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 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
52240 Federal Register / Vol. 78, No. 163 / Thursday, August 22, 2013 / Proposed Rules 

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: 

Æ General requirements; 

Æ Surface and subsurface safety 

systems—Dry trees; 

Æ Subsea and subsurface safety 

systems—Subsea trees; 

Æ Production safety systems; 

Æ Additional production system 

requirements; 

Æ Safety device testing; and 

Æ 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: 

Æ SPPE life cycle and failure 

reporting; 

Æ Foam firefighting systems; 

Æ Electronic-based emergency 

shutdown systems (ESDs); 

Æ Valve closure timing; 

Æ Valve leakage rates; 

Æ Boarding shut down valves (BSDV); 

and 

Æ Equipment used for high 

temperature and high pressure wells. 

• Rewrite the subpart in plain 

language according to: 

Æ The Plain Writing Act of 2010; 

Æ Executive Order 12866; 

Æ Executive Order 12988; and 

Æ 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 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 78, No. 163 / Thursday, August 22, 2013 / Proposed Rules 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 (§ 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. 


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52242 Federal Register / Vol. 78, No. 163 / Thursday, August 22, 2013 / Proposed Rules 

Current regulation Proposed rule 

§ 250.802 Design, installation, and operation of surface productionsafety 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 safetyrelated or have been incorporated into 

Federal regulations, including the 

standards in this rule. These standards 

are available for review, and hardcopies 

and printable versions will continue to 

be available for purchase. We are 

proposing to incorporate API standards 

in this proposed rule, and the address 

to the API Web site is: http://

publications.api.org/

documentslist.aspx. You may also call 

the API Standard/Document Contact 

IHS at 1–800–854–7179 or 303–397– 

7956 local and international. 

For the convenience of the viewing 

public who may not wish to purchase or 


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


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52244 Federal Register / Vol. 78, No. 163 / Thursday, August 22, 2013 / Proposed Rules 

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), crossreferencing 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 (H2S) or in 

zones where the presence of H2S 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 H2S, or in 

HPHT environments where the presence 

of H2S 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. 


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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 surfacecontrolled 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 


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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 Electrohydraulic 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 


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(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%20

BOEMRE%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 


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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 lockedrotor 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 alreadyapproved 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 facilityspecific 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. 


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Federal Register / Vol. 78, No. 163 / Thursday, August 22, 2013 / Proposed Rules 52249 

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 noflows, 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 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
52250 Federal Register / Vol. 78, No. 163 / Thursday, August 22, 2013 / Proposed Rules 

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 HeaterTreaters 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/TechnologyAssessment-and-Research/Project272.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: 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 78, No. 163 / Thursday, August 22, 2013 / Proposed Rules 52251 

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.

liquid leakage rate < 400 cubic centimeters per minute, 

or 

gas leakage rate < 5 cubic feet per minute .................... gas leakage rate < 15 cubic feet per minute. 

Tubing plug .......................... liquid leakage rate < 200 cubic centimeters per minute, 

or.

liquid leakage rate < 400 cubic centimeters per minute, 

or 

gas leakage rate < 5 cubic feet per minute .................... gas leakage rate < 15 cubic feet per minute. 

Injection valves .................... liquid leakage rate < 200 cubic centimeters per minute, 

or.

liquid leakage rate < 400 cubic centimeters per minute, 

or 

gas leakage rate < 5 cubic feet per minute .................... gas leakage rate < 15 cubic feet per minute. 

USVs .................................... 0 leakage rate ................................................................. liquid leakage rate < 400 cubic centimeters per minute, 

or 

gas leakage rate < 15 cubic feet per minute. 

Flow safety valves (FSV) ..... liquid leakage rate < 200 cubic centimeters per minute, 

or.

liquid leakage rate < 400 cubic centimeters per minute, 

or 

gas leakage rate < 5 cubic feet per minute .................... gas leakage rate < 15 cubic feet per minute. 

Additionally, proposed § 250.880 

would contain new requirements for 

BSDVs, changes to the testing frequency 

for underwater safety valves, and 

requirements for the testing of ESD 

systems, as well as pneumatic/

electronic switch LSH and level safety 

low (LSL) controls. This section would 

also add testing and repair/replacement 

requirements for subsurface safety 

devices and associated systems on 

subsea trees and for subsea wells shutin and disconnected from monitoring 

capability for greater than 6 months. 

Many of these requirements would be 

included in a series of proposed tables. 

[RESERVED] (§§ 250.881–250.889) 

Records and Training 

Records (§ 250.890) 

Existing § 250.804(b), pertaining to 

maintaining records of installed safety 

devices, would be recodified as 

proposed § 250.890, with new 

information submittal requirements that 

are meant to assist BSEE in contacting 

operators. 

Safety Device Training (§ 250.891) 

Existing § 250.805, pertaining to 

personnel training, would be recodified 

as proposed § 250.891. The wording of 

this section would be changed to more 

accurately capture the scope of subpart 

S training requirements. 

[RESERVED] (§§ 250.892–250.899) 

Additional Comments Solicited 

In additional to the input requested 

above, BSEE requests public comment 

on the following: 

Organization of Rule Based on Use of 

Subsea Trees and Dry Trees 

The BSEE requests general public 

comments on whether the proposed 

reorganization of the regulations by type 

of facility (subsea tree and dry tree) is 

helpful. 

Lifecycle Analysis Approach to Other 

Types of Critical Equipment Such as 

Blowout Preventers (BOPs) 

The BSEE is considering applying a 

lifecycle analysis approach to other 

types of critical equipment that we 

regulate. We are specifically requesting 

comments on how this approach could 

be used to assist in increasing the 

reliability of critical equipment such as 

BOPs. The BSEE currently relies on 

pressure testing to demonstrate BOP 

performance and reliability. Can a 

lifecycle approach replace or 

supplement these requirements? Are 

there other types of critical equipment 

that are good candidates for the life 

cycle approach? Are there industry 

standards that can serve as the basis for 

BSEE’s increased focus on the life cycle 

of critical equipment? 

Failure Reporting and Information 

Dissemination 

Industry standards such as API Spec. 

14A include processes and procedures 

for addressing the reporting and 

subsequent review of the failure of 

critical equipment. This information is 

extremely important in ensuring 

continuous improvement in the design 

and reliability of the equipment. Based 

on recent experiences in the GOM and 

input from industry, BSEE believes 

there are a variety of factors that 

discourage the timely and voluntary 

exchange of this type of information 

with the rest of the industry and BSEE. 

The BSEE believes that a more 

comprehensive and formalized 

reporting and review system would 

increase the exchange of data and allow 

the industry and BSEE to identify trends 

and issues that impact offshore safety. 

The BSEE requests comments on 

whether these failure reports should be 

submitted directly to BSEE or provided 

to an appropriate third party 

organization that would be responsible 

for reviewing and analyzing the data 

and notifying the industry of potential 

problems. The BSEE also requests 

comments on how this type of system 

could be broaden to include 

international offshore operations. 

Third Party Certification Organizations 

In various sections of the regulations, 

BSEE requires third party verification of 

the design of systems and equipment. 

The design, installation, inspection, 

maintenance, and repair of subsea 

equipment and systems presents a 

variety of unique technical challenges to 

the industry and BSEE. The BSEE 

solicits comments on the use of third 

party certification organizations to assist 

BSEE in ensuring that these systems are 

designed and maintained during its 

entire service life with an acceptable 

degree of risk. The BSEE also solicits 

comments on the use of a single 

lifecycle certification program that 

covers SPPE, risers, platforms, and 

production systems. 

Information Requested on 

Opportunities To Limit Emissions of 

Natural Gas From OCS Production 

Equipment 

Throughout the production process, 

certain volumes of natural gas are lost 

to the atmosphere through fugitive 

emissions and flaring or venting. The 

BSEE is evaluating opportunities to 

reduce methane and other air emissions 

through use of the best available 

production equipment technology and 

practices. We are seeking additional 

information on these opportunities. 

Information obtained through public 

comments on this topic may be used to 

support a Regulatory Impact Analysis. 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
52252 Federal Register / Vol. 78, No. 163 / Thursday, August 22, 2013 / Proposed Rules 

We are not proposing new production 

equipment requirements to limit 

emissions in this rulemaking, but are 

seeking additional information on 

technologies and costs for emissionslimiting equipment that can be used on 

OCS production facilities. This 

information will be considered 

consistent with applicable statutes and 

E.O. 12866/13563 during BSEE’s 

evaluation of future regulatory options. 

The GAO issued a report on this topic 

in October 2010: http://www.gao.gov/

new.items/d1134.pdf, Opportunities 

Exist To Capture Vented and Flared 

Natural Gas, Which Would Increase 

Royalty Payments and Reduce 

Greenhouse Gases. As part of Interior’s 

response to that report, BSEE is further 

evaluating opportunities to limit natural 

gas emissions on existing production 

facilities. 

Venting, flaring, and small fugitive 

releases of natural gas are often a 

necessary part of production; however, 

the lost gas has safety, economic, and 

environmental implications. It 

represents a loss of revenue for lessees, 

loss of royalty revenue for the Federal 

government, and adds to greenhouse 

gases in the atmosphere. 

Implementation of available emissionslimiting equipment and venting and 

flaring reduction technologies could 

increase sales volumes, revenue, and 

improve the environment. 

Routine preventive maintenance and 

certain technologies are applied to 

capture or flare much of this lost gas. 

The technologies’ feasibility varies and 

heavily depends on the characteristics 

of the OCS production facility. The 

following emissions-limiting equipment 

may provide for prevention, capture, or 

flaring of released natural gas: 

(1) Gas dehydration: A flash tank 

separator and vapor recovery unit that 

reduces the amount of gas that is vented 

into the atmosphere. 

(2) Pneumatic devices: Replacing 

pneumatic devices at all stages of 

production that release, or ‘‘bleed,’’ gas 

at a high rate (high-bleed pneumatics) 

with devices that bleed gas at a lower 

rate (low-bleed pneumatics), or 

installing an air pneumatic system and 

converting to instrument air instead. 

(3) Losses from flashing (reciprocating 

compressors): Replace cup ring, cups, 

and cases. How often is this preventive 

maintenance performed on 

reciprocating compressors? 

(4) Losses from flashing (centrifugal 

compressors): Replace wet seals with 

dry seals or install a gas recovery 

system. 

We are seeking additional information 

on the cost, economic viability and 

estimated effectiveness of equipment 

and these actions or others on OCS 

production facilities. If your OCS 

production facilities already employ the 

best available emissions limiting 

technology and equipment, or if there 

are other equipment or practices that 

limit emissions on OCS production 

facilities, we welcome that information 

also. Does your company have a leak 

detection (infrared/acoustic detection 

equipment) or maintenance program for 

OCS production facilities? What has 

your company found regarding the costeffectiveness and benefits of such a 

program? Comments from the public are 

also welcome. 

Flaring 

We are seeking additional information 

similar to that provided by the Offshore 

Operators Committee (OOC) at the then 

Bureau of Ocean Energy Management 

Regulation and Enforcement, March 

2011, workshop on venting and flaring. 

The profiles of operator’s production 

facilities vary widely and BSEE 

welcomes additional facility 

information from operators beyond that 

provided at the workshop. 

The workshop (75 FR 81950) 

regulations.gov docket BOEM–2010– 

0042 resulted in some information for 

the installation of flare equipment on 

GOM shelf facilities. The cost 

information in the following table was 

provided by OOC for a single operator’s 

GOM production facilities. Furthermore 

we would like to get similar information 

from other operators. We are specifically 

seeking your company count of the 

facility types listed in the table below, 

and if the associated estimated cost for 

each facility type is appropriate. 

Facility type Estimated cost for 

flare installation 

Gas already flared ......................................................................................................................................................................... $0 

Satellite facilities with no significant venting ................................................................................................................................. 0 

Facilities with adequate vent boom to support flare ..................................................................................................................... 1,629,000 

Facilities with inadequate vent boom, but structure can support flare boom installation ............................................................. 2,639,000 

Facilities with inadequate vent boom, structure cannot support flare boom installation. ............................................................. 6,664,000 

Procedural Matters 

Regulatory Planning and Review 

(Executive Orders 12866 and 13563) 

Executive Order 12866 provides that 

the Office of Information and Regulatory 

Affairs (OIRA) will review all significant 

rules. The OIRA determined that that 

this rule is not a significant rulemaking 

under E.O. 12866. Nevertheless, BSEE 

had an outside contractor prepare an 

economic analysis to assess the 

anticipated costs and potential benefits 

of the proposed rulemaking. The 

following discussions summarize the 

economic analysis; however, a complete 

copy of the economic analysis can be 

viewed at www.Regulations.gov (use the 

keyword/ID ‘‘BSEE–2012–0005’’). 

This proposed rule largely codifies 

standard industry practice and clarifies 

existing BSEE regulations and guidance. 

The requirements under the proposed 

rule align with those under the 1988 

rule and other existing documents that 

regulate and guide the industry (e.g., 

Deepwater Operations Plans (DWOPs), 

Notices to Lessees (NTLs), and 

American Petroleum Institute (API) 

industry standards). The economic 

effect of the proposed rule is confined 

to certain reporting, certification, 

inspection, and documentation 

requirements, which have an estimated 

incremental cost for offshore oil and 

natural gas production facilities in 

aggregate of approximately $170,000 per 

year (see Table 1 below) without taking 

into consideration the potential benefits 

associated with the potential reduction 

in oil spills and injuries. The following 

Table provides a summary of the 

economic analysis. 

TABLE 1—ECONOMIC ANALYSIS SUMMARY

$ costs of proposed rule = ............................................................................................................................................. ¥($1.71 million). 

