29790 Federal Register / Vol. 87, No. 94 / Monday, May 16, 2022 / Proposed Rules 

DEPARTMENT OF THE INTERIOR 

Bureau of Safety and Environmental 

Enforcement 

30 CFR Part 250 

[Docket ID: BSEE–2021–0003; EEEE500000 

223E1700D2 ET1SF0000.EAQ000] 

RIN 1014–AA49 

Oil and Gas and Sulfur Operations in 

the Outer Continental Shelf—High 

Pressure High Temperature and 

Subpart B Revisions 

AGENCY: Bureau of Safety and 

Environmental Enforcement, Interior. 

ACTION: Proposed rule. 

SUMMARY: The Bureau of Safety and 

Environmental Enforcement (BSEE) is 

proposing to add requirements for new 

or unusual technology, including 

equipment used in high pressure high 

temperature (HPHT) environments, to 

revise and reorganize the information 

submission requirements for a project’s 

Conceptual Plans and Deepwater 

Operations Plans (DWOP), and to 

require independent third parties to 

review certain information prior to 

submission to BSEE. This proposed rule 

would improve operational and 

environmental safety and human health 

while providing consistency and clarity 

to industry regarding the equipment and 

operational requirements necessary for 

BSEE review and approval of projects 

using new or unusual technology. 

DATES: Send your comments on this 

proposed rule to BSEE on or before July 

15, 2022. BSEE is not obligated to 

consider or include in the 

Administrative Record for the final rule 

comments that we receive after the close 

of the comment period (see DATES) or 

comments delivered to an address other 

than those listed below (see ADDRESSES). 

Information Collection Requirements: If 

you wish to comment on the 

information collection requirements in 

this proposed rule, please note that the 

Office of Management and Budget 

(OMB) is required to make a decision 

concerning the collection of information 

contained in this proposed rule between 

30 and 60 days after publication of this 

proposed rule in the Federal Register. 

Therefore, comments should be 

submitted to OMB by June 15, 2022. 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–AA49 as an identifier in your 

message. See also Public Availability of 

Comments under Procedural Matters. 

• Federal eRulemaking Portal: 

https://www.regulations.gov. In the 

entry titled Enter Keyword or ID, enter 

BSEE–2021–0003 then click search. 

Follow the instructions to submit public 

comments and view supporting and 

related materials available for this 

rulemaking. BSEE may post all 

submitted comments. 

• Mail or Hand-Carry Comments to 

BSEE: Attention: Regulations and 

Standards Branch, 45600 Woodland 

Road, VAE–ORP, Sterling VA 20166. 

Please reference RIN 1014–AA49, ‘‘Oil 

and Gas and Sulfur Operations on the 

Outer Continental Shelf—High Pressure 

High Temperature and Subpart B 

Revisions,’’ in your comments, and 

include your name and return address. 

• All API standards that are safetyrelated and that are incorporated into 

Federal regulations are available to the 

public for free viewing online in the 

Incorporation by Reference Reading 

Room or for purchase on API’s website 

at: https://publications.api.org and 

https://www.api.org/products-andservices/standards/purchase, 

respectively. 

• NACE International (NACE) 

standards can be accessed through the 

American National Standards Institute 

(ANSI) Incorporated by Reference (IBR) 

Portal. The website can be accessed at: 

https://ibr.ansi.org. 

• For the convenience of the viewing 

public who may not wish to purchase or 

view the incorporated documents 

online, the documents may be inspected 

at BSEE’s offices at: 1919 Smith Street, 

Suite 14042, Houston, Texas 77002 

(phone: 1–844–259–4779), or 45600 

Woodland Road, Sterling, Virginia 

20166 (email: regs@bsee.gov), by 

appointment only. 

• Send comments on the information 

collection in this rule to: Interior Desk 

Officer 1014–0028, Office of 

Management and Budget; 202–395–5806 

(fax); email: oira_submission@

omb.eop.gov. Please send a copy to 

BSEE at regs@bsee.gov. 

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. 

In order for BSEE to withhold from 

disclosure your personal identifying 

information, you must identify any 

information contained in your comment 

submittal that, if released, would 

constitute a clearly unwarranted 

invasion of your personal privacy. You 

must also briefly describe any possible 

harmful consequence(s) of the 

disclosure of information, such as 

embarrassment, injury, or other harm. 

While you may request that we 

withhold your personal identifying 

information from public review, we 

cannot guarantee that we will be able to 

do so. 

FOR FURTHER INFORMATION CONTACT: For 

questions, contact Kirk Malstrom, 

Regulations and Standards Branch, 

(202) 258–1518, or by email: regs@

bsee.gov. 

SUPPLEMENTARY INFORMATION: 

Executive Summary 

Through this rulemaking, BSEE 

would improve operational safety and 

human health and environmental 

protections while providing industry 

with clarity and consistency regarding 

the submissions necessary for BSEE to 

review and approve operations using 

new or unusual technology. BSEE 

considers new or unusual technology to 

include equipment or procedures that 

have not been used previously or 

extensively under the anticipated 

operating conditions, or that have not 

been used previously in a particular 

BSEE Outer Continental Shelf (OCS) 

Region, or that have operating 

characteristics outside the performance 

parameters established in 30 CFR part 

250. Currently, operations and 

equipment used in HPHT environments 

are relatively new on the United States 

OCS. In general, an HPHT environment 

is present when well conditions have 

pressures greater than 15,000 pounds 

per square inch absolute (psia) or have 

a temperature greater than 350 degrees 

Fahrenheit. Historically, oilfield 

equipment has not been designed to 

withstand these high pressures and 

temperatures. Working in an HPHT 

environment also increases the 

operational complexity because HPHT 

associated operations require the use of 

equipment that exists at the limits of 

current technology and without a long 

operational history. Due to limited 

industry experience in HPHT 

environments, there are few standards 

that directly address HPHT equipment 

and operations. Currently, BSEE 

carefully reviews HPHT projects on a 

case-by-case basis. To date, BSEE has 

received several applications for 

projects in an HPHT environment and 

anticipates HPHT project interest to 

increase due to equipment technological 

advancements and industry capabilities 

to develop resources in these 

environments. 


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Federal Register / Vol. 87, No. 94 / Monday, May 16, 2022 / Proposed Rules 29791 

For new or unusual technology 

projects, including HPHT projects, BSEE 

regulations currently: 

• Require submission of information 

in a sequence that is not conducive to 

new or unusual technology projects 

because these projects require more 

BSEE review and approval upfront; 

• Lack specific equipment 

requirements because the technology is 

new and there are few applicable 

industry standards; and 

• Do not require submission of 

information in a way that best facilitates 

BSEE review. 

To address these issues, this 

rulemaking would: 

• Require submission of information 

in a sequence that provides both 

operators and BSEE the ability to 

evaluate whether a new or unusual 

technology project is economically and 

operationally feasible; 

• Add specific equipment 

requirements, particularly for barriers, 

through new regulations and 

incorporation of industry standards; and 

• Require Independent Third Party 

(I3P) review of operator submissions, in 

certain cases, or provide BSEE with the 

ability to require I3P review, to ensure 

project viability and safety. 

Currently, the DWOP process requires 

information to be submitted in two 

distinct phases: The Conceptual Plan 

phase and the DWOP approval phase. 

This rulemaking would revise the 

DWOP process to establish three standalone conceptual plans to address 

deepwater development projects, subsea 

tieback development technology, and 

new or unusual technology. The three 

proposed Conceptual Plans would be a 

Project Conceptual Plan, a New or 

Unusual Technology Conceptual Plan, 

or a New or Unusual Technology Barrier 

Conceptual Plan. A Project Conceptual 

Plan would be required for any project 

planned in water depths greater than 

1,000 feet or that will include the use of 

subsea tieback development technology 

regardless of water depth. A New or 

Unusual Technology Conceptual Plan 

would be required for any project or 

system involving new or unusual 

technology equipment or procedures. A 

New or Unusual Technology Barrier 

Conceptual Plan would be required for 

any project or system involving new or 

unusual technology equipment or 

procedures identified as a primary or 

secondary barrier to isolate 

hydrocarbons and or pressure from 

people and the environment. An 

operator must submit the applicable 

Conceptual Plan(s) and may be required 

to submit multiple Conceptual Plans 

based on specifics of the proposed 

project. Equipment or procedures that 

would be used in an HPHT environment 

would be considered new or unusual 

technology, and, for operations 

involving such equipment or 

procedures, an operator would be 

required to submit either a New or 

Unusual Technology Conceptual Plan or 

a New or Unusual Technology Barrier 

Conceptual Plan. The information 

specific to HPHT projects submitted in 

the applicable Conceptual Plan(s) or in 

the DWOP would be evaluated for 

adequacy prior to approval. Creation of 

the new Conceptual Plans and a new 

timing requirement—whereby these 

Conceptual Plans must be approved 

before any associated applicable permit 

(e.g., pipeline, platform, Application for 

Permit to Drill (APD), Application for 

Permit to Modify (APM)) approval— 

would provide both operators and BSEE 

the ability to evaluate whether a new or 

unusual technology project is 

economically and operationally feasible 

earlier in the project planning process, 

before permit approval. 

In addition, 30 CFR part 250, subpart 

B and the DWOP Process would be 

revised to incorporate the BSEE Barrier 

Concept into the requirements, 

including for new or unusual 

technology projects. The Barrier 

Concept is a holistic approach to the 

barrier system. BSEE considers a barrier 

or barrier system to be any engineered 

equipment, materials, component, or 

assembly that is intended to prevent the 

release of a hydrocarbon or other 

pressure source(s) that would cause 

harm to people or the environment. This 

proposed rulemaking would define, in 

subpart B, the types of equipment that 

BSEE considers to be barriers and how 

barriers must be used. Portions of the 

Barrier Concept would also be included 

in the DWOP Process under the New or 

Unusual Technology Barrier Conceptual 

Plan as a means of ensuring that new or 

unusual technology projects include 

sufficient barriers, which will enhance 

protections for people and the 

environment. This rulemaking would 

incorporate into regulations the existing 

BSEE policy on the Barrier Concept 

discussed in NTLs 2009–G36, Using 

Alternate Compliance in Safety Systems 

for Subsea Production Operations, 

2019–G02, Guidance for Information 

Submissions Regarding Proposed High 

Pressure and/or High Temperature 

(HPHT) Well Design, Completion, and 

Intervention Operations, and 2019–G03, 

Guidance for Information Submissions 

Regarding Site Specific and Non-Site 

Specific HPHT Equipment Design 

Verification Analysis and Design 

Validation Testing. 

Furthermore, the DWOP Process 

would be revised to require I3P review 

of equipment or procedures identified 

in a New or Unusual Technology Barrier 

Conceptual Plan and allow BSEE to 

require an operator to use an I3P to 

review certain equipment or procedures 

identified in a New or Unusual 

Technology Conceptual Plan. 

Independent third parties have been 

utilized as a longstanding industry 

practice to support certifications and 

verifications that ensure project viability 

and safety. I3P review provides an 

additional review in circumstances 

where proposed equipment or processes 

may be technically complex and require 

a high degree of specialized engineering 

knowledge, expertise, and experience to 

evaluate. 

The Principal Deputy Assistant 

Secretary—Lands and Minerals 

Management takes this action pursuant 

to delegated authority. 

Table of Contents 

I. Background 

A. BSEE Statutory and Regulatory 

Authority and Responsibilities 

B. Purpose and Summary of the 

Rulemaking 

C. Summary of Documents Incorporated by 

Reference 

II. Section-by-Section Discussion of Proposed 

Changes 

III. Additional Comments Solicited 

IV. Derivation Table 

V. Procedural Matters 

I. Background 

A. BSEE Statutory and Regulatory 

Authority and Responsibilities 

BSEE derives its authority primarily 

from the Outer Continental Shelf Lands 

Act (OCSLA), 43 U.S.C. 1331–1356a. 

Congress enacted OCSLA in 1953, 

authorizing the Secretary of the Interior 

(Secretary) to lease the OCS for mineral 

development, and to regulate oil and gas 

exploration, development, and 

production operations on the OCS. The 

Secretary has delegated authority to 

perform certain of these functions to 

BSEE. 

To carry out its responsibilities, BSEE 

regulates offshore oil and gas operations 

to enhance the safety of exploration for 

and development of oil and gas on the 

OCS, to ensure that those operations 

protect the environment, and to 

implement advancements in technology. 

BSEE also conducts onsite inspections 

to assure compliance with regulations, 

lease terms, and approved plans and 

permits. Detailed information 

concerning BSEE’s regulations and 

guidance to the offshore oil and gas 

industry may be found on BSEE’s 

website at: https://www.bsee.gov/ 

guidance-and-regulations. 

BSEE’s regulatory program covers a 

wide range of OCS facilities and 


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29792 Federal Register / Vol. 87, No. 94 / Monday, May 16, 2022 / Proposed Rules 

1BSEE’s regulations at 30 CFR part 250 generally 

apply to ‘‘a lessee, the owner or holder of operating 

rights, a designated operator or agent of the 

lessee(s). . . .’’ 30 CFR 250.105 (definition of 

‘‘you’’). For convenience, this preamble will refer to 

these regulated entities as ‘‘operators’’ unless 

otherwise indicated. 

2BSEE’s regulations at 30 CFR part 250 generally 

apply to ‘‘a lessee, the owner or holder of operating 

rights, a designated operator or agent of the 

lessee(s). . . .’’ 30 CFR 250.105 (definition of 

‘‘you’’). For convenience, this preamble will refer to 

these regulated entities as ‘‘operators’’ unless 

otherwise indicated. 

activities, including drilling, 

completion, workover, production, 

pipeline, and decommissioning 

operations. Drilling, completion, 

workover, and decommissioning 

operations are types of well operations 

that offshore operators 1 perform 

throughout the OCS. This rulemaking is 

applicable to these listed operational 

activities that involve deepwater 

development projects, subsea tieback 

development technology, projects or 

systems that use new or unusual 

technology, or barriers. 

B. Purpose and Summary of the 

Rulemaking 

The purpose of this rulemaking is to 

improve the requirements and 

information submission process for oil 

and gas operations in deepwater and for 

new or unusual technology equipment 

or procedures. The proposed regulations 

would achieve this purpose by adding 

requirements for new or unusual 

technology projects, including HPHT 

projects, by reorganizing the deepwater 

project information submission process, 

and by requiring I3P review of certain 

submissions. 

Together, these regulations would 

ensure that operators consider and 

submit sufficient information to BSEE at 

an early stage in the process so that the 

operator and BSEE can adequately 

address any issues concerning 

equipment selection, design, and 

fabrication. 

C. Summary of Documents Incorporated 

by Reference 

This rulemaking would update one 

document currently incorporated by 

reference to a newer edition and would 

apply three documents already 

incorporated by reference to additional 

workover and completion operations. A 

brief summary of the proposed changes, 

based on the descriptions in each 

standard or specification, is provided in 

the following text. 

American National Standards 

Institute (ANSI)/API Specification 

(Spec.) 11D1, Packers and Bridge Plugs, 

Third Edition, April 2015. 

This specification provides minimum 

requirements and guidelines for packers 

and bridge plugs used downhole in oil 

and gas operations. The performance of 

this equipment is often critical to 

maintaining well control during drilling 

and production operations. This 

specification provides requirements for 

the design, design verification and 

validation, materials, documentation 

and data control, repair, shipment, and 

storage of packers and bridge plugs. 

ANSI/API Spec. 6A, Specification for 

Wellhead and Christmas Tree 

Equipment, October 2010; Addendum 1, 

November 2011; Errata 2, November 

2011; Addendum 2, November 2012; 

Addendum 3, March 2013; Errata 3, 

June 2013; Errata 4, August 2013; Errata 

5, November 2013; Errata 6, March 

2014; Errata 7, December 2014; Errata 8, 

February 2016; Addendum 4, June 2016; 

Errata 9, June 2016; Errata 10, August 

2016. 

This specification defines 

requirements for the design of valves, 

wellheads and Christmas tree 

equipment that is used during drilling 

and production operations. This 

specification includes requirements 

related to dimensional and functional 

interchangeability, design, materials, 

testing, inspection, welding, marking, 

handling, storing, shipment, purchasing, 

repair and remanufacture. 

ANSI/API Spec. 17D, Design and 

Operation of Subsea Production 

Systems—Subsea Wellhead and Tree 

Equipment, Second Edition, May 2011; 

Addendum 1, September 2015; Errata, 

September 2011; Errata 2, January 2012; 

Errata 3, June 2013; Errata 4, July 2013; 

Errata 5, October 2013; Errata 6, August 

2015; Errata 7, October 2015. 

This specification provides 

requirements for subsea wellheads, 

mudline wellheads, and drill-through 

mudline wellheads, as well as vertical 

and horizontal subsea trees. These 

devices are located on the seafloor, and, 

therefore, ensuring the safe and reliable 

performance of this equipment is 

extremely important. This specification 

identifies the tooling necessary to 

handle, test and install the equipment. 

It also specifies the parameters for 

design, material, welding, quality 

control (including factory acceptance 

testing), marking, storing, and shipping 

for both individual sub-assemblies (used 

to build complete subsea tree 

assemblies) and complete subsea tree 

assemblies. 

NACE Standard MR0175–2003, 

Standard Material Requirements, Metals 

for Sulfide Stress Cracking and Stress 

Corrosion Cracking Resistance in Sour 

Oilfield Environments, Revised January 

2003. 

This standard describes general 

principles and provides requirements 

and recommendations for the selection 

and qualification of metallic materials 

for equipment used in oil and gas 

production, and in natural-gas 

sweetening plants, in hydrogen sulfide 

(H2S)-containing environments, where 

the failure of such equipment can pose 

a risk to the health and safety of the 

public and personnel or to the 

environment. Application of this 

standard can help avoid costly corrosion 

damage to equipment. This standard 

supplements, but does not replace, the 

material requirements contained in 

applicable design codes, standards, or 

regulations. This standard also 

addresses all mechanisms of cracking 

that can be caused by H2S, including 

sulfide stress cracking, stress corrosion 

cracking, hydrogen-induced cracking 

and stepwise cracking, stress-oriented 

hydrogen-induced cracking, soft zone 

cracking, and galvanically induced 

hydrogen stress cracking. This standard 

does not include, and is not intended to 

include design specifications. 

The American Petroleum Institute 

(API) provides free online public access 

to view read-only copies of its key 

industry standards, including a broad 

range of technical standards. All API 

standards that are safety-related and that 

are incorporated into Federal 

regulations are available to the public 

for free viewing online in the 

Incorporation by Reference Reading 

Room on API’s website at: https://

publications.api.org.2 In addition to the 

free availability of these standards on 

API’s website, hardcopies and printable 

versions are available for purchase from 

API. The API website address to 

purchase standards is: https://

www.api.org/products-and-services/ 

standards/purchase. 

NACE International (NACE) standards 

can be accessed through the American 

National Standards Institute (ANSI). 

The ANSI Incorporated by Reference 

(IBR) Portal provides access to many 

standards that have been incorporated 

by reference in the U.S. Code of Federal 

Regulations (CFR). These standards 

incorporated by the U.S. government in 

rulemakings are offered at no cost in 

‘‘read only’’ format and are presented 

for online reading. However, there are 

no print or download options. The 

website can be accessed at: https://

ibr.ansi.org. 

For the convenience of the viewing 

public who may not wish to purchase or 

view the incorporated documents 

online, the documents may be inspected 

at BSEE’s offices at: 1919 Smith Street, 

Suite 14042, Houston, Texas 77002 

(phone: 1–844–259–4779), or 45600 


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Federal Register / Vol. 87, No. 94 / Monday, May 16, 2022 / Proposed Rules 29793 

Woodland Road, Sterling, Virginia 

20166 (email: regs@bsee.gov), by 

appointment only. An appointment is 

required to ensure personnel are 

available to accommodate the request 

and to account for competing agency 

obligations or concerns, including those 

related to public health and natural 

disasters. Additional information on 

where these documents can be 

inspected or purchased can be found at 

30 CFR 250.198, Documents 

incorporated by reference, or by sending 

a request by email to regs@bsee.gov. 

II. Section-by-Section Discussion of 

Proposed Changes 

BSEE is proposing to revise the 

following regulations: 

Subpart A—General 

Definitions (§ 250.105) 

This rulemaking would add 

definitions for ‘‘BOP systems and 

related equipment’’ and ‘‘HPHT 

environment.’’ 

The new definition of ‘‘BOP systems 

and related equipment’’ would include 

all pressure controlling and pressure 

containing well control equipment that 

may or will be exposed to the well’s 

maximum anticipated surface pressure 

(MASP) during any phase of operation 

(i.e., drilling, completion, workover, 

intervention, or abandonment). The 

definition would also explain that well 

control equipment includes equipment 

that is installed for the purpose of 

pressure control and containment when 

it becomes necessary to physically enter 

a well bore during drilling, completion, 

workover, intervention, or abandonment 

modes of operation. The proposed 

definition of ‘‘BOP systems and related 

equipment’’ is consistent with how 

BSEE defined the term in NTL 2019– 

G03. 

