[Federal Register Volume 76, Number 201 (Tuesday, October 18, 2011)]
[Rules and Regulations]
[Pages 64431-64780]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2011-22675]
[[Page 64431]]
Vol. 76
Tuesday,
No. 201
October 18, 2011
Part II
Department of the Interior
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Bureau of Safety and Environmental Enforcement
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30 CFR Chapter II
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Bureau of Ocean Energy Management
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30 CFR Chapter V
Reorganization of Title 30: Bureaus of Safety and Environmental
Enforcement and Ocean Energy Management; Final Rule
Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 /
Rules and Regulations
[[Page 64432]]
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DEPARTMENT OF THE INTERIOR
Bureau of Safety and Environmental Enforcement
30 CFR Chapter II
Bureau of Ocean Energy Management
30 CFR Chapter V
[Docket ID: BOEM-2011-0070]
RIN 1010-AD79
Reorganization of Title 30: Bureaus of Safety and Environmental
Enforcement and Ocean Energy Management
AGENCY: Bureau of Safety and Environmental Enforcement (BSEE);
Interior, Bureau of Ocean Energy Management (BOEM); Interior.
ACTION: Direct final rule.
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SUMMARY: This rule contains regulations that will be under the
authority of two newly formed Bureaus, the Bureau of Safety and
Environmental Enforcement (BSEE) and the Bureau of Ocean Energy
Management (BOEM), both within the Department of the Interior. On May
19, 2010, the Secretary of the Interior announced the separation of the
responsibilities performed by the Bureau of Ocean Energy Management,
Regulation and Enforcement (BOEMRE) (formerly the Minerals Management
Service) into three new separate organizations: Office of Natural
Resources Revenue (ONRR), Bureau of Ocean Energy Management (BOEM), and
Bureau of Safety and Environmental Enforcement (BSEE). Those
regulations that will apply to the authority of BSEE organization will
remain in 30 CFR chapter II, but be retitled ``Bureau of Safety and
Environmental Enforcement.'' This rule removes from chapter II those
regulations that will apply to the authority of BOEM and recodifies
them into a new 30 CFR chapter V entitled ``Bureau of Ocean Energy
Management.''
DATES: Effective Dates: This rule is effective on October 1, 2011.
FOR FURTHER INFORMATION CONTACT: Kumkum Ray, Regulations and Standards
Branch, (703) 787-1604, e-mail address: kumkum.ray@boemre.gov.
SUPPLEMENTARY INFORMATION:
Background
Order of Events
On May 19, 2010, the Secretary of the Department of the Interior
(Secretary) issued Secretarial Order No. 3299, which announced the
restructuring of the former Minerals Management Service (MMS). The
restructuring divided the responsibilities of the former MMS into three
new bureaus within the Department of the Interior:
(1) Bureau of Ocean Energy Management (BOEM).
(2) Bureau of Safety and Environmental Enforcement (BSEE).
(3) Office of Natural Resources Revenue (ONRR).
On June 18, 2010, the Secretary issued Secretarial Order No. 3302,
which announced the name change of the former MMS to Bureau of Ocean
Energy Management, Regulation and Enforcement (BOEMRE). This name,
BOEMRE, will be in effect until the new organizations are in place
October 1, 2011.
On October 1, 2010, the functions of the former Minerals Revenue
Management (MRM) officially transferred to ONRR, reporting to the
Assistant Secretary for Policy, Management and Budget.
On October 4, 2010, ONRR published a final rule in the Federal
Register (75 FR 61051), moving the regulations related to its royalty
and revenue functions from 30 CFR chapter II to chapter XII.
October 1, 2011 will be the effective date of the separation of the
[remaining components of] BOEMRE into BOEM and BSEE.
Responsibilities
Secretarial Order No. 3299 established the responsibilities for
BOEM, BSEE, and ONRR as follows:
BOEM will be responsible for conventional (e.g., oil and gas) and
renewable energy-related management functions including, but not
limited to, activities involving resource evaluation, planning, and
leasing, environmental science, and environmental analysis.
BSEE will be responsible for safety and environmental enforcement
functions including, but not limited to, the authority to permit
activities, inspect, investigate, summon witnesses and produce
evidence: levy penalties; cancel or suspend activities; and oversee
safety, response and removal preparedness.
ONRR is responsible for royalty and revenue management functions
including, but not limited to, royalty and revenue collection,
distribution, auditing and compliance, investigation and enforcement,
and asset management for both onshore and offshore activities.
Secretarial Order No. 3299 further established that BOEM and BSEE
will be under the supervision of the Assistant Secretary for Land and
Minerals Management (ASLM) and that ONRR will be under the supervision
of the Assistant Secretary for Policy, Management and Budget. This
order also directed the ASLM to ``take appropriate steps to ensure that
this reorganization will provide that agency decisions are made in
compliance with all applicable safety, environmental, and conservation
laws and regulations * * *'' The reorganization of these regulations
supports this directive.
In a January 19, 2011, statement, the Secretary established the
missions and functions of BOEM and BSEE as follows:
BOEM Mission: Responsible for managing development of the
nation's offshore resources in an environmentally and economically
responsible way.
BOEM Functions include: Leasing, Plan Administration,
Environmental Studies, National Environmental Policy Act (NEPA)
Analysis, Resource Evaluation, Economic Analysis, and the Renewable
Energy Program.
BSEE Mission: Enforce safety and environmental
regulations.
BSEE Functions include: All field operations including
Permitting and Research, Inspections, Research, Offshore Regulatory
Programs, Oil Spill Response, and newly formed Training and
Environmental Compliance functions.
Rulemaking Procedure
This rule pertains solely to the organization and codification of
existing rules and related technical changes necessitated by a division
of one agency into two separate agencies. It makes no changes to the
substantive legal rights, obligations, or interests of affected
parties. This rule therefore is a ``rule[] of agency organization,
procedure or practice'' and is therefore exempt from the notice-and-
comment requirements of 5 U.S.C. 553 under 5 U.S.C. 553(b)(A).
Additionally, for the same reasons, BOEMRE finds for good cause shown
that notice and comment on this rule are unnecessary and contrary to
the public interest under 5 U.S.C. 553(b)(B). Because this rule makes
no changes to the legal obligations or rights of non-governmental
entities, the Department further finds that good cause exists under 5
U.S.C. 553(d)(3) to make this rule effective on October 1, 2011, rather
than a full 30 days after publication in the Federal Register.
Proposed Rule
BOEM and BSEE will also jointly issue a proposed rule that will
address some more substantive changes to the regulations. In part, the
proposed rule will address regulatory anomalies created by splitting
the functions of one
[[Page 64433]]
agency into two bureaus. In certain cases, the split necessitated
changing the wording of specific provisions. Rather than changing the
wording in this final rule, we have concluded it is more appropriate to
do so in a proposed rule. The proposed rule changes will be substantial
enough in nature to necessitate public comments and publication of a
Notice of Proposed Rulemaking (NPR).
Reorganization of CFR Title 30
Background Information
This final rule assigns the regulations previously codified under
Title 30 of the Code of Federal Regulations (30 CFR), chapter II--
Minerals Management Service, Department of the Interior, Subchapter A--
Minerals Revenue Management, Subchapter B--Offshore, and Subchapter C--
Appeals; to BSEE, under chapter II and to BOEM, under chapter V. The
assignment of the regulations is based on the responsibilities and
authorities established by Secretarial Order No. 3299, separating BSEE
and BOEM and the January 19, 2011, statement that further clarified
each bureau's mission and functions.
To effectively manage the energy and mineral resources of the Outer
Continental Shelf (OCS), the current regulations must be separated
based on the responsibilities of the new bureaus. Based on the
responsibilities established by Secretarial Order No. 3299, separating
BOEMRE into BOEM and BSEE, this direct final rule reorganizes the
regulations previously found in 30 CFR chapter II by:
1. Retitling chapter II as ``Bureau of Safety and Environmental
Enforcement'';
2. Retaining the regulations that will be under the authority of
BSEE in chapter II;
3. Adding a new chapter, ``Chapter V--Bureau of Ocean Energy
Management''; and
4. Moving the regulations that will be under the authority of BOEM
to 30 CFR chapter V.
In addition to redesignating the regulations to the appropriate
bureau, this rule makes minor supporting edits for clarification,
consistency, or to reiterate current and longstanding practices.
However, the regulatory requirements themselves are not changed. These
edits generally fall under one of the following categories:
Updates to cross-references to reflect the two new sets of
rules, such as:
[cir] Change Sec. 250.101(a) to 550.101(a)),
[cir] Change Sec. 250.123 to 30 CFR 250.123,
[cir] Change ``see Sec. 250.111'' to ``see Sec. 250.111 and 30
CFR 550.111'';
Change references from MMS or BOEMRE to BSEE or BOEM. It
should be understood, however, that references to BSEE or BOEM actions
before October 1, 2011, refer to the predecessor agency (MMS or BOEMRE)
performing the functions specified in the regulations;
Changes in the text to reference new chapter, section, or
title headings;
Correction of spelling or grammatical errors;
Changes of physical and Web site addresses;
Changes of titles, i.e., authorized manager (Regional
Director, Regional Supervisor etc.), and specifying the appropriate
title, based on the bureau (i.e., BSEE Regional Director or BOEM
Regional Director); and/or
Cross-References
This direct final rule is not intended to make any substantive
changes to the regulations or requirements previously set forth in 30
CFR chapter II. In redesignating the regulations, various provisions of
this rule contain cross-references to earlier approvals or other
actions taken under redesignated sections. This rule replaces the
cross-references to previous sections with cross-references to new
sections.
Forms and Information Collection
BOEM and BSEE will rename forms as either BOEM or BSEE forms; MMS
will be removed from the form names. Each form will retain its already
assigned number, except that all numbers will now be four digits. We
will add a zero(s) in front of an existing form number where necessary
(e.g., form MMS-123 will now become form BSEE-0123). The forms
themselves are not changed by this rule.
There are no Information Collection (IC) burden changes in this
rule.
Assignment of Regulations and Explanations
All sections that BSEE retains keep their existing numbers,
reflecting their existing location in 30 CFR chapter II. BOEM citations
are renumbered using the number ``5'' as the first number for the part,
reflecting their new location in 30 CFR chapter V.
The following table (Table A) provides an overview of the
assignment of regulations between BOEM and BSEE, by part. Many parts
are retained in their entirety by BSEE or moved in their entirety to
BOEM. Additional details of how other parts are divided between the two
bureaus follow in Tables B through O.
Table A--Derivation Table
Title 30--Mineral Resources
Chapter II--Bureau of Ocean Energy Management, Regulation and
Enforcement
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Current part New location Justification
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Subchapter A--Minerals Revenue Management
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Part 203--Relief or Reduction Retained in its BSEE will oversee the
in Royalty Rates. entirety in administration of
BSEE, chapter II. royalty relief
awarded after lease
issuance as an
operational
responsibility.
However, BOEM will
set the terms and
conditions of any
future leases issued
with royalty relief
provisions.
Part 219--Distribution and Moved in its BOEM will perform
Disbursement of Royalties, entirety to revenue share
Rentals, and Bonuses. BOEM, chapter V, calculations for
part 519. Outer Continental
Shelf (OCS) receipts
shared under the
Gulf of Mexico
Energy Security Act
(GOMESA). ONRR will
continue to
distribute the
revenue shares to
Gulf producing
States and Coastal
Political
Subdivisions.
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Subchapter B--Offshore
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Part 250--Oil and Gas and Responsibilities Both bureaus have
Sulphur Operations in the divided between responsibilities
Outer Continental Shelf. BOEM and BSEE. that are related to
operations on OCS
leases. These
responsibilities
were divided between
the two bureaus as
detailed in Table B.
[[Page 64434]]
Part 251--Geological and Responsibilities BOEM will be
Geophysical (G&G) divided between responsible for
Explorations of the Outer BOEM and BSEE. issuing the permits
Continental Shelf. and notices and
overseeing the
activities under the
approved permit, as
these are prelease,
resource assessment-
related activities.
BSEE will be
responsible for
issuing permits for
test drilling
activities under
their
responsibilities for
operations. Further
details are provided
in Table C.
Part 252--Outer Continental Both BOEM and Part 252 regulates
Shelf (OCS) Oil and Gas BSEE will have how and when the
Information Program. this part in its date and information
entirety. is released by the
OCS Oil and Gas
Information Program.
Since both bureaus
will collect,
maintain, and use
data and information
collected under this
program, both are
responsible for
managing the data
and determining how
and when the data
and information are
released. Further
details are provided
in Table D.
Part 253--Oil Spill Financial Moved to BOEM in BOEM is responsible
Responsibility for Offshore its entirety, for all activities
Facilities. chapter V, part related to financial
553. assurance. Oil spill
financial
responsibility
requirements are
mandated by the Oil
Pollution Act of
1990 (OPA) that
applies to oil
handling activities
at any offshore
facility (whether or
not involved in oil
production) seaward
of the coastline.
Further details are
provided in Table E.
Part 254--Oil-Spill Response Retained in its All oil-spill related
Requirements for Facilities entirety in BSEE. activities, except
Located Seaward of the Coast for financial
Line. responsibility, will
fall under BSEE,
under its
responsibility for
oil-spill response.
Further details are
provided in Table F.
Part 256--Leasing of Sulphur Responsibilities BOEM has primary
or Oil and Gas in the Outer divided between responsibility for
Continental Shelf. BOEM and BSEE. leasing and leasing-
related activities.