Potential $ benefits of proposed rule due to increased leakage rates = ....................................................................... $1.54 million. 

(Potential $ benefits of increased leakage rates ¥ $ costs) = ...................................................................................... ¥($172,027). 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 78, No. 163 / Thursday, August 22, 2013 / Proposed Rules 52253 

TABLE 1—ECONOMIC ANALYSIS SUMMARY—Continued 

Potential benefits in $ due to potential incident avoidance of oil spills and injuries = .................................................. $19.4 million. 

Break-even risk reduction level = ................................................................................................................................... 8.07 percent. 

The proposed rule is intended to 

address, among other things, issues that 

have developed since publication in 

1988 (53 FR 10690) of the existing 

Subpart H rule. Since that time, oil and 

gas production on the OCS has moved 

into deeper waters, introducing new 

challenges for industry and BSEE. For 

example, industry has shown interest in 

employing new technologies, including 

foam firefighting systems; subsea 

pumping, water flooding, and gas lift; 

and new alloys and equipment for high 

temperature and high pressure wells. 

Many of the new provisions in the 

proposed rule would codify BSEE’s 

policies pertaining to production safety 

systems. This proposed rule would 

codify essential elements included in 

existing guidance documents, make 

clear BSEE’s basic expectations, and 

provide industry with a balance of 

predictability and flexibility to address 

concerns related to offshore oil and 

natural gas production. 

The BSEE is requesting comment on 

other options to consider, including 

alternatives to the specific provisions 

contained in the proposed rule, with the 

goal of ensuring a full discussion of 

these issues in advance of the final rule 

stage. 

The BSEE retained a contractor to 

estimate the annual economic effect of 

this proposed rule on the offshore oil 

and natural gas production industry by 

comparing the costs and potential 

benefits of the new provisions in the 

proposed rule to the baseline (i.e., 

current practice in accordance with the 

1988 rule, existing guidance documents, 

and industry standards). Existing 

impacts from the 1988 rule, DWOPs, 

NTLs, and API standards were not 

considered as costs and benefits of this 

proposed rule because they are part of 

the baseline. The analysis covered 10 

years (2012 through 2021) to capture all 

major costs and potential benefits that 

could result from this proposed rule and 

presents the estimated annual effects, as 

well as the 10-year discounted totals 

using discount rates of 3 and 7 percent. 

The BSEE welcomes comments on 

this analysis, including potential 

sources of data or information on the 

costs and potential benefits of this 

proposed rule. In summary, the 

contractor monetized the costs of the 

proposed rule for all the following 

provisions determined to result in a 

change from baseline: Reporting after a 

failure of SPPE equipment; notifying 

BSEE of production safety issues; 

certification for designs of mechanical 

and electrical systems; certification 

letter for mechanical and electrical 

systems installed in accordance with 

approved designs; certification of asbuilt diagrams of schematic piping and 

instrumentation diagrams and the safety 

analysis flow diagram; As-built piping 

and instrumentation diagrams to be 

maintained at a secure onshore location; 

inspection, testing, and certification of 

foam firefighting systems; inspection of 

fired and exhaust heated components; 

and submission of a contact list for OCS 

platforms. The analysis also considered 

the time required for industry staff to 

read and familiarize themselves with 

the new regulation. The total expected 

cost over 10 years of complying with 

these provisions is $16.87 million, or on 

average $1.7 million annually. 

In addition, the analysis valued the 

expected potential benefits of the 

proposed rule by evaluating the increase 

of the allowable leakage rates for certain 

safety valves and by evaluating oil spills 

and injuries as a whole. This proposed 

rule intends to address the unnecessary 

repair or replacement of certain safety 

valves due to a higher allowable leakage 

rate and reduce the number of incidents 

resulting in oil spills and injuries. Thus, 

the total benefits of the rule consist of 

potential benefits for increasing the 

allowable leakage rates of certain safety 

devices and avoided damages. The 

potential benefit of allowing a higher 

leakage rate for certain safety valves is 

approximately $1.54 million annually. 

Using avoided cost factors developed for 

rulemaking in the wake of the 

Deepwater Horizon oil spill, the 

contractor estimated OCS facilities 

addressed by this rule account for an 

annual average of $19.4 million dollars 

in damages due to potential spills and 

injuries, for a total maximum potential 

benefit amount of $20.9 million. While 

the proposed rule is aimed at preventing 

oil spills and injuries, the actual 

reduction in the probability of incidents 

that the proposed rule would achieve is 

uncertain. Due to this uncertainty, BSEE 

was not able to perform a standard costbenefit analysis estimating the net 

benefits of the proposed rule. As is 

common in situations where regulatory 

benefits are highly uncertain, a breakeven analysis, which estimates the 

minimum risk reduction the proposed 

rule would need to achieve for the rule 

to be cost-beneficial. However, the 

potential benefits of the proposed rule 

only need to reduce these baseline 

adverse effects by between 8 and 9 

percent to be considered cost-effective. 

This break-even analysis result suggests 

that the proposed rule would be 

beneficial even if it resulted in only one 

or two fewer typical incidents annually 

than the average of about 200 per year 

that happen under the baseline 

conditions. 

Thus, BSEE has concluded that the 

proposed rule would produce 

substantial benefits that justify the 

compliance costs that it would impose. 

Executive Order 13563 reaffirms the 

principles of E.O. 12866 while calling 

for improvements in the Nation’s 

regulatory system to promote 

predictability, to reduce uncertainty, 

and to use the best, most innovative, 

and least burdensome tools for 

achieving regulatory ends. The 

executive order directs agencies to 

consider regulatory approaches that 

reduce burdens and maintain flexibility 

and freedom of choice for the public 

where these approaches are relevant, 

feasible, and consistent with regulatory 

objectives. E.O. 13563 emphasizes 

further that regulations must be based 

on the best available science and that 

the rulemaking process must allow for 

public participation and an open 

exchange of ideas. The BSEE works 

closely with engineers and technical 

staff to ensure this rulemaking utilizes 

sound engineering principles and 

options through research, standards 

development, and interaction with 

industry. Thus, we have developed this 

rule in a manner consistent with these 

requirements. 

Regulatory Flexibility Act 

The DOI certifies that this proposed 

rule would not have a significant 

economic effect on a substantial number 

of small entities as defined under the 

Regulatory Flexibility Act (5 U.S.C. 601 

et seq.). 

The Regulatory Flexibility Act (RFA) 

at 5 U.S.C. 603 requires agencies to 

prepare a regulatory flexibility analysis 

to determine whether a regulation 

would have a significant economic 

impact on a substantial number of small 

entities. Section 605 of the RFA allows 

an agency to certify a rule in lieu of 

preparing an analysis if the regulation is 

not expected to have a significant 

economic impact on a substantial 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
52254 Federal Register / Vol. 78, No. 163 / Thursday, August 22, 2013 / Proposed Rules 

number of small entities. Further, under 

the Small Business Regulatory 

Enforcement Fairness Act of 1996, 5 

U.S.C. 801 (SBREFA), an agency is 

required to produce compliance 

guidance for small entities if the rule 

has a significant economic impact. For 

the reasons explained in this section, 

BSEE believes this rule is not likely to 

have a significant economic impact and, 

therefore, an initial regulatory flexibility 

analysis is not required by the RFA. 

However, in the interest of 

transparency, BSEE had a contractor 

prepare an Initial Regulatory Flexibility 

Analysis (IRFA) to assess the impact of 

this proposed rule on small entities, as 

defined by the applicable Small 

Business Administration (SBA) size 

standards. The following discussions 

summarize the IRFA; however, a copy of 

the complete IRFA can be viewed at 

www.Regulations.gov (use the keyword/ 

ID ‘‘BSEE–2012–0005’’). 

a. Reasons BSEE Is Considering Action 

The BSEE identified a need to revise 

Subpart H, Oil and Gas Production 

Safety Systems, which addresses 

production safety systems, subsurface 

safety devices, and safety device testing 

used in oil and natural gas production 

on the OCS, among other issues. These 

systems play a critical role in protecting 

workers and the environment. However, 

BSEE has not revised the regulation 

since its publication in 1988 (53 FR 

10690). Since that time, oil and gas 

production on the OCS has moved into 

deeper waters, introducing new 

challenges for industry and BSEE. Many 

of the new provisions in the proposed 

rule would codify BSEE guidance and 

incorporate current industry practice. In 

addition, the wording and structure of 

the 1988 rule creates confusion about 

the requirements. The BSEE has 

rewritten and reorganized the rule to 

clarify existing requirements and 

highlight important information. These 

revisions would significantly improve 

readability of the regulation. 

b. Description and Estimated Number of 

Small Entities Regulated 

A small entity is one that is 

‘‘independently owned and operated 

and which is not dominant in its field 

of operation.’’ The definition of small 

business varies from industry to 

industry in order to properly reflect 

industry size differences. 

The proposed rule would affect 

operators and holders of Federal oil and 

gas leases, as well as pipeline right-ofway holders, on the OCS. The BSEE’s 

analysis shows that this includes about 

130 companies with active operations. 

Entities that operate under this rule fall 

under the SBA’s North American 

Industry Classification System (NAICS) 

codes 211111 (Crude Petroleum and 

Natural Gas Extraction) and 213111 

(Drilling Oil and Gas Wells). For these 

NAICS classifications, a small company 

is defined as one with fewer than 500 

employees. Based on this criterion, 

approximately 90 (69 percent) of the 

companies operating on the OCS are 

considered small and the rest are 

considered large businesses. Therefore, 

BSEE estimates that the proposed rule 

would affect a substantial number of 

small entities. 

c. Description and Estimate of 

Compliance Requirements 

The BSEE has estimated the 

incremental costs for small operators, 

lease holders, and right-of-way holders 

in the offshore oil and natural gas 

production industry. Costs that already 

existed as a result of the 1988 rule, 

DWOPs, and currently-incorporated API 

standards were not considered as costs 

of this rule because they are part of the 

baseline. We have estimated the costs of 

the following provisions of the proposed 

rule: Reporting after a failure of SPPE 

equipment; notifying BSEE about 

production technical issues; 

certification, submission, and 

maintenance of designs and diagrams; 

inspection, testing, and certification of 

foam firefighting systems; inspection of 

fired and exhaust heated components; 

submission of contact list for OCS 

platforms; and familiarization with the 

new regulation. 

Table 2 below shows the annual costs 

per small entity. Because most small 

entities would not be subject to all of 

the rule provisions, we also calculated 

the most likely impact on small entities, 

or the impact associated with only 

incurring the cost for the provisions for 

foam firefighting systems, inspection of 

fired and exhaust heated components, 

submission of contact list, and 

familiarization with the new 

regulations. This calculation resulted in 

a most likely average annual cost per 

affected small entity of $5,906 as shown 

in Table 2. In addition, we calculated a 

‘‘complete compliance scenario’’ impact 

for an entity that would incur the costs 

of all of the rule provisions. As shown 

in Table 2, this complete compliance 

scenario impact is $8,183 per affected 

entity. 

We then calculated the impact on 

small entities for these three scenarios 

as a percentage of the average revenues 

for small entities in the affected 

industries. 

TABLE 2—ANNUAL COST PER SMALL

ENTITY

[10-Year average] 1

10-Year 

average 

(1) Reporting after a failure 

of SPPE equipment .......... $168 

(2) Notifying BSEE about 

technical issues ................. 378 

(3) Certification, submission, 

and maintenance of designs and diagrams ........... 1,730 

(4) Inspection, testing, and 

certification of foam firefighting systems ................ 757 

(5) Five-year inspection of 

fired and exhaust heated 

components ....................... 5,000 

(6) Submission of contact list 

for OCS platforms ............. 127 

(7) Familiarization with new 

regulation .......................... 22 

Most likely average annual 

cost per small entity (4 + 5 

+ 6 + 7) ............................. 5,906 

Complete compliance scenario average annual cost 

per small entity .................. 8,183 

1Totals may not add because of rounding. 

As shown in Table 3, the average 

costs of the two scenarios represent far 

less than 1 percent of average annual 

revenues for small entities in the 

affected industries. 

TABLE 3—COST AS A PERCENTAGE OF REVENUE

Average revenue of a small business 45,700,000 

Cost Cost/revenue 

(percent) 

Most likely total (4 + 5 + 6 + 7) ............................................................................................................................... $5,906 0.013 

Complete compliance scenario cost total ................................................................................................................ 8,183 0.018 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
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Based on this analysis, BSEE believes 

that this proposed rule would have a 

limited net direct cost impact on small 

operators, lease holders, and pipeline 

right-of-way holders beyond the 

baseline costs currently imposed by 

regulations with which industry already 

complies. The BSEE concludes that this 

proposed rule would not have a 

significant economic impact on a 

substantial number of small entities. 

d. Description of Significant 

Alternatives to the Proposed Rule 

The operating risk for small 

companies to incur safety or 

environmental accidents is not 

necessarily lower than it is for larger 

companies. Offshore operations are 

highly technical and can be hazardous. 

Adverse consequences in the event of 

incidents are the same regardless of the 

operator’s size. The proposed rule 

would reduce risk for entities of all 

sizes. Nonetheless, BSEE is requesting 

comment on the costs of these proposed 

policies on small entities, with the goal 

of ensuring thorough consideration and 

discussion at the final rule stage. We 

specifically request comments on the 

burden estimates discussed above as 

well as information on regulatory 

alternatives that would reduce the 

burden on small entities (e.g., different 

compliance requirements for small 

entities, alternative testing requirements 

and periods, and exemption from 

regulatory requirements). 

