Oil and Gas and Sulphur Operations on the Outer Continental Shelf-Oil and Gas Production Safety Systems
Federal Register, Volume 78 Issue 163 (Thursday, August 22, 2013)
Federal Register Volume 78, Number 163 (Thursday, August 22, 2013)
Proposed Rules
Pages 52239-52284
From the Federal Register Online via the Government Printing Office www.gpo.gov
FR Doc No: 2013-19861
Page 52239
Vol. 78
Thursday,
No. 163
August 22, 2013
Part II
Department of the Interior
-----------------------------------------------------------------------
Bureau of Safety and Environmental Enforcement
-----------------------------------------------------------------------
30 CFR Part 250
Oil and Gas and Sulphur Operations on the Outer Continental Shelf--Oil and Gas Production Safety Systems; Proposed Rule
Page 52240
-----------------------------------------------------------------------
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.
-----------------------------------------------------------------------
SUMMARY: The Bureau of Safety and Environmental Enforcement (BSEE) proposes to amend and update the regulations regarding oil and natural gas production by addressing issues such as: Safety and pollution prevention equipment lifecycle analysis, production safety systems, subsurface safety devices, and safety device testing. The proposed rule would differentiate the requirements for operating dry tree and subsea tree production systems on the Outer Continental Shelf (OCS) and divide the current subpart H into multiple sections to make the regulations easier to read and understand. The changes in this proposed rule are necessary to bolster human safety, environmental protection, and regulatory oversight of critical equipment involving production safety systems.
DATES: Submit comments by October 21, 2013. The BSEE may not fully consider comments received after this date. You may submit comments to the Office of Management and Budget (OMB) on the information collection burden in this proposed rule by September 23, 2013. The deadline for comments on the information collection burden does not affect the deadline for the public to comment to BSEE on the proposed regulations.
ADDRESSES: You may submit comments on the rulemaking by any of the following methods. Please use the Regulation Identifier Number (RIN) 1014-AA10 as an identifier in your message. See also Public Availability of Comments under Procedural Matters.
Federal eRulemaking Portal: http://www.regulations.gov. In the entry titled Enter Keyword or ID, enter BSEE-2012-0005 then click search. Follow the instructions to submit public comments and view supporting and related materials available for this rulemaking. The BSEE may post all submitted comments.
Mail or hand-carry comments to the Department of the Interior (DOI); Bureau of Safety and Environmental Enforcement; Attention: Regulations Development Branch; 381 Elden Street, HE3313; Herndon, Virginia 20170-4817. Please reference ``Oil and Gas Production Safety Systems, 1014-AA10'' in your comments and include your name and return address.
Send comments on the information collection in this rule to: Interior Desk Officer 1014-0003, Office of Management and Budget; 202-395-5806 (fax); email: oira_submission@omb.eop.gov. Please send a copy to BSEE.
Public Availability of Comments--Before including your address, phone number, email address, or other personal identifying information in your comment, you should be aware that your entire comment--including your personal identifying information--may be made publicly available at any time. While you can ask us in your comment to withhold your personal identifying information from public review, we cannot guarantee that we will be able to do so.
FOR FURTHER INFORMATION CONTACT: Kirk Malstrom, Regulations Development Branch, 703-787-1751, kirk.malstrom@bsee.gov.
SUPPLEMENTARY INFORMATION:
Executive Summary
This proposed rule would amend and update the Subpart H, Oil and Gas Production Safety Systems regulations. Subpart H has not had a major revision since it was first published in 1988. Since that time, much of the oil and gas production on the OCS has moved into deeper waters and the regulations have not kept pace with the technological advancements.
These regulations address issues such as production safety systems, subsurface safety devices, and safety device testing. These systems play a critical role in protecting workers and the environment. The BSEE would make the following changes to Subpart H in this rulemaking:
Restructure the subpart to have shorter, easier-to-read sections based on the following headings:
cir General requirements;
cir Surface and subsurface safety systems--Dry trees;
cir Subsea and subsurface safety systems--Subsea trees;
cir Production safety systems;
cir Additional production system requirements;
cir Safety device testing; and
cir Records and training.
Update and improve the safety and pollution prevention equipment (SPPE) lifecycle analysis in order to increase the overall level of certainty that this equipment would perform as intended including in emergency situations. The lifecycle analysis involves vigilance throughout the entire lifespan of the SPPE, including design, manufacture, operational use, maintenance, and eventual decommissioning of the equipment. A major component of the lifecycle analysis involves the proper documentation of the entire process. The documentation allows an avenue for continual improvement throughout the life of the equipment by evaluation of mechanical integrity and communication between equipment operators and manufacturers.
Expand the regulations to differentiate the requirements for operating dry tree and subsea tree production systems on the OCS.
Incorporate new industry standards and update the incorporation of partially incorporated standards to require compliance with the complete standards.
Add new requirements for, but not limited to, the following:
cir SPPE life cycle and failure reporting;
cir Foam firefighting systems;
cir Electronic-based emergency shutdown systems (ESDs);
cir Valve closure timing;
cir Valve leakage rates;
cir Boarding shut down valves (BSDV); and
cir Equipment used for high temperature and high pressure wells.
Rewrite the subpart in plain language according to:
cir The Plain Writing Act of 2010;
cir Executive Order 12866;
cir Executive Order 12988; and
cir Executive Order 13563, Improving Regulation and Regulatory Review.
In addition to Subpart H revisions, we would revise the regulation in Subpart A requiring best available and safest technology (BAST) to follow more closely the Outer Continental Shelf Lands Act's (OCSLA, or the Act) statutory provision for BAST, 43 U.S.C. 1347(b).
Review of Proposed Rule
This rulemaking proposes a complete revision of the regulations at 30 CFR Part 250, Subpart H--Oil and Gas Production Safety Systems. The current regulations were originally published on April 1, 1988 (53 FR 10690). Since that time, various sections were updated, and BSEE has issued several Notices to
Page 52241
Lessees (NTLs) to clarify the regulations and to provide guidance. The new version of subpart H would represent a major improvement in the structure and readability of the regulation with new changes in the requirements.
Organization
The proposed rule would restructure Subpart H. The new version is divided into shorter, easier-to-read sections. These sections are more logically organized, as each section focuses on a single topic instead of multiple topics found in each section of the current regulations. For example, in the current regulations, all requirements for subsurface safety devices are found in one section (Sec. 250.801). In the proposed rule, requirements for subsurface safety devices would be contained in 27 sections (Sec. Sec. 250.810 through 250.839), with the sections organized by general requirements and requirements related to the use of either a dry or subsea tree. The groupings in the proposed rule would make it easier for an operator to find the information that applies to a particular situation. The numbering for proposed Subpart H would start at Sec. 250.800, and end at Sec. 250.891. The proposed rule would separate Subpart H into the following undesignated headings:
General Requirements
Surface and Subsurface Safety Systems--Dry Trees
Subsea and Subsurface Safety Systems--Subsea Trees
Production Safety Systems
Additional Production System Requirements
Safety Device Testing
Records and Training
Major Changes to the Rule
Typically, well completions associated with offshore production platforms are characterized as either dry tree (surface) or subsea tree completions. The ``tree'' is the assembly of valves, gauges, and chokes mounted on a well casinghead used to control the production and flow of oil or gas. Dry tree completions are the standard for OCS shallow water platforms, with the tree in a ``dry'' state located on the deck of the production platform. The dry tree arrangement allows direct access to valves and gauges to monitor well conditions, such as pressure, temperature, and flow rate, as well as direct vertical well access. As oil and gas production moved into deeper water, dry tree completions, because they are easily accessible, were still used on new types of platforms more suitable for deeper waters; such as compliant towers, tension-leg platforms, and spars. Starting with Conoco's Hutton tension-leg platform installed in the North Sea in 1984 in approximately 486 feet of water, these platform types gradually extended the depth of usage for dry tree completions to over 4,600 feet of water depth.
Production in the Gulf of Mexico now occurs in depths of 9,000 feet of water, with many of the wells producing from water depths greater than 4,000 feet utilizing ``wet'' or subsea trees. With a subsea tree completion the tree is located on the seafloor. These subsea completions are generally tied back to floating production platforms, and from there the production moves to shore through pipelines. Due to the location on the seafloor, subsea trees or subsea completions do not allow for direct access to valves and gauges, but the pressure, temperature, and flow rate from the subsea location is monitored from the production platform and in some cases from onshore data centers. In conjunction with all production operations and completions, there are associated subsurface safety devices designed to prevent uncontrolled releases of reservoir fluid or gas.
Subpart H has not kept pace with industry's use of subsea trees and other technologies that have evolved or become more prevalent offshore over the last 20 years. This includes items as diverse as foam firefighting systems; electronic-based ESDs; subsea pumping, waterflooding, and gaslift; and new alloys and equipment for high temperature and high pressure wells.
Another major change to the regulations in this proposed rule involves the lifecycle analysis of SPPE. The lifecycle analysis of SPPE is not a new concept and its elements are discussed in several industry documents incorporated in this rule, such as American Petroleum Institute (API) Spec. 6a, API Spec. 14A, API Recommended Practice (RP) 14B, and corresponding International Organization for Standardization (ISO) 10432 and ISO 10417. This proposed rule would codify aspects of the lifecycle analysis into the regulations and bring attention to its importance. The lifecycle analysis involves careful consideration and vigilance throughout SPPE design, manufacture, operational use, maintenance, and decommissioning of the equipment. Lifecycle analysis is a tool for continual improvement throughout the life of the equipment.
To assist in locating the regulations, the following table shows how sections of the proposed rule correspond to provisions of the current regulations in Subpart H:
------------------------------------------------------------------------
Current regulation Proposed rule
------------------------------------------------------------------------
Sec. 250.800 General requirements.... Sec. 250.800 General.
Sec. 250.801 Subsurface safety Sec. 250.810 Dry tree
devices. subsurface safety devices--
general.
Sec. 250.811 Specifications
for subsurface safety valves
(SSSVs)--dry trees.
Sec. 250.812 Surface-
controlled SSSVs--dry trees.
Sec. 250.813 Subsurface-
controlled SSSVs.
Sec. 250.814 Design,
installation, and operation of
SSSVs--dry trees.
Sec. 250.815 Subsurface
safety devices in shut-in
wells--dry trees.
Sec. 250.816 Subsurface
safety devices in injection
wells--dry trees.
Sec. 250.817 Temporary
removal of subsurface safety
devices for routine
operations.
Sec. 250.818 Additional
safety equipment--dry trees.
Sec. 250.821 Emergency
action.
Sec. 250.825 Subsea tree
subsurface safety devices--
general.
Sec. 250.826 Specifications
for SSSVs--subsea trees.
Sec. 250.827 Surface-
controlled SSSVs--subsea
trees.
Sec. 250.828 Design,
installation, and operation of
SSSVs--subsea trees.
Sec. 250.829 Subsurface
safety devices in shut-in
wells--subsea trees.
Sec. 250.830 Subsurface
safety devices in injection
wells--subsea trees.
Sec. 250.832 Additional
safety equipment--subsea
trees.
Sec. 250.837 Emergency action
and safety system shutdown.
Page 52242
Sec. 250.802 Design, installation, Sec. 250.819 Specification
and operation of surface production- for surface safety valves
safety systems. (SSVs).
Sec. 250.820 Use of SSVs.
Sec. 250.833 Specification
for underwater safety valves
(USVs).
Sec. 250.834 Use of USVs.
Sec. 250.840 Design,
installation, and maintenance--
general.
Sec. 250.841 Platforms.
Sec. 250.842 Approval of
safety systems design and
installation features.
Sec. 250.803 Additional production Sec. 250.850 Production
system requirements. system requirements--general.
Sec. 250.851 Pressure vessels
(including heat exchangers)
and fired vessels.
Sec. 250.852 Flowlines/
Headers.
Sec. 250.853 Safety sensors.
Sec. 250.855 Emergency
shutdown (ESD) system.
Sec. 250.856 Engines.
Sec. 250.857 Glycol
dehydration units.
Sec. 250.858 Gas compressors.
Sec. 250.859 Firefighting
systems.
Sec. 250.862 Fire and gas-
detection systems.
Sec. 250.863 Electrical
equipment.
Sec. 250.864 Erosion.
Sec. 250.869 General platform
operations.
Sec. 250.871 Welding and
burning practices and
procedures.
Sec. 250.804 Production safety-system Sec. 250.880 Production
testing and records. safety system testing.
Sec. 250.890 Records.
Sec. 250.805 Safety device training.. Sec. 250.891 Safety device
training.
Sec. 250.806 Safety and pollution Sec. 250.801 Safety and
prevention equipment quality assurance pollution prevention equipment
requirements. (SPPE) certification.
Sec. 250.802 Requirements for
SPPE.
Sec. 250.807 Additional requirements Sec. 250.804 Additional
for subsurface safety valves and requirements for subsurface
related equipment installed in high safety valves (SSSVs) and
pressure high temperature (HPHT) related equipment installed in
environments. high pressure high temperature
(HPHT) environments.
Sec. 250.808 Hydrogen sulfide........ Sec. 250.805 Hydrogen
sulfide.
New Sections Sec. 250.803 What SPPE
failure reporting procedures
must I follow?
Sec. 250.831 Alteration or
disconnection of subsea
pipeline or umbilical.
Sec. 250.835 Specification
for all boarding shut down
valves (BSDV) associated with
subsea systems.
Sec. 250.836 Use of BSDVs
Sec. 250.838 What are the
maximum allowable valve
closure times and hydraulic
bleeding requirements for an
electro-hydraulic control
system?
Sec. 250.839 What are the
maximum allowable valve
closure times and hydraulic
bleeding requirements for a
direct-hydraulic control
system?
Sec. 250.854 Floating
production units equipped with
turrets and turret mounted
systems.
Sec. 250.860 Chemical
firefighting system.
Sec. 250.861 Foam
firefighting system.
Sec. 250.865 Surface pumps.
Sec. 250.866 Personal safety
equipment.
Sec. 250.867 Temporary
quarters and temporary
equipment.
Sec. 250.868 Non-metallic
piping.
Sec. 250.870 Time delays on
pressure safety low (PSL)
sensors.
Sec. 250.872 Atmospheric
vessels.
Sec. 250.873 Subsea gas lift
requirements.
Sec. 250.874 Subsea water
injection systems.
Sec. 250.875 Subsea pump
systems.
Sec. 250.876 Fired and
Exhaust Heated Components.
------------------------------------------------------------------------
Availability of Incorporated Documents for Public Viewing
When a copyrighted technical industry standard is incorporated by reference into our regulations, BSEE is obligated to observe and protect that copyright. The BSEE provides members of the public with Web site addresses where these standards may be accessed for viewing--
sometimes for free and sometimes for a fee. The decision to charge a fee is decided by the standard developing organizations. The American Petroleum Institute (API) will provide free online public access to 160 key industry standards, including a broad range of technical standards. The standards available for public access represent almost one-third of all API standards and include all that are safety-related or have been incorporated into Federal regulations, including the standards in this rule. These standards are available for review, and hardcopies and printable versions will continue to be available for purchase. We are proposing to incorporate API standards in this proposed rule, and the address to the API Web site is: http://publications.api.org/documentslist.aspx. You may also call the API Standard/Document Contact IHS at 1-800-854-7179 or 303-397-7956 local and international.
For the convenience of the viewing public who may not wish to purchase or
Page 52243
view these proposed documents online, they may be inspected at the Bureau of Safety and Environmental Enforcement, 381 Elden Street, Room 3313, Herndon, Virginia 20170; phone: 703-787-1587; or at the National Archives and Records Administration (NARA).
For information on the availability of this material at NARA, call 202-741-6030, or go to: http://www.archives.gov/federal_register/code_of_federal_regulations/ibr_locations.html.
These documents, if incorporated in the final rule, would continue to be made available to the public for viewing when requested. Specific information on where these documents can be inspected or purchased can be found at 30 CFR 250.198, Documents Incorporated by Reference.
Section-by-Section Discussion
The following is a brief section-by-section description of the substantive proposed changes to subpart H, as well as other sections of the proposed rule. In several of the section descriptions below, BSEE requests comments on particular issues raised by that section.
What must I do to protect health, safety, property, and the environment? (Sec. 250.107)
The proposed rule would revise portions of Sec. 250.107 related to the use of best available and safest technology (BAST) by revising paragraph (c) and removing paragraph (d). The intent of the change is to more closely track the BAST provision in the OCSLA. That statutory provision requires:
on all new drilling and production operations and, wherever practicable, on existing operations, the use of the best available and safest technologies which the Secretary determines to be economically feasible, wherever failure of equipment would have a significant effect on safety, health, or the environment, except where the Secretary determines that the incremental benefits are clearly insufficient to justify the incremental costs of utilizing such technologies (43 U.S.C. 1347(b).)
Existing Sec. 250.107(c) requires the use of BAST ``whenever practical'' on ``all exploration, development, and production operations.'' Moreover, it provides that compliance with the regulations generally is considered to be the use of BAST. The existing provision is problematic for a number of reasons. The use of the phrase ``whenever practical'' provides an operator substantial discretion in the use of BAST. The statute, on the other hand, requires the use of BAST that DOI determines to be economically feasible on all new drilling and production operations. With respect to existing operations, the Act requires operators to use BAST ``wherever practicable,'' which does not afford the operator complete discretion in the use of systems equipment. In addition, although operators must comply with BSEE regulations, such compliance does not necessarily equate to the use of BAST. Existing paragraph (d) is written in terms of additional measures the Director can require under the Act, and includes a general requirement that the benefits of such measures outweigh the costs.
