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

Federal RegisterAug 22, 2013

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DEPARTMENT OF THE INTERIOR

Bureau of Safety and Environmental Enforcement

30 CFR Part 250

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

RIN 1014-AA10

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

AGENCY:

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

ACTION:

Proposed rule.

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:

○ 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; and

○ 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:

○ SPPE life cycle and failure reporting;

○ Foam firefighting systems;

○ Electronic-based emergency shutdown systems (ESDs);

○ Valve closure timing;

○ Valve leakage rates;

○ Boarding shut down valves (BSDV); and

○ Equipment used for high temperature and high pressure wells.

• Rewrite the subpart in plain language according to:

○ The Plain Writing Act of 2010;

○ Executive Order 12866;

○ Executive Order 12988; and

○ 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

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 (§ 250.801). In the proposed rule, requirements for subsurface safety devices would be contained in 27 sections (§§ 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 § 250.800, and end at § 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

§ 250.800 General requirements

§ 250.800 General.

§ 250.801 Subsurface safety devices

§ 250.810 Dry tree subsurface safety devices—general.

§ 250.811 Specifications for subsurface safety valves (SSSVs)—dry trees.

§ 250.812 Surface-controlled SSSVs—dry trees.

§ 250.813 Subsurface-controlled SSSVs.

§ 250.814 Design, installation, and operation of SSSVs—dry trees.

§ 250.815 Subsurface safety devices in shut-in wells—dry trees.

§ 250.816 Subsurface safety devices in injection wells—dry trees.

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

§ 250.818 Additional safety equipment—dry trees.

§ 250.821 Emergency action.

§ 250.825 Subsea tree subsurface safety devices—general.

§ 250.826 Specifications for SSSVs—subsea trees.

§ 250.827 Surface-controlled SSSVs—subsea trees.

§ 250.828 Design, installation, and operation of SSSVs—subsea trees.

§ 250.829 Subsurface safety devices in shut-in wells—subsea trees.

§ 250.830 Subsurface safety devices in injection wells—subsea trees.

§ 250.832 Additional safety equipment—subsea trees.

§ 250.837 Emergency action and safety system shutdown.

§ 250.802 Design, installation, and operation of surface production-safety systems

§ 250.819 Specification for surface safety valves (SSVs).

§ 250.820 Use of SSVs.

§ 250.833 Specification for underwater safety valves (USVs).

§ 250.834 Use of USVs.

§ 250.840 Design, installation, and maintenance—general.

§ 250.841 Platforms.

§ 250.842 Approval of safety systems design and installation features.

§ 250.803 Additional production system requirements

§ 250.850 Production system requirements—general.

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

§ 250.852 Flowlines/Headers.

§ 250.853 Safety sensors.

§ 250.855 Emergency shutdown (ESD) system.

§ 250.856 Engines.

§ 250.857 Glycol dehydration units.

§ 250.858 Gas compressors.

§ 250.859 Firefighting systems.

§ 250.862 Fire and gas-detection systems.

§ 250.863 Electrical equipment.

§ 250.864 Erosion.

§ 250.869 General platform operations.

§ 250.871 Welding and burning practices and procedures.

§ 250.804 Production safety-system testing and records

§ 250.880 Production safety system testing.

§ 250.890 Records.

§ 250.805 Safety device training

§ 250.891 Safety device training.

§ 250.806 Safety and pollution prevention equipment quality assurance requirements

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

§ 250.802 Requirements for SPPE.

§ 250.807 Additional requirements for subsurface safety valves and related equipment installed in high pressure high temperature (HPHT) environments

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

§ 250.808 Hydrogen sulfide.

§ 250.805 Hydrogen sulfide.

New Sections

§ 250.803 What SPPE failure reporting procedures must I follow?

§ 250.831 Alteration or disconnection of subsea pipeline or umbilical.

§ 250.835 Specification for all boarding shut down valves (BSDV) associated with subsea systems.

§ 250.836 Use of BSDVs

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

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

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

§ 250.860 Chemical firefighting system.

§ 250.861 Foam firefighting system.