Your comments are important. The 

Small Business and Agriculture 

Regulatory Enforcement Ombudsman 

and 10 Regional Fairness Boards were 

established to receive comments from 

small businesses about Federal agency 

enforcement actions. The Ombudsman 

will annually evaluate the enforcement 

activities and rate each agency’s 

responsiveness to small business. If you 

wish to comment on the actions of 

BSEE, call 1–888–734–3247. You may 

comment to the Small Business 

Administration without fear of 

retaliation. Allegations of 

discrimination/retaliation filed with the 

Small Business Administration will be 

investigated for appropriate action. 

Small Business Regulatory Enforcement 

Fairness Act 

The proposed rule is not a major rule 

under the Small Business Regulatory 

Enforcement Fairness Act (5 U.S.C. 801 

et seq.). This proposed rule: 

a. Would not have an annual effect on 

the economy of $100 million or more. 

This proposed rule would revise the 

requirements for oil and gas production 

safety systems. The changes would not 

have an impact on the economy or any 

economic sector, productivity, jobs, the 

environment, or other units of 

government. Most of the new 

requirements are related to inspection, 

testing, and paperwork requirements, 

and would not add significant time to 

development and production processes. 

The complete annual compliance cost 

for each affected small entity is 

estimated at $8,183. 

b. Would not cause a major increase 

in costs or prices for consumers, 

individual industries, Federal, State, or 

local government agencies, or 

geographic regions. 

c. Would not have significant adverse 

effects on competition, employment, 

investment, productivity, innovation, or 

the ability of U.S.-based enterprises to 

compete with foreign-based enterprises. 

The requirements will apply to all 

entities operating on the OCS. 

Unfunded Mandates Reform Act of 

1995 

This proposed rule would not impose 

an unfunded mandate on State, local, or 

tribal governments or the private sector 

of more than $100 million per year. The 

proposed rule would not have a 

significant or unique effect on State, 

local, or tribal governments or the 

private sector. A statement containing 

the information required by Unfunded 

Mandates Reform Act (2 U.S.C. 1531 et 

seq.) is not required. 

Takings Implication Assessment 

(Executive Order 12630) 

Under the criteria in E.O. 12630, this 

proposed rule does not have significant 

takings implications. The proposed rule 

is not a governmental action capable of 

interference with constitutionally 

protected property rights. A Takings 

Implications Assessment is not 

required. 

Federalism (Executive Order 13132) 

Under the criteria in E.O. 13132, this 

proposed rule does not have federalism 

implications. This proposed rule would 

not substantially and directly affect the 

relationship between the Federal and 

State governments. To the extent that 

State and local governments have a role 

in OCS activities, this proposed rule 

would not affect that role. A Federalism 

Assessment is not required. 

The BSEE has the authority to 

regulate offshore oil and gas production. 

State governments do not have authority 

over offshore production in Federal 

waters. None of the changes in this 

proposed rule would affect areas that 

are under the jurisdiction of the States. 

It would not change the way that the 

States and the Federal government 

interact, or the way that States interact 

with private companies. 

Civil Justice Reform (Executive Order 

12988) 

This rule complies with the 

requirements of E.O. 12988. 

Specifically, this rule: 

(a) Meets the criteria of section 3(a) 

requiring that all regulations be 

reviewed to eliminate errors, ambiguity, 

and be written to minimize litigation; 

and 

(b) meets the criteria of section 3(b)(2) 

requiring that all regulations be written 

in clear language and contain clear legal 

standards. 

Consultation With Indian Tribes 

(Executive Order 13175) 

Under the criteria in E.O. 13175, we 

have evaluated this proposed rule and 

determined that it has no potential 

effects on federally recognized Indian 

tribes. 

Paperwork Reduction Act (PRA) of 

1995 

This proposed rule contains a 

collection of information that will be 

submitted to the Office of Management 

and Budget (OMB) for review and 

approval under the Paperwork 

Reduction Act of 1995 (44 U.S.C. 3501 

et seq.). As part of our continuing effort 

to reduce paperwork and respondent 

burdens, BSEE invites the public and 

other Federal agencies to comment on 

any aspect of the reporting and 

recordkeeping burden. If you wish to 

comment on the information collection 

(IC) aspects of this proposed rule, you 

may send your comments directly to 

OMB and send a copy of your comments 

to the Regulations and Standards 

Branch (see the ADDRESSES section of 

this proposed rule). Please reference; 30 

CFR Part 250, Subpart H, Oil and Gas 

Production Safety Systems, 1014–0003, 

in your comments. You may obtain a 

copy of the supporting statement for the 

new collection of information by 

contacting the Bureau’s Information 

Collection Clearance Officer at (703) 

787–1607. To see a copy of the entire 

ICR submitted to OMB, go to http://

www.reginfo.gov (select Information 

Collection Review, Currently Under 

Review). 

The PRA provides that an agency may 

not conduct or sponsor, and a person is 

not required to respond to, a collection 

of information unless it displays a 

currently valid OMB control number. 

OMB is required to make a decision 

concerning the collection of information 

contained in these proposed regulations 

30 to 60 days after publication of this 

document in the Federal Register. 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
52256 Federal Register / Vol. 78, No. 163 / Thursday, August 22, 2013 / Proposed Rules 

Therefore, a comment to OMB is best 

assured of having its full effect if OMB 

receives it by September 23, 2013. This 

does not affect the deadline for the 

public to comment to BSEE on the 

proposed regulations. 

The title of the collection of 

information for this rule is 30 CFR Part 

250, Subpart H, Oil and Gas Production 

Safety Systems (Proposed Rulemaking). 

The proposed regulations concern oil 

and gas production requirements, and 

the information is used in our efforts to 

protect life and the environment, 

conserve natural resources, and prevent 

waste. 

Potential respondents comprise 

Federal OCS oil, gas, and sulphur 

operators and lessees. The frequency of 

response varies depending upon the 

requirement. Responses to this 

collection of information are mandatory, 

or are required to obtain or retain a 

benefit; they are also submitted on 

occasion, annually, and as a result of 

situations encountered depending upon 

the requirement. The IC does not 

include questions of a sensitive nature. 

The BSEE will protect proprietary 

information according to the Freedom of 

Information Act (5 U.S.C. 552) and its 

implementing regulations (43 CFR part 

2), 30 CFR part 252, OCS Oil and Gas 

Information Program, and 30 CFR 

250.197, Data and information to be 

made available to the public or for 

limited inspection. 

As discussed earlier in the preamble, 

the proposed rule is a complete revision 

of the current subpart H. It incorporates 

guidance from several NTLs that 

respondents currently follow, and 

would codify various conditions that 

BSEE imposes when approving 

production safety systems to ensure that 

they are installed and operated in a safe 

and environmentally sound manner. 

OMB approved the IC burden of the 

current 30 CFR part 250, subpart H 

regulations under control number 1014– 

0003 (62,963 burden hours; and 

$343,794 non-hour cost burdens). When 

the final revised subpart H regulations 

take effect, the IC burden approved for 

this rulemaking will replace the 

collection under 1014–0003 in its 

entirety. 

There is also a revised paragraph 

(c)(2) proposed for 30 CFR 250.107 that 

would impose a new IC requirement. 

The paperwork burden for this proposed 

regulation is included in the submission 

to OMB for approval of the proposed IC 

for subpart H. When this rulemaking 

becomes final, the 30 CFR Part 250, 

Subpart A, paperwork burden would be 

removed from this collection of 

information and consolidated with the 

IC burden under OMB Control Number 

1014–0022, 30 CFR Part 250, Subpart A, 

General. 

The following table provides a 

breakdown of the paperwork and nonhour cost burdens for this proposed 

rulemaking. For the current 

requirements retained in the proposed 

rule, we used the approved estimated 

hour burdens and the average number of 

annual responses where discernible. 

However, there are several new 

requirements in the proposed rule as 

follows: 

• Under subpart A, (§ 250.107(c)), we 

have added proposed BAST 

requirements (+10 hours). 

• Under General Requirements 

(§ 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 (§§ 250.825–833) would add new 

burden requirements (+24 hours). 

• Under Production Safety Systems 

(§ 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, 

(§ 250.861(b)) would add new 

requirements pertaining to submission 

of foam samples annually for testing 

(+1,000 hours). 

• A proposed new section, (§ 250.867) 

would add new requirements pertaining 

to submittals for temporary quarters, 

firewater systems, or equipment (+307 

hours). 

• A proposed new section, (§ 250.870) 

added documentation requirements (+3 

hours). 

• In § 250.860, we proposed submittal 

notification and/or recordkeeping of 

minor and major changes using 

chemical only fire prevention system 

(+7 hours). 

• Proposed new, (§ 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 nonhour 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. 

Citation 30 CFR 250, 

subpart A Reporting and recordkeeping requirement Hour burden Average number of annual responses 

Annual 

burden hours 

107(c)(2) ............................. NEW: Demonstrate to us that by using BAST the benefits are insufficient to justify the cost.5 2 justifications ............ 10 

Subtotal ........................ 2 responses ............... 10 

Citation 30 CFR 250 

Subpart H and NTL(s) 

Reporting and Recordkeeping Requirement Hour Burden Average number of 

annual responses 

Annual burden 

hours 

Non-Hour Cost Burdens* 

General Requirements 

800(a) .................................. Requirements for your production safety system application.Burden included with specific 

requirements below. 

0 

800(a); 880(a) ..................... Prior to production, request approval of pre-production 

inspection; notify BSEE 72 hours before commencement so we may witness preproduction test and conduct inspection.

1 76 requests ............... 76 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 78, No. 163 / Thursday, August 22, 2013 / Proposed Rules 52257 

Citation 30 CFR 250, 

subpart A Reporting and recordkeeping requirement Hour burden Average number of annual responses 

Annual 

burden hours 

801(c) .................................. Request evaluation and approval [OORP] of other 

quality assurance programs covering manufacture of 

SPPE.

2 1 request ................... 2 

802(c)(1); 852(e)(4); 861(b) NEW: Submit statement/certification for: exposure 

functionality; pipe is suitable and manufacturer has 

complied with IVA; suitable firefighting foam per 

original manufacturer specifications.

Not considered IC under 5 CFR 

1320.3(h)(1). 

0 

802(c)(5) ............................. NEW: Document all manufacturing, traceability, quality 

control, and inspection requirements. Retain required 

documentation until 1 year after the date of decommissioning the equipment.

2 30 documents ............ 60 

803(a) .................................. NEW: Within 30 days of discovery and identification of 

SPPE failure, provide a written report of equipment 

failure to manufacturer.

2 10 reports .................. 20 

803(b) .................................. NEW: Document and determine the results of the 

SPPE failure within 60-days and corrective action 

taken.

5 10 documents ............ 50 

803(c) .................................. NEW: Submit [OORP] 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.

2 1 submittal ................. 2 

804 ...................................... Submit detailed info regarding installing SSVs in an 

HPHT environment with your APD, APM, DWOP etc.

Burdens are covered under 30 CFR 

Part 250, Subparts D and B, 1014– 

0018 and 1014–0024. 

0 

804(b); 829(b), (c); 841(b) .. NEW: District Manager will approve on a case-by-case 

basis.

Not considered IC per 5 CFR 

1320.3(h)(6). 

0 

Subtotal ........................ ......................................................................................... ........................ 128 responses ........... 210 

Surface and Subsurface Safety Systems—Dry Trees 

810; 816; 825(a); 830 ......... Submit request for a determination that a well is incapable of natural flow.53⁄4 41 wells ..................... 246 

Verify the no-flow condition of the well annually ........... 1⁄4

814(a); 821; 828(a); 

838(c)(3); 859(b); 870(b).

Specific alternate approval requests requiring approval Burden covered under 30 CFR part 

250, subpart A, 1014–0022. 

0 

817(b); 869(a) ..................... Identify well with sign on wellhead that subsurface 

safety device is removed; flag safety devices that 

are out of service; a visual indicator must be used to 

identify the bypassed safety device.

Usual/customary safety procedure for 

removing or identifying out-of-service 

safety devices. 

0 

817(b) .................................. Record removal of subsurface safety device ................. Burden included in § 250.890 of this 

subpart. 

0 

817(c) .................................. Request alternate approval of master valve [required to 

be submitted with an APM].

Burden covered under 30 CFR part 

250, subpart D, 1014–0018. 

0 

Subtotal ........................ ......................................................................................... ........................ 41 responses ............. 246 

Subsea and Subsurface Safety Systems—Subsea Trees 

Notifications 

825(b); 831; 833; 837(c)(5); 

838(c); 874(g)(2); 874(f).

NEW: Notify BSEE: (1) If you cannot test all valves 

and sensors; (2) 48 hours in advance if 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.

(1) 1⁄2

(2) 2 

(3) 1 

(4) 1⁄2

(5) 1⁄2

6 ................................

1 

1 

1 

1 

7 

827 ...................................... NEW: Request remote location approval ....................... 1 1 request ................... 1 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
52258 Federal Register / Vol. 78, No. 163 / Thursday, August 22, 2013 / Proposed Rules 

Citation 30 CFR 250, 

subpart A Reporting and recordkeeping requirement Hour burden Average number of annual responses 

Annual 

burden hours 

831 ...................................... NEW: Submit a repair/replacement plan to monitor and 

test.

2 1 submittal ................. 2 

837(a) .................................. NEW: Request approval to not shut-in a subsea well in 

an emergency.

1⁄2 10 requests ............... 5 

837(b) .................................. NEW: Prepare and submit for approval a plan to shutin wells affected by a dropped object.2 1 submittal ................. 2 

837(c)(2) ............................. NEW: Obtain approval to resume production re P/L 

PSHL sensor.

