[Federal Register Volume 87, Number 94 (Monday, May 16, 2022)]
[Proposed Rules]
[Pages 29790-29818]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2022-09560]
[[Page 29789]]
Vol. 87
Monday,
No. 94
May 16, 2022
Part II
Department of the Interior
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Bureau of Safety and Environmental Enforcement
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30 CFR Part 250
Oil and Gas and Sulfur Operations in the Outer Continental Shelf--High
Pressure High Temperature and Subpart B Revisions; Proposed Rule
Federal Register / Vol. 87 , No. 94 / Monday, May 16, 2022 / Proposed
Rules
[[Page 29790]]
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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.
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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 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 or
for purchase on API's website at: https://publications.api.org and
https://www.api.org/products-and-services/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: [email protected]), 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: [email protected]. Please send a
copy to BSEE at [email protected].
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:
[email protected].
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.
[[Page 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
stand-alone 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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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.
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\1\ BSEE'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.
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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.
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\2\ BSEE'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.
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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
[[Page 29793]]
Woodland Road, Sterling, Virginia 20166 (email: [email protected]), 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 [email protected].
II. Section-by-Section Discussion of Proposed Changes
BSEE is proposing to revise the following regulations:
Subpart A--General
Definitions (Sec. 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 Sec.
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 Sec. 250.804(b)
and is identical to the definition in NTL 2019-G03.
Service Fees (Sec. 250.125)
This rulemaking would revise paragraph (a)(2) of Sec. 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 (Sec. 250.198)
This rulemaking would revise paragraph (e)(82) of Sec. 250.198,
which incorporates ANSI/API Spec. 6A, Specification for Wellhead and
Christmas Tree Equipment, to add new references to Sec. Sec. 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 Sec. Sec. 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 Sec. 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 Sec. 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 Sec. Sec. 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
Sec. Sec. 250.518 and 250.619 and are addressed further in the
section-by-section discussion for these two sections.
This rulemaking would also revise paragraph (i)(1) of Sec.
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 Sec. Sec. 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 Sec. Sec. 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 (Sec. 250.200)
This rulemaking would revise paragraph (a) of Sec. 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 Sec. 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:
[cir] Category 1 Barrier, which would mean any equipment,
component, or
[[Page 29794]]
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
[cir] 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
non-barrier 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
(Sec. 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 ``non-conventional 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? (Sec. 250.201)
This rulemaking would revise existing paragraph (a) of Sec.
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? (Sec.
250.202)
The content of this proposed section would be moved from existing
Sec. 250.204 without revision.
Are there special requirements if my well affects an adjacent property?
(Sec. 250.203)
The content of this proposed section would be moved from existing
Sec. 250.205 without revision.
Requirements for High Pressure High Temperature (HPHT) Barrier
Equipment (Sec. 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 cross-references 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? (Sec. 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 Sec.
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? (Sec. 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?
(Sec. 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? (Sec. 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? (Sec. 250.210)
The content of this proposed section would be moved from Sec.
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?
(Sec. 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 Sec. Sec. 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? (Sec. 250.220)
The content of this proposed section would be moved from Sec.
250.286 and
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would contain the following revisions and additions:
Paragraph (a) of Sec. 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 Sec. Sec. 250.227 through
250.229 would identify the contents of the Conceptual Plans. Proposed
Sec. Sec. 250.236 through 250.242 would identify what the DWOP must
contain.
When must I use the DWOP Process? (Sec. 250.221)
The content of this proposed section would be moved from Sec.
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? (Sec.
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 Sec. 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 Sec. 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
Sec. 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,
Sec. Sec. 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? (Sec.
250.226)
The content of this proposed section would be moved from Sec. Sec.
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 Sec. 250.226 would include content from
Sec. 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 Sec.
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.
[[Page 29797]]
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 Sec. 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? (Sec. 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 Sec. 250.227
would reflect content of existing Sec. 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:
[cir] A well location plat;
[cir] A subsea field schematic depicting the planned development
infrastructure that contains the wells, pipelines, riser systems,
umbilical(s), and facility footprint;
[cir] The surface or subsea tree;
[cir] 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
[cir] 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 Sec. 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? (Sec.
