design changes or
                                you changed
                                operating or repair
                                procedures as result
                                of a failure, within
                                30 days.
----------------------------------------------------------------------------------------------------------------
804..........................  Submit detailed info   Burdens are covered under 30 CFR Part 250,               0
                                regarding installing  Subparts D and B, 1014-0018 and 1014-0024.
                                SSVs in an HPHT
                                environment with
                                your APD, APM, DWOP
                                etc.
----------------------------------------------------------------------------------------------------------------
804(b); 829(b), (c); 841(b)..  NEW: District Manager   Not considered IC per 5 CFR 1320.3(h)(6).               0
                                will approve on a
                                case-by-case basis.
----------------------------------------------------------------------------------------------------------------
    Subtotal.................  .....................  ..............  128 responses.............             210
----------------------------------------------------------------------------------------------------------------
                                Surface and Subsurface Safety Systems--Dry Trees
----------------------------------------------------------------------------------------------------------------
810; 816; 825(a); 830........  Submit request for a           5\3/4\  41 wells..................             246
                                determination that a
                                well is incapable of
                                natural flow.
                              ---------------------------------------
                               Verify the no-flow              \1/4\
                                condition of the
                                well annually.
----------------------------------------------------------------------------------------------------------------
814(a); 821; 828(a);           Specific alternate        Burden covered under 30 CFR part 250,                 0
 838(c)(3); 859(b); 870(b).     approval requests                subpart A, 1014-0022.
                                requiring approval.
----------------------------------------------------------------------------------------------------------------
817(b); 869(a)...............  Identify well with        Usual/customary safety procedure for                  0
                                sign on wellhead        removing or identifying out-of-service
                                that subsurface                     safety devices.
                                safety device is
                                removed; flag safety
                                devices that are out
                                of service; a visual
                                indicator must be
                                used to identify the
                                bypassed safety
                                device.
----------------------------------------------------------------------------------------------------------------
817(b).......................  Record removal of       Burden included in Sec.   250.890 of this               0
                                subsurface safety                      subpart.
                                device.
----------------------------------------------------------------------------------------------------------------
817(c).......................  Request alternate         Burden covered under 30 CFR part 250,                 0
                                approval of master               subpart D, 1014-0018.
                                valve [required to
                                be submitted with an
                                APM].
----------------------------------------------------------------------------------------------------------------
    Subtotal.................  .....................  ..............  41 responses..............             246
----------------------------------------------------------------------------------------------------------------
                               Subsea and Subsurface Safety Systems--Subsea Trees
----------------------------------------------------------------------------------------------------------------
                                                                     Notifications
                                                     --------------------------------------------
825(b); 831; 833; 837(c)(5);   NEW: Notify BSEE: (1)       (1) \1/2\  6.........................               7
 838(c); 874(g)(2); 874(f).     If you cannot test             (2) 2  1.........................
                                all valves and                 (3) 1  1.........................
                                sensors; (2) 48            (4) \1/2\  1.........................
                                hours in advance if        (5) \1/2\  1.........................
                                monitoring ability
                                affected; (3)
                                designating USV2 or
                                another qualified
                                valve; (4) resuming
                                production; (5) 12
                                hours of detecting
                                loss of
                                communication;
                                immediately if you
                                cannot meet value
                                closure conditions.
----------------------------------------------------------------------------------------------------------------
827..........................  NEW: Request remote                 1  1 request.................               1
                                location approval.
----------------------------------------------------------------------------------------------------------------

[[Page 52258]]

 
831..........................  NEW: Submit a repair/               2  1 submittal...............               2
                                replacement plan to
                                monitor and test.
----------------------------------------------------------------------------------------------------------------
837(a).......................  NEW: Request approval           \1/2\  10 requests...............               5
                                to not shut-in a
                                subsea well in an
                                emergency.
----------------------------------------------------------------------------------------------------------------
837(b).......................  NEW: Prepare and                    2  1 submittal...............               2
                                submit for approval
                                a plan to shut-in
                                wells affected by a
                                dropped object.
----------------------------------------------------------------------------------------------------------------
837(c)(2)....................  NEW: Obtain approval            \1/2\  2 approvals...............               1
                                to resume production
                                re P/L PSHL sensor.
----------------------------------------------------------------------------------------------------------------
838(a); 839(a)(2)............  NEW: Verify closure                 2  2 verifications...........               4
                                time of USV upon
                                request of District
                                Manager.
----------------------------------------------------------------------------------------------------------------
838(c)(3)....................  NEW: Request approval               2  1 approval................               2
                                to produce after
                                loss of
                                communication;
                                include alternate
                                valve closure table.
----------------------------------------------------------------------------------------------------------------
    Subtotal.................  .....................  ..............  28 responses..............              24
----------------------------------------------------------------------------------------------------------------
                                            Production Safety Systems
----------------------------------------------------------------------------------------------------------------
842..........................  Submit application,                16  1 application.............              16
                                and all required/
                                supporting
                                information, for a
                                production safety
                                system with > 125
                                components.
                                                     -----------------------------------------------------------
                                                                  $5,030 per submission x 1 = $5,030
                                                               $13,238 per offshore visit x 1 = $13,238
                                                                $6,884 per shipyard visit x 1 = $6,884
                              ----------------------------------------------------------------------------------
                               25-125 components....              13  10 applications...........             130
                                                     -----------------------------------------------------------
                                                                 $1,218 per submission x 10 = $12,180
                                                                $8,313 per offshore visit x 1 = $8,313
                                                                $4,766 per shipyard visit x 1 = $4,766
                              ----------------------------------------------------------------------------------
                                125
                                components.
                                                     -----------------------------------------------------------
                                                                 $561 per submission x 180 = $100,980
                              ----------------------------------------------------------------------------------
                               25-125 components....               7  758 modifications.........           5,306
                                                     -----------------------------------------------------------
                                                                 $201 per submission x 758 = $152,358
                              ----------------------------------------------------------------------------------
                               2\
                                within 60-days after
                                production that the
                                as-built diagrams,
                                piping, and
                                instrumentation
                                diagrams are on
                                file, certified
                                correct, and stamped
                                by a registered
                                professional
                                engineer; submit all
                                the as-built
                                diagrams.
                              ----------------------------------------------------------------------------------

[[Page 52259]]

 
842(f).......................  NEW: Maintain records           \1/2\  32 records................              16
                                pertaining to
                                approved design and
                                installation
                                features and as-
                                built pipe and
                                instrumentation
                                diagrams at your
                                offshore field
                                office or location
                                available to the
                                District Manager;
                                make available to
                                BSEE upon request
                                and retained for the
                                life of the facility.
----------------------------------------------------------------------------------------------------------------
    Subtotal.................  .....................  ..............  1,426 responses...........           9,485
                                                                     -------------------------------------------
                                                                            $343,794 non-hour cost burdens
----------------------------------------------------------------------------------------------------------------
                                    Additional Production System Requirements
----------------------------------------------------------------------------------------------------------------
851(a)(4)....................  NEW: Request approval               2  1 request.................               2
                                to use uncoded
                                pressure and fired
                                vessels beyond their
                                18 months of
                                continued use.
----------------------------------------------------------------------------------------------------------------
851(b); 852(a)(3); 858(c);     Maintain [most                     23  615 records...............          14,145
 865(b).                        current] pressure-
                                recorder information
                                at location
                                available to the
                                District Manager for
                                as long as
                                information is valid.
----------------------------------------------------------------------------------------------------------------
851(c)(2)....................  NEW: Request approval               1  10 requests...............              10
                                from District
                                Manager for
                                activation limits
                                set less than 5 psi.
----------------------------------------------------------------------------------------------------------------
852(c)(1)....................  NEW: Request approval               1  10 requests...............              10
                                from District
                                Manager to vent to
                                some other location.
----------------------------------------------------------------------------------------------------------------
852(c)(2)....................  NEW: Request a                      1  1 request.................               5
                                different sized PSV.
----------------------------------------------------------------------------------------------------------------
852(c)(2)....................  NEW: Request                        1  5 request.................               5
                                different upstream
                                location of the PSV..
----------------------------------------------------------------------------------------------------------------
852(e).......................  Submit required           Burden is covered by the application                  0
                                design documentation        requirement in Sec.   250.842.
                                for unbonded
                                flexible pipe.
----------------------------------------------------------------------------------------------------------------
855(b).......................  Maintain ESD                       15  615 listings..............           9,225
                                schematic listing
                                control function of
                                all safety devices
                                at location
                                conveniently
                                available to the
                                District Manager for
                                the life of the
                                facility.
----------------------------------------------------------------------------------------------------------------
858(b).......................  NEW: Request approval               1  1 request.................               1
                                from District
                                Manager to use
                                different procedure
                                for gas-well gas
                                affected.
----------------------------------------------------------------------------------------------------------------
859(a)(2)....................  Request approval for      Burden covered under 30 CFR part 250,                 0
                                alternate                        subpart A, 1014-0022.
                                firefighting system.
----------------------------------------------------------------------------------------------------------------
859(a)(3), (4)...............  Post diagram of                     5  38 postings...............             190
                                firefighting system;
                                furnish evidence
                                firefighting system
                                suitable for
                                operations in
                                subfreezing climates.
----------------------------------------------------------------------------------------------------------------
859(b).......................  NEW: Request              Burden covered under 30 CFR part 250,                 0
                                extension from                   subpart A, 1014-0022.
                                District Manager up
                                to 7 days of your
                                approved departure
                                to use chemicals.
----------------------------------------------------------------------------------------------------------------
860(a); related NTL(s).......  Request approval,                  22  31 requests...............             682
                                including but not
                                limited to,
                                submittal of
                                justification and
                                risk assessment, to
                                use chemical only
                                fire prevention and
                                control system in
                                lieu of a water
                                system.
----------------------------------------------------------------------------------------------------------------
860(b).......................  NEW: Minor change(s)            \1/2\  10 minor changes..........               5
                                made after approval
                                rec'd re 860(a)--
                                document change;
                                maintain the revised
                                version at facility
                                or closest field
                                office for BSEE
                                review/inspection;
                                maintain for life of
                                facility.
----------------------------------------------------------------------------------------------------------------
860(b).......................  NEW: Major change(s)                2  1 major change............               2
                                made after approval
                                rec'd re 860(a)--
                                submit new request w/
                                updated risk
                                assessment to
                                District Manager for
                                approval; maintain
                                at facility or
                                closest field office
                                for BSEE review/
                                inspection; maintain
                                for life of facility.
----------------------------------------------------------------------------------------------------------------
861(b).......................  NEW: Submit foam                    2  500 submittals............           1,000
                                concentrate samples
                                annually to
                                manufacturer for
                                testing.
----------------------------------------------------------------------------------------------------------------
864..........................  Maintain erosion                   12  615 records...............           7,380
                                control program
                                records for 2 years;
                                make available to
                                BSEE upon request.
----------------------------------------------------------------------------------------------------------------