1⁄2 2 approvals ................ 1 

838(a); 839(a)(2) ................. NEW: Verify closure time of USV upon request of District Manager.2 2 verifications ............ 4 

838(c)(3) ............................. NEW: Request approval to produce after loss of communication; include alternate valve closure table.2 1 approval ................. 2 

Subtotal ........................ ......................................................................................... ........................ 28 responses ............. 24 

Production Safety Systems 

842 ...................................... Submit application, and all required/supporting information, for a production safety system with > 125 components.16 1 application .............. 16 

$5,030 per submission × 1 = $5,030 

$13,238 per offshore visit × 1 = $13,238 

$6,884 per shipyard visit × 1 = $6,884 

25–125 components ....................................................... 13 10 applications .......... 130 

$1,218 per submission × 10 = $12,180 

$8,313 per offshore visit × 1 = $8,313 

$4,766 per shipyard visit × 1 = $4,766 

< 25 components ........................................................... 8 20 applications .......... 160 

$604 per submission × 20 = $12,080 

Submit modification to application for production safety 

system with > 125 components.

9 180 modifications ...... 1,620 

$561 per submission × 180 = $100,980 

25–125 components ....................................................... 7 758 modifications ...... 5,306 

$201 per submission × 758 = $152,358 

< 25 components ........................................................... 5 329 modifications ...... 1,645 

$85 per submission × 329 = $27,965 

842(b) .................................. NEW: Your application must also include certification(s) that the designs for mechanical and electrical systems were reviewed, approved, and 

stamped by registered professional engineer. [Note: 

Upon promulgation, these certification production 

safety systems requirements will be consolidated 

into the application hour burden for the specific components].

6 32 certifications ......... 192 

842(c) .................................. NEW: Submit a certification letter that the mechanical 

and electrical systems were installed in accordance 

with approved designs.

6 32 letters ................... 192 

842(d), (e) ........................... NEW: Submit a certification letter within 60-days after 

production that the as-built diagrams, piping, and instrumentation diagrams are on file, certified correct, 

and stamped by a registered professional engineer; 

submit all the as-built diagrams.

6 

1⁄2

32 letters ................... 208 


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Citation 30 CFR 250, 

subpart A Reporting and recordkeeping requirement Hour burden Average number of annual responses 

Annual 

burden hours 

842(f) ................................... NEW: Maintain records pertaining to approved design 

and installation features and as-built pipe and instrumentation diagrams at your offshore field office or location available to the District Manager; make available to BSEE upon request and retained for the life 

of the facility.

1⁄2 32 records ................. 16 

Subtotal ........................ ......................................................................................... ........................ 1,426 responses ........ 9,485 

$343,794 non-hour cost burdens 

Additional Production System Requirements 

851(a)(4) ............................. NEW: Request approval to use uncoded pressure and 

fired vessels beyond their 18 months of continued 

use.

2 1 request ................... 2 

851(b); 852(a)(3); 858(c); 

865(b).

Maintain [most current] pressure-recorder information 

at location available to the District Manager for as 

long as information is valid.

23 615 records ............... 14,145 

851(c)(2) ............................. NEW: Request approval from District Manager for activation limits set less than 5 psi.1 10 requests ............... 10 

852(c)(1) ............................. NEW: Request approval from District Manager to vent 

to some other location.

1 10 requests ............... 10 

852(c)(2) ............................. NEW: Request a different sized PSV ............................ 1 1 request ................... 5 

852(c)(2) ............................. NEW: Request different upstream location of the PSV. 1 5 request ................... 5 

852(e) .................................. Submit required design documentation for unbonded 

flexible pipe.

Burden is covered by the application 

requirement in § 250.842. 

0 

855(b) .................................. Maintain ESD schematic listing control function of all 

safety devices at location conveniently available to 

the District Manager for the life of the facility.

15 615 listings ................ 9,225 

858(b) .................................. NEW: Request approval from District Manager to use 

different procedure for gas-well gas affected.

1 1 request ................... 1 

859(a)(2) ............................. Request approval for alternate firefighting system ........ Burden covered under 30 CFR part 

250, subpart A, 1014–0022. 

0 

859(a)(3), (4) ....................... Post diagram of firefighting system; furnish evidence 

firefighting system suitable for operations in subfreezing climates.

5 38 postings ................ 190 

859(b) .................................. NEW: Request extension from District Manager up to 7 

days of your approved departure to use chemicals.

Burden covered under 30 CFR part 

250, subpart A, 1014–0022. 

0 

860(a); related NTL(s) ........ Request approval, including but not limited to, submittal of justification and risk assessment, to use 

chemical only fire prevention and control system in 

lieu of a water system.

22 31 requests ............... 682 

860(b) .................................. NEW: Minor change(s) made after approval rec’d re 

860(a)—document change; maintain the revised 

version at facility or closest field office for BSEE review/inspection; maintain for life of facility.

1⁄2 10 minor changes ...... 5 

860(b) .................................. NEW: Major change(s) made after approval rec’d re 

860(a)—submit new request w/updated risk assessment to District Manager for approval; maintain at facility or closest field office for BSEE review/inspection; maintain for life of facility.

2 1 major change ......... 2 

861(b) .................................. NEW: Submit foam concentrate samples annually to 

manufacturer for testing.

2 500 submittals ........... 1,000 

864 ...................................... Maintain erosion control program records for 2 years; 

make available to BSEE upon request.

12 615 records ............... 7,380 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
52260 Federal Register / Vol. 78, No. 163 / Thursday, August 22, 2013 / Proposed Rules 

Citation 30 CFR 250, 

subpart A Reporting and recordkeeping requirement Hour burden Average number of annual responses 

Annual 

burden hours 

867(a) .................................. NEW: Request approval from District Manager to install temporary quarters.6 1 request ................... 6 

867(b) .................................. NEW: Submit supporting information/documentation if 

required by District Manager to install a temporary 

firewater system.

1 1 request ................... 1 

867(c) .................................. NEW: Request approval form District manager to use 

temporary equipment for well testing/clean-up.

1 300 requests ............. 300 

869(a)(3) ............................. NEW: Request approval from District Manager to bypass an element of ESS.1 2 requests ................. 2 

870 ...................................... NEW: Document PSL on your field test records w/

delay greater than 45 seconds.

1⁄2 6 records ................... 3 

871 ...................................... Request variance from District Manager on approved 

welding and burning practices.

Burden covered under 30 CFR part 

250, subpart A—1014–0022. 

0 

874(g)(2), (3) ....................... NEW: Submit request to District Manager with alternative plan ensuring subsea shutdown capability.2 5 requests ................. 10 

874(g)(3) ............................. NEW: Request approval from District Manager to forgo 

WISDV testing.

1 10 requests ............... 10 

874(f)(2) .............................. NEW: Request approval from District Manager to continue to inject w/loss of communication.1 5 requests ................. 5 

874(f)(2) .............................. NEW: Request alternate hydraulic bleed schedule ....... Burden covered under 30 CFR part 

250, subpart A, 1014–0022. 

0 

Subtotal ........................ ......................................................................................... ........................ 2,783 responses ........ 32,999 

Safety Device Testing 

880(a)(3) ............................. NEW: Notify BSEE and receive approval before performing modifications to existing subsea infrastructure.Burden covered under 30 CFR part 

250, subpart A 1014–0022. 

0 

880(c)(5)(vi) ........................ NEW: Request approval for disconnected well shut-in 

to exceed more than 2 years.

1 1 request ................... 1 

Subtotal ........................ ......................................................................................... ........................ 1 response ................ 1 

Records and Training 

890 ...................................... Maintain records for 2 years on subsurface and surface safety devices to include, but limited to, status 

and history of each device; approved design & installation date and features, inspection, testing, repair, removal, adjustments, reinstallation, etc.; at 

field office nearest facility AND a secure onshore location; make records available to BSEE.

36 615 records ............... 22,140 

890(c) .................................. NEW: Submit annually to District Manager a contact 

list for all OCS operated platforms or submit when 

revised.

1⁄2

1⁄2

1,000 annual lists ......

100 revised lists 

550 

Subtotal ........................ 1,715 responses ........ 22,690 

Total Burden Hours ..... ......................................................................................... ........................ 6,124 Responses ...... 65,665 

$343,794 Non-Hour Cost Burdens 

The BSEE specifically solicits 

comments on the following: 

(1) Is the IC necessary or useful for us 

to perform properly; (2) is the proposed 

burden accurate; (3) are there 

suggestions that will enhance the 

quality, usefulness, and clarity of the 

information to be collected; and (4) can 

we minimize the burden on the 

respondents, including the use of 

technology. 

In addition, the PRA requires agencies 

to also estimate the non-hour paperwork 

cost burdens to respondents or 

recordkeepers resulting from the 

collection of information. Therefore, if 

you have other than hour burden costs 

to generate, maintain, and disclose this 

information, you should comment and 

provide your total capital and startup 

cost components or annual operation, 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 78, No. 163 / Thursday, August 22, 2013 / Proposed Rules 52261 

maintenance, and purchase of service 

components. Generally, your estimate 

should not include burdens other than 

those associated with the provision of 

information to, or recordkeeping for the 

government; or burdens that are part of 

customary and usual business or private 

practices. For further information on 

this non-hour burden estimation 

process, refer to 5 CFR 1320.3(b)(1) and 

(2), or contact the BSEE Bureau 

Information Collection Clearance 

Officer. 

National Environmental Policy Act of 

1969 

We prepared an environmental 

assessment to determine whether this 

proposed rule would have a significant 

impact on the quality of the human 

environment under the National 

Environmental Policy Act of 1969. This 

proposed rule does not constitute a 

major Federal action significantly 

affecting the quality of the human 

environment. A detailed statement 

under the National Environmental 

Policy Act of 1969 is not required 

because we reached a Finding of No 

Significant Impact (FONSI). A copy of 

the FONSI and Environmental 

Assessment can be viewed at 

www.Regulations.gov (use the keyword/ 

ID ‘‘BSEE–2012–0005’’). 

Data Quality Act 

In developing this rule we did not 

conduct or use a study, experiment, or 

survey requiring peer review under the 

Data Quality Act (Pub. L. 106–554, app. 

C § 515, 114 Stat. 2763, 2763A–153– 

154). 

Effects on the Nation’s Energy Supply 

(Executive Order 13211) 

This proposed rule is not a significant 

energy action under the definition in 

E.O. 13211. A Statement of Energy 

Effects is not required. 

Clarity of This Regulation (Executive 

Order 12866) 

We are required by E.O. 12866, E.O. 

12988, and by the Presidential 

Memorandum of June 1, 1998, to write 

all rules in plain language. This means 

that each rule we publish must: 

(a) Be logically organized; 

(b) use the active voice to address 

readers directly; 

(c) use clear language rather than 

jargon; 

(d) be divided into short sections and 

sentences; and 

(e) use lists and tables wherever 

possible. 

If you feel that we have not met these 

requirements, send us comments by one 

of the methods listed in the ADDRESSES

section. To better help us revise the 

rule, your comments should be as 

specific as possible. For example, you 

should tell us the numbers of the 

sections or paragraphs that you find 

unclear, which sections or sentences are 

too long, the sections where you feel 

lists or tables would be useful, etc. 

Public Availability of Comments 

Before including your address, phone 

number, email address, or other 

personal identifying information in your 

comment, you should be aware that 

your entire comment—including your 

personal identifying information—may 

be made publicly available at any time. 

While you can ask us in your comment 

to withhold your personal identifying 

information from public review, we 

cannot guarantee that we will be able to 

do so. 

List of Subjects in 30 CFR Part 250 

Administrative practice and 

procedure, Continental shelf, 

Environmental impact statements, 

Environmental protection, Government 

contracts, Incorporation by reference, 

Investigations, Oil and gas exploration, 

Penalties, Pipelines, Public lands— 

mineral resources, Public lands—rightsof-way, Reporting and recordkeeping 

requirements, Sulphur. 

Dated: August 6, 2013. 

Tommy Beaudreau, 

Acting Assistant Secretary—Land and 

Minerals Management. 

For the reasons stated in the 

preamble, the Bureau of Safety and 

Environmental Enforcement (BSEE) 

proposes to amend 30 CFR Part 250 as 

follows: 

PART 250—OIL AND GAS AND 

SULPHUR OPERATIONS IN THE 

OUTER CONTINENTAL SHELF 

■ 1. The authority citation for part 250 

continues to read as follows: 

Authority: 30 U.S.C. 1751; 31 U.S.C. 9701; 

43 U.S.C. 1334. 

■ 2. Amend § 250.107 by revising 

paragraph (c) and removing paragraph 

(d) to read as follows: 

§ 250.107 What must I do to protect health, 

safety, property, and the environment? 

* * * * * 

(c)(1) Wherever failure of equipment 

may have a significant effect on safety, 

health, or the environment, you must 

use the best available and safest 

technology (BAST) that BSEE 

determines to be economically feasible 

on: 

(i) All new drilling and production 

operations and 

(ii) Wherever practicable, on existing 

operations. 

(2) You may request an exception by 

demonstrating to BSEE that the 

incremental benefits of using BAST are 

clearly insufficient to justify the 

incremental costs of utilizing such 

technologies. 

■ 3. Revise § 250.125(a)(10), (11), (12), 

(13), (14), and (15) to read as follows: 

§ 250.125 Service fees. 

(a) * * * 

Service—processing of the following: Fee amount 30 CFR 

citation 

*******

(10) New Facility Production Safety System Application for facility with more than 125 components.$5,030 A component is a piece of equipment or ancillary system that is 

protected by one or more of the safety devices required by API RP 14C 

(as incorporated by reference in § 250.198); $13,238 additional fee will 

be charged if BSEE deems it necessary to visit a facility offshore, and 

$6,884 to visit a facility in a shipyard.