§ 250.865 Surface pumps.

§ 250.866 Personal safety equipment.

§ 250.867 Temporary quarters and temporary equipment.

§ 250.868 Non-metallic piping.

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

§ 250.872 Atmospheric vessels.

§ 250.873 Subsea gas lift requirements.

§ 250.874 Subsea water injection systems.

§ 250.875 Subsea pump systems.

§ 250.876 Fired and Exhaust Heated Components.

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

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? (§ 250.107)

The proposed rule would revise portions of § 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 § 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 § 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 § 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 (§ 250.125)

This section would be revised to update the service fee citation to § 250.842 in paragraphs (a)(10) through (a)(15).

Documents Incorporated by Reference (§ 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 (§ 250.517)

This section would be revised to update the cross-reference to the appropriate subpart H sections from § 250.801 in current regulations to §§ 250.810 through 250.839 in the proposed rule.

Tubing and Wellhead Equipment (§ 250.618)

This section would be revised to update the cross-reference to the appropriate subpart H sections from § 250.801 in current regulations to §§ 250.810 through 250.839 in the proposed rule.

Subpart H—General Requirements

General (§ 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 § 250.800(c)(3).

Safety and Pollution Prevention Equipment (SPPE) Certification (§ 250.801)

Existing § 250.806, pertaining to SPPE certification, would be recodified as proposed § 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

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 § 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 § 250.141.

Requirements for SPPE (§ 250.802)

Existing § 250.806(a)(3), cross-referencing API requirements for SPPE, would be recodified as proposed §§ 250.802(a) and (b).

Proposed § 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 § 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 § 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 § 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? (§ 250.803)

Proposed § 250.803 would establish SPPE failure reporting procedures. Proposed § 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 § 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 § 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 (§ 250.804)

Existing § 250.807 would be recodified as proposed § 250.804, with no significant revisions proposed.

Hydrogen Sulfide (§ 250.805)

Existing § 250.808, pertaining to production operations in zones known to contain hydrogen sulfide (H

S) or in zones where the presence of H

S is unknown, as defined in § 250.490, would be recodified as proposed § 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 H

S, or in HPHT environments where the presence of H

S is unknown.

[RESERVED] §§ 250.806—250.809

Surface and Subsurface Safety Systems—Dry Trees

Dry Tree Subsurface Safety Devices—General (§ 250.810)

Existing § 250.801(a) would be recodified as proposed § 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 (§ 250.811)

Existing § 250.801(b) would be recodified as proposed § 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.

Surface-Controlled SSSVs—Dry Trees (§ 250.812)

Existing § 250.801(c) would be recodified as proposed § 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 (§ 250.813)

Existing § 250.801(d) would be recodified as proposed § 250.813, and rewritten using plain language.

Design, Installation, and Operation of SSSVs—Dry Trees (§ 250.814)

Existing § 250.801(e) would be recodified as proposed § 250.814. Proposed § 250.814(c) would also add a definition of routine operation similarly to what is found under the definitions section at § 250.601.

Subsurface Safety Devices in Shut-in Wells—Dry Trees (§ 250.815)

Existing § 250.801(f) would be recodified as proposed § 250.815, and rewritten in plain language.

Subsurface Safety Devices in Injection Wells—Dry Trees (§ 250.816)

Existing § 250.801(g) would be recodified as proposed § 250.816, and rewritten in plain language.

Temporary Removal of Subsurface Safety Devices for Routine Operations (§ 250.817)

Existing § 250.801(h) would be recodified as proposed § 250.817. The title of the section would be changed for clarity. In proposed § 250.817(c), the term “support vessel” would be added as another option for attendance on a satellite structure.

Additional Safety Equipment—Dry Trees (§ 250.818)

Existing § 250.801(i) would be recodified as proposed § 250.818, with no significant revisions proposed.

Specification for Surface Safety Valves (SSVs) (§ 250.819)

The portion of existing § 250.802(c) related to wellhead SSVs and their actuators would be included in proposed § 250.819. The portion of the existing § 250.802(c) related to underwater safety valves would be placed in proposed § 250.833.