[[Page 52260]]

 
867(a).......................  NEW: Request approval               6  1 request.................               6
                                from District
                                Manager to install
                                temporary quarters.
----------------------------------------------------------------------------------------------------------------
867(b).......................  NEW: Submit                         1  1 request.................               1
                                supporting
                                information/
                                documentation if
                                required by District
                                Manager to install a
                                temporary firewater
                                system.
----------------------------------------------------------------------------------------------------------------
867(c).......................  NEW: Request approval               1  300 requests..............             300
                                form District
                                manager to use
                                temporary equipment
                                for well testing/
                                clean-up.
----------------------------------------------------------------------------------------------------------------
869(a)(3)....................  NEW: Request approval               1  2 requests................               2
                                from District
                                Manager to bypass an
                                element of ESS.
----------------------------------------------------------------------------------------------------------------
870..........................  NEW: Document PSL on            \1/2\  6 records.................               3
                                your field test
                                records w/delay
                                greater than 45
                                seconds.
----------------------------------------------------------------------------------------------------------------
871..........................  Request variance from     Burden covered under 30 CFR part 250,                 0
                                District Manager on              subpart A--1014-0022.
                                approved welding and
                                burning practices.
----------------------------------------------------------------------------------------------------------------
874(g)(2), (3)...............  NEW: Submit request                 2  5 requests................              10
                                to District Manager
                                with alternative
                                plan ensuring subsea
                                shutdown capability.
----------------------------------------------------------------------------------------------------------------
874(g)(3)....................  NEW: Request approval               1  10 requests...............              10
                                from District
                                Manager to forgo
                                WISDV testing.
----------------------------------------------------------------------------------------------------------------
874(f)(2)....................  NEW: Request approval               1  5 requests................               5
                                from District
                                Manager to continue
                                to inject w/loss of
                                communication.
----------------------------------------------------------------------------------------------------------------
874(f)(2)....................  NEW: Request              Burden covered under 30 CFR part 250,                 0
                                alternate hydraulic              subpart A, 1014-0022.
                                bleed schedule.
----------------------------------------------------------------------------------------------------------------
    Subtotal.................  .....................  ..............  2,783 responses...........          32,999
----------------------------------------------------------------------------------------------------------------
                                              Safety Device Testing
----------------------------------------------------------------------------------------------------------------
880(a)(3)....................  NEW: Notify BSEE and      Burden covered under 30 CFR part 250,                 0
                                receive approval                 subpart A 1014-0022.
                                before performing
                                modifications to
                                existing subsea
                                infrastructure.
----------------------------------------------------------------------------------------------------------------
880(c)(5)(vi)................  NEW: Request approval               1  1 request.................               1
                                for disconnected
                                well shut-in to
                                exceed more than 2
                                years.
----------------------------------------------------------------------------------------------------------------
    Subtotal.................  .....................  ..............  1 response................               1
----------------------------------------------------------------------------------------------------------------
                                              Records and Training
----------------------------------------------------------------------------------------------------------------
890..........................  Maintain records for               36  615 records...............          22,140
                                2 years on
                                subsurface and
                                surface safety
                                devices to include,
                                but limited to,
                                status and history
                                of each device;
                                approved design &
                                installation date
                                and features,
                                inspection, testing,
                                repair, removal,
                                adjustments,
                                reinstallation,
                                etc.; at field
                                office nearest
                                facility AND a
                                secure onshore
                                location; make
                                records available to
                                BSEE.
----------------------------------------------------------------------------------------------------------------
890(c).......................  NEW: Submit annually            \1/2\  1,000 annual lists........             550
                                to District Manager            \1/2\  100 revised lists.........
                                a contact list for
                                all OCS operated
                                platforms or submit
                                when revised.
                                                     -----------------------------------------------------------
    Subtotal.................                                         1,715 responses...........          22,690
----------------------------------------------------------------------------------------------------------------
    Total Burden Hours.......  .....................  ..............  6,124 Responses...........          65,665
                                                                     -------------------------------------------
                                                                            $343,794 Non-Hour Cost Burdens
----------------------------------------------------------------------------------------------------------------

    The BSEE specifically solicits comments on the following:
    (1) Is the IC necessary or useful for us to perform properly; (2) 
is the proposed burden accurate; (3) are there suggestions that will 
enhance the quality, usefulness, and clarity of the information to be 
collected; and (4) can we minimize the burden on the respondents, 
including the use of technology.
    In addition, the PRA requires agencies to also estimate the non-
hour paperwork cost burdens to respondents or recordkeepers resulting 
from the collection of information. Therefore, if you have other than 
hour burden costs to generate, maintain, and disclose this information, 
you should comment and provide your total capital and startup cost 
components or annual operation,

[[Page 52261]]

maintenance, and purchase of service components. Generally, your 
estimate should not include burdens other than those associated with 
the provision of information to, or recordkeeping for the government; 
or burdens that are part of customary and usual business or private 
practices. For further information on this non-hour burden estimation 
process, refer to 5 CFR 1320.3(b)(1) and (2), or contact the BSEE 
Bureau Information Collection Clearance Officer.

National Environmental Policy Act of 1969

    We prepared an environmental assessment to determine whether this 
proposed rule would have a significant impact on the quality of the 
human environment under the National Environmental Policy Act of 1969. 
This proposed rule does not constitute a major Federal action 
significantly affecting the quality of the human environment. A 
detailed statement under the National Environmental Policy Act of 1969 
is not required because we reached a Finding of No Significant Impact 
(FONSI). A copy of the FONSI and Environmental Assessment 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 (Executive Order 13211)

    This proposed rule is not a significant energy action under the 
definition in E.O. 13211. A Statement of Energy Effects is not 
required.

Clarity of This Regulation (Executive Order 12866)

    We are required by E.O. 12866, E.O. 12988, and by the Presidential 
Memorandum of June 1, 1998, to write all rules in plain language. This 
means that each rule we publish must:
    (a) Be logically organized;
    (b) use the active voice to address readers directly;
    (c) use clear language rather than jargon;
    (d) be divided into short sections and sentences; and
    (e) use lists and tables wherever possible.
    If you feel that we have not met these requirements, send us 
comments by one of the methods listed in the ADDRESSES section. To 
better help us revise the rule, your comments should be as specific as 
possible. For example, you should tell us the numbers of the sections 
or paragraphs that you find unclear, which sections or sentences are 
too long, the sections where you feel lists or tables would be useful, 
etc.

Public Availability of Comments

    Before including your address, phone number, email address, or 
other personal identifying information in your comment, you should be 
aware that your entire comment--including your personal identifying 
information--may be made publicly available at any time. While you can 
ask us in your comment to withhold your personal identifying 
information from public review, we cannot guarantee that we will be 
able to do so.

List of Subjects in 30 CFR Part 250

    Administrative practice and procedure, Continental shelf, 
Environmental impact statements, Environmental protection, Government 
contracts, Incorporation by reference, Investigations, Oil and gas 
exploration, Penalties, Pipelines, Public lands--mineral resources, 
Public lands--rights-of-way, Reporting and recordkeeping requirements, 
Sulphur.

    Dated: August 6, 2013.
Tommy Beaudreau,
Acting Assistant Secretary--Land and Minerals Management.

    For the reasons stated in the preamble, the Bureau of Safety and 
Environmental Enforcement (BSEE) proposes to amend 30 CFR Part 250 as 
follows:

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

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

    Authority:  30 U.S.C. 1751; 31 U.S.C. 9701; 43 U.S.C. 1334.
0
2. Amend Sec.  250.107 by revising paragraph (c) and removing paragraph 
(d) to read as follows:

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

* * * * *
    (c)(1) Wherever failure of equipment may have a significant effect 
on safety, health, or the environment, you must use the best available 
and safest technology (BAST) that BSEE determines to be economically 
feasible on:
    (i) All new drilling and production operations and
    (ii) Wherever practicable, on existing operations.
    (2) You may request an exception by demonstrating to BSEE that the 
incremental benefits of using BAST are clearly insufficient to justify 
the incremental costs of utilizing such technologies.
0
3. Revise Sec.  250.125(a)(10), (11), (12), (13), (14), and (15) to 
read as follows:

Sec.  250.125  Service fees.