§ 250.842 

(11) New Facility Production Safety System Application for facility with 25–125 components.$1,218 Additional fee of $8,313 will be charged if BSEE deems it necessary to visit a facility offshore, and $4,766 to visit a facility in a shipyard.§ 250.842 

(12) New Facility Production Safety System Application for facility with fewer than 25 components.$604 ................................................................................................................ § 250.842 

(13) Production Safety System Application—Modification with more than 125 components reviewed.$561 ................................................................................................................ § 250.842 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
52262 Federal Register / Vol. 78, No. 163 / Thursday, August 22, 2013 / Proposed Rules 

Service—processing of the following: Fee amount 30 CFR 

citation 

(14) Production Safety System Application—Modification with 25–125 components reviewed.$201 ................................................................................................................ § 250.842 

(15) Production Safety System Application—Modification with fewer than 25 components reviewed..$85 .................................................................................................................. § 250.842 

* * * * * * * 

■ 4. Amend § 250.198 as follows: 

■ a. Remove paragraphs (g)(6) and (g)(7); 

■ b. Redesignate paragraph (g)(8) as 

(g)(6); 

■ c. Revise paragraphs (g)(1) through 

(g)(3), (h)(1), (h)(51) through (h)(53), 

(h)(55) through (h)(62), (h)(65), (h)(66), 

(h)(68), (h)(70), (h)(71), (h)(73), and 

(h)(74); and 

■ d. Add new paragraph (h)(89) to read 

as follows: 

§ 250.198 Documents incorporated by 

reference. 

* * * * * 

(g) * * * 

(1) ANSI/ASME Boiler and Pressure 

Vessel Code, Section I, Rules for 

Construction of Power Boilers; 

including Appendices, 2004 Edition; 

and July 1, 2005 Addenda, and all 

Section I Interpretations Volume 55, 

incorporated by reference at 

§§ 250.851(a)(1)(i), (a)(4)(iii), (a)(5)(i), 

and 250.1629(b)(1), (b)(1)(i). 

(2) ANSI/ASME Boiler and Pressure 

Vessel Code, Section IV, Rules for 

Construction of Heating Boilers; 

including Appendices 1, 2, 3, 5, 6, and 

Non-mandatory Appendices B, C, D, E, 

F, H, I, K, L, and M, and the Guide to 

Manufacturers Data Report Forms, 2004 

Edition; July 1, 2005 Addenda, and all 

Section IV Interpretations Volume 55, 

incorporated by reference at 

§§ 250.851(a)(1)(i), (a)(4)(iii), (a)(5)(i), 

and 250.1629(b)(1), (b)(1)(i). 

(3) ANSI/ASME Boiler and Pressure 

Vessel Code, Section VIII, Rules for 

Construction of Pressure Vessels; 

Divisions 1 and 2, 2004 Edition; July 1, 

2005 Addenda, Divisions 1, 2, and 3 and 

all Section VIII Interpretations Volumes 

54 and 55, incorporated by reference at 

§§ 250.851(a)(1)(i), (a)(4)(iii), (a)(5)(i), 

and 250.1629(b)(1), (b)(1)(i). 

* * * * * 

(h) * * * 

(1) API 510, Pressure Vessel 

Inspection Code: In-Service Inspection, 

Rating, Repair, and Alteration, 

Downstream Segment, Ninth Edition, 

June 2006, Product No. C51009; 

incorporated by reference at 

§§ 250.851(a)(1)(ii) and 250.1629(b)(1); 

* * * * * 

(51) API RP 2RD, Recommended 

Practice for Design of Risers for Floating 

Production Systems (FPSs) and 

Tension-Leg Platforms (TLPs), First 

Edition, June 1998; reaffirmed, May 

2006, Errata, June 2009; Order No. 

G02RD1; incorporated by reference at 

§§ 250.800(c)(2), 250.901(a), (d), and 

250.1002(b)(5); 

(52) API RP 2SK, Recommended 

Practice for Design and Analysis of 

Stationkeeping Systems for Floating 

Structures, Third Edition, October 2005, 

Addendum, May 2008, Product No. 

G2SK03; incorporated by reference at 

§§ 250.800(c)(3) and 250.901(a), (d); 

(53) API RP 2SM, Recommended 

Practice for Design, Manufacture, 

Installation, and Maintenance of 

Synthetic Fiber Ropes for Offshore 

Mooring, First Edition, March 2001, 

Addendum, May 2007; incorporated by 

reference at §§ 250.800(c)(3) and 

250.901; 

* * * * * 

(55) API RP 14B, Recommended 

Practice for Design, Installation, Repair 

and Operation of Subsurface Safety 

Valve Systems, ANSI/API 

Recommended Practice 14B, Fifth 

Edition, October 2005, also available as 

ISO 10417: 2004, (Identical) Petroleum 

and natural gas industries—Subsurface 

safety valve systems—Design, 

installation, operation and redress, 

Product No. GX14B05; incorporated by 

reference at §§ 250.802(b), 250.803(a), 

250.814(d), 250.828(c), and 

250.880(c)(1)(i), (c)(4)(i), (c)(5)(ii)(A); 

(56) API RP 14C, Recommended 

Practice for Analysis, Design, 

Installation, and Testing of Basic 

Surface Safety Systems for Offshore 

Production Platforms, Seventh Edition, 

March 2001, Reaffirmed: March 2007; 

Product No. C14C07; incorporated by 

reference at §§ 250.125(a)(10), 

250.292(j), 250.841(a), 250.842(a)(2), 

250.850, 250.852(a)(1), 250.855, 

250.858(a), 250.862(e), 250.867(a), 

250.869(a)(3), (b), (c), 250.872(a), 

250.873(a), 250.874(a), 250.880(b)(2), 

(c)(2)(v), 250.1002(d), 250.1004(b)(9), 

250.1628(c), (d)(2), 250.1629(b)(2), 

(b)(4)(v), and 250.1630(a); 

(57) API RP 14E, Recommended 

Practice for Design and Installation of 

Offshore Production Platform Piping 

Systems, Fifth Edition, October 1991; 

Reaffirmed, March 2007, Order No. 811– 

07185; incorporated by reference at 

§§ 250.841(b), 250.842(a)(1), and 

250.1628(b)(2), (d)(3); 

(58) API RP 14F, Recommended 

Practice for Design, Installation, and 

Maintenance of Electrical Systems for 

Fixed and Floating Offshore Petroleum 

Facilities for Unclassified and Class 1, 

Division 1 and Division 2 Locations, 

Upstream Segment, Fifth Edition, July 

2008, Product No. G14F05; incorporated 

by reference §§ 250.114(c), 

250.842(b)(1), 250.862(e), and 

250.1629(b)(4)(v); 

(59) API RP 14FZ, Recommended 

Practice for Design and Installation of 

Electrical Systems for Fixed and 

Floating Offshore Petroleum Facilities 

for Unclassified and Class I, Zone 0, 

Zone 1 and Zone 2 Locations, First 

Edition, September 2001, Reaffirmed: 

March 2007; Product No. G14FZ1; 

incorporated by reference at 

§§ 250.114(c), 250.842(b)(1), 250.862(e), 

and 250.1629(b)(4)(v); 

(60) API RP 14G, Recommended 

Practice for Fire Prevention and Control 

on Fixed Open-type Offshore 

Production Platforms, Fourth Edition, 

April 2007; Product No. G14G04; 

incorporated by reference at 

§§ 250.859(a), 250.862(e), and 

250.1629(b)(3), (b)(4)(v); 

(61) API RP 14H, Recommended 

Practice for Installation, Maintenance 

and Repair of Surface Safety Valves and 

Underwater Safety Valves Offshore, 

Fifth Edition, August 2007, Product No. 

G14H05; incorporated by reference at 

§§ 250.820, 250.834, 250.836, and 

250.880(c)(2)(iv), (c)(4)(iii); 

(62) API RP 14J, Recommended 

Practice for Design and Hazards 

Analysis for Offshore Production 

Facilities, Second Edition, May 2001; 

Reaffirmed: March 2007; Product No. 

G14J02; incorporated by reference at 

§§ 250.800(b), (c)(1), 250.842(b)(3), and 

250.901(a)(14); 

* * * * * 

(65) API RP 500, Recommended 

Practice for Classification of Locations 

for Electrical Installations at Petroleum 

Facilities Classified as Class I, Division 

1 and Division 2, Second Edition, 

November 1997; Errata August 17, 1998, 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 78, No. 163 / Thursday, August 22, 2013 / Proposed Rules 52263 

Reaffirmed November 2002, API Stock 

No. C50002; incorporated by reference 

at §§ 250.114(a), 250.459, 250.842(a)(1), 

(a)(3)(i), 250.862(a), (e), 250.872(a), 

250.1628(b)(3), (d)(4)(i), and 

250.1629(b)(4)(i); 

(66) API RP 505, Recommended 

Practice for Classification of Locations 

for Electrical Installations at Petroleum 

Facilities Classified as Class I, Zone 0, 

Zone 1, and Zone 2, First Edition, 

November 1997; Errata August 17, 1998, 

American National Standards Institute, 

ANSI/API RP 505–1998, Approved: 

January 7, 1998, Order No. C50501; 

incorporated by reference at 

§§ 250.114(a), 250.459, 250.842(a)(1), 

(a)(3)(i), 250.862(a), (e), 250.872(a), 

250.1628(b)(3), (d)(4)(i), and 

250.1629(b)(4)(i); 

* * * * * 

(68) ANSI/API Spec. Q1, Specification 

for Quality Programs for the Petroleum, 

Petrochemical and Natural Gas Industry, 

Eighth Edition, December 2007, 

Effective Date: June 15, 2008, 

Addendum 1, June 2010, Effective Date: 

December 1, 2010; also available as ISO 

TS 29001:2007 (Identical), Petroleum, 

petrochemical and natural gas 

industries—Sector specific 

requirements—Requirements for 

product and service supply 

organizations, Effective Date: December 

15, 2003, API Stock No. GQ1007; 

incorporated by reference at 

§ 250.801(b), (c); 

* * * * * 

(70) API Spec. 6A, Specification for 

Wellhead and Christmas Tree 

Equipment, Nineteenth Edition, July 

2004, Effective Date: February 1, 2005; 

Contains API Monogram Annex as part 

of US National Adoption; also available 

as ISO 10423:2003 (Modified), 

Petroleum and natural gas industries— 

Drilling and production equipment— 

Wellhead and Christmas tree 

equipment; Errata 1, September 2004, 

Errata 2, April 2005, Errata 3, June 2006, 

Errata 4, August 2007, Errata 5, May 

2009, Addendum 1, February 2008, 

Addendum 2, December 2008, 

Addendum 3, December 2008, 

Addendum 4, December 2008, Product 

No. GX06A19; incorporated by reference 

at §§ 250.802(a), 250.803(a), 250.873(b), 

(b)(3)(iii), 250.874(g)(2) and 250.1002 

(b)(1), (b)(2); 

(71) API Spec. 6AV1, Specification for 

Verification Test of Wellhead Surface 

Safety Valves and Underwater Safety 

Valves for Offshore Service, First 

Edition, February 1, 1996; reaffirmed 

January 2003, API Stock No. G06AV1; 

incorporated by reference at 

§§ 250.802(a), 250.833, 250.873(b) and 

250.874(g)(2); 

* * * * * 

(73) ANSI/API Spec. 14A, 

Specification for Subsurface Safety 

Valve Equipment, Eleventh Edition, 

October 2005, Effective Date: May 1, 

2006; also available as ISO 10432:2004 

(Identical), Petroleum and natural gas 

industries—Downhole equipment— 

Subsurface safety valve equipment, 

Product No. GX14A11; incorporated by 

reference at §§ 250.802(b) and 

250.803(a) 

(74) ANSI/API Spec. 17J, 

Specification for Unbonded Flexible 

Pipe, Third Edition, July 2008, Effective 

Date: January 1, 2009, Contains API 

Monogram Annex as part of US National 

Adoption; also available as ISO 13628– 

2:2006 (Identical), Petroleum and 

natural gas industries—Design and 

operation of subsea production 

systems—Part 2: Unbonded flexible 

pipe systems for subsea and marine 

application; Product No. GX17J03; 

incorporated by reference at 

§§ 250.852(e)(1), (e)(4), 250.1002(b)(4), 

and 250.1007(a)(4)(i)(D). 

* * * * * 

(89) API 570 Piping Inspection Code: 

In-service Inspection, Rating, Repair, 

and Alteration of Piping Systems, Third 

Edition, November 2009; Product No. 

C57003; incorporated by reference at 

§ 250.841(b). 

■ 5. Revise § 250.517(e) to read as 

follows: 

§ 250. 517 Tubing and wellhead 

equipment. 

* * * * * 

(e) Subsurface safety equipment must 

be installed, maintained, and tested in 

compliance with the applicable sections 

in §§ 250.810 through 250.839 of this 

part. 

■ 6. Revise § 250.618(e) to read as 

follows: 

§ 250.618 Tubing and wellhead equipment. 

* * * * * 

(e) Subsurface safety equipment must 

be installed, maintained, and tested in 

compliance with the applicable sections 

in §§ 250.810 through 250.839 of this 

part. 

■ 7. Revise subpart H to read as follows: 

Subpart H—Oil and Gas Production Safety 

Systems 

General Requirements 

Sec. 

250.800 General. 

250.801 Safety and pollution prevention 

equipment (SPPE) certification. 

250.802 Requirements for SPPE. 

250.803 What SPPE failure reporting 

procedures must I follow? 

250.804 Additional requirements for 

subsurface safety valves (SSSVs) and 

related equipment installed in high 

pressure high temperature (HPHT) 

environments. 

250.805 Hydrogen sulfide. 

250.806–250.809 [RESERVED] 

Surface and Subsurface Safety Systems—Dry 

Trees 

250.810 Dry tree subsurface safety 

devices—general. 