The definition of HPHT environment 

would be moved from § 250.804(b) to 

this section and revised to include 

operations (1) that require equipment or 

well control equipment pressure rated 

for greater than 15,000 psia or 

temperature rated for greater than 350 

degrees Fahrenheit; (2) where the MASP 

or shut in tubing pressure (SITP) is 

greater than 15,000 psia on the seafloor 

for a well with a subsea wellhead or at 

the surface for a well with a surface 

wellhead; or (3) with a flowing 

temperature greater than 350 degrees 

Fahrenheit measured on the seafloor for 

a well with a subsea wellhead or at the 

surface for a well with a surface 

wellhead. The proposed definition is 

consistent with BSEE’s current 

definition of HPHT environments in 

§ 250.804(b) and is identical to the 

definition in NTL 2019–G03. 

Service Fees (§ 250.125) 

This rulemaking would revise 

paragraph (a)(2) of § 250.125 by adding 

new service fees for BSEE review of 

submittals associated with the DWOP 

Process. Specifically, this rulemaking 

would add service fees for processing a 

Project Conceptual Plan, New or 

Unusual Technology Conceptual Plan, 

New or Unusual Technology Barrier 

Conceptual Plan, revised DWOP, 

Combined Conceptual Plan/DWOP, and 

Supplemental DWOP. This rulemaking 

would also revise the cost recovery fee 

amount for DWOP approval to reflect 

current BSEE review and processing 

timeframes. These service and cost 

recovery fees would cover BSEE’s costs 

for administrative and technical review 

of each identified submittal and 

processing. 

Documents Incorporated by Reference 

(§ 250.198) 

This rulemaking would revise 

paragraph (e)(82) of § 250.198, which 

incorporates ANSI/API Spec. 6A, 

Specification for Wellhead and 

Christmas Tree Equipment, to add new 

references to §§ 250.518 and 250.619, 

making this standard applicable to 

completion and workover operations. 

The changes to this paragraph are 

administrative to reflect changes made 

to §§ 250.518 and 250.619 to reference 

this standard and are addressed further 

in the section-by-section discussion for 

these two sections. 

This rulemaking would revise 

paragraph (e)(86) of § 250.198 to update 

the incorporation of ANSI/API Spec. 

11D1 to the third edition of that 

standard. BSEE reviewed the new 

edition and differences between the 

second and third editions of ANSI/API 

Spec. 11D1 and determined that the 

third edition is appropriate to 

incorporate into the regulations. The 

ANSI/API Spec. 11D1 third edition now 

includes an improved testing procedure 

for design verification and validation of 

packers and bridge plugs. The most 

significant change from the second 

edition to the third edition was the 

addition of the enhanced validation of 

the testing processes. 

This rulemaking would revise 

paragraph (e)(91) of § 250.198, which 

incorporates ANSI/API Spec. 17D, 

Design and Operation of Subsea 

Production Systems—Subsea Wellhead 

and Tree Equipment, Second Edition, to 

add new references to §§ 250.518 and 

250.619, making this standard 

applicable to completion and workover 

operations. The changes to this 

paragraph are administrative and reflect 

changes made to §§ 250.518 and 250.619 

and are addressed further in the sectionby-section discussion for these two 

sections. 

This rulemaking would also revise 

paragraph (i)(1) of § 250.198, which 

incorporates NACE Standard MR0175– 

2003, Standard Material Requirements, 

Metals for Sulfide Stress Cracking and 

Stress Corrosion Cracking Resistance in 

Sour Oilfield Environments, Revised 

January 17, 2003, to add new references 

to §§ 250.518 and 250.619, making this 

standard applicable to completion and 

workover operations. The changes to 

this paragraph are administrative and 

reflect changes made to §§ 250.518 and 

250.619 and are addressed further in the 

section-by-section discussion for these 

two sections. 

Subpart B—Plans and Information 

BSEE is proposing to reorganize this 

subpart to incorporate new 

requirements and to ensure that 

information is submitted in an 

appropriate sequence. Many of the 

current provisions in this subpart would 

be moved into other sections within this 

same subpart without change. This 

section-by-section discussion identifies 

where BSEE proposes to move the 

content of the current provisions, 

explains proposed revisions to existing 

language, and proposes new provisions. 

For more information on these changes, 

BSEE has included a derivation table in 

Section IV of this notice. 

The proposed rule would restructure 

Subpart B—Plans and Information, 

under the following undesignated 

headings: 

—General Information 

—Barrier Equipment and Systems 

—Activities and Post-Approval 

Requirements for the EP, DPP, DWOP, 

AND DOCD 

—Deepwater Operations Plan (DWOP) 

Process 

—Conceptual Plans 

—DWOP Approval. 

General Information 

Definitions (§ 250.200) 

This rulemaking would revise 

paragraph (a) of § 250.200 by adding the 

acronym for HPHT. These are all 

common terms that are used throughout 

this subpart. 

This rulemaking would also revise 

paragraph (b) of § 250.200 by adding, 

revising, or eliminating the following 

definitions, as noted: 

• Add definition for ‘‘Barrier 

categorization’’ to identify barriers as 

one of the following two categories: 

Æ Category 1 Barrier, which would 

mean any equipment, component, or 


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29794 Federal Register / Vol. 87, No. 94 / Monday, May 16, 2022 / Proposed Rules 

assembly that functions as part of a 

primary barrier system during any 

operational phase of its life cycle. The 

operational phases of the barrier 

equipment, component or assembly are 

drilling, completion, workover, 

intervention, injection, production, or 

abandonment; and 

Æ Category 2 Barrier, which would 

mean any equipment, component, or 

assembly that normally functions as part 

of a secondary barrier system in all 

operational phases of its life cycle, 

except when a primary barrier fails. The 

operational phases of the barrier 

equipment, component or assembly are 

drilling, completion, workover, 

intervention, injection, production, or 

abandonment. BSEE may consider nonbarrier structural components of a 

barrier system as Category 2 barriers, if 

failure of this structural component 

could reasonably result in a barrier 

failure. 

• Add a definition for Primary Barrier 

system, which would mean the 

component, or group of components 

that is designated as the principle 

means of isolating the source of 

hydrocarbons and/or pressure from 

people and the environment. 

• Add the definition for Secondary 

Barrier system, which would mean the 

component or group of components that 

is designated as the secondary means of 

isolating the source of hydrocarbons 

and/or pressure from people and the 

environment. The secondary barrier 

system would be redundant to the 

primary barrier system as long as the 

primary barrier remains intact. 

• Revise the definition for ‘‘new or 

unusual technology’’ to include 

equipment or procedures used for any 

drilling, completion, workover, 

intervention, injection, production, 

pipeline, platform, decommissioning, or 

abandonment operation that meets any 

of the following criteria: 

(1) Has not been approved for use or 

used extensively in a BSEE OCS Region; 

(2) Has not been approved for use or 

used extensively under the anticipated 

operating conditions; 

(3) Has operating characteristics that 

are outside the performance parameters 

established in 30 CFR part 250; 

(4) Will operate in an HPHT 

environment as defined in proposed 

(§ 250.105); or 

(5) Is part of a primary or secondary 

barrier system that uses materials, 

design analysis techniques, validation 

testing methods or manufacturing 

processes not addressed in existing 

industry standards. This is intended to 

include any existing industry standard 

and is not limited to those standards 

incorporated by reference in BSEE 

regulations. 

These revisions would provide 

improved clarity regarding operations 

that BSEE has determined involve new 

or unusual technology and provide 

consistency for operators when actions 

would need to be taken using new or 

unusual technology. 

• Replace the definition for ‘‘nonconventional production or completion 

technology’’ with ‘‘subsea tieback 

development technology.’’ The 

definition of ‘‘subsea tieback 

development technology’’ would still 

include the current examples of floating 

production systems, tension leg 

platforms, spars, Floating Production 

Storage and Offloading Vessel (FPSO) 

systems, guyed towers, compliant 

towers, subsea manifolds, and subsea 

production components and would add 

subsea wells, hybrid wells, and other 

subsea completion components to the 

list of examples. This proposed term 

revision is intended to provide clarity 

and reflect the current nomenclature for 

this technology. 

• Remove the definitions of 

‘‘modification,’’ ‘‘offshore vehicle,’’ 

‘‘resubmitted OCS plan,’’ ‘‘revised OCS 

plan,’’ and ‘‘supplemental OCS plan.’’ 

These terms are currently not used 

elsewhere in this subpart and are 

residual from when BSEE separated 

these regulations from BOEM 

requirements (see 76 FR 64432). 

What plans and information must I 

submit before I conduct any activities 

on my lease or unit? (§ 250.201) 

This rulemaking would revise existing 

paragraph (a) of § 250.201 to reflect the 

creation of the New or Unusual 

Technology Conceptual Plan, New or 

Unusual Technology Barrier Conceptual 

Plan, and the Project Conceptual Plan. 

This section provides general 

information about each plan and 

identifies when BSEE approval is 

necessary. Paragraph (a) would also 

clarify when each plan approval is 

required for certain activities. An 

operator is only required to submit the 

applicable conceptual plan(s). Each of 

these conceptual plans are standalone 

plans and are not contingent upon 

approval of each other. For example, if 

an operator plans to use new or unusual 

technology barrier equipment, they 

would only be required to submit a New 

or Unusual Technology Barrier 

Conceptual Plan, they would not be 

required to submit a New or Unusual 

Technology Conceptual Plan as well. 

This rulemaking would also remove 

existing paragraph (c), which includes 

the limiting information provisions. The 

limiting information provisions allow 

the Regional Director to limit the 

amount of information or analyses 

required to be included with the 

submitted plans or documents, covered 

by this subpart, under certain 

conditions. The limiting information 

provisions are not used by BSEE and are 

residual from when BSEE separated 

these regulations from BOEM 

requirements (see 76 FR 64432). 

How must I protect the rights of the 

Federal government? (§ 250.202) 

The content of this proposed section 

would be moved from existing § 250.204 

without revision. 

Are there special requirements if my 

well affects an adjacent property? 

(§ 250.203) 

The content of this proposed section 

would be moved from existing § 250.205 

without revision. 

Requirements for High Pressure High 

Temperature (HPHT) Barrier Equipment 

(§ 250.204) 

This proposed section is new and 

clarifies what information an operator 

would be required to submit to BSEE if 

the operator plans to install HPHT 

barrier equipment. This section crossreferences the applicable DWOP Process 

requirements associated with the New 

or Unusual Technology Barrier 

Conceptual Plan. These additions are 

necessary to help ensure that the 

equipment is fit for service in the 

specific HPHT environment. BSEE’s 

review and approval of information 

submitted during the DWOP Process is 

intended to occur in conjunction with 

BSEE review and approval of associated 

applications or permits (e.g., APD, APM, 

pipeline, and production safety system). 

Barrier Equipment and Systems 

What equipment does BSEE consider to 

be a barrier? (§ 250.206) 

This section would codify some of the 

barrier concepts from BSEE NTL 2009– 

G36. Many parts of existing BSEE 

regulations under Subparts D, E, F, G, H, 

J and Q are dedicated to establishing 

barrier requirements. This section 

would clarify that BSEE considers a 

barrier or barrier system to be any 

engineered equipment, materials, 

component, or assembly that is installed 

to contain a hydrocarbon or other 

pressure source(s) to prevent harm to 

people or the environment. BSEE only 

recognizes barriers (non-mechanical or 

mechanical in nature) that are either 

permanently or temporarily installed, 

pressure controlling, and/or pressure 

containing barriers. Pressure controlling 

barriers must be able to be activated on 

demand. This rulemaking would also 


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clarify that barriers or barrier systems 

are required to be able to function and/ 

or be pressure tested repeatedly to 

defined acceptance criteria. If the barrier 

or barrier system is classified as Safety 

and Pollution Prevention Equipment 

(SPPE) (as described under 

§ 250.801(a)), then it must also be 

compliant with the leak test 

requirements established in Subpart H. 

Any specific engineered equipment, 

materials, components, or assembly that 

exist within a barrier system that are not 

tested would not be considered a 

barrier. This section would not alter or 

impact any existing regulation; it only 

documents a principle that is the basis 

of many BSEE regulations. 

These barrier concepts are based on 

BSEE’s viewpoint that abnormal 

conditions and/or failures are potential 

risks in a well or pipeline system. When 

an abnormal condition or failure occurs, 

it must be detectable, and upon 

detection, it is important to isolate its 

source behind redundant barriers. 

Primary or Secondary Barrier equipment 

may include, but is not limited to: 

• Wellhead system, such as the high 

pressure housing, production casing 

hangers, and seal assemblies 

• Tubing head 

• Tubing hanger 

• Tree, including all valves, fittings, 

and chokes 

• Surface Controlled Subsurface Safety 

Valve (SCSSV), including all 

associated safety valve locks and 

landing nipples 

• Capping stack 

• BOP 

• Completion workover riser system 

(CWOR) 

• Surface flowhead used above a CWOR 

• Subsea test tree (SSTT) 

• Wellhead connector 

• Landing nipples and tubing plugs 

• Production liner hanger/packer 

• Packers 

• Pipeline boarding shutdown valve 

• Flowline riser 

• High integrity pressure protection 

system (HIPPS), including all 

equipment between the HIPPS and 

the tree 

• Well top tension riser systems 

• Production tubing 

• Production casing 

• Production liner 

• Production casing and liner cement 

• Production tubing, casing, and liner 

threaded connections 

• Production liner hanger/packer 

• Flowline jumpers 

• Jumper connectors 

• Manifolds 

• Pipeline End Termination (PLETs) 

• Pipeline End Manifolds (PLEMs) 

• Flowlines 

• Umbilicals 

• Any other pressure containing or 

pressure controlling equipment from 

the production liner within the well 

through the last barrier in a subsea 

production, BOP, or intervention 

system. 

How must barrier systems be used? 

(§ 250.207) 

Under this section, operators would 

be required to install and maintain a 

primary and secondary barrier system to 

prevent a loss of containment during 

any operational phase of a well, 

flowline, pipeline, production, or riser 

system. It is BSEE’s goal to prevent loss 

of containment by minimizing single 

point failures wherever possible. Given 

the probability that any barrier may fail 

during its service life due to age, 

corrosion, wear, damage, environment 

or accidents, the best mitigation is 

redundancy. This section would not 

alter or impact any existing regulation; 

it only documents a principle that is the 

basis of many BSEE regulations. 

Activities and Post-Approval 

Requirements for the EP, DPP, DWOP, 

and DOCD 

How must I conduct activities under an 

approved EP, DPP, or DOCD? 

(§ 250.208) 

The content of this proposed section 

would be similar to the language in 30 

CFR 550.280, How must I conduct 

activities under the approved EP, DPP, 

or DOCD? During the regulatory split 

between BSEE and BOEM, the content 

of this section was inadvertently 

removed from this part; however, the 

content is still applicable to BSEE and 

should be included in this part, as well 

as in 30 CFR part 550. 

What must I do to conduct activities 

under the approved EP, DPP, or DOCD? 

(§ 250.209) 

The content of this proposed section 

would be similar to the language in 30 

CFR 550.281, What must I do to conduct 

activities under the approved EP, DPP, 

or DOCD? paragraphs (a) and (b). During 

the regulatory split between BSEE and 

BOEM, the content of this section was 

inadvertently removed from this part; 

however, the content is still applicable 

to BSEE and should be included in this 

part, as well as in 30 CFR part 550. 

Do I have to conduct post-approval 

monitoring? (§ 250.210) 

The content of this proposed section 

would be moved from § 250.282. This 

section would also add minor revisions 

to clarify that the Regional Supervisor 

may direct operators to conduct 

monitoring programs in association with 

their approved EP, DPP, DWOP, or 

DOCD. 

What are my new or unusual technology 

failure reporting requirements? 

(§ 250.211) 

This proposed section is new and 

would clarify the new or unusual 

technology failure reporting 

requirements. Currently, BSEE does not 

receive new or unusual technology 

failure data associated with approved 

DWOPs; however, BSEE has recently 

requested new or unusual technology 

failure data as a condition of DWOP 

approval. This section would require an 

operator to notify BSEE within 30 days 

of a failure and provide a written report 

identifying the root causes of the failure. 

This new section is intended to provide 

BSEE with a better understanding of 

operational limitations of equipment 

associated with an approved DWOP. 

Existing failure and incident reporting 

requirements in §§ 250.188, What 

incidents must I report to BSEE and 

when must I report them?, 250.730, 

What are the general requirements for 

BOP systems and system components?, 

and 250.803, What SPPE failure 

reporting procedures must I follow? may 

be used to help fulfill the new or 

unusual technology failure reporting 

requirements of this section. This 

section is not a substitute for other 

currently applicable failure or incident 

reporting requirements. Even though 

BSEE requires the operator to perform a 

risk assessment, failure mode analysis, 

design verification analysis, and 

validation testing on all new or unusual 

technology, a failure could still occur. 

Operating experience is an important 

tool for comprehensively understanding 

all possible issues with new 

technologies. BSEE has approved many 

new technologies for operators in the 

OCS. Even with successful 

implementation, new technology is 

often modified based on lessons learned 

during its use and application on the 

OCS. If a failure occurs on a new or 

unusual technology that was installed, 

BSEE may not approve this same new or 

unusual technology for installation 

again until we comprehensively 

understand the root cause of the failure 

and we confirm that the failure can be 

mitigated. Therefore, it is important for 

all failures to be reported. 

Deepwater Operations Plan (DWOP) 

Process 

What is the DWOP Process? (§ 250.220) 

The content of this proposed section 

would be moved from § 250.286 and 


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would contain the following revisions 

and additions: 

Paragraph (a) of § 250.220 would 

clarify that the DWOP Process is not 

only used for review of subsea tieback 

development technology, but also 

applies to deepwater development 

projects and other projects or systems 

that use new or unusual technology 

during any phase of drilling, 

completion, workover, intervention, 

injection, production, pipeline, 

platform, decommissioning, or 

abandonment operations. These 

additions clarify when the DWOP 

Process is necessary and correspond 

with the proposed additions of DWOP 

Process new or unusual technology 

requirements. 

Paragraph (b) would add that the 

DWOP Process does not replace other 

BSEE applications or permits (e.g., APD, 

APM, pipeline, and platform). Other 

minor revisions to this paragraph reflect 

the corresponding additions to the 

proposed new or unusual technology 

requirements for the DWOP Process. 

Paragraph (c) would clarify that the 

DWOP Process consists of two phases: 

The Conceptual Plans and the DWOP. 

The current DWOP regulations do not 

differentiate between the DWOP Process 

and the DWOP plan itself, as they 

currently use the term DWOP to refer to 

both. This proposed section would 

clarify the terms and is intended to 

reduce confusion about the different 

phases of the DWOP Process. The 

proposed DWOP requirements are not 

intended to require the submittal of a 

DWOP for operations not currently 

covered under the DWOP plan stage 

(e.g., drilling and decommissioning), but 

would require submittal of the 

appropriate Conceptual Plan. Proposed 

§§ 250.227 through 250.229 would 

identify the contents of the Conceptual 

Plans. Proposed §§ 250.236 through 

250.242 would identify what the DWOP 

must contain. 

When must I use the DWOP Process? 

(§ 250.221) 

The content of this proposed section 

would be moved from § 250.287 and 

would clarify that the DWOP Process is 

applicable to any project in water 

depths greater than 1000 feet and to any 

project that will include the use of 

subsea tieback development technology, 

regardless of water depth, or new or 

unusual technology for any drilling, 

completion, workover, intervention, 

injection, production, pipeline, 

platform, decommissioning, or 

abandonment operations. These 

revisions provide consistency and 

reflect corresponding additions to the 

proposed new or unusual technology 

and DWOP requirements. 

DWOPs have always been required 

when a development is situated in water 

depths of 1000 feet or greater or when 

subsea tieback development technology 

is used in any water depth. BSEE 

proposes to codify our existing practices 

to include the expansion of new or 

unusual technology. This rulemaking 

would also add requirements for the 

DWOP Process when any new or 

unusual technology is used for drilling, 

completion, workover, intervention, 

injection, production, pipeline, 

platform, decommissioning, or 

abandonment projects. This would 

provide consistency for all new or 

unusual technology reviews. 

Conceptual Plans 

What are the types of Conceptual Plans 

that I must submit? (§ 250.225) 

This proposed section is new and 

would identify the three types of 

proposed Conceptual Plans: 

• A Project Conceptual Plan is 

required for any project that is planned 

in water depths greater than 1000 feet or 

will include the use of subsea tieback 

development technology, regardless of 

water depth (see proposed § 250.221 

paragraphs (a)(1) and (2)); 

• A new or unusual technology 

Conceptual Plan is required for any 

project or system that involves 

equipment or systems that are 

considered new or unusual technology 

(see proposed § 250.200 for the 

definition of new or unusual 

technology); and 

• A new or unusual technology 

Barrier Conceptual Plan is required for 

any project or system involving new or 

unusual technology that is also 

identified as a primary or secondary 

barrier (see proposed § 250.200 for the 

definition of primary or secondary 

barriers). 

This proposed section would add 

clarity by describing the proposed types 

of Conceptual Plans. The proposed 

requirements for each Conceptual Plan 

are discussed in the applicable 

corresponding sections, §§ 250.227 

through 250.229. An operator must 

submit the applicable Conceptual 

Plan(s) based on specifics of the 

proposed project. The operator may be 

required to submit multiple Conceptual 

Plans. 