    (a) * * *

----------------------------------------------------------------------------------------------------------------
                                                                                                      30 CFR
     Service--processing of the following:                         Fee amount                        citation
----------------------------------------------------------------------------------------------------------------
 
                                                  * * * * * * *
(10) New Facility Production Safety System      $5,030 A component is a piece of equipment or     Sec.   250.842
 Application for facility with more than 125     ancillary system that is protected by one or
 components.                                     more of the safety devices required by API RP
                                                 14C (as incorporated by reference in Sec.
                                                 250.198); $13,238 additional fee will be
                                                 charged if BSEE deems it necessary to visit a
                                                 facility offshore, and $6,884 to visit a
                                                 facility in a shipyard.
(11) New Facility Production Safety System      $1,218 Additional fee of $8,313 will be charged   Sec.   250.842
 Application for facility with 25-125            if BSEE deems it necessary to visit a facility
 components.                                     offshore, and $4,766 to visit a facility in a
                                                 shipyard.
(12) New Facility Production Safety System      $604............................................  Sec.   250.842
 Application for facility with fewer than 25
 components.
(13) Production Safety System Application--     $561............................................  Sec.   250.842
 Modification with more than 125 components
 reviewed.

[[Page 52262]]

 
(14) Production Safety System Application--     $201............................................  Sec.   250.842
 Modification with 25-125 components reviewed.
(15) Production Safety System Application--     $85.............................................  Sec.   250.842
 Modification with fewer than 25 components
 reviewed..
 
                                                  * * * * * * *
----------------------------------------------------------------------------------------------------------------

0
4. Amend Sec.  250.198 as follows:
0
a. Remove paragraphs (g)(6) and (g)(7);
0
b. Redesignate paragraph (g)(8) as (g)(6);
0
c. Revise paragraphs (g)(1) through (g)(3), (h)(1), (h)(51) through 
(h)(53), (h)(55) through (h)(62), (h)(65), (h)(66), (h)(68), (h)(70), 
(h)(71), (h)(73), and (h)(74); and
0
d. Add new paragraph (h)(89) to read as follows:

Sec.  250.198  Documents incorporated by reference.

* * * * *
    (g) * * *
    (1) ANSI/ASME Boiler and Pressure Vessel Code, Section I, Rules for 
Construction of Power Boilers; including Appendices, 2004 Edition; and 
July 1, 2005 Addenda, and all Section I Interpretations Volume 55, 
incorporated by reference at Sec. Sec.  250.851(a)(1)(i), (a)(4)(iii), 
(a)(5)(i), and 250.1629(b)(1), (b)(1)(i).
    (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)(1)(i), (a)(4)(iii), 
(a)(5)(i), and 250.1629(b)(1), (b)(1)(i).
    (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)(1)(i), (a)(4)(iii), (a)(5)(i), and 
250.1629(b)(1), (b)(1)(i).
* * * * *
    (h) * * *
    (1) API 510, Pressure Vessel Inspection Code: In-Service 
Inspection, Rating, Repair, and Alteration, Downstream Segment, Ninth 
Edition, June 2006, Product No. C51009; incorporated by reference at 
Sec. Sec.  250.851(a)(1)(ii) and 250.1629(b)(1);
* * * * *
    (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; 
Order No. G02RD1; incorporated by reference at Sec. Sec.  
250.800(c)(2), 250.901(a), (d), and 250.1002(b)(5);
    (52) API RP 2SK, Recommended Practice for Design and Analysis of 
Stationkeeping Systems for Floating Structures, Third Edition, October 
2005, Addendum, May 2008, Product No. G2SK03; incorporated by reference 
at Sec. Sec.  250.800(c)(3) 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)(3) and 250.901;
* * * * *
    (55) API RP 14B, Recommended Practice for Design, Installation, 
Repair and Operation of Subsurface Safety Valve Systems, ANSI/API 
Recommended Practice 14B, Fifth Edition, October 2005, also available 
as ISO 10417: 2004, (Identical) Petroleum and natural gas industries--
Subsurface safety valve systems--Design, installation, operation and 
redress, Product No. GX14B05; incorporated by reference at Sec. Sec.  
250.802(b), 250.803(a), 250.814(d), 250.828(c), and 250.880(c)(1)(i), 
(c)(4)(i), (c)(5)(ii)(A);
    (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; Product No. C14C07; incorporated by reference at Sec. Sec.  
250.125(a)(10), 250.292(j), 250.841(a), 250.842(a)(2), 250.850, 
250.852(a)(1), 250.855, 250.858(a), 250.862(e), 250.867(a), 
250.869(a)(3), (b), (c), 250.872(a), 250.873(a), 250.874(a), 
250.880(b)(2), (c)(2)(v), 250.1002(d), 250.1004(b)(9), 250.1628(c), 
(d)(2), 250.1629(b)(2), (b)(4)(v), 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, March 2007, Order No. 811-07185; incorporated by 
reference at Sec. Sec.  250.841(b), 250.842(a)(1), and 250.1628(b)(2), 
(d)(3);
    (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, 
Product No. G14F05; incorporated by reference Sec. Sec.  250.114(c), 
250.842(b)(1), 250.862(e), and 250.1629(b)(4)(v);
    (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; 
Product No. G14FZ1; incorporated by reference at Sec. Sec.  250.114(c), 
250.842(b)(1), 250.862(e), and 250.1629(b)(4)(v);
    (60) API RP 14G, Recommended Practice for Fire Prevention and 
Control on Fixed Open-type Offshore Production Platforms, Fourth 
Edition, April 2007; Product No. G14G04; incorporated by reference at 
Sec. Sec.  250.859(a), 250.862(e), and 250.1629(b)(3), (b)(4)(v);
    (61) API RP 14H, Recommended Practice for Installation, Maintenance 
and Repair of Surface Safety Valves and Underwater Safety Valves 
Offshore, Fifth Edition, August 2007, Product No. G14H05; incorporated 
by reference at Sec. Sec.  250.820, 250.834, 250.836, and 
250.880(c)(2)(iv), (c)(4)(iii);
    (62) API RP 14J, Recommended Practice for Design and Hazards 
Analysis for Offshore Production Facilities, Second Edition, May 2001; 
Reaffirmed: March 2007; Product No. G14J02; incorporated by reference 
at Sec. Sec.  250.800(b), (c)(1), 250.842(b)(3), and 250.901(a)(14);
* * * * *
    (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,

[[Page 52263]]

Reaffirmed November 2002, API Stock No. C50002; incorporated by 
reference at Sec. Sec.  250.114(a), 250.459, 250.842(a)(1), (a)(3)(i), 
250.862(a), (e), 250.872(a), 250.1628(b)(3), (d)(4)(i), and 
250.1629(b)(4)(i);
    (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; Errata August 17, 1998, American National Standards 
Institute, ANSI/API RP 505-1998, Approved: January 7, 1998, Order No. 
C50501; incorporated by reference at Sec. Sec.  250.114(a), 250.459, 
250.842(a)(1), (a)(3)(i), 250.862(a), (e), 250.872(a), 250.1628(b)(3), 
(d)(4)(i), and 250.1629(b)(4)(i);
* * * * *
    (68) ANSI/API Spec. Q1, Specification for Quality Programs for the 
Petroleum, Petrochemical and Natural Gas Industry, Eighth Edition, 
December 2007, Effective Date: June 15, 2008, Addendum 1, June 2010, 
Effective Date: December 1, 2010; also available as ISO TS 29001:2007 
(Identical), Petroleum, petrochemical and natural gas industries--
Sector specific requirements--Requirements for product and service 
supply organizations, Effective Date: December 15, 2003, API Stock No. 
GQ1007; incorporated by reference at Sec.  250.801(b), (c);
* * * * *
    (70) API Spec. 6A, Specification for Wellhead and Christmas Tree 
Equipment, Nineteenth Edition, July 2004, Effective Date: February 1, 
2005; Contains API Monogram Annex as part of US National Adoption; also 
available as ISO 10423:2003 (Modified), Petroleum and natural gas 
industries--Drilling and production equipment--Wellhead and Christmas 
tree equipment; Errata 1, September 2004, Errata 2, April 2005, Errata 
3, June 2006, Errata 4, August 2007, Errata 5, May 2009, Addendum 1, 
February 2008, Addendum 2, December 2008, Addendum 3, December 2008, 
Addendum 4, December 2008, Product No. GX06A19; incorporated by 
reference at Sec. Sec.  250.802(a), 250.803(a), 250.873(b), 
(b)(3)(iii), 250.874(g)(2) and 250.1002 (b)(1), (b)(2);
    (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 January 
2003, API Stock No. G06AV1; incorporated by reference at Sec. Sec.  
250.802(a), 250.833, 250.873(b) and 250.874(g)(2);
* * * * *
    (73) ANSI/API Spec. 14A, Specification for Subsurface Safety Valve 
Equipment, Eleventh Edition, October 2005, Effective Date: May 1, 2006; 
also available as ISO 10432:2004 (Identical), Petroleum and natural gas 
industries--Downhole equipment--Subsurface safety valve equipment, 
Product No. GX14A11; 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, Effective Date: January 1, 2009, Contains API 
Monogram Annex as part of US National Adoption; also available as ISO 
13628-2:2006 (Identical), Petroleum and natural gas industries--Design 
and operation of subsea production systems--Part 2: Unbonded flexible 
pipe systems for subsea and marine application; Product No. GX17J03; 
incorporated by reference at Sec. Sec.  250.852(e)(1), (e)(4), 
250.1002(b)(4), and 250.1007(a)(4)(i)(D).
* * * * *
    (89) API 570 Piping Inspection Code: In-service Inspection, Rating, 
Repair, and Alteration of Piping Systems, Third Edition, November 2009; 
Product No. C57003; incorporated by reference at Sec.  250.841(b).
0
5. Revise Sec.  250.517(e) to read as follows:

Sec.  250.  517 Tubing and wellhead equipment.

* * * * *
    (e) Subsurface safety equipment must be installed, maintained, and 
tested in compliance with the applicable sections in Sec. Sec.  250.810 
through 250.839 of this part.
0
6. Revise Sec.  250.618(e) to read as follows:

Sec.  250.618  Tubing and wellhead equipment.