Some
responsibilities
related to
operations and
production will be
in both bureaus.
Suspension-related
requirements will go
to BSEE. Further
details are provided
in Table G.
Part 259--Mineral Leasing: Moved to BOEM in BOEM is responsible
Definitions. its entirety, for leasing
chapter V, part activities. Further
559. details are provided
in Table H.
Part 260--Outer Continental Moved to BOEM in BOEM is responsible
Shelf Oil and Gas Leasing. its entirety, for leasing
chapter V, part activities. Further
560. details are provided
in Table I.
Part 270--Nondiscrimination in Both BOEM and Both BOEM and BSEE
the Outer Continental Shelf. BSEE will have are responsible for
this part in its ensuring that
entirety. lessees and
operators comply
with section 604 of
the OCSLA of 1978,
which provides that
``no person shall,
on the grounds of
race, creed, color,
national origin, or
sex, be excluded
from receiving or
participating in any
activity, sale, or
employment,
conducted pursuant
to the provisions of
. . . the Outer
Continental Shelf
Lands Act.'' Further
details are provided
in Table J.
Part 280--Prospecting for Moved to BOEM in This part regulates
Minerals Other Than Oil, Gas, its entirety, prospecting
and Sulphur on the Outer chapter V, part activities or
Continental Shelf. 580. scientific research
activities on the
OCS in Federal
waters related to
hard minerals on
unleased lands or on
lands under lease to
a third party. These
activities fall
under BOEM
responsibilities for
managing the
development of
offshore resources
and activities on
unleased land or on
lands leased to a
third party. Further
details are provided
in Table K.
Part 281--Leasing of Minerals Moved to BOEM in This part regulates
Other Than Oil, Gas, and its entirety, leasing for minerals
Sulphur in the Outer chapter V, part other than oil, gas,
Continental Shelf. 581. and sulphur in the
OCS. Leasing
activities are a
BOEM responsibility.
Further details are
provided in Table L.
Part 282--Operations in the Responsibilities Both BOEM and BSEE
Outer Continental Shelf for divided between have
Minerals Other Than Oil, Gas, BOEM and BSEE. responsibilities for
and Sulphur. operations conducted
under a mineral
lease for OCS
minerals other than
oil, gas, or
sulphur. These
responsibilities
were divided between
the two bureaus as
detailed in Table M.
Part 285--Renewable Energy and Moved in its At this time, the
Alternate Uses of Existing entirety to renewable energy
Facilities on the Outer BOEM, chapter V, program will be
Continental Shelf. part 585. managed under BOEM.
At a later date, the
renewable energy
program will be
reorganized and a
determination will
be made regarding
what functions will
be administered by
which agency.
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Subchapter C--Appeals
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Part 290--Appeal Procedures... Both BOEM and Appeal procedures
BSEE will have apply to decisions
this part in its and orders issued by
entirety. both BOEM and BSEE.
Further details are
provided in Table O.
Part 291--Open and Retained in its This part deals with
Nondiscriminatory Access to entirety in BSEE. access to pipelines.
Oil and Gas Pipelines under All aspects of
the Outer Continental Shelf pipelines, including
Lands Act. operations are under
the responsibility
of BSEE. Further
details are provided
in Table P.
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[[Page 64435]]
The reorganization of the individual parts and subparts is as
follows:
Subchapter A--Minerals Revenue Management
Part 203--Relief or Reduction in Royalty Rates--Retained in Its
Entirety in BSEE, Chapter II
BSEE is responsible for the regulatory oversight of need-based
royalty relief awarded after lease issuance and the tracking of all
royalty-free production.
Part 219--Distribution and Disbursement of Royalties, Rentals, and
Bonuses--Moved in Its Entirety to BOEM, Chapter V, Part 519
BOEM will perform revenue share calculations for OCS receipts
shared under GOMESA.
Subchapter B--Offshore
Part 250--Oil and Gas and Sulphur Operations in the Outer Continental
Shelf
Part 250 established the requirements for offshore oil, natural
gas, and sulphur operations. These operations include activities after
the lease is established. Most of current Part 250 will stay under
BSEE, with some sections going to BOEM. The details of this division
are as follows.
Table B--Detailed Table for Part 250
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Implementing
Current citation and BSEE bureau and BOEM
citation (if applicable) citation (if Explanation
applicable)
------------------------------------------------------------------------
Subpart A--General
This subpart establishes the basic regulations for oil, gas, and sulphur
exploration, development, and production operations in the OCS. Many of
the requirements in this subpart represent joint responsibilities;
therefore, they belong in both bureaus. Other requirements are the sole
responsibility of one bureau.
------------------------------------------------------------------------
Sec. 250.101 Authority and Both BSEE and Establishes authority
applicability. BOEM, Sec. for the entire part,
550.101. allowing both
bureaus to have some
authority for
operations in the
OCS and both bureaus
need to establish
their authority.
This section also
establishes the
basic requirements
for OCS oil, gas,
and sulphur
operations.
Sec. 250.102 What does this Both BSEE and This section
part do?. BOEM, Sec. describes the
550.102. purpose of these
regulations (parts
250 and 550) and
provides a reference
table addressing
where to find
information for
conducting OCS
operations; it is
applicable to the
regulations in both
bureaus.
Sec. 250.103 Where can I Both BSEE and This section
find more information about BOEM, Sec. establishes the
the requirements in this 550.103. authority for the
part? bureaus to issue
additional guidance
to lessees and
operators, in the
form of Notices to
Lessees and
Operators (NTLs),
and establishes the
expectation of the
lessees and
operators to respond
to that guidance.
Sec. 250.104 How may I Both BSEE and This section explains
appeal a decision made under BOEM, Sec. how a lessee or
MMS regulations? 550.104. operator may appeal
a decision made by
either BSEE or BOEM,
it is informational
and important to
include in both sets
of regulations.
Sec. 250.105 Definitions.... Both BSEE and This section contains
BOEM, Sec. the definitions used
550.105. in parts 250 and
550, the same
definitions will
apply to both sets
of regulations.
Sec. 250.106 What standards Retained by BSEE. This section defines
will the Director use to the standards for
regulate lease operations? performance that
BSEE will use to
regulate lease
operations, these
operations fall
under the authority
of BSEE.
Sec. 250.107 What must I do Retained by BSEE. This section
to protect health, safety, establishes the
property, and the expectations for
environment? operators to protect
health, safety, and
the environment,
these
responsibilities
fall under the
authority of BSEE.
Sec. 250.108 What Retained by BSEE. Addresses cranes and
requirements must I follow other material-
for cranes and other material- handling equipment,
handling equipment? which is related to
an offshore
operation that is
under the authority
of BSEE.
Sec. 250.109 What documents Retained by BSEE. These sections
must I prepare and maintain address welding
related to welding? requirements, which
are related to
offshore operations
that are under the
authority of BSEE.
Sec. 250.110 What must I
include in my welding plan?
Sec. 250.111 Who oversees
operations under my welding
plan?
Sec. 250.112 What standards
must my welding equipment
meet?
Sec. 250.113 What procedures
must I follow when welding?
Sec. 250.114 How must I Retained by BSEE. Addresses the
install and operate installation and
electrical equipment? operation of
electrical
equipment, which are
related to offshore
operations that are
under the authority
of BSEE.
Sec. 250.115 How do I Moved to BOEM, Addresses well
determine well producibility? Sec. Sec. producibility that
550.115, is under the
550.116, and authority of BOEM.
550.117.
Sec. 250.116 How do I
determine producibility if my
well is in the Gulf of
Mexico?
Sec. 250.117 How does a
determination of well
producibility affect royalty
status?
Sec. 250.118 Will MMS Retained by BSEE. Addresses gas
approve gas injection? injection operations
that are under the
authority of BSEE.
[[Page 64436]]
Sec. 250.119 Will MMS Moved to BOEM, Addresses subsurface
approve subsurface gas Sec. 550.119. gas storage that is
storage? under the authority
of BOEM.
Sec. 250.120 How does Retained by BSE.. These pertain to gas
injecting, storing, or storage operations
treating gas affect my that are under the
royalty payments? authority of BSEE.
Sec. 250.121 What happens
when the reservoir contains
both original gas in place
and injected gas?
Sec. 250.122 What effect Both BSEE and This section
does subsurface storage have BOEM Sec. clarifies that an
on the lease term? 550.122. approved storage
project has no
effect on lease
term.
Sec. 250.123 Will MMS allow Moved to BOEM, This section allows
gas storage on unleased Sec. 550.123. gas storage on
lands? unleased lands,
through a right-of-
use and easement
(RUE). RUEs are
issued by BOEM,
under their
responsibility for
resource management.
Sec. 250.124 Will MMS Retained by BSEE. This section
approve gas injection into addresses gas
the cap rock containing a injection
sulphur deposit? operations.
Offshore operations
are under the
authority of BSEE.
Sec. 250.125 Service fees... Both BSEE and Both BSEE and BOEM
BOEM, Sec. will oversee
550.125. activities that
require collection
of a service fee.
Sec. 250.126 Electronic Both BSEE and Provides information
payment instructions. BOEM, Sec. on how to pay the
550.126. fees collected by
BSEE and BOEM.
Sec. 250.130 Why does MMS Retained by BSEE. BSEE will be
conduct inspections? responsible for
issuing permits and
notices and
inspecting the
operations under
approved leases,
plans, and permit.
Sec. 250.131 Will MMS notify Retained by BSEE. BSEE will be
me before conducting an responsible for
inspection? inspecting
operations and
activities on the
OCS.
Sec. 250.132 What must I do
when MMS conducts an
inspection?
Sec. 250.133 Will MMS
reimburse me for my expenses
related to inspections?
Sec. 250.135 What will MMS Both BSEE and BSEE is responsible
do if my operating BOEM, Sec. Sec. for finding operator
performance is unacceptable? 550.135 and performance
550.136. unacceptable under
the criteria of Sec.
550.136, but the
final adjudication
is a BOEM action.
Sec. 250.136 How will MMS
determine if my operating
performance is unacceptable?
Sec. 250.140 When will I Both BSEE and Both BSEE and BOEM
receive an oral approval? BOEM, Sec. may grant verbal
550.140, except approvals for
for paragraph activities and
(c), which will operations under
remain with BSEE their respective
only. authorities.
Paragraph (c)
addresses oral
approvals for gas
flaring that will be
regulated only by
BSEE.
Sec. 250.141 May I ever use Both BSEE and This section explains
alternate procedures or BOEM, Sec. how a lessee or
equipment? 550.141. operator may request
to use alternate
procedures or
equipment that is
not addressed in
current regulations.
It is informational
and important to
include in both sets
of regulations.
Sec. 250.142 How do I Both BSEE and This section provides
receive approval for BOEM, Sec. information on how a
departures? 550.142. lessee or operator
can request a
departure from the
applicable BSEE or
BOEM regulations.
BSEE and BOEM may
grant departures for
activities and
operations under the
respective
authorities.
Sec. 250.143 How do I Moved to BOEM, This section
designate an operator? Sec. 550.143. addresses the
designation of an
operator that is
under the authority
of BOEM.
Sec. 250.144 How do I Moved to BOEM, This section
designate a new operator when Sec. 550.144. addresses the
a designation of operator designation of an
terminates? operator that is
under the authority
of BOEM.
Sec. 250.145 How do I Both BSEE and This section
designate an agent or a local BOEM, Sec. addresses the
agent? 550.145. designation of an
agent that is under
the authority of
both BSEE and BOEM.
Sec. 250.146 Who is Both BSEE and This section provides
responsible for fulfilling BOEM, Sec. information on who
leasehold obligations? 550.146. is responsible for
fulfilling leasehold
obligations. These
activities are
conducted under the
authority of both
BSEE and BOEM.
Sec. 250.150 How do I name Retained by BSEE. This section provides
facilities and wells in the information on
Gulf of Mexico Region? naming facilities
and wells in the
Gulf of Mexico
region that is under
the authority of
BSEE.
Sec. 250.151 How do I name Retained by BSEE. This section provides
facilities in the Pacific information on
Region? naming facilities
and wells in the
Pacific region that
are under the
authority of BSEE.
Sec. 250.152 How do I name Retained by BSEE. This section provides
facilities in the Alaska information on
Region? naming facilities
and wells in the
Alaska region that
are under the
authority of BSEE.
Sec. 250.153 Do I have to Retained by BSEE. This section provides
rename an existing facility information on
or well? renaming existing
facilities and wells
that are under the
authority of BSEE.
Sec. 250.154 What Retained by BSEE. This section provides
identification signs must I information on the
display? required
identification signs
that must be
displayed that are
under the authority
of BSEE.
[[Page 64437]]
Sec. 250.160 When will MMS Moved to BOEM, This section provides
grant me a right-of-use and Sec. 550.160. information on the
easement, and what requirements that
requirements must I meet? must be met to
obtain a RUE. RUEs
are issued by BOEM
under their
responsibility for
resource management.
Sec. 250.161 What else must Moved to BOEM, This section provides
I submit with my application? Sec. 550.161. information on
additional
requirements that
must be contained in
the RUE application.
RUEs are issued by
BOEM under their
responsibility for
resource management.
Sec. 250.162 May I continue Moved to BOEM, This section provides
my right-of-use and easement Sec. 550.162. information on RUEs
after the termination of any that are issued by
lease on which it is BOEM under their
situated? responsibility for
resource management.