When and how must I submit each 

applicable Conceptual Plan? (§ 250.226) 

The content of this proposed section 

would be moved from §§ 250.288 and 

250.290 and revised to clarify that the 

operator must submit its Conceptual 

Plans to the Regional Supervisor after 

the operator decides on the general 

concept(s) for a project or system, and 

before it begins final engineering design 

of the equipment, well, well safety 

control system, or subsea production 

systems. These revisions would help 

ensure that the operator considers the 

information associated with the 

proposed Conceptual Plans before 

application or permit (e.g., APD, APM, 

pipeline, platform) approval. Once an 

operator begins final engineering design, 

it is generally too late to address 

changes to design and fabrication that 

may affect an entire project and may 

significantly delay project approval if 

such changes are necessary. This 

rulemaking would add a table to 

organize and clarify information 

associated with the three types of 

proposed Conceptual Plans. 

Proposed paragraph (a) of § 250.226 

would include content from § 250.290 

and would further clarify that Project 

Conceptual Plan approval would be 

required before completion of any 

production or injection well, or 

installation of the tree. 

Proposed paragraph (b) would add the 

following requirements regarding a New 

or Unusual Technology Conceptual 

Plan: 

—The operator may not install any new 

or unusual technology until BSEE 

approves the New or Unusual 

Technology Conceptual Plan; 

BSEE must approve the New or 

Unusual Technology Conceptual Plan 

before BSEE may approve any 

associated application or permit (e.g., 

pipeline, platform, APD, APM); and 

—The Regional Supervisor may require 

the operator to use an I3P to perform 

certain functions and verifications in 

accordance with § 250.231, as 

applicable. This addition would allow 

BSEE to use I3P services for new or 

unusual technology reviews that may 

involve technically complex 

engineering and require a high degree 

of specialized engineering knowledge, 

expertise, and experience to evaluate 

and help ensure appropriate reviews 

are conducted for the new or unusual 

technology. 

These revisions would help ensure 

that operators consider the information 

associated with the proposed 

Conceptual Plans before application 

submittal, which would allow for 

changes to be considered in the design 

and fabrication process, potentially 

saving operators significant time and 

expense. This would also establish a 

formalized process for BSEE to review 

new or unusual technology 

technologies. 


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Proposed paragraph (c) would add the 

following requirements regarding a New 

or Unusual Technology Barrier 

Conceptual Plan: 

—The operator must submit a New or 

Unusual Technology Barrier 

Conceptual Plan for any project or 

system involving new or unusual 

technology that is also identified as a 

primary or secondary barrier; 

—BSEE must approve the New or 

Unusual Technology Barrier 

Conceptual Plan prior to new or 

unusual technology barrier equipment 

installation; 

—BSEE must approve the new or 

unusual technology barrier equipment 

before BSEE may approve of any 

associated application or permit (e.g., 

pipeline, platform, APD, APM); and 

—An operator submitting a New or 

Unusual Technology Barrier 

Conceptual Plan must use an I3P to 

perform certain functions and 

verifications in accordance with 

proposed § 250.231, What are the I3P 

review requirements for Conceptual 

Plan reviews? 

These revisions would help ensure 

that operators consider the information 

associated with the proposed 

conceptual plans before application 

submittal, thereby allowing for changes 

to be considered in the design and 

fabrication process, potentially saving 

operators significant time and expense. 

This would also establish a formalized 

process for BSEE to review new or 

unusual technology barrier 

technologies. 

What must the Project Conceptual Plan 

contain? (§ 250.227) 

This proposed section would require 

a Project Conceptual Plan to include the 

basis of design that the operator would 

use to develop the field. Proposed 

paragraphs (a), (b), (c), and (i)(1) of 

§ 250.227 would reflect content of 

existing § 250.289. In addition, this 

section would require the operator to 

include the following information in the 

Project Conceptual Plan: 

—Confirmation that the subsea 

production safety system will comply 

with Subpart H; 

—For a new facility, a description of the 

type of facility the operator plans to 

install (e.g., Spar, Tension Leg 

Platform (TLP), FPSO, etc.); 

—For a subsea tieback to an existing 

facility, a statement identifying 

whether a minor or major structural 

modification will be made to the 

facility and the facility’s remaining 

design life. If modifications will be 

made to the existing facility, a 

calculation of the facility’s remaining 

design life and explanation of how the 

modifications will impact the design 

life; 

—A statement regarding whether the 

host facility will be manned or 

unmanned; 

—A schedule of development activities, 

including well completion, facility 

installation, and date of first oil; 

—Schematics, including: 

Æ A well location plat; 

Æ A subsea field schematic depicting 

the planned development 

infrastructure that contains the 

wells, pipelines, riser systems, 

umbilical(s), and facility footprint; 

Æ The surface or subsea tree; 

Æ Wellbore and completion schematic 

for a typical well (including SCSSV 

location and chemical injection 

points; and depiction of, or 

statement of whether there will be 

gas zones behind the production 

casing or production liner and how 

they will be isolated); and 

Æ Information concerning the drilling 

and completion systems. 

—The estimated shut-in tubing pressure 

for the proposed well(s), including the 

calculation used to arrive at the 

estimate, specifying true vertical 

depth (TVD), reservoir pressure, and 

the fluid gradient used, or a brief 

discussion of the pressure volume 

temperature (PVT) data used for 

estimation; 

—The wellbore static bottomhole 

temperature and the estimated 

flowing temperature at the tree; 

—The pressure and temperature rating 

of the tree and wellhead; 

—Identify if there will be corrosive 

production (e.g., H2S, carbon dioxide 

(CO2), Mercury (Hg) or injection fluids 

(e.g., acid), including concentrations; 

—Identify whether any proposed 

equipment will be re-furbished and 

re-certified; 

—Identify whether enhanced recovery is 

planned for the early life of the 

project; 

—Identify whether any new or unusual 

technology will be used to develop 

your project involving the following 

activities: Drilling, completion, 

injection, production, pipeline, or 

platform; 

—Identify whether the well(s) will 

include smart completion technology; 

and 

—Payment of the service fee listed in 

§ 250.125. 

BSEE currently requests and receives 

information similar to information listed 

in these proposed revisions for current 

conceptual plan approval. These 

revisions would codify current BSEE 

practices and provide BSEE with 

sufficient information to review Project 

Conceptual Plans. These revisions 

would also provide clarity and 

consistency for operator submittals of 

the Project Conceptual Plan. This 

rulemaking would also align the DWOP 

Process requirements with the current 

electronic system for submitting 

applicable plans. 

These revisions would help ensure 

that operators consider the information 

associated with the Project Conceptual 

Plan before application submittal and 

allow for potential changes to be 

considered in the design and fabrication 

process, potentially saving operators 

significant time and expense. 

What must the New or Unusual 

Technology Conceptual Plan contain? 

(§ 250.228) 

Proposed paragraph (a) of § 250.228 

would require the following information 

to be included in the New or Unusual 

Technology Conceptual Plan: 

—How the New or Unusual Technology 

Conceptual Plan fits within the 

overall site-specific project, if 

applicable, including an overview of 

the project development concepts; 

—Description of the technology and 

specific conditions under which it 

will be used; 

—Description of shut-in capabilities and 

procedures; 

—Description of redundancies of critical 

components or systems that will be 

used; 

—Discussion of how the technology 

could impact the barrier system, if 

any, including the detection method 

for technology failure and how the 

barrier functions to a fail-safe state 

when impacted by new or unusual 

technology failure; 

—Information on inspection and testing 

capabilities; 

—A risk assessment and failure mode 

analysis; 

—Operating procedures; 

—History of development and 

application of the technology; 

—The basis of design, including design 

verification and validation testing; 

—Detailed schematics; 

—Justification for new or unusual 

technology use, and any additional 

information required for a complete 

review; 

—A list of any requested alternate 

procedures or equipment in 

accordance with § 250.141 and 

requested departures in accordance 

with § 250.142; 

—A certification statement that the 

technology is fit for service in the 

applicable environment for the 

specific project location; and 


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—Payment of the service fee listed in 

§ 250.125. 

Proposed paragraph (b) would allow 

for the Regional Supervisor to require 

the use of an I3P according to proposed 

§ 250.230 if the system or equipment 

requires a high degree of specialized or 

technically complex engineering 

knowledge, expertise, and experience to 

evaluate, or is not addressed in existing 

industry standards. This addition would 

help BSEE ensure that the equipment or 

process is appropriate for use in the 

specific environmental and operating 

conditions. In addition, the Regional 

Supervisor would be able to require 

operators to follow I3P requirements 

under § 250.231, on a case-by-case basis. 

Finally, this section would instruct 

operators to direct any questions about 

I3P requirements for New or Unusual 

Technology Conceptual Plans to the 

Regional Supervisor. 

BSEE currently requests and receives 

information for conceptual plans similar 

to what would be required by these 

revisions. These revisions would codify 

current BSEE practices and would 

ensure BSEE consistently receives 

sufficient information for New or 

Unusual Technology Conceptual Plan 

review. These revisions would also 

provide clarity and consistency for 

operator submittal of the New or 

Unusual Technology Conceptual Plan. 

Similar information is presently 

required or requested of operators and 

provided to BSEE for review in the 

current DWOP Process. 

What must the New or Unusual 

Technology Barrier Conceptual Plan 

include? (§ 250.229) 

This proposed section would require 

the following information to be 

included in the New or Unusual 

Technology Barrier Conceptual Plan: 

—Description of how the New or 

Unusual Technology Barrier 

Conceptual Plan fits within the 

overall site specific project, if 

applicable, including an overview of 

the project development concepts and 

a proposed schedule for submittal of 

associated conceptual plans; 

—Diagram depicting the primary and 

secondary barriers, including all 

components, assemblies or subassemblies labeled and categorized as 

Category 1 barriers or Category 2 

barriers; 

—List of the primary and secondary 

barriers that include all components, 

assemblies, or sub-assemblies, 

specifying each assigned barrier as 

either a Category 1 barrier or Category 

2 barrier; 

—List of the engineering standards that 

will be used in the equipment’s 

material selection and qualification, 

design verification analysis, and 

design validation testing; 

—List of requested alternate procedures 

or equipment in accordance with 

§ 250.141 or requested departures in 

accordance § 250.142; 

—List of the functional requirements 

(i.e., environmental, and physical 

loads (magnitude and frequency)) for 

which the barrier equipment is being 

designed; 

—Description of the barrier equipment’s 

safety critical functions, (i.e., 

function(s) performed by or inherent 

to the equipment enabling it to 

achieve or maintain a safe state); 

—An I3P nomination, in accordance 

with proposed § 250.230 paragraph 

(a); and 

—An I3P verification plan that includes: 

—Discussion of the barrier 

equipment’s material selection and 

qualification; 

—Discussion of the barrier 

equipment’s design verification 

analyses; 

—Discussion of the barrier 

equipment’s design validation 

testing; 

—Explanation of why the analyses, 

processes, and procedures ensure 

that the barrier equipment is fit for 

service in the applicable 

environment; and 

—Details regarding how the I3P will 

address the additional items listed 

in proposed § 250.231; 

—I3P reports as required in proposed 

§ 250.232; and 

—Payment of the service fees listed in 

§ 250.125. 

Proposed paragraph (l) would clarify 

that, after BSEE receives all of the 

required I3P reports, the operator must 

submit a certification statement that the 

barrier equipment is fit for service in the 

applicable environment (for the specific 

project location). 

BSEE currently requests and receives 

information in conceptual plans similar 

to these proposed revisions. These 

revisions would provide clarity and 

consistency for operator submittal of the 

New or Unusual Technology Barrier 

Conceptual Plan, codify existing BSEE 

practices, and would provide BSEE with 

sufficient information for proper New or 

Unusual Technology Barrier Conceptual 

Plan review and, if warranted, approval. 

What are the requirements for the 

Independent Third Party (I3P) 

nomination? (§ 250.230) 

This proposed section would outline 

the requirements for the operator to 

nominate an I3P to be used in 

conjunction with applicable Conceptual 

Plans. Paragraph (a) would add the 

nomination criteria for the I3P to review 

the design verification and design 

validation classification of the Original 

Equipment Manufacturer (OEM), 

including that the I3P must be a 

technical classification society, a 

licensed professional engineering firm, 

or a registered professional engineer 

capable of providing the required 

certifications and verifications. This 

paragraph would also clarify that the 

I3P nomination must be submitted to 

BSEE for approval and must include the 

following information: 

—Previous experience in third-party 

verification or experience in the 

design, fabrication, or installation of 

applicable offshore oil and gas 

equipment; 

—Technical capabilities of the 

individual or the primary staff for the 

specific project; 

—Size and type of organization or 

corporation; 

—In-house availability of, or access to, 

appropriate technology to review the 

specific project (this should include 

computer programs, hardware, and 

testing materials and equipment as 

applicable); 

—Ability to perform the I3P functions 

for the specific project considering 

current commitments (e.g., project 

timelines, schedules, and personnel 

availability); and 

—Previous experience with BSEE 

requirements and procedures. 

This proposed section would help 

ensure that BSEE is informed of the I3P 

competencies and show that the I3P is 

qualified to perform the required 

verifications and certifications of this 

subpart. 

Paragraph (b) would require that 

operators allow the I3P to access all 

associated documentation and 

equipment related to items in proposed 

§ 250.229(i) to perform the complete 

reviews in accordance with proposed 

§ 250.231. This may include OEM 

documents or access to the fabrication 

and manufacturing locations. The 

operator is responsible for ensuring that 

the I3P has the appropriate information 

to complete the required verifications 

and certifications. This documentation 

is necessary for the I3P to conduct its 

review and verify, as appropriate, that 

the equipment is designed and 

manufactured to operate within its 

specified operating limits. 

Multiple I3Ps may be used to conduct 

the applicable verifications. These 

proposed revisions are not intended to 

limit the number of I3Ps, as operators 

may need multiple I3Ps to cover 


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multiple types of equipment covered 

under all applicable Conceptual Plans. 

What are the I3P review requirements 

for Conceptual Plan reviews? (§ 250.231) 

This proposed section identifies the 

requirements for the I3P review. 

Paragraph (a) would require the I3P to 

review the following information 

regarding the applicable equipment or 

system: 

—Basis of Design, Technical 

Specification (if known at this point 

in the design process) and Functional 

Requirements (i.e., environmental, 

and physical loads (magnitude and 

frequency)); 

—Risk assessment and failure mode 

analysis; 

—Material specification, selection, 

qualification, and testing; 

—Design verification analysis, including 

a structural/strength analysis and 

fatigue assessment and/or analysis; 

—If fatigue is identified as a potential 

failure mode in the required fatigue 

assessment and/or analysis, the plan 

to record and gather data (i.e., load 

monitoring) in order to conduct a 

future fatigue analysis; 

—Design validation testing; and 

—Fabrication, quality management 

system, and inspection and test 

plan(s) that identifies the quality 

control/quality assurance process, and 

inspection of the final products. 

Paragraph (b) would require the I3P to 

submit a report to BSEE documenting 

the review of each item covered under 

paragraph (a) of this section. This 

paragraph would also require each 

report to identify all OEM and operator 

documents used during the I3P reviews. 

Paragraph (c) would require the I3P to 

submit a final report to BSEE that 

summarizes each of the review 

requirements covered under paragraph 

(a) of this section. This paragraph would 

also require the final report to include 

the equipment and/or system’s technical 

specifications, including a certification 

statement that the equipment and/or 

system is fit for purpose for the 

technical specification by the I3P, and 

verification that the equipment’s 

technical specifications meet or exceed 

the project’s functional requirements, 

including a certification statement that 

the equipment and/or system is fit for 

purpose for the proposed project by the 

I3P. 

Paragraph (d) would clarify that, for 

any subsequent I3P review of equipment 

and/or system’s technical specification 

that was previously approved in the 

operator’s New or Unusual Technology 

Barrier Conceptual Plan, the Regional 

Supervisor may accept a final report in 

accordance with § 250.231(c), including 

the existing certification covered under 

paragraph (c)(1) of this section, in lieu 

of reports required in paragraph (b). The 

I3P would be required to submit an 

updated certification statement in 

accordance with § 250.231(c)(2) for the 

specific project. 

This section would require I3P review 

of all new or unusual technology 

Category 1 or Category 2 barrier 

equipment to help minimize the risk of 

loss of containment on new barrier 

equipment through reliance on the 

principle of qualified redundant barrier 

systems. The concept of using an I3P 

review process has been used in the 

regulations for various operations (e.g., 

§§ 250.914 through 250.918, 250.420, 

and 250.732). The I3P review process 

within § 250.231, would be the same 

process described in NTL 2019–G03 

‘‘Guidance for Information Submissions 

Regarding Site Specific and Non-Site 

Specific HPHT Equipment Design 

Verification Analysis and Design 

Validation Testing.’’ The industry is 

currently using this NTL for the design 

verification and validation analysis for 

HPHT barrier equipment that will be 

used in the Gulf of Mexico. The 

verification processes in this section 

would be similar to the basic 

engineering design and manufacturing 

methodologies found in many existing 

engineering standards. 

General Requirements for Any I3P 

Report (§ 250.232) 

This proposed section would clarify 

expectations for the I3P reports. This 

rulemaking would require that an I3P 

report must be a standalone document 

that clearly summarizes the verification 

work performed and must contain a 

sufficient level of detail (i.e., 

quantitative information) and clarity to 

establish the basis of the I3P’s findings 

and recommendation(s). Each report 

would be required to identify the OEM 

or operator documents reviewed, the 

detailed I3P review, and convey the 

results of the I3P’s review without 

requiring BSEE to review any other 

referenced document. This section 

would establish basic expectations for 

I3P reports and provide consistency and 

uniformity for operator submittals and 

BSEE reviews. These reports are an 

important tool for BSEE to conduct 

appropriate reviews and it is imperative 

to ensure that these reports are 

comprehensive and clear. These reports 

also contain information necessary for 

audit purposes. 

DWOP Approval 

When and how must I submit the 

DWOP? (§ 250.235) 

The content of this proposed section 

would be moved from § 250.291, and 

would be revised to clarify that a DWOP 

must be submitted to the Regional 

Supervisor after BSEE has approved the 

operator’s project conceptual plan and 

the operator has substantially completed 

system design, and before the operator 

conducts post-completion installation 

activities for a deepwater development 

project, or for any project that will 

involve the use of subsea tieback 

development technology in any water 

depth, which may include new or 

unusual technology or new or unusual 

technology barrier equipment. This 

section would also clarify that operators 

cannot begin production from the well 

until BSEE approves the DWOP. The 

revisions to this section would help 

ensure that there is enough time for 

BSEE to review a DWOP, including 

resolution of any potential issues, prior 

to DWOP approval. The operator should 

consider the DWOP requirements when 

beginning to procure or fabricate the 

safety and operational systems (other 

than a tree, because operators may 

install a tree after Conceptual Plan 

approval), production platforms, 

pipelines, or other parts of the 

production system. 

What information must I submit with 

the DWOP? (§ 250.236) 

This proposed section is 

organizational in nature and would 

identify the types of information that 

the operator must submit with the 

DWOP by adding a table that lists the 

applicable sections and the information 

to be included. In this section, BSEE 

would reorganize and breakout the 

DWOP requirements by topic, as 

reflected in paragraphs (a) through (f). 

These revisions would improve clarity 

for applicable information requirements. 

What general information must my 

DWOP include? (§ 250.237) 

This proposed section identifies the 

general information that an operator 

would be required to submit in the 

DWOP, as applicable. The content of 

paragraphs (a) and (b) of this proposed 

section would be moved from current 

§ 250.292(o) and (q). This section would 

add Paragraph (c) to require the 

submission of a list of any associated 

industry standards not incorporated in 

the regulations that the operator will use 

for project design or operation. 


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What well or completions information 

must my DWOP include? (§ 250.238) 

The content of this proposed section 

would be moved from current § 250.292 

and would include a revision to 

paragraph (c) to clarify that this section 

requires information in the operator’s 

DWOP about the design and fabrication 

of each wellbore riser system deployed 

from a floating production facility or 

TLP. This revision would clarify that 

these informational requirements apply 

to wellbore risers as components of the 

well and resolve confusion regarding 

the general term ‘‘riser’’ and its 

applicability of multiple types of risers 

(e.g., pipeline risers and wellbore risers) 

used on the OCS. 

What structural information must my 

DWOP include? (§ 250.239) 

The content of this proposed section 

would be moved from current § 250.292 

and would include a revision to 

paragraph (b) to clarify that the design, 

fabrication, installation, and monitoring 

information would be required for the 

tendon or mooring systems, including 

the turret or buoy system, as applicable. 

This revision would reflect current 

equipment and operations common to 

DWOP approvals. 

What production safety system 

information must my DWOP include? 

(§ 250.240) 

This proposed section identifies the 

production safety system information 

that an operator would be required to 

submit in the DWOP, as applicable, to 

align with the activities the operator 

plans to address in the associated 

production safety systems application. 

The content of paragraphs (a), (b), (c), 

(d), (e)(3) of this proposed section 

would be moved from current § 250.292. 