Use of SSVs (§ 250.820)

The portion of existing § 250.802(d) related to SSVs would be included in proposed § 250.820. The portion of the existing § 250.802(d) related to underwater safety valves would be placed in proposed § 250.834.

Emergency Action (§ 250.821)

Existing § 250.801(j) would be recodified as proposed § 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 § 250.803(b)(4)(ii), the valve closure times for dry tree emergency shutdowns.

[RESERVED] §§ 250.822—250.824

Subsea and Subsurface Safety Systems—Subsea Trees

Subsea Tree Subsurface Safety Devices—General (§ 250.825)

Proposed § 250.825(a) is derived from existing § 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 §§ 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 § 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 §§ 250.810 through 250.821.

Proposed § 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 § 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 (§ 250.826)

Proposed § 250.826 would be developed from existing § 250.801(b). The portions of § 250.801(b) pertaining to subsurface-controlled SSSVs for dry tree wells would be moved to proposed § 250.811. Subsurface-controlled SSSVs are not allowed on wells with subsea trees.

Surface-Controlled SSSVs—Subsea Trees (§ 250.827)

This section would be derived from existing § 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 (§ 250.828)

Existing § 250.801(e) would be recodified as proposed § 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 (§ 250.829)

Existing § 250.801(f) would be recodified as proposed § 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 (§ 250.830)

This section would be derived from existing § 250.801(g). The substance of proposed § 250.830 for subsea tree wells would be substantially similar to the regulatory sections pertaining to proposed § 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 (§ 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

replacement plan to conduct the required monitoring and testing.

Additional Safety Equipment—Subsea Trees (§ 250.832)

This section would be derived from existing § 250.801(i), with changes made to reflect that this section covers subsea tree installations. The last sentence of existing § 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 §§ 250.838 and 250.839, described later.

Specification for Underwater Safety Valves (USVs) (§ 250.833)

Proposed § 250.833 derives in part from existing § 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 § 250.819. Proposed § 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 § 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 §§ 250.833 through 250.839 derives from existing NTL No. 2009-G36, and is currently implemented through the DWOP process described under §§ 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 (§ 250.834)

Proposed § 250.834, pertaining to the inspection, installation, maintenance, and testing of USVs, derives from existing § 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 (§ 250.835)

Proposed § 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 (§ 250.836)

Proposed § 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 (§ 250.837)

Proposed § 250.837 would replace existing § 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 § 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? (§ 250.838)

Proposed § 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 § 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? (§ 250.839)

Proposed § 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 § 250.838.

Production Safety Systems

Design, Installation, and Maintenance—General (§ 250.840)

Existing § 250.802(a) would be recodified as proposed § 250.840. Several new production components (pumps, heat exchangers, etc.) would be added to this section.

Platforms (§ 250.841)

Existing § 250.802(b) would be recodified as proposed § 250.841. New requirements for facility process piping would be added in proposed § 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 § 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 (§ 250.842)

Existing § 250.802(e) would be recodified as proposed § 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

(P&IDs) must be certified correct and stamped by a registered professional engineer. This section would also specify that the registered professional engineer, in both instances, must be registered in a State or Territory of the United States and have sufficient expertise and experience to perform the duties. The importance of these new provisions were highlighted in the Atlantis investigation report “BP'S Atlantis Oil And Gas Production Platform: An Investigation of Allegations that Operations Personnel Did Not Have Access to Engineer‐Approved Drawings,” published March 4, 2011, prepared by BSEE's predecessor agency, the Bureau of Ocean Energy Management, Regulation and Enforcement. A copy of this report is available online at the following address:

http://www.bsee.gov/uploadedFiles/03-0311%20BOEMRE%20Atlantis%20Report%20-%20FINAL.pdf.

To clarify some of the issues discussed in the Atlantis investigation report related to as-built P&IDs and to clarify other diagram requirements, proposed § 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 § 250.842(a)(1) and (2) to be submitted to the District Managers.