* * * * *
    (e) Subsurface safety equipment must be installed, maintained, and 
tested in compliance with the applicable sections in Sec. Sec.  250.810 
through 250.839 of this part.
0
7. 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 subsurface safety valves (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.
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 shut down valves (BSDVs) 
associated with subsea systems.
250.836 Use of BSDVs.
250.837 Emergency action and safety system shutdown.
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 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]

[[Page 52264]]

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 system.
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.
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]

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, Recommended Practice for Design and Hazards 
Analysis for Offshore Production Facilities (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); spars, etc.), you 
must:
    (1) Comply with API RP 14J;
    (2) Meet the drilling, well completion, well workover, and well 
production riser standards of API RP 2RD, Recommended Practice for 
Design of Risers for Floating Production Systems (FPSs) and Tension-Leg 
Platforms (TLPs) (incorporated by reference as specified in Sec.  
250.198). Beginning 1 year from the publication date of the final rule 
and thereafter, you are prohibited from installing single bore 
production risers from floating production facilities.
    (3) Design all stationkeeping systems for floating production 
facilities to meet the standards of API RP 2SK, Design and Analysis of 
Stationkeeping Systems for Floating Structures and API RP 2SM, Design, 
Manufacture, Installation, and Maintenance of Synthetic Fiber Ropes for 
Offshore Mooring (both incorporated by reference as specified in Sec.  
250.198), as well as relevant U.S. Coast Guard regulations; and
    (4) Design stationkeeping systems for floating facilities to meet 
the structural requirements of Sec. Sec.  250.900 through 250.921.

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. The 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 shut down valves (BSDV), 1 year after the date of 
publication of the final rule;
    (3) Underwater safety valves (USV) and actuators; and
    (4) Subsurface safety valves (SSSV) and associated safety valve 
locks and landing nipples. Subsurface-controlled SSSVs are not allowed 
on subsea wells.
    (b) Certification of SPPE. SPPE equipment that is manufactured and 
marked pursuant to API Spec. Q1, Specification for Quality Programs for 
the Petroleum, Petrochemical and Natural Gas Industry (ISO TS 
29001:2007) (incorporated by reference as specified in Sec.  250.198), 
is considered certified SPPE under this part. The BSEE considers all 
other SPPE as noncertified unless approved in accordance with 
250.801(c).
    (c) Accepting SPPE manufactured under other quality assurance 
programs. The BSEE may exercise its discretion to accept SPPE 
manufactured under quality assurance programs other than API Spec. Q1 
(ISO TS 29001:2007), provided an operator submits a request to BSEE 
containing relevant information about the alternative program under 
Sec.  250.141, and receives BSEE approval. Such requests should be 
submitted to the Chief, Office of Offshore Regulatory Programs; Bureau 
of Safety and Environmental Enforcement; HE 3314; 381 Elden Street; 
Herndon, Virginia 20170-4817.

Sec.  250.802  Requirements for SPPE.

    (a) All SSVs, BSDVs, and USVs must meet all of the specifications 
contained in API/ANSI Spec. 6A, Specification for Wellhead and 
Christmas Tree Equipment, (ISO 10423:2003); and Spec. 6AV1, 
Specification for Verification Test of Wellhead Surface Safety Valves 
and Underwater Safety Valves for Offshore Service (both incorporated by 
reference as specified in Sec.  250.198).
    (b) All SSSVs must meet all of the specifications and recommended 
practices of API/ANSI Spec. 14A, Specification for Subsurface Safety 
Valve Equipment (ISO 10432:2004) and ANSI/API RP 14B, Recommended 
Practice for Design, Installation, and Operation of Subsurface Safety 
Valve Systems (ISO 10417:2004), including all Annexes (both 
incorporated by reference as specified in Sec.  250.198).
    (c) Requirements derived from the documents incorporated in this 
section for SSVs, BSDVs, USVs, and SSSVs, include, but are not limited 
to, the following:
    (1) Each device must be designed to function and to close at 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.

[[Page 52265]]

    (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 certified SPPE according to the following 
table.

------------------------------------------------------------------------
                If . . .                            Then . . .
------------------------------------------------------------------------
(1) You need to install any SPPE.......  You must install certified
                                          SPPE.
(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
 offsite repair, re-manufacturing, or     certified SPPE.
 any hot work such as welding.
------------------------------------------------------------------------

    (e) You must retain all documentation related to the manufacture, 
installation, testing, repair, redress, and performance of the SPPE 
equipment 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 
report of equipment failure 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.
    (b) You must ensure that an investigation and a failure analysis 
are performed within 60 days of the failure to determine the cause of 
the failure. You must also ensure that the results and any corrective 
action are documented. If the investigation and analysis are performed 
by an entity other than the manufacturer, you must ensure that the 
manufacturer receives a copy of 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 of Office of Offshore Regulatory 
Programs; Bureau of Safety and Environmental Enforcement; HE 3314; 381 
Elden Street; Herndon, Virginia 20170-4817.

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), Application for Permit to Modify (APM), or 
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 analysis;
    (2) A discussion of the SSSVs' and related equipment's design 
validation and functional testing process and procedures used; and
    (3) An explanation of why the analysis, process, 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 
psig 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 psig 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) You must conduct production operations in zones known to 
contain hydrogen sulfide (H2S) or in zones where the 
presence of H2S is unknown, as defined in Sec.  250.490 of 
this part, in accordance with that section and other relevant 
requirements of this subpart.
    (b) You must receive approval through the DWOP process (Sec. Sec.  
250.286-250.295) 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. These subsurface 
safety devices include the following devices and any associated safety 
valve lock, flow coupling above and below, 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 subsurface safety valves (SSSVs)--dry 
trees.

    All surface-controlled and subsurface-controlled SSSVs, safety 
valve locks, landing nipples, and flow couplings installed in the OCS 
must conform to the requirements in Sec. Sec.  250.801 through 250.803. 
You may request that BSEE approve non-conforming SSSVs in accordance 
with Sec.  250.141, regarding alternative procedures or equipment.

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 that BSEE approve situating 
the surface controls at a remote location in

[[Page 52266]]

accordance with Sec.  250.141, regarding alternative procedures or 
equipment.
    (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 request BSEE approval to equip a dry tree well with a 
subsurface-controlled SSSV in lieu of a surface-controlled SSSV, in 
accordance with Sec.  250.141 regarding alternative procedures or 
equipment, if the subsurface-controlled SSSV installed in a well 
equipped with a surface-controlled SSSV 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, operate, repair, and maintain 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 in accordance with Sec.  250.141 or 
Sec.  250.142.
    (b) 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.
    (c) The well must not be open to flow while the SSSV is removed, 
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.
    (d) You must install, maintain, inspect, repair, and test all SSSVs 
in accordance with API RP 14B, Recommended Practice for Design, 
Installation, and Operation of Subsurface Safety Valve Systems (ISO 
10417:2004) (incorporated by reference as specified in Sec.  250.198).

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 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 will 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) 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 with a support vessel 
or a pump-through plug 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, Recommended Practice for Installation, 
Maintenance and Repair of Surface Safety Valves and Underwater Safety 
Valves Offshore (incorporated by reference as specified in Sec.  
250.198). If any SSV does not operate properly, or if any fluid flow is 
observed during the leakage test, then you must shut-in all sources to 
the SSV and repair or replace the valve before resuming production.

Sec.  250.821  Emergency action.

    (a) In the event of an emergency, such as an impending 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 all oil wells and gas wells requiring 
compression, unless otherwise approved by the District Manager in 
accordance with Sec. Sec.  250.141 or 250.142. The shut-in may be 
accomplished by closing the SSV and SSSV.
    (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

[[Page 52267]]

minutes after the shut-in signal has closed the SSV. The District 
Manager must approve any design-delayed closure time greater than 2 
minutes based on the mechanical/production characteristics of the 
individual well or subsea field in accordance with Sec. Sec.  250.141 
or 250.142.

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 unless. You may 
seek BSEE approval for using alternative procedures or equipment in 
accordance with Sec.  250.141 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, for instance where the well at issue is 
incapable of natural flow. Subsurface safety devices include the 
following and any associated safety valve lock, flow coupling above and 
below, 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. If you cannot perform these 
tests, you may seek BSEE approval for a departure from this operating 
requirement under Sec.  250.142

Sec.  250.826  Specifications for SSSVs--subsea trees.

    All SSSVs, safety valve locks, flow couplings, and landing nipples 
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.

    All tubing installations open to a hydrocarbon-bearing zone that is 
capable of natural flow must be equipped with a surface-controlled 
SSSV, except as specified in Sec. Sec.  250.829 and 250.830. The 
surface controls must be located on the site, or you may seek BSEE 
approval for locating the controls at a remote location in a request to 
use alternative procedures or equipment under Sec.  250.141.

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

    You must design, install, operate, and maintain 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, hydrate formation, or paraffin problems, you may seek BSEE 
approval for an alternate setting depth in a request to use alternative 
procedures or equipment under Sec.  250.141.
    (b) The well must not be open to flow while an SSSV is inoperable.
    (c) You must install, maintain, inspect, repair, and test all SSSVs 
in accordance with your Deepwater Operations Plan (DWOP) and API RP 
14B, Recommended Practice for Design, Installation, Repair and 
Operation of Subsurface Safety Valve Systems (ISO 10417:2004) 
(incorporated by reference as specified in Sec.  250.198).

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

    (a) You must equip new completions (perforated but not placed on 
production) and completions shut-in for a period of 6 months with 
either:
    (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 or if your 
controls employ an electro-hydraulic control umbilical and the 
hydraulic control pressure to the individual well cannot be isolated, 
and 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) The appropriate BSEE District Manager may consider alternate 
methods on a case-by-case basis.
    (c) When warranted by conditions such as unstable bottom 
conditions, hydrate formations, and paraffin problems, you may seek 
BSEE approval to use an alternate setting depth of the subsurface 
safety device for shut-in wells in a request to use alternative 
procedures or equipment under 250.141.