The proposed rule would more closely track the Act. Proposed Sec. 250.107(c) would provide that wherever failure of equipment may have a significant effect on safety, health, or the environment, an operator must use the BAST that BSEE determines to be economically feasible on all new drilling and production operations, and wherever practicable, on existing operations. Under this proposed provision, BSEE would specify what is economically feasible BAST. This could be accomplished generally, for instance, through the use of NTLs, or on a case-specific basis. To implement the exception allowed by the Act, proposed Sec. 250.107(c)(2) would allow an operator to request an exception from the use of BAST by demonstrating to BSEE that the incremental benefits of using BAST are clearly insufficient to justify the incremental costs of utilizing such technologies.
Service Fees (Sec. 250.125)
This section would be revised to update the service fee citation to Sec. 250.842 in paragraphs (a)(10) through (a)(15).
Documents Incorporated by Reference (Sec. 250.198)
This section would be revised to update cross-references to subpart H. The proposed rule would also add by incorporation, ``American Petroleum Institute (API) 570, Piping Inspection Code: In-service Inspection, Rating, Repair, and Alteration of Piping Systems.''
Tubing and Wellhead Equipment (Sec. 250.517)
This section would be revised to update the cross-reference to the appropriate subpart H sections from Sec. 250.801 in current regulations to Sec. Sec. 250.810 through 250.839 in the proposed rule.
Tubing and Wellhead Equipment (Sec. 250.618)
This section would be revised to update the cross-reference to the appropriate subpart H sections from Sec. 250.801 in current regulations to Sec. Sec. 250.810 through 250.839 in the proposed rule.
Subpart H--General Requirements
General (Sec. 250.800)
This section would clarify the design requirements for production safety equipment and specify the appropriate industry standards that must be followed. A provision would be added that would require operators to comply with American Petroleum Institute Recommended Practice (API RP) 14J, Recommended Practice for Design and Hazards Analysis for Offshore Production Facilities, for all new production systems on fixed leg platforms and floating production systems (FPSs). This section would clarify requirements for operators to comply with the drilling, well completion, well workover, and well production riser standards of API RP 2RD, Recommended Practice for Design of Risers for Floating Production Systems (FPSs) and Tension-Leg Platforms (TLPs). However, this new section would prohibit the installation of single bore production risers from floating production facilities, effective 1 year from publication of the final rule. The BSEE believes that a single bore production riser does not provide an acceptable level of safety to operate on the OCS when an operator has to perform work through the riser. When an operator performs work through a single bore production riser, wear on the riser may occur that compromises the integrity of the riser. This section would also revise stationkeeping system design requirements for floating production facilities by adding a reference to API RP 2SM, Recommended Practice for Design, Manufacture, Installation, and Maintenance of Synthetic Fiber Ropes for Offshore Mooring, in proposed Sec. 250.800(c)(3).
Safety and Pollution Prevention Equipment (SPPE) Certification (Sec. 250.801)
Existing Sec. 250.806, pertaining to SPPE certification, would be recodified as proposed Sec. 250.801 and rewritten in plain language. Additional subsections would be added to clarify that SPPE includes SSV and actuators, including those installed on injection wells that are capable of natural flow, and, following a 1-year grace period, boarding shut down valves (BSDVs). The final rule would specify the end date of the grace period. This section would also specify that BSEE would not
Page 52244
allow subsurface-controlled subsurface safety valves on subsea wells.
The existing regulations recognize two quality assurance programs: (1) API Spec. Q1 and (2) American National Standards Institute/American Society of Mechanical Engineers (ANSI/ASME) SPPE-1-1994 and SPPE-1d-
1996 Addenda. The proposed rule would remove the reference to the ANSI/
ASME standards because they are defunct, but would continue to provide that SPPE equipment, which is manufactured and marked pursuant to API Spec. Q1, Specification for Quality Programs for the Petroleum, Petrochemical and Natural Gas Industry (ISO TS 29001:2007), would be considered certified SPPE under part 250. The BSEE presumptively considers all other SPPE as noncertified. Notwithstanding this presumption, under proposed Sec. 250.801(c), BSEE may exercise its discretion to accept SPPE manufactured under quality assurance programs other than API Spec. Q1 (ISO TS 29001:2007), provided an operator submits a request to BSEE containing relevant information about the alternative program, and receives BSEE approval under Sec. 250.141.
Requirements for SPPE (Sec. 250.802)
Existing Sec. 250.806(a)(3), cross-referencing API requirements for SPPE, would be recodified as proposed Sec. Sec. 250.802(a) and (b).
Proposed Sec. 250.802(c) would include a summary of some of the requirements that are contained in documents that are currently incorporated by reference to provide examples of the types of requirements that are contained in these documents. These requirements would address a range of activities over the entire lifecycle of the equipment that are intended to increase the reliability of the equipment through lifecycle analysis. These include:
Independent third party review and certification;
Manufacturing controls;
Design verification and testing;
Traceability requirements;
Installation and testing protocols; and
Requirements for the use of qualified parts and personnel to perform repairs.
The lifecycle analysis for SPPE would consider the ``cradle-to-
grave'' implications of the associated equipment. Lifecycle analysis would also be a tool to evaluate the operational use, maintenance, and repair of SPPE from an equipment lifecycle perspective. Requirements that address the full lifecycle of critical equipment are essential to increase the overall level of certainty that this equipment would perform in emergency situations and would provide documentation from manufacture through the end of the operational limits of the SPPE equipment.
Proposed Sec. 250.802(c)(1) would require that each device be designed to function and to close at the most extreme conditions to which it may be exposed. This includes extreme temperature, pressure, flow rates, and environmental conditions. Under the proposed rule, an operator would be required to have an independent third party review and certify that each device will function as designed under the conditions to which it may be exposed. The independent third party would be required to have sufficient expertise and experience to perform the review and certification.
A table would be added in proposed Sec. 250.802(d) to clarify when operators must install certified SPPE equipment. Under the proposed rule, non-certified SPPE already in service at a well could remain in service, but if the equipment requires offsite repair, re-
manufacturing, or any hot work such as welding, it must be replaced with certified SPPE.
Proposed Sec. 250.802(e) would require that operators must retain all documentation related to the manufacture, installation, testing, repair, redress, and performance of SPPE equipment until 1 year after the date of decommissioning of the equipment.
What SPPE failure reporting procedures must I follow? (Sec. 250.803)
Proposed Sec. 250.803 would establish SPPE failure reporting procedures. Proposed Sec. 250.803(a) would require operators to follow the failure reporting requirements contained in Section 10.20.7.4 of API Spec. 6A for SSVs, BSDVs, and USVs and Section 7.10 of API Spec. 14A and Annex F of API RP 14B for SSSVs, and to provide a written report of equipment failure to the manufacturer of such equipment within 30 days after the discovery and identification of the failure. The proposed rule would define a failure as any condition that prevents the equipment from meeting the functional specification. This is intended to assure that design defects are identified and corrected and to assure that equipment is replaced before it fails.
Proposed Sec. 250.803(b) would require operators to ensure that an investigation and a failure analysis are performed within 60 days of the failure to determine the cause of the failure and that the results and any corrective action are documented. If the investigation and analysis is performed by an entity other than the manufacturer, the proposed rule would require operators to ensure that the manufacturer receives a copy of the analysis report.
Proposed Sec. 250.803(c) would specify that if an equipment manufacturer notifies an operator that it has changed the design of the equipment that failed, or if the operator has changed operating or repair procedures as a result of a failure, then the operator must, within 30 days of such changes, report the design change or modified procedures in writing to BSEE.
Additional Requirements for Subsurface Safety Valves (SSSVs) and Related Equipment Installed in High Pressure High Temperature (HPHT) Environments (Sec. 250.804)
Existing Sec. 250.807 would be recodified as proposed Sec. 250.804, with no significant revisions proposed.
Hydrogen Sulfide (Sec. 250.805)
Existing Sec. 250.808, pertaining to production operations in zones known to contain hydrogen sulfide (H2S) or in zones where the presence of H2S is unknown, as defined in Sec. 250.490, would be recodified as proposed Sec. 250.805. This section would also clarify that the operator must receive approval through the Deepwater Operations Plan (DWOP) process for production operations in HPHT environments containing H2S, or in HPHT environments where the presence of H2S is unknown.
RESERVED Sec. Sec. 250.806--250.809
Surface and Subsurface Safety Systems--Dry Trees
Dry Tree Subsurface Safety Devices--General (Sec. 250.810)
Existing Sec. 250.801(a) would be recodified as proposed Sec. 250.810, and restructured for clarity. This section would also add the equipment flow coupling above and below to the list of devices associated with subsurface safety devices.
Specifications for Subsurface Safety Valves (SSSVs)--Dry Trees (Sec. 250.811)
Existing Sec. 250.801(b) would be recodified as proposed Sec. 250.811. This section would also add the equipment flow coupling above and below to the list of devices associated with subsurface safety devices. Section 250.811 would permit BSEE to approve non-certified SSSVs in accordance with the process specified in 250.141 regarding alternative procedures or equipment.
Page 52245
Surface-Controlled SSSVs--Dry Trees (Sec. 250.812)
Existing Sec. 250.801(c) would be recodified as proposed Sec. 250.812. A change from current regulations would require BSEE approval for locating the surface controls at a remote location. The request and approval to locate surface controls at a remote location would be made in accordance with 250.141, regarding alternative procedures or equipment.
Subsurface-Controlled SSSVs (Sec. 250.813)
Existing Sec. 250.801(d) would be recodified as proposed Sec. 250.813, and rewritten using plain language.
Design, Installation, and Operation of SSSVs--Dry Trees (Sec. 250.814)
Existing Sec. 250.801(e) would be recodified as proposed Sec. 250.814. Proposed Sec. 250.814(c) would also add a definition of routine operation similarly to what is found under the definitions section at Sec. 250.601.
Subsurface Safety Devices in Shut-in Wells--Dry Trees (Sec. 250.815)
Existing Sec. 250.801(f) would be recodified as proposed Sec. 250.815, and rewritten in plain language.
Subsurface Safety Devices in Injection Wells--Dry Trees (Sec. 250.816)
Existing Sec. 250.801(g) would be recodified as proposed Sec. 250.816, and rewritten in plain language.
Temporary Removal of Subsurface Safety Devices for Routine Operations (Sec. 250.817)
Existing Sec. 250.801(h) would be recodified as proposed Sec. 250.817. The title of the section would be changed for clarity. In proposed Sec. 250.817(c), the term ``support vessel'' would be added as another option for attendance on a satellite structure.
Additional Safety Equipment--Dry Trees (Sec. 250.818)
Existing Sec. 250.801(i) would be recodified as proposed Sec. 250.818, with no significant revisions proposed.
Specification for Surface Safety Valves (SSVs) (Sec. 250.819)
The portion of existing Sec. 250.802(c) related to wellhead SSVs and their actuators would be included in proposed Sec. 250.819. The portion of the existing Sec. 250.802(c) related to underwater safety valves would be placed in proposed Sec. 250.833.
Use of SSVs (Sec. 250.820)
The portion of existing Sec. 250.802(d) related to SSVs would be included in proposed Sec. 250.820. The portion of the existing Sec. 250.802(d) related to underwater safety valves would be placed in proposed Sec. 250.834.
Emergency Action (Sec. 250.821)
Existing Sec. 250.801(j) would be recodified as proposed Sec. 250.821. The example of an emergency would be revised to refer to a National Weather Service-named tropical storm or hurricane because not all impending storms constitute emergencies. A requirement would be added that oil and gas wells requiring compression must be shut-in in the event of an emergency unless otherwise approved by the District Manager. This section would also include, from existing Sec. 250.803(b)(4)(ii), the valve closure times for dry tree emergency shutdowns.
RESERVED Sec. Sec. 250.822--250.824
Subsea and Subsurface Safety Systems--Subsea Trees
Subsea Tree Subsurface Safety Devices--General (Sec. 250.825)
Proposed Sec. 250.825(a) is derived from existing Sec. 250.801(a). This section would provide clarification on subsurface safety devices on subsea trees. Requirements for dry trees subsea safety systems can be found at Sec. Sec. 250.810 through 250.821. This section would also add the equipment flow coupling above and below to the list of devices associated with subsurface safety devices. Proposed Sec. 250.825(a) would also permit operators to seek BSEE approval to use alternative procedures or equipment in accordance with 250.141 if the subsea safety systems proposed for use vary from the regulatory requirements, including those pertaining to dry subsea safety systems found at Sec. Sec. 250.810 through 250.821.
Proposed Sec. 250.825(b) would provide that, after installing the subsea tree, but before the rig or installation vessel leaves the area, an operator must test all valves and sensors to ensure that they are operating as designed and meet all the conditions specified in subpart H. Proposed Sec. 250.825(b) would permit an operator to seek BSEE approval of a departure under 250.142 in the event the operator cannot perform these tests.
Specifications for SSSVs--Subsea Trees (Sec. 250.826)
Proposed Sec. 250.826 would be developed from existing Sec. 250.801(b). The portions of Sec. 250.801(b) pertaining to subsurface-
controlled SSSVs for dry tree wells would be moved to proposed Sec. 250.811. Subsurface-controlled SSSVs are not allowed on wells with subsea trees.
Surface-Controlled SSSVs--Subsea Trees (Sec. 250.827)
This section would be derived from existing Sec. 250.801(c). A change from the existing provision would require BSEE approval for locating the surface controls at a remote location.
Design, Installation, and Operation of SSSVs--Subsea Trees (Sec. 250.828)
Existing Sec. 250.801(e) would be recodified as proposed Sec. 250.828, with changes made to reflect that this section covers subsea tree installations. One change from existing regulations would establish that a well with a subsea tree must not be open to flow while an SSSV is inoperable. The BSEE would not allow exceptions.
Subsurface Safety Devices in Shut-in Wells--Subsea Trees (Sec. 250.829)
Existing Sec. 250.801(f) would be recodified as proposed Sec. 250.829. The BSEE would also clarify when a surface-controlled SSSV is considered inoperative. This explanation would be added because the hydraulic control pressure to an individual subsea well may not be able to be isolated due to the complexity of the subsea hydraulic distribution of subsea fields.
Subsurface Safety Devices in Injection Wells--Subsea Trees (Sec. 250.830)
This section would be derived from existing Sec. 250.801(g). The substance of proposed Sec. 250.830 for subsea tree wells would be substantially similar to the regulatory sections pertaining to proposed Sec. 250.816 for dry tree wells. This is one example in which BSEE has consolidated similar provisions for easier public understanding.
Alteration or Disconnection of Subsea Pipeline or Umbilical (Sec. 250.831)
This is a new section that would be added to codify policy and guidance from an existing BSEE Gulf of Mexico Region NTL, ``Using Alternate Compliance in Safety Systems for Subsea Production Operations,'' NTL No. 2009-G36. The proposed provision would provide that if a necessary alteration or disconnection of the pipeline or umbilical of any subsea well would affect an operator's ability to monitor casing pressure or to test any subsea valves or equipment, the operator must contact the appropriate BSEE District Office at least 48 hours in advance and submit a repair or
Page 52246
replacement plan to conduct the required monitoring and testing.
Additional Safety Equipment--Subsea Trees (Sec. 250.832)
This section would be derived from existing Sec. 250.801(i), with changes made to reflect that this section covers subsea tree installations. The last sentence of existing Sec. 250.801(i), generally requiring closure of surface-controlled SSSVs in certain circumstances, would not be needed for wells with subsea trees, because more specific surface-controlled SSSV closure requirements would be established in proposed Sec. Sec. 250.838 and 250.839, described later.
Specification for Underwater Safety Valves (USVs) (Sec. 250.833)
Proposed Sec. 250.833 derives in part from existing Sec. 250.802(c) with references to surface safety valves removed to separate out requirements for the use of dry or subsea trees. The portions of the existing rule concerning surface safety valves for dry trees would be contained in proposed Sec. 250.819. Proposed Sec. 250.833 would also clarify the designations of the primary USV (USV1), the secondary USV (USV2), and that an alternate isolation valve (AIV) may qualify as a USV. Proposed Sec. 250.833(a) would require that operators must install at least one USV on a subsea tree and designate it as the primary USV, and that BSEE must be kept informed if the primary USV designation changes.
Much of the material included in proposed Sec. Sec. 250.833 through 250.839 derives from existing NTL No. 2009-G36, and is currently implemented through the DWOP process described under Sec. Sec. 250.286 through 250.295. Inclusion of this material in subpart H would better inform the regulated community of BSEE's expectations, and seeking public comment through this rulemaking will allow for possible improvements.
Use of USVs (Sec. 250.834)
Proposed Sec. 250.834, pertaining to the inspection, installation, maintenance, and testing of USVs, derives from existing Sec. 250.802(d) with references to surface safety valves removed to separate out requirements for the use of dry or subsea trees. This section would add references to USVs designated as primary, secondary, and any alternate isolation valve (AIV) that acts as a USV and also would add a reference to DWOPs.
Specification for All Boarding Shut Down Valves (BSDVs) Associated With Subsea Systems (Sec. 250.835)
Proposed Sec. 250.835 would be a new section which would establish minimum design and other requirements for BSDVs and their actuators. This section would impose the requirements for the use of a BSDV, which assumes the role of the SSV required by 30 CFR Part 250, Subpart H for a traditional dry tree. This would ensure the maximum level of safety for the production facility and the people aboard the facility. Because the BSDV is the most critical component of the subsea system, it is necessary that this valve be subject to rigorous design and testing criteria.
Use of BSDVs (Sec. 250.836)
Proposed Sec. 250.836 would establish a new requirement that all BSDVs must be inspected, maintained, and tested according to the provisions of API RP 14H. This section also specifies what the operator would do if a BSDV does not operate properly or if fluid flow is observed during the leakage test.