Sec. 250.163 If I have a Moved to BOEM, This section concerns
State lease, will MMS grant Sec. 550.163. RUEs that are issued
me a right-of-use and by BOEM under their
easement? responsibility for
resource management.
Sec. 250.164 If I have a Moved to BOEM, This section provides
State lease, what conditions Sec. 550.164. information on RUEs
apply for a right-of-use and that are issued by
easement? BOEM under their
responsibility for
resource management.
Sec. 250.165 If I have a Moved to BOEM, This section provides
State lease, what fees do I Sec. 550.165. information on RUEs
have to pay for a right-of- that are issued by
use and easement? BOEM under their
responsibility for
resource management.
Sec. 250.166 If I have a Moved to BOEM, This section provides
State lease, what surety bond Sec. 550.166. information on RUEs
must I have for a right-of- that are issued by
use and easement? BOEM under their
responsibility for
resource management.
Sec. 250.168 May operations Retained by BSEE. These sections
or production be suspended? address suspension
of operations or
production. Offshore
operations are under
the authority of
BSEE.
Sec. 250.169 What effect
does suspension have on my
lease?
Sec. 250.170 How long does a
suspension last?
Sec. 250.171 How do I
request a suspension?
Sec. 250.172 When may the Retained by BSEE. These sections
Regional Supervisor grant or address suspension
direct an SOO or SOP? of operations or
production. Offshore
operations are under
the authority of
BSEE.
Sec. 250.173 When may the Retained by BSEE.
Regional Supervisor direct an
SOO or SOP?
Sec. 250.174 When may the Retained by BSEE.
Regional Supervisor grant or
direct an SOP?
Sec. 250.175 When may the Retained by BSEE. This section
Regional Supervisor grant an addresses suspension
SOO? of operations.
Offshore operations
are under the
authority of BSEE.
Sec. 250.176 Does a Retained by BSEE. These sections
suspension affect my royalty address suspension
payment? of operations or
production. Offshore
operations are under
the authority of
BSEE.
Sec. 250.177 What additional
requirements may the Regional
Supervisor order for a
suspension?
Sec. 250.180 What am I Retained by BSEE. This section
required to do to keep my addresses
lease term in effect? requirements for
keeping a lease term
in effect. BSEE will
determine if a lease
meets these
requirements.
Sec. 250.181 When may the Moved to BOEM, This section
Secretary cancel my lease and Sec. 550.181. addresses lease
when am I compensated for cancellations.
cancellation? Offshore lease
administration is
under the authority
of BOEM. Past the
primary lease term,
BSEE has greater
authority over lease
extensions via
operations or
suspensions; BOEM
continues its lease
administration
function.
Sec. 250.182 When may the Moved to BOEM, This section
Secretary cancel a lease at Sec. 550.182. addresses lease
the exploration stage? cancellations.
Offshore lease
administration,
including lease
terms, is under the
authority of BOEM.
Past the primary
lease term, BSEE has
greater authority
over lease
extensions via
operations or
suspensions; BOEM
continues its lease
administration
function.
Sec. 250.183 When may MMS or Moved to BOEM, This section
the Secretary extend or Sec. 550.183. addresses lease
cancel a lease at the cancellations.
development and production Offshore lease
stage? administration, is
under the authority
of BOEM. Past the
primary lease term,
BSEE has greater
authority over lease
extensions via
operations or
suspensions; BOEM
continues its lease
administration
function.
Sec. 250.184 What is the Moved to BOEM, This section
amount of compensation for Sec. 550.184. addresses lease
lease cancellation? cancellations.
Offshore lease
administration,
including lease
terms, is under the
authority of BOEM.
Sec. 250.185 When is there Moved to BOEM, This section
no compensation for a lease Sec. 550.185. addresses lease
cancellation? cancellations.
Offshore lease
administration,
including lease
terms, is under the
authority of BOEM.
[[Page 64438]]
Sec. 250.186 What reporting Both BSEE and This section provides
information and report forms BOEM, Sec. information
must I submit? 550.186. concerning reporting
requirements and
form submission This
information is
applicable to both
BSEE and BOEM
activities.
Sec. 250.187 What are MMS' Retained by BSEE. This section
incident reporting addresses incident
requirements? reporting
requirements for
offshore operations
that are under the
authority of BSEE.
Sec. 250.188 What incidents Retained by BSEE. This section
must I report to MMS and when addresses incident
must I report them? reporting
requirements for
offshore operations
that are under the
authority of BSEE.
Sec. 250.189 Reporting Retained by BSEE. This section
requirements for incidents addresses incident
requiring immediate reporting
notification. requirements for
offshore operations
that are under the
authority of BSEE.
Sec. 250.190 Reporting Retained by BSEE. This section
requirements for incidents addresses incident
requiring written reporting
notification. requirements for
offshore operations
that are under the
authority of BSEE.
Sec. 250.191 How does MMS Retained by BSEE. This section
conduct incident addresses incident
investigations? investigations for
offshore operations
that are under the
authority of BSEE.
Sec. 250.192 What reports Retained by BSEE. This section requires
and statistics must I submit operators to submit
relating to a hurricane, information relating
earthquake, or other natural to the impact of
occurrence? hurricanes on on-
going offshore
operations, which
are under the
authority of BSEE.
Sec. 250.193 Reports and Retained by BSEE. This section
investigations of apparent addresses incident
violations. reporting
requirements for
offshore operations
that are under the
authority of BSEE.
Sec. 250.194 How must I Moved to BOEM, BOEM is responsible
protect archaeological paragraph (c) for plans. Paragraph
resources? retained by BSEE (c) directs
and also in BOEM operators to report
with cross to BSEE any
reference. archaeological
resource discovered
while conducting
operations in a
lease or right-of-
way area.
Sec. 250.195 What Retained by BSEE. This section
notification does MMS require addresses the
on the production status of production status of
wells? wells. This
information is
required to
determine when a
well begins to
actively produce.
BSEE will oversee
this function under
their responsibility
for offshore
operations.
Sec. 250.196 Reimbursements Both BSEE and Data and information
for reproduction and BOEM, Sec. may be requested by
processing costs. 550.196. either BSEE or BOEM.
Sec. 250.197 Data and BOEM--Introductor Both BSEE and BOEM
information to be made y paragraph and will collect and be
available to the public or paragraphs responsible for
for limited inspection. (a)(6), (9), various types of
(10), (b), information. This
(c)(4), (5), and section describes
(6). when the information
collected will be
made available to
the public and what
data and information
will be made
available for
limited inspection.
The section was
divided based on the
type of data and
information
addressed in each
paragraph.
BSEE--Introductor
y paragraph and
paragraphs
(a)(1) through
(5), (7), (8),
(b), (c)(1)
through (5) and
(7) retained in
BSEE.
Sec. 250.198 Documents Retained by BSEE. This section
incorporated by reference. addresses documents
incorporated by
reference and
pertains to both
BSEE and BOEM
activities--e.g.
Renewable Energy in
BOEM.
Sec. 250.199 Paperwork Both BSEE and This section
Reduction Act statements-- BOEM, Sec. addresses the
information collection. 550.199. Paperwork Reduction
Act that is
applicable to both
BSEE and BOEM.
------------------------------------------------------------------------
Subpart B--Plans and Information
The plans function, which includes approving Exploration Plans and
Development and Production Plans, falls under the jurisdiction of BOEM,
under its authority to manage development of the Nation's offshore
resources in an environmentally and economically responsible way.
Therefore, most of Subpart B is being moved to BOEM. BSEE is
responsible for Deepwater Operations Plans (DWOPs).
------------------------------------------------------------------------
Sec. 250.200 Definitions.... Both BSEE and Definitions section,
BOEM, Sec. the same definitions
550.200. apply to both
bureaus.
Sec. 250.201 What plans and Both BSEE and This section
information must I submit BOEM, Sec. addresses plans that
before I conduct any 550.201. are the
activities on my lease or responsibility of
unit? BOEM. BSEE is
responsible for
DWOPs.
Sec. 250.202 What criteria Moved to BOEM, This section
must the Exploration Plan Sec. 550.202. addresses plans that
(EP), Development and are the
Production Plan (DPP), or responsibility of
Development Operations BOEM.
Coordination Document (DOCD)
meet?
Sec. 250.203 Where can wells Moved to BOEM, This section
be located under an EP, DPP, Sec. 550.203. addresses plans that
or DOCD? are the
responsibility of
BOEM.
[[Page 64439]]
Sec. 250.204 How must I Retained by BSEE. This section
protect the rights of the describes the
Federal Government? responsibilities of
the operator to
protect the rights
of the Federal
Government while
conducting
operations on their
lease or units. BSEE
will be responsible
for offshore
operations and
ensuring operators
fulfill these
obligations.
Sec. 250.205 Are there Retained by BSEE. This section
special requirements if my describes the
well affects an adjacent measures operators
property? must take to protect
the rights of
adjacent lessees
during offshore
operations. Offshore
operations are under
the authority of
BSEE.
Sec. 250.206 How do I submit Moved to BOEM, This section
the EP, DPP, or DOCD? Sec. 550.206. addresses plans that
are the
responsibility of
BOEM.
Sec. 250.207 What ancillary Moved to BOEM, This section is under
activities may I conduct? Sec. 550.207. the responsibility
of BOEM.
Sec. 250.208 If I conduct Moved to BOEM, This section is under
ancillary activities, what Sec. 550.208. the responsibility
notices must I provide? of BOEM.
Sec. 250.209 What is the MMS Moved to BOEM, This section is under
review process for the Sec. 550.209. the responsibility
notice? of BOEM.
Sec. 250.210 If I conduct Moved to BOEM, This section is under
ancillary activities, what Sec. 550.210. the responsibility
reporting and data/ of BOEM.
information retention
requirements must I satisfy?
Sec. 250.211 What must the Moved to BOEM, This section
EP include? Sec. 550.211. addresses plans that
are the
responsibility of
BOEM.
Sec. 250.212 What Moved to BOEM, This section
information must accompany Sec. 550.212. addresses plans that
the EP? are the
responsibility of
BOEM.
Sec. 250.213 What general Moved to BOEM, This section
information must accompany Sec. 550.213. addresses plans that
the EP? are the
responsibility of
BOEM.
Sec. 250.214 What geological Moved to BOEM, This section
and geophysical (G&G) Sec. 550.214. addresses plans that
information must accompany are the
the EP? responsibility of
BOEM.
Sec. 250.215 What hydrogen Moved to BOEM, This section
sulfide (H2S) information Sec. 550.215. addresses plans that
must accompany the EP? are the
responsibility of
BOEM.
Sec. 250.216 What Moved to BOEM, This section
biological, physical, and Sec. 550.216. addresses plans that
socioeconomic information are the
must accompany the EP? responsibility of
BOEM.
Sec. 250.217 What solid and Moved to BOEM, This section
liquid wastes and discharges Sec. 550.217. addresses plans that
information and cooling water are the
intake information must responsibility of
accompany the EP? BOEM.
Sec. 250.218 What air Moved to BOEM, This section
emissions information must Sec. 550.218. addresses plans that
accompany the EP? are the
responsibility of
BOEM.
Sec. 250.219 What oil and Moved to BOEM, This section
hazardous substance spills Sec. 550.219. addresses plans that
information must accompany are the
the EP? responsibility of
BOEM.
Sec. 250.220 If I propose Moved to BOEM, This section
activities in the Alaska OCS Sec. 550.220. addresses plans that
Region, what planning are the
information must accompany responsibility of
the EP? BOEM.
Sec. 250.221 What Moved to BOEM, This section
environmental monitoring Sec. 550.221. addresses plans that
information must accompany are the
the EP? responsibility of
BOEM.
Sec. 250.222 What lease Moved to BOEM, This section
stipulations information must Sec. 550.222. addresses plans that
accompany the EP? are the
responsibility of
BOEM.
Sec. 250.223 What mitigation Moved to BOEM, This section
measures information must Sec. 550.223. addresses plans that
accompany the EP? are the
responsibility of
BOEM.
Sec. 250.224 What Moved to BOEM, This section
information on support Sec. 550.224. addresses plans that
vessels, offshore vehicles, are the
and aircraft you will use responsibility of
must accompany the EP? BOEM.
Sec. 250.225 What Moved to BOEM, This section
information on the onshore Sec. 550.225. addresses plans that
support facilities you will are the
use must accompany the EP? responsibility of
BOEM.
Sec. 250.226 What Coastal Moved to BOEM, This section
Zone Management Act (CZMA) Sec. 550.226. addresses plans that
information must accompany are the
the EP? responsibility of
BOEM.
[[Page 64440]]
Sec. 250.227 What Moved to BOEM, This section
environmental impact analysis Sec. 550.227. addresses plans that
(EIA) information must are the
accompany the EP? responsibility of
BOEM.
Sec. 250.228 What Moved to BOEM, This section
administrative information Sec. 550.228. addresses plans that
must accompany the EP? are the
responsibility of
BOEM.
Sec. 250.231 After receiving Moved to BOEM, This section
the EP, what will MMS do? Sec. 550.231. addresses plans that
are the
responsibility of
BOEM.
Sec. 250.232 What actions Moved to BOEM, This section
will MMS take after the EP is Sec. 550.232. addresses plans that
deemed submitted? are the
responsibility of
BOEM.
Sec. 250.233 What decisions Moved to BOEM, This section
will MMS make on the EP and Sec. 550.233. addresses plans that
within what timeframe? are the
responsibility of
BOEM.