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 affects your ability to monitor casing 
pressure or to test any subsea valves or equipment, you must contact 
the appropriate BSEE 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 pumpdown-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 SSSV.
    (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. 6AV1 (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.
    (b) Secondary USV (USV2). You may equip your tree with two or more 
valves

[[Page 52268]]

qualified to be designated as a USV, one of which may be designated as 
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 
BSEE 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. This valve must be located upstream of the choke to be 
designated as a USV.

Sec.  250.834  Use of USVs.

    You must install, maintain, inspect, repair, and test all USVs, 
including those designated as primary or secondary, and any AIV which 
acts as a USV if applicable in accordance with this subpart, your DWOP 
as specified in Sec. Sec.  250.286 through 250.295, and API RP 14H, 
Recommended Practice for Installation, Maintenance and Repair of 
Surface Safety Valves and Underwater Safety Valves Offshore 
(incorporated by reference as specified in Sec.  250.198).

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

    You must install a BSDV on the pipeline boarding riser. All BSDVs 
and their actuators installed in the OCS must meet the requirements 
specified in Sec. Sec.  250.801 through 250.803 and the following 
requirements. You must:
    (a) Ensure that the internal design pressure of the pipeline(s), 
riser(s), and BSDV(s) is fully rated for the maximum pressure of any 
input source and comply 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.

    All BSDVs must be inspected, maintained, and tested in accordance 
with API RP 14H, Recommended Practice for Installation, Maintenance and 
Repair of Surface Safety Valves and Underwater Safety Valves Offshore 
(incorporated by reference as specified in Sec.  250.198) for SSVs. If 
any BSDV does not operate properly or if any fluid flow is observed 
during the leakage test, then you must shut-in all sources to the BSDV 
and repair or replace it before resuming production.

Sec.  250.837  Emergency action and safety system shutdown.

    (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 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 a permit to drill or an application for permit to 
modify, to shut-in any wells that could be affected by a dropped 
object. If an object is dropped, the driller must immediately secure 
the well directly under the MODU using the ESD on the well control 
panel located on the rig floor 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. If communication is lost between the MODU 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 BSEE 
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 BSEE District Manager.
    (3) ESD/TSE (Platform). In the event of an ESD activation that is 
initiated because of a platform ESD or platform TSE on the host 
platform 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 MODU because of a dropped object from a rig or 
intervention vessel, you must secure all wells in the proximity of the 
MODU 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 BSEE District Manager before resuming 
production.
    (d) 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 following an ESD or fire 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 BSEE 
District Manager may require you to verify the closure time of the 
USV(s) through visual authentication by diver or ROV.
    (b) If you have not lost communication with your rig or platform, 
you must comply with the maximum allowable valve closure times and 
hydraulic system bleeding

[[Page 52269]]

requirements listed in the following table or your approved DWOP:

                                                 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 minute 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                            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 minutes after ESD   Close within 20   Close within 20  Initiate         Initiate
                                seconds after      or sensor activation. If you use   minutes after     minutes after    unrestricted     unrestricted
                                ESD or sensor      a 5-minute resettable timer, you   ESD or sensor     ESD or sensor    bleed within     bleed within
                                activation.         may continue to reset the time    activation.       activation. If   60 minutes       60 minutes
                                                  for closure up to a maximum of 20                     you use a 20-    after ESD or     after ESD or
                                                            minutes total.                              minute           sensor           sensor
                                                                                                        resettable       activation. If   activation. If
                                                                                                        timer, you may   you use a 60-    you use a 60-
                                                                                                        continue to      minute           minute
                                                                                                        reset the time   resettable       resettable
                                                                                                        for closure up   timer you must   timer you must
                                                                                                        to a maximum     initiate         initiate
                                                                                                        of 60 minutes    unrestricted     unrestricted
                                                                                                        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) Dropped object--(Subsea    [no                Initiate valve closure immediately. You may allow for closure of the  Initiate         Initiate
 ESD MODU).                     requirements].     tree valves immediately prior to closure of the surface-controlled    unrestricted     unrestricted
                                                                            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 this section, you must notify the 
appropriate BSEE 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 this section, you must notify the 
appropriate BSEE 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. Bleed 
the other hydraulic system within 180 minutes after loss of 
communication.
    (3) You must obtain prior approval from the appropriate BSEE 
District Manager if you want to continue 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 table that your system is 
able to achieve. The appropriate BSEE 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:

                                    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.
--------------------------------------------------------------------------------------------------------------------------------------------------------

[[Page 52270]]

 
(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).                      within 20
                                                                                                                                          minutes.
--------------------------------------------------------------------------------------------------------------------------------------------------------
(5) Dropped object--subsea     [no                Initiate closure immediately. You may allow for closure of the tree   Initiate         Initiate
 ESD (MODU).                    requirements].     valves immediately prior to closure of the surface-controlled SSSV    unrestricted     unrestricted
                                                                               if desired.                               bleed            bleed
                                                                                                                         immediately.     immediately
--------------------------------------------------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------------------------------------------------------

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

    (a) If you have 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 BSEE 
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.
--------------------------------------------------------------------------------------------------------------------------------------------------------
(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) Dropped object--Subsea     [no                Initiate closure immediately. If desired, you may allow for closure   Initiate         Initiate
 ESD.                           requirements].       of the tree valves immediately prior to closure of the surface-     unrestricted     unrestricted
(MODU).......................                                               controlled SSSV.                             bleed            bleed
                                                                                                                         immediately.     immediately.
--------------------------------------------------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------------------------------------------------------

[[Page 52271]]

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, Recommended Practice for Analysis, 
Design, Installation, and Testing of Basic Surface Safety Systems for 
Offshore Production Platforms (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 30 CFR 250.1004.
    (b) You must design, analyze, install, test, and maintain in 
operating condition all platform production process piping in 
accordance with API RP 14E, Design and Installation of Offshore 
Production Platform Piping Systems and API 570, Piping Inspection Code: 
In-service Inspection, Rating, Repair, and Alteration of Piping Systems 
(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:

------------------------------------------------------------------------
       You must submit:         Details and/or additional 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).
                               (vii) Size and maximum allowable working
                                pressures as determined in accordance
                                with API RP 14E, Recommended Practice
                                for Design and Installation of Offshore
                                Production Platform Piping Systems
                                (incorporated by reference as specified
                                in Sec.   250.198).
(2) A safety analysis flow     If processing components are used, other
 diagram (API RP 14C,           than those for which Safety Analysis
 Appendix E) and the related    Checklists are included in API RP 14C,
 Safety Analysis Function       you must use the same analysis technique
 Evaluation (SAFE) chart (API   and documentation to determine the
 RP 14C, subsection 4.3.3)      effects and requirements of these
 (incorporated by reference     components upon the safety system.
 as specified in Sec.
 250.198)
(3) Electrical system          (i) A plan for each platform deck and
 information, including         outlining all classified areas. You must
                                classify areas according to API RP 500,
                                Recommended Practice for Classification
                                of Locations for Electrical
                                Installations at Petroleum Facilities
                                Classified as Class I, Division 1 and
                                Division 2; or 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 (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, and 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     Showing a functional block diagram of the
 and gas-detection systems      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  The fee you must pay will be determined
 Sec.   250.125                 by the number of components involved in
                                the review and approval process.
------------------------------------------------------------------------

    (b) The production safety system application must also include the 
following certifications:
    (1) That all electrical installations were designed according to 
API RP 14F, Design, Installation, and Maintenance of Electrical Systems 
for Fixed and Floating Offshore Petroleum Facilities for Unclassified 
and Class I, Division 1 and Division 2 Locations, or 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, as applicable 
(incorporated by reference as specified in Sec.  250.198);

[[Page 52272]]

    (2) That the designs for the mechanical and electrical systems were 
reviewed, approved, and stamped by a 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; and
    (3) That a hazard analysis was performed during the design process 
in accordance with 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:
    (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, you must certify, in a letter 
to the District Manager, that the as-built diagrams outlined in (a)(1) 
and (2) of this section and the piping and instrumentation diagrams are 
on file and have been certified correct and stamped by a 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 (a)(1) and (2) of this 
section must be submitted to the District Manager within 60 days after 
production.
    (f) You must maintain information concerning the approved design 
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 
the following sections (Sec. Sec.  250.851 through 250.872), some of 
which are in addition to those 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 
must meet the requirements in the following table:

------------------------------------------------------------------------
                                               Applicable codes and
               Item name                           requirements
------------------------------------------------------------------------
(1) Pressure and fired vessels where     (i) Must be designed,
 the operating pressure is or will be     fabricated, and code stamped
 15 pounds per square inch gauge (psig)   according to applicable
 or greater.                              provisions of sections I, IV,
                                          and VIII of the ANSI/ASME
                                          Boiler and Pressure Vessel
                                          Code.
                                         (ii) Must be repaired,
                                          maintained, and inspected in
                                          accordance with API 510,
                                          Pressure Vessel Inspection
                                          Code: In-Service Inspection,
                                          Rating, Repair, and
                                          Alteration, Downstream Segment
                                          (incorporated by reference as
                                          specified in Sec.   250.198).
(2) Pressure and fired vessels (such as  Must employ a safety analysis
 flare and vent scrubbers) where the      checklist in the design of
 operating pressure is or will be at      each component. These vessels
 least 5 psig and less than 15 psig.      do not need to be ASME Code
                                          stamped as pressure vessels.
(3) Pressure and fired vessels where     Are not subject to the
 the operating pressure is or will be     requirements of paragraphs
 less than 5 psig.                        (a)(1) and (a)(2).
(4) Existing uncoded Pressure and fired  Must be justified and approval
 vessels (i) in use on the effective      obtained from the District
 date of the final rule; (ii) with an     Manager for their continued
 operating pressure of 5 psig or          use beyond 18 months from the
 greater; and (iii) that are not code     effective date of the final
 stamped in accordance with the ANSI/     rule.
 ASME Boiler and Pressure Vessel Code .
 . .
(5) 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.
                                         (ii) Must conform to the valve
                                          sizing and pressure-relieving
                                          requirements specified in
                                          these documents, but (except
                                          for completely redundant
                                          relief valves), must be set no
                                          higher than the maximum-
                                          allowable working pressure of
                                          the vessel.
                                         (iii) And vents must be
                                          positioned in such a way as to
                                          prevent fluid from striking
                                          personnel or ignition sources.
(6) 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.
(7) 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) You must also install 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 the normalized system pressure changes by 5 
percent. 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:

[[Page 52273]]

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

Sec.  250.852  Flowlines/Headers.