Emergency Action and Safety System Shutdown (Sec. 250.837)
Proposed Sec. 250.837 would replace existing Sec. 250.801(j) for subsea tree installations. New requirements would be added to clarify allowances for valve closing sequences for subsea installations and specify actions required for certain situations. Proposed Sec. 250.837(c) and (d) would describe a number of emergency situations requiring that shutdowns occur and safety valves be closed, and in certain situations that hydraulic systems be bled.
What are the Maximum Allowable Valve Closure Times and Hydraulic Bleeding Requirements for an Electro-hydraulic Control System? (Sec. 250.838)
Proposed Sec. 250.838 would establish maximum allowable valve closure times and hydraulic system bleeding requirements for electro-
hydraulic control systems. Proposed paragraph (b) would apply to electro-hydraulic control systems when an operator has not lost communication with its rig or platform. Proposed paragraph (c) would apply to electro-hydraulic control systems when an operator has lost communication with its rig or platform. Each paragraph would include a table containing valve closure times for BSDVs, USVs, and surface-
controlled SSSVs under the various scenarios described in proposed Sec. 250.837(c). The tables derive from Appendices to NTL No. 2009-
G36.
What are the maximum allowable valve closure times and hydraulic bleeding requirements for direct-hydraulic control system? (Sec. 250.839)
Proposed Sec. 250.839 would establish maximum allowable valve closure times and hydraulic system bleeding requirements for direct-
hydraulic control systems. It would contain a valve closure table comparable to those contained in proposed Sec. 250.838.
Production Safety Systems
Design, Installation, and Maintenance--General (Sec. 250.840)
Existing Sec. 250.802(a) would be recodified as proposed Sec. 250.840. Several new production components (pumps, heat exchangers, etc.) would be added to this section.
Platforms (Sec. 250.841)
Existing Sec. 250.802(b) would be recodified as proposed Sec. 250.841. New requirements for facility process piping would be added in proposed Sec. 250.841(b). The new paragraph would require adherence to existing industry documents, API RP 14E, Design and Installation of Offshore Production Platform Piping Systems and API 570, Piping Inspection Code: In-service Inspection, Rating, Repair, and Alteration of Piping Systems. Both of these documents would be incorporated by reference in Sec. 250.198. The proposed rule would also specify that the BSEE District Manager could approve temporary repairs to facility piping on a case-by-case basis for a period not to exceed 30 days.
Approval of Safety Systems Design and Installation Features (Sec. 250.842)
Existing Sec. 250.802(e) would be recodified as proposed Sec. 250.842, including the service fee associated with the submittal of the production safety system application. The proposed rule would require adherence to API Recommended Practice documents pertaining to the design of electrical installations. The proposed rule would also require completion of a hazard analysis during the design process and require that a hazards analysis program be in place to assess potential hazards during the operation of the platform. A table would be placed in the proposed rule for clarity, amplifying some of the current requirements. This section would also add the requirements that the designs for the mechanical and electrical systems were reviewed, approved, and stamped by a registered professional engineer. Also, it would add a requirement that the as-built piping and instrumentation diagrams
Page 52247
(P&IDs) must be certified correct and stamped by a registered professional engineer. This section would also specify that the registered professional engineer, in both instances, must be registered in a State or Territory of the United States and have sufficient expertise and experience to perform the duties. The importance of these new provisions were highlighted in the Atlantis investigation report ``BP'S Atlantis Oil And Gas Production Platform: An Investigation of Allegations that Operations Personnel Did Not Have Access to EngineerhyphenApproved 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 Under subpart A, (Sec. 250.107(c)), we have added proposed BAST requirements (+10 hours).
Under General Requirements (Sec. 250.802-803), we have added proposed SPPE life cycle analysis requirements (+132 hours).
A proposed new section, Subsea and Subsurface Safety Systems--Subsea Trees (Sec. Sec. 250.825-833) would add new burden requirements (+24 hours).
Under Production Safety Systems (Sec. 250.842), we added proposed certification requirements as well as documentation of these requirements (+608 hours).
In various proposed requirements, requests for unique, specific approvals (+61 hours).
A proposed new section, (Sec. 250.861(b)) would add new requirements pertaining to submission of foam samples annually for testing (+1,000 hours).
A proposed new section, (Sec. 250.867) would add new requirements pertaining to submittals for temporary quarters, firewater systems, or equipment (+307 hours).
A proposed new section, (Sec. 250.870) added documentation requirements (+3 hours).
In Sec. 250.860, we proposed submittal notification and/
or recordkeeping of minor and major changes using chemical only fire prevention system (+7 hours).
Proposed new, (Sec. 250.890) added an annual contact list submittal (+550 hours).
Current subpart H regulations have 62,963 hours and $343,794 non-
hour cost burdens approved by OMB. This revision to the collection requests a total of 65,665 hours which is a burden hour net increase of 2,702 hours. The non-hour cost burdens are unchanged. With the exception of items identified as NEW in the following chart, the burden estimates shown are those that are estimated for the current subpart H regulations.
----------------------------------------------------------------------------------------------------------------
Reporting and
Citation 30 CFR 250, subpart recordkeeping Hour burden Average number of annual Annual burden
A requirement responses hours
----------------------------------------------------------------------------------------------------------------
107(c)(2).................... NEW: Demonstrate to 5 2 justifications.......... 10
us that by using
BAST the benefits
are insufficient to
justify the cost.
----------------------------------------------------------------------------------------------------------------
Subtotal................. 2 responses............... 10
----------------------------------------------------------------------------------------------------------------
Citation 30 CFR 250 Subpart H Reporting and Hour Burden Average number of annual Annual burden
and NTL(s) Recordkeeping responses hours
Requirement
-----------------------------------------------------------
Non-Hour Cost Burdens*
----------------------------------------------------------------------------------------------------------------
General Requirements
----------------------------------------------------------------------------------------------------------------
800(a)....................... Requirements for your Burden included with specific requirements 0
production safety below.
system application.
----------------------------------------------------------------------------------------------------------------
800(a); 880(a)............... Prior to production, 1 76 requests............... 76
request approval of
pre-production
inspection; notify
BSEE 72 hours before
commencement so we
may witness
preproduction test
and conduct
inspection.
----------------------------------------------------------------------------------------------------------------
Page 52257
801(c)....................... Request evaluation 2 1 request................. 2
and approval OORP
of other quality
assurance programs
covering manufacture
of SPPE.
----------------------------------------------------------------------------------------------------------------
802(c)(1); 852(e)(4); 861(b). NEW: Submit statement/ Not considered IC under 5 CFR 0
certification for: 1320.3(h)(1).
exposure
functionality; pipe
is suitable and
manufacturer has
complied with IVA;
suitable
firefighting foam
per original
manufacturer
specifications.
----------------------------------------------------------------------------------------------------------------
802(c)(5).................... NEW: Document all 2 30 documents.............. 60
manufacturing,
traceability,
quality control, and
inspection
requirements. Retain
required
documentation until
1 year after the
date of
decommissioning the
equipment.
----------------------------------------------------------------------------------------------------------------
803(a)....................... NEW: Within 30 days 2 10 reports................ 20
of discovery and
identification of
SPPE failure,
provide a written
report of equipment
failure to
manufacturer.
----------------------------------------------------------------------------------------------------------------
803(b)....................... NEW: Document and 5 10 documents.............. 50
determine the
results of the SPPE
failure within 60-
days and corrective
action taken.
----------------------------------------------------------------------------------------------------------------
803(c)....................... NEW: Submit OORP 2 1 submittal............... 2
modified procedures
you made if notified
by manufacturer of
design changes or
you changed
operating or repair
procedures as result
of a failure, within
30 days.
----------------------------------------------------------------------------------------------------------------
804.......................... Submit detailed info Burdens are covered under 30 CFR Part 250, 0
regarding installing Subparts D and B, 1014-0018 and 1014-0024.
SSVs in an HPHT
environment with
your APD, APM, DWOP
etc.
----------------------------------------------------------------------------------------------------------------
804(b); 829(b), (c); 841(b).. NEW: District Manager Not considered IC per 5 CFR 1320.3(h)(6). 0
will approve on a
case-by-case basis.
----------------------------------------------------------------------------------------------------------------
Subtotal................. ..................... .............. 128 responses............. 210
----------------------------------------------------------------------------------------------------------------
Surface and Subsurface Safety Systems--Dry Trees
----------------------------------------------------------------------------------------------------------------
810; 816; 825(a); 830........ Submit request for a 5\3/4\ 41 wells.................. 246
determination that a
well is incapable of
natural flow.
---------------------------------------
Verify the no-flow \1/4\
condition of the
well annually.
----------------------------------------------------------------------------------------------------------------
814(a); 821; 828(a); Specific alternate Burden covered under 30 CFR part 250, 0
838(c)(3); 859(b); 870(b). approval requests subpart A, 1014-0022.
requiring approval.
----------------------------------------------------------------------------------------------------------------
817(b); 869(a)............... Identify well with Usual/customary safety procedure for 0
sign on wellhead removing or identifying out-of-service
that subsurface safety devices.
safety device is
removed; flag safety
devices that are out
of service; a visual
indicator must be
used to identify the
bypassed safety
device.
----------------------------------------------------------------------------------------------------------------
817(b)....................... Record removal of Burden included in Sec. 250.890 of this 0
subsurface safety subpart.
device.
----------------------------------------------------------------------------------------------------------------
817(c)....................... Request alternate Burden covered under 30 CFR part 250, 0
approval of master subpart D, 1014-0018.
valve required to
be submitted with an
APM.
----------------------------------------------------------------------------------------------------------------
Subtotal................. ..................... .............. 41 responses.............. 246
----------------------------------------------------------------------------------------------------------------
Subsea and Subsurface Safety Systems--Subsea Trees
----------------------------------------------------------------------------------------------------------------
Notifications
--------------------------------------------
825(b); 831; 833; 837(c)(5); NEW: Notify BSEE: (1) (1) \1/2\ 6......................... 7
838(c); 874(g)(2); 874(f). If you cannot test (2) 2 1.........................
all valves and (3) 1 1.........................
sensors; (2) 48 (4) \1/2\ 1.........................
hours in advance if (5) \1/2\ 1.........................
monitoring ability
affected; (3)
designating USV2 or
another qualified
valve; (4) resuming
production; (5) 12
hours of detecting
loss of
communication;
immediately if you
cannot meet value
closure conditions.
----------------------------------------------------------------------------------------------------------------
827.......................... NEW: Request remote 1 1 request................. 1
location approval.
----------------------------------------------------------------------------------------------------------------
Page 52258
831.......................... NEW: Submit a repair/ 2 1 submittal............... 2
replacement plan to
monitor and test.
----------------------------------------------------------------------------------------------------------------
837(a)....................... NEW: Request approval \1/2\ 10 requests............... 5
to not shut-in a
subsea well in an
emergency.
----------------------------------------------------------------------------------------------------------------
837(b)....................... NEW: Prepare and 2 1 submittal............... 2
submit for approval
a plan to shut-in
wells affected by a
dropped object.
----------------------------------------------------------------------------------------------------------------
837(c)(2).................... NEW: Obtain approval \1/2\ 2 approvals............... 1
to resume production
re P/L PSHL sensor.
----------------------------------------------------------------------------------------------------------------
838(a); 839(a)(2)............ NEW: Verify closure 2 2 verifications........... 4
time of USV upon
request of District
Manager.
----------------------------------------------------------------------------------------------------------------
838(c)(3).................... NEW: Request approval 2 1 approval................ 2
to produce after
loss of
communication;
include alternate
valve closure table.
----------------------------------------------------------------------------------------------------------------
Subtotal................. ..................... .............. 28 responses.............. 24
----------------------------------------------------------------------------------------------------------------
Production Safety Systems
----------------------------------------------------------------------------------------------------------------
842.......................... Submit application, 16 1 application............. 16
and all required/
supporting
information, for a
production safety
system with > 125
components.
-----------------------------------------------------------
$5,030 per submission x 1 = $5,030
$13,238 per offshore visit x 1 = $13,238
$6,884 per shipyard visit x 1 = $6,884
----------------------------------------------------------------------------------
25-125 components.... 13 10 applications........... 130
-----------------------------------------------------------
$1,218 per submission x 10 = $12,180
$8,313 per offshore visit x 1 = $8,313
$4,766 per shipyard visit x 1 = $4,766
----------------------------------------------------------------------------------
125
components.
-----------------------------------------------------------
$561 per submission x 180 = $100,980
----------------------------------------------------------------------------------
25-125 components.... 7 758 modifications......... 5,306
-----------------------------------------------------------
$201 per submission x 758 = $152,358
----------------------------------------------------------------------------------
2S) or in zones where the presence of H2S is unknown, as defined in Sec. 250.490 of this part, in accordance with that section and other relevant requirements of this subpart.
(b) You must receive approval through the DWOP process (Sec. Sec. 250.286-250.295) for production operations in HPHT environments known to contain H2S or in HPHT environments where the presence of H2S is unknown.
Sec. Sec. 250.806-250.809 Reserved
Surface and Subsurface Safety Systems--Dry Trees
Sec. 250.810 Dry tree subsurface safety devices--general.
For wells using dry trees or for which you intend to install dry trees, you must equip all tubing installations open to hydrocarbon-
bearing zones with subsurface safety devices that will shut off the flow from the well in the event of an emergency unless, after you submit a request containing a justification, the District Manager determines the well to be incapable of natural flow. These subsurface safety devices include the following devices and any associated safety valve lock, flow coupling above and below, and landing nipple:
(a) An SSSV, including either:
(1) A surface-controlled SSSV; or
(2) A subsurface-controlled SSSV.
(b) An injection valve.
(c) A tubing plug.
(d) A tubing/annular subsurface safety device.
Sec. 250.811 Specifications for subsurface safety valves (SSSVs)--dry trees.
All surface-controlled and subsurface-controlled SSSVs, safety valve locks, landing nipples, and flow couplings installed in the OCS must conform to the requirements in Sec. Sec. 250.801 through 250.803. You may request that BSEE approve non-conforming SSSVs in accordance with Sec. 250.141, regarding alternative procedures or equipment.
Sec. 250.812 Surface-controlled SSSVs--dry trees.
You must equip all tubing installations open to a hydrocarbon-
bearing zone that is capable of natural flow with a surface-controlled SSSV, except as specified in Sec. Sec. 250.813, 250.815, and 250.816.
(a) The surface controls must be located on the site or at a BSEE-
approved remote location. You may request that BSEE approve situating the surface controls at a remote location in
Page 52266
accordance with Sec. 250.141, regarding alternative procedures or equipment.
(b) You must equip dry tree wells not previously equipped with a surface-controlled SSSV, and dry tree wells in which a surface-
controlled SSSV has been replaced with a subsurface-controlled SSSV with a surface-controlled SSSV when the tubing is first removed and reinstalled.
Sec. 250.813 Subsurface-controlled SSSVs.
You may request BSEE approval to equip a dry tree well with a subsurface-controlled SSSV in lieu of a surface-controlled SSSV, in accordance with Sec. 250.141 regarding alternative procedures or equipment, if the subsurface-controlled SSSV installed in a well equipped with a surface-controlled SSSV has become inoperable and cannot be repaired without removal and reinstallation of the tubing. If you remove and reinstall the tubing, you must equip the well with a surface-controlled SSSV.
Sec. 250.814 Design, installation, and operation of SSSVs--dry trees.
You must design, install, operate, repair, and maintain an SSSV to ensure its reliable operation.
(a) You must install the SSSV at a depth at least 100 feet below the mudline within 2 days after production is established. When warranted by conditions such as permafrost, unstable bottom conditions, hydrate formation, or paraffin problems, the District Manager may approve an alternate setting depth in accordance with Sec. 250.141 or Sec. 250.142.
(b) Until the SSSV is installed, the well must be attended in the immediate vicinity so that any necessary emergency actions can be taken while the well is open to flow. During testing and inspection procedures, the well must not be left unattended while open to production unless you have installed a properly operating SSSV in the well.
(c) The well must not be open to flow while the SSSV is removed, except when flowing the well is necessary for a particular operation such as cutting paraffin or performing other routine operations as defined in Sec. 250.601.
(d) You must install, maintain, inspect, repair, and test all SSSVs in accordance with API RP 14B, Recommended Practice for Design, Installation, and Operation of Subsurface Safety Valve Systems (ISO 10417:2004) (incorporated by reference as specified in Sec. 250.198).
Sec. 250.815 Subsurface safety devices in shut-in wells--dry trees.
(a) You must equip all new dry tree completions (perforated but not placed on production) and completions shut-in for a period of 6 months with one of the following:
(1) A pump-through-type tubing plug;
(2) A surface-controlled SSSV, provided the surface control has been rendered inoperative; or
(3) An injection valve capable of preventing backflow.
(b) When warranted by conditions such as permafrost, unstable bottom conditions, hydrate formation, and paraffin problems the District Manager will approve the setting depth of the subsurface safety device for a shut-in well on a case-by-case basis.
Sec. 250.816 Subsurface safety devices in injection wells--dry trees.
You must install a surface-controlled SSSV or an injection valve capable of preventing backflow in all injection wells. This requirement is not applicable if the District Manager determines that the well is incapable of natural flow. You must verify the no-flow condition of the well annually.
Sec. 250.817 Temporary removal of subsurface safety devices for routine operations.
(a) You may remove a wireline- or pumpdown-retrievable subsurface safety device without further authorization or notice, for a routine operation that does not require BSEE approval of a Form BSEE-0124, Application for Permit to Modify (APM). For a list of these routine operations, see Sec. 250.601. The removal period must not exceed 15 days.
(b) You must identify the well by placing a sign on the wellhead stating that the subsurface safety device was removed. You must note the removal of the subsurface safety device in the records required by Sec. 250.890. If the master valve is open, you must ensure that a trained person (see Sec. 250.891) is in the immediate vicinity to attend the well and take any necessary emergency actions.