250.811 Specifications for subsurface safety 

valves (SSSVs)—dry trees. 

250.812 Surface-controlled SSSVs—dry 

trees. 

250.813 Subsurface-controlled SSSVs. 

250.814 Design, installation, and operation 

of SSSVs—dry trees. 

250.815 Subsurface safety devices in shutin wells—dry trees. 

250.816 Subsurface safety devices in 

injection wells—dry trees. 

250.817 Temporary removal of subsurface 

safety devices for routine operations. 

250.818 Additional safety equipment—dry 

trees. 

250.819 Specification for surface safety 

valves (SSVs). 

250.820 Use of SSVs. 

250.821 Emergency action. 

250.822–250.824 [RESERVED] 

Subsea and Subsurface Safety Systems— 

Subsea Trees 

250.825 Subsea tree subsurface safety 

devices—general. 

250.826 Specifications for SSSVs—subsea 

trees. 

250.827 Surface-controlled SSSVs—subsea 

trees. 

250.828 Design, installation, and operation 

of SSSVs—subsea trees. 

250.829 Subsurface safety devices in shutin wells—subsea trees. 

250.830 Subsurface safety devices in 

injection wells—subsea trees. 

250.831 Alteration or disconnection of 

subsea pipeline or umbilical. 

250.832 Additional safety equipment— 

subsea trees. 

250.833 Specification for underwater safety 

valves (USVs). 

250.834 Use of USVs. 

250.835 Specification for all boarding shut 

down valves (BSDVs) associated with 

subsea systems. 

250.836 Use of BSDVs. 

250.837 Emergency action and safety 

system shutdown. 

250.838 What are the maximum allowable 

valve closure times and hydraulic 

bleeding requirements for an electrohydraulic control system? 

250.839 What are the maximum allowable 

valve closure times and hydraulic 

bleeding requirements for directhydraulic control system? 

Production Safety Systems 

250.840 Design, installation, and 

maintenance—general. 

250.841 Platforms. 

250.842 Approval of safety systems design 

and installation features. 

250.843–250.849 [RESERVED] 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
52264 Federal Register / Vol. 78, No. 163 / Thursday, August 22, 2013 / Proposed Rules 

Additional Production System Requirements 

250.850 Production system requirements— 

general. 

250.851 Pressure vessels (including heat 

exchangers) and fired vessels. 

250.852 Flowlines/Headers. 

250.853 Safety sensors. 

250.854 Floating production units equipped 

with turrets and turret mounted systems. 

250.855 Emergency shutdown (ESD) 

system. 

250.856 Engines. 

250.857 Glycol dehydration units. 

250.858 Gas compressors. 

250.859 Firefighting systems. 

250.860 Chemical firefighting system. 

250.861 Foam firefighting system. 

250.862 Fire and gas-detection systems. 

250.863 Electrical equipment. 

250.864 Erosion. 

250.865 Surface pumps. 

250.866 Personnel safety equipment. 

250.867 Temporary quarters and temporary 

equipment. 

250.868 Non-metallic piping. 

250.869 General platform operations. 

250.870 Time delays on pressure safety low 

(PSL) sensors. 

250.871 Welding and burning practices and 

procedures. 

250.872 Atmospheric vessels. 

250.873 Subsea gas lift requirements. 

250.874 Subsea water injection systems. 

250.875 Subsea pump systems. 

250.876 Fired and Exhaust Heated 

Components. 

250.877–250.879 [RESERVED] 

Safety Device Testing 

250.880 Production safety system testing. 

250.881–250.889 [RESERVED] 

Records and Training 

250.890 Records. 

250.891 Safety device training. 

250.892–250.899 [RESERVED] 

General Requirements 

§ 250.800 General. 

(a) You must design, install, use, 

maintain, and test production safety 

equipment in a manner to ensure the 

safety and protection of the human, 

marine, and coastal environments. For 

production safety systems operated in 

subfreezing climates, you must use 

equipment and procedures that account 

for floating ice, icing, and other extreme 

environmental conditions that may 

occur in the area. You must not 

commence production until BSEE 

approves your production safety system 

application and you have requested a 

preproduction inspection. 

(b) For all new production systems on 

fixed leg platforms, you must comply 

with API RP 14J, Recommended 

Practice for Design and Hazards 

Analysis for Offshore Production 

Facilities (incorporated by reference as 

specified in § 250.198); 

(c) For all new floating production 

systems (FPSs) (e.g., column-stabilizedunits (CSUs); floating production, 

storage and offloading facilities (FPSOs); 

tension-leg platforms (TLPs); spars, 

etc.), you must: 

(1) Comply with API RP 14J; 

(2) Meet the drilling, well completion, 

well workover, and well production 

riser standards of API RP 2RD, 

Recommended Practice for Design of 

Risers for Floating Production Systems 

(FPSs) and Tension-Leg Platforms 

(TLPs) (incorporated by reference as 

specified in § 250.198). Beginning 1 year 

from the publication date of the final 

rule and thereafter, you are prohibited 

from installing single bore production 

risers from floating production facilities. 

(3) Design all stationkeeping systems 

for floating production facilities to meet 

the standards of API RP 2SK, Design 

and Analysis of Stationkeeping Systems 

for Floating Structures and API RP 2SM, 

Design, Manufacture, Installation, and 

Maintenance of Synthetic Fiber Ropes 

for Offshore Mooring (both incorporated 

by reference as specified in § 250.198), 

as well as relevant U.S. Coast Guard 

regulations; and 

(4) Design stationkeeping systems for 

floating facilities to meet the structural 

requirements of §§ 250.900 through 

250.921. 

§ 250.801 Safety and pollution prevention 

equipment (SPPE) certification. 

(a) SPPE equipment. In wells located 

on the OCS, you must install only safety 

and pollution prevention equipment 

(SPPE) considered certified under 

paragraph (b) of this section or accepted 

under paragraph (c) of this section. The 

BSEE considers the following 

equipment to be types of SPPE: 

(1) Surface safety valves (SSV) and 

actuators, including those installed on 

injection wells capable of natural flow; 

(2) Boarding shut down valves 

(BSDV), 1 year after the date of 

publication of the final rule; 

(3) Underwater safety valves (USV) 

and actuators; and 

(4) Subsurface safety valves (SSSV) 

and associated safety valve locks and 

landing nipples. Subsurface-controlled 

SSSVs are not allowed on subsea wells. 

(b) Certification of SPPE. SPPE 

equipment that is manufactured and 

marked pursuant to API Spec. Q1, 

Specification for Quality Programs for 

the Petroleum, Petrochemical and 

Natural Gas Industry (ISO TS 

29001:2007) (incorporated by reference 

as specified in § 250.198), is considered 

certified SPPE under this part. The 

BSEE considers all other SPPE as 

noncertified unless approved in 

accordance with 250.801(c). 

(c) Accepting SPPE manufactured 

under other quality assurance programs. 

The BSEE may exercise its discretion to 

accept SPPE manufactured under 

quality assurance programs other than 

API Spec. Q1 (ISO TS 29001:2007), 

provided an operator submits a request 

to BSEE containing relevant information 

about the alternative program under 

§ 250.141, and receives BSEE approval. 

Such requests should be submitted to 

the Chief, Office of Offshore Regulatory 

Programs; Bureau of Safety and 

Environmental Enforcement; HE 3314; 

381 Elden Street; Herndon, Virginia 

20170–4817. 

§ 250.802 Requirements for SPPE. 

(a) All SSVs, BSDVs, and USVs must 

meet all of the specifications contained 

in API/ANSI Spec. 6A, Specification for 

Wellhead and Christmas Tree 

Equipment, (ISO 10423:2003); and Spec. 

6AV1, Specification for Verification 

Test of Wellhead Surface Safety Valves 

and Underwater Safety Valves for 

Offshore Service (both incorporated by 

reference as specified in § 250.198). 

(b) All SSSVs must meet all of the 

specifications and recommended 

practices of API/ANSI Spec. 14A, 

Specification for Subsurface Safety 

Valve Equipment (ISO 10432:2004) and 

ANSI/API RP 14B, Recommended 

Practice for Design, Installation, and 

Operation of Subsurface Safety Valve 

Systems (ISO 10417:2004), including all 

Annexes (both incorporated by 

reference as specified in § 250.198). 

(c) Requirements derived from the 

documents incorporated in this section 

for SSVs, BSDVs, USVs, and SSSVs, 

include, but are not limited to, the 

following: 

(1) Each device must be designed to 

function and to close at the most 

extreme conditions to which it may be 

exposed, including temperature, 

pressure, flow rates, and environmental 

conditions. You must have an 

independent third party review and 

certify that each device will function as 

designed under the conditions to which 

it may be exposed. The independent 

third party must have sufficient 

expertise and experience to perform the 

review and certification. 

(2) All materials and parts must meet 

the original equipment manufacturer 

specifications and acceptance criteria. 

(3) The device must pass applicable 

validation tests and functional tests 

performed by an API-licensed test 

agency. 

(4) You must have requalification 

testing performed following 

manufacture design changes. 

(5) You must comply with and 

document all manufacturing, 

traceability, quality control, and 

inspection requirements. 


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(6) You must follow specified 

installation, testing, and repair 

protocols. 

(7) You must use only qualified parts, 

procedures, and personnel to repair or 

redress equipment. 

(d) You must install certified SPPE 

according to the following table. 

If . . . Then . . . 

(1) You need to install any SPPE ............................................................ You must install certified SPPE. 

(2) A non-certified SPPE is already in service ......................................... It may remain in service on that well. 

(3) A non-certified SPPE requires offsite repair, re-manufacturing, or 

any hot work such as welding.

You must replace it with certified SPPE. 

(e) You must retain all documentation 

related to the manufacture, installation, 

testing, repair, redress, and performance 

of the SPPE equipment until 1 year after 

the date of decommissioning of the 

equipment. 

§ 250.803 What SPPE failure reporting 

procedures must I follow? 

(a) You must follow the failure 

reporting requirements contained in 

section 10.20.7.4 of API Spec. 6A for 

SSVs, BSDVs, and USVs and section 

7.10 of API Spec. 14A and Annex F of 

API RP 14B for SSSVs (all incorporated 

by reference in § 250.198). You must 

provide a written report of equipment 

failure to the manufacturer of such 

equipment within 30 days after the 

discovery and identification of the 

failure. A failure is any condition that 

prevents the equipment from meeting 

the functional specification. 

(b) You must ensure that an 

investigation and a failure analysis are 

performed within 60 days of the failure 

to determine the cause of the failure. 

You must also ensure that the results 

and any corrective action are 

documented. If the investigation and 

analysis are performed by an entity 

other than the manufacturer, you must 

ensure that the manufacturer receives a 

copy of the analysis report. 

(c) If the equipment manufacturer 

notifies you that it has changed the 

design of the equipment that failed or if 

you have changed operating or repair 

procedures as a result of a failure, then 

you must, within 30 days of such 

changes, report the design change or 

modified procedures in writing to the 

Chief of Office of Offshore Regulatory 

Programs; Bureau of Safety and 

Environmental Enforcement; HE 3314; 

381 Elden Street; Herndon, Virginia 

20170–4817. 

§ 250.804 Additional requirements for 

subsurface safety valves (SSSVs) and 

related equipment installed in high pressure 

high temperature (HPHT) environments. 

(a) If you plan to install SSSVs and 

related equipment in an HPHT 

environment, you must submit detailed 

information with your Application for 

Permit to Drill (APD), Application for 

Permit to Modify (APM), or Deepwater 

Operations Plan (DWOP) that 

demonstrates the SSSVs and related 

equipment are capable of performing in 

the applicable HPHT environment. Your 

detailed information must include the 

following: 

(1) A discussion of the SSSVs’ and 

related equipment’s design verification 

analysis; 

(2) A discussion of the SSSVs’ and 

related equipment’s design validation 

and functional testing process and 

procedures used; and 

(3) An explanation of why the 

analysis, process, and procedures 

ensure that the SSSVs and related 

equipment are fit-for-service in the 

applicable HPHT environment. 

(b) For this section, HPHT 

environment means when one or more 

of the following well conditions exist: 

(1) The completion of the well 

requires completion equipment or well 

control equipment assigned a pressure 

rating greater than 15,000 psig or a 

temperature rating greater than 350 

degrees Fahrenheit; 

(2) The maximum anticipated surface 

pressure or shut-in tubing pressure is 

greater than 15,000 psig on the seafloor 

for a well with a subsea wellhead or at 

the surface for a well with a surface 

wellhead; or 

(3) The flowing temperature is equal 

to or greater than 350 degrees 

Fahrenheit on the seafloor for a well 

with a subsea wellhead or at the surface 

for a well with a surface wellhead. 

(c) For this section, related equipment 

includes wellheads, tubing heads, 

tubulars, packers, threaded connections, 

seals, seal assemblies, production trees, 

chokes, well control equipment, and 

any other equipment that will be 

exposed to the HPHT environment. 

§ 250.805 Hydrogen sulfide. 

(a) You must conduct production 

operations in zones known to contain 

hydrogen sulfide (H2S) or in zones 

where the presence of H2S is unknown, 

as defined in § 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 (§§ 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. 

§§ 250.806–250.809 [Reserved] 

Surface and Subsurface Safety 

Systems—Dry Trees 

§ 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. 

§ 250.811 Specifications for subsurface 

safety valves (SSSVs)—dry trees. 

All surface-controlled and subsurfacecontrolled SSSVs, safety valve locks, 

landing nipples, and flow couplings 

installed in the OCS must conform to 

the requirements in §§ 250.801 through 

250.803. You may request that BSEE 

approve non-conforming SSSVs in 

accordance with § 250.141, regarding 

alternative procedures or equipment. 