Sec. 250.234 How do I submit Moved to BOEM, This section
a modified EP or resubmit a Sec. 550.234. addresses plans that
disapproved EP, and when will are the
MMS make a decision? responsibility of
BOEM.
Sec. 250.235 If a State Moved to BOEM, This section
objects to the EP's coastal Sec. 550.235. addresses plans that
zone consistency are the
certification, what can I do? responsibility of
BOEM.
Sec. 250.241 What must the Moved to BOEM, This section
DPP or DOCD include? Sec. 550.241. addresses plans that
are the
responsibility of
BOEM.
Sec. 250.242 What Moved to BOEM, This section
information must accompany Sec. 550.242. addresses plans that
the DPP or DOCD? are the
responsibility of
BOEM.
Sec. 250.243 What general Moved to BOEM, This section
information must accompany Sec. 550.243. addresses plans that
the DPP or DOCD? are the
responsibility of
BOEM.
Sec. 250.244 What geological Moved to BOEM, This section
and geophysical (G&G) Sec. 550.244. addresses plans that
information must accompany are the
the DPP or DOCD? responsibility of
BOEM.
Sec. 250.245 What hydrogen Moved to BOEM, This section
sulfide (H2S) information Sec. 550.245. addresses plans that
must accompany the DPP or are the
DOCD? responsibility of
BOEM.
Sec. 250.246 What mineral Moved to BOEM, This section
resource conservation Sec. 550.246. addresses plans that
information must accompany are the
the DPP or DOCD? responsibility of
BOEM.
Sec. 250.247 What Moved to BOEM, This section
biological, physical, and Sec. 550.247. addresses plans that
socioeconomic information are the
must accompany the DPP or responsibility of
DOCD? BOEM.
Sec. 250.248 What solid and Moved to BOEM, This section
liquid wastes and discharges Sec. 550.248. addresses plans that
information and cooling water are the
intake information must responsibility of
accompany the DPP or DOCD? BOEM.
Sec. 250.249 What air Moved to BOEM, This section
emissions information must Sec. 550.249. addresses plans that
accompany the DPP or DOCD? are the
responsibility of
BOEM.
Sec. 250.250 What oil and Moved to BOEM, This section
hazardous substance spills Sec. 550.250. addresses plans that
information must accompany are the
the DPP or DOCD? responsibility of
BOEM.
Sec. 250.251 If I propose Moved to BOEM, This section
activities in the Alaska OCS Sec. 550.251. addresses plans that
Region, what planning are the
information must accompany responsibility of
the DPP? BOEM.
Sec. 250.252 What Moved to BOEM, This section
environmental monitoring Sec. 550.252. addresses plans that
information must accompany are the
the DPP or DOCD? responsibility of
BOEM.
Sec. 250.253 What lease Moved to BOEM, This section
stipulations information must Sec. 550.253. addresses plans that
accompany the DPP or DOCD? are the
responsibility of
BOEM.
Sec. 250.254 What mitigation Moved to BOEM, This section
measures information must Sec. 550.254. addresses plans that
accompany the DPP or DOCD? are the
responsibility of
BOEM.
Sec. 250.255 What Moved to BOEM, This section
decommissioning information Sec. 550.255. addresses plans that
must accompany the DPP or are the
DOCD? responsibility of
BOEM.
[[Page 64441]]
Sec. 250.256 What related Moved to BOEM, This section
facilities and operations Sec. 550.256. addresses plans that
information must accompany are the
the DPP or DOCD? responsibility of
BOEM.
Sec. 250.257 What Moved to BOEM, This section
information on the support Sec. 550.257. addresses plans that
vessels, offshore vehicles, are the
and aircraft you will use responsibility of
must accompany the DPP or BOEM.
DOCD?
Sec. 250.258 What Moved to BOEM, This section
information on the onshore Sec. 550.258. addresses plans that
support facilities you will are the
use must accompany the DPP or responsibility of
DOCD? BOEM.
Sec. 250.259 What sulphur Moved to BOEM, This section
operations information must Sec. 550.259. addresses plans that
accompany the DPP or DOCD? are the
responsibility of
BOEM.
Sec. 250.260 What Coastal Moved to BOEM, This section
Zone Management Act (CZMA) Sec. 550.260. addresses plans that
information must accompany are the
the DPP or DOCD? responsibility of
BOEM.
Sec. 250.261 What Moved to BOEM, This section
environmental impact analysis Sec. 550.261. addresses plans that
(EIA) information must are the
accompany the DPP or DOCD? responsibility of
BOEM.
Sec. 250.262 What Moved to BOEM, This section
administrative information Sec. 550.262. addresses plans that
must accompany the DPP or are the
DOCD? responsibility of
BOEM.
Sec. 250.266 After receiving Moved to BOEM, This section
the DPP or DOCD, what will Sec. 550.266. addresses plans that
MMS do? are the
responsibility of
BOEM.
Sec. 250.267 What actions Moved to BOEM, This section
will MMS take after the DPP Sec. 550.267. addresses plans that
or DOCD is deemed submitted? are the
responsibility of
BOEM.
Sec. 250.268 How does MMS Moved to BOEM, This section
respond to recommendations? Sec. 550.268. addresses plans that
are the
responsibility of
BOEM.
Sec. 250.269 How will MMS Moved to BOEM, This section
evaluate the environmental Sec. 550.269. addresses plans that
impacts of the DPP or DOCD? are the
responsibility of
BOEM.
Sec. 250.270 What decisions Moved to BOEM, This section
will MMS make on the DPP or Sec. 550.270. addresses plans that
DOCD and within what are the
timeframe? responsibility of
BOEM.
Sec. 250.271 For what Moved to BOEM, This section
reasons will MMS disapprove Sec. 550.271. addresses plans that
the DPP or DOCD? are the
responsibility of
BOEM.
Sec. 250.272 If a State Moved to BOEM, This section
objects to the DPP's or Sec. 550.272. addresses plans that
DOCD's coastal zone are the
consistency certification, responsibility of
what can I do? BOEM.
Sec. 250.273 How do I submit Moved to BOEM, This section
a modified DPP or DOCD or Sec. 550.273. addresses plans that
resubmit a disapproved DPP or are the
DOCD? responsibility of
BOEM.
Sec. 250.280 How must I Moved to BOEM, This section
conduct activities under the Sec. 550.280. addresses plans that
approved EP, DPP, or DOCD? are the
responsibility of
BOEM.
Sec. 250.281 What must I do Moved to BOEM, This section
to conduct activities under Sec. 550.281. addresses plans that
the approved EP, DPP, or are the
DOCD? responsibility of
BOEM.
Sec. 250.282 Do I have to Both BSEE and Both BOEM and BSEE
conduct post-approval BOEM, Sec. will have oversight
monitoring? 550.282. functions for post-
approval monitoring.
Sec. 250.283 When must I Moved to BOEM, This section
revise or supplement the Sec. 550.283. addresses plans that
approved EP, DPP, or DOCD? are the
responsibility of
BOEM.
Sec. 250.284 How will MMS Moved to BOEM, This section
require revisions to the Sec. 550.284. addresses plans that
approved EP, DPP, or DOCD? are the
responsibility of
BOEM.
Sec. 250.285 How do I submit Moved to BOEM, This section
revised and supplemental EPs, Sec. 550.285. addresses plans that
DPPs, and DOCDs? are the
responsibility of
BOEM.
Sec. 250.286 What is a DWOP? Retained by BSEE. This section
addresses DWOPs that
are part of Field
Operations and under
the authority of
BSEE.
[[Page 64442]]
Sec. 250.287 For what Retained by BSEE. This section
development projects must I addresses DWOPs that
submit a DWOP? are part of Field
Operations and under
the authority of
BSEE.
Sec. 250.288 When and how Retained by BSEE. This section
must I submit the Conceptual addresses DWOPs that
Plan? are part of Field
Operations and under
the authority of
BSEE.
Sec. 250.289 What must the Retained by BSEE. This section
Conceptual Plan contain? addresses DWOPs that
are part of Field
Operations and under
the authority of
BSEE.
Sec. 250.290 What operations Retained by BSEE. This section
require approval of the addresses DWOPs that
Conceptual Plan? are part of Field
Operations and under
the authority of
BSEE.
Sec. 250.291 When and how Retained by BSEE. This section
must I submit the DWOP? addresses DWOPs that
are part of Field
Operations and under
the authority of
BSEE.
Sec. 250.292 What must the Retained by BSEE. This section
DWOP contain? addresses DWOPs that
are part of Field
Operations and under
the authority of
BSEE.
Sec. 250.293 What operations Retained by BSEE. This section
require approval of the DWOP? addresses DWOPs that
are part of Field
Operations and under
the authority of
BSEE.
Sec. 250.294 May I combine Retained by BSEE. This section
the Conceptual Plan and the addresses DWOPs that
DWOP? are part of Field
Operations and under
the authority of
BSEE.
Sec. 250.295 When must I Retained by BSEE. This section
revise my DWOP? addresses DWOPs that
are part of Field
Operations and under
the authority of
BSEE.
Sec. 250.296 When and how Moved to BOEM, This section
must I submit a CID or a Sec. 550.296. addresses
revision to a CID? Conservation
Information
Documents (CIDs)
that are under the
authority of BOEM to
manage development
of the Nation's
offshore resources
in an
environmentally and
economically
responsible way.
Sec. 250.297 What Moved to BOEM, This section
information must a CID Sec. 550.297. addresses CIDs that
contain? are under the
authority of BOEM to
manage development
of the Nation's
offshore resources
in an
environmentally and
economically
responsible way.
Sec. 250.298 How long will Moved to BOEM, This section
MMS take to evaluate and make Sec. 550.298. addresses CIDs that
a decision on the CID? are under the
authority of BOEM to
manage development
of the Nation's
offshore resources
in an
environmentally and
economically
responsible way.
Sec. 250.299 What operations Moved to BOEM, This section
require approval of the CID? Sec. 550.299. addresses CIDs that
are under the
authority of BOEM to
manage development
of the Nation's
offshore resources
in an
environmentally and
economically
responsible way.
------------------------------------------------------------------------
Subpart C--Pollution Prevention and Control
------------------------------------------------------------------------
Sec. 250.300 Pollution Retained by BSEE. This section
prevention. addresses pollution
prevention during
offshore operations.
Offshore operations
are under the
authority of BSEE.
Sec. 250.301 Inspection of Retained by BSEE. BSEE will be
facilities. responsible for all
inspection
activities on the
OCS.
Sec. 250.302 Definitions Moved to BOEM, This section pertains
concerning air quality. Sec. 550.302. to air quality
concerns that are
under the authority
of BOEM.
Sec. 250.303 Facilities Moved to BOEM, This section pertains
described in a new or revised Sec. 550.303. to air quality
Exploration Plan or concerns that are
Development and Production under the authority
Plan. of BOEM.
Sec. 250.304 Existing Moved to BOEM, This section pertains
facilities. Sec. 550.304. to air quality
concerns that are
under the authority
of BOEM.
------------------------------------------------------------------------
Subpart D--Oil and Gas Drilling Operations
------------------------------------------------------------------------
Retained in its entirety by BSEE. This section addresses oil and gas
drilling operations on the OCS. Offshore operations are under the
authority of BSEE.
------------------------------------------------------------------------
Subpart E--Oil and Gas Well-Completion Operations
Retained in its entirety by BSEE. BSEE will oversee all well-operations,
under Field Operations, under its authority for ensuring safety and
environmental compliance on the OCS.
------------------------------------------------------------------------
Subpart F--Oil and Gas Well-Workover Operations
Retained in its entirety by BSEE. This subpart addresses Oil and Gas
Well Workover Operations on the OCS. Offshore operations are the
responsibility of BSEE, under its authority for ensuring safety and
environmental compliance on the OCS.
------------------------------------------------------------------------
Subpart G--[Reserved]
------------------------------------------------------------------------
Subpart H--Oil and Gas Production Safety Systems
Retained in its entirety by BSEE. Addresses oil and gas production
safety systems used during offshore operations, which are under the
authority of BSEE.
------------------------------------------------------------------------
Subpart I--Platforms and Structures
Retained in its entirety by BSEE. This section addresses platforms and
structures on the OCS for offshore operations. Offshore operations are
under the authority of BSEE.
------------------------------------------------------------------------
[[Page 64443]]
Subpart J--Pipelines and Pipeline Rights-of-Way
Mostly retained by BSEE, except for provisions related to bond
requirements (Sec. 250.1011). Bonding for all activities is the
responsibility of BOEM, and the bonding section will be moved to Sec.
550.1011. The rest of pipeline operations, including the issuance of
pipeline rights-of-way, are under the authority of BSEE.
------------------------------------------------------------------------
Sec. 250.1000 General Retained by BSEE. This section
requirements.. addresses pipelines
and pipeline rights-
of-way on the OCS,
which are offshore
operations. Offshore
operations are under
the authority of
BSEE.
Sec. 250.1001 Definitions... Retained by BSEE. This section
addresses pipelines
and pipeline rights-
of-way on the OCS,
which are offshore
operations. Offshore
operations are under
the authority of
BSEE.
Sec. 250.1002 Design Retained by BSEE. This section
requirements for DOI addresses pipelines
pipelines. and pipeline rights-
of-way on the OCS,
which are offshore
operations. Offshore
operations are under
the authority of
BSEE.