The proposed § 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 § 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] §§ 250.843-250.849

Additional Production System Requirements

Production System Requirements—General (§ 250.850)

The proposed rule would split existing § 250.803 into a number of sections (proposed §§ 250.850 through 250.872) to make the regulations shorter, and thus more readable. Existing § 250.803(a) would be codified as proposed § 250.850.

Pressure Vessels (Including Heat Exchangers) and Fired Vessels (§ 250.851)

Existing § 250.803(b)(1), establishing requirements for pressure and fired vessels, would be codified as proposed § 250.851. Tables would be placed in the proposed rule for clarity.

Flowlines/Headers (§ 250.852)

Existing § 250.803(b)(2), which establishes requirements for flowlines and headers, would be codified as proposed § 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 (§ 250.853)

Existing § 250.803(b)(3), pertaining to safety sensors, would be codified as proposed § 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 (§ 250.854)

Proposed § 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 §§ 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 §§ 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 (§ 250.855)

Existing § 250.803(b)(4), pertaining to emergency shutdown systems, would be recodified as proposed § 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 (§ 250.856)

Existing § 250.803(b)(5), pertaining to engine exhaust and diesel engine air intake, would be recodified as proposed § 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 (§ 250.857)

Existing § 250.803(b)(6), pertaining to glycol dehydration units, would be recodified as proposed § 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 (§ 250.858)

Existing § 250.803(b)(7), pertaining to gas compressors, would be recodified as proposed § 250.858. New proposed requirements would be added to require the use of pressure recording devices to

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 § 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 (§ 250.859)

Existing § 250.803(b)(8), pertaining to firefighting systems, would be recodified in proposed §§ 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 § 250.859(a)(2) would include additional requirements. Existing § 250.803(b)(8)(i) and (ii) would be included in proposed § 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 § 250.859(a)(5) would require that all firefighting equipment located on a facility be in good working order. Existing § 250.803(b)(8)(iv) and (v) would be included in proposed § 250.859(a)(3) and (4).

Proposed § 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 § 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 (§ 250.860)

Existing § 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 § 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 § 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 (§ 250.861)

Proposed § 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 (§ 250.862)

Existing § 250.803(b)(9), pertaining to fire and gas-detection systems, would be recodified as proposed § 250.862.

Electrical Equipment (§ 250.863)

Existing § 250.803(b)(10) pertaining to electrical equipment, would be recodified as proposed § 250.863.

Erosion (§ 250.864)

Existing § 250.803(b)(11) pertaining to erosion control, would be recodified as proposed § 250.864.

Surface Pumps (§ 250.865)

Proposed § 250.865, pertaining to surface pumps, would contain material from existing § 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 (§ 250.866)

Proposed § 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 (§ 250.867)

Proposed § 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 (§ 250.868)

Proposed § 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 (§ 250.869)

Existing § 250.803(c), pertaining to general platform operations, would be codified as proposed § 250.869, with a new requirement in the proposed rule (§ 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 § 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 (§ 250.870)

Proposed § 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 § 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 § 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 § 250.141 from the appropriate BSEE District Manager.

Welding and Burning Practices and Procedures (§ 250.871)

Existing § 250.803(d), pertaining to welding and burning practices and procedures, would be recodified as proposed § 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 § 250.141.

Atmospheric Vessels (§ 250.872)

Proposed § 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

be installed to sense the level in the oil bucket.

Subsea Gas Lift Requirements (§ 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 § 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 (§ 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 § 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 (§ 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 § 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 (§ 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] §§ 250.877-250.879

Safety Device Testing

Production Safety System Testing (§ 250.880)

Existing § 250.804(a), pertaining to production safety system testing, would be recodified as proposed § 250.880. A table would be inserted to help to clarify requirements and make them easier to find.

Proposed § 250.880(a) would include the notification requirement from existing § 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 § 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 § 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:

Item name

Allowable leakage rate testing requirements under

current regulations

The increased allowable leakage rate testing

requirements for the proposed rule

Surface-controlled SSSVs (including devices installed in shut-in and injection wells)

liquid leakage rate < 200 cubic centimeters per minute, or