    (a)(1) You must 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) You must 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.
    (3) You must 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:

------------------------------------------------------------------------
       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 assure 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.
------------------------------------------------------------------------

    (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 liquid 
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 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, 
Specification for Unbonded Flexible Pipe (ISO 13628-2:2006) 
(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 (ISO 13628-2:2006) 
(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 
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 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;
    (c) All pressure sensors are equipped to permit testing with an 
external pressure source; and,
    (d) All level sensors are equipped to permit testing through an 
external bridle on all new vessel installations.

[[Page 52274]]

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:
    (i) Your buoy is clamped,
    (ii) Your auto slew mode is activated, and
    (iii) 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 
nonrestricted to enable the rapid actuation of the shutdown system. 
Only ESD stations at the boat landing may utilize a loop of breakable 
synthetic tubing in lieu of a valve. This breakable loop is not 
required to be physically located on the boat landing, but must be 
accessible from a boat.
    (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 shutdown the diesel engine in the event of 
runaway. 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; 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 overpressurization. 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.

250.858  Gas compressors.

    (a) You must equip compressor installations with the following 
protective equipment as required in API RP 14C, sections A4 and A8 
(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), and 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 on each compressor 
discharge cylinder.
    (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 a 
compressor suction must be diverted to the pipeline 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) You must use pressure recording devices to establish the new 
operating pressure ranges for compressor discharge sensors at any time 
when the normalized system pressure changes by 50 psig or 5 percent, 
whichever is higher. You must:
    (1) 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.
    (2) Set the PSH sensor(s) no higher than 15 percent or 5 psi, 
whichever is greater, above the highest operating pressure of the 
discharge line and sufficiently below the maximum discharge pressure to 
ensure actuation of the suction SDV. Set the PSH sensor(s) sufficiently 
below (5 percent or 5 psi, whichever is greater) the set pressure of 
the PSV to assure that the pressure source is shut-in before the PSV 
activates.
    (3) Set PSL sensor(s) 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.
    (c) For vapor recovery units, when the suction side of the 
compressor is operating below 5 psig and the system is capable of being 
vented to atmosphere, you are not required to install PSH and PSL 
sensors on the suction side of the compressor.

Sec.  250.859  Firefighting systems.

    (a) Firefighting systems for both open and totally enclosed 
platforms installed for extreme weather conditions or other reasons 
must conform to API RP 14G, Recommended Practice for Fire Prevention 
and Control on Fixed Open-type Offshore Production Platforms 
(incorporated by reference as specified in Sec.  250.198), and require 
approval of the District Manager. The following additional requirements 
apply for both open- and closed-production platforms:
    (1) You must install a firewater system consisting of rigid pipe 
with firehose stations fixed firewater monitors. The firewater system 
must protect in all areas where production-handling equipment is 
located. You

[[Page 52275]]

must install a fixed water spray system in enclosed well-bay areas 
where hydrocarbon vapors may accumulate.
    (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. As of 1 year after the 
publication date of the final rule, 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. 
For electric driven firewater pump drivers, in the event of a 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. 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 a diagram of the firefighting system showing the 
location of all firefighting equipment in a prominent place on the 
facility or structure.
    (4) For operations in subfreezing climates, you must furnish 
evidence to the District Manager that the firefighting system is 
suitable for those conditions.
    (5) All firefighting equipment located on a facility must be in 
good working order whether approved as the primary, secondary, or 
ancillary firefighting system.
    (b) Inoperable Firewater Systems. If you are required to maintain a 
firewater system and it becomes inoperable, either shut-in your 
production operations while making the necessary repairs, or request 
that the appropriate BSEE District Manager grant you 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 you make the 
necessary repairs. If you are unable to complete repairs during the 
approved time period because of circumstances beyond your control, the 
BSEE District Manager may grant extensions to your approved departure 
for periods up to 7 days.

Sec.  250.860  Chemical firefighting system.

    (a) Major platforms and minor manned platforms. A firefighting 
system using chemicals-only may be used in lieu of a water-based system 
on a major platform or a minor manned platform 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. A 
major platform is a structure with either six or more completions or 
zero to five completions with more than one item of production process 
equipment. A minor platform is a structure with zero to five 
completions with one item of production process equipment. A manned 
platform is one that is attended 24 hours a day or one on which 
personnel are quartered overnight. To obtain approval to use a 
chemical-only fire prevention and control system on a major platform or 
a minor manned platform, in lieu of a water system, 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. 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 provide the                   Including . . .
    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 day, 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         (A) Identification of all likely fire
 (facility specific).           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            (A) Descriptions of the fire-related
 assessment (not facility       training your employees and contractors
 specific).                     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 contractor on the
                                platform.

[[Page 52276]]

 
(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 are
 assessment.                    proposing to use an alternative fire
                                prevention and control system.
                               (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.
------------------------------------------------------------------------

    (b) Changes after approval. If BSEE has approved your request to 
use a chemical-only fire suppressant system in lieu of a water system, 
and if you make an insignificant change to your platform subsequent to 
that approval, document the change and maintain the documentation at 
the facility or nearest field office for BSEE review and/or inspection 
and maintain for the life of the facility. Do not submit this 
documentation to the BSEE 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, submit a new request, including an updated risk 
assessment, to the appropriate BSEE District Manager for approval. You 
must maintain the most recent documentation that you submitted to BSEE 
for the life of the facility at either location discussed previously.
    (c) 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, on all platforms that are both minor and 
unmanned, as long as you ensure that the unit is available on the 
platform when personnel are on board.

Sec.  250.861  Foam firefighting system.

    When foam firefighting systems are installed as part of your 
firefighting system, 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 per 
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) The quantity of concentrate must meet design requirements, and 
tanks or containers must be kept full with space allowed for expansion.

Sec.  250.862  Fire and gas-detection systems.

    (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. 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. Enclosed areas (e.g., buildings, living quarters, or 
doghouses) are defined as those areas confined on more than four of 
their six 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. 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. Living quarters and 
doghouses not containing a gas source and not located in a classified 
area do not require a gas detection system.
    (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).

[[Page 52277]]

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 by 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 section A7 (incorporated 
by reference as specified in Sec.  250.198).
    (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. 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. The PSH 
sensor(s) must be set no higher than 15 percent or 5 psi, whichever is 
greater, above the highest operating pressure of the discharge line. 
But in all cases, you must set the PSH sensor sufficiently below the 
maximum allowable working pressure of the discharge piping. In 
addition, you must set the PSH sensor(s) 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. You must set 
the PSL sensor(s) 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.
    (c) The PSL does not need to be placed into service until such time 
as the pump discharge pressure has risen above the PSL sensing point, 
as long as this time does not exceed 45 seconds.
    (d) 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.
    (e) You must install a TSE in the immediate vicinity of all pumps 
in hydrocarbon service or those powered by platform fuel gas.
    (f) The pump maximum discharge pressure must be determined using 
the maximum possible suction pressure and the maximum power output of 
the driver.

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 on OCS facilities. You must equip 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 in temporary quarters.
    (c) Temporary equipment used for well testing and/or well clean-up 
needs to be approved by the District Manager.

Sec.  250.868  Non-metallic piping.

    You may use non-metallic piping, such as that made from polyvinyl 
chloride, chlorinated polyvinyl chloride, and reinforced fiberglass 
only in atmospheric, primarily non-hydrocarbon service such as:
    (a) Piping in galleys and living quarters;
    (b) Open atmospheric drain systems;
    (c) Overboard water piping for atmospheric produced water systems; 
and
    (d) Firewater system piping.

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 non-computer-based 
system 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 computer-based technology system 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 (Site 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 operating procedure 
in accordance with 250.142. 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

[[Page 52278]]

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) The adequate ventilation system;
    (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 SSSV) 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 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 above in 
paragraph (3), 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) All new production safety system installations, component 
process control devices, and component safety devices must not be 
installed utilizing the same sensing points.

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

    (a) You must apply industry standard Class B, Class C, and 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 
of a request under Sec.  250.141. You must document on your field test 
records 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. Use of a manual 
bypass that involves a time delay greater than 45 seconds requires 
approval from the appropriate BSEE District Manager of a request made 
under Sec.  250.141.

[[Page 52279]]

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. The BSEE 
approval of variances from your approved welding and burning practices 
and procedures may be requested in accordance with 250.141 regarding 
use of alternative procedures or equipment.