Sec. 250.1003 Installation, Retained by BSEE. This section
testing, and repair addresses pipelines
requirements for DOI and pipeline rights-
pipelines. of-way on the OCS,
which are offshore
operations. Offshore
operations are under
the authority of
BSEE.
Sec. 250.1004 Safety Retained by BSEE. This section
equipment requirements for addresses pipelines
DOI pipelines. and pipeline rights-
of-way on the OCS,
which are offshore
operations. Offshore
operations are under
the authority of
BSEE.
Sec. 250.1005 Inspection Retained by BSEE. This section
requirements for DOI addresses pipelines
pipelines. and pipeline rights-
of-way on the OCS,
which are offshore
operations. Offshore
operations are under
the authority of
BSEE.
Sec. 250.1006 How must I Retained by BSEE. This section
decommission and take out of addresses pipelines
service a DOI pipeline? and pipeline rights-
of-way on the OCS,
which are offshore
operations. Offshore
operations are under
the authority of
BSEE.
Sec. 250.1007 What to Retained by BSEE. This section
include in applications. addresses pipelines
and pipeline rights-
of-way on the OCS,
which are offshore
operations. Offshore
operations are under
the authority of
BSEE.
Sec. 250.1008 Reports....... Retained by BSEE. This section
addresses pipelines
and pipeline rights-
of-way on the OCS,
which are offshore
operations. Offshore
operations are under
the authority of
BSEE.
Sec. 250.1009 Requirements Retained by BSEE. This section
to obtain pipeline right-of- addresses pipelines
way grants. and pipeline rights-
of-way on the OCS,
which are offshore
operations. The
pipeline rights-of-
way are so closely
related to the
regulation of
pipeline operations
that it is most
efficient to vest
the authority in
BSEE.
Sec. 250.1010 General Retained by BSEE. The pipeline rights-
requirements for pipeline of-way are so
right-of-way holders. closely related to
the regulation of
pipeline operations
that it is most
efficient to vest
the authority in
BSEE.
Sec. 250.1011 Bond Moved to BOEM, All bonding is under
requirements for pipeline Sec. 550.1011. the authority of
right-of-way holders. BOEM.
Sec. 250.1012 Required Retained by BSEE. The pipeline rights-
payments for pipeline right- of-way are so
of-way holders. closely related to
the regulation of
pipeline operations
that it is most
efficient to vest
the authority in
BSEE.
Sec. 250.1013 Grounds for Retained by BSEE. The pipeline rights-
forfeiture of pipeline right- of-way are so
of-way grants. closely related to
the regulation of
pipeline operations
that it is most
efficient to vest
the authority in
BSEE.
Sec. 250.1014 When pipeline Retained by BSEE. The pipeline rights-
right-of-way grants expire. of-way are so
closely related to
the regulation of
pipeline operations
that it is most
efficient to vest
the authority in
BSEE.
Sec. 250.1015 Applications Retained by BSEE. The pipeline rights-
for pipeline right-of-way of-way are so
grants. closely related to
the regulation of
pipeline operations
that it is most
efficient to vest
the authority in
BSEE.
Sec. 250.1016 Granting Retained by BSEE. The pipeline rights-
pipeline rights-of-way. of-way are so
closely related to
the regulation of
pipeline operations
that it is most
efficient to vest
the authority in
BSEE.
Sec. 250.1017 Requirements Retained by BSEE. The pipeline rights-
for construction under of-way are so
pipeline right-of-way grants. closely related to
the regulation of
pipeline operations
that it is most
efficient to vest
the authority in
BSEE.
Sec. 250.1018 Assignment of Retained by BSEE. The pipeline rights-
pipeline right-of-way grants. of-way are so
closely related to
the regulation of
pipeline operations
that it is most
efficient to vest
the authority in
BSEE.
Sec. 250.1019 Relinquishment Retained by BSEE. The pipeline rights-
of pipeline right-of-way of-way are so
grants. closely related to
the regulation of
pipeline operations
that it is most
efficient to vest
the authority in
BSEE.
------------------------------------------------------------------------
Subpart K--Oil and Gas Production Requirements
Mostly retained by BSEE, except for provisions related to static
bottomhole pressure surveys and classifying reservoirs; BOEM will
oversee these requirements because they are operator reporting
requirements that can be separated from BSEE's enforcement
responsibilities.
------------------------------------------------------------------------
[[Page 64444]]
Sec. 250.1150 What are the Retained by BSEE. This section
general reservoir production addresses oil and
requirements? gas production
requirements that
are part of offshore
operations and are
under the authority
of BSEE.
Sec. 250.1151 How often must Retained by BSEE. This section
I conduct well production addresses oil and
tests? gas production
requirements that
are part of offshore
operations and are
under the authority
of BSEE.
Sec. 250.1152 How do I Retained by BSEE. This section
conduct well tests? addresses oil and
gas production
requirements that
are part of offshore
operations and are
under the authority
of BSEE.
Sec. 250.1153 When must I Moved to BOEM, BOEM will oversee
conduct a static bottomhole Sec. 550.1153. these requirements
pressure survey? because they are
operator reporting
requirements that
can be separated
from BSEE's
enforcement
responsibilities.
Sec. 250.1154 How do I Moved to BOEM, BOEM will oversee
determine if my reservoir is Sec. 550.1154. these requirements
sensitive? because they are
operator reporting
requirements that
can be separated
from BSEE's
enforcement
responsibilities.
Sec. 250.1155 What Moved to BOEM, BOEM will oversee
information must I submit for Sec. 550.1155. these requirements
sensitive reservoirs? because they are
operator reporting
requirements that
can be separated
from BSEE's
enforcement
responsibilities.
Sec. 250.1156 What steps Retained by BSEE. This section
must I take to receive addresses oil and
approval to produce within gas production
500 feet of a unit or lease requirements that
line? are part of offshore
operations and are
under the authority
of BSEE.
Sec. 250.1157 How do I Retained by BSEE. This section
receive approval to produce addresses oil and
gas-cap gas from an oil gas production
reservoir with an associated requirements that
gas cap? are part of offshore
operations and are
under the authority
of BSEE.
Sec. 250.1158 How do I Retained by BSEE. This section
receive approval to downhole addresses oil and
commingle hydrocarbons? gas production
requirements that
are part of offshore
operations and are
under the authority
of BSEE.
Sec. 250.1159 May the Retained by BSEE. This section
Regional Supervisor limit my addresses oil and
well or reservoir production gas production
rates? requirements that
are part of offshore
operations and are
under the authority
of BSEE.
Sec. 250.1160 When may I Retained by BSEE. This section
flare or vent gas? addresses oil and
gas production
requirements that
are part of offshore
operations and are
under the authority
of BSEE.
Sec. 250.1161 When may I Retained by BSEE. This section
flare or vent gas for addresses oil and
extended periods of time? gas production
requirements that
are part of offshore
operations and are
under the authority
of BSEE.
Sec. 250.1162 When may I Retained by BSEE. This section
burn produced liquid addresses oil and
hydrocarbons? gas production
requirements that
are part of offshore
operations and are
under the authority
of BSEE.
Sec. 250.1163 How must I Retained by BSEE. This section
measure gas flaring or addresses oil and
venting volumes and liquid gas production
hydrocarbon burning volumes, requirements that
and what records must I are part of offshore
maintain? operations and are
under the authority
of BSEE.
Sec. 250.1164 What are the Retained by BSEE. This section
requirements for flaring or addresses oil and
venting gas containing H2S? gas production
requirements that
are part of offshore
operations and are
under the authority
of BSEE.
Sec. 250.1165 What must I do Responsibilities This section
for enhanced recovery divided between addresses oil and
operations? BSEE and BOEM, gas production
Sec. requirements that
550.1165(b). are part of offshore
operations and are
under the authority
of BSEE. Paragraph
550.1165 (b) refers
operators to BSEE
for approval.
Sec. 250.1166 What Responsibilities BSEE will oversee
additional reporting is divided between these requirements
required for developments in BSEE and BOEM, because they are
the Alaska OCS Region? Sec. operator reporting
550.1166(c). requirements.
Paragraph
550.1166(c) requires
the lessee/operator
to request the
Maximum Efficient
Rate (MER) when
submitting Form BOEM-
0127 as required
under Sec.
550.1155 for
sensitive
reservoirs.
Sec. 250.1167 What Responsibilities This section
information must I submit divided between addresses
with forms and for approvals? BSEE and BOEM. information to be
submitted; both BSEE
and BOEM functions.
------------------------------------------------------------------------
Subpart L--Oil and Gas Production Measurement, Surface Commingling, and
Security
Retained in its entirety by BSEE. This subpart addresses production
measurement, which is a responsibility of BSEE, under its authority for
regulatory enforcement of conservation compliance.
------------------------------------------------------------------------
Subpart M--Unitization
Retained in its entirety by BSEE. This subpart addresses unitization,
which is a responsibility of BSEE, under its authority for regulatory
enforcement of conservation compliance.
------------------------------------------------------------------------
[[Page 64445]]
Subpart N--Outer Continental Shelf (OCS) Civil Penalties
Retained in both bureaus in its entirety, with the exception of
provisions in current Sec. 250.1460 that are specific to operational
violations penalized only by BSEE. BOEM issues civil penalties for
violations that occur prior to commencement of lease operations and not
involving safety and environmental matters, but arising from the lease
management functions and regulations of BOEM. BSEE issues civil
penalties for violations that occur after permits are approved; these
violations would include violations of lease terms or approved plans
that occur during operations.
------------------------------------------------------------------------
Subpart O--Well Control and Production Safety Training
Retained in its entirety by BSEE. This subpart establishes training
requirements for individuals working in the offshore oil and gas
industry; which is the responsibility of BSEE, under its authority for
regulatory enforcement of safety related to offshore operations.
------------------------------------------------------------------------
Subpart P--Sulphur Operations
Retained in its entirety by BSEE. Sulphur operations are the
responsibility of BSEE, under the authority for regulatory enforcement
of safety, environment and conservation compliance of the Nation's
offshore resources.
------------------------------------------------------------------------
Subpart Q--Decommissioning Activities
Retained in its entirety by BSEE. Decommissioning activities are the
responsibility of BSEE, under the authority for regulatory enforcement
of safety, environment and conservation compliance of the Nation's
offshore resources.
------------------------------------------------------------------------
Subpart R--[Reserved]
------------------------------------------------------------------------
Subpart S--Safety and Environmental Management Systems (SEMS)
Retained in its entirety by BSEE. This subpart addresses operator
developed SEMS programs; these programs are the responsibility of BSEE,
under the authority for regulatory enforcement of safety, environment
and conservation compliance of the Nation's offshore resources.
------------------------------------------------------------------------
Part 251--Geological and Geophysical (G&G) Explorations of the Outer
Continental Shelf
This part establishes requirements to conduct G&G activities
related to oil, gas, and sulphur on unleased lands, or lands under
lease to a third party. Most of this part will be the responsibility of
BOEM, under its authority to conduct exploration or scientific research
activities. Some sections that address drilling will go to BSEE that
address drilling.
Table C--Detailed Table for Part 251
------------------------------------------------------------------------
Implementing
Current citation and BSEE bureau and BOEM
citation (if applicable) citation (if Explanation
applicable)
------------------------------------------------------------------------
PART 251--GEOLOGICAL AND GEOPHYSICAL (G&G) EXPLORATIONS OF THE OUTER
CONTINENTAL SHELF
------------------------------------------------------------------------
Sec. 251.1 Definitions...... Both BSEE and Definitions section,
BOEM, Sec. the same definitions
551.1. apply to both
bureaus.
Sec. 251.2 Purpose of this Moved to BOEM, This section
part. Sec. 551.2. addresses prelease
G&G activities.
Prelease activities
are under the
authority of BOEM.
Sec. 251.3 Authority and Both BSEE and This section
applicability of this part. BOEM, Sec. addresses prelease
551.3. G&G activities.
Prelease activities
are under the
authority of BOEM.
Sec. 251.4 Types of G&G Moved to BOEM, This section
activities that require Sec. 551.4. addresses prelease
permits or Notices. G&G activities.
Prelease activities
are under the
authority of BOEM.
Sec. 251.5 Applying for Moved to BOEM, This section
permits or filing Notices. Sec. 551.5. addresses prelease
G&G activities.
Prelease activities
are under the
authority of BOEM.
Sec. 251.6 Obligations and Moved to BOEM, This section
rights under a permit or a Sec. 551.6. addresses prelease
Notice. G&G activities.
Prelease activities
are under the
authority of BOEM.
Sec. 251.7 Test drilling Responsibilities All of paragraph (b)
activities under a permit. divided between regulates drilling
both BSEE and activities, which
BOEM. are operations that
require a permit,
under the authority
of BSEE. All of Sec.
551.7, except
(b)(6) and (b)(8),
is under BOEM.
Sec. 251.8 Inspection and Moved to BOEM, This section
reporting requirements for Sec. 551.8. addresses prelease
activities under a permit. G&G activities.
Prelease activities
are under the
authority of BOEM.
Sec. 251.9 Temporarily Moved to BOEM, This section
stopping, canceling, or Sec. 551.9. addresses prelease
relinquishing activities G&G activities.
approved under a permit. Prelease activities
are under the
authority of BOEM.
Sec. 251.10 Penalties and Moved to BOEM, This section
appeals. Sec. 551.10. addresses prelease
G&G activities.
Prelease activities
are under the
authority of BOEM.