§ 250.812 Surface-controlled SSSVs—dry 

trees. 

You must equip all tubing 

installations open to a hydrocarbonbearing zone that is capable of natural 

flow with a surface-controlled SSSV, 

except as specified in §§ 250.813, 

250.815, and 250.816. 

(a) The surface controls must be 

located on the site or at a BSEEapproved remote location. You may 

request that BSEE approve situating the 

surface controls at a remote location in 


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accordance with § 250.141, regarding 

alternative procedures or equipment. 

(b) You must equip dry tree wells not 

previously equipped with a surfacecontrolled SSSV, and dry tree wells in 

which a surface-controlled SSSV has 

been replaced with a subsurfacecontrolled SSSV with a surfacecontrolled SSSV when the tubing is first 

removed and reinstalled. 

§ 250.813 Subsurface-controlled SSSVs. 

You may request BSEE approval to 

equip a dry tree well with a subsurfacecontrolled SSSV in lieu of a surfacecontrolled SSSV, in accordance with 

§ 250.141 regarding alternative 

procedures or equipment, if the 

subsurface-controlled SSSV installed in 

a well equipped with a surfacecontrolled 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 surfacecontrolled SSSV. 

§ 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 

§ 250.141 or § 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 § 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 § 250.198). 

§ 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. 

§ 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 noflow condition of the well annually. 

§ 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 § 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 § 250.890. If the 

master valve is open, you must ensure 

that a trained person (see § 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 § 250.880. 

§ 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 surfacecontrolled 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. Surfacecontrolled SSSVs must close in 

response to shut-in signals from the ESD 

and in response to the fire loop or other 

fire detection devices. 

§ 250.819 Specification for surface safety 

valves (SSVs). 

All wellhead SSVs and their actuators 

must conform to the requirements 

specified in §§ 250.801 through 250.803. 

§ 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 § 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. 

§ 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 §§ 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 surfacecontrolled SSSV must close within 2 


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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 

§§ 250.141 or 250.142. 

§§ 250.822–250.824 [Reserved] 

Subsea and Subsurface Safety 

Systems—Subsea Trees 

§ 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 hydrocarbonbearing 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 § 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 

§ 250.142 

§ 250.826 Specifications for SSSVs— 

subsea trees. 

All SSSVs, safety valve locks, flow 

couplings, and landing nipples must 

conform to the requirements specified 

in §§ 250.801 through 250.803 and any 

Deepwater Operations Plan (DWOP) 

required by §§ 250.286 through 250.295. 

§ 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 §§ 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 § 250.141. 

§ 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 § 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 § 250.198). 

§ 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. 

§ 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 noflow condition of the well annually. 

§ 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. 

§ 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 surfacecontrolled 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. 

§ 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 §§ 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 § 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 


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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 § 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. 

§ 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 

§§ 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 § 250.198). 

§ 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 

§§ 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. 

§ 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 § 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. 

§ 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 §§ 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 §§ 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 surfacecontrolled SSSVs in accordance with 

the applicable tables in §§ 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 §§ 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 §§ 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 §§ 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 §§ 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. 

§ 250.838 What are the maximum 

allowable valve closure times and hydraulic 

bleeding requirements for an electrohydraulic 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 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 78, No. 163 / Thursday, August 22, 2013 / Proposed Rules 52269 

requirements listed in the following 

table or your approved DWOP: 

VALVE CLOSURE TIMING, ELECTRO-HYDRAULIC CONTROL SYSTEM

If you have the 

following . . . 

Your pipeline 

BSDV must 

. . . 

Your USV1 

must . . . 

Your USV2 must 

. . . 

Your alternate isolation valve must . . . 

Your surfacecontrolled SSSV 

must . . . 

Your LP hydraulic 

system must . . . 

Your HP hydraulic 

system must . . . 

(1) Process 

upset.

Close within 45 

seconds after 

sensor activation.

[no requirements] [no requirements] ... [no requirements] ... [no requirements] 

(2) Pipeline 

PSHL.

Close within 45 

seconds after 

sensor activation.

Close one or more valves within 2 minute and 45 seconds 

after sensor activation. Close the designated USV1 within 

20 minutes after sensor activation 

Close within 60 

minutes after 

sensor activation. 

If you use a 60- 

minute resettable 

timer, you may 

continue to reset 

the time for closure up to a maximum of 24 hours 

total.

[no requirements] ... Initiate unrestricted 

bleed within 24 

hours after sensor activation. 

(3) ESD/TSE 

(Platform).

Close within 45 

seconds after 

ESD or sensor activation.

Close within 5 minutes after ESD or 

sensor activation. If you use a 5- 

minute resettable timer, you may 

continue to reset the time for closure up to a maximum of 20 minutes total. 

Close within 20 

minutes after 

ESD or sensor 

activation.

Close within 20 

minutes after 

ESD or sensor 

activation. If you 

use a 20-minute 

resettable timer, 

you may continue 

to reset the time 

for closure up to 

a maximum of 60 

minutes total.

Initiate unrestricted 

bleed within 60 

minutes after 

ESD or sensor 

activation. If you 

use a 60-minute 

resettable timer 

you must initiate 

unrestricted bleed 

within 24 hours.

Initiate unrestricted 

bleed within 60 

minutes after 

ESD or sensor 

activation. If you 

use a 60-minute 

resettable timer 

you must initiate 

unrestricted bleed 

within 24 hours. 

(4) Subsea ESD 

(Platform) or 

BSDV TSE.

Close within 45 

seconds after 

ESD or sensor activation.

Close one or more valves within 2 minutes and 45 seconds 

after ESD or sensor activation. Close all tree valves within 

10 minutes after ESD or sensor activation. 

Close within 10 

minutes after 

ESD or sensor 

activation.

Initiate unrestricted 

bleed within 60 

minutes after 

ESD or sensor 

activation.

Initiate unrestricted 

bleed within 60 

minutes after 

ESD or sensor 

activation. 

(5) Dropped object—(Subsea 

ESD MODU).

[no requirements].Initiate valve closure immediately. You may allow for closure of the tree valves immediately prior to closure of the surface-controlled SSSV if desired. Initiate unrestricted 

bleed immediately.

Initiate unrestricted 

bleed within 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

If you have the 

following . . . 

Your pipeline 

BSDV must 

. . . 

Your USV1 

must . . . 

Your USV2 must 

. . . 

Your alternate isolation valve must . . . 

Your surfacecontrolled SSSV 

must . . . 

Your LP hydraulic 

system must . . . 

Your HP hydraulic 

system must . . . 

(1) Process 

upset.

Close within 45 

seconds after 

sensor activation.

[no requirements] [no requirements] ... [no requirements] ... [no requirements]. 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
52270 Federal Register / Vol. 78, No. 163 / Thursday, August 22, 2013 / Proposed Rules 

VALVE CLOSURE TIMING, ELECTRO-HYDRAULIC CONTROL SYSTEM WITH LOSS OF COMMUNICATION—Continued 

If you have the 

following . . . 

Your pipeline 

BSDV must 

. . . 

Your USV1 

must . . . 

Your USV2 must 

. . . 

Your alternate isolation valve must . . . 

Your surfacecontrolled SSSV 

must . . . 

Your LP hydraulic 

system must . . . 

Your HP hydraulic 

system must . . . 

(2) Pipeline 

PSHL.

Close within 45 

seconds after 

sensor activation.

Initiate closure when LP hydraulic system is bled (close 

valves within 5 minutes after sensor activation). 

Initiate closure 

when HP hydraulic system is bled 

(close within 24 

hours after sensor activation).

Initiate unrestricted 

bleed immediately, concurrent with sensor 

activation.

Initiate unrestricted 

bleed within 24 

hours after sensor activation. 

(3) ESD/TSE 

(Platform).

Close within 45 

seconds after 

ESD or sensor activation.

Initiate closure when LP hydraulic system is bled (close 

valves within 20 minutes after ESD or sensor activation). 

Initiate closure 

when HP hydraulic system is bled 

(close within 60 

minutes after 

ESD or sensor 

activation).

Initiate unrestricted 

bleed concurrent 

with BSDV closure (bleed within 

20 minutes after 

ESD or sensor 

activation).

Initiate unrestricted 

bleed within 60 

minutes after 

ESD or sensor 

activation. 

(4) Subsea ESD 

(Platform) or 

BSDV TSE.

Close within 45 

seconds after 

ESD or sensor activation.

Initiate closure when LP hydraulic system is bled (close 

valves within 5 minutes after ESD or sensor activation). 

Initiate closure 

when HP hydraulic system is bled 

(close within 20 

minutes after 

ESD or sensor 

activation).

Initiate unrestricted 

bleed immediately.

Initiate unrestricted 

bleed immediately, allowing 

for surface-controlled SSSV closure within 20 

minutes. 

(5) Dropped object—subsea 

ESD (MODU).

[no requirements].Initiate closure immediately. You may allow for closure of the tree valves immediately prior to closure of the surface-controlled SSSV if desired. Initiate unrestricted 

bleed immediately.

Initiate unrestricted 

bleed immediately 

§ 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

If you have the 

following . . . 

Your pipeline 

BSDV must 

. . . 

Your USV1 

must . . . 

Your USV2 must 

. . . 

Your alternate isolation valve must . . . 

Your surfacecontrolled SSSV 

must . . . 

Your LP hydraulic 

system must . . . 

Your HP hydraulic 

system must . . . 

(1) Process 

upset.

Close within 45 

seconds after 

sensor activation.

[no requirements] [no requirements] ... [no requirements] ... [no requirements]. 

(2) Flowline 

PSHL.

Close within 45 

seconds after 

sensor activation.

Close one or more valves within 2 minutes and 45 seconds 

after sensor activation. Close the designated USV1 within 

20 minutes after sensor activation. 

Close within 24 

hours after sensor activation.

Complete bleed of 

USV1, USV2 and 

the AIV within 20 

minutes after 

sensor activation.

Complete bleed 

within 24 hours 

after sensor activation. 

(3) ESD/TSE 

(Platform).

Close within 45 

seconds after 

ESD or sensor activation.

Close all valves within 20 minutes after ESD or sensor activation. Close within 60 

minutes after 

ESD or sensor 

activation.

Complete bleed of 

USV1, USV2 and 

the AIV within 20 

minutes after 

ESD or sensor 

activation.

Complete bleed 

within 60 minutes 

after ESD or sensor activation. 

(4) Subsea ESD 

(Platform) or 

BSDV TSE.

Close within 45 

seconds after 

ESD or sensor activation.

Close one or more valves within 2 minutes and 45 seconds 

after ESD or sensor activation. Close all tree valves within 

10 minutes after ESD or sensor activation. 

Close within 10 

minutes after 

ESD or sensor 

activation.

Complete bleed of 

USV1, USV2, 

and the AIV within 10 minutes 

after ESD or sensor activation.

Complete bleed 

within 10 minutes 

after ESD or sensor activation. 

(5) Dropped object—Subsea 

ESD.

(MODU) ...........

[no requirements].Initiate closure immediately. If desired, you may allow for closure of the tree valves 

immediately prior to closure of the surface-controlled SSSV. 

Initiate unrestricted 

bleed immediately.

Initiate unrestricted 

bleed immediately. 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 78, No. 163 / Thursday, August 22, 2013 / Proposed Rules 52271 

Production Safety Systems 

§ 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. 

§ 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 § 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 § 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. 

§ 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 instrumentation diagram . . . Showing the following: 

(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 § 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 § 250.198). 

(2) A safety analysis flow diagram (API RP 

14C, Appendix E) and the related Safety 

Analysis Function Evaluation (SAFE) chart 

(API RP 14C, subsection 4.3.3) (incorporated 

by reference as specified in § 250.198) 

If processing components are used, other than those for which Safety Analysis Checklists are 

included in API RP 14C, you must use the same analysis technique and documentation to 

determine the effects and requirements of these components upon the safety system. 

(3) Electrical system information, including (i) A plan for each platform deck and 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 § 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 and gas-detection 

systems 

Showing a functional block diagram of the detection system, including the electrical power 

supply and also including the type, location, and number of detection sensors; the type and 

kind of alarms, including emergency equipment to be activated; the method used for detection; and the method and frequency of calibration. 

(5) The service fee listed in § 250.125 The fee you must pay will be determined 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 § 250.198); 


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52272 Federal Register / Vol. 78, No. 163 / Thursday, August 22, 2013 / Proposed Rules 

(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 § 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. 

§§ 250.843—250.849 [Reserved] 

Additional Production System 

Requirements 

§ 250.850 Production system 

requirements—general. 

You must comply with the production 

safety system requirements in the 

following sections (§§ 250.851 through 

250.872), some of which are in addition 

to those contained in API RP 14C 

(incorporated by reference as specified 

in § 250.198). 

§ 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: 

Item name Applicable codes and requirements 

(1) Pressure and fired vessels where the operating pressure is or will 

be 15 pounds per square inch gauge (psig) or greater.

(i) Must be designed, fabricated, and code stamped according to applicable provisions of sections I, IV, and VIII of the ANSI/ASME Boiler 

and Pressure Vessel Code. 

(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 § 250.198). 

(2) Pressure and fired vessels (such as flare and vent scrubbers) 

where the operating pressure is or will be at least 5 psig and less 

than 15 psig.

Must employ a safety analysis checklist in the design of each component. These vessels do not need to be ASME Code stamped as 

pressure vessels. 

(3) Pressure and fired vessels where the operating pressure is or will 

be less than 5 psig.

Are not subject to the requirements of paragraphs (a)(1) and (a)(2). 

(4) Existing uncoded Pressure and fired vessels (i) in use on the effective date of the final rule; (ii) with an operating pressure of 5 psig or 

greater; and (iii) that are not code stamped in accordance with the 

ANSI/ASME Boiler and Pressure Vessel Code . . . 