250.228)
Proposed paragraph (a) of Sec. 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 Sec. 250.141 and requested departures in accordance
with Sec. 250.142;
--A certification statement that the technology is fit for service in
the applicable environment for the specific project location; and
[[Page 29798]]
--Payment of the service fee listed in Sec. 250.125.
Proposed paragraph (b) would allow for the Regional Supervisor to
require the use of an I3P according to proposed Sec. 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 Sec. 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? (Sec. 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 sub-assemblies 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 Sec. 250.141 or requested departures in accordance Sec. 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 Sec. 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 Sec. 250.231;
--I3P reports as required in proposed Sec. 250.232; and
--Payment of the service fees listed in Sec. 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? (Sec. 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
Sec. 250.229(i) to perform the complete reviews in accordance with
proposed Sec. 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
[[Page 29799]]
multiple types of equipment covered under all applicable Conceptual
Plans.
What are the I3P review requirements for Conceptual Plan reviews?
(Sec. 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 Sec. 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 Sec. 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., Sec. Sec. 250.914 through 250.918,
250.420, and 250.732). The I3P review process within Sec. 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 (Sec. 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? (Sec. 250.235)
The content of this proposed section would be moved from Sec.
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? (Sec. 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? (Sec. 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 Sec. 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.
[[Page 29800]]
What well or completions information must my DWOP include? (Sec.
250.238)
The content of this proposed section would be moved from current
Sec. 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? (Sec. 250.239)
The content of this proposed section would be moved from current
Sec. 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? (Sec.
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 Sec. 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?
(Sec. 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 Sec. 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 in-service 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;
[[Page 29801]]
--Corrosion monitoring and prevention/inhibition provisions;
--Details of any re-furbished and/or re-certified 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? (Sec.
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 Sec. Sec. 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 Sec. Sec. 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? (Sec. 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 Sec. 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 Sec. 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 Sec. 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? (Sec. 250.246)
The content of this proposed section would be moved from current
Sec. 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? (Sec. 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
[[Page 29802]]
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? (Sec.
250.248)
This proposed section would describe the information that must be
included in the supplement to the DWOP referenced in proposed Sec.
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 Sec. 250.125.
Subpart D--Oil and Gas Drilling Operations
Hydrogen Sulfide (Sec. 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 Sec. Sec. 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 Sec. 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 Well-Completion Operations
Tubing and Wellhead Equipment (Sec. 250.518)
This proposed rule would revise paragraph (a) of Sec. 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 Sec. 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 Sec. 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 Sec. 250.198) or ANSI/API Spec. 17D (as incorporated by
reference in Sec. 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
[[Page 29803]]
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 (Sec. 250.619)
This proposed rule would revise paragraph (a) of Sec. 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 Sec. 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
Sec. 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
Sec. 250.198) or ANSI/API Spec. 17D (as incorporated by reference in
Sec. 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?
(Sec. 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 Sec. 250.105. This revision is
administrative.
What are the independent third party requirements for BOP systems and
system components? (Sec. 250.732)
This rulemaking would revise existing paragraph (c) of Sec.
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.
[[Page 29804]]
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 (Sec. 250.804)
This rulemaking proposes to remove and reserve this section. The
existing requirements from this section would be addressed under
proposed Sec. Sec. 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-by-section discussion
and regulatory text of this proposed rule.
The proposed rule would make changes as outlined in the following
table:
------------------------------------------------------------------------
Proposed rule
Current regulations section 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.
[[Page 29805]]
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
[[Page 29806]]
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 $16.5 million/year revenues.
or other reports).
------------------------------------------------------------------------
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 $]
------------------------------------------------------------------------
Industry
Company size Percent of rulemaking
revenues costs ($)
------------------------------------------------------------------------
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 $]
----------------------------------------------------------------------------------------------------------------
Average
annualized Average annual Cost as percent
Company size Count industry cost per revenue per firm of revenue
firm
----------------------------------------------------------------------------------------------------------------
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
foreign-based enterprises. The increase of cost noted earlier, $2.9
million per year, would not have a significant adverse effect in terms
of this Act.
[[Page 29807]]
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 Sec. 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 non-hour 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 Sec. 250.210 (current Sec. 250.282) is covered
under BOEM's 1010-0151. Accordingly, a new burden for BSEE is being
added.
As discussed in the Section-by-Section 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]
Sec. 250.210--This section would be revised and moved from
existing Sec. 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).