Sec. 251.11 Submission, Moved to BOEM, This section
inspection, and selection of Sec. 551.11. addresses prelease
geological data and G&G activities.
information collected under a Prelease activities
permit and processed by are under the
permittees or third parties. authority of BOEM.
[[Page 64446]]
Sec. 251.12 Submission, Moved to BOEM, This section
inspection, and selection of Sec. 551.12. addresses prelease
geophysical data and G&G activities.
information collected under a Prelease activities
permit and processed by are under the
permittees or third parties. authority of BOEM.
Sec. 251.13 Reimbursement Moved to BOEM, This section
for the costs of reproducing Sec. 551.13. addresses prelease
data and information and G&G activities.
certain processing costs. Prelease activities
are under the
authority of BOEM.
Sec. 251.14 Protecting and Moved to BOEM, This section
disclosing data and Sec. 551.14. addresses prelease
information submitted to MMS G&G activities.
under a permit. Prelease activities
are under the
authority of BOEM.
Sec. 251.15 Authority for In both BSEE and This section
information collection. BOEM Sec. establishes the
551.15. authority for the
bureaus to collect
the required
information from
lessees and
operators who
conduct business on
the OCS. Information
collection is
required in this
part for aspects
regulated by both
BSEE and BOEM.
------------------------------------------------------------------------
Part 252--Outer Continental Shelf (OCS) Oil and Gas Information Program
Both BOEM and BSEE will have this part in its entirety. Both
bureaus will be responsible for collecting and maintaining certain data
and information. This subpart establishes the responsibilities of the
bureau for protecting and releasing this data.
Table D--Detailed Table for Part 252
------------------------------------------------------------------------
Implementing
Current citation and BSEE bureau and BOEM
citation (if applicable) citation (if Explanation
applicable)
------------------------------------------------------------------------
PART 252--OUTER CONTINENTAL SHELF (OCS) OIL AND GAS INFORMATION PROGRAM
------------------------------------------------------------------------
Sec. 252.1 Purpose.......... In both BSEE and Both BSEE and BOEM
BOEM Sec. will collect,
552.1. maintain, and use
data collected under
this program. Both
bureaus are
responsible for
managing the data
and determining how
and when the data is
released.
Sec. 252.2 Definitions...... In both BSEE and Definitions section.
BOEM Sec. The same definitions
552.2. apply to both sets
of regulations.
Sec. 252.3 Oil and gas data In both BSEE and Both BSEE and BOEM
and information to be BOEM Sec. will collect.
provided for use in the OCS 552.3.
Oil and Gas Information
Program.
Sec. 252.4 Summary Report to In both BSEE and Both BSEE and BOEM
affected States. BOEM Sec. will collect.
552.4.
Sec. 252.5 Information to be In both BSEE and Both BSEE and BOEM
made available to affected BOEM Sec. will collect.
States. 552.5.
Sec. 252.6 Freedom of In both BSEE and Both BSEE and BOEM
Information Act requirements. BOEM Sec. will collect.
552.6.
Sec. 252.7 Privileged and In both BSEE and Both BSEE and BOEM
proprietary data and BOEM Sec. will collect.
information to be made 552.7.
available to affected States.
------------------------------------------------------------------------
Part 253--Oil Spill Financial Responsibility for Offshore Facilities--
Moved to BOEM in Its Entirety, Chapter V Part 523
All financial responsibility functions will be under the authority
of BOEM, under its mission to manage the development of offshore
resources in an economically responsible way.
[[Page 64447]]
Table E--Detailed Table for Part 253
------------------------------------------------------------------------
Implementing
Current citation and BSEE bureau and BOEM
citation (if applicable) citation (if Explanation
applicable)
------------------------------------------------------------------------
Subpart A--General
------------------------------------------------------------------------
Sec. 253.1 What is the Moved to BOEM, BOEM is responsible
purpose of this part? Sec. 553.1. for all activities
related to financial
assurance. OPA
financial
responsibility is
required of all oil
handling facilities
seaward of the
coastline, whether
production
facilities or not
and whether Federal
or not.
Sec. 253.3 How are the terms Moved to BOEM, BOEM is responsible
used in this regulation Sec. 553.3. for all activities
defined? related to financial
assurance.
Sec. 253.5 What is the Moved to BOEM, BOEM is responsible
authority for collecting Oil Sec. 553.5. for all activities
Spill Financial related to financial
Responsibility (OSFR) assurance.
information?
------------------------------------------------------------------------
Subpart B--Applicability and Amount of OSFR
------------------------------------------------------------------------
Sec. 253.10 What facilities Moved to BOEM, BOEM is responsible
does this part cover? Sec. 553.10. for all activities
related to financial
assurance.
Sec. 253.11 Who must Moved to BOEM, BOEM is responsible
demonstrate OSFR? Sec. 553.11. for all activities
related to financial
assurance.
Sec. 253.12 May I ask MMS Moved to BOEM, BOEM is responsible
for a determination of Sec. 553.12. for all activities
whether I must demonstrate related to financial
OSFR? assurance.
Sec. 253.13 How much OSFR Moved to BOEM, BOEM is responsible
must I demonstrate? Sec. 553.13. for all activities
related to financial
assurance.
Sec. 253.14 How do I Moved to BOEM, BOEM is responsible
determine the worst case oil- Sec. 553.14. for all activities
spill discharge volume? related to financial
assurance.
Sec. 253.15 What are my Moved to BOEM, BOEM is responsible
general OSFR compliance Sec. 553.15. for all activities
responsibilities? related to financial
assurance.
------------------------------------------------------------------------
Subpart C--Methods for Demonstrating OSFR
------------------------------------------------------------------------
Sec. 253.20 What methods may Moved to BOEM, BOEM is responsible
I use to demonstrate OSFR? Sec. 553.20. for all activities
related to financial
assurance.
Sec. 253.21 How can I use Moved to BOEM, BOEM is responsible
self-insurance as OSFR Sec. 553.21. for all activities
evidence? related to financial
assurance.
Sec. 253.22 How do I apply Moved to BOEM, BOEM is responsible
to use self-insurance as OSFR Sec. 553.22. for all activities
evidence? related to financial
assurance.
Sec. 253.23 What information Moved to BOEM, BOEM is responsible
must I submit to support my Sec. 553.23. for all activities
net worth demonstration? related to financial
assurance.
Sec. 253.24 When I submit Moved to BOEM, BOEM is responsible
audited annual financial Sec. 553.24. for all activities
statements to verify my net related to financial
worth, what standards must assurance.
they meet?
Sec. 253.25 What financial Moved to BOEM, BOEM is responsible
test procedures must I use to Sec. 553.25. for all activities
determine the amount of self- related to financial
insurance allowed as OSFR assurance.
evidence based on net worth?
Sec. 253.26 What information Moved to BOEM, BOEM is responsible
must I submit to support my Sec. 553.26. for all activities
unencumbered assets related to financial
demonstration? assurance.
Sec. 253.27 When I submit Moved to BOEM, BOEM is responsible
audited annual financial Sec. 553.27. for all activities
statements to verify my related to financial
unencumbered assets, what assurance.
standards must they meet?
Sec. 253.28 What financial Moved to BOEM, BOEM is responsible
test procedures must I use to Sec. 553.28. for all activities
evaluate the amount of self- related to financial
insurance allowed as OSFR assurance.
evidence based on
unencumbered assets?
Sec. 253.29 How can I use Moved to BOEM, BOEM is responsible
insurance as OSFR evidence? Sec. 553.29. for all activities
related to financial
assurance.
Sec. 253.30 How can I use an Moved to BOEM, BOEM is responsible
indemnity as OSFR evidence? Sec. 553.30. for all activities
related to financial
assurance.
Sec. 253.31 How can I use a Moved to BOEM, BOEM is responsible
surety bond as OSFR evidence? Sec. 553.31. for all activities
related to financial
assurance.
[[Page 64448]]
Sec. 253.32 Are there Moved to BOEM, BOEM is responsible
alternative methods to Sec. 553.32. for all activities
demonstrate OSFR? related to financial
assurance.
------------------------------------------------------------------------
Subpart D--Requirements for Submitting OSFR Information
------------------------------------------------------------------------
Sec. 253.40 What OSFR Moved to BOEM, BOEM is responsible
evidence must I submit to Sec. 553.40. for all activities
MMS? related to financial
assurance.
Sec. 253.41 What terms must Moved to BOEM, BOEM is responsible
I include in my OSFR Sec. 553.41. for all activities
evidence? related to financial
assurance.
Sec. 253.42 How can I amend Moved to BOEM, BOEM is responsible
my list of COFs? Sec. 553.42. for all activities
related to financial
assurance.
Sec. 253.43 When is my OSFR Moved to BOEM, BOEM is responsible
demonstration or the Sec. 553.43. for all activities
amendment to my OSFR related to financial
demonstration effective? assurance.
Sec. 253.44 [Reserved]...... Sec. 553.44 BOEM is responsible
[Reserved]. for all activities
related to financial
assurance.
Sec. 253.45 Where do I send Moved to BOEM, BOEM is responsible
my OSFR evidence? Sec. 553.45. for all activities
related to financial
assurance.
------------------------------------------------------------------------
Subpart E--Revocation and Penalties
------------------------------------------------------------------------
Sec. 253.50 How can MMS Moved to BOEM, BOEM is responsible
refuse or invalidate my OSFR Sec. 553.50. for all activities
evidence? related to financial
assurance.
Sec. 253.51 What are the Moved to BOEM, BOEM is responsible
penalties for not complying Sec. 553.51. for all activities
with this part? related to financial
assurance.
------------------------------------------------------------------------
Subpart F--Claims for Oil-Spill Removal Costs and Damages
------------------------------------------------------------------------
Sec. 253.60 To whom may I Moved to BOEM, BOEM is responsible
present a claim? Sec. 553.60. for all activities
related to financial
assurance.
Sec. 253.61 When is a Moved to BOEM, BOEM is responsible
guarantor subject to direct Sec. 553.61. for all activities
action for claims? related to financial
assurance.
Sec. 253.62 What are the Moved to BOEM, BOEM is responsible
designated applicant's Sec. 553.62. for all activities
notification obligations related to financial
regarding a claim? assurance.
Appendix--Appendix to Part Moved to BOEM, BOEM is responsible
253--List of U.S. Geological Appendix to part for all activities
Survey Topographic Maps. 553. related to financial
assurance.
------------------------------------------------------------------------
Part 254--Oil-Spill Response Requirements for Facilities Located
Seaward of the Coast Line--Retained in Its Entirety in BSEE
All oil-spill response functions will be managed by BSEE under its
responsibility for enforcement of environmental compliance
requirements.
Table F--Detailed Table for Part 254
------------------------------------------------------------------------
Implementing
Current citation and BSEE bureau and BOEM
citation (if applicable) citation (if Explanation
applicable)
------------------------------------------------------------------------
Subpart A--General
------------------------------------------------------------------------
Sec. 254.1 Who must submit a Retained in its All oil spill related
spill-response plan? entirety in regulations, except
BSEE, chapter II. for financial
responsibility, are
under BSEE, under
its responsibility
for oil spill
response.
Sec. 254.2 When must I Retained in its All oil spill related
submit a response plan? entirety in regulations, except
BSEE, chapter II. for financial
responsibility, are
under BSEE, under
its responsibility
for oil spill
response.
Sec. 254.3 May I cover more Retained in its All oil spill related
than one facility in my entirety in regulations, except
response plan? BSEE, chapter II. for financial
responsibility, are
under BSEE, under
its responsibility
for oil spill
response.
Sec. 254.4 May I reference Retained in its All oil spill related
other documents in my entirety in regulations, except
response plan? BSEE, chapter II. for financial
responsibility, are
under BSEE, under
its responsibility
for oil spill
response.
Sec. 254.5 General response Retained in its All oil spill related
plan requirements. entirety in regulations, except
BSEE, chapter II. for financial
responsibility, are
under BSEE, under
its responsibility
for oil spill
response.
Sec. 254.6 Definitions...... Retained in its All oil spill related
entirety in regulations, except
BSEE, chapter II. for financial
responsibility, are
under BSEE, under
its responsibility
for oil spill
response.
Sec. 254.7 How do I submit Retained in its All oil spill related
my response plan to the MMS? entirety in regulations, except
BSEE, chapter II. for financial
responsibility, are
under BSEE, under
its responsibility
for oil spill
response.
[[Page 64449]]
Sec. 254.8 May I appeal Retained in its All oil spill related
decisions under this part? entirety in regulations, except
BSEE, chapter II. for financial
responsibility, are
under BSEE, under
its responsibility
for oil spill
response.
Sec. 254.9 Authority for Retained in its All oil spill related
information collection. entirety in regulations, except
BSEE, chapter II. for financial
responsibility, are
under BSEE, under
its responsibility
for oil spill
response.
------------------------------------------------------------------------
Subpart B--Oil-Spill Response Plans for Outer Continental Shelf
Facilities
------------------------------------------------------------------------
Sec. 254.20 Purpose......... Retained in its All oil spill related
entirety in regulations, except
BSEE, chapter II. for financial
responsibility, are
under BSEE, under
its responsibility
for oil spill
response.
Sec. 254.21 How must I Retained in its All oil spill related
format my response plan? entirety in regulations, except
BSEE, chapter II. for financial
responsibility, are
under BSEE, under
its responsibility
for oil spill
response.