The additions to this proposed section 

would require submission of the 

following information: 

—(In paragraph (e)(1)) Methods, 

frequency, and acceptance criteria for 

testing the Underwater Safety Valves 

(USVs), SCSSVs, and Boarding 

Shutdown Valves (BSDVs); 

—(in paragraph (e)(2)) The function and 

testing of the host facility Emergency 

Shutdown Device (ESD) system and 

its interface to the subsea system; and 

—(in paragraph (f)) Information on the 

design, operation, maintenance, 

personnel competency, and testing of 

your subsea leak detection system to 

protect your subsea field/ 

infrastructure (e.g., trees, manifolds, 

jumpers). Operators must include 

procedures for how to operate the 

system, ensure system functionality, 

identify a leak, and the actions to be 

taken when a leak is identified. 

The content of this section would 

codify similar concepts from NTL 2000– 

N06, Deepwater Operations Plans 

(DWOP). These proposed revisions 

would also help ensure compliance 

with the requirements of Subpart H. 

Subsea leak detection systems are 

critical for all subsea production 

systems to minimize discharges of 

hydrocarbons into the environment due 

to equipment failure below the 

waterline. 

What subsea systems and pipeline 

information must my DWOP include? 

(§ 250.241) 

This proposed section would identify 

the subsea systems and associated 

pipeline systems information that must 

be included in the DWOP, as applicable. 

The content of paragraphs (c)(2)(i), (ii), 

(iii) of this proposed section would be 

moved from current § 250.292. Proposed 

paragraph (a) would require the operator 

to identify the information common to 

the subsea system and the associated 

pipeline system, which constitute all or 

part of a single project development 

covered by the DWOP and/or aligns 

with activities addressed in an 

associated pipeline application, and 

would require the submission of the 

following: 

—Subsea field schematic depicting the 

planned subsea development 

equipment and infrastructure, 

including wells/trees, non-pipe 

subsea equipment, pipeline route(s), 

pipeline riser systems, umbilical(s), 

and platform footprint; 

—Description of the subsea 

development project detailing the 

subsea and pipeline equipment design 

criteria and analysis procedures 

(including industry standards, 

pressure and temperature ratings, 

materials selection), testing methods, 

and general operational procedures; 

—Description of the fabrication and 

assembly/testing location of subsea 

trees, pipelines, and non-pipe subsea 

equipment (manifold, PLEM, PLET, 

Subsea Umbilical Termination 

Assembly (SUTA), subsea pumps, 

suction piles, etc.); 

—Summary of the subsea tieback 

development technologies’ Integrity 

Management Program, including a 

plan for inspection and monitoring to 

support assessment of system 

condition a minimum of once every 

10 years. This should include, but not 

be limited to, the in-service 

inspections or surveys of hull and 

topsides structures, tendons, 

moorings, and pipelines and/or 

wellbore riser systems to assess 

component condition by inspection 

and analysis after each significant 

environmental event (e.g., hurricane, 

earthquake, loop and eddy currents, 

or mudslide), impacting the system, 

or once every 10 years, whichever 

occurs first. The longevity of the 

activities covered by a DWOP has 

proven to be greater than was 

originally conceived in many cases. 

Subsea tiebacks have become more 

commonplace since this rule was last 

revised, and the importance of 

integrity management for these assets 

has become apparent. This is evident 

especially based on time-dependent 

failure modes like corrosion and 

fatigue, which can significantly 

impact an operator’s ability to 

maintain safe operations. Operators 

are already required to use recognized 

engineering practices, which are 

evaluated in a DWOP, to reduce risk 

in the operation of their assets. Other 

regulations specify that necessary inservice inspections be completed. 

Operators should already have 

integrity management programs in 

place to address the monitoring, 

inspection, and condition assessment 

of their assets. This section would 

codify similar inspection plans and 

maintenance language from NTL 

2000–N06; and 

—Summary of safety and environmental 

controls. 

Paragraph (b) would require 

submission of the following information 

about subsea systems that constitute all 

or part of a single project development 

covered by the DWOP, as applicable: 

—System control type (i.e., direct 

hydraulic or electro-hydraulic); 

—Well tree(s), wellhead, and non-pipe 

equipment general arrangement 

drawings and schematics, with size 

and valve type annotations to 

illustrate the tree and other 

equipment in operation; 

—Estimated shut-in tubing pressure for 

the proposed well(s), including the 

calculations used to arrive at the 

estimate, specifying TVD, reservoir 

pressure, and the fluid gradient used, 

or a brief discussion of the PVT data 

used for estimation; 

—Wellbore static bottomhole 

temperature and the estimated 

flowing temperature at the tree, 

including a description of the method 

used to calculate this estimate; 

—Umbilical(s) and umbilical 

connection(s), including an umbilical 

cross-section schematic; 

—Chemical or other injection systems 

and/or enhanced recovery systems to 

be used; 


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—Corrosion monitoring and prevention/ 

inhibition provisions; 

—Details of any re-furbished and/or recertified equipment you plan to use; 

and 

—A schedule of development activities, 

including well completion, facility 

installation, and anticipated date of 

first oil. 

Paragraph (c) would require an 

operator to include pipeline information 

in its DWOP, as applicable, to align with 

the activities to be addressed in the 

associated pipeline application(s): 

—Design and fabrication information for 

each pipeline riser system; 

—For projects that will use a pipeline 

free standing hybrid riser (FSHR) on 

a permanent installation that uses a 

buoyancy air can suspended from the 

top of the riser, the operator would be 

required to provide the following 

information in its DWOP as part of the 

discussion required by paragraph 

(b)(1) and (2) of this section: A 

detailed description and drawings of 

the FSHR, buoy, and the associated 

connection system; detailed 

information regarding the system used 

to connect the FSHR to the buoyancy 

air can, and associated redundancies; 

and descriptions of the monitoring 

system and monitoring plan for the 

pipeline FSHR and the associated 

connection system for fatigue, stress, 

and any other abnormal condition 

(e.g., corrosion), that may negatively 

impact the riser system’s integrity; 

and 

—Pipeline and pipeline riser 

installation methods. 

Submission of this information is 

consistent with what BSEE presently 

requires in the DWOP (and has 

historically required). The proposed 

requirements would clarify general 

language in the existing regulation by 

adding specificity regarding scope. 

What new or unusual technology 

information must my DWOP include? 

(§ 250.242) 

This proposed section would identify 

the new or unusual technology 

information that must be included in 

the DWOP, including the information 

referenced in the applicable Conceptual 

Plan. Proposed paragraph (a) would 

require the submission of a description 

of any new or unusual technology being 

used in a development project, 

including a reference to previously 

approved New or Unusual Technology 

Conceptual Plans or New or Unusual 

Technology Barrier Conceptual Plans. 

Paragraph (b) would require 

submission of a description of any new 

or unusual technology not covered 

under the New or Unusual Technology 

Conceptual Plan or New or Unusual 

Technology Barrier Conceptual Plan. It 

would also require an operator to 

include the same applicable information 

as required in §§ 250.228 or 250.229. 

This information is consistent with 

what BSEE historically and presently 

requires to be included in the DWOP. 

The requirements clarify general 

language in the existing regulation by 

adding specificity to the scope of 

information required in a DWOP. This 

would allow for previously reviewed 

technology to be described and 

referenced, if applicable. It would also 

allow for new or unusual technology 

proposals and approvals at a later stage 

of project development, provided that 

enough time is allowed to also comply 

with §§ 250.228 and/or 250.229. 

These revisions would codify current 

BSEE practices and would provide 

BSEE with sufficient information for 

proper new or unusual technology and 

DWOP review. These revisions would 

also provide clarity and consistency for 

operator submittal of the DWOP. 

May I combine the Conceptual Plan and 

the DWOP? (§ 250.245) 

The content of this proposed section, 

which addresses when an operator may 

submit a combined Conceptual Plan and 

DWOP, would be moved from current 

§ 250.294 and would include the 

following revisions: 

The introductory paragraph would be 

revised to clarify that, if the operator’s 

development project meets the criteria 

in proposed paragraphs (a) and (b) of 

this section, an operator may submit a 

combined Conceptual Plan/DWOP that 

complies with all applicable 

requirements for both, on or before the 

deadline for submitting the Conceptual 

Plan, as described in proposed 

§ 250.226. Existing paragraph (a), which 

allows the operator to submit a 

combined Conceptual Plan/DWOP if the 

project is located in water depths of less 

than 400 meters (1,312 feet), would be 

removed. In the past, deepwater 

development projects, including 

projects in water depths greater than 

400 meters, involved the use of systems 

and technologies that, at the time, were 

new and complex, and necessitated 

separate reviews provided through the 

Conceptual Plan and DWOP process. 

Over time, however, as deepwater 

development projects became more 

common, the knowledge gained and 

technologies used have matured to such 

a degree that these projects are now 

largely standardized and routine. 

Therefore, BSEE no longer finds the 

water depth criteria relevant to the 

allowance to combine a Conceptual Plan 

and DWOP. The key factor necessary to 

determine the need for a separate 

Conceptual Plan and DWOP is whether 

the project proposes to use new 

technology, regardless of water depth. 

Existing paragraph (a) would be 

replaced with existing paragraph (b), 

which allows a combined plan if the 

project is similar to projects involving 

subsea tieback development technology 

for which the operator has obtained 

approval previously. This rulemaking 

would add a new paragraph (b) to allow 

for the submission of a combined 

Conceptual Plan/DWOP if the project 

does not involve either new or unusual 

technology or a new platform. As 

previously stated at the beginning of the 

paragraph, the operator must meet the 

criteria in paragraph (a) and (b) of 

proposed § 250.245 in order to be able 

to submit a combined Conceptual Plan/ 

DWOP. 

These revisions would provide clarity 

for operators to streamline the process, 

when appropriate, and would reflect 

conforming edits for new or unusual 

technology. These revisions would 

reflect current BSEE acceptance of 

combined submission of the Conceptual 

Plan and DWOP in certain situations. 

When must I revise my DWOP? 

(§ 250.246) 

The content of this proposed section 

would be moved from current § 250.295 

and revised to clarify when revision to 

an approved Conceptual Plan or DWOP 

is necessary. Revision is necessary when 

there are changes in the development 

project that alter the proposed plan or 

procedures, but that do not involve a 

physical alteration of the equipment on 

the platform or the seabed. As explained 

below, a supplement is required when 

changes involve a physical alteration of 

the equipment on the platform or the 

seabed. This section and the following 

section are intended to reduce 

confusion by helping operators 

determine when a revision or a 

supplement to the applicable 

Conceptual Plan or DWOP is necessary. 

When must I supplement my DWOP? 

(§ 250.247) 

This proposed section would identify 

when an operator must supplement the 

approved DWOP to reflect additions or 

changes in the development project. 

Proposed paragraph (a) would require 

the operator to submit a supplement to 

the DWOP to reflect any additions or 

changes in the development project that 

physically alter the platform, process 

facilities, equipment, or systems 

approved in the original Conceptual 

Plan or DWOP. If a Supplemental 

DWOP proposes the addition of any 


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wells (e.g., a new subsea field) not 

approved in the original DWOP, the 

operator may not complete or produce 

from the new well(s) until BSEE 

approves the Supplemental DWOP. 

Proposed paragraph (b) would require 

a supplement to the DWOP for additions 

or changes that involve the addition of 

any new or unusual technology to the 

project that was not previously 

approved under the New or Unusual 

Technology Conceptual Plan, New or 

Unusual Technology Barrier Conceptual 

Plan, or DWOP. This proposed 

paragraph would also clarify that the 

operator may not install any new or 

unusual technology until BSEE 

approves the Supplemental DWOP. 

This section would be added to clarify 

when operators must submit 

Supplemental DWOPs. This section and 

the section above are intended to reduce 

confusion by helping operators 

determine when a revision or a 

supplement to the DWOP is necessary. 

What information must I include in my 

Supplemental DWOP? (§ 250.248) 

This proposed section would describe 

the information that must be included 

in the supplement to the DWOP 

referenced in proposed § 250.247. 

Paragraph (a) would require the same 

information for the wells or equipment 

as required in the applicable Conceptual 

Plan and DWOP requirements in this 

subpart. This addition would ensure 

consistency between the initial and 

supplemental submissions. 

Paragraph (b) would describe 

information for each applicable 

Conceptual Plan or DWOP section that 

is being impacted by the addition or 

change. 

Paragraph (c) would require payment 

of the new service fee for BSEE’s review 

and processing of a supplemental 

DWOP, as listed in the proposed 

revisions to § 250.125. 

Subpart D—Oil and Gas Drilling 

Operations 

Hydrogen Sulfide (§ 250.490) 

This proposed rule would revise 

paragraph (p) of this section, which 

addresses metallurgical properties of 

equipment used in an H2S environment. 

The paragraph would be revised to state 

that if operating in a zone with H2S 

present or when the concentration of 

H2S in the produced fluid may exceed 

0.05 pounds per square inch (psi) partial 

pressure of H2S, the operator must use 

equipment that is constructed of 

materials with metallurgical properties 

that resist or prevent sulfide stress 

cracking (also known as hydrogen 

embrittlement, stress corrosion cracking, 

or H2S embrittlement), chloride-stress 

cracking, hydrogen-induced cracking, 

and other failure modes. 

This regulation would be revised to be 

consistent with the requirements of 

NACE Standard MR0175–2003, 

‘‘Standard Material Requirements, 

Metals for Sulfide Stress Cracking and 

Stress Corrosion Cracking Resistance in 

Sour Oilfield Environments,’’ Revised 

January 17, 2003; incorporated by 

reference at existing §§ 250.490 and 

250.901 and NTL 2009–G31. Section 

250.490 paragraph (p) currently requires 

that the tubing and casing be designed 

for NACE requirements, but incorrectly 

refers only to ‘‘H2S present’’ as the 

concentration necessary to trigger this 

requirement. ‘‘H2S present’’ is defined 

in existing § 250.490 paragraph (b) as 

‘‘could potentially result in atmospheric 

concentration of 20 ppm or more of 

H2S.’’ This proposed rule would clarify 

that in either ‘‘H2S present’’ conditions 

or when H2S concentrations in the 

produced fluid exceed 0.05 psi partial 

pressure of H2S, the operator must use 

equipment that is constructed of 

materials with certain metallurgical 

properties, in accordance with NACE 

Standard MR0175–2003. 

Subpart E—Oil and Gas WellCompletion Operations 

Tubing and Wellhead Equipment 

(§ 250.518) 

This proposed rule would revise 

paragraph (a) of § 250.518 to include the 

following: 

—The tubing string must be evaluated 

for burst, collapse, and axial loads 

with appropriate safety and design 

factors for the pressure and 

temperature environments of the 

completion, production, shut-in, and 

injection load cases. 

—The tubing string materials must be 

appropriate for the environment. The 

operator must follow NACE Standard 

MR0175–2003 (as incorporated by 

reference in § 250.198) when H2S 

concentration may equal or exceed 

0.05 psi partial pressure. 

—The tubing string threaded connectors 

must be appropriate for the loads 

identified in proposed paragraph 

(a)(1). 

These revisions would reflect 

essential well design elements 

addressed in industry standards. 

Current regulations discuss well design 

specific to casing, but little is provided 

for tubing design, which is equally 

critical for well integrity. Regulations 

currently establish H2S concentrations 

that constitute a specific threat to 

personnel and establish concentrations 

that trigger enactment of H2S protocols. 

Additional requirements added to this 

section would address H2S impacts to 

equipment integrity, as these 

components must function as barriers to 

personnel and the environment. Section 

250.490 paragraph (p) currently requires 

that the tubing and casing be designed 

for NACE requirements, but incorrectly 

refers only to ‘‘H2S present’’ as the 

concentration necessary to trigger this 

requirement. ‘‘H2S present’’ is defined 

in existing § 250.490 paragraph (b) as 

‘‘could potentially result in atmospheric 

concentration of 20 ppm or more of 

H2S.’’ This proposed rule would clarify 

that, in either ‘‘H2S present’’ conditions 

or when H2S concentrations in the 

produced fluid exceed 0.05 psi partial 

pressure of H2S, the operator must use 

equipment that is constructed of 

materials with certain metallurgical 

properties, in accordance with NACE 

Standard MR0175–2003. 

The proposed rule would also revise 

paragraph (c) of this section to include 

the design and testing of the wellhead, 

tree, and related equipment in 

accordance with ANSI/API Spec. 6A (as 

incorporated by reference in § 250.198) 

or ANSI/API Spec. 17D (as incorporated 

by reference in § 250.198), as applicable. 

This rulemaking would also add 

paragraphs (c)(1), (2), and (3) to clarify 

that: 

—Newly completed dry trees (e.g., 

fixed, hybrid, or mudline suspension) 

for production or injection wells must 

be equipped with a minimum of one 

master valve and one surface safety 

valve (SSV), installed above the 

master valve, in the vertical run of the 

tree. 

—Newly completed subsea production 

or injection wells must be equipped 

with a minimum of one USV installed 

in the horizontal or vertical run of the 

tree (e.g., vertical, or horizontal 

subsea trees). 

—Newly completed wells with a 

mudline suspension conversion to a 

subsea tree must have a minimum of 

two casing strings tied back and 

sealed below the tubing head. At a 

minimum, the production casing and 

the next outer casing must be tied 

back to the wellhead, to ensure 

annular isolation. 

Current regulations do not address 

modern tree design and application. 

These proposed revisions would better 

define safety valve requirements based 

upon modern configuration and tree 

design. ANSI/API Spec. 6A is 

referenced extensively in Subpart H for 

Safety and Pollution Prevention 

Equipment (SPPE) equipment; by 

including ANSI/API Spec. 6A in this 

section, BSEE would reinforce the 


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importance of its use at the tree 

installation stage. ANSI/API Spec. 17D 

is currently applied in regulations to 

Blowout Preventer (BOP) Systems and 

Components. However, its relevance 

extends heavily to tree design. These 

proposed changes would reduce 

requests to use alternate procedures or 

equipment and reflect universal 

industry accepted practices for tree 

design and operation. 

Proposed paragraph (c)(3) would also 

be added because ANSI/API Spec. 17D 

does not address mudline suspension 

conversion to a subsea tree with more 

than one casing tieback. These revisions 

would also codify similar language from 

NTL 2006 G–20, which would establish 

a requirement for a minimum of two 

casing strings tied back and sealed 

below the tubing head for a mudline 

suspension conversion to a subsea tree. 

Paragraph (d) of this section would 

also be revised to clarify that both the 

subsurface safety equipment and surface 

safety equipment must comply with 

applicable requirements of Subpart H. 

Subpart F—Oil and Gas Well-Workover 

Operations 

Tubing and Wellhead Equipment 

(§ 250.619) 

This proposed rule would revise 

paragraph (a) of § 250.619 to include the 

following: 

—The tubing string must be evaluated 

for burst, collapse, and axial loads 

with appropriate safety and design 

factors for the pressure and 

temperature environments of the 

completion, production, shut-in, and 

injection load cases. 

—The tubing string materials must be 

appropriate for the environment. The 

operator must follow NACE Standard 

MR0175–2003 (as incorporated by 

reference in § 250.198) when H2S 

concentration may equal or exceed 

0.05 psi partial pressure. 

—The tubing string threaded connectors 

must be appropriate for the loads 

identified in proposed paragraph 

(a)(1). 

These revisions would reflect 

essential well design elements 

addressed in industry standards. 

Current regulations discuss well design 

specific to casing, but little is provided 

for tubing design, which is equally 

critical for well integrity. Regulations 

currently establish H2S concentrations 

that constitute a threat to personnel and 

establish concentrations that trigger 

enactment of H2S protocols. Additional 

requirements added to this section 

address H2S impacts to equipment 

integrity, as these components must 

function as barriers to personnel and the 

environment. Section 250.490 paragraph 

(p) currently requires that the tubing 

and casing be designed for NACE 

requirements, but incorrectly refers only 

to ‘‘H2S present’’ as the concentration 

necessary to trigger this requirement. 

‘‘H2S present’’ is defined in existing 

§ 250.490 paragraph (b) as ‘‘could 

potentially result in atmospheric 

concentration of 20 ppm or more of 

H2S.’’ This proposed rule would clarify 

that in either ‘‘H2S present’’ conditions 

or when H2S concentrations in the 

produced fluid exceed 0.05 psi partial 

pressure of H2S, the operator must use 

equipment that is constructed of 

materials with certain metallurgical 

properties, in accordance with NACE 

Standard MR0175–2003. 

This proposed rule would also revise 

paragraph (c) to include the design and 

testing of the wellhead, tree, and related 

equipment in accordance with ANSI/ 

API Spec. 6A (as incorporated by 

reference in § 250.198) or ANSI/API 

Spec. 17D (as incorporated by reference 

in § 250.198), as applicable. This section 

would also add paragraphs (c)(1), (2), 

and (3) to clarify that: 

—Newly completed dry trees (e.g., 

fixed, hybrid, or mudline suspension) 

for production or injection wells must 

be equipped with a minimum of one 

master valve and one SSV, installed 

above the master valve, in the vertical 

run of the tree. 

—Newly completed subsea production 

or injection wells must be equipped 

with a minimum of one USV installed 

in the horizontal or vertical run of the 

tree (for vertical or horizontal subsea 

trees). 

—Newly completed wells with a 

mudline suspension conversion to a 

subsea tree must have a minimum of 

two casing strings tied back and 

sealed below the tubing head. At a 

minimum, the production casing and 

the next outer casing must be tied 

back to the wellhead, to ensure 

annular isolation. 

Paragraph (d) would also be revised to 

clarify that surface safety equipment 

must be installed, maintained, and 

tested in accordance with applicable 

sections of Subpart H, in addition to the 

subsurface safety equipment. 