Sec. 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).
Sec. 250.221(b)--This section would be revised and moved from
existing Sec. 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).
Sec. 250.226--This section would be revised and moved from
existing Sec. Sec. 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).
Sec. 250.227--This section would be revised and moved from
existing Sec. 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).
Sec. 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).
Sec. 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).
Sec. 250.230--This section is new and would outline the
requirements for the
[[Page 29808]]
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).
Sec. 250.231(a)--This section is new and would add the required
information that the I3P is to review (+ 16,660 burden hours).
Sec. Sec. 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).
Sec. Sec. 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).
Sec. Sec. 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 Sec. Sec. 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
non-hour costs burden).
Sec. 250.245--This section would be revised and moved from
existing Sec. 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).
Sec. 250.246--This section would be revised and moved from
existing Sec. 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).
Sec. Sec. 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 non-hour 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
rights-of-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
Sec. Sec. 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.
[[Page 29809]]
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
0
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
0
2. Amend Sec. 250.105 by adding definitions for ``BOP systems and
related equipment'' and ``HPHT environment' in alphabetical order to
read as follows:
Sec. 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.
* * * * *
0
3. Amend Sec. 250.125 by revising paragraph (a)(2) to read as follows:
Sec. 250.125 Service fees.
(a) * * *
[[Page 29810]]
------------------------------------------------------------------------
30 CFR
Service--processing of the following Fee amount citation
------------------------------------------------------------------------
* * * * * * *
(2) Deepwater Operations Plan (DWOP)
process:
(i) Project Conceptual Plan......... $2,510 250.226.
(ii) New or Unusual Technology 32,611 250.226.
Conceptual Plan....................
(iii) New or Unusual Technology 71,570 250.226.
Barrier Conceptual Plan............
(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.
* * * * * * *
------------------------------------------------------------------------
0
4. Amend Sec. 250.198 by revising the introductory text and paragraphs
(e)(82), (86), (91), and (i)(1) to read as follows:
Sec. 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: [email protected], 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 Sec. Sec. 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
Sec. Sec. 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 Sec. Sec. 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 Sec. Sec. 250.490, 250.518(a),
250.619(a), and 250.901;
* * * * *
0
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
Sec. 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:
[[Page 29811]]
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 non-barrier 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 Sec.
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.
Sec. 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 Additional
a(n) . . . Before you . . . information
------------------------------------------------------------------------
(1) New or Unusual Technology install the new or Must be approved
Conceptual Plan. unusual technology. before any
associated
application or
permit (e.g.,
pipeline,
platform, APD,
APM) approval.
(2) New or Unusual Technology install the new or (i) Is required
Barrier Conceptual Plan. unusual technology for any project
barrier equipment. 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 Must be approved
installation or well before well
completion activities completion
for a deepwater permit (e.g.,
development project, APM) approval.
or for any project
that will involve the
use of a subsea
tieback development
technology in any
water depth.
(4) Deepwater Operations Plan (i) conduct post- Must include
(DWOP),. completion reference to
installation all applicable,
activities for a previously
deepwater development approved
project, or for any Conceptual
project that will Plans for the
involve the use of a associated
subsea tieback development
development project.
technology in any
water depth, which
may include new or
unusual technology,
or new or unusual
technology barrier
equipment; and.
(ii) initiate
production
activities..
------------------------------------------------------------------------
[[Page 29812]]
(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.
Sec. 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.
Sec. 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.
Sec. 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 Sec. Sec. 250.229 and 250.242.
Sec. 250.205 [Reserved]
Barrier Equipment and Systems
Sec. 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 Sec. 250.801(a)), then it must also meet
the leak test requirements established in Subpart H.
Sec. 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
Sec. 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 Sec. 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.
Sec. 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.
Sec. 250.210 Do I have to conduct post-approval 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.
Sec. 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.,
Sec. Sec. 250.188, 250.730, and 250.803).
[[Page 29813]]
Sec. 250.212-250.219 ]Reserved]
Deepwater Operations Plan (DWOP) Process
Sec. 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 Sec. Sec. 250.236 through 250.242.
Sec. 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.
Sec. 250.222-250.224 [Reserved]
Conceptual Plans
Sec. 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 Sec. 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 Sec. 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 Sec.