Sec. 254.22 What information Retained in its All oil spill related
must I include in the entirety in regulations, except
``Introduction and plan BSEE, chapter II. for financial
contents'' section? responsibility, are
under BSEE, under
its responsibility
for oil spill
response.
Sec. 254.23 What information Retained in its All oil spill related
must I include in the entirety in regulations, except
``Emergency response action BSEE, chapter II. for financial
plan'' section? responsibility, are
under BSEE, under
its responsibility
for oil spill
response.
Sec. 254.24 What information Retained in its All oil spill related
must I include in the entirety in regulations, except
``Equipment inventory'' BSEE, chapter II. for financial
appendix? responsibility, are
under BSEE, under
its responsibility
for oil spill
response.
Sec. 254.25 What information Retained in its All oil spill related
must I include in the entirety in regulations, except
``Contractual agreements'' BSEE, chapter II. for financial
appendix? responsibility, are
under BSEE, under
its responsibility
for oil spill
response.
Sec. 254.26 What information Retained in its All oil spill related
must I include in the ``Worst entirety in regulations, except
case discharge scenario'' BSEE, chapter II. for financial
appendix? responsibility, are
under BSEE, under
its responsibility
for oil spill
response.
Sec. 254.27 What information Retained in its All oil spill related
must I include in the entirety in regulations, except
``Dispersant use plan'' BSEE, chapter II. for financial
appendix? responsibility, are
under BSEE, under
its responsibility
for oil spill
response.
Sec. 254.28 What information Retained in its All oil spill related
must I include in the ``In entirety in regulations, except
situ burning plan'' appendix? BSEE, chapter II. for financial
responsibility, are
under BSEE, under
its responsibility
for oil spill
response.
Sec. 254.29 What information Retained in its All oil spill related
must I include in the entirety in regulations, except
``Training and drills'' BSEE, chapter II. for financial
appendix? responsibility, are
under BSEE, under
its responsibility
for oil spill
response.
Sec. 254.30 When must I Retained in its All oil spill related
revise my response plan? entirety in regulations, except
BSEE, chapter II. for financial
responsibility, are
under BSEE, under
its responsibility
for oil spill
response.
------------------------------------------------------------------------
Subpart C--Related Requirements for Outer Continental Shelf Facilities
------------------------------------------------------------------------
Sec. 254.40 Records......... Retained in its All oil spill related
entirety in regulations, except
BSEE, chapter II. for financial
responsibility, are
under BSEE, under
its responsibility
for oil spill
response.
Sec. 254.41 Training your Retained in its All oil spill related
response personnel. entirety in regulations, except
BSEE, chapter II. for financial
responsibility, are
under BSEE, under
its responsibility
for oil spill
response.
Sec. 254.42 Exercises for Retained in its All oil spill related
your response personnel and entirety in regulations, except
equipment. BSEE, chapter II. for financial
responsibility, are
under BSEE, under
its responsibility
for oil spill
response.
Sec. 254.43 Maintenance and Retained in its All oil spill related
periodic inspection of entirety in regulations, except
response equipment. BSEE, chapter II. for financial
responsibility, are
under BSEE, under
its responsibility
for oil spill
response.
Sec. 254.44 Calculating Retained in its All oil spill related
response equipment effective entirety in regulations, except
daily recovery capacities. BSEE, chapter II. for financial
responsibility, are
under BSEE, under
its responsibility
for oil spill
response.
Sec. 254.45 Verifying the Retained in its All oil spill related
capabilities of your response entirety in regulations, except
equipment. BSEE, chapter II. for financial
responsibility, are
under BSEE, under
its responsibility
for oil spill
response.
Sec. 254.46 Whom do I notify Retained in its All oil spill related
if an oil spill occurs? entirety in regulations, except
BSEE, chapter II. for financial
responsibility, are
under BSEE, under
its responsibility
for oil spill
response.
Sec. 254.47 Determining the Retained in its All oil spill related
volume of oil of your worst entirety in regulations, except
case discharge scenario. BSEE, chapter II. for financial
responsibility, are
under BSEE, under
its responsibility
for oil spill
response.
------------------------------------------------------------------------
Subpart D--Oil-Spill Response Requirements for Facilities Located in
State Waters Seaward of the Coast Line
------------------------------------------------------------------------
Sec. 254.50 Spill response Retained in its All oil spill related
plans for facilities located entirety in regulations, except
in State waters seaward of BSEE, chapter II. for financial
the coast line. responsibility, are
under BSEE, under
its responsibility
for oil spill
response.
Sec. 254.51 Modifying an Retained in its All oil spill related
existing OCS response plan. entirety in regulations, except
BSEE, chapter II. for financial
responsibility, are
under BSEE, under
its responsibility
for oil spill
response.
Sec. 254.52 Following the Retained in its All oil spill related
format for an OCS response entirety in regulations, except
plan. BSEE, chapter II. for financial
responsibility, are
under BSEE, under
its responsibility
for oil spill
response.
[[Page 64450]]
Sec. 254.53 Submitting a Retained in its All oil spill related
response plan developed under entirety in regulations, except
State requirements. BSEE, chapter II. for financial
responsibility, are
under BSEE, under
its responsibility
for oil spill
response.
Sec. 254.54 Spill prevention Retained in its All oil spill related
for facilities located in entirety in regulations, except
State waters seaward of the BSEE, chapter II. for financial
coast line. responsibility, are
under BSEE, under
its responsibility
for oil spill
response.
------------------------------------------------------------------------
Part 256--Leasing of Sulphur or Oil and Gas in the Outer Continental
Shelf
This part establishes leasing requirements for sulphur, oil, and
natural gas. Most of this part will be under the responsibility of BOEM
under its authority to manage the development of the Nation's offshore
resources in an environmentally and economically responsible way. Some
sections will go to BSEE that address lease extensions by drilling and
suspensions of operations or production.
Table G--Detailed Table for Part 256
------------------------------------------------------------------------
Implementing
Current citation and BSEE bureau and BOEM
citation (if applicable) citation (if Explanation
applicable)
------------------------------------------------------------------------
Subpart A--Outer Continental Shelf Oil, Gas, and Sulphur Management,
General
------------------------------------------------------------------------
Sec. 256.0 Authority for Moved to BOEM, This section
information collection. Sec. 556.0. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.1 Purpose.......... Moved to BOEM, This section
Sec. 556.1, addresses leasing
retained purpose activities on the
except for right- OCS that are under
of-way grant the authority of
clause; under BOEM.
BSEE retained
right-of-way
grant clause.
Sec. 256.2 Policy........... Moved to BOEM, This section
Sec. 556.2. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.4 Authority........ Moved to BOEM, This section
Sec. 556.4. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.5 Definitions...... Moved to BOEM, This section
Sec. 556.5. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.7 Cross references. Both BSEE and This section contains
BOEM Sec. cross references
556.7. that are pertinent
to both BSEE and
BOEM activities.
Sec. 256.8 Leasing maps and Moved to BOEM, This section
diagrams. Sec. 556.8. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.10 Information to Moved to BOEM, This section
States. Sec. 556.10. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.11 Helium.......... Moved to BOEM, This section
Sec. 556.11. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.12 Supplemental Moved to BOEM, This section
sales. Sec. 556.12. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
------------------------------------------------------------------------
Subpart B--Oil and Gas Leasing Program
------------------------------------------------------------------------
Sec. 256.16 Receipt and Moved to BOEM, This section
consideration of nominations; Sec. 556.16. addresses leasing
public notice and activities on the
participation. OCS that are under
the authority of
BOEM.
Sec. 256.17 Review by State Moved to BOEM, This section
and local governments and Sec. 556.17. addresses leasing
other persons. activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.19 Periodic Moved to BOEM, This section
consultation with interested Sec. 556.19. addresses leasing
parties. activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.20 Consideration of Moved to BOEM, This section
coastal zone management Sec. 556.20. addresses leasing
program. activities on the
OCS that are under
the authority of
BOEM.
------------------------------------------------------------------------
Subpart C--Reports From Federal Agencies
------------------------------------------------------------------------
Sec. 256.22 General......... Moved to BOEM, This section
Sec. 556.22. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
------------------------------------------------------------------------
Subpart D--Call for Information and Nominations
------------------------------------------------------------------------
Sec. 256.23 Information on Moved to BOEM, This section
areas. Sec. 556.23. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.25 Areas near Moved to BOEM, This section
coastal states. Sec. 556.25. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
------------------------------------------------------------------------
[[Page 64451]]
Subpart E--Area Identification and Tract Size
------------------------------------------------------------------------
Sec. 256.26 General......... Moved to BOEM, This section
Sec. 556.26. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.28 Tract size...... Moved to BOEM, This section
Sec. 556.28. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
------------------------------------------------------------------------
Subpart F--Lease Sales
------------------------------------------------------------------------
Sec. 256.29 Proposed notice Moved to BOEM, This section
of sale. Sec. 556.29. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.31 State comments.. Moved to BOEM, This section
Sec. 556.31. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.32 Notice of sale.. Moved to BOEM, This section
Sec. 556.32. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
------------------------------------------------------------------------
Subpart G--Issuance of Leases
------------------------------------------------------------------------
Sec. 256.35 Qualifications Moved to BOEM, This section
of lessees. Sec. 556.35. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.37 Lease term...... Moved to BOEM, This section
Sec. 556.37. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.38 Joint bidding Moved to BOEM, This section
provisions. Sec. 556.38. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.40 Definitions..... Moved to BOEM, This section
Sec. 556.40. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.41 Joint bidding Moved to BOEM, This section
requirements. Sec. 556.41. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.43 Chargeability Moved to BOEM, This section
for production. Sec. 556.43. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.44 Bids Moved to BOEM, This section
disqualified. Sec. 556.44. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.46 Submission of Moved to BOEM, This section
bids. Sec. 556.46. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.47 Award of leases. Moved to BOEM, This section
Sec. 556.47. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.49 Lease form...... Moved to BOEM, This section
Sec. 556.49. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.50 Dating of leases Moved to BOEM, This section
Sec. 556.50. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
------------------------------------------------------------------------
Subpart H--Rentals and Royalties [Reserved]
------------------------------------------------------------------------
Subpart I--Bonding
------------------------------------------------------------------------
Sec. 256.52 Bond Moved to BOEM, This section
requirements for an oil and Sec. 556.52. addresses leasing
gas or sulphur lease. activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.53 Additional bonds Moved to BOEM, This section
Sec. 556.53. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.54 General Moved to BOEM, This section
requirements for bonds. Sec. 556.54. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.55 Lapse of bond... Moved to BOEM, This section
Sec. 556.55. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.56 Lease-specific Moved to BOEM, This section
abandonment accounts. Sec. 556.56. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.57 Using a third- Moved to BOEM, This section
party guarantee instead of a Sec. 556.57. addresses leasing
bond. activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.58 Termination of Moved to BOEM, This section
the period of liability and Sec. 556.58. addresses leasing
cancellation of a bond. activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.59 Forfeiture of Moved to BOEM, This section
bonds and/or other securities. Sec. 556.59. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
------------------------------------------------------------------------
Subpart J--Assignments, Transfers, and Extensions
------------------------------------------------------------------------
Sec. 256.62 Assignment of Moved to BOEM, This section
lease or interest in lease. Sec. 556.62. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.63 Service fees.... Moved to BOEM, This section
Sec. 556.63. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.64 How to file Moved to BOEM, This section
transfers. Sec. 556.64. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
[[Page 64452]]
Sec. 256.65 Attorney General Moved to BOEM, This section
review. Sec. 556.65. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.67 Separate filings Moved to BOEM, This section
for assignments. Sec. 556.67. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.68 Effect of Moved to BOEM, This section
assignment of a particular Sec. 556.68. addresses leasing
tract. activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.70 Extension of Both BSEE and Needed by both
lease by drilling or well BOEM Sec. agencies.
reworking operations. 556.70.
Sec. 256.71 Directional Both BSEE and Needed by both
drilling. BOEM Sec. agencies.
556.71.
Sec. 256.72 Compensatory Both BSEE and Needed by both
payments as production. BOEM Sec. agencies.
556.72.
Sec. 256.73 Effect of Retained by BSEE. This section
suspensions on lease term. addresses
enforcement of
suspension
activities on the
OCS that is under
the authority of
BSEE. Beyond the
primary lease term,
BSEE's oversight
over operations and
production and
suspensions thereof
determine the lease
term.
------------------------------------------------------------------------
Subpart K--Termination of Leases
------------------------------------------------------------------------
Sec. 256.76 Relinquishment Moved to BOEM, This section
of leases or parts of leases. Sec. 556.76. addresses leasing
administration on
the OCS that are
under the authority
of BOEM.
Sec. 256.77 Cancellation of Both BSEE and BOEM is authorized to
leases. BOEM, Sec. cancel leases. BSEE
556.77. has the authority to
initiate lease
cancellation.
------------------------------------------------------------------------
Subpart L--Section 6 Leases
------------------------------------------------------------------------
Sec. 256.79 Effect of Both BSEE and Needed by both
regulations on lease. BOEM Sec. agencies.
556.79.
Sec. 256.80 Leases of other Moved to BOEM, This section
minerals. Sec. 556.80. addresses leasing
administration on
the OCS that are
under the authority
of BOEM.