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).
    (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 in accordance with the following or as approved in your 
DWOP. You must:
    (a) Design the gas lift supply pipeline in accordance with the 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 appropriate requirements in the following table:

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                  Then you must install a . . .
                                   -------------------------------------------------------------------------------------------
                                     API Spec 6A and API
                                       Spec 6AV1 (both
  If your subsea gas lift system       incorporated by                                                    API Spec 6A and API
introduces the lift gas to the . .       reference as       FSV on the gas-lift    PSHL on the gas-lift    Spec 6AV1 manual     Additional requirements
                 .                    specified in Sec.    supply pipeline . . .       supply . . .       isolation valve . .
                                      250.198) gas-lift                                                            .
                                        shutdown valve
                                      (GLSDV), and . . .
--------------------------------------------------------------------------------------------------------------------------------------------------------
(1) Subsea Pipelines, Pipeline      meet all of the        upstream (in board)    pipeline upstream (in  downstream (out       (i) Ensure that the MAOP
 Risers, or Manifolds via an         requirements for the   of the GLSDV.          board) of the GLSDV.   board) of the PSHL    of a subsea gas lift
 External Gas Lift Pipeline.         BSDV described in                                                    and above the         supply pipeline is equal
                                     250.835 and 250.836                                                  waterline. This       to the MAOP of the
                                     on the gas-lift                                                      valve does not have   production pipeline. an
                                     supply pipeline.                                                     to be actuated.       actuated fail-safe close
                                                                                                                                gas-lift isolation valve
                                                                                                                                (GLIV) located at the
                                                                                                                                point of intersection
                                                                                                                                between the gas lift
                                                                                                                                supply pipeline and the
                                                                                                                                production pipeline,
                                                                                                                                pipeline riser, or
                                                                                                                                manifold.
                                                                                                                               (ii) Install an actuated
                                                                                                                                fail-safe close gas-lift
                                                                                                                                isolation valve (GLIV)
                                                                                                                                located at the point of
                                                                                                                                intersection between the
                                                                                                                                gas lift supply pipeline
                                                                                                                                and the production
                                                                                                                                pipeline, pipeline
                                                                                                                                riser, or manifold.
                                                                                                                                Install the GLIV
                                                                                                                                downstream of the
                                                                                                                                underwater safety
                                                                                                                                valve(s) (USV) and/or
                                                                                                                                AIV(s).
(2) Subsea Well(s) through the      Locate the GLSDV       on the platform        pipeline on the        downstream (out       Install an actuated, fail-
 Casing String via an External Gas   within 10 feet of      upstream (in board)    platform downstream    board) of the PSHL    safe-closed GLIV on the
 Lift Pipeline.                      the first of access    of the GLSDV.          (out board) of the     and above the         gas lift supply pipeline
                                     to the gas-lift                               GLSDV.                 waterline. This       near the wellhead to
                                     riser or topsides                                                    valve does not have   provide the dual
                                     umbilical                                                            to be actuated.       function of containing
                                     termination assembly                                                                       annular pressure and
                                     (TUTA) (i.e., within                                                                       shutting off the gas
                                     10 feet of the edge                                                                        lift supply gas. If your
                                     of the platform if                                                                         subsea trees or tubing
                                     the GLSDV is                                                                               head is equipped with an
                                     horizontal, or                                                                             annulus master valve
                                     within 10 feet above                                                                       (AMV) or an annulus wing
                                     the first accessible                                                                       valve (AWV), one of
                                     working deck,                                                                              these may be designated
                                     excluding the boat                                                                         as the GLIV. Consider
                                     landing and above                                                                          installing the GLIV
                                     the splash zone, if                                                                        external to the subsea
                                     the GLSDV is in the                                                                        tree to facilitate
                                     vertical run of a                                                                          repair and or
                                     riser, or within 10                                                                        replacement if
                                     feet of the TUTA if                                                                        necessary.
                                     using an umbilical).

[[Page 52280]]

 
(3) Pipeline Risers via a Gas-Lift  locate the GLSDV       upstream (in board)    flowline upstream (in  downstream (out       (i) Ensure that the gas-
 Line Contained within the           within 10 feet of      of the GLSDV.          board) of the FSV.     board) of the GLSDV.  lift supply flowline
 Pipeline Riser.                     the first of access                                                                        from the gas-lift
                                     to the gas-lift                                                                            compressor to the GLSDV
                                     riser or TUTA (i.e.,                                                                       is pressure-rated for
                                     within 10 feet of                                                                          the MAOP of the pipeline
                                     the edge of the                                                                            riser. Ensure that any
                                     platform if the                                                                            surface equipment
                                     GLSDV is horizontal,                                                                       associated with the gas-
                                     or within 10 feet                                                                          lift system is rated for
                                     above the first                                                                            the MAOP of the pipeline
                                     accessible working                                                                         riser.
                                     deck, excluding the                                                                       (ii) Ensure that the gas-
                                     boat landing and                                                                           lift compressor
                                     above the splash                                                                           discharge pressure never
                                     zone, if the GLSDV                                                                         exceeds the MAOP of the
                                     is in the vertical                                                                         pipeline riser.
                                     run of a riser, or                                                                        (iii) Suspend and seal
                                     within 10 feet of                                                                          the gas-lift flowline
                                     the TUTA if using an                                                                       contained within the
                                     umbilical).                                                                                production riser in a
                                                                                                                                flanged API Spec. 6A
                                                                                                                                component such as an API
                                                                                                                                Spec. 6A tubing head and
                                                                                                                                tubing hanger or a
                                                                                                                                component designed,
                                                                                                                                constructed, tested, and
                                                                                                                                installed to the
                                                                                                                                requirements of API
                                                                                                                                Spec. 6A. Ensure that
                                                                                                                                all potential leak paths
                                                                                                                                upstream or near the
                                                                                                                                production riser BSDV on
                                                                                                                                the platform provide the
                                                                                                                                same level of safety and
                                                                                                                                environmental protection
                                                                                                                                as the production riser
                                                                                                                                BSDV. In addition,
                                                                                                                                ensure that this
                                                                                                                                complete assembly is
                                                                                                                                fire-rated for 30
                                                                                                                                minutes. Attach the
                                                                                                                                GLSDV by flanged
                                                                                                                                connection directly to
                                                                                                                                the API Spec. 6A
                                                                                                                                component used to
                                                                                                                                suspend and seal the gas-
                                                                                                                                lift line contained
                                                                                                                                within the production
                                                                                                                                riser. To facilitate the
                                                                                                                                repair or replacement of
                                                                                                                                the GLSDV or production
                                                                                                                                riser BSDV, you may
                                                                                                                                install a manual
                                                                                                                                isolation valve between
                                                                                                                                the GLSDV and the API
                                                                                                                                Spec. 6A component used
                                                                                                                                to suspend and seal the
                                                                                                                                gas-lift line contained
                                                                                                                                within the production
                                                                                                                                riser, or outboard of
                                                                                                                                the production riser
                                                                                                                                BSDV and inboard of the
                                                                                                                                API Spec. 6A component
                                                                                                                                used to suspend and seal
                                                                                                                                the gas-lift line
                                                                                                                                contained within the
                                                                                                                                production riser.
--------------------------------------------------------------------------------------------------------------------------------------------------------

    (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 valve testing requirements according to the 
following table:

----------------------------------------------------------------------------------------------------------------
       Type of gas lift system                  Valve            Allowable leakage rate     Testing frequency
----------------------------------------------------------------------------------------------------------------
(i) Gas Lifting a subsea pipeline,    GLSDV...................  Zero leakage...........  Monthly, not to exceed
 pipeline riser, or manifold via an                                                       6 weeks.
 external gas lift pipeline.
                                      GLIV....................  N/A....................  Function tested
                                                                                          quarterly, not to
                                                                                          exceed 120 days.
(ii) Gas Lifting a subsea well        GLSDV...................  Zero leakage...........  Monthly, not to exceed
 through the casing string via an                                                         6 weeks.
 external gas lift pipeline.
                                      GLIV....................  400 cc per minute of     Function tested
                                                                 liquid or 15 scf per     quarterly, not to
                                                                 minute of gas.           exceed 120 days.
(iii) Gas lifting the pipeline riser  GLSDV...................  Zero leakage...........  Monthly, not to exceed
 via a gas lift line contained                                                            6 weeks.
 within the pipeline riser.
----------------------------------------------------------------------------------------------------------------

Sec.  250.874  Subsea water injection systems.

    If you choose to install a subsea water injection system, you must 
design your system in accordance with the following or as approved in 
your DWOP. You must:
    (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-

[[Page 52281]]

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) All subsea tree(s), wellhead(s), connector(s), tree valves, and 
an surface-controlled SSSV or WIV associated with a water injection 
system must be rated for the maximum anticipated injection pressure.
    (e) Consider the effects of hydrogen sulfide (H2S) when designing 
your water flood system.
    (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,
    (3) Direct-hydraulic control system with water injection.
    (g) Follow the WIV testing requirements according to the following:
    (1) WIV testing table,

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

    (2) Should a designated USV on a water injection well fail to test, 
notify the appropriate BSEE District Manager, and either 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, or 
modify the valve closure time of the surface-controlled SSSV or WIV to 
close within 20 minutes after sensor activation for a water injection 
line PSHL or platform ESD/TSE (host). If a USV on a water injection 
well fails and the surface-controlled SSSV or WIV cannot be tested 
because of low reservoir pressure, submit a request to the appropriate 
BSEE District Manager with an alternative plan that ensures subsea 
shutdown capabilities.
    (3) Function test the WISDV quarterly if you are operating under a 
departure approval to not test the WISDV. You may request approval from 
the appropriate BSEE District Manager to forgo testing the WISDV until 
the shut-in tubing pressure of the water injection well is greater than 
the external hydrostatic pressure, provided that the USVs meet the 
allowable leakage rate listed in the valve closure testing table in 
Sec.  250.880 (c)(4)(ii). Should the USVs fail to meet the allowable 
leakage rate, submit a request to the appropriate BSEE District Manager 
with an alternative plan that ensures subsea shutdown capabilities.
    (f) If you experience a loss of communications during water 
injection operations, comply with the following:
    (1) Notify the appropriate BSEE District Manager within 12 hours 
after loss of communication detection; and
    (2) Obtain approval from the appropriate BSEE District Manager, to 
continue to inject with loss of communication. The District Manager may 
also order a shut-in. In that case, the BSEE District Manager may 
approve an alternate hydraulic bleed schedule to allow for an orderly 
shut-in.