(c) You must monitor a platform well when a subsurface safety device has been removed, but a person does not need to remain in the well-bay area continuously if the master valve is closed. If the well is on a satellite structure, it must be attended with a support vessel or a pump-through plug installed in the tubing at least 100 feet below the mudline, and the master valve must be closed, unless otherwise approved by the appropriate District Manager.
(d) You must not allow the well to flow while the subsurface safety device is removed, except when it is necessary for the particular operation for which the SSSV is removed. The provisions of this paragraph are not applicable to the testing and inspection procedures specified in Sec. 250.880.
Sec. 250.818 Additional safety equipment--dry trees.
(a) You must equip all tubing installations that have a wireline- or pumpdown-retrievable subsurface safety device with a landing nipple, with flow couplings or other protective equipment above and below it to provide for the setting of the device.
(b) The control system for all surface-controlled SSSVs must be an integral part of the platform emergency shutdown system (ESD).
(c) In addition to the activation of the ESD by manual action on the platform, the system may be activated by a signal from a remote location. Surface-controlled SSSVs must close in response to shut-in signals from the ESD and in response to the fire loop or other fire detection devices.
Sec. 250.819 Specification for surface safety valves (SSVs).
All wellhead SSVs and their actuators must conform to the requirements specified in Sec. Sec. 250.801 through 250.803.
Sec. 250.820 Use of SSVs.
You must install, maintain, inspect, repair, and test all SSVs in accordance with API RP 14H, Recommended Practice for Installation, Maintenance and Repair of Surface Safety Valves and Underwater Safety Valves Offshore (incorporated by reference as specified in Sec. 250.198). If any SSV does not operate properly, or if any fluid flow is observed during the leakage test, then you must shut-in all sources to the SSV and repair or replace the valve before resuming production.
Sec. 250.821 Emergency action.
(a) In the event of an emergency, such as an impending named tropical storm or hurricane:
(1) Any well not yet equipped with a subsurface safety device and that is capable of natural flow must have the subsurface safety device properly installed as soon as possible, with due consideration being given to personnel safety.
(2) You must shut-in all oil wells and gas wells requiring compression, unless otherwise approved by the District Manager in accordance with Sec. Sec. 250.141 or 250.142. The shut-in may be accomplished by closing the SSV and SSSV.
(b) Closure of the SSV must not exceed 45 seconds after automatic detection of an abnormal condition or actuation of an ESD. The surface-
controlled SSSV must close within 2
Page 52267
minutes after the shut-in signal has closed the SSV. The District Manager must approve any design-delayed closure time greater than 2 minutes based on the mechanical/production characteristics of the individual well or subsea field in accordance with Sec. Sec. 250.141 or 250.142.
Sec. Sec. 250.822-250.824 Reserved
Subsea and Subsurface Safety Systems--Subsea Trees
Sec. 250.825 Subsea tree subsurface safety devices--general.
(a) For wells using subsea (wet) trees or for which you intend to install subsea trees, you must equip all tubing installations open to hydrocarbon-bearing zones with subsurface safety devices that will shut off the flow from the well in the event of an emergency unless. You may seek BSEE approval for using alternative procedures or equipment in accordance with Sec. 250.141 if you propose to use a subsea safety system that is not capable of shutting off the flow from the well in the event of an emergency, for instance where the well at issue is incapable of natural flow. Subsurface safety devices include the following and any associated safety valve lock, flow coupling above and below, and landing nipple:
(1) A surface-controlled SSSV;
(2) An injection valve;
(3) A tubing plug; and
(4) A tubing/annular subsurface safety device.
(b) After installing the subsea tree, but before the rig or installation vessel leaves the area, you must test all valves and sensors to ensure that they are operating as designed and meet all the conditions specified in this subpart. If you cannot perform these tests, you may seek BSEE approval for a departure from this operating requirement under Sec. 250.142
Sec. 250.826 Specifications for SSSVs--subsea trees.
All SSSVs, safety valve locks, flow couplings, and landing nipples must conform to the requirements specified in Sec. Sec. 250.801 through 250.803 and any Deepwater Operations Plan (DWOP) required by Sec. Sec. 250.286 through 250.295.
Sec. 250.827 Surface-controlled SSSVs--subsea trees.
All tubing installations open to a hydrocarbon-bearing zone that is capable of natural flow must be equipped with a surface-controlled SSSV, except as specified in Sec. Sec. 250.829 and 250.830. The surface controls must be located on the site, or you may seek BSEE approval for locating the controls at a remote location in a request to use alternative procedures or equipment under Sec. 250.141.
Sec. 250.828 Design, installation, and operation of SSSVs--subsea trees.
You must design, install, operate, and maintain an SSSV to ensure its reliable operation.
(a) You must install the SSSV at a depth at least 100 feet below the mudline. When warranted by conditions such as unstable bottom conditions, hydrate formation, or paraffin problems, you may seek BSEE approval for an alternate setting depth in a request to use alternative procedures or equipment under Sec. 250.141.
(b) The well must not be open to flow while an SSSV is inoperable.
(c) You must install, maintain, inspect, repair, and test all SSSVs in accordance with your Deepwater Operations Plan (DWOP) and API RP 14B, Recommended Practice for Design, Installation, Repair and Operation of Subsurface Safety Valve Systems (ISO 10417:2004) (incorporated by reference as specified in Sec. 250.198).
Sec. 250.829 Subsurface safety devices in shut-in wells--subsea trees.
(a) You must equip new completions (perforated but not placed on production) and completions shut-in for a period of 6 months with either:
(1) A pump-through-type tubing plug;
(2) An injection valve capable of preventing backflow; or
(3) A surface-controlled SSSV, provided the surface control has been rendered inoperative. For purposes of this section, a surface-
controlled SSSV is considered inoperative if for a direct hydraulic control system you have bled the hydraulics from the control line and have isolated it from the hydraulic control pressure or if your controls employ an electro-hydraulic control umbilical and the hydraulic control pressure to the individual well cannot be isolated, and you perform the following:
(i) Disable the control function of the surface-controlled SSSV within the logic of the programmable logic controller which controls the subsea well;
(ii) Place a pressure alarm high on the control line to the surface-controlled SSSV of the subsea well; and
(iii) Close the USV and at least one other tree valve on the subsea well.
(b) The appropriate BSEE District Manager may consider alternate methods on a case-by-case basis.
(c) When warranted by conditions such as unstable bottom conditions, hydrate formations, and paraffin problems, you may seek BSEE approval to use an alternate setting depth of the subsurface safety device for shut-in wells in a request to use alternative procedures or equipment under 250.141.
Sec. 250.830 Subsurface safety devices in injection wells--subsea trees.
You must install a surface-controlled SSSV or an injection valve capable of preventing backflow in all injection wells. This requirement is not applicable if the District Manager determines that the well is incapable of natural flow. You must verify the no-flow condition of the well annually.
Sec. 250.831 Alteration or disconnection of subsea pipeline or umbilical
If a necessary alteration or disconnection of the pipeline or umbilical of any subsea well affects your ability to monitor casing pressure or to test any subsea valves or equipment, you must contact the appropriate BSEE District Office at least 48 hours in advance and submit a repair or replacement plan to conduct the required monitoring and testing. You must not alter or disconnect until the repair or replacement plan is approved.
Sec. 250.832 Additional safety equipment--subsea trees.
(a) You must equip all tubing installations that have a wireline- or pumpdown-retrievable subsurface safety device installed after May 31, 1988, with a landing nipple, with flow couplings, or other protective equipment above and below it to provide for the setting of the SSSV.
(b) The control system for all surface-controlled SSSVs must be an integral part of the platform ESD.
(c) In addition to the activation of the ESD by manual action on the platform, the system may be activated by a signal from a remote location.
Sec. 250.833 Specification for underwater safety valves (USVs).
All USVs, including those designated as primary or secondary and any alternate isolation valve (AIV) that acts as a USV, if applicable, and their actuators must conform to the requirements specified in Sec. Sec. 250.801 through 250.803. A production master or wing valve may qualify as a USV under API Spec. 6AV1 (incorporated by reference as specified in Sec. 250.198).
(a) Primary USV (USV1). You must install and designate one USV on a subsea tree as the USV1. The USV1 must be located upstream of the choke valve.
(b) Secondary USV (USV2). You may equip your tree with two or more valves
Page 52268
qualified to be designated as a USV, one of which may be designated as USV2. If the USV1 fails to operate properly or exhibits a leakage rate greater than allowed in Sec. 250.880, you must notify the appropriate BSEE District Office and designate the USV2 or another qualified valve (e.g., an AIV) that meets all the requirements of this subpart for USVs as the USV1. This valve must be located upstream of the choke to be designated as a USV.
Sec. 250.834 Use of USVs.
You must install, maintain, inspect, repair, and test all USVs, including those designated as primary or secondary, and any AIV which acts as a USV if applicable in accordance with this subpart, your DWOP as specified in Sec. Sec. 250.286 through 250.295, and API RP 14H, Recommended Practice for Installation, Maintenance and Repair of Surface Safety Valves and Underwater Safety Valves Offshore (incorporated by reference as specified in Sec. 250.198).
Sec. 250.835 Specification for all boarding shut down valves (BSDVs) associated with subsea systems.
You must install a BSDV on the pipeline boarding riser. All BSDVs and their actuators installed in the OCS must meet the requirements specified in Sec. Sec. 250.801 through 250.803 and the following requirements. You must:
(a) Ensure that the internal design pressure of the pipeline(s), riser(s), and BSDV(s) is fully rated for the maximum pressure of any input source and comply with the design requirements set forth in Subpart J, unless BSEE approves an alternate design.
(b) Use a BSDV that is fire rated for 30 minutes, and is pressure rated for the maximum allowable operating pressure (MAOP) approved in your pipeline application.
(c) Locate the BSDV within 10 feet of the first point of access to the boarding pipeline riser (i.e., within 10 feet of the edge of platform if the BSDV is horizontal, or within 10 feet above the first accessible working deck, excluding the boat landing and above the splash zone, if the BSDV is vertical).
(d) Install a temperature safety element (TSE) and locate it within 5 feet of each BSDV.
Sec. 250.836 Use of BSDVs.
All BSDVs must be inspected, maintained, and tested in accordance with API RP 14H, Recommended Practice for Installation, Maintenance and Repair of Surface Safety Valves and Underwater Safety Valves Offshore (incorporated by reference as specified in Sec. 250.198) for SSVs. If any BSDV does not operate properly or if any fluid flow is observed during the leakage test, then you must shut-in all sources to the BSDV and repair or replace it before resuming production.
Sec. 250.837 Emergency action and safety system shutdown.
(a) In the event of an emergency, such as an impending named tropical storm or hurricane, you must shut-in all subsea wells unless otherwise approved by the District Manager. A shut-in is defined as a closed BSDV, USV, and surface-controlled SSSV.
(b) When operating a mobile offshore drilling unit (MODU) or other type of workover vessel in an area with producing subsea wells, you must:
(1) Suspend production from all such wells that could be affected by a dropped object, including upstream wells that flow through the same pipeline; or
(2) Establish direct, real-time communications between the MODU and the production facility control room and prepare a plan to be submitted to the appropriate District Manager for approval, as part of an application for a permit to drill or an application for permit to modify, to shut-in any wells that could be affected by a dropped object. If an object is dropped, the driller must immediately secure the well directly under the MODU using the ESD on the well control panel located on the rig floor while simultaneously communicating with the platform to shut-in all affected wells. You must also maintain without disruption and continuously verify communication between the platform and the MODU. If communication is lost between the MODU and the platform for 20 minutes or more, you must shut-in all wells that could be affected by a dropped object.
(c) In the event of an emergency, you must operate your production system according to the valve closure times in the applicable tables in Sec. Sec. 250.838 and 250.839 for the following conditions:
(1) Process Upset. In the event an upset in the production process train occurs downstream of the BSDV, you must close the BSDV in accordance with the applicable tables in Sec. Sec. 250.838 and 250.839. You may reopen the BSDV to blow down the pipeline to prevent hydrates provided you have secured the well(s) and ensured adequate protection.
(2) Pipeline pressure safety high and low (PSHL) sensor. In the event that either a high or a low pressure condition is detected by a PSHL sensor located upstream of the BSDV, you must secure the affected well and pipeline, and all wells and pipelines associated with a dual or multi pipeline system by closing the BSDVs, USVs, and surface-
controlled SSSVs in accordance with the applicable tables in Sec. Sec. 250.838 and 250.839. You must obtain approval from the appropriate BSEE District Manager to resume production in the unaffected pipeline(s) of a dual or multi pipeline system. If the PSHL sensor activation was a false alarm, you may return the wells to production without contacting the appropriate BSEE District Manager.
(3) ESD/TSE (Platform). In the event of an ESD activation that is initiated because of a platform ESD or platform TSE on the host platform not associated with the BSDV, you must close the BSDV, USV, and surface-controlled SSSV in accordance with the applicable tables in Sec. Sec. 250.838 and 250.839.
(4) Subsea ESD (Platform) or BSDV TSE. In the event of an emergency shutdown activation that is initiated by the host platform due to an abnormal condition subsea, or a TSE associated with the BSDV, you must close the BSDV, USV, and surface-controlled SSSV in accordance with the applicable tables in Sec. Sec. 250.838 and 250.839.
(5) Subsea ESD MODU. In the event of an ESD activation that is initiated by a MODU because of a dropped object from a rig or intervention vessel, you must secure all wells in the proximity of the MODU by closing the USVs and surface-controlled SSSVs in accordance with the applicable tables in Sec. Sec. 250.838 and 250.839. You must notify the appropriate BSEE District Manager before resuming production.
(d) You must bleed your low pressure (LP) and high pressure (HP) hydraulic systems in accordance with the applicable tables in Sec. Sec. 250.838 and 250.839 to ensure that the valves are locked out of service following an ESD or fire and cannot be reopened inadvertently.
Sec. 250.838 What are the maximum allowable valve closure times and hydraulic bleeding requirements for an electro-hydraulic control system?
(a) If you have an electro-hydraulic control system you must:
(1) Design the subsea control system to meet the valve closure times listed in paragraphs (b) and (d) of this section or your approved DWOP; and
(2) Verify the valve closure times upon installation. The BSEE District Manager may require you to verify the closure time of the USV(s) through visual authentication by diver or ROV.
(b) If you have not lost communication with your rig or platform, you must comply with the maximum allowable valve closure times and hydraulic system bleeding
Page 52269
requirements listed in the following table or your approved DWOP:
Valve Closure Timing, Electro-Hydraulic Control System
--------------------------------------------------------------------------------------------------------------------------------------------------------
Your LP Your HP
If you have the following . . Your pipeline Your USV1 must . Your USV2 must . Your alternate Your surface- hydraulic hydraulic
. BSDV must . . . . . . . isolation valve controlled SSSV system must . . system must . .
must . . . must . . . . .
--------------------------------------------------------------------------------------------------------------------------------------------------------
(1) Process upset............ Close within 45 no requirements no no no
seconds after requirements. requirements. requirements
sensor
activation.
--------------------------------------------------------------------------------------------------------------------------------------------------------
(2) Pipeline PSHL............ Close within 45 Close one or more valves within 2 minute and 45 Close within 60 no Initiate
seconds after seconds after sensor activation. Close the minutes after requirements. unrestricted
sensor designated USV1 within 20 minutes after sensor sensor bleed within
activation. activation activation. If 24 hours after
you use a 60- sensor
minute activation.
resettable
timer, you may
continue to
reset the time
for closure up
to a maximum
of 24 hours
total.
--------------------------------------------------------------------------------------------------------------------------------------------------------
(3) ESD/TSE (Platform)....... Close within 45 Close within 5 minutes after ESD Close within 20 Close within 20 Initiate Initiate
seconds after or sensor activation. If you use minutes after minutes after unrestricted unrestricted
ESD or sensor a 5-minute resettable timer, you ESD or sensor ESD or sensor bleed within bleed within
activation. may continue to reset the time activation. activation. If 60 minutes 60 minutes
for closure up to a maximum of 20 you use a 20- after ESD or after ESD or
minutes total. minute sensor sensor
resettable activation. If activation. If
timer, you may you use a 60- you use a 60-
continue to minute minute
reset the time resettable resettable
for closure up timer you must timer you must
to a maximum initiate initiate
of 60 minutes unrestricted unrestricted
total. bleed within bleed within
24 hours. 24 hours.
--------------------------------------------------------------------------------------------------------------------------------------------------------
(4) Subsea ESD (Platform) or Close within 45 Close one or more valves within 2 minutes and 45 Close within 10 Initiate Initiate
BSDV TSE. seconds after seconds after ESD or sensor activation. Close all minutes after unrestricted unrestricted
ESD or sensor tree valves within 10 minutes after ESD or sensor ESD or sensor bleed within bleed within
activation. activation. activation. 60 minutes 60 minutes
after ESD or after ESD or
sensor sensor
activation. activation.
--------------------------------------------------------------------------------------------------------------------------------------------------------
(5) Dropped object--(Subsea no Initiate valve closure immediately. You may allow for closure of the Initiate Initiate
ESD MODU). requirements. tree valves immediately prior to closure of the surface-controlled unrestricted unrestricted
SSSV if desired. bleed bleed within
immediately. 10 minutes
after ESD
activation.
--------------------------------------------------------------------------------------------------------------------------------------------------------
(c) If you have an electro-hydraulic control system and experience a loss of communications (EH Loss of Comms), you must comply with the following:
(1) If you can meet the EH Loss of Comms valve closure timing conditions specified in the table in this section, you must notify the appropriate BSEE District Office within 12 hours of detecting the loss of communication.
(2) If you cannot meet the EH Loss of Comms valve closure timing conditions specified in the table in this section, you must notify the appropriate BSEE District Office immediately after detecting the loss of communication. You must shut-in production by initiating a bleed of the low pressure (LP) hydraulic system or the high pressure (HP) hydraulic system within 120 minutes after loss of communication. Bleed the other hydraulic system within 180 minutes after loss of communication.