------------------------------------------------------------------------
Subpart M--Studies
------------------------------------------------------------------------
Sec. 256.82 Environmental Moved to BOEM, This section
studies. Sec. 556.82. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
------------------------------------------------------------------------
Subpart N--Bonus or Royalty Credits for Exchange of Certain Leases
------------------------------------------------------------------------
Offshore Florida
------------------------------------------------------------------------
Sec. 256.90 Which leases may Moved to BOEM, This section
I exchange for a bonus or Sec. 556.90. addresses leasing
royalty credit? activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.91 How much bonus Moved to BOEM, This section
or royalty credit will MMS Sec. 556.91. addresses leasing
grant in exchange for a activities on the
lease? OCS that are under
the authority of
BOEM.
Sec. 256.92 What must I do Moved to BOEM, This section
to obtain a bonus or royalty Sec. 556.92. addresses leasing
credit? activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.93 How is the bonus Moved to BOEM, This section
or royalty credit allocated Sec. 556.93. addresses leasing
among multiple lease owners? activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.94 How may I use Moved to BOEM, This section
the bonus or royalty credit? Sec. 556.94. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 256.95 How do I Moved to BOEM, This section
transfer a bonus or royalty Sec. 556.95. addresses leasing
credit to another person? activities on the
OCS that are under
the authority of
BOEM.
APPENDIX A PART 256--Appendix Moved to BOEM, This section
A to Part 256--Oil and Gas APPENDIX A PART addresses leasing
Cash Bonus Bid. 556. activities on the
OCS that are under
the authority of
BOEM.
------------------------------------------------------------------------
Part 259--Mineral Leasing: Definitions--Moved to BOEM in Its Entirety,
Chapter V Part 559
[[Page 64453]]
Table H--Detailed Table for Part 259
------------------------------------------------------------------------
Implementing
Current citation and BSEE bureau and BOEM
citation (if applicable) citation (if Explanation
applicable)
------------------------------------------------------------------------
Sec. 259.001 Purpose and Moved to BOEM, This section
scope. Sec. 559.001. addresses
definitions used in
lease administration
under the authority
of BOEM.
Sec. 259.002 Definitions.... Moved to BOEM, This section used in
Sec. 559.002. lease administration
under the authority
of BOEM.
------------------------------------------------------------------------
Part 260--Outer Continental Shelf Oil and Gas Leasing--Moved to BOEM in
Its Entirety, Chapter V, Part 560
BOEM is responsible for lease sales, bidding systems, the
regulatory oversight of incentive-based royalty relief and establishing
royalty relief thresholds.
Table I--Detailed Table for Part 260
------------------------------------------------------------------------
Implementing
Current citation and BSEE bureau and BOEM
citation (if applicable) citation (if Explanation
applicable)
------------------------------------------------------------------------
Subpart A--General Provisions
------------------------------------------------------------------------
Sec. 260.1 What is the Moved to BOEM, This section
purpose of this part? Sec. 560.1. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 260.2 What definitions Moved to BOEM, This section
apply to this part? Sec. 560.2. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 260.3 What is MMS's Moved to BOEM, This section
authority to collect Sec. 560.3. addresses leasing
information? activities on the
OCS that are under
the authority of
BOEM.
------------------------------------------------------------------------
Subpart B--Bidding Systems
------------------------------------------------------------------------
Sec. 260.101 What is the Moved to BOEM, This section
purpose of this subpart? Sec. 560.101. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 260.102 What Moved to BOEM, This section
definitions apply to this Sec. 560.102. addresses leasing
subpart? activities on the
OCS that are under
the authority of
BOEM.
Sec. 260.110 What bidding Moved to BOEM, This section
systems may MMS use? Sec. 560.110. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 260.111 What conditions Moved to BOEM, This section
apply to the bidding systems Sec. 560.111. addresses leasing
that MMS uses? activities on the
OCS that are under
the authority of
BOEM.
Sec. 260.112 How do royalty Moved to BOEM, This section
suspension volumes apply to Sec. 560.112. addresses leasing
eligible leases? activities on the
OCS that are under
the authority of
BOEM.
Sec. 260.113 When does an Moved to BOEM, This section
eligible lease qualify for a Sec. 560.113. addresses leasing
royalty suspension volume? activities on the
OCS that are under
the authority of
BOEM.
Sec. 260.114 How does MMS Moved to BOEM, This section
assign and monitor royalty Sec. 560.114. addresses leasing
suspension volumes for activities on the
eligible leases? OCS that are under
the authority of
BOEM.
Sec. 260.115 How long will a Moved to BOEM, This section
royalty suspension volume for Sec. 560.115. addresses leasing
an eligible lease be activities on the
effective? OCS that are under
the authority of
BOEM.
Sec. 260.116 How do I Moved to BOEM, This section
measure natural gas Sec. 560.116. addresses leasing
production on my eligible activities on the
lease? OCS that are under
the authority of
BOEM.
Sec. 260.120 How does Moved to BOEM, This section
royalty suspension apply to Sec. 560.120. addresses leasing
leases issued in a sale held activities on the
after November 2000? OCS that are under
the authority of
BOEM.
Sec. 260.121 When does a Moved to BOEM, This section
lease issued in a sale held Sec. 560.121. addresses leasing
after November 2000 get a activities on the
royalty suspension? OCS that are under
the authority of
BOEM.
Sec. 260.122 How long will a Moved to BOEM, This section
royalty suspension volume be Sec. 560.122. addresses leasing
effective for a lease issued activities on the
in a sale held after November OCS that are under
2000? the authority of
BOEM.
Sec. 260.123 How do I Moved to BOEM, This section
measure natural gas Sec. 560.123. addresses leasing
production for a lease issued activities on the
in a sale held after November OCS that are under
2000? the authority of
BOEM.
[[Page 64454]]
Sec. 260.124 How will Moved to BOEM, This section
royalty suspension apply if Sec. 560.124. addresses leasing
MMS assigns a lease issued in activities on the
a sale held after November OCS that are under
2000 to a field that has a the authority of
pre-Act lease? BOEM.
Sec. 260.130 What criteria Moved to BOEM, This section
does MMS use for selecting Sec. 560.130. addresses leasing
bidding systems and bidding activities on the
system components? OCS that are under
the authority of
BOEM.
------------------------------------------------------------------------
Subpart C--[Reserved]
------------------------------------------------------------------------
Subpart D--Joint Bidding
------------------------------------------------------------------------
Sec. 260.301 What is the Moved to BOEM, This section
purpose of this subpart? Sec. 560.301. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
Sec. 260.302 What Moved to BOEM, This section
definitions apply to this Sec. 560.302. addresses leasing
subpart? activities on the
OCS that are under
the authority of
BOEM.
Sec. 260.303 What are the Moved to BOEM, This section
joint bidding requirements? Sec. 560.303. addresses leasing
activities on the
OCS that are under
the authority of
BOEM.
------------------------------------------------------------------------
Part 270--Nondiscrimination in the Outer Continental Shelf
Both BOEM and BSEE will have this part in its entirety.
Table J--Detailed Table for Part 270
------------------------------------------------------------------------
Implementing
Current citation and BSEE bureau and BOEM
citation (if applicable) citation (if Explanation
applicable)
------------------------------------------------------------------------
Sec. 270.1 Purpose.......... Revised in both This section
BSEE and BOEM addresses the
Sec. 570.1. nondiscrimination on
the OCS provisions
that are relevant to
the activities
regulated by both
BSEE and BOEM.
Sec. 270.2 Application of Revised in both This section
this part. BSEE and BOEM addresses the
Sec. 570.2. nondiscrimination on
the OCS provisions
that are under the
authority of both
BSEE and BOEM.
Sec. 270.3 Definitions...... Revised in both This section
BSEE and BOEM addresses the
Sec. 570.3. nondiscrimination on
the OCS provisions
that are under the
authority of both
BSEE and BOEM.
Sec. 270.4 Discrimination Revised in both This section
prohibited. BSEE and BOEM addresses the
Sec. 570.4. nondiscrimination on
the OCS provisions
that are under the
authority of both
BSEE and BOEM.
Sec. 270.5 Complaint........ Revised in both This section
BSEE and BOEM addresses the
Sec. 570.5. nondiscrimination on
the OCS provisions
that are under the
authority of both
BSEE and BOEM.
Sec. 270.6 Process.......... Revised in both This section
BSEE and BOEM addresses the
Sec. 570.6. nondiscrimination on
the OCS provisions
that are under the
authority of both
BSEE and BOEM.
Sec. 270.7 Remedies......... Revised in both This section
BSEE and BOEM addresses the
Sec. 570.7. nondiscrimination on
the OCS provisions
that are under the
authority of both
BSEE and BOEM.
------------------------------------------------------------------------
Part 280--Prospecting for Minerals Other Than Oil, Gas, and Sulphur
on the Outer Continental Shelf--Moved to BOEM in Its Entirety, Chapter
V, Part 580
BOEM is responsible for regulating prospecting activities or
scientific research activities on the OCS related to hard minerals on
unleased lands or on lands under lease to a third party.
Table K--Detailed Table for Part 280
------------------------------------------------------------------------
Current citation and Implementing bureau
BSEE citation (if and BOEM citation (if Explanation
applicable) applicable)
------------------------------------------------------------------------
Subpart A--General Information
------------------------------------------------------------------------
Sec. 280.1 What Moved to BOEM, Sec. This section addresses
definitions apply to 580.1. activities within the
this part? scope of oil, gas, and
sulphur prospecting on
the OCS under BOEM.
Sec. 280.2 What is Moved to BOEM, Sec. This section addresses
the purpose of this 580.2. activities within the
part? scope of oil, gas and
sulphur prospecting on
the OCS under BOEM.
[[Page 64455]]
Sec. 280.3 What Moved to BOEM, Sec. This section addresses
requirements must I 580.3. activities within the
follow when I conduct scope of oil, gas, and
prospecting or sulphur prospecting on
research activities? the OCS under BOEM.
Sec. 280.4 What Moved to BOEM, Sec. This section addresses
activities are not 580.4. activities within the
covered by this part? scope of oil, gas, and
sulphur prospecting on
the OCS under BOEM.
------------------------------------------------------------------------
Subpart B--How To Apply for a Permit or File a Notice
------------------------------------------------------------------------
Sec. 280.10 What Moved to BOEM, Sec. This section addresses
must I do before I 580.10. activities within the
may conduct scope of oil, gas, and
prospecting sulphur prospecting on
activities? the OCS under BOEM.
Sec. 280.11 What Moved to BOEM, Sec. This section addresses
must I do before I 580.11. activities within the
may conduct scope of oil, gas, and
scientific research? sulphur prospecting on
the OCS under BOEM.
Sec. 280.12 What Moved to BOEM, Sec. This section addresses
must I include in my 580.12. activities within the
application or scope of oil, gas, and
notification? sulphur prospecting on
the OCS under BOEM.
Sec. 280.13 Where Moved to BOEM, Sec. This section addresses
must I send my 580.13. activities within the
application or scope of oil, gas, and
notification? sulphur prospecting on
the OCS under BOEM.
------------------------------------------------------------------------
Subpart C--Obligations Under This Part
------------------------------------------------------------------------
Sec. 280.20 What Moved to BOEM, Sec. This section addresses
must I not do in 580.20. activities within the
conducting Geological scope of oil, gas, and
and Geophysical (G&G) sulphur prospecting on
prospecting or the OCS under BOEM.
scientific research?
Sec. 280.21 What Moved to BOEM, Sec. This section addresses
must I do in 580.21. activities within the
conducting G&G scope of oil, gas, and
prospecting or sulphur prospecting on
scientific research? the OCS under BOEM.
Sec. 280.22 What Moved to BOEM, Sec. This section addresses
must I do when 580.22. activities within the
seeking approval for scope of oil, gas, and
modifications? sulphur prospecting on
the OCS under BOEM.
Sec. 280.23 How must Moved to BOEM, Sec. This section addresses
I cooperate with 580.23. activities within the
inspection scope of oil, gas, and
activities? sulphur prospecting on
the OCS under BOEM.
Sec. 280.24 What Moved to BOEM, Sec. This section addresses
reports must I file? 580.24. activities within the
scope of oil, gas, and
sulphur prospecting on
the OCS under BOEM.
Sec. 280.25 When may Moved to BOEM, Sec. This section addresses
MMS require me to 580.25. activities within the
stop activities under scope of oil, gas, and
this part? sulphur prospecting on
the OCS under BOEM.
Sec. 280.26 When may Moved to BOEM, Sec. This section addresses
I resume activities? 580.26. activities within the
scope of oil, gas, and
sulphur prospecting on
the OCS under BOEM.
Sec. 280.27 When may In both BSEE and This section addresses
MMS cancel my permit? BOEM, Sec. 580.27. activities within the
scope of oil, gas, and
sulphur prospecting on
the OCS under BOEM.
Sec. 280.28 May I In both BSEE and This section addresses
relinquish my permit? BOEM, Sec. 580.28. activities within the
scope of oil, gas, and
sulphur prospecting on
the OCS under BOEM.
Sec. 280.29 Will MMS Moved to BOEM, Sec. This section addresses
monitor the 580.29. activities within the
environmental effects scope of oil, gas, and
of my activity? sulphur prospecting on
the OCS under BOEM.
Sec. 280.30 What Moved to BOEM, Sec. This section addresses
activities will not 580.30. activities within the
require environmental scope of oil, gas, and
analysis? sulphur prospecting on
the OCS under BOEM.
Sec. 280.31 Whom Moved to BOEM, Sec. This section addresses
