[Federal Register Volume 78, Number 163 (Thursday, August 22, 2013)]
[Proposed Rules]
[Pages 52240-52284]
From the Federal Register Online via the Government Publishing 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: [email protected]. Please send a
copy to BSEE.
Public Availability of Comments--Before including your
address, phone number, email address, or other personal identifying
information in your comment, you should be aware that your entire
comment--including your personal identifying information--may be made
publicly available at any time. 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, [email protected].
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:
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Current regulation Proposed rule
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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
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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 < 200 cubic < 400 cubic
installed in shut-in and centimeters per centimeters per
injection wells). minute, or. minute, or
gas leakage rate < 5 gas leakage rate <
cubic feet per 15 cubic feet per
minute. minute.
Tubing plug................. liquid leakage rate liquid leakage rate
< 200 cubic < 400 cubic
centimeters per centimeters per
minute, or. minute, or
gas leakage rate < 5 gas leakage rate <
cubic feet per 15 cubic feet per
minute. minute.
Injection valves............ liquid leakage rate liquid leakage rate
< 200 cubic < 400 cubic
centimeters per centimeters per
minute, or. minute, or
gas leakage rate < 5 gas leakage rate <
cubic feet per 15 cubic feet per
minute. minute.
USVs........................ 0 leakage rate...... liquid leakage rate
< 400 cubic
centimeters per
minute, or
gas leakage rate <
15 cubic feet per
minute.
Flow safety valves (FSV).... liquid leakage rate liquid leakage rate
< 200 cubic < 400 cubic
centimeters per centimeters per
minute, or. minute, or
gas leakage rate < 5 gas leakage rate <
cubic feet per 15 cubic feet per
minute. minute.
------------------------------------------------------------------------
Additionally, proposed Sec. 250.880 would contain new requirements
for BSDVs, changes to the testing frequency for underwater safety
valves, and requirements for the testing of ESD systems, as well as
pneumatic/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
----------------------------------------------------------------------------------
< 25 components...... 8 20 applications........... 160
-----------------------------------------------------------
$604 per submission x 20 = $12,080
----------------------------------------------------------------------------------
Submit modification 9 180 modifications......... 1,620
to application for
production safety
system with > 125
components.
-----------------------------------------------------------
$561 per submission x 180 = $100,980
----------------------------------------------------------------------------------
25-125 components.... 7 758 modifications......... 5,306
-----------------------------------------------------------
$201 per submission x 758 = $152,358
----------------------------------------------------------------------------------
< 25 components...... 5 329 modifications......... 1,645
-----------------------------------------------------------
$85 per submission x 329 = $27,965
----------------------------------------------------------------------------------------------------------------
842(b)....................... NEW: Your application 6 32 certifications......... 192
must also include
certification(s)
that the designs for
mechanical and
electrical systems
were reviewed,
approved, and
stamped by
registered
professional
engineer. [Note:
Upon promulgation,
these certification
production safety
systems requirements
will be consolidated
into the application
hour burden for the
specific components].
----------------------------------------------------------------------------------------------------------------
842(c)....................... NEW: Submit a 6 32 letters................ 192
certification letter
that the mechanical
and electrical
systems were
installed in
accordance with
approved designs.
----------------------------------------------------------------------------------------------------------------
842(d), (e).................. NEW: Submit a 6 32 letters................ 208
certification letter \1/2\
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.
--------------------------------------------------------------------------------------------------------------------------------------------------------
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[[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:
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------------------------------------------------------------------------
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.
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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
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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