(3) You must obtain prior approval from the appropriate BSEE District Manager if you want to continue to produce after loss of communication when you cannot meet the EH Loss of Comms valve closure times specified in the table in paragraph (d) of this section. In your request, include an alternate valve closure table that your system is able to achieve. The appropriate BSEE District Manager may also approve an alternate hydraulic bleed schedule to allow for hydrate mitigation and orderly shut-in.
(d) If you experience a loss of communications, you must comply with the maximum allowable valve closure times and hydraulic system bleeding requirements listed in the following table or your approved DWOP:
Valve Closure Timing, Electro-Hydraulic Control System with Loss of Communication
--------------------------------------------------------------------------------------------------------------------------------------------------------
Your LP Your HP
If you have the following . . Your pipeline Your USV1 must . Your USV2 must . Your alternate Your surface- hydraulic hydraulic
. BSDV must . . . . . . . isolation valve controlled SSSV system must . . system must . .
must . . . must . . . . .
--------------------------------------------------------------------------------------------------------------------------------------------------------
(1) Process upset............ Close within 45 no requirements no no no
seconds after requirements. requirements. requirements.
sensor
activation.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Page 52270
(2) Pipeline PSHL............ Close within 45 Initiate closure when LP hydraulic system is bled Initiate Initiate Initiate
seconds after (close valves within 5 minutes after sensor closure when unrestricted unrestricted
sensor activation). HP hydraulic bleed bleed within
activation. system is bled immediately, 24 hours after
(close within concurrent sensor
24 hours after with sensor activation.
sensor activation.
activation).
--------------------------------------------------------------------------------------------------------------------------------------------------------
(3) ESD/TSE (Platform)....... Close within 45 Initiate closure when LP hydraulic system is bled Initiate Initiate Initiate
seconds after (close valves within 20 minutes after ESD or sensor closure when unrestricted unrestricted
ESD or sensor activation). HP hydraulic bleed bleed within
activation. system is bled concurrent 60 minutes
(close within with BSDV after ESD or
60 minutes closure (bleed sensor
after ESD or within 20 activation.
sensor minutes after
activation). ESD or sensor
activation).
--------------------------------------------------------------------------------------------------------------------------------------------------------
(4) Subsea ESD (Platform) or Close within 45 Initiate closure when LP hydraulic system is bled Initiate Initiate Initiate
BSDV TSE. seconds after (close valves within 5 minutes after ESD or sensor closure when unrestricted unrestricted
ESD or sensor activation). HP hydraulic bleed bleed
activation. system is bled immediately. immediately,
(close within allowing for
20 minutes surface-
after ESD or controlled
sensor SSSV closure
activation). within 20
minutes.
--------------------------------------------------------------------------------------------------------------------------------------------------------
(5) Dropped object--subsea no Initiate closure immediately. You may allow for closure of the tree Initiate Initiate
ESD (MODU). requirements. valves immediately prior to closure of the surface-controlled SSSV unrestricted unrestricted
if desired. bleed bleed
immediately. immediately
--------------------------------------------------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------------------------------------------------------
Sec. 250.839 What are the maximum allowable valve closure times and hydraulic bleeding requirements for direct-hydraulic control system?
(a) If you have direct-hydraulic control system you must:
(1) Design the subsea control system to meet the valve closure times listed in this section or your approved DWOP; and
(2) Verify the valve closure times upon installation. The BSEE District Manager may require you to verify the closure time of the USV(s) through visual authentication by diver or ROV.
(b) You must comply with the maximum allowable valve closure times and hydraulic system bleeding requirements listed in the following table or your approved DWOP:
Valve Closure Timing, Direct-Hydraulic Control System
--------------------------------------------------------------------------------------------------------------------------------------------------------
Your LP Your HP
If you have the following . . Your pipeline Your USV1 must . Your USV2 must . Your alternate Your surface- hydraulic hydraulic
. BSDV must . . . . . . . isolation valve controlled SSSV system must . . system must . .
must . . . must . . . . .
--------------------------------------------------------------------------------------------------------------------------------------------------------
(1) Process upset............ Close within 45 no requirements no no no
seconds after requirements. requirements. requirements.
sensor
activation.
--------------------------------------------------------------------------------------------------------------------------------------------------------
(2) Flowline PSHL............ Close within 45 Close one or more valves within 2 minutes and 45 Close within 24 Complete bleed Complete bleed
seconds after seconds after sensor activation. Close the hours after of USV1, USV2 within 24
sensor designated USV1 within 20 minutes after sensor sensor and the AIV hours after
activation. activation. activation. within 20 sensor
minutes after activation.
sensor
activation.
--------------------------------------------------------------------------------------------------------------------------------------------------------
(3) ESD/TSE (Platform)....... Close within 45 Close all valves within 20 minutes after ESD or Close within 60 Complete bleed Complete bleed
seconds after sensor activation. minutes after of USV1, USV2 within 60
ESD or sensor ESD or sensor and the AIV minutes after
activation. activation. within 20 ESD or sensor
minutes after activation.
ESD or sensor
activation.
--------------------------------------------------------------------------------------------------------------------------------------------------------
(4) Subsea ESD (Platform) or Close within 45 Close one or more valves within 2 minutes and 45 Close within 10 Complete bleed Complete bleed
BSDV TSE. seconds after seconds after ESD or sensor activation. Close all minutes after of USV1, USV2, within 10
ESD or sensor tree valves within 10 minutes after ESD or sensor ESD or sensor and the AIV minutes after
activation. activation. activation. within 10 ESD or sensor
minutes after activation.
ESD or sensor
activation.
--------------------------------------------------------------------------------------------------------------------------------------------------------
(5) Dropped object--Subsea no Initiate closure immediately. If desired, you may allow for closure Initiate Initiate
ESD. requirements. of the tree valves immediately prior to closure of the surface- unrestricted unrestricted
(MODU)....................... controlled SSSV. bleed bleed
immediately. immediately.
--------------------------------------------------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------------------------------------------------------
Page 52271
Production Safety Systems
Sec. 250.840 Design, installation, and maintenance--general.
You must design, install, and maintain all production facilities and equipment including, but not limited to, separators, treaters, pumps, heat exchangers, fired components, wellhead injection lines, compressors, headers, and flowlines in a manner that is efficient, safe, and protects the environment.
Sec. 250.841 Platforms.
(a) You must protect all platform production facilities with a basic and ancillary surface safety system designed, analyzed, installed, tested, and maintained in operating condition in accordance with the provisions of API RP 14C, Recommended Practice for Analysis, Design, Installation, and Testing of Basic Surface Safety Systems for Offshore Production Platforms (incorporated by reference as specified in Sec. 250.198). If you use processing components other than those for which Safety Analysis Checklists are included in API RP 14C, you must utilize the analysis technique and documentation specified in API RP 14C to determine the effects and requirements of these components on the safety system. Safety device requirements for pipelines are contained in 30 CFR 250.1004.
(b) You must design, analyze, install, test, and maintain in operating condition all platform production process piping in accordance with API RP 14E, Design and Installation of Offshore Production Platform Piping Systems and API 570, Piping Inspection Code: In-service Inspection, Rating, Repair, and Alteration of Piping Systems (both incorporated by reference as specified in Sec. 250.198). The District Manager may approve temporary repairs to facility piping on a case-by-case basis for a period not to exceed 30 days.
Sec. 250.842 Approval of safety systems design and installation features.
(a) Before you install or modify a production safety system, you must submit a production safety system application to the District Manager for approval. The application must include the information prescribed in the following table:
------------------------------------------------------------------------
You must submit: Details and/or additional requirements:
------------------------------------------------------------------------
(1) A schematic piping and Showing the following:
instrumentation diagram . .
.
(i) Well shut-in tubing pressure;
(ii) Piping specification breaks, piping
sizes;
(iii) Pressure relief valve set points;
(iv) Size, capacity, and design working
pressures of separators, flare
scrubbers, heat exchangers, treaters,
storage tanks, compressors and metering
devices;
(v) Size, capacity, design working
pressures, and maximum discharge
pressure of hydrocarbon-handling pumps;
(vi) size, capacity, and design working
pressures of hydrocarbon-handling
vessels, and chemical injection systems
handling a material having a flash point
below 100 degrees Fahrenheit for a Class
I flammable liquid as described in API
RP 500 and 505 (both incorporated by
reference as specified in Sec.
250.198).
(vii) Size and maximum allowable working
pressures as determined in accordance
with API RP 14E, Recommended Practice
for Design and Installation of Offshore
Production Platform Piping Systems
(incorporated by reference as specified
in Sec. 250.198).
(2) A safety analysis flow If processing components are used, other
diagram (API RP 14C, than those for which Safety Analysis
Appendix E) and the related Checklists are included in API RP 14C,
Safety Analysis Function you must use the same analysis technique
Evaluation (SAFE) chart (API and documentation to determine the
RP 14C, subsection 4.3.3) effects and requirements of these
(incorporated by reference components upon the safety system.
as specified in Sec.
250.198)
(3) Electrical system (i) A plan for each platform deck and
information, including outlining all classified areas. You must
classify areas according to API RP 500,
Recommended Practice for Classification
of Locations for Electrical
Installations at Petroleum Facilities
Classified as Class I, Division 1 and
Division 2; or API RP 505, Recommended
Practice for Classification of Locations
for Electrical Installations at
Petroleum Facilities Classified as Class
I, Zone 0, Zone 1, and Zone 2 (both
incorporated by reference as specified
in Sec. 250.198).
(ii) Identification of all areas where
potential ignition sources, including
non-electrical ignition sources, are to
be installed showing:
(A) All major production equipment,
wells, and other significant hydrocarbon
sources, and a description of the type
of decking, ceiling, and walls (e.g.,
grating or solid) and firewalls and;
(B) the location of generators, control
rooms, panel boards, major cabling/
conduit routes, and identification of
the primary wiring method (e.g., type
cable, conduit, wire) and;
(iii) one-line electrical drawings of all
electrical systems including the safety
shutdown system. You must also include a
functional legend.
(4) Schematics of the fire Showing a functional block diagram of the
and gas-detection systems detection system, including the
electrical power supply and also
including the type, location, and number
of detection sensors; the type and kind
of alarms, including emergency equipment
to be activated; the method used for
detection; and the method and frequency
of calibration.
(5) The service fee listed in The fee you must pay will be determined
Sec. 250.125 by the number of components involved in
the review and approval process.
------------------------------------------------------------------------
(b) The production safety system application must also include the following certifications:
(1) That all electrical installations were designed according to API RP 14F, Design, Installation, and Maintenance of Electrical Systems for Fixed and Floating Offshore Petroleum Facilities for Unclassified and Class I, Division 1 and Division 2 Locations, or API RP 14FZ, Recommended Practice for Design and Installation of Electrical Systems for Fixed and Floating Offshore Petroleum Facilities for Unclassified and Class I, Zone 0, Zone 1 and Zone 2 Locations, as applicable (incorporated by reference as specified in Sec. 250.198);
Page 52272
(2) That the designs for the mechanical and electrical systems were reviewed, approved, and stamped by a registered professional engineer(s). The registered professional engineer must be registered in a State or Territory in the United States and have sufficient expertise and experience to perform the duties; and
(3) That a hazard analysis was performed during the design process in accordance with API RP 14J (incorporated by reference as specified in Sec. 250.198), and that you have a hazards analysis program in place to assess potential hazards during the operation of the platform:
(c) Before you begin production, you must certify, in a letter to the District Manager, that the mechanical and electrical systems were installed in accordance with the approved designs.
(d) Within 60 days after production, you must certify, in a letter to the District Manager, that the as-built diagrams outlined in (a)(1) and (2) of this section and the piping and instrumentation diagrams are on file and have been certified correct and stamped by a registered professional engineer(s). The registered professional engineer must be registered in a State or Territory in the United States and have sufficient expertise and experience to perform the duties.
(e) All as-built diagrams outlined in (a)(1) and (2) of this section must be submitted to the District Manager within 60 days after production.
(f) You must maintain information concerning the approved design and installation features of the production safety system at your offshore field office nearest the OCS facility or at other locations conveniently available to the District Manager. As-built piping and instrumentation diagrams must be maintained at a secure onshore location and readily available offshore. These documents must be made available to BSEE upon request and be retained for the life of the facility. All approvals are subject to field verifications.
Sec. Sec. 250.843--250.849 Reserved
Additional Production System Requirements
Sec. 250.850 Production system requirements--general.
You must comply with the production safety system requirements in the following sections (Sec. Sec. 250.851 through 250.872), some of which are in addition to those contained in API RP 14C (incorporated by reference as specified in Sec. 250.198).
Sec. 250.851 Pressure vessels (including heat exchangers) and fired vessels.
(a) Pressure vessels (including heat exchangers) and fired vessels must meet the requirements in the following table:
------------------------------------------------------------------------
Applicable codes and
Item name requirements
------------------------------------------------------------------------
(1) Pressure and fired vessels where (i) Must be designed,
the operating pressure is or will be fabricated, and code stamped
15 pounds per square inch gauge (psig) according to applicable
or greater. provisions of sections I, IV,
and VIII of the ANSI/ASME
Boiler and Pressure Vessel
Code.
(ii) Must be repaired,
maintained, and inspected in
accordance with API 510,
Pressure Vessel Inspection
Code: In-Service Inspection,
Rating, Repair, and
Alteration, Downstream Segment
(incorporated by reference as
specified in Sec. 250.198).
(2) Pressure and fired vessels (such as Must employ a safety analysis
flare and vent scrubbers) where the checklist in the design of
operating pressure is or will be at each component. These vessels
least 5 psig and less than 15 psig. do not need to be ASME Code
stamped as pressure vessels.
(3) Pressure and fired vessels where Are not subject to the
the operating pressure is or will be requirements of paragraphs
less than 5 psig. (a)(1) and (a)(2).
(4) Existing uncoded Pressure and fired Must be justified and approval
vessels (i) in use on the effective obtained from the District
date of the final rule; (ii) with an Manager for their continued
operating pressure of 5 psig or use beyond 18 months from the
greater; and (iii) that are not code effective date of the final
stamped in accordance with the ANSI/ rule.
ASME Boiler and Pressure Vessel Code .
. .
(5) Pressure relief valves............. (i) Must be designed and
installed according to
applicable provisions of
sections I, IV, and VIII of
the ASME Boiler and Pressure
Vessel Code.
(ii) Must conform to the valve
sizing and pressure-relieving
requirements specified in
these documents, but (except
for completely redundant
relief valves), must be set no
higher than the maximum-
allowable working pressure of
the vessel.
(iii) And vents must be
positioned in such a way as to
prevent fluid from striking
personnel or ignition sources.
(6) Steam generators operating at less Must be equipped with a level
than 15 psig. safety low (LSL) sensor which
will shut off the fuel supply
when the water level drops
below the minimum safe level.
(7) Steam generators operating at 15 (i) Must be equipped with a
psig or greater. level safety low (LSL) sensor
which will shut off the fuel
supply when the water level
drops below the minimum safe
level.
(ii) You must also install a
water-feeding device that will
automatically control the
water level except when closed
loop systems are used for
steam generation.
------------------------------------------------------------------------
(b) Operating pressure ranges. You must use pressure recording devices to establish the new operating pressure ranges of pressure vessels at any time the normalized system pressure changes by 5 percent. You must maintain the pressure recording information you used to determine current operating pressure ranges at your field office nearest the OCS facility or at another location conveniently available to the District Manager for as long as the information is valid.
(c) Pressure shut-in sensors must be set according to the following table:
Page 52273
------------------------------------------------------------------------
Additional
Type of sensor Settings requirements
------------------------------------------------------------------------
(1) High pressure shut-in Must be no higher Must also be set
sensor. than 15 percent or sufficiently below
5 psi (whichever is (5 percent or 5
greater) above the psi, whichever is
highest operating greater) the relief
pressure of the valve's set
vessel. pressure to assure
that the pressure
source is shut-in
before the relief
valve activates.
(2) Low pressure shut-in Must be set no lower You must receive
sensor. than 15 percent or specific approval
5 psi (whichever is from the District
greater) below the Manager for
lowest pressure in activation limits
the operating range. on pressure vessels
that have a
pressure safety low
(PSL) sensor set
less than 5 psi.
------------------------------------------------------------------------
Sec. 250.852 Flowlines/Headers.
(a)(1) You must equip flowlines from wells with both PSH and PSL sensors. You must locate these sensors in accordance with section A.1 of API RP 14C (incorporated by reference as specified in Sec. 250.198).
(2) You must use pressure recording devices to establish the new operating pressure ranges of flowlines at any time when the normalized system pressure changes by 50 psig or 5 percent, whichever is higher.
(3) You must maintain the most recent pressure recording information you used to determine operating pressure ranges at your field office nearest the OCS facility or at another location conveniently available to the District Manager for as long as the information is valid.
(b) Flowline shut-in sensors must meet the requirements in the following table:
------------------------------------------------------------------------
Type of flowline sensor Settings
------------------------------------------------------------------------
(1) PSH sensor....................... Must be set no higher than 15
percent or 5 psi (whichever is
greater) above the highest
operating pressure of the
flowline. In all cases, the PSH
must be set sufficiently below
the maximum shut-in wellhead
pressure or the gas-lift supply
pressure to assure actuation of
the SSV. Do not set the PSH
sensor above the maximum
allowable working pressure of
the flowline.
(2) PSL sensor....................... Must be set no lower than 15
percent or 5 psi (whichever is
greater) below the lowest
operating pressure of the
flowline in which it is
installed.