Current regulations do not address 

modern tree design and application. 

These revisions would better define 

safety valve requirements based upon 

configuration and tree design. ANSI/API 

Spec. 6A is referenced extensively in 

Subpart H for SPPE equipment. By 

including ANSI/API Spec. 6A into this 

section, BSEE would reinforce the 

importance of its use at the tree 

installation stage. ANSI/API Spec. 17D 

is currently applied in regulations 

related to BOP systems and 

components; however, its relevance 

extends heavily to tree design. These 

changes would reduce requests to use 

alternate procedures or equipment and 

reflect industry accepted practices for 

tree design and operation. 

Subpart G—Well Operations and 

Equipment 

What information must I submit for BOP 

systems and system components? 

(§ 250.731) 

This proposed rule would revise 

existing paragraph (c)(4) of this section 

to update a cross-reference to the 

definition of HPHT in accordance with 

proposed § 250.105. This revision is 

administrative. 

What are the independent third party 

requirements for BOP systems and 

system components? (§ 250.732) 

This rulemaking would revise existing 

paragraph (c) of § 250.732 to reflect the 

addition of the new or unusual 

technology and new or unusual 

technology barrier requirements in 

Subpart B. This rulemaking would 

delete the third party requirements 

under existing paragraph (c) because 

that information would be covered 

under the new DWOP Process 

requirements. These revisions would 

connect the HPHT permitting (e.g., 

APD) requirements and the DWOP 

Process requirements and would 

improve BSEE’s review and decision 

process. These revisions help ensure 

that the specified equipment is fit for 

service in the environmental conditions 

reasonably expected at the operation’s 

site. 

The proposed revisions to this section 

would remove duplicative requirements 

now covered under the DWOP new or 

unusual technology barrier 

requirements and would provide greater 

detail considering that the Conceptual 

Plan review occurs before use of HPHT 

equipment and would occur before 

application review. This rulemaking 

would consolidate the language and 

refer to the applicable new or unusual 

technology barrier requirements and 

would specify that BSEE would require 

Conceptual Plan and appropriate permit 

approval before equipment installation. 

This addition would provide 

clarification to operators unfamiliar 

with the applicable DWOP 

requirements. 


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29804 Federal Register / Vol. 87, No. 94 / Monday, May 16, 2022 / Proposed Rules 

Subpart H—Oil and Gas Production 

Safety Systems 

Additional Requirements for Subsurface 

Safety Valves (SSSVs) and Related 

Equipment Installed in High Pressure 

High Temperature (HPHT) 

Environments (§ 250.804) 

This rulemaking proposes to remove 

and reserve this section. The existing 

requirements from this section would be 

addressed under proposed §§ 250.105 

and 250.204. 

III. Additional Comments Solicited 

In addition to public comments on the 

revisions proposed under this 

rulemaking, BSEE is soliciting 

comments on the following issues: 

A. Additional Industry Standards To 

Consider for Incorporation 

BSEE is seeking information regarding 

any existing industry standards that 

address qualification of new technology 

barrier equipment that should be 

considered for incorporation into the 

regulations. Please provide any rationale 

for BSEE to consider incorporation. 

B. Fluid as a Conditional Temporary 

Barrier 

BSEE is considering adding the 

following into the final rule: 

‘‘BSEE may consider wellbore fluids 

as a temporary barrier if you meet the 

following criteria: 

(1) BOP systems and related 

equipment are installed in accordance 

with the approved operation on the well 

and can be actuated on demand; 

(2) The density of the wellbore fluid 

is known and creates a pressure greater 

than the source pressure; 

(3) The elevation of the wellbore fluid 

level is known; 

(4) The fluid pit volumes are 

continuously monitored for increases 

and the well for flow; and 

(5) The well must be continuously 

monitored during well operations and 

must not be left unattended at any time 

unless the well is shut in and secured. 

Once well bore fluids are isolated 

below a mechanical barrier, they are no 

longer considered a barrier.’’ 

BSEE is soliciting comments on the 

appropriateness of promulgating these 

provisions in the final rule. 

Additionally, BSEE is soliciting 

comments that identify any other 

conditions that should be considered 

when determining whether to use fluid 

as a temporary barrier. Please provide 

supporting reasons and data for your 

comments. 

C. Economic Data 

The compliance costs and savings in 

the initial regulatory impact analysis 

(IRIA) are BSEE’s best estimates based 

on experience with the current DWOP 

process, stakeholder interactions, and 

communication with industry. BSEE is 

requesting comments related to the 

appropriateness and accuracy of the 

compliance costs and benefits identified 

in the IRIA. Please provide supporting 

reasons and data for your comments. 

IV. Derivation Table 

The following table is intended to 

provide information about the 

derivation of proposed requirements in 

Subparts B. This table provides 

guidance on the following: 

—The destination of various existing 

requirements. 

—The organization and content of the 

proposed revisions. 

This table does not provide definitive 

or exhaustive guidance and should be 

used in conjunction with the section-bysection discussion and regulatory text of 

this proposed rule. 

The proposed rule would make 

changes as outlined in the following 

table: 

Current regulations section Proposed rule 

section Nature of change 

Subpart A: 

250.804 .............................................. 250.105 Would move the definition of HPHT to make it applicable to all operations, not just 

production 

Subpart B: 

250.200 .............................................. 250.200 Would add definitions for barrier categorization, primary and secondary barriers, 

and new or unusual technology. 

250.201 .............................................. 250.201 Would add information about the three new conceptual plans and when submittal of 

each plan is required. 

250.204 .............................................. 250.202 Moved without revision. 

250.205 .............................................. 250.203 Moved without revision. 

New .................................................... 250.204 Would clarify what information must be submitted to BSEE if an operator plans to 

install HPHT barrier equipment. 

New .................................................... 250.206 Would codify some of the barrier concepts from existing BSEE guidance. 

New .................................................... 250.207 Would require the installation and maintenance of a primary and secondary barrier 

system to contain the source. 

550.280 .............................................. 250.208 Would include similar content with minor formatting changes to reflect BSEE applicability. 

550.281(a) and (b) ............................. 250.209 Would include similar content with minor formatting changes to reflect BSEE applicability. 

250.282 .............................................. 250.210 Would include similar content with minor formatting changes to reflect BSEE applicability. 

New .................................................... 250.211 Would clarify the new or unusual technology failure reporting requirements. 

250.286 .............................................. 250.220 Would clarify the addition of new or unusual technology, and the operations that 

could be covered under the DWOP Process. 

250.287 .............................................. 250.221 Would include similar content and clarify when the DWOP Process is applicable. 

New .................................................... 250.225 This rulemaking would add this section to identify the 3 new proposed conceptual 

plans. 

250.288 and 250.290 ........................ 250.226 Would include similar content and clarify when to submit the applicable conceptual 

plans. 

250.289 .............................................. 250.227 Would include content from existing paragraphs (a), (b), (c), (i)(1), and specify the 

content of the Project Conceptual Plan. 

New .................................................... 250.228 Would specify the content of the New or Unusual Technology Conceptual Plan. 

New .................................................... 250.229 Would specify the content of the New or Unusual Technology Barrier Conceptual 

Plan. 

New .................................................... 250.230 Would specify the I3P nomination requirements. 


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Federal Register / Vol. 87, No. 94 / Monday, May 16, 2022 / Proposed Rules 29805 

Current regulations section Proposed rule 

section Nature of change 

New .................................................... 250.231 Would specify the I3P requirements for applicable conceptual plan review. 

New .................................................... 250.232 Would clarify the I3P report expectations. 

250.291 .............................................. 250.235 Would include similar content and clarify DWOP submittals to reflect new or unusual technology additions. 

New .................................................... 250.236 Would add a table listing the applicable sections with corresponding information for 

the DWOP content. 

250.292 .............................................. 250.237 Would include content from existing paragraphs (a), (b) and clarify the general 

DWOP requirements. 

250.292 .............................................. 250.238 Would include content from existing paragraphs (a), (b), (c) and clarify the completions information DWOP requirements. 

250.292 .............................................. 250.239 Would include content from existing paragraphs (a), (b), (c) and clarify the structural information DWOP requirements. 

250.292 .............................................. 250.240 Would include content from existing paragraphs (a), (b), (c), (d), (e)(3) and clarify 

the production safety system information DWOP requirements. 

250.292 .............................................. 250.241 Would include content from existing paragraphs (c)(2)(i), (ii), (iii) and clarify the 

subsea systems and pipeline information DWOP requirements. 

New .................................................... 250.242 Would clarify the new or unusual technology information DWOP requirements. 

250.294 .............................................. 250.245 Would include similar content and clarify when an operator can combine the conceptual plan and the DWOP. 

250.295 .............................................. 250.246 Would include similar content and clarify when a revised DWOP is necessary. 

New .................................................... 250.247 Would clarify when a supplemental DWOP is necessary. 

New .................................................... 250.248 Would clarify the content of a supplemental DWOP. 

V. Procedural Matters 

Regulatory Planning and Review 

(Executive Orders (E.O.) 12866 and 

13563) 

E.O. 12866, Regulatory Planning and 

Review provides that OMB’s Office of 

Information and Regulatory Affairs 

(OIRA) will review all significant 

regulatory actions. A significant 

regulatory action is one that is likely to 

result in a rule that: 

• Has an annual effect on the 

economy of $100 million or more, or 

adversely affects in a material way the 

economy, a sector of the economy, 

productivity, competition, jobs, the 

environment, public health or safety, or 

state, local, or tribal governments or 

communities; 

• Creates serious inconsistency or 

otherwise interferes with an action 

taken or planned by another agency; 

• Materially alters the budgetary 

impacts of entitlement grants, user fees, 

loan programs, or the rights and 

obligations of recipients thereof; or 

• Raises novel legal or policy issues 

arising out of legal mandates, the 

President’s priorities, or the principles 

set forth in E.O. 12866. 

BSEE has concluded that this 

proposed rule is not likely to be a 

significant action under E.O. 12866. In 

particular, it is estimated that this 

proposed rule would not have an annual 

economic impact of $100 million or 

more and would not have a material 

adverse effects or raise novel issues. 

In support of that conclusion, BSEE 

prepared an IRIA to assess the 

anticipated costs and potential benefits 

of the proposed rulemaking. The IRIA 

estimates that the increase in 

annualized costs, compared with the 

baseline in the absence of the proposed 

rule, is $2.9 million per year. Over the 

period 2021–2030, those costs are 

estimated to have a total present value 

of $29.0 million undiscounted, $24.7 

million discounted at 3 percent, and 

$20.4 million discounted at 7 percent. 

The IRIA for this proposed rulemaking 

can be found in the docket at https://

www.regulations.gov/ (Docket ID: BSEE– 

2021–0003). 

As required by the Independent 

Offices Appropriation Act (IOAA), as 

amended (31 U.S.C. 9701), the proposed 

rule would establish new fees for 

BSEE’s review and processing of several 

types of operator submissions and 

reports. This rulemaking would add 

service fees for processing a Project 

Conceptual Plan, New or Unusual 

Technology Conceptual Plan, New or 

Unusual Technology Barrier Conceptual 

Plan, revised DWOP, Combined 

Conceptual Plan/DWOP, and 

Supplemental DWOP. This rulemaking 

would also revise the cost recovery fee 

amount for DWOP review. The 

proposed rule would increase, and not 

adversely affect, the government’s 

receipt of user fees. BSEE’s economic 

analysis projects that, altogether, the 

fees anticipated to be collected under 

the proposal over a 10-year period 

(2021–2030) would exceed the baseline 

fees collected by approximately $7.8 

million (undiscounted). 

The rulemaking would improve 

operational and environmental safety 

and human health for deepwater 

development projects and other projects 

or systems that use new or unusual 

technology, not only by providing 

clarity and regulatory certainty 

regarding the information submission 

process, but also by ensuring that 

additional regulatory requirements and 

that New or Unusual Technology Barrier 

Conceptual Plans are reviewed by I3Ps, 

as well as providing BSEE discretion to 

require I3P review of New or Unusual 

Technology Conceptual Plans. In a 

detailed analysis of the costs and 

benefits of the proposed regulation, 

BSEE has estimated the increased costs 

for industry and government relating to 

the enhanced plan preparation and 

submission requirements. Anticipated 

costs to industry and government were 

estimated assuming current rules and 

practices and contrasted with the 

proposed rule. Combined costs over 

2021–2030 totaled $38.1 million with 

current rules and practices versus $67.1 

million with the proposed rule, 

implying annualized cost increases of 

$2.9 million discounted at 3% or 7%. 

BSEE has not quantified the benefits of 

the new submission process, the new 

requirements for new or unusual 

technology projects, including HPHT 

projects, and I3P reviews. BSEE believes 

that updating references to industry 

standards and by giving greater clarity 

to requirements for submissions for new 

or unusual technology and HPHT 

projects and plans, the proposed rule 

promotes the objectives of E.O. 13563, 

including a reasoned determination that 

its benefits justify its costs (recognizing 

that some benefits and costs are difficult 

to quantify). 

Executive Order 13563, Improving 

Regulation and Regulatory Review, 

reaffirms the principles of E.O. 12866 

while calling for improvements in the 


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29806 Federal Register / Vol. 87, No. 94 / Monday, May 16, 2022 / Proposed Rules 

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. E.O. 13563 

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. We have developed 

this proposed rule in a manner 

consistent with these requirements. 

Regulatory Flexibility Act and Small 

Business Regulatory Enforcement 

Fairness Act 

The Regulatory Flexibility Act (RFA), 

5 U.S.C. 601–612, requires agencies to 

analyze the economic impact of 

regulations when there is likely to be a 

significant economic impact on a 

substantial number of small entities, 

and allows an agency to certify a rule, 

in lieu of preparing an analysis, if the 

regulation will not have such an 

economic impact. Further, the Small 

Business Regulatory Enforcement 

Fairness Act of 1996 (SBREFA), Public 

Law 104–121, (March 29, 1996), as 

amended, requires agencies to produce 

compliance guidance for small entities 

if the rule has a significant economic 

impact on a substantial number of small 

entities. 

BSEE considers that a rule will have 

an impact on a ‘‘substantial number of 

small entities’’ when the total number of 

small entities impacted by the rule is 

equal to or exceeds 10 percent of the 

relevant universe of small entities in a 

given industry. The relevant small-size 

criteria for affected operators and firms 

likely to help prepare reports are 

presented in Table 1 below. 

TABLE 1—SMALL-ENTITY CRITERIA

FOR AFFECTED FIRMS

Industry sector Small-entity 

criteria 

211120 Crude petroleum 

extraction.

1250 employees. 

211130 Natural gas extraction.1250 employees. 

213111 Drilling oil and gas 

wells.

1000 employees. 

541330 Engineering services (for the I3P or other 

reports).

$16.5 million/ 

year revenues. 

Using these criteria, BSEE estimates 

that about 23 companies would be 

affected by the proposed rule over the 

next 10 years (2021–2030), of which 

approximately 12 (52 percent) of the 

potentially impacted businesses are 

considered small; the rest are 

considered large businesses. All of the 

operating businesses meeting the U.S. 

Small Business Administration 

classification are potentially impacted; 

therefore, BSEE expects that the rule 

will affect a substantial number of small 

entities. 

As noted in the E.O. 12866 

discussion, the amendments will result 

in increased costs to firms from HPHT 

and new or unusual technology 

reporting requirements and increased 

service fees, including mandatory I3P 

nominations and reports. The increase 

in cost borne by industry includes cost 

of submissions, preparation, and cost 

recovery fees. BSEE has evaluated 

quantifiable costs and benefits and has 

estimated that there are quantified costs 

to industry from the proposed 

provisions. BSEE has estimated the 

annualized industry costs by business 

size in Table 2. The percent of the total 

industry cost impacts to small operators 

was estimated based on their percentage 

of overall revenues. These revenues 

were estimated by applying Census 

Statistics of U.S. Businesses revenue 

estimates by employment ranges to each 

impacted operator. Based on historical 

information, BSEE estimates that small 

companies will bear 8 percent of the 

industry costs from this rule and large 

companies will bear the remaining 92 

percent. 

TABLE 2—TOTAL 10-YEAR INDUSTRY

COSTS ASSOCIATED WITH RULEMAKING

[2021–2030] 

[Undiscounted annualized $] 

Company size Percent of 

revenues 

Industry 

rulemaking 

costs 

($) 

Small Companies ................ 8 169,977 

Large Companies ................ 92 1,954,737 

Total ........... 100 2,124,715 

The average industry cost and 

revenue per firm were derived from data 

presented in Table 2 and the numbers 

of firms classified as small or large. This 

is presented in Table 3, which 

illustrates that on a per-firm basis the 

new reporting costs that would be 

imposed on small firms by the new 

requirements, at $14,165 per year, 

would represent approximately 0.005 

percent of revenue. That is deemed to be 

not a significant impact. BSEE therefore 

projects that the proposed rule is not 

likely to have a significant economic 

impact on a substantial number of small 

entities. Although it is not likely 

required because of this projection, 

BSEE has conducted an initial 

regulatory flexibility analysis (IRFA) 

which provides information on the 

impact of the proposed rule on small 

entities; it is contained in the IRIA 

which can be found in the docket at 

https://www.regulations.gov/ (Docket 

ID: BSEE–2021–0003). 

TABLE 3—AVERAGE ANNUAL INDUSTRY COST AND REVENUE PER FIRM

[Undiscounted annualized $] 

Company size Count 

Average 

annualized 

industry cost 

per firm 

Average annual 

revenue per firm 

Cost as percent 

of revenue 

Small Companies ..................................................................... 12 $14,165 $283,524,338 0.005 

Large Companies .................................................................... 11 177,703 3,555,005,441 0.005 

The proposed rule is not a major rule 

under the Small Business Regulatory 

Enforcement Fairness Act. To be a major 

rule for that purpose, it must have an 

annual effect on the economy of $100 

million or more, cause a major increase 

in costs or prices, or have significant 

adverse effects on competition, 

employment, investment, productivity, 

innovation, or the ability of U.S.-based 

enterprises to compete with foreignbased enterprises. The increase of cost 

noted earlier, $2.9 million per year, 

would not have a significant adverse 

effect in terms of this Act. 


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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 (E.O. 

12630) 

Under the criteria in E.O. 12630, this 

proposed rule does not have significant 

takings implications. The rule is not a 

governmental action capable of 

interference with constitutionally 

protected property rights. A Takings 

Implication Assessment is not required. 

Federalism (E.O. 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. 

Civil Justice Reform (E.O. 12988) 

This proposed rule complies with the 

requirements of E.O. 12988. 

Specifically, this rule: 

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

requiring that all regulations be 

reviewed to eliminate errors and 

ambiguity and be written to minimize 

litigation; and 

(2) 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 (E.O. 

13175) 

BSEE is committed to regular and 

meaningful consultation and 

collaboration with tribes on policy 

decisions that have tribal implications. 

Under the criteria in E.O. 13175 and 

DOI’s Policy on Consultation with 

Indian Tribes (Secretarial Order 3317, 

Amendment 2, dated December 31, 

2013), we have evaluated this proposed 

rule and determined that it has no 

substantial direct effects on federally 

recognized Indian tribes. 

National Technology Transfer and 

Advancement Act (NTTAA) 

BSEE complies with the National 

Technology Transfer and Advancement 

Act (NTTAA) (15 U.S.C. 3701 et seq.) 

requirement that an agency ‘‘use 

standards developed or adopted by 

voluntary consensus standards bodies 

rather than government-unique 

standards, except where inconsistent 

with applicable law or otherwise 

impractical.’’ (OMB Circular A–119 at p. 

13). BSEE also complies with the Office 

of the Federal Register (OFR) regulations 

governing incorporation by reference. 

(See, 1 CFR part 51.) Those regulations 

also specify the process for updating an 

incorporated standard at § 51.11(a), and 

BSEE complies with those requirements, 

including seeking approval by OFR for 

a change to a standard incorporated by 

reference in a final rule. 

Paperwork Reduction Act (PRA) of 1995 

This proposed rule contains existing 

and new information collection (IC) 

requirements for regulations at 30 CFR 

part 250, subpart B and submission to 

the OMB for review under the 

Paperwork Reduction Act of 1995 (44 

U.S.C. 3501 et seq.) is required. 

Therefore, BSEE will submit an IC 

request to OMB for review and approval 

and will request a new OMB control 

number. Once the 1014–AA49 final rule 

is effective, we will transfer the hour 

burden and non-hour costs burden from 

1014–NEW to 1014–0024 (44,458 hours, 

$68,381 non-hour cost burden, 

expiration October 31, 2021) 30 CFR 

part 250, subpart B, Plans and 

Information, then discontinue the new 

number associated with this 

rulemaking. We may not conduct or 

sponsor, and you are not required to 

respond to, a collection of information, 

unless it displays a currently valid OMB 

control number. 

The proposed regulations would 

establish new and/or revise current 

requirements in Subpart B, Plans and 

Information, by revising regulations 

regarding the Deepwater Operations 

Plan (DWOP) Process and information 

submittal and approval process, which 

includes Conceptual Plans and DWOPs; 

adding requirements for HPHT barrier 

equipment and systems and new or 

unusual technology; and requiring, or 

providing BSEE with the option to 

require, independent third party 

reviews of Conceptual Plans and 

DWOPs. 