Sec.  250.875  Subsea Pump Systems.

    If you choose to install a subsea pump system, you must design your 
system in accordance with the following or as approved in your DWOP. 
You must:
    (a) Install an isolation valve at the inlet of your subsea pump 
module.
    (b) Install 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) Comply with the following, 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) Install, at minimum, two independent functioning PSHL sensors 
upstream of the subsea pump and two independent functioning PSHL 
sensors downstream of the pump.
    (i) Ensure PSHL sensors are operational when the subsea pump is in 
service; and
    (ii) Ensure that PSHL activation will 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 two PSHL sensors are installed upstream and 
downstream of the subsea pump for operational flexibility, then a 2 out 
of 3 voting logic may be implemented in which the subsea pump remains 
operational provided a minimum of two 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 
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;
    (iii) The upstream subsea pump isolation valve is open; and
    (iv) All alarms associated with the subsea pump operation (pump 
temperature high, pump vibration high, pump suction pressure high, pump 
discharge pressure high, pump suction flow low) are cleared or 
continuously monitored (personnel should 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 communications with the subsea wells and not the 
subsea pump control system without a ESD or sensor activation,
    (3) A loss of communications with the subsea pump control system, 
but not the subsea wells,
    (4) A loss of communications with the subsea wells and the subsea 
pump control system.
    (e) Follow the subsea pump testing requirements by:
    (1) Performing 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) Testing the subsea pump shutdown including PSHL sensors both

[[Page 52282]]

upstream and downstream of the pump each quarter, but in no case more 
than 120 days between tests. This testing may be performed concurrently 
with the ESD function test.

Sec.  250.876  Fired and Exhaust Heated Components.

    Every 5 years you must have a qualified third party remove, 
inspect, repair, or replace 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 them available to BSEE 
upon request.

Sec. Sec.  250.877 through 250.879  [Reserved]

Safety Device Testing

Sec.  250.880  Production safety system testing.

    (a) Notification. You must:
    (1) Notify District Manager at least 72 hours before commencing 
production, so that BSEE may witness a preproduction test and 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 contained in the table set forth 
in paragraph (c)(4).
    (b) Testing methodologies. You must:
    (1) Test safety valves and other equipment at the intervals 
specified in the tables set forth in paragraph (c) or more frequently 
if operating conditions warrant; and
    (2) Perform testing and inspection in accordance with API RP 14C, 
Appendix D (incorporated by reference as specified in Sec.  250.198), 
and the additional requirements found in the tables of this section or 
as approved in the DWOP for your subsea system.
    (c) Testing frequencies and allowable parameters.
    (1) The following testing requirements apply to subsurface safety 
devices on dry tree wells:

------------------------------------------------------------------------
                                  Testing frequency, allowable leakage
          Item name                  rates, and other requirements
------------------------------------------------------------------------
(i) Surface-controlled SSSVs   Not to exceed 6 months. Also test in
 (including devices installed   place when first installed or
 in shut-in and injection       reinstalled. If the device does not
 wells).                        operate properly, or if a liquid leakage
                                rate > 400 cubic centimeters per minute
                                or a gas leakage rate > 15 cubic feet
                                per minute is observed, the device must
                                be removed, repaired, and reinstalled or
                                replaced. Testing must be according to
                                API RP 14B (ISO 10417:2004)
                                (incorporated by reference as specified
                                in Sec.   250.198) to ensure proper
                                operation.
(ii) Subsurface-controlled     Not to exceed 6 months for valves not
 SSSVs.                         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............  Not to exceed 6 months. Test by opening
                                the well to possible flow. If a liquid
                                leakage rate > 400 cubic centimeters per
                                minute or a gas leakage rate > 15 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........  Not to exceed 6 months. Test by opening
                                the well to possible flow. If a liquid
                                leakage rate > 400 cubic centimeters per
                                minute or a gas leakage rate > 15 cubic
                                feet per minute is observed, the valve
                                must be removed, repaired and
                                reinstalled, or replaced.
------------------------------------------------------------------------

    (2) The following testing requirements apply to surface valves:

------------------------------------------------------------------------
          Item name                Testing frequency and requirements
------------------------------------------------------------------------
(i) PSVs.....................  Once each 12 months, not to exceed 13
                                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.
(ii) Automatic inlet SDVs      Once each calendar month, not to exceed 6
 that are actuated by a         weeks between tests.
 sensor on a vessel or
 compressor.
(iii) SDVs in liquid           Once each calendar month, not to exceed 6
 discharge lines and actuated   weeks between tests.
 by vessel low-level sensors.
(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 fluid flow is
                                observed during the leakage test, the
                                valve must be immediately repaired or
                                replaced.
(v) FSVs.....................  Once each calendar month, not to exceed 6
                                weeks between tests. All FSVs must be
                                tested, including those installed on a
                                host facility in lieu of being installed
                                at a satellite well. You must test FSVs
                                for leakage in accordance with the test
                                procedure specified in API RP 14C,
                                appendix D, section D4, table D2
                                subsection D (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 cubic feet per minute,
                                the FSV must be repaired or replaced.
------------------------------------------------------------------------

    (3) The following testing requirements apply to surface safety 
systems and devices:

[[Page 52283]]

------------------------------------------------------------------------
          Item name                Testing frequency and requirements
------------------------------------------------------------------------
(i) Pumps for firewater        Must be inspected and operated according
 systems.                       to API RP 14G, Section 7.2 (incorporated
                                by reference as specified in Sec.
                                250.198).
(ii) Fire- (flame, heat, or    Must be tested for operation and
 smoke) detection systems.      recalibrated every 3 months 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.
                               (B) Electronic based ESD systems must be
                                tested for operation at least once every
                                three 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.
                               (C) Electronic/pneumatic based ESD
                                systems must be tested for operation at
                                least once every three 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.
(iv) TSH devices.............  Must be tested for operation at least
                                once every 12 months, excluding those
                                addressed in paragraph (b)(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      Must be tested every 6 months and
 installed on compressor        repaired or replaced as necessary.
 installations that can be
 nondestructively tested.
(vi) Burner safety low.......  Must be tested at least once every 12
                                months.
(vii) Flow safety low devices  Must be tested at least once every 12
                                months.
(viii) Flame, spark, and       Must be visually inspected at least once
 detonation arrestors.          every 12 months.
(ix) Electronic pressure       Must be tested at least once every 3
 transmitters and level         months, but no more than 120 days elapse
 sensors: PSH and PSL; LSH      between tests.
 and LSL.
(x) Pneumatic/electronic       Must be tested at least once each
 switch PSH and PSL;            calendar month, but with no more than 6
 pneumatic/electronic switch/   weeks elapsed time between tests.
 electric analog with
 mechanical linkage LSH and
 LSL controls.
------------------------------------------------------------------------

    (4) The following testing requirements apply to subsurface safety 
devices and associated systems on subsea tree wells:

------------------------------------------------------------------------
                                  Testing frequency, allowable leakage
          Item name                  rates, and other requirements
------------------------------------------------------------------------
(i) Surface-controlled SSSVs   Tested semiannually, not to exceed 6
 (including devices installed   months. If the device does not operate
 in shut-in and injection       properly, or if a liquid leakage rate >
 wells).                        400 cubic centimeters per minute or a
                                gas leakage rate > 15 cubic feet per
                                minute is observed, the device must be
                                removed, repaired, and reinstalled or
                                replaced. Testing must be according to
                                API RP 14B (ISO 10417:2004)
                                (incorporated by reference as specified
                                in Sec.   250.198) to ensure proper
                                operation, or as approved in your DWOP.
(ii) USVs....................  Tested quarterly, not to exceed 120 days.
                                If the device does not function
                                properly, or if a liquid leakage rate >
                                400 cubic centimeters per minute or a
                                gas leakage rate > 15 cubic feet per
                                minute is observed, the valve must be
                                removed, repaired and reinstalled, or
                                replaced.
(iii) BSDVs..................  Tested monthly, not to exceed 6 weeks.
                                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 monthly, not to exceed 6 weeks.
(v) Electronic ESD function..  Tested quarterly, not to exceed 120 days.
                                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.
------------------------------------------------------------------------

    (5) The following testing and other requirements apply to subsea 
wells shut-in and disconnected from monitoring capability for periods 
greater than 6 months:
    (i) Each well must be left with three pressure barriers: A closed 
and tested surface-controlled SSSV, a closed and tested USV, and one 
additional closed and tested tree valve.
    (ii) Acceptance criteria for the tested pressure barriers prior to 
the rig leaving the well are 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.
    (iii) A sealing pressure cap must be installed on the flowline 
connection hub until installation of and connection to the flowline. A 
pressure cap must be designed to accommodate monitoring for pressure 
between the production wing valve and cap. A diagnostics capability 
must be integrated into the design such that a remotely operated 
vehicle can bleed pressure off and monitor for buildup, confirming 
barrier integrity.

[[Page 52284]]

    (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 (prior to 
demobilizing rig from field).
    (v) A drilling vessel capable of intervention into the disconnected 
well must be in the field or readily accessible for use until the wells 
are brought on line.
    (vi) The shut-in period for each disconnected well must not exceed 
24 months, unless authorized by BSEE.

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 operated platforms at least annually or when contact 
information is revised. The contact list must include:
    (1) Designated operator name;
    (2) Designated person in charge (PIC);
    (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 S 
of this part.

Sec. Sec.  250.892-250.899  [Reserved]

[FR Doc. 2013-19861 Filed 8-21-13; 8:45 am]
BILLING CODE 4310-VH-P
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