------------------------------------------------------------------------
(c) If a well flows directly to a pipeline before separation, the flowline and valves from the well located upstream of and including the header inlet valve(s) must have a working pressure equal to or greater than the maximum shut-in pressure of the well unless the flowline is protected by one of the following:
(1) A relief valve which vents into the platform flare scrubber or some other location approved by the District Manager. You must design the platform flare scrubber to handle, without liquid-hydrocarbon carryover to the flare, the maximum-anticipated flow of liquid hydrocarbons that may be relieved to the vessel; or
(2) Two SSVs with independent PSH sensors connected to separate relays and sensing points and installed with adequate volume upstream of any block valve to allow sufficient time for the SSVs to close before exceeding the maximum allowable working pressure. Each independent PSH sensor must close both SSVs along with any associated flowline PSL sensor. If the maximum shut-in pressure of a dry tree satellite well(s) is greater than 1\1/2\ times the maximum allowable pressure of pipeline, a pressure safety valve (PSV) of sufficient size and relief capacity to protect against any SSV leakage or fluid hammer effect may be required by the District Manager. The PSV must be installed upstream of the host platform boarding valve and vent into the platform flare scrubber or some other location approved by the District Manager.
(d) If a well flows directly to the pipeline from a header without prior separation, the header, the header inlet valves, and pipeline isolation valve must have a working pressure equal to or greater than the maximum shut-in pressure of the well unless the header is protected by the safety devices as outlined in paragraph (c) of this section.
(e) If you are installing flowlines constructed of unbonded flexible pipe on a floating platform, you must:
(1) Review the manufacturer's Design Methodology Verification Report and the independent verification agent's (IVA's) certificate for the design methodology contained in that report to ensure that the manufacturer has complied with the requirements of API Spec. 17J, Specification for Unbonded Flexible Pipe (ISO 13628-2:2006) (incorporated by reference as specified in Sec. 250.198);
(2) Determine that the unbonded flexible pipe is suitable for its intended purpose;
(3) Submit to the District Manager the manufacturer's design specifications for the unbonded flexible pipe; and
(4) Submit to the District Manager a statement certifying that the pipe is suitable for its intended use and that the manufacturer has complied with the IVA requirements of API Spec. 17J (ISO 13628-2:2006) (incorporated by reference as specified in Sec. 250.198).
(f) Automatic pressure or flow regulating choking devices must not prevent the normal functionality of the process safety system that includes, but is not limited to, the flowline pressure safety devices and the SSV.
(g) You may install a single flow safety valve (FSV) on the platform to protect multiple subsea pipelines or wells that tie into a single pipeline riser provided that you install an FSV for each riser and test it in accordance with the criteria prescribed in Sec. 250.880(c)(2)(v).
(h) You may install a single PSHL sensor on the platform to protect multiple subsea pipelines that tie into a single pipeline riser provided that you install a PSHL sensor for each riser and locate it upstream of the BSDV.
Sec. 250.853 Safety sensors.
You must ensure that:
(a) All shutdown devices, valves, and pressure sensors function in a manual reset mode;
(b) Sensors with integral automatic reset are equipped with an appropriate device to override the automatic reset mode;
(c) All pressure sensors are equipped to permit testing with an external pressure source; and,
(d) All level sensors are equipped to permit testing through an external bridle on all new vessel installations.
Page 52274
Sec. 250.854 Floating production units equipped with turrets and turret mounted systems.
(a) For floating production units equipped with an auto slew system, you must integrate the auto slew control system with your process safety system allowing for automatic shut-in of the production process, including the sources (subsea wells, subsea pumps, etc.) and releasing of the buoy. Your safety system must immediately initiate a process system shut-in according to Sec. Sec. 250.838 and 250.839 and release the buoy to prevent hydrocarbon discharge and damage to the subsea infrastructure when the following are encountered:
(i) Your buoy is clamped,
(ii) Your auto slew mode is activated, and
(iii) You encounter a ship heading/position failure or an exceedance of the rotational tolerances of the clamped buoy.
(b) For floating production units equipped with swivel stack arrangements, you must equip the portion of the swivel stack containing hydrocarbons with a leak detection system. Your leak detection system must be tied into your production process surface safety system allowing for automatic shut-in of the system. Upon seal system failure and detection of a hydrocarbon leak, your surface safety system must immediately initiate a process system shut-in according to Sec. Sec. 250.838 and 250.839.
Sec. 250.855 Emergency shutdown (ESD) system.
The ESD system must conform to the requirements of Appendix C, section C1, of API RP 14C (incorporated by reference as specified in Sec. 250.198), and the following:
(a) The manually operated ESD valve(s) must be quick-opening and nonrestricted to enable the rapid actuation of the shutdown system. Only ESD stations at the boat landing may utilize a loop of breakable synthetic tubing in lieu of a valve. This breakable loop is not required to be physically located on the boat landing, but must be accessible from a boat.
(b) You must maintain a schematic of the ESD that indicates the control functions of all safety devices for the platforms on the platform, at your field office nearest the OCS facility, or at another location conveniently available to the District Manager for the life of the facility.
Sec. 250.856 Engines.
(a) Engine exhaust. You must equip all engine exhausts to comply with the insulation and personnel protection requirements of API RP 14C, section 4.2., (incorporated by reference as specified in Sec. 250.198). You must equip exhaust piping from diesel engines with spark arresters.
(b) Diesel engine air intake. You must equip diesel engine air intakes with a device to shutdown the diesel engine in the event of runaway. You must equip diesel engines that are continuously attended with either remotely operated manual or automatic shutdown devices. You must equip diesel engines that are not continuously attended with automatic shutdown devices. The following diesel engines do not require a shutdown device: Engines for fire water pumps; engines on emergency generators; engines that power BOP accumulator systems; engines that power air supply for confined entry personnel; temporary equipment on non-producing platforms; booster engines whose purpose is to start larger engines; and engines that power portable single cylinder rig washers.
Sec. 250.857 Glycol dehydration units.
(a) You must install a pressure relief system or an adequate vent on the glycol regenerator (reboiler) to prevent overpressurization. The discharge of the relief valve must be vented in a nonhazardous manner.
(b) You must install the FSV on the dry glycol inlet to the glycol contact tower as near as practical to the glycol contact tower.
(c) You must install the shutdown valve (SDV) on the wet glycol outlet from the glycol contact tower as near as practical to the glycol contact tower.
250.858 Gas compressors.
(a) You must equip compressor installations with the following protective equipment as required in API RP 14C, sections A4 and A8 (incorporated by reference as specified in Sec. 250.198).
(1) A pressure safety high (PSH) sensor, a pressure safety low (PSL) sensor, a pressure safety valve (PSV), and a level safety high (LSH) sensor, and a level safety low (LSL) sensor to protect each interstage and suction scrubber.
(2) A temperature safety high (TSH) sensor on each compressor discharge cylinder.
(3) You must design the PSH and PSL sensors and LSH controls protecting compressor suction and interstage scrubbers to actuate automatic SDVs located in each compressor suction and fuel gas line so that the compressor unit and the associated vessels can be isolated from all input sources. All automatic SDVs installed in compressor suction and fuel gas piping must also be actuated by the shutdown of the prime mover. Unless otherwise approved by the District Manager, gas-well gas affected by the closure of the automatic SDV on a compressor suction must be diverted to the pipeline or shut-in at the wellhead.
(4) You must install a blowdown valve on the discharge line of all compressor installations that are 1,000 horsepower (746 kilowatts) or greater.
(b) You must use pressure recording devices to establish the new operating pressure ranges for compressor discharge sensors at any time when the normalized system pressure changes by 50 psig or 5 percent, whichever is higher. You must:
(1) Maintain the most recent pressure recording information that you used to determine operating pressure ranges at your field office nearest the OCS facility or at another location conveniently available to the District Manager.
(2) Set the PSH sensor(s) no higher than 15 percent or 5 psi, whichever is greater, above the highest operating pressure of the discharge line and sufficiently below the maximum discharge pressure to ensure actuation of the suction SDV. Set the PSH sensor(s) sufficiently below (5 percent or 5 psi, whichever is greater) the set pressure of the PSV to assure that the pressure source is shut-in before the PSV activates.
(3) Set PSL sensor(s) no lower than 15 percent or 5 psi, whichever is greater, below the lowest operating pressure of the discharge line in which it is installed.
(c) For vapor recovery units, when the suction side of the compressor is operating below 5 psig and the system is capable of being vented to atmosphere, you are not required to install PSH and PSL sensors on the suction side of the compressor.
Sec. 250.859 Firefighting systems.
(a) Firefighting systems for both open and totally enclosed platforms installed for extreme weather conditions or other reasons must conform to API RP 14G, Recommended Practice for Fire Prevention and Control on Fixed Open-type Offshore Production Platforms (incorporated by reference as specified in Sec. 250.198), and require approval of the District Manager. The following additional requirements apply for both open- and closed-production platforms:
(1) You must install a firewater system consisting of rigid pipe with firehose stations fixed firewater monitors. The firewater system must protect in all areas where production-handling equipment is located. You
Page 52275
must install a fixed water spray system in enclosed well-bay areas where hydrocarbon vapors may accumulate.
(2) Fuel or power for firewater pump drivers must be available for at least 30 minutes of run time during a platform shut-in. If necessary, you must install an alternate fuel or power supply to provide for this pump operating time unless the District Manager has approved an alternate firefighting system. As of 1 year after the publication date of the final rule, you must have equipped all new firewater pump drivers with automatic starting capabilities upon activation of the ESD, fusible loop, or other fire detection system. For electric driven firewater pump drivers, in the event of a loss of primary power, you must install an automatic transfer switch to cross over to an emergency power source in order to maintain at least 30 minutes of run time. The emergency power source must be reliable and have adequate capacity to carry the locked-rotor currents of the fire pump motor and accessory equipment. You must route power cables or conduits with wires installed between the fire water pump drivers and the automatic transfer switch away from hazardous-classified locations that can cause flame impingement. Power cables or conduits with wires that connect to the fire water pump drivers must be capable of maintaining circuit integrity for not less than 30 minutes of flame impingement.
(3) You must post a diagram of the firefighting system showing the location of all firefighting equipment in a prominent place on the facility or structure.
(4) For operations in subfreezing climates, you must furnish evidence to the District Manager that the firefighting system is suitable for those conditions.
(5) All firefighting equipment located on a facility must be in good working order whether approved as the primary, secondary, or ancillary firefighting system.
(b) Inoperable Firewater Systems. If you are required to maintain a firewater system and it becomes inoperable, either shut-in your production operations while making the necessary repairs, or request that the appropriate BSEE District Manager grant you a departure under Sec. 250.142 to use a firefighting system using chemicals on a temporary basis (for a period up to 7 days) while you make the necessary repairs. If you are unable to complete repairs during the approved time period because of circumstances beyond your control, the BSEE District Manager may grant extensions to your approved departure for periods up to 7 days.
Sec. 250.860 Chemical firefighting system.
(a) Major platforms and minor manned platforms. A firefighting system using chemicals-only may be used in lieu of a water-based system on a major platform or a minor manned platform if the District Manager determines that the use of a chemical system provides equivalent fire-
protection control and would not increase the risk to human safety. A major platform is a structure with either six or more completions or zero to five completions with more than one item of production process equipment. A minor platform is a structure with zero to five completions with one item of production process equipment. A manned platform is one that is attended 24 hours a day or one on which personnel are quartered overnight. To obtain approval to use a chemical-only fire prevention and control system on a major platform or a minor manned platform, in lieu of a water system, you must submit to the District Manager:
(1) A justification for asserting that the use of a chemical system provides equivalent fire-protection control. The justification must address fire prevention, fire protection, fire control, and firefighting on the platform; and
(2) A risk assessment demonstrating that a chemical-only system would not increase the risk to human safety. Provide the following and any other important information in your risk assessment:
------------------------------------------------------------------------
For the use of a chemical
firefighting system on major
and minor manned platforms,
you must provide the Including . . .
following in your risk
assessment . . .
------------------------------------------------------------------------
(i) Platform description..... (A) The type and quantity of hydrocarbons
(i.e., natural gas, oil) that are
produced, handled, stored, or processed
at the facility.
(B) The capacity of any tanks on the
facility that you use to store either
liquid hydrocarbons or other flammable
liquids.
(C) The total volume of flammable liquids
(other than produced hydrocarbons)
stored on the facility in containers
other than bulk storage tanks. Include
flammable liquids stored in paint
lockers, storerooms, and drums.
(D) If the facility is manned, provide
the maximum number of personnel on board
and the anticipated length of their
stay.
(E) If the facility is unmanned, provide
the number of days per week the facility
will be visited, the average length of
time spent on the facility per day, the
mode of transportation, and whether or
not transportation will be available at
the facility while personnel are on
board.
(F) A diagram that depicts: Quarters
location, production equipment location,
fire prevention and control equipment
location, lifesaving appliances and
equipment location, and evacuation plan
escape routes from quarters and all
manned working spaces to primary
evacuation equipment.
(ii) Hazard assessment (A) Identification of all likely fire
(facility specific). initiation scenarios (including those
resulting from maintenance and repair
activities). For each scenario, discuss
its potential severity and identify the
ignition and fuel sources.
(B) Estimates of the fire/radiant heat
exposure that personnel could be
subjected to. Show how you have
considered designated muster areas and
evacuation routes near fuel sources and
have verified proper flare boom sizing
for radiant heat exposure.
(iii) Human factors (A) Descriptions of the fire-related
assessment (not facility training your employees and contractors
specific). have received. Include details on the
length of training, whether the training
was hands-on or classroom, the training
frequency, and the topics covered during
the training.
(B) Descriptions of the training your
employees and contractors have received
in fire prevention, control of ignition
sources, and control of fuel sources
when the facility is occupied.
(C) Descriptions of the instructions and
procedures you have given to your
employees and contractors on the actions
they should take if a fire occurs.
Include those instructions and
procedures specific to evacuation. State
how you convey this information to your
employees and contractor on the
platform.
Page 52276
(iv) Evacuation assessment (A) A general discussion of your
(facility specific). evacuation plan. Identify your muster
areas (if applicable), both the primary
and secondary evacuation routes, and the
means of evacuation for both.
(B) Description of the type, quantity,
and location of lifesaving appliances
available on the facility. Show how you
have ensured that lifesaving appliances
are located in the near vicinity of the
escape routes.
(C) Description of the types and
availability of support vessels, whether
the support vessels are equipped with a
fire monitor, and the time needed for
support vessels to arrive at the
facility.
(D) Estimates of the worst case time
needed for personnel to evacuate the
facility should a fire occur.
(v) Alternative protection (A) Discussion of the reasons you are
assessment. proposing to use an alternative fire
prevention and control system.
(B) Lists of the specific standards used
to design the system, locate the
equipment, and operate the equipment/
system.
(C) Description of the proposed
alternative fire prevention and control
system/equipment. Provide details on the
type, size, number, and location of the
prevention and control equipment.
(D) Description of the testing,
inspection, and maintenance program you
will use to maintain the fire prevention
and control equipment in an operable
condition. Provide specifics regarding
the type of inspection, the personnel
who conduct the inspections, the
inspection procedures, and documentation
and recordkeeping.
(vi) Conclusion.............. A summary of your technical evaluation
showing that the alternative system
provides an equivalent level of
personnel protection for the specific
hazards located on the facility.
------------------------------------------------------------------------
(b) Changes after approval. If BSEE has approved your request to use a chemical-only fire suppressant system in lieu of a water system, and if you make an insignificant change to your platform subsequent to that approval, document the change and maintain the documentation at the facility or nearest field office for BSEE review and/or inspection and maintain for the life of the facility. Do not submit this documentation to the BSEE District Manager. However, if you make a significant change to your platform (e.g., placing a storage vessel with a capacity of 100 barrels or more on the facility, adding production equipment) or if you plan to man an unmanned platform temporarily, submit a new request, including an updated risk assessment, to the appropriate BSEE District Manager for approval. You must maintain the most recent documentation that you submitted to BSEE for the life of the facility at either location discussed previously.
(c) Minor unmanned platforms. You may use a U.S. Coast Guard type and size rating ``B-II'' portable dry chemical unit (with a minimum UL Rating (US) of 60-B:C) or a 30-pound portable dry chemical unit, in lieu of a water system, on all platforms that are both minor and unmanned, as long as you ensure that the unit is available on the platform when personnel are on board.
Sec. 250.861 Foam firefighting system.
When foam firefighting systems are installed as part of your firefighting system, you must:
(a) Annually conduct an inspection of the foam concentrates and their tanks or storage containers for evidence of excessive sludging or deterioration.
(b) Annually send samples of the foam concentrate to the manufacturer or authorized representative for quality condition testing. You must have the sample tested to determine the specific gravity, pH, percentage of water dilution, and solid content. Based on these results, the foam must be certified by an authorized representative of the manufacturer as suitable firefighting foam per the original manufacturer's specifications. The certification document must be readily accessible for field inspection. In lieu of sampling and certification, you may choose to replace the total inventory of foam with suitable new stock.
(c) The quantity of concentrate must meet design requirements, and tanks or containers must be kept full with space allowed for expansion.
Sec. 250.862 Fire and gas-detection systems.
(a) You must install fire (flame, heat, or smoke) sensors in all enclosed classified areas. You must install gas sensors in all inadequately ventilated, enclosed classified areas. Adequate ventilation is defined as ventilation that is sufficient to prevent accumulation of significant quantities of vapor-air mixture in concentrations over 25 percent of the lower explosive limit. An acceptable method of providing adequate ventilation is one that provides a change of air volume each 5 minutes or 1 cubic foot of air-
volume flow per minute per square foot of solid floor area, whichever is greater. Enclosed areas (e.g., buildings, living quarters, or doghouses) are defined as those areas confined on more than four of their six possible sides by walls, floors, or ceilings more restrictive to air flow than grating or fixed open louvers and of sufficient size to allow entry of personnel. A classified area is any area classified Class I, Group D, Division 1 or 2, following the guidelines of API RP 500 (incorporated by reference as specified in Sec. 250.198), or any area classified Class I, Zone 0, Zone 1, or Zone 2, following the guidelines of API RP 505 (incorporated by reference as specified in Sec. 250.198).