The following provides a breakdown 

of the paperwork hour burdens and nonhour cost burdens for this proposed 

rule. While some sections are being 

moved from existing Subpart B 

requirements, it is noted that the burden 

in proposed § 250.210 (current 

§ 250.282) is covered under BOEM’s 

1010–0151. Accordingly, a new burden 

for BSEE is being added. 

As discussed in the Section-bySection analysis above, and in the 

supporting statement available at 

RegInfo.gov, this rule proposes to add/ 

revise: 

[New requirements due to the 

proposed rule are shown in bold] 

§ 250.210—This section would be 

revised and moved from existing 

§ 250.282. It would include minor 

revisions to clarify that the Regional 

Supervisor may direct operators to 

conduct monitoring programs in 

association with their approved EP, 

DPP, DWOP, or DOCD (+ 12 burden 

hours). 

§ 250.211—This section is new and 

would clarify the new or unusual 

technology failure reporting 

requirements and would require 

notification to BSEE within 30 days of 

the failure and provision of a written 

report identifying the root causes of the 

failure (+ 400 burden hours). 

§ 250.221(b)—This section would be 

revised and moved from existing 

§ 250.287. It would clarify that the 

DWOP Process is applicable to any 

project that will include the use of new 

or unusual technology (+ 6 burden 

hours). 

§ 250.226—This section would be 

revised and moved from existing 

§§ 250.288 and 250.290. It would add 

two new Conceptual Plans: New or 

Unusual Technology Conceptual Plan 

and New or Unusual Technology Barrier 

Conceptual Plan. There are also three 

new Cost Recovery Fees (250.125— 

Service Fees) associated with each 

conceptual plan (+ 39 burden hours and 

$1,276,600 non-hour costs burden). 

§ 250.227—This section would be 

revised and moved from existing 

§ 250.289. It would list additional 

information to be submitted with a 

Project Conceptual Plan and would add 

new Independent Third Party (I3P) costs 

for various reviews, certifications, 

verifications, etc. (+ 320 burden hours 

and $37,776 non-hour costs burden). 

§ 250.228—This section is new and 

would list the various submissions 

required with a New or Unusual 

Technology Conceptual Plan and would 

add new I3P costs for various reviews, 

certifications, verifications, etc. (+ 3,600 

burden hours and $676,130 non-hour 

costs burden). 

§ 250.229—This section is new and 

lists the various submissions required 

with a New or Unusual Technology 

Barrier Conceptual Plan and would add 

new I3P costs for various reviews, 

certifications, verifications, etc. (+ 9,360 

burden hours and $2,955,719 non-hour 

costs burden). 

§ 250.230—This section is new and 

would outline the requirements for the 


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operator to nominate an I3P to be used 

in conjunction with applicable 

conceptual plans, including that the I3P 

must be a technical classification 

society, a licensed professional 

engineering firm, or a registered 

professional engineer capable of 

providing the required certifications and 

verifications (+ 9 burden hours). 

§ 250.231(a)—This section is new and 

would add the required information that 

the I3P is to review (+ 16,660 burden 

hours). 

§§ 250.231(b); 250.232—This section 

is new and would require the I3P to 

submit a report documenting the review 

of each item and identify all OEM and 

operator documents used during the 

reviews (+ 60 burden hours). 

§§ 250.231(c), (d); 250.232—This 

section is new and would require the 

I3P to submit a final report that 

summarizes each review requirement 

under (a) of this section and would also 

require the summary report to include 

the equipment and/or system’s technical 

specifications, including a certification 

statement that the equipment and/or 

system is fit for purpose for the 

technical specification by the I3P, and 

verification that the equipment’s 

technical specifications meet or exceed 

the project’s functional requirements 

including a certification statement that 

the equipment and/or system is fit for 

purpose (+ 9 burden hours). 

§§ 250.235; 250.236; 250.237; 250.238; 

250.239; 250.240; 250.241; 250.242; 

250.243; 250.204; and 732(c)—These 

sections would be revised and moved 

from existing §§ 250.291 and 250.292. 

These would identify when and how to 

submit a DWOP; and what general 

information, well or completions 

information, structural information, 

Production Safety System information, 

subsea systems, and pipeline 

information to submit with DWOPs (+ 

1,070 burden hours and $194,655 nonhour costs burden). 

§ 250.245—This section would be 

revised and moved from existing 

§ 250.294. It would be revised to clarify 

that operators may submit a combined 

Conceptual Plan/DWOP, with all 

applicable requirements for both, on or 

before the deadline for submitting the 

Conceptual Plan (+ 428 burden hours 

and $17,918 non-hour costs burden). 

§ 250.246—This section would be 

revised and moved from existing 

§ 250.295. It would be revised to clarify 

when a revision to a Conceptual Plan or 

DWOP is necessary (+ 80 burden hours 

and $1,792 non-hour costs burden). 

§§ 250.247; 250.248—This section is 

new and would identify when an 

operator must supplement the DWOP to 

reflect additions or changes in the 

development project and would add the 

required information that must be 

included in the supplement to the 

DWOP. It would also require a 

supplement to the DWOP when a 

project change involves the addition of 

any new or unusual technology that was 

not previously covered under the New 

or Unusual Technology Conceptual 

Plan, New or Unusual Technology 

Barrier Conceptual Plan, or DWOP (+ 

3,990 burden hours and $736,200 nonhour costs burden). 

Title of Collection: 30 CFR part 250, 

subpart B, Plans and Information. 

OMB Control Number: 1014–NEW. 

Form Number: None. 

Type of Review: New. 

Respondents/Affected Public: 

Potential respondents comprise Federal 

OCS oil, gas, and sulfur lessees/ 

operators and holders of pipeline rightsof-way. 

Total Estimated Number of Annual 

Respondents: Currently there are 

approximately 60 oil and gas drilling 

and production operators in the OCS. 

Not all the potential respondents would 

submit information at any given time, 

and some may submit multiple times. 

Total Estimated Number of Annual 

Responses: 304. 

Estimated Completion Time per 

Response: Varies from 15 minutes to 

980 hours depending on activity. 

Total Estimated Number of Annual 

Burden Hours: 36,043. 

Respondent’s Obligation: Responses 

are mandatory. 

Frequency of Collection: Generally, on 

occasion and as required in the 

regulations. 

Total Estimated Annual Nonhour 

Burden Cost: $5,944,006. 

This rule is also proposing edits and 

citation updates to §§ 250.731(c) and 

250.732(c). No burden changes are being 

proposed. 

In addition, the PRA requires agencies 

to estimate the total annual reporting 

and recordkeeping non-hour cost 

burden resulting from the collection of 

information, and we solicit your 

comments on this item. For reporting 

and recordkeeping only, your response 

should split the cost estimate into two 

components: (1) Total capital and 

startup cost component and (2) annual 

operation, maintenance, and purchase 

of service component. Your estimates 

should consider the cost to generate, 

maintain, and disclose or provide the 

information. You should describe the 

methods you use to estimate major cost 

factors, including system and 

technology acquisition, expected useful 

life of capital equipment, discount 

rate(s), and the period over which you 

incur costs. Generally, your estimates 

should not include equipment or 

services purchased: (1) Before October 

1, 1995; (2) to comply with 

requirements not associated with the 

information collection; (3) for reasons 

other than to provide information or 

keep records for the Government; or (4) 

as part of customary and usual business 

or private practices. 

As part of our continuing effort to 

reduce paperwork and respondent 

burdens, we invite the public and other 

Federal agencies to comment on any 

aspect of this information collection, 

including: 

(1) Whether the collection of 

information is necessary, including 

whether the information will have 

practical utility; 

(2) The accuracy of our estimate of the 

burden for this collection of 

information; 

(3) Ways to enhance the quality, 

utility, and clarity of the information to 

be collected; and 

(4) Ways to minimize the burden of 

the collection of information on 

respondents. 

Send your comments and suggestions 

on this information collection by the 

date indicated in the DATES section to 

the Desk Officer for the Department of 

the Interior at OMB–OIRA at (202) 395– 

5806 (fax) or via the RegInfo.gov portal 

(online). You may view the information 

collection request(s) at https://

www.reginfo.gov/public/do/PRAMain. 

Please provide a copy of your comments 

to the BSEE Information Collection 

Clearance Officer (see the ADDRESSES

section). You may contact Kye Mason, 

BSEE Information Collection Clearance 

Officer at (703) 787–1607 with any 

questions. Please reference Proposed 

Rule 1014–AA49, Oil and Gas and 

Sulfur Operations in the Outer 

Continental Shelf—30 CFR 250, Subpart 

B, Plans and Information (OMB Control 

No. 1014–NEW), in your comments. 

National Environmental Policy Act of 

1969 (NEPA) 

BSEE is proposing to cover this action 

under a National Environmental Policy 

Act of 1969 (NEPA) categorical 

exclusion (see 43 CFR 46.205). BSEE 

believes it meets the criteria set forth at 

43 CFR 46.210(i) for a Departmental 

Categorical Exclusion in that this 

proposed rule is ‘‘. . . of an 

administrative, financial, legal, 

technical, or procedural nature . . . .’’ 

Further, we have preliminarily 

determined that the proposed rule does 

not involve any of the extraordinary 

circumstances listed in 43 CFR 46.215 

that would require further analysis 

under NEPA. The proposed rule does 

not authorize any activities on the OCS. 


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The proposed rule involves the review 

of concepts and specialized 

requirements associated with deepwater 

needs (special moorings, fittings, 

production equipment, HPHT items, 

etc.); however, actual approval of 

Conceptual Plans and DWOPs are for 

administrative purposes and do not 

directly lead to OCS activity that can 

result in environmental impacts. The 

Conceptual Plans and DWOPs only lead 

to an action once they are included and 

addressed in an Exploration Plan (EP), 

Development Operations Coordination 

Document (DOCD), or Development and 

Production Plan (DPP) and subsequent 

permit applications. EPs, DOCDs, DPPs, 

as well as the subsequent well and 

facility permit applications, are 

reviewed under site-specific NEPA 

analyses. Only EPs, DOCDs, and DPPs 

include the detailed regulatory 

requirements to fully assess 

environmental impacts. If an operator 

chooses to modify their Conceptual 

Plans, DWOPs, or proposed technology 

or submit a new one for an activity that 

has already been reviewed and 

approved under the respective EP, 

DOCD, or DPP, then the operator must 

submit a revised EP, DOCD, or DPP as 

per 30 CFR 550.283, which would 

undergo additional NEPA analysis. 

Data Quality Act 

In developing this rule, we did not 

conduct or use a study, experiment, or 

survey requiring peer review under the 

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

C, sec. 515, 114 Stat. 2763, 2763A–153– 

154). 

Effects on the Nation’s Energy Supply 

(E.O. 13211) 

This proposed rule is not a significant 

energy action under the definition in 

E.O. 13211. Although the rule is a 

significant regulatory action under E.O. 

12866, it is not likely to have a 

significant adverse effect on the supply, 

distribution, or use of energy. A 

Statement of Energy Effects is not 

required. 

Clarity of This Regulation 

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: 

(1) Be logically organized; 

(2) Use the active voice to address 

readers directly; 

(3) Use clear language rather than 

jargon; 

(4) Be divided into short sections and 

sentences; and 

(5) 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, or the sections where you feel 

lists or tables would be useful. 

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. 

In order for BSEE to withhold from 

disclosure your personal identifying 

information, you must identify any 

information contained in your comment 

submittal that, if released, would 

constitute a clearly unwarranted 

invasion of your personal privacy. You 

must also briefly describe any possible 

harmful consequence(s) of the 

disclosure of information, such as 

embarrassment, injury, or other harm. 

While you may request that we 

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, 

Outer Continental Shelf—mineral 

resources, Outer Continental Shelf— 

rights-of-way, Penalties, Pipelines, 

Reporting and recordkeeping 

requirements, Sulfur. 

Laura Daniel-Davis, 

Principal Deputy Assistant Secretary, Land 

and Minerals Management. 

For the reasons stated in the 

preamble, the Bureau of Safety and 

Environmental Enforcement (BSEE) is 

proposing to amend 30 CFR part 250 as 

follows: 

PART 250—OIL AND GAS AND 

SULFUR 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, 

33 U.S.C. 1321(j)(1)(C), 43 U.S.C. 1334. 

Subpart A—General 

■ 2. Amend § 250.105 by adding 

definitions for ‘‘BOP systems and 

related equipment’’ and ‘‘HPHT 

environment’ in alphabetical order to 

read as follows: 

§ 250.105 Definitions. 

* * * * * 

BOP systems and related equipment 

includes all pressure controlling and 

pressure containing well control 

equipment that may or will be exposed 

to the well’s MASP during drilling, 

completion, workover, intervention, or 

abandonment. Well control equipment 

includes equipment that is installed for 

the purpose of pressure control and 

containment when it becomes necessary 

to physically enter a well bore during 

drilling, completion, workover, 

intervention, or abandonment modes of 

operation. 

* * * * * 

HPHT environment means when one 

or more of the following well conditions 

exist: 

(1) The drilling, completion, 

workover, intervention, injection, 

production, or abandonment of the well 

requires pressure controlling or pressure 

containing equipment, including well 

control equipment, assigned a pressure 

rating greater than 15,000 psia or a 

temperature rating greater than 350 

degrees Fahrenheit; 

(2) The MASP or SITP is greater than 

15,000 psia 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 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. 

* * * * * 

■ 3. Amend § 250.125 by revising 

paragraph (a)(2) to read as follows: 

§ 250.125 Service fees. 

(a) * * * 


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Service—processing of the following Fee amount 30 CFR 

citation 

*******

(2) Deepwater Operations Plan (DWOP) process: 

(i) Project Conceptual Plan ............................................................................................................................... $2,510 250.226. 

(ii) New or Unusual Technology Conceptual Plan ........................................................................................... 32,611 250.226. 

(iii) New or Unusual Technology Barrier Conceptual Plan ............................................................................... 71,570 250.226. 

(iv) DWOP ......................................................................................................................................................... 13,907 250.235. 

(v) Revised DWOP ........................................................................................................................................... 896 250.246. 

(vi) Combined Conceptual Plan/DWOP ........................................................................................................... 8,959 250.245. 

(vii) Supplemental DWOP ................................................................................................................................. 8,959 250.247. 

* * * * * * * 

■ 4. Amend § 250.198 by revising the 

introductory text and paragraphs (e)(82), 

(86), (91), and (i)(1) to read as follows: 

§ 250.198 Documents incorporated by 

reference. 

Certain material is incorporated by 

reference into this [chapter/subchapter/ 

part/subpart] with the approval of the 

Director of the Federal Register in 

accordance with 5 U.S.C. 552(a) and 1 

CFR part 51. All approved material is 

available for inspection at BSEE and at 

the National Archives and Records 

Administration (NARA). Contact BSEE 

at: the Houston BSEE office at 1919 

Smith Street Suite 14042, Houston, 

Texas 77002; 1–844–259–4779. For 

information on the availability of this 

material at NARA, email: fr.inspection@

nara.gov, or go to: www.archives.gov/ 

federal-register/cfr/ibr-locations.html. 

The material may be obtained from the 

following source(s): 

* * * * * 

(e) * * * 

(82) ANSI/API Spec. 6A, Specification 

for Wellhead and Christmas Tree 

Equipment, Twentieth Edition, October 

2010; Addendum 1, November 2011; 

Errata 2, November 2011; Addendum 2, 

November 2012; Addendum 3, March 

2013; Errata 3, June 2013; Errata 4, 

August 2013; Errata 5, November 2013; 

Errata 6, March 2014; Errata 7, 

December 2014; Errata 8, February 2016; 

Addendum 4, June 2016; Errata 9, June 

2016; Errata 10, August 2016; 

incorporated by reference at 

§§ 250.518(c), 250.619(c), 250.730, 

250.802(a), 250.803(a), 250.833, 

250.873(b), 250.874(g), and 250.1002(b); 

* * * * * 

(86) ANSI/API Spec. 11D1, Packers 

and Bridge Plugs, Third Edition, April 

2015; Errata 1, August 2019; 

incorporated by reference at 

§§ 250.518(e), 250.619(e), and 250.1703; 

* * * * * 

(91) ANSI/API Spec. 17D, Design and 

Operation of Subsea Production 

Systems—Subsea Wellhead and Tree 

Equipment, Second Edition, May 2011; 

incorporated by reference at 

§§ 250.518(c), 250.619(c), and 250.730; 

* * * * * 

(i) * * * 

(1) NACE Standard MR0175–2003, 

Standard Material Requirements, Metals 

for Sulfide Stress Cracking and Stress 

Corrosion Cracking Resistance in Sour 

Oilfield Environments, Revised January 

17, 2003; incorporated by reference at 

§§ 250.490, 250.518(a), 250.619(a), and 

250.901; 

* * * * * 

■ 5. Revise Subpart B to read as follows: 

Subpart B—Plans and Information 

General Information 

Sec. 

250.200 Definitions. 

250.201 What plans and information must I 

submit before I conduct any activities on 

my lease or unit? 

250.202 How must I protect the rights of the 

Federal government? 

250.203 Are there special requirements if 

my well affects an adjacent property? 

250.204 Requirements for high pressure 

high temperature (HPHT) barrier 

equipment. 

250.205 [Reserved] 

Barrier Equipment and Systems 

250.206 What equipment does BSEE 

consider to be a Barrier? 

250.207 How must barrier systems be used? 

Activities and Post-Approval Requirements 

for the EP, DPP, DWOP, and DOCD 

250.208 How must I conduct activities 

under an approved EP, DPP, or DOCD? 

250.209 What must I do to conduct 

activities under the approved EP, DPP, or 

DOCD? 

250.210 Do I have to conduct post-approval 

monitoring? 

250.211 What are my new or unusual 

technology failure reporting 

requirements? 

250.212–250.219 [Reserved] 

Deepwater Operations Plan (DWOP) Process 

250.220 What is the DWOP Process? 

250.221 When must I use the DWOP 

Process? 

250.222–250.224 [Reserved] 

Conceptual Plans 

250.225 What are the types of Conceptual 

Plans that I must submit? 

250.226 When and how must I submit each 

applicable Conceptual Plan? 

250.227 What must the Project Conceptual 

Plan contain? 

250.228 What must the New or Unusual 

Technology Conceptual Plan contain? 

250.229 What must the New or Unusual 

Technology Barrier Conceptual Plan 

include? 

250.230 What are your requirements for the 

Independent Third Party (I3P) 

nomination? 

250.231 What are the I3P review 

requirements for Conceptual Plan 

reviews? 

250.232 General requirements for any I3P 

Report. 

DWOP Approval 

250.235 When and how must I submit the 

DWOP? 

250.236 What information must I submit 

with the DWOP? 

250.237 What general information must my 

DWOP include? 

250.238 What well or completions 

information must my DWOP include? 

250.239 What structural information must 

my DWOP include? 

250.240 What Production Safety System 

information must my DWOP include? 

250.241 What subsea systems and pipeline 

information must my DWOP include? 

250.242 What new or unusual technology 

information must my DWOP include? 

250.243 and 250.244 [Reserved] 

250.245 May I combine the Conceptual Plan 

and the DWOP? 

250.246 When must I revise my DWOP? 

250.247 When must I supplement my 

DWOP? 

250.248 What information must I include in 

my Supplemental DWOP? 

Subpart B—Plans and Information 

General Information 

§ 250.200 Definitions. 

Acronyms and terms used in this 

subpart have the following meanings: 

(a) Acronyms used frequently in this 

subpart are listed alphabetically below: 


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BOEM means Bureau of Ocean Energy 

Management of the U.S. Department of 

the Interior. 

BSEE means Bureau of Safety and 

Environmental Enforcement of the U.S. 

Department of the Interior. 

CID means Conservation Information 

Document. 

CZMA means Coastal Zone 

Management Act. 

DOCD means Development 

Operations Coordination Document. 

DPP means Development and 

Production Plan. 

DWOP means Deepwater Operations 

Plan. 

EIA means Environmental Impact 

Analysis. 

EP means Exploration Plan. 

ESA means Endangered Species Act. 

HPHT means High Pressure High 

Temperature 

MMPA means Marine Mammal 

Protection Act. 

NPDES means National Pollutant 

Discharge Elimination System. 

NTL means Notice to Lessees and 

Operators. 

OCS means Outer Continental Shelf. 

(b) Terms used in this subpart are 

listed alphabetically below: 

Amendment means a change you 

make to an EP, DPP, or DOCD that is 

pending before BOEM for a decision 

(see 30 CFR 550.232(d) and 550.267(d)). 

Barrier categorization includes 

identifying barriers as one of the 

following two types of categories: 

Category 1 Barrier means any 

equipment, component, or assembly 

that functions as part of a primary 

barrier system during any operational 

phase of its life cycle. The operational 

phases of the barrier equipment, 

component, or assembly are drilling, 

completion, workover, intervention, 

injection, production, or abandonment. 

Category 2 Barrier means any 

equipment, component, or assembly 

that normally functions as part of a 

secondary barrier system in all 

operational phases of its life cycle, 

except when a primary barrier fails. The 

operational phases of the barrier 

equipment, component, or assembly are 

drilling, completion, workover, 

intervention, injection, production, or 

abandonment. BSEE may consider nonbarrier structural components of a 

barrier system as Category 2 barrier if 

failure of this structural component 

could reasonably result in a barrier 

failure. 