250.200 for the definition of primary or secondary barriers).
Sec. 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:
------------------------------------------------------------------------
Where to find the Additional
Conceptual plan type description information
------------------------------------------------------------------------
(a) Project Conceptual Plan... Sec. 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 Sec. 250.228 (1) You may not
Conceptual Plan. 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 Sec.
250.231, as
applicable.
(c) A New or Unusual Sec. 250.229 (1) You must submit a
Technology Barrier Conceptual new or unusual
Plan. 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 Sec.
250.231.
------------------------------------------------------------------------
[[Page 29814]]
Sec. 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 re-
furbished 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 Sec. 250.125.
Sec. 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 fail-safe 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 Sec. 250.141 and request for departures in accordance
with Sec. 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 Sec. 250.125
(b) The Regional Supervisor may require the use of an Independent
Third Party (I3P) according to Sec. 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 Sec. 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.
Sec. 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 sub-assemblies, 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 sub-assemblies 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 Sec. 250.141 and requested departures in accordance
with Sec. 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 Sec. 250.230(a);
[[Page 29815]]
(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 Sec. 250.231
(j) I3P reports as required in Sec. 250.232;
(k) Payment of the service fee listed in Sec. 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).
Sec. 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 Sec. 250.229(i) to
perform the complete reviews in accordance with Sec. 250.231,
including OEM documentation and access to the OEM fabrication and
manufacturing locations.
Sec. 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 Sec. 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 Sec. 250.231(c)(2) for the specific project.
Sec. 250.232 General requirements for any I3P Report.
An I3P report as required in Sec. 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.
Sec. 250.233-250.234 [Reserved]
DWOP Approval
Sec. 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.
Sec. 250.236 What information must I submit with the DWOP?
Your DWOP must contain the following information, as applicable:
------------------------------------------------------------------------
Where to
Information that you must include with your DWOP find the
description
------------------------------------------------------------------------
(a) General information.................................... Sec.
250.237
(b) Well or completion information......................... Sec.
250.238
(c) Structural information................................. Sec.
250.239
(d) Production safety system information................... Sec.
250.240
(e) Subsea system and pipeline information................. Sec.
250.241
[[Page 29816]]
(f) New or unusual technology information.................. Sec.
250.242
------------------------------------------------------------------------
Sec. 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 Sec. 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.
Sec. 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.
Sec. 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.
Sec. 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 Sec.
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.
Sec. 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 non-pipe 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;
[[Page 29817]]
(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.
Sec. 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 Sec. Sec. 250.228 or 250.229.
Sec. Sec. 250.243 and 250.244 [Reserved]
Sec. 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 Sec. 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.
Sec. 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.
Sec. 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.
Sec. 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 Sec. 250.125.
Subpart D--Oil and Gas Drilling Operations
0
6. Amend Sec. 250.490 by revising the introductory text to paragraph
(p) to read as follows:
Sec. 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:
* * * * *
0
7. Amend Sec. 250.518 by revising paragraphs (a), (c), and (d) to read
as follows:
Sec. 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 Sec. 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 Sec. 250.198) or ANSI/API Spec. 17D (as incorporated by
reference in Sec. 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
[[Page 29818]]
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.
* * * * *
0
8. Amend Sec. 250.619 by revising paragraphs (a), (c), and (d) to read
as follows:
Sec. 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 Sec. 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 Sec. 250.198) or ANSI/API Spec. 17D (as incorporated by
reference in Sec. 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.
* * * * *
0
9. Amend Sec. 250.731 by revising paragraph (c)(4) to read as follows:
Sec. 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
Sec. 250.105, or a surface BOP on
a floating facility, the BOP has
not been compromised or damaged
from previous service.
* * * * * * *
------------------------------------------------------------------------
0
10. Amend Sec. 250.732 by revising paragraph (c) to read as follows:
Sec. 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 Sec. 250.105, with the proposed equipment, you must include
the following in your applicable permit:
(1) The I3P certification required in Sec. 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 Sec. 250.231(c); and
(5) The fit-for-service certification statement required in Sec.
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).
* * * * *
Sec. 250.804 [Removed and Reserved]
0
11. Remove and reserve Sec. 250.804.
[FR Doc. 2022-09560 Filed 5-13-22; 8:45 am]
BILLING CODE 4310-VH-P