Must be justified and approval obtained from the District Manager for 

their continued use beyond 18 months from the effective date of the 

final rule. 

(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 than 15 psig .............................. Must be equipped with a level 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 psig or greater ............................. (i) Must be equipped with a 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: 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 78, No. 163 / Thursday, August 22, 2013 / Proposed Rules 52273 

Type of sensor Settings Additional requirements 

(1) High pressure shut-in 

sensor.

Must be no higher than 15 percent or 5 psi (whichever 

is greater) above the highest operating pressure of 

the vessel.

Must also be set sufficiently below (5 percent or 5 psi, 

whichever is greater) the relief valve’s set pressure to 

assure that the pressure source is shut-in before the 

relief valve activates. 

(2) Low pressure shut-in 

sensor.

Must be set no lower than 15 percent or 5 psi (whichever is greater) below the lowest pressure in the operating range.You must receive specific approval from the District 

Manager for activation limits on pressure vessels that 

have a pressure safety low (PSL) sensor set less 

than 5 psi. 

§ 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 § 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 liquidhydrocarbon 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 11⁄2 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 § 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 § 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 

§ 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. 

§ 250.853 Safety sensors. 

You must ensure that: 

(a) All shutdown devices, valves, and 

pressure sensors function in a manual 

reset mode; 

(b) Sensors with integral automatic 

reset are equipped with an appropriate 

device to override the automatic reset 

mode; 

(c) All pressure sensors are equipped 

to permit testing with an external 

pressure source; and, 

(d) All level sensors are equipped to 

permit testing through an external bridle 

on all new vessel installations. 


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52274 Federal Register / Vol. 78, No. 163 / Thursday, August 22, 2013 / Proposed Rules 

§ 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 

§§ 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 

§§ 250.838 and 250.839. 

§ 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 § 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. 

§ 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 § 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. 

§ 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 § 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. 

§ 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 Opentype Offshore Production Platforms 

(incorporated by reference as specified 

in § 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 productionhandling equipment is located. You 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 78, No. 163 / Thursday, August 22, 2013 / Proposed Rules 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 § 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. 

§ 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 

following in your risk assessment . . . 

Including . . . 

(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 (facility specific).(A) Identification of all likely fire initiation scenarios (including those resulting from maintenance and repair activities). For each scenario, discuss its potential severity and identify the ignition and fuel sources. 

(B) Estimates of the fire/radiant heat exposure that personnel could be subjected to. Show how you have considered designated muster areas and evacuation routes near fuel sources and have verified proper flare boom 

sizing for radiant heat exposure. 

(iii) Human factors assessment (not facility specific).(A) Descriptions of the fire-related training your employees and contractors have received. Include details on the 

length of training, whether the training was hands-on or classroom, the training frequency, and the topics covered during the training. 

(B) Descriptions of the training your employees and contractors have received in fire prevention, control of ignition sources, and control of fuel sources when the facility is occupied. 

(C) Descriptions of the instructions and procedures you have given to your employees and contractors on the actions they should take if a fire occurs. Include those instructions and procedures specific to evacuation. State 

how you convey this information to your employees and contractor on the platform. 


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52276 Federal Register / Vol. 78, No. 163 / Thursday, August 22, 2013 / Proposed Rules 

For the use of a chemical 

firefighting system on major 

and minor manned platforms, you must provide the 

following in your risk assessment . . . 

Including . . . 

(iv) Evacuation assessment 

(facility specific).

(A) A general discussion of your 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 assessment.(A) Discussion of the reasons you are 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. 

§ 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. 

§ 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 § 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 § 250.198). 

(b) All detection systems must be 

capable of continuous monitoring. Firedetection 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 

§ 250.198). 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 78, No. 163 / Thursday, August 22, 2013 / Proposed Rules 52277 

§ 250.863 Electrical equipment. 

You must design, install, and 

maintain electrical equipment and 

systems in accordance with the 

requirements in § 250.114. 

§ 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 erosioncontrol 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. 

§ 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 § 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. 

§ 250.866 Personnel safety equipment. 

You must maintain all personnel 

safety equipment located on a facility, 

whether required or not, in good 

working condition. 

§ 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 § 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. 

§ 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 nonhydrocarbon 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. 

§ 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-computerbased 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 computerbased 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 § 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 


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52278 Federal Register / Vol. 78, No. 163 / Thursday, August 22, 2013 / Proposed Rules 

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 § 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 § 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. 

§ 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 § 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 § 250.141. 


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§ 250.871 Welding and burning practices 

and procedures. 

All welding, burning, and hot-tapping 

activities must be conducted according 

to the specific requirements in 

§ 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. 

§ 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 § 250.198) with protective 

equipment identified in API RP 14C, 

section A.5 (incorporated by reference 

as specified in § 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). 

§ 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 § 250.198) for the gas lift supply 

system located on the platform. 

(b) Meet the appropriate requirements 

in the following table: 

If your subsea gas lift 

system introduces the 

lift gas to the . . . 

Then you must install a . . . 

Additional requirements 

API Spec 6A and API 

Spec 6AV1 (both incorporated by reference as specified 

in § 250.198) gas-lift 

shutdown valve 

(GLSDV), and . . . 

FSV on the gas-lift 

supply pipeline . . . 

PSHL on the gas-lift 

supply . . . 

API Spec 6A and API 

Spec 6AV1 manual 

isolation valve . . . 

(1) Subsea Pipelines, 

Pipeline Risers, or 

Manifolds via an External Gas Lift Pipeline.

meet all of the requirements for the 

BSDV described in 

250.835 and 

250.836 on the 

gas-lift supply pipeline.

upstream (in board) 

of the GLSDV.

pipeline upstream (in 

board) of the 

GLSDV.

downstream (out 

board) of the PSHL 

and above the waterline. This valve 

does not have to 

be actuated.

(i) Ensure that the MAOP of a subsea gas 

lift supply pipeline is equal to the MAOP 

of the production pipeline. 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. 

(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 Casing 

String via an External 

Gas Lift Pipeline.

Locate the GLSDV 

within 10 feet of 

the first of access 

to the gas-lift riser 

or topsides umbilical termination assembly (TUTA) 

(i.e., within 10 feet 

of the edge of the 

platform if the 

GLSDV is horizontal, or within 10 

feet above the first 

accessible working 

deck, excluding the 

boat landing and 

above the splash 

zone, if the GLSDV 

is in the vertical 

run of a riser, or 

within 10 feet of 

the TUTA if using 

an umbilical).

on the platform upstream (in board) 

of the GLSDV.

pipeline on the platform downstream 

(out board) of the 

GLSDV.

downstream (out 

board) of the PSHL 

and above the waterline. This valve 

does not have to 

be actuated.

Install an actuated, fail-safe-closed GLIV 

on the gas lift supply pipeline near the 

wellhead to provide the dual function of 

containing annular pressure and shutting 

off the gas lift supply gas. If your subsea 

trees or tubing head is equipped with an 

annulus master valve (AMV) or an annulus wing valve (AWV), one of these may 

be designated as the GLIV. Consider installing the GLIV external to the subsea 

tree to facilitate repair and or replacement if necessary. 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
52280 Federal Register / Vol. 78, No. 163 / Thursday, August 22, 2013 / Proposed Rules 

If your subsea gas lift 

system introduces the 

lift gas to the . . . 

Then you must install a . . . 

Additional requirements 

API Spec 6A and API 

Spec 6AV1 (both incorporated by reference as specified 

in § 250.198) gas-lift 

shutdown valve 

(GLSDV), and . . . 

FSV on the gas-lift 

supply pipeline . . . 

PSHL on the gas-lift 

supply . . . 

API Spec 6A and API 

Spec 6AV1 manual 

isolation valve . . . 

(3) Pipeline Risers via 

a Gas-Lift Line Contained within the 

Pipeline Riser.

locate the GLSDV 

within 10 feet of 

the first of access 

to the gas-lift riser 

or TUTA (i.e., within 10 feet of the 

edge of the platform if the GLSDV 

is horizontal, or 

within 10 feet 

above the first accessible working 

deck, excluding the 

boat landing and 

above the splash 

zone, if the GLSDV 

is in the vertical 

run of a riser, or 

within 10 feet of 

the TUTA if using 

an umbilical).

upstream (in board) 

of the GLSDV.

flowline upstream (in 

board) of the FSV.

downstream (out 

board) of the 

GLSDV.

(i) Ensure that the gas-lift supply flowline 

from the gas-lift compressor to the 

GLSDV is pressure-rated for the MAOP 

of the pipeline riser. Ensure that any surface equipment associated with the gaslift system is rated for the MAOP of the 

pipeline riser. 

(ii) Ensure that the gas-lift compressor discharge pressure never exceeds the 

MAOP of the pipeline riser. 

(iii) Suspend and seal the gas-lift flowline 

contained within the 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 gaslift 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, pipeline 

riser, or manifold via an external gas 

lift pipeline.

GLSDV ......... Zero leakage ............................................ Monthly, not to exceed 6 weeks. 

GLIV ............. N/A ........................................................... Function tested quarterly, not to exceed 

120 days. 

(ii) Gas Lifting a subsea well through the 

casing string via an external gas lift 

pipeline.

GLSDV ......... Zero leakage ............................................ Monthly, not to exceed 6 weeks. 

GLIV ............. 400 cc per minute of liquid or 15 scf per 

minute of gas.

Function tested quarterly, not to exceed 

120 days. 

(iii) Gas lifting the pipeline riser via a gas 

lift line contained within the pipeline 

riser.

GLSDV ......... Zero leakage ............................................ Monthly, not to exceed 6 weeks. 

§ 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 § 250.198) for the water injection 

equipment located on the platform. In 

accordance with § 250.830, either a 

surface-controlled SSSV or a water 

injection valve (WIV) that is selfVerDate Mar<15>2010 17:10 Aug 21, 2013 Jkt 229001 PO 00000 Frm 00042 Fmt 4701 Sfmt 4702 E:\FR\FM\22AUP2.SGM 22AUP2

tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 78, No. 163 / Thursday, August 22, 2013 / Proposed Rules 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 surfacecontrolled 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, 

Valve Allowable leakage rate Testing frequency 

(i) WISDV ........................................................... Zero leakage .................................................... Monthly, not to exceed 6 weeks. 

(ii) Surface-controlled SSSV or WIV .................. 400 cc per minute of liquid or 15 scf per 

minute of gas.

Semiannually, not to exceed 6 calendar 

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 

§ 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 shutin 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 § 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. 

§ 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 electrohydraulic 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 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
52282 Federal Register / Vol. 78, No. 163 / Thursday, August 22, 2013 / Proposed Rules 

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. 

§ 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. 

§§ 250.877 through 250.879 [Reserved] 

Safety Device Testing 

§ 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 § 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: 

Item name Testing frequency, allowable leakage rates, and other requirements 

(i) Surface-controlled SSSVs (including devices 

installed in shut-in and injection wells).

Not to exceed 6 months. Also test in place when first installed or reinstalled. If the device does 

not operate properly, or if a liquid leakage rate > 400 cubic centimeters per minute or a gas 

leakage rate > 15 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 § 250.198) to ensure proper operation. 

(ii) Subsurface-controlled SSSVs ....................... Not to exceed 6 months for valves not installed in a landing nipple and 12 months for valves 

installed in a landing nipple. The valve must be removed, inspected, and repaired or adjusted, as necessary, and reinstalled or replaced. 

(iii) Tubing plug ................................................... 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 benchtested 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 that are actuated by a 

sensor on a vessel or compressor.

Once each calendar month, not to exceed 6 weeks between tests. 

(iii) SDVs in liquid discharge lines and actuated 

by vessel low-level sensors.

Once each calendar month, not to exceed 6 weeks between tests. 

(iv) SSVs ............................................................. Once each calendar month, not to exceed 6 weeks between tests. Valves must be tested for 

both operation and leakage. You must test according to API RP 14H (incorporated by reference as specified in § 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 

§ 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: 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
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Item name Testing frequency and requirements 

(i) Pumps for firewater systems .......................... Must be inspected and operated according to API RP 14G, Section 7.2 (incorporated by reference as specified in § 250.198). 

(ii) Fire- (flame, heat, or smoke) detection systems.Must be tested for operation and 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 installed on compressor installations that can be nondestructively tested.Must be tested every 6 months and repaired or replaced as necessary. 

(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 detonation arrestors ...... Must be visually inspected at least once every 12 months. 

(ix) Electronic pressure transmitters and level 

sensors: PSH and PSL; LSH and LSL.

Must be tested at least once every 3 months, but no more than 120 days elapse between 

tests. 

(x) Pneumatic/electronic switch PSH and PSL; 

pneumatic/electronic switch/electric analog 

with mechanical linkage LSH and LSL controls.

Must be tested at least once each calendar month, but with no more than 6 weeks elapsed 

time between tests. 

(4) The following testing requirements 

apply to subsurface safety devices and 

associated systems on subsea tree wells: 

Item name Testing frequency, allowable leakage rates, and other requirements 

(i) Surface-controlled SSSVs (including devices 

installed in shut-in and injection wells).

Tested semiannually, not to exceed 6 months. If the device does not 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 § 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 § 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 

§ 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. 


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52284 Federal Register / Vol. 78, No. 163 / Thursday, August 22, 2013 / Proposed Rules 

(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. 

§§ 250.881–250.889 [Reserved] 

Records and Training 

§ 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. 

§ 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. 

§§ 250.892–250.899 [Reserved] 

[FR Doc. 2013–19861 Filed 8–21–13; 8:45 am] 

BILLING CODE 4310–VH–P 


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