Primary Barrier system means the 

component or group of components that 

is designated as the principal means of 

isolating the source of hydrocarbons 

and/or pressure from people and the 

environment. 

Secondary Barrier system means the 

component or group of components that 

is designated as the secondary means of 

isolating the source of hydrocarbons 

and/or pressure from people and the 

environment. 

New or unusual technology means 

equipment or procedures used for any 

drilling, completion, workover, 

intervention, injection, production, 

pipeline, platform, decommissioning, or 

abandonment operations that meet any 

of the following criteria: 

(1) Have not been approved for use or 

used extensively in a BSEE OCS Region; 

(2) Have not been approved for use or 

used extensively under the anticipated 

operating conditions; 

(3) Have operating characteristics that 

are outside the performance parameters 

established in 30 CFR part 250; 

(4) Will operate in an HPHT 

environment as defined in § 250.105; or 

(5) Is part of a primary or secondary 

barrier system that uses materials, 

design analysis techniques, validation 

testing methods, or manufacturing 

processes not addressed in existing 

industry standards. 

Subsea tieback development 

technology means, but is not limited to, 

floating production systems, tension leg 

platforms, spars, Floating Production 

Storage and Offloading Vessel (FPSO) 

systems, guyed towers, compliant 

towers, subsea manifolds, subsea wells, 

hybrid wells, and other subsea 

completion or production components 

that rely on a remote site or host facility 

for utility and well control services. 

§ 250.201 What plans and information 

must I submit before I conduct any 

activities on my lease or unit? 

(a) Plans and permits. Before you 

conduct the activities on your lease or 

unit listed in the following table, you 

must submit, and BSEE must approve, 

the listed plans, and any applicable 

permits. Your plans and applicable 

permits may cover one or more leases or 

units. 

You must have BSEE approval of 

a(n) . . . Before you . . . Additional information 

(1) New or Unusual Technology 

Conceptual Plan.

install the new or unusual technology ................................................... Must be approved before any associated application or permit 

(e.g., pipeline, platform, APD, 

APM) approval. 

(2) New or Unusual Technology 

Barrier Conceptual Plan.

install the new or unusual technology barrier equipment ..................... (i) Is required for any project or 

system involving new or unusual 

technology that is also identified 

as a primary or secondary barrier. 

(ii) Must be approved before any 

associated application or permit 

(e.g., pipeline, platform, APD, 

APM) approval. 

(3) Project Conceptual Plan ............ conduct post-drilling installation or well completion activities for a 

deepwater development project, or for any project that will involve 

the use of a subsea tieback development technology in any water 

depth.

Must be approved before well 

completion permit (e.g., APM) 

approval. 

(4) Deepwater Operations Plan 

(DWOP),.

(i) conduct post-completion installation activities for a deepwater development project, or for any project that will involve the use of a 

subsea tieback development technology in any water depth, which 

may include new or unusual technology, or new or unusual technology barrier equipment; and.

(ii) initiate production activities. .............................................................

Must include reference to all applicable, previously approved Conceptual Plans for the associated 

development project. 


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(b) Submitting additional information. 

On a case-by-case basis, the Regional 

Supervisor may require you to submit 

additional information if the Regional 

Supervisor determines that it is 

necessary to evaluate your proposed 

plan or permit. 

(c) Referencing. In preparing your 

proposed plan or permit, you may 

reference information and data 

discussed in other plans or permits you 

previously submitted or that are 

otherwise readily available to BSEE. 

§ 250.202 How must I protect the rights of 

the Federal government? 

(a) To protect the rights of the Federal 

government, you must either: 

(1) Drill and produce the wells that 

the Regional Supervisor determines are 

necessary to protect the Federal 

government from loss due to production 

on other leases or units or from adjacent 

lands under the jurisdiction of other 

entities (e.g., State and foreign 

governments); or 

(2) Pay a sum that the Regional 

Supervisor determines as adequate to 

compensate the Federal government for 

your failure to drill and produce any 

well. 

(b) Payment under paragraph (a)(2) of 

this section may constitute production 

in paying quantities for the purpose of 

extending the lease term. 

(c) You must complete and produce 

any penetrated hydrocarbon-bearing 

zone that the Regional Supervisor 

determines is necessary to conform to 

sound conservation practices. 

§ 250.203 Are there special requirements if 

my well affects an adjacent property? 

For wells that could intersect or drain 

an adjacent property, the Regional 

Supervisor may require special 

measures to protect the rights of the 

Federal government and objecting 

lessees or operators of adjacent leases or 

units. 

§ 250.204 Requirements for high pressure 

high temperature (HPHT) barrier equipment. 

If you plan to install HPHT barrier 

equipment, you must submit 

information with your applicable permit 

and/or application, New or Unusual 

Technology Barrier Conceptual Plan, 

and/or DWOP that demonstrates the 

equipment is fit for service in the 

applicable HPHT environment. You 

must follow the applicable DWOP 

Process requirements, including 

§§ 250.229 and 250.242. 

§ 250.205 [Reserved] 

Barrier Equipment and Systems 

§ 250.206 What equipment does BSEE 

consider to be a Barrier? 

A barrier or barrier system is any 

engineered equipment, materials, 

component, or assembly that is installed 

to contain a hydrocarbon or other 

pressure source(s) to prevent harm to 

people or the environment. BSEE only 

recognizes barriers (non-mechanical or 

mechanical in nature) that are either 

permanently or temporarily installed, 

pressure controlling, and/or pressure 

containing. Pressure controlling barriers 

must be able to be activated on demand. 

You must be able to function and/or 

pressure test your barriers or barrier 

systems to a defined acceptance criteria 

that can be repeated. If the barrier or 

barrier system is classified as Safety and 

Pollution Prevention Equipment (SPPE) 

(as described under § 250.801(a)), then it 

must also meet the leak test 

requirements established in Subpart H. 

§ 250.207 How must barrier systems be 

used? 

You must install and maintain a 

primary and a secondary barrier system 

(redundant barriers) to prevent a loss of 

containment during any operational 

phase of a well, flowline, pipeline, 

production, or riser system. 

Activities and Post-Approval 

Requirements for the EP, DPP, DWOP, 

and DOCD 

§ 250.208 How must I conduct activities 

under an approved EP, DPP, or DOCD? 

(a) Compliance. You must conduct all 

of your lease and unit activities 

according to your approved EP, DPP, or 

DOCD and any approval conditions. If 

you fail to comply with your approved 

EP, DPP, or DOCD: 

(1) You may be subject to BSEE 

enforcement action, including civil 

penalties; and 

(2) The lease(s) involved in your EP, 

DPP, or DOCD may be forfeited or 

cancelled under 43 U.S.C. 1334(c) or (d). 

If this happens, you will not be entitled 

to compensation under § 550.185(b) and 

30 CFR 556.77. 

(b) Emergencies. Nothing in this 

subpart or in your approved EP, DPP, or 

DOCD relieves you of, or limits your 

responsibility to take appropriate 

measures to meet emergency situations. 

In an emergency situation, the Regional 

Environmental Officer may approve or 

require departures from your approved 

EP, DPP, or DOCD. 

§ 250.209 What must I do to conduct 

activities under the approved EP, DPP, or 

DOCD? 

(a) Approvals and permits. Before you 

conduct activities under your approved 

EP, DPP, or DOCD you must obtain the 

following approvals and or permits, as 

applicable, from the District Manager or 

BSEE Regional Supervisor: 

(1) Approval of Applications for 

Permits to Drill (APDs) (see 30 CFR 

250.410); 

(2) Approval of production safety 

systems (see 30 CFR 250.800); 

(3) Approval of new platforms and 

other structures (or major modifications 

to platforms and other structures) (see 

30 CFR 250.905); 

(4) Approval of applications to install 

lease term pipelines (see 30 CFR 

250.1007); and 

(5) Other permits, as required by 

applicable law. 

(b) Conformance. The activities 

proposed in these applications and 

permits must conform to the activities 

described in detail in your approved EP, 

DPP, or DOCD. 

§ 250.210 Do I have to conduct postapproval monitoring? 

The Regional Supervisor may direct 

you to conduct monitoring programs, 

including monitoring in accordance 

with the ESA and the MMPA, in 

association with your approved EP, 

DPP, DWOP, or DOCD. You must retain 

copies of all monitoring data obtained or 

derived from your monitoring programs 

and make them available to BSEE upon 

request. The Regional Supervisor may 

require you to: 

(a) Submit monitoring plans for 

approval before you begin work; and 

(b) Prepare and submit reports that 

summarize and analyze data and 

information obtained or derived from 

your monitoring programs. The Regional 

Supervisor will specify requirements for 

preparing and submitting these reports. 

§ 250.211 What are my new or unusual 

technology failure reporting requirements? 

If you have an approved new or 

unusual technology and it experiences a 

failure during or post-installation, such 

that the technology is unable to perform 

its intended function or if it will be 

recovered and repaired or replaced, you 

must notify the applicable Regional 

Supervisor within 30 days of the failure 

and provide a written report as soon as 

available. The written report must 

identify the root cause(s) for the failure. 

You must also follow all applicable 

failure or incident reporting 

requirements associated with the failure 

(e.g., §§ 250.188, 250.730, and 250.803). 


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§ 250.212–250.219 ]Reserved] 

Deepwater Operations Plan (DWOP) 

Process 

§ 250.220 What is the DWOP Process? 

(a) The DWOP Process consists of 

providing sufficient information from a 

total system approach for BSEE to 

review: 

(1) A deepwater development project, 

(2) A subsea tieback development 

technology, or 

(3) Any other project or system that 

uses new or unusual technology during 

any phase of drilling, completion, 

workover, intervention, injection, 

production, pipeline, platform, 

decommissioning, or abandonment 

operations. 

(b) The DWOP Process does not 

replace but complements other 

submittals required by the regulations, 

such as BOEM EPs, DPPs, and DOCDs, 

or BSEE applications and/or permits 

(e.g., APD, Application for Permit to 

Modify (APM), pipeline, and platform). 

BSEE will use the information in your 

DWOP Process to determine whether 

the project will be developed in an 

acceptable manner, particularly with 

respect to operational safety and 

environmental protection issues 

involved with a deepwater development 

project, subsea tieback development 

technology, or new or unusual 

technology. 

(c) The DWOP Process consists of two 

phases: 

(1) The Conceptual Plans. The 

Conceptual Plans outline certain 

equipment and process specifications, 

operational concepts, and basis of 

design that you plan to use for project 

development, and for applicable 

equipment design, installation and 

operation. Sections 250.227 through 

250.229 prescribe what each of the 

Conceptual Plans must contain. Each 

Conceptual Plan may be submitted 

separately or combined as applicable; 

and 

(2) The DWOP. The DWOP identifies 

specific design, fabrication, installation 

and operational requirements for 

equipment, systems, and activities as 

applicable in §§ 250.236 through 

250.242. 

§ 250.221 When must I use the DWOP 

Process? 

(a) You must use the DWOP Process 

for any project that meets any of the 

following criteria: 

(1) Is planned in water depths greater 

than 1000 ft; 

(2) Will include the use of subsea 

tieback development technology, 

regardless of water depth; or 

(3) Will include the use of any new or 

unusual technology for any drilling, 

completion, workover, intervention, 

injection, production, pipeline, 

platform, decommissioning, or 

abandonment project. 

(b) If you are unsure if your project 

contains subsea tieback development 

technology or new or unusual 

technology, you must contact the 

Regional Supervisor for guidance. 

§ 250.222–250.224 [Reserved] 

Conceptual Plans 

§ 250.225 What are the types of 

Conceptual Plans that I must submit? 

There are three types of Conceptual 

Plans: 

(a) A Project Conceptual Plan—is 

required for any project that is planned 

in water depths greater than 1000 feet or 

will include the use of subsea tieback 

development technology, regardless of 

water depth (see § 250.221 paragraphs 

(a)(1) and (2)) 

(b) A New or Unusual Technology 

Conceptual Plan—is required for any 

project or system that involves 

equipment or systems that are 

considered new or unusual technology 

(see § 250.200 for the definition of new 

or unusual technology); and 

(c) A New or Unusual Technology 

Barrier Conceptual Plan—is required for 

any project or system involving new or 

unusual technology that is also 

identified as a primary or secondary 

barrier (see § 250.200 for the definition 

of primary or secondary barriers). 

§ 250.226 When and how must I submit 

each applicable Conceptual Plan? 

You must submit each applicable 

Conceptual Plan to the Regional 

Supervisor after you have decided on 

the general concept(s) for a project or 

system, and before you begin final 

engineering design of the equipment, 

well, well safety control system, or 

subsea production systems. You must 

submit, for BSEE approval, each 

Conceptual Plan according to the 

following table: 

Conceptual plan type Where to find the 

description Additional information 

(a) Project Conceptual Plan .................... § 250.227 You may not complete any production or injection well or install the tree before 

BSEE has approved the Project Conceptual Plan. 

(b) New or Unusual Technology Conceptual Plan.§ 250.228 (1) You may not install any new or unusual technology until BSEE approves 

your new or unusual technology Conceptual Plan. 

(2) Your plan must be approved by BSEE before it can approve any associated 

application or permit (e.g., pipeline, platform, APD, APM) approval. 

(3) The Regional Supervisor may require the operator to use an independent 

third party to perform certain functions and verifications in accordance with 

§ 250.231, as applicable. 

(c) A New or Unusual Technology Barrier Conceptual Plan.§ 250.229 (1) You must submit a new or unusual technology Barrier Conceptual Plan for 

any project or system involving new or unusual technology that is also identified as a primary or secondary barrier. 

(2) Your plan must be approved by BSEE prior to new or unusual technology 

barrier equipment installation. 

(3) All new or unusual technology barrier equipment must be approved by BSEE 

before any associated application or permit (e.g., pipeline, platform, APD, 

APM) approval. 

(4) All new or unusual technology Barrier Conceptual Plans require the use of 

an Independent Third Party (I3P) to perform certain functions and verifications 

in accordance with § 250.231. 


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§ 250.227 What must the Project 

Conceptual Plan contain? 

In the Project Conceptual Plan, you 

must explain the basis of design that 

you will use to develop the field. You 

must include the following information: 

(a) An overview of the development 

concept(s); 

(b) The system control type (i.e., 

direct hydraulic or electro-hydraulic); 

(c) The distance from each of the 

wells to the host platform, and 

umbilical length(s); 

(d) Confirmation that the subsea 

production safety system will comply 

with Subpart H of this part; 

(e) For a new facility, a description of 

the type of facility you plan to install 

(e.g. Spar, tension leg platform (TLP), 

FPSO, etc.); 

(f) For a subsea tieback to an existing 

facility, a statement identifying whether 

a minor or major structural modification 

will be made to the facility and the 

facility remaining design life. If 

modifications will be made to the 

facility, a calculation of the facility’s 

remaining design life and explanation of 

how the modifications will impact the 

design life; 

(g) A statement regarding whether the 

host facility will be manned or 

unmanned; 

(h) A schedule of development 

activities, including well completion, 

facility installation, and date of first oil; 

(i) Schematics, including: 

(1) A well location plat, 

(2) A subsea field schematic depicting 

the planned development infrastructure 

that contains the wells, pipelines, riser 

systems, umbilical(s), and facility 

footprint, 

(3) The surface or subsea tree, 

(4) Wellbore and completion 

schematic for a typical well (including 

Surface Controlled Subsurface Safety 

Valve (SCSSV) location and chemical 

injection points; and depiction or 

description of gas zones, if any, behind 

the production casing or production 

liner and how those gas zones will be 

isolated), and 

(5) Information concerning the 

drilling and completion systems. 

(j) The estimated shut-in tubing 

pressure for the proposed well(s), 

including the calculation used to arrive 

at the estimate, specifying true vertical 

depth (TVD), reservoir pressure, and the 

fluid gradient used, or a brief discussion 

of the pressure volume temperature 

(PVT) data used for estimation; 

(k) The wellbore static bottomhole 

temperature and the estimated flowing 

temperature at the tree; 

(l) The pressure and temperature 

rating of the tree and wellhead; 

(m) Identify if there will be corrosive 

production (e.g., hydrogen sulfide (H2S), 

Carbon dioxide (CO2), Mercury (Hg) or 

injection fluids (e.g., acid), including 

concentrations; 

(n) Identify whether any of the 

proposed equipment will be refurbished and re-certified; 

(o) Identify whether enhanced 

recovery is planned for the early life of 

the project; 

(p) Identify whether any new or 

unusual technology will be used to 

develop your project involving the 

following activities: drilling, 

completion, injection, production, 

pipeline, or platform; 

(q) Identify whether the well(s) will 

include smart completion technology; 

and 

(r) Payment of the service fee listed in 

§ 250.125. 

§ 250.228 What must the New or Unusual 

Technology Conceptual Plan contain? 

(a) You must include the following 

information, as applicable, in your New 

or Unusual Technology Conceptual 

Plan: 

(1) How the New or Unusual 

Technology Conceptual Plan fits within 

your overall site specific project, if 

applicable, including an overview of the 

project development concepts. 

(2) A description of the technology 

and specific conditions under which it 

will be used; 

(3) Description of shut-in capabilities 

and procedures; 

(4) Description of redundancies of 

critical components or systems that will 

be used; 

(5) Discussion of how the new or 

unusual technology could impact the 

barrier system, if any, including 

(i) Detection method for new or 

unusual technology failure, 

(ii) How the barrier functions to a failsafe state when impacted by new or 

unusual technology failure; 

(6) Information on inspection and 

testing capabilities; 

(7) A risk assessment and failure 

mode analysis; 

(8) Operating procedures; 

(9) History of development and 

application of the technology; 

(10) The basis of design, including 

design verification and validation 

testing; 

(11) Detailed schematics; 

(12) Justification for new or unusual 

technology use, and any additional 

information required for a complete 

review; 

(13) A list of requests for alternate 

procedures or equipment in accordance 

with § 250.141 and request for 

departures in accordance with 

§ 250.142; 

(14) A certification statement that the 

technology is fit for service in the 

applicable environment (for the specific 

project at location); and 

(15) Payment of the service fee listed 

in § 250.125 

(b) The Regional Supervisor may 

require the use of an Independent Third 

Party (I3P) according to § 250.230 if the 

system or equipment requires a high 

degree of specialized or technically 

complex engineering knowledge, 

expertise, and experience to evaluate, or 

is not addressed in existing industry 

standards. 

(1) The Regional Supervisor may also 

require you to follow the I3P 

requirements according to § 250.231, as 

applicable, on a case-by-case basis. 

(2) If you have any questions about 

I3P requirements for the New or 

Unusual Technology Conceptual Plan, 

contact the applicable Regional 

Supervisor. 

§ 250.229 What must the New or Unusual 

Technology Barrier Conceptual Plan 

include? 

Your New or Unusual Technology 

Barrier Conceptual Plan must include 

the following information: 

(a) How the New or Unusual 

Technology Barrier Conceptual Plan fits 

within your overall site specific project, 

if applicable. You must include an 

overview of the project development 

concepts and a proposed schedule for 

submittal of associated conceptual 

plans; 

(b) A diagram depicting the primary 

and secondary barriers that includes all 

components, assemblies, or subassemblies, each labeled and 

categorized as a Category 1 barrier or 

Category 2 barrier; 

(c) A list of the primary and 

secondary barriers that includes all 

components, assemblies, or subassemblies specifying each assigned 

barrier as either a Category 1 barrier or 

Category 2 barrier; 

(d) A list of the engineering standards 

that will be used in the equipment’s 

material selection and qualification, 

design verification analysis, and design 

validation testing; 

(e) A list of requested alternate 

procedures or equipment in accordance 

with § 250.141 and requested departures 

in accordance with § 250.142; 

(f) A list of the functional 

requirements (i.e., environmental and 

physical loads (magnitude and 

frequency)) for which the barrier 

equipment is being designed; 

(g) Description of the equipment’s 

safety critical functions, (i.e., function(s) 

performed by or inherent to the 

equipment enabling it to achieve or 

maintain a safe state); 

(h) An I3P nomination, in accordance 

with § 250.230(a); 


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(i) An I3P verification plan that 

includes the following: 

(1) A discussion of the equipment’s 

material selection and qualification; 

(2) A discussion of the equipment’s 

design verification analyses; 

(3) A discussion of the equipment’s 

design validation testing; 

(4) An explanation of why the 

analyses, processes, and procedures 

ensure that the equipment is fit for 

service in the applicable environment; 

and 

(5) Details regarding how the I3P will 

address the additional items listed in 

§ 250.231 

(j) I3P reports as required in 

§ 250.232; 

(k) Payment of the service fee listed in 

§ 250.125; and 

(l) After BSEE receives all of the 

required I3P reports, a certification 

statement that the barrier equipment is 

fit for service in the applicable 

environment (for the specific project 

location). 

§ 250.230 What are your requirements for 

the Independent Third Party (I3P) 

nomination? 

When required by BSEE and in 

accordance with each applicable 

Conceptual Plan, you must: 

(a) Nominate I3P(s) to review the 

design verification and design 

validation documentation of the 

Original Equipment Manufacturer 

(OEM). Your I3P must be a technical 

classification society, a licensed 

professional engineering firm, or a 

registered professional engineer capable 

of providing the required certifications 

and verifications. You must submit your 

I3P nomination(s) to BSEE for approval. 