(b) All detection systems must be capable of continuous monitoring. Fire-detection systems and portions of combustible gas-detection systems related to the higher gas concentration levels must be of the manual-reset type. Combustible gas-detection systems related to the lower gas-concentration level may be of the automatic-reset type.
(c) A fuel-gas odorant or an automatic gas-detection and alarm system is required in enclosed, continuously manned areas of the facility which are provided with fuel gas. Living quarters and doghouses not containing a gas source and not located in a classified area do not require a gas detection system.
(d) The District Manager may require the installation and maintenance of a gas detector or alarm in any potentially hazardous area.
(e) Fire- and gas-detection systems must be an approved type, and designed and installed in accordance with API RP 14C, API RP 14G, API RP 14F, API RP 14FZ, API RP 500, and API RP 505 (all incorporated by reference as specified in Sec. 250.198).
Page 52277
Sec. 250.863 Electrical equipment.
You must design, install, and maintain electrical equipment and systems in accordance with the requirements in Sec. 250.114.
Sec. 250.864 Erosion.
You must have a program of erosion control in effect for wells or fields that have a history of sand production. The erosion-control program may include sand probes, X-ray, ultrasonic, or other satisfactory monitoring methods. You must maintain records by lease that indicate the wells that have erosion-control programs in effect. You must also maintain the results of the programs for at least 2 years and make them available to BSEE upon request.
Sec. 250.865 Surface pumps.
(a) You must equip pump installations with the protective equipment required in API RP 14C, Appendix A--A.7, Pumps section A7 (incorporated by reference as specified in Sec. 250.198).
(b) You must use pressure recording devices to establish the new operating pressure ranges for pump discharge sensors at any time when the normalized system pressure changes by 50 psig or 5 percent, whichever is higher. You must only maintain the most recent pressure recording information that you used to determine operating pressure ranges at your field office nearest the OCS facility or at another location conveniently available to the District Manager. The PSH sensor(s) must be set no higher than 15 percent or 5 psi, whichever is greater, above the highest operating pressure of the discharge line. But in all cases, you must set the PSH sensor sufficiently below the maximum allowable working pressure of the discharge piping. In addition, you must set the PSH sensor(s) at least (5 percent or 5 psi, whichever is greater) below the set pressure of the PSV to assure that the pressure source is shut-in before the PSV activates. You must set the PSL sensor(s) no lower than 15 percent or 5 psi, whichever is greater, below the lowest operating pressure of the discharge line in which it is installed.
(c) The PSL does not need to be placed into service until such time as the pump discharge pressure has risen above the PSL sensing point, as long as this time does not exceed 45 seconds.
(d) You may exclude the PSH and PSL sensors on small, low-volume pumps such as chemical injection-type pumps. This is acceptable if such a pump is used as a sump pump or transfer pump, has a discharge rating of less than \1/2\ gallon per minute (gpm), discharges into piping that is 1 inch or less in diameter, and terminates in piping that is 2 inches or larger in diameter.
(e) You must install a TSE in the immediate vicinity of all pumps in hydrocarbon service or those powered by platform fuel gas.
(f) The pump maximum discharge pressure must be determined using the maximum possible suction pressure and the maximum power output of the driver.
Sec. 250.866 Personnel safety equipment.
You must maintain all personnel safety equipment located on a facility, whether required or not, in good working condition.
Sec. 250.867 Temporary quarters and temporary equipment.
(a) The District Manager must approve all temporary quarters to be installed on OCS facilities. You must equip temporary quarters with all safety devices required by API RP 14C, Appendix C (incorporated by reference as specified in Sec. 250.198).
(b) The District Manager may require you to install a temporary firewater system in temporary quarters.
(c) Temporary equipment used for well testing and/or well clean-up needs to be approved by the District Manager.
Sec. 250.868 Non-metallic piping.
You may use non-metallic piping, such as that made from polyvinyl chloride, chlorinated polyvinyl chloride, and reinforced fiberglass only in atmospheric, primarily non-hydrocarbon service such as:
(a) Piping in galleys and living quarters;
(b) Open atmospheric drain systems;
(c) Overboard water piping for atmospheric produced water systems; and
(d) Firewater system piping.
Sec. 250.869 General platform operations.
(a) Surface or subsurface safety devices must not be bypassed or blocked out of service unless they are temporarily out of service for startup, maintenance, or testing. You may take only the minimum number of safety devices out of service. Personnel must monitor the bypassed or blocked-out functions until the safety devices are placed back in service. Any surface or subsurface safety device which is temporarily out of service must be flagged. A designated visual indicator must be used to identify the bypassed safety device. You must follow the monitoring procedures as follows:
(1) If you are using a non-computer-based system, meaning your safety system operates primarily with pneumatic supply or non-
programmable electrical systems, you must monitor non-computer-based system bypassed safety devices by positioning monitoring personnel at either the control panel for the bypassed safety device, or at the bypassed safety device, or at the component that the bypassed safety device would be monitoring when in service. You must also ensure that monitoring personnel are able to view all relevant essential operating conditions until all bypassed safety devices are placed back in service and are able to initiate shut-in action in the event of an abnormal condition.
(2) If you are using a computer-based technology system, meaning a computer-controlled electronic safety system such as supervisory control and data acquisition and remote terminal units, you must monitor computer-based technology system bypassed safety devices by maintaining instantaneous communications at all times among remote monitoring personnel and the personnel performing maintenance, testing, or startup. Until all bypassed safety devices are placed back in service, you must also position monitoring personnel at a designated control station that is capable of the following:
(i) Displaying all relevant essential operating conditions that affect the bypassed safety device, well, pipeline, and process component. If electronic display of all relevant essential conditions is not possible, you must have field personnel monitoring the level gauges (Site glass) and pressure gauges in order to know the current operating conditions. You must be in communication with all field personnel monitoring the gauges;
(ii) Controlling the production process equipment and the entire safety system;
(iii) Displaying a visual indicator when safety devices are placed in the bypassed mode; and
(iv) Upon command, overriding the bypassed safety device and initiating shut-in action in the event of an abnormal condition.
(3) You must not bypass for startup any element of the emergency support system or other support system required by API RP 14C, Appendix C, (incorporated by reference as specified in Sec. 250.198) without first receiving BSEE approval to depart from this operating procedure in accordance with 250.142. These systems include, but are not limited to:
(i) The ESD system to provide a method to manually initiate platform shutdown by personnel observing abnormal conditions or undesirable events. You do not have to receive
Page 52278
approval from the District Manager for manual reset and/or initial charging of the system;
(ii) The fire loop system to sense the heat of a fire and initiate platform shutdown, and other fire detection devices (flame, thermal, and smoke) that are used to enhance fire detection capability. You do not have to receive approval from the District Manager for manual reset and/or initial charging of the system;
(iii) The combustible gas detection system to sense the presence of hydrocarbons and initiate alarms and platform shutdown before gas concentrations reach the lower explosive limit;
(iv) The adequate ventilation system;
(v) The containment system to collect escaped liquid hydrocarbons and initiate platform shutdown;
(vi) Subsurface safety valves, including those that are self-
actuated (subsurface-controlled SSSV) or those that are activated by an ESD system and/or a fire loop (surface-controlled SSSV). You do not have to receive approval from the District Manager for routine operations in accordance with 250.817;
(vii) The pneumatic supply system; and
(viii) The system for discharging gas to the atmosphere.
(4) In instances where components of the ESD, as listed above in paragraph (3), are bypassed for maintenance, precautions must be taken to provide the equivalent level of protection that existed prior to the bypass.
(b) When wells are disconnected from producing facilities and blind flanged, or equipped with a tubing plug, or the master valves have been locked closed, you are not required to comply with the provisions of API RP 14C (incorporated by reference as specified in Sec. 250.198) or this regulation concerning the following:
(1) Automatic fail-close SSVs on wellhead assemblies, and
(2) The PSH and PSL sensors in flowlines from wells.
(c) When pressure or atmospheric vessels are isolated from production facilities (e.g., inlet valve locked closed or inlet blind-
flanged) and are to remain isolated for an extended period of time, safety device testing in accordance with API RP 14C (incorporated by reference as specified in Sec. 250.198) or this subpart is not required, with the exception of the PSV, unless the vessel is open to the atmosphere.
(d) All open-ended lines connected to producing facilities and wells must be plugged or blind-flanged, except those lines designed to be open-ended such as flare or vent lines.
(e) All new production safety system installations, component process control devices, and component safety devices must not be installed utilizing the same sensing points.
Sec. 250.870 Time delays on pressure safety low (PSL) sensors.
(a) You must apply industry standard Class B, Class C, and Class B/
C logic to all applicable PSL sensors installed on process equipment, as long as the time delay does not exceed 45 seconds. Use of a PSL sensor with a time delay greater than 45 seconds requires BSEE approval of a request under Sec. 250.141. You must document on your field test records use of a PSL sensor with a time delay greater than 45 seconds. For purposes of this section, PSL sensors are categorized as follows:
(1) Class B safety devices have logic that allows for the PSL sensors to be bypassed for a fixed time period (typically less than 15 seconds, but not more than 45 seconds). Examples include sensors used in conjunction with the design of pump and compressor panels such as PSL sensors, lubricator no-flows, and high-water jacket temperature shutdowns.
(2) Class C safety devices have logic that allows for the PSL sensors to be bypassed until the component comes into full service (i.e., the time at which the startup pressure equals or exceeds the set pressure of the PSL sensor, the system reaches a stabilized pressure, and the PSL sensor clears).
(3) Class B/C safety devices have logic that allows for the PSL sensors to incorporate a combination of Class B and Class C circuitry. These devices are used to ensure that the PSL sensors are not unnecessarily bypassed during startup and idle operations, e.g., Class B/C bypass circuitry activates when a pump is shut down during normal operations. The PSL sensor remains bypassed until the pump's start circuitry is activated and either
(i) The Class B timer expires no later than 45 seconds from start activation or
(ii) The Class C bypass is initiated until the pump builds up pressure above the PSL sensor set point and the PSL sensor comes into full service.
(b) If you do not install time delay circuitry that bypasses activation of PSL sensor shutdown logic for a specified time period on process and product transport equipment during startup and idle operations, you must manually bypass (pin out or disengage) the PSL sensor, with a time delay not to exceed 45 seconds. Use of a manual bypass that involves a time delay greater than 45 seconds requires approval from the appropriate BSEE District Manager of a request made under Sec. 250.141.
Page 52279
Sec. 250.871 Welding and burning practices and procedures.
All welding, burning, and hot-tapping activities must be conducted according to the specific requirements in Sec. 250.113. The BSEE approval of variances from your approved welding and burning practices and procedures may be requested in accordance with 250.141 regarding use of alternative procedures or equipment.
Sec. 250.872 Atmospheric vessels.
(a) You must equip atmospheric vessels used to process and/or store liquid hydrocarbons or other Class I liquids as described in API RP 500 or 505 (both incorporated by reference as specified in Sec. 250.198) with protective equipment identified in API RP 14C, section A.5 (incorporated by reference as specified in Sec. 250.198).
(b) You must ensure that all atmospheric vessels are designed and maintained to ensure the proper working conditions for LSH sensors. The LSH sensor bridle must be designed to prevent different density fluids from impacting sensor functionality. For atmospheric vessels that have oil buckets, the LSH sensor must be installed to sense the level in the oil bucket.
(c) You must ensure that all flame arrestors are maintained to ensure proper design function (installation of a system to allow for ease of inspection should be considered).
Sec. 250.873 Subsea gas lift requirements.
If you choose to install a subsea gas lift system, you must design your system in accordance with the following or as approved in your DWOP. You must:
(a) Design the gas lift supply pipeline in accordance with the API RP 14C (incorporated by reference as specified in Sec. 250.198) for the gas lift supply system located on the platform.
(b) Meet the appropriate requirements in the following table:
--------------------------------------------------------------------------------------------------------------------------------------------------------
Then you must install a . . .
-------------------------------------------------------------------------------------------
API Spec 6A and API
Spec 6AV1 (both
If your subsea gas lift system incorporated by API Spec 6A and API
introduces the lift gas to the . . reference as FSV on the gas-lift PSHL on the gas-lift Spec 6AV1 manual Additional requirements
. specified in Sec. supply pipeline . . . supply . . . isolation valve . .
250.198) gas-lift .
shutdown valve
(GLSDV), and . . .
--------------------------------------------------------------------------------------------------------------------------------------------------------
(1) Subsea Pipelines, Pipeline meet all of the upstream (in board) pipeline upstream (in downstream (out (i) Ensure that the MAOP
Risers, or Manifolds via an requirements for the of the GLSDV. board) of the GLSDV. board) of the PSHL of a subsea gas lift
External Gas Lift Pipeline. BSDV described in and above the supply pipeline is equal
250.835 and 250.836 waterline. This to the MAOP of the
on the gas-lift valve does not have production pipeline. an
supply pipeline. to be actuated. actuated fail-safe close
gas-lift isolation valve
(GLIV) located at the
point of intersection
between the gas lift
supply pipeline and the
production pipeline,
pipeline riser, or
manifold.
(ii) Install an actuated
fail-safe close gas-lift
isolation valve (GLIV)
located at the point of
intersection between the
gas lift supply pipeline
and the production
pipeline, pipeline
riser, or manifold.
Install the GLIV
downstream of the
underwater safety
valve(s) (USV) and/or
AIV(s).
(2) Subsea Well(s) through the Locate the GLSDV on the platform pipeline on the downstream (out Install an actuated, fail-
Casing String via an External Gas within 10 feet of upstream (in board) platform downstream board) of the PSHL safe-closed GLIV on the
Lift Pipeline. the first of access of the GLSDV. (out board) of the and above the gas lift supply pipeline
to the gas-lift GLSDV. waterline. This near the wellhead to
riser or topsides valve does not have provide the dual
umbilical to be actuated. function of containing
termination assembly annular pressure and
(TUTA) (i.e., within shutting off the gas
10 feet of the edge lift supply gas. If your
of the platform if subsea trees or tubing
the GLSDV is head is equipped with an
horizontal, or annulus master valve
within 10 feet above (AMV) or an annulus wing
the first accessible valve (AWV), one of
working deck, these may be designated
excluding the boat as the GLIV. Consider
landing and above installing the GLIV
the splash zone, if external to the subsea
the GLSDV is in the tree to facilitate
vertical run of a repair and or
riser, or within 10 replacement if
feet of the TUTA if necessary.
using an umbilical).
Page 52280
(3) Pipeline Risers via a Gas-Lift locate the GLSDV upstream (in board) flowline upstream (in downstream (out (i) Ensure that the gas-
Line Contained within the within 10 feet of of the GLSDV. board) of the FSV. board) of the GLSDV. lift supply flowline
Pipeline Riser. the first of access from the gas-lift
to the gas-lift compressor to the GLSDV
riser or TUTA (i.e., is pressure-rated for
within 10 feet of the MAOP of the pipeline
the edge of the riser. Ensure that any
platform if the surface equipment
GLSDV is horizontal, associated with the gas-
or within 10 feet lift system is rated for
above the first the MAOP of the pipeline
accessible working riser.
deck, excluding the (ii) Ensure that the gas-
boat landing and lift compressor
above the splash discharge pressure never
zone, if the GLSDV exceeds the MAOP of the
is in the vertical pipeline riser.
run of a riser, or (iii) Suspend and seal
within 10 feet of the gas-lift flowline
the TUTA if using an contained within the
umbilical). production riser in a
flanged API Spec. 6A
component such as an API
Spec. 6A tubing head and
tubing hanger or a
component designed,
constructed, tested, and
installed to the
requirements of API
Spec. 6A. Ensure that
all potential leak paths
upstream or near the
production riser BSDV on
the platform provide the
same level of safety and
environmental protection
as the production riser
BSDV. In addition,
ensure that this
complete assembly is
fire-rated for 30
minutes. Attach the
GLSDV by flanged
connection directly to
the API Spec. 6A
component used to
suspend and seal the gas-
lift line contained
within the production
riser. To facilitate the
repair or replacement of
the GLSDV or production
riser BSDV, you may
install a manual
isolation valve between
the GLSDV and the API
Spec. 6A component used
to suspend and seal the
gas-lift line contained
within the production
riser, or outboard of
the production riser
BSDV and inboard of the
API Spec. 6A component
used to suspend and seal
the gas-lift line
contained within the
production riser.
--------------------------------------------------------------------------------------------------------------------------------------------------------
(c) Follow the valve closure times and hydraulic bleed requirements according to your approved DWOP for the following:
(1) Electro-hydraulic control system with gas lift,
(2) Electro-hydraulic control system with gas lift with loss of communications,
(3) Direct-hydraulic control system with gas lift.
(d) Follow the gas lift valve testing requirements according to the following table:
----------------------------------------------------------------------------------------------------------------
Type of gas lift system Valve Allowable leakage rate Testing frequency
----------------------------------------------------------------------------------------------------------------
(i) Gas Lifting a subsea pipeline, GLSDV................... Zero leakage........... Monthly, not to exceed
pipeline riser, or manifold via an 6 weeks.
external gas lift pipeline.
GLIV.................... N/A.................... Function tested
quarterly, not to
exceed 120 days.
(ii) Gas Lifting a subsea well GLSDV................... Zero leakage........... Monthly, not to exceed
through the casing string via an 6 weeks.
external gas lift pipeline.