Your I3P nomination must include the 

following: 

(1) Previous experience in third-party 

verification or experience in the design, 

fabrication, or installation of applicable 

offshore oil and gas equipment. 

(2) Technical capabilities of the 

individual or the primary staff for the 

specific project; 

(3) Size and type of organization or 

corporation; 

(4) In-house availability of, or access 

to, appropriate technology to review the 

specific project. This should include 

computer programs, hardware, and 

testing materials and equipment as 

applicable; 

(5) Ability to perform the I3P 

functions for the specific project 

considering current commitments (e.g., 

project timelines, schedules, and 

personnel availability); and 

(6) Previous experience with BSEE 

requirements and procedures; 

(b) You must ensure that the I3P has 

access to all associated documentation 

and equipment related to items 

§ 250.229(i) to perform the complete 

reviews in accordance with § 250.231, 

including OEM documentation and 

access to the OEM fabrication and 

manufacturing locations. 

§ 250.231 What are the I3P review 

requirements for Conceptual Plan reviews? 

As directed by BSEE, or for all new 

or unusual technology Barrier review for 

Equipment categorized as Category 1 or 

Category 2, the I3P must: 

(a) Review the following information 

regarding the applicable equipment 

and/or system: 

(1) Basis of Design, Technical 

Specification (if known at this point in 

the design process) and Functional 

Requirements (i.e., environmental and 

physical loads (magnitude and 

frequency)). 

(2) Risk assessment and failure mode 

analysis 

(3) Material specification, selection, 

qualification, and testing 

(4) Design verification analysis, 

including: 

(i) Structural/strength analysis and 

(ii) Fatigue assessment and/or 

analysis; 

(5) If fatigue is identified as a 

potential failure mode, as identified in 

the fatigue assessment and/or analysis 

in paragraph (a)(4)(ii) of this section, the 

plan to record and gather data (load 

monitoring) in order to conduct a future 

fatigue analysis; 

(6) Design validation testing; 

(7) Fabrication, quality management 

system, and inspection and test plan 

that identifies the quality control/ 

quality assurance process, and 

inspection of the final products. 

(b) Submit a report to BSEE 

documenting the review of each item 

covered under paragraph (a). Each 

report must clearly identify all OEM and 

operator documents used during the I3P 

review; 

(c) Submit to BSEE a final report 

summarizing each of the review 

requirements covered under paragraph 

(a) of this section, including: 

(1) The equipment and/or system’s 

technical specifications, including a 

certification statement that the 

equipment and/or system is fit for 

purpose for the technical specification 

by the I3P; and 

(2) Verification that the equipment’s 

technical specifications meet or exceed 

the project’s functional requirements, 

including a certification statement that 

the equipment and/or system is fit for 

purpose for the proposed project by the 

I3P. 

(d) For any subsequent I3P review of 

equipment and/or system’s technical 

specification that was previously 

approved in your New or Unusual 

Technology Barrier Conceptual Plan, the 

Regional Supervisor may accept a final 

report in accordance with § 250.231(c), 

including the existing certification 

covered under paragraph (c)(1) of this 

section, in lieu of reports required in 

paragraph (b) of this section. The I3P 

must also submit an updated 

certification statement in accordance 

with § 250.231(c)(2) for the specific 

project. 

§ 250.232 General requirements for any 

I3P Report. 

An I3P report as required in § 250.231 

must be a standalone document that 

clearly summarizes the verification 

work performed and must contain a 

sufficient level of detail (i.e., 

quantitative information) and clarity to 

establish the basis of the I3P’s findings 

and/or recommendation(s). Each report 

must identify the OEM or operator 

documents reviewed, the detailed I3P 

review, and convey the results of the 

I3P’s review without requiring BSEE to 

review of any other referenced 

document. 

§ 250.233–250.234 [Reserved] 

DWOP Approval 

§ 250.235 When and how must I submit the 

DWOP? 

You must submit the DWOP to the 

Regional Supervisor after BSEE has 

approved your project conceptual plan 

and you have substantially completed 

system design, and before you conduct 

post-completion installation activities 

for a deepwater development project, or 

for any project that will involve the use 

of subsea tieback development 

technology in any water depth which 

may include new or unusual technology 

or new or unusual technology barrier 

equipment. You may not begin 

production from the well until BSEE 

approves your DWOP. 

§ 250.236 What information must I submit 

with the DWOP? 

Your DWOP must contain the 

following information, as applicable: 

Information that you must 

include with your DWOP 

Where to 

find the 

description 

(a) General information ............ § 250.237 

(b) Well or completion information ........................................ § 250.238 

(c) Structural information .......... § 250.239 

(d) Production safety system information ............................... § 250.240 

(e) Subsea system and pipeline 

information ............................ § 250.241 


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Information that you must 

include with your DWOP 

Where to 

find the 

description 

(f) New or unusual technology 

information ............................ § 250.242 

§ 250.237 What general information must 

my DWOP include? 

You must include the following 

general information in your DWOP, as 

applicable: 

(a) A list of any alternate compliance 

procedures or equipment or departures 

being requested and a list of any for 

which you anticipate requesting 

approval in any future applicable permit 

or application; 

(b) Payment of the service fee listed in 

§ 250.125; and 

(c) A list of any associated industry 

standards not incorporated in the 

regulations that you are using for your 

project design or operation. 

§ 250.238 What well or completions 

information must my DWOP include? 

You must include the following 

information in your DWOP, as 

applicable, to align with the activities to 

be addressed in the associated well 

permit(s): 

(a) A description and schematic of the 

typical wellbore, casing, and 

completion; 

(b) Information concerning the 

drilling and completion systems; and 

(c) Design and fabrication information 

for each wellbore riser system (e.g., 

drilling, completion, workover, 

intervention, injection, or production) 

deployed from a floating production 

facility or TLP. 

§ 250.239 What structural information 

must my DWOP include? 

You must include the following 

information in your DWOP, as 

applicable, to align with the activities, 

including any major modifications, to be 

addressed in the associated platform 

application: 

(a) Structural design, fabrication, and 

installation information; 

(b) Design, fabrication, installation, 

and monitoring information on the 

tendon, or mooring systems, including 

the turret or buoy system, if applicable; 

and 

(c) Information on any active station 

keeping system(s) involving thrusters or 

other means of propulsion. 

§ 250.240 What Production Safety System 

information must my DWOP include? 

You must include the following 

information in your DWOP, as 

applicable, to align with the activities 

you plan to address in the associated 

production safety system application: 

(a) A general description of the 

operating procedures, including a table 

summarizing the curtailment of 

production and offloading based on 

operational considerations; 

(b) Information about the design, 

fabrication, and operation of an offtake 

system for transferring produced 

hydrocarbons to a transport vessel; 

(c) A description of the process 

facility installation and commissioning 

procedure; 

(d) Safety analysis flow diagram of the 

production system from the SCSSV 

downstream to the first item of 

separation equipment; 

(e) A certification statement that the 

surface and/or subsea safety system and 

emergency support systems will comply 

with Subpart H of this part. You must 

also include: 

(1) Methods, frequency, and 

acceptance criteria for testing the 

Underwater Safety Valves (USVs), 

SCSSVs, and Boarding Shutdown 

Valves (BSDVs); 

(2) The function and testing of the 

host facility Emergency Shutdown 

Device (ESD) system and its interface to 

the subsea system; 

(3) If applicable, a description of the 

surface and/or subsea safety system and 

emergency support systems not covered 

in Subpart H of this part. For systems 

not covered in Subpart H, you must 

request an approval of alternate 

procedures or equipment according to 

§ 250.141, and you must also include a 

table that depicts what valves will close, 

at what times, and for what events or 

reasons; and 

(f) Information on the design, 

operation, maintenance, personnel 

competency, and testing of your subsea 

leak detection system to protect your 

subsea field/infrastructure (e.g., trees, 

manifolds, jumpers). You must include 

procedures for how you will operate the 

system, ensure system functionality, 

identify a leak, and the actions you will 

take when a leak is identified. 

§ 250.241 What subsea systems and 

pipeline information must my DWOP 

include? 

(a) You must include the following 

information common to the subsea 

system and the associated pipeline 

systems, which constitute all or part of 

a single project development covered by 

the DWOP and/or aligns with activities 

addressed in your associated pipeline 

application, as applicable: 

(1) The subsea field schematic 

depicting the planned subsea 

development equipment and 

infrastructure, including wells/trees, 

non-pipe subsea equipment, pipeline 

route(s), pipeline riser systems, 

umbilical(s), and platform footprint; 

(2) Description of the subsea 

development project detailing the 

subsea and pipeline equipment design 

criteria and analysis procedures 

(including industry standards, pressure 

and temperature ratings, materials 

selection), testing methods, and general 

operational procedures; 

(3) Description of the fabrication and 

assembly/testing location of subsea 

trees, pipelines, and non-pipe subsea 

equipment (manifold, Pipeline End 

Manifold (PLEM), Pipeline End 

Termination (PLET), Subsea Umbilical 

Termination Assembly (SUTA), subsea 

pumps, suction piles, etc.); 

(4) Summary of the Integrity 

Management Program for subsea tieback 

development technologies, including a 

plan for inspection and monitoring to 

support assessment of the condition of 

the systems a minimum of once every 

10 years. This should include, but is not 

limited to, the in-service inspections or 

survey of hull and topsides structures, 

tendons, mooring, and pipeline and/or 

wellbore riser systems to assess 

component condition by inspection and 

analysis after each significant 

environmental event (e.g., hurricane, 

earthquake, loop and eddy currents, or 

mudslide) impacting the system, or once 

every 10 years, whichever occurs first; 

and 

(5) Summary of safety and 

environmental controls. 

(b) You must include the following 

information about subsea systems that 

constitute all or part of a single project 

development covered by the DWOP, as 

applicable: 

(1) The system control type (i.e., 

direct hydraulic or electro-hydraulic); 

(2) Well tree(s), wellhead, and nonpipe equipment general arrangement 

drawings and schematics, with size and 

valve type annotations to illustrate the 

tree and other equipment in operation; 

(3) The estimated shut-in tubing 

pressure for the proposed well(s), 

including the calculation used to arrive 

at the estimate, specifying TVD, 

reservoir pressure, and the fluid 

gradient used, or a brief discussion of 

the pressure volume temperature (PVT) 

data used for estimation; 

(4) The wellbore static bottomhole 

temperature and the estimated flowing 

temperature at the tree, including a 

description of the method used to 

calculate this estimate; 

(5) Umbilical(s) and umbilical 

connection(s), including an umbilical 

cross-section schematic; 

(6) Chemical or other injection 

systems and/or enhanced recovery 

systems to be used; 


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(7) Corrosion monitoring and 

prevention/inhibition provisions; 

(8) Details of any re-furbished and/or 

re-certified equipment you plan to use; 

and 

(9) A schedule of development 

activities, including well completion, 

facility installation, and anticipated date 

of first oil. 

(c) You must include the following 

pipeline information in your DWOP, as 

applicable, to align with the activities to 

be addressed in your associated pipeline 

application(s): 

(1) Design and fabrication information 

for each pipeline riser system; 

(2) If you propose to use a pipeline 

free standing hybrid riser (FSHR) on a 

permanent installation that uses a 

buoyancy air can suspended from the 

top of the riser, you must provide the 

following information in your DWOP as 

part of the discussions required by 

paragraphs (b)(1) and (2) of this section: 

(i) A detailed description and 

drawings of the FSHR, buoy, and the 

associated connection system; 

(ii) Detailed information regarding the 

system used to connect the FSHR to the 

buoyancy air can, and associated 

redundancies; and 

(iii) Descriptions of your monitoring 

system and monitoring plan for the 

pipeline FSHR and the associated 

connection system for fatigue, stress, 

and any other abnormal condition (e.g., 

corrosion), that may negatively impact 

the riser system’s integrity; and 

(3) Pipeline and pipeline riser 

installation methods. 

§ 250.242 What new or unusual technology 

information must my DWOP include? 

You must include the following new 

or unusual technology information in 

your DWOP, as applicable: 

(a) A description of any new or 

unusual technology being used in your 

development project, including a 

reference to previously approved New 

or Unusual Technology Conceptual 

Plans or New or Unusual Technology 

Barrier Conceptual Plans. 

(b) A description of any new or 

unusual technology not covered under 

the New or Unusual Technology 

Conceptual Plan or New or Unusual 

Technology Barrier Conceptual Plan. 

You must include the same applicable 

information as required in §§ 250.228 or 

250.229. 

§§ 250.243 and 250.244 [Reserved] 

§ 250.245 May I combine the Conceptual 

Plan and the DWOP? 

If your development project meets the 

following criteria, you may submit a 

combined Conceptual Plan/DWOP that 

complies with all applicable 

requirements for both, on or before the 

deadline for submitting the Conceptual 

Plan, as described in § 250.226: 

(a) The project is similar to projects 

involving subsea tieback development 

technology for which you have obtained 

approval previously, and 

(b) The project does not involve either 

new or unusual technology or a new 

platform. 

§ 250.246 When must I revise my DWOP? 

You must revise either the Conceptual 

Plan or your DWOP to reflect any 

change to the proposed plan or 

procedures that does not involve a 

physical alteration of the equipment on 

the platform or the seabed. 

§ 250.247 When must I supplement my 

DWOP? 

You must supplement your DWOP to 

reflect additions or changes in your 

development project that: 

(a) Physically alter the platform, 

process facilities, equipment, or systems 

approved in your original Conceptual 

Plan or DWOP. If a Supplemental 

DWOP includes the addition of a well 

or wells (e.g., a new subsea field) not 

approved in your original DWOP, you 

may not complete or produce from the 

new well(s) until BSEE approves the 

Supplemental DWOP. 

(b) Involves the addition of any new 

or unusual technology to your project 

that was not previously covered under 

the New or Unusual Technology 

Conceptual Plan, New or Unusual 

Technology Barrier Conceptual Plan, or 

DWOP. You cannot install any new or 

unusual technology until BSEE 

approves the Supplemental DWOP. 

§ 250.248 What information must I include 

in my Supplemental DWOP? 

You must include the following 

information, as applicable, in your 

Supplemental DWOP: 

(a) The same information for your 

wells or equipment as required in the 

applicable Conceptual Plan and DWOP 

requirements in this subpart; 

(b) Information for each applicable 

Conceptual Plan or DWOP section that 

is being impacted by the addition or 

change; and 

(c) Payment of the service fee listed in 

§ 250.125. 

Subpart D—Oil and Gas Drilling 

Operations 

■ 6. Amend § 250.490 by revising the 

introductory text to paragraph (p) to 

read as follows: 

§ 250.490 Hydrogen sulfide. 

* * * * * 

(p) Metallurgical properties of 

equipment. When operating in a zone 

with H2S present or when the 

concentration of H2S in the produced 

fluid may exceed 0.05 psi partial 

pressure of H2S, you must use 

equipment that is constructed of 

materials with metallurgical properties 

that resist or prevent sulfide stress 

cracking (also known as hydrogen 

embrittlement, stress corrosion cracking, 

or H2S embrittlement), chloride-stress 

cracking, hydrogen-induced cracking, 

and other failure modes. You must do 

all of the following: 

* * * * * 

■ 7. Amend § 250.518 by revising 

paragraphs (a), (c), and (d) to read as 

follows: 

§ 250.518 Tubing and wellhead equipment. 

(a) No tubing string can be placed in 

service or continue to be used unless 

such tubing string has the necessary 

strength and pressure integrity and is 

otherwise suitable for its intended use. 

(1) The tubing string must be 

evaluated for burst, collapse, and axial 

loads with appropriate safety and design 

factors for the pressure and temperature 

environments of the completion, 

production, shut-in, and injection load 

cases. 

(2) The tubing string materials must 

be appropriate for the environment. You 

must follow NACE Standard MR0175– 

2003 (as incorporated by reference in 

§ 250.198) when H2S concentration may 

equal or exceed 0.05 psi partial 

pressure. 

(3) The tubing string threaded 

connectors must be appropriate for the 

loads identified in paragraph (a)(1) of 

this section. 

* * * * * 

(c) You must design and test the 

wellhead, tree, and related equipment in 

accordance with ANSI/API Spec. 6A (as 

incorporated by reference in § 250.198) 

or ANSI/API Spec. 17D (as incorporated 

by reference in § 250.198), as applicable. 

The wellhead, tree, and related 

equipment must have a pressure rating 

greater than the maximum anticipated 

surface pressure and must be designed, 

installed, operated, maintained, and 

tested to achieve and maintain pressure 

containment and pressure control. 

(1) Newly completed dry trees (e.g., 

fixed, hybrid, or mudline suspension) 

for production or injection wells must 

be equipped with a minimum of one 

master valve and one surface safety 

valve (SSV), installed above the master 

valve, in the vertical run of the tree. 

(2) Newly completed subsea 

production or injection wells must be 

equipped with a minimum of one 

underwater safety valve (USV) installed 

in the horizontal or vertical run of the 


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29818 Federal Register / Vol. 87, No. 94 / Monday, May 16, 2022 / Proposed Rules 

tree (e.g., vertical or horizontal subsea 

trees). 

(3) Newly completed wells with a 

mudline suspension conversion to a 

subsea tree must have a minimum of 

two casing strings tied back and sealed 

below the tubing head. At a minimum, 

the production casing and the next outer 

casing must be tied back to the 

wellhead, to ensure annular isolation. 

(d) You must install, maintain, and 

test surface and subsurface safety 

equipment in accordance with the 

applicable requirements in Subpart H of 

this part. 

* * * * * 

■ 8. Amend § 250.619 by revising 

paragraphs (a), (c), and (d) to read as 

follows: 

§ 250.619 Tubing and wellhead equipment. 

* * * * * 

(a) No tubing string can be placed in 

service or continue to be used unless 

such tubing string has the necessary 

strength and pressure integrity and is 

otherwise suitable for its intended use. 

(1) The tubing string must be 

evaluated for burst, collapse, and axial 

loads with appropriate safety and design 

factors for the pressure and temperature 

environments of the completion, 

production, shut-in, and injection load 

cases. 

(2) The tubing string materials must 

be appropriate for the environment. You 

must follow NACE Standard MR0175– 

2003 (as incorporated by reference in 

§ 250.198) when H2S concentration may 

equal or exceed 0.05 psi partial pressure 

. 

(3) The tubing string threaded 

connectors must be appropriate for the 

loading identified in paragraph (a)(1) of 

this section. 

* * * * * 

(c) You must design and test the 

wellhead, tree, and related equipment in 

accordance with ANSI/API Spec. 6A (as 

incorporated by reference in § 250.198) 

or ANSI/API Spec. 17D (as incorporated 

by reference in § 250.198), as applicable. 

The wellhead, tree, and related 

equipment must have a pressure rating 

greater than the shut-in tubing pressure 

and must be designed, installed, 

operated, maintained, and tested so as 

to achieve and maintain pressure 

containment and pressure control. 

(1) Dry trees (e.g.., fixed, hybrid, or 

mudline suspension) for production or 

injection wells must be equipped with 

a minimum of one master valve and one 

surface safety valve (SSV), installed 

above the master valve, in the vertical 

run of the tree. 

(2) Subsea production or injection 

wells must be equipped with a 

minimum of one underwater safety 

valve (USV) installed in the horizontal 

or vertical run of the tree (for vertical or 

horizontal subsea trees). 

(3) Wells with a mudline suspension 

conversion to a subsea tree must have a 

minimum of two casing strings tied back 

and sealed below the tubing head. At 

minimum, the production casing and 

the next outer casing must be tied back 

to the wellhead, to ensure annular 

isolation. 

(d) You must install, maintain, and 

test surface and subsurface safety 

equipment in accordance with the 

applicable requirements in Subpart H of 

this part. 

* * * * * 

■ 9. Amend § 250.731 by revising 

paragraph (c)(4) to read as follows: 

§ 250.731 What information must I submit 

for BOP systems and system components? 

You must submit: Including: 

*******

(c) * * * ........................................... (4) If using a subsea BOP, a BOP in an HPHT environment, as defined in § 250.105, or a surface BOP on 

a floating facility, the BOP has not been compromised or damaged from previous service. 

* * * * * * * 

■ 10. Amend § 250.732 by revising 

paragraph (c) to read as follows: 

§ 250.732 What are the independent third 

party requirements for BOP systems and 

system components? 

* * * * * 

(c) Before you begin any operations in 

an HPHT environment, as defined by 

§ 250.105, with the proposed 

equipment, you must include the 

following in your applicable permit: 

(1) The I3P certification required in 

§ 250.731(c); 

(2) A description of any new or 

unusual technology being used; 

(3) A reference to the previously 

approved associated new or unusual 

technology Barrier Conceptual Plan; 

(4) The final report and certification 

statements in accordance with 

§ 250.231(c); and 

(5) The fit-for-service certification 

statement required in § 250.229(l). 

You may not deploy your proposed 

HPHT BOP systems and related 

equipment until BSEE approves the 

New or Unusual Technology Barrier 

Equipment Conceptual Plan and 

appropriate permits (e.g., APD). 

* * * * * 

§ 250.804 [Removed and Reserved] 

■ 11. Remove and reserve § 250.804. 

[FR Doc. 2022–09560 Filed 5–13–22; 8:45 am] 

BILLING CODE 4310–VH–P 


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