GLIV.................... 400 cc per minute of Function tested
liquid or 15 scf per quarterly, not to
minute of gas. exceed 120 days.
(iii) Gas lifting the pipeline riser GLSDV................... Zero leakage........... Monthly, not to exceed
via a gas lift line contained 6 weeks.
within the pipeline riser.
----------------------------------------------------------------------------------------------------------------
Sec. 250.874 Subsea water injection systems.
If you choose to install a subsea water injection system, you must design your system in accordance with the following or as approved in your DWOP. You must:
(a) Adhere to the water injection requirements described in API RP 14C (incorporated by reference as specified in Sec. 250.198) for the water injection equipment located on the platform. In accordance with Sec. 250.830, either a surface-controlled SSSV or a water injection valve (WIV) that is self-
Page 52281
activated and not controlled by emergency shut-down (ESD) or sensor activation must be installed in a subsea water injection well.
(b) Equip a water injection pipeline with a surface FSV and water injection shutdown valve (WISDV) on the surface facility.
(c) Install a PSHL sensor upstream (in board) of the FSV and WISDV.
(d) All subsea tree(s), wellhead(s), connector(s), tree valves, and an surface-controlled SSSV or WIV associated with a water injection system must be rated for the maximum anticipated injection pressure.
(e) Consider the effects of hydrogen sulfide (H2S) when designing your water flood system.
(f) Follow the valve closure times and hydraulic bleed requirements according to your approved DWOP for the following:
(1) Electro-hydraulic control system with water injection,
(2) Electro-hydraulic control system with water injection with loss of communications,
(3) Direct-hydraulic control system with water injection.
(g) Follow the WIV testing requirements according to the following:
(1) WIV testing table,
------------------------------------------------------------------------
Allowable leakage
Valve rate Testing frequency
------------------------------------------------------------------------
(i) WISDV................... Zero leakage........ Monthly, not to
exceed 6 weeks.
(ii) Surface-controlled SSSV 400 cc per minute of Semiannually, not to
or WIV. liquid or 15 scf exceed 6 calendar
per minute of gas. months.
------------------------------------------------------------------------
(2) Should a designated USV on a water injection well fail to test, notify the appropriate BSEE District Manager, and either designate another API Spec 6A and API Spec. 6AV1 (both incorporated by reference as specified in Sec. 250.198) certified subsea valve as your USV, or modify the valve closure time of the surface-controlled SSSV or WIV to close within 20 minutes after sensor activation for a water injection line PSHL or platform ESD/TSE (host). If a USV on a water injection well fails and the surface-controlled SSSV or WIV cannot be tested because of low reservoir pressure, submit a request to the appropriate BSEE District Manager with an alternative plan that ensures subsea shutdown capabilities.
(3) Function test the WISDV quarterly if you are operating under a departure approval to not test the WISDV. You may request approval from the appropriate BSEE District Manager to forgo testing the WISDV until the shut-in tubing pressure of the water injection well is greater than the external hydrostatic pressure, provided that the USVs meet the allowable leakage rate listed in the valve closure testing table in Sec. 250.880 (c)(4)(ii). Should the USVs fail to meet the allowable leakage rate, submit a request to the appropriate BSEE District Manager with an alternative plan that ensures subsea shutdown capabilities.
(f) If you experience a loss of communications during water injection operations, comply with the following:
(1) Notify the appropriate BSEE District Manager within 12 hours after loss of communication detection; and
(2) Obtain approval from the appropriate BSEE District Manager, to continue to inject with loss of communication. The District Manager may also order a shut-in. In that case, the BSEE District Manager may approve an alternate hydraulic bleed schedule to allow for an orderly shut-in.
Sec. 250.875 Subsea Pump Systems.
If you choose to install a subsea pump system, you must design your system in accordance with the following or as approved in your DWOP. You must:
(a) Install an isolation valve at the inlet of your subsea pump module.
(b) Install a PSHL sensor upstream of the BSDV, if the maximum possible discharge pressure of the subsea pump operating in a dead head condition (that is the maximum shut-in tubing pressure at the pump inlet and a closed BSDV) is less than the MAOP of the associated pipeline.
(c) Comply with the following, if the maximum possible discharge pressure of the subsea pump operating in a dead head situation could be greater than the MAOP of the pipeline:
(1) Install, at minimum, two independent functioning PSHL sensors upstream of the subsea pump and two independent functioning PSHL sensors downstream of the pump.
(i) Ensure PSHL sensors are operational when the subsea pump is in service; and
(ii) Ensure that PSHL activation will shut down the subsea pump, the subsea inlet isolation valve, and either the designated USV1, the USV2, or the alternate isolation valve.
(iii) If more than two PSHL sensors are installed upstream and downstream of the subsea pump for operational flexibility, then a 2 out of 3 voting logic may be implemented in which the subsea pump remains operational provided a minimum of two independent PSHL sensors are functional both upstream and downstream of the pump.
(2) Interlock the subsea pump motor with the BSDV to ensure that the pump cannot start or operate when the BSDV is closed, incorporate the following permissive signals into the control system for your subsea pump, and ensure that the subsea pump is not able to be started or re-started unless:
(i) The BSDV is open;
(ii) All automated valves downstream of the subsea pump are open;
(iii) The upstream subsea pump isolation valve is open; and
(iv) All alarms associated with the subsea pump operation (pump temperature high, pump vibration high, pump suction pressure high, pump discharge pressure high, pump suction flow low) are cleared or continuously monitored (personnel should observe visual indicators displayed at a designated control station and have the capability to initiate shut-in action in the event of an abnormal condition).
(3) Monitor the separator for seawater.
(4) Ensure that the subsea pump systems are controlled by an electro-hydraulic control system.
(d) Follow the valve closure times and hydraulic bleed requirements according to your approved DWOP for the following:
(1) Electro-hydraulic control system with a subsea pump,
(2) A loss of communications with the subsea wells and not the subsea pump control system without a ESD or sensor activation,
(3) A loss of communications with the subsea pump control system, but not the subsea wells,
(4) A loss of communications with the subsea wells and the subsea pump control system.
(e) Follow the subsea pump testing requirements by:
(1) Performing a complete subsea pump function test, including full shutdown after any intervention, or changes to the software and equipment affecting the subsea pump; and
(2) Testing the subsea pump shutdown including PSHL sensors both
Page 52282
upstream and downstream of the pump each quarter, but in no case more than 120 days between tests. This testing may be performed concurrently with the ESD function test.
Sec. 250.876 Fired and Exhaust Heated Components.
Every 5 years you must have a qualified third party remove, inspect, repair, or replace tube-type heaters that are equipped with either automatically controlled natural or forced draft burners installed in either atmospheric or pressure vessels that heat hydrocarbons and/or glycol. If removal and inspection indicates tube-
type heater deficiencies, you must complete and document repairs or replacements. You must document the inspection results, retain such documentation for at least 5 years, and make them available to BSEE upon request.
Sec. Sec. 250.877 through 250.879 Reserved
Safety Device Testing
Sec. 250.880 Production safety system testing.
(a) Notification. You must:
(1) Notify District Manager at least 72 hours before commencing production, so that BSEE may witness a preproduction test and conduct a preproduction inspection of the integrated safety system.
(2) Notify the District Manager upon commencement of production so that BSEE may conduct a complete inspection.
(3) Notify the District Manager and receive BSEE approval before you perform any subsea intervention that modifies the existing subsea infrastructure in a way that may affect the casing monitoring capabilities and testing frequencies contained in the table set forth in paragraph (c)(4).
(b) Testing methodologies. You must:
(1) Test safety valves and other equipment at the intervals specified in the tables set forth in paragraph (c) or more frequently if operating conditions warrant; and
(2) Perform testing and inspection in accordance with API RP 14C, Appendix D (incorporated by reference as specified in Sec. 250.198), and the additional requirements found in the tables of this section or as approved in the DWOP for your subsea system.
(c) Testing frequencies and allowable parameters.
(1) The following testing requirements apply to subsurface safety devices on dry tree wells:
------------------------------------------------------------------------
Testing frequency, allowable leakage
Item name rates, and other requirements
------------------------------------------------------------------------
(i) Surface-controlled SSSVs Not to exceed 6 months. Also test in
(including devices installed place when first installed or
in shut-in and injection reinstalled. If the device does not
wells). operate properly, or if a liquid leakage
rate > 400 cubic centimeters per minute
or a gas leakage rate > 15 cubic feet
per minute is observed, the device must
be removed, repaired, and reinstalled or
replaced. Testing must be according to
API RP 14B (ISO 10417:2004)
(incorporated by reference as specified
in Sec. 250.198) to ensure proper
operation.
(ii) Subsurface-controlled Not to exceed 6 months for valves not
SSSVs. installed in a landing nipple and 12
months for valves installed in a landing
nipple. The valve must be removed,
inspected, and repaired or adjusted, as
necessary, and reinstalled or replaced.
(iii) Tubing plug............ Not to exceed 6 months. Test by opening
the well to possible flow. If a liquid
leakage rate > 400 cubic centimeters per
minute or a gas leakage rate > 15 cubic
feet per minute is observed, the plug
must be removed, repaired, and
reinstalled, or replaced. An additional
tubing plug may be installed in lieu of
removal.
(iv) Injection valves........ Not to exceed 6 months. Test by opening
the well to possible flow. If a liquid
leakage rate > 400 cubic centimeters per
minute or a gas leakage rate > 15 cubic
feet per minute is observed, the valve
must be removed, repaired and
reinstalled, or replaced.
------------------------------------------------------------------------
(2) The following testing requirements apply to surface valves:
------------------------------------------------------------------------
Item name Testing frequency and requirements
------------------------------------------------------------------------
(i) PSVs..................... Once each 12 months, not to exceed 13
months between tests. Valve must either
be bench-tested or equipped to permit
testing with an external pressure
source. Weighted disc vent valves used
as PSVs on atmospheric tanks may be
disassembled and inspected in lieu of
function testing.
(ii) Automatic inlet SDVs Once each calendar month, not to exceed 6
that are actuated by a weeks between tests.
sensor on a vessel or
compressor.
(iii) SDVs in liquid Once each calendar month, not to exceed 6
discharge lines and actuated weeks between tests.
by vessel low-level sensors.
(iv) SSVs.................... Once each calendar month, not to exceed 6
weeks between tests. Valves must be
tested for both operation and leakage.
You must test according to API RP 14H
(incorporated by reference as specified
in Sec. 250.198). If an SSV does not
operate properly or if any fluid flow is
observed during the leakage test, the
valve must be immediately repaired or
replaced.
(v) FSVs..................... Once each calendar month, not to exceed 6
weeks between tests. All FSVs must be
tested, including those installed on a
host facility in lieu of being installed
at a satellite well. You must test FSVs
for leakage in accordance with the test
procedure specified in API RP 14C,
appendix D, section D4, table D2
subsection D (incorporated by reference
as specified in Sec. 250.198). If
leakage measured exceeds a liquid flow
of 400 cubic centimeters per minute or a
gas flow of 15 cubic feet per minute,
the FSV must be repaired or replaced.
------------------------------------------------------------------------
(3) The following testing requirements apply to surface safety systems and devices:
Page 52283
------------------------------------------------------------------------
Item name Testing frequency and requirements
------------------------------------------------------------------------
(i) Pumps for firewater Must be inspected and operated according
systems. to API RP 14G, Section 7.2 (incorporated
by reference as specified in Sec.
250.198).
(ii) Fire- (flame, heat, or Must be tested for operation and
smoke) detection systems. recalibrated every 3 months provided
that testing can be performed in a non-
destructive manner. Open flame or
devices operating at temperatures that
could ignite a methane-air mixture must
not be used. All combustible gas-
detection systems must be calibrated
every 3 months.
(iii) ESD systems............ (A) Pneumatic based ESD systems must be
tested for operation at least once each
calendar month, not to exceed 6 weeks
between tests. You must conduct the test
by alternating ESD stations monthly to
close at least one wellhead SSV and
verify a surface-controlled SSSV closure
for that well as indicated by control
circuitry actuation.
(B) Electronic based ESD systems must be
tested for operation at least once every
three calendar months, not to exceed 120
days between tests. The test must be
conducted by alternating ESD stations to
close at least one wellhead SSV and
verify a surface-controlled SSSV closure
for that well as indicated by control
circuitry actuation.
(C) Electronic/pneumatic based ESD
systems must be tested for operation at
least once every three calendar months,
not to exceed 120 days between tests.
The test must be conducted by
alternating ESD stations to close at
least one wellhead SSV and verify a
surface-controlled SSSV closure for that
well as indicated by control circuitry
actuation.
(iv) TSH devices............. Must be tested for operation at least
once every 12 months, excluding those
addressed in paragraph (b)(3)(v) of this
section and those that would be
destroyed by testing. Those that could
be destroyed by testing must be visually
inspected and the circuit tested for
operations at least once every 12
months.
(v) TSH shutdown controls Must be tested every 6 months and
installed on compressor repaired or replaced as necessary.
installations that can be
nondestructively tested.
(vi) Burner safety low....... Must be tested at least once every 12
months.
(vii) Flow safety low devices Must be tested at least once every 12
months.
(viii) Flame, spark, and Must be visually inspected at least once
detonation arrestors. every 12 months.
(ix) Electronic pressure Must be tested at least once every 3
transmitters and level months, but no more than 120 days elapse
sensors: PSH and PSL; LSH between tests.
and LSL.
(x) Pneumatic/electronic Must be tested at least once each
switch PSH and PSL; calendar month, but with no more than 6
pneumatic/electronic switch/ weeks elapsed time between tests.
electric analog with
mechanical linkage LSH and
LSL controls.
------------------------------------------------------------------------
(4) The following testing requirements apply to subsurface safety devices and associated systems on subsea tree wells:
------------------------------------------------------------------------
Testing frequency, allowable leakage
Item name rates, and other requirements
------------------------------------------------------------------------
(i) Surface-controlled SSSVs Tested semiannually, not to exceed 6
(including devices installed months. If the device does not operate
in shut-in and injection properly, or if a liquid leakage rate >
wells). 400 cubic centimeters per minute or a
gas leakage rate > 15 cubic feet per
minute is observed, the device must be
removed, repaired, and reinstalled or
replaced. Testing must be according to
API RP 14B (ISO 10417:2004)
(incorporated by reference as specified
in Sec. 250.198) to ensure proper
operation, or as approved in your DWOP.
(ii) USVs.................... Tested quarterly, not to exceed 120 days.
If the device does not function
properly, or if a liquid leakage rate >
400 cubic centimeters per minute or a
gas leakage rate > 15 cubic feet per
minute is observed, the valve must be
removed, repaired and reinstalled, or
replaced.
(iii) BSDVs.................. Tested monthly, not to exceed 6 weeks.
Valves must be tested for both operation
and leakage. You must test according to
API RP 14H for SSVs (incorporated by
reference as specified in Sec.
250.198). If a BSDV does not operate
properly or if any fluid flow is
observed during the leakage test, the
valve must be immediately repaired or
replaced.
(iv) Electronic ESD logic.... Tested monthly, not to exceed 6 weeks.
(v) Electronic ESD function.. Tested quarterly, not to exceed 120 days.
Shut-in at least one well during the ESD
function test. If multiple wells are
tied back to the same platform, a
different well should be shut-in with
each quarterly test.
------------------------------------------------------------------------
(5) The following testing and other requirements apply to subsea wells shut-in and disconnected from monitoring capability for periods greater than 6 months:
(i) Each well must be left with three pressure barriers: A closed and tested surface-controlled SSSV, a closed and tested USV, and one additional closed and tested tree valve.
(ii) Acceptance criteria for the tested pressure barriers prior to the rig leaving the well are as follows:
(A) The surface-controlled SSSV must be tested for leakage in accordance with Sec. 250.828(c).
(B) The USV and other pressure barrier must be tested to confirm zero leakage.
(iii) A sealing pressure cap must be installed on the flowline connection hub until installation of and connection to the flowline. A pressure cap must be designed to accommodate monitoring for pressure between the production wing valve and cap. A diagnostics capability must be integrated into the design such that a remotely operated vehicle can bleed pressure off and monitor for buildup, confirming barrier integrity.
Page 52284
(iv) Pressure monitoring at the sealing pressure cap on the flowline connection hub must be performed in each well at intervals not to exceed 12 months from the time of initial testing (prior to demobilizing rig from field).
(v) A drilling vessel capable of intervention into the disconnected well must be in the field or readily accessible for use until the wells are brought on line.
(vi) The shut-in period for each disconnected well must not exceed 24 months, unless authorized by BSEE.
Sec. Sec. 250.881-250.889 Reserved
Records and Training
Sec. 250.890 Records.
(a) You must maintain records that show the present status and history of each safety device. Your records must include dates and details of installation, removal, inspection, testing, repairing, adjustments, and reinstallation.
(b) You must maintain these records for at least 2 years. You must maintain the records at your field office nearest the OCS facility and a secure onshore location. These records must be available for review by a representative of BSEE.
(c) You must submit to the appropriate District Manager a contact list for all OCS operated platforms at least annually or when contact information is revised. The contact list must include:
(1) Designated operator name;
(2) Designated person in charge (PIC);
(3) Facility phone number(s), if applicable;
(4) Facility fax number, if applicable;
(5) Facility radio frequency, if applicable;
(6) Facility helideck rating and size, if applicable; and
(7) Facility records location if not contained on the facility.
Sec. 250.891 Safety device training.
You must ensure that personnel installing, repairing, testing, maintaining, and operating surface and subsurface safety devices and personnel operating production platforms, including but not limited to separation, dehydration, compression, sweetening, and metering operations, are trained in accordance with the procedures in subpart S of this part.
Sec. Sec. 250.892-250.899 Reserved
FR Doc. 2013-19861 Filed 8-21-13; 8:45 am
BILLING CODE 4310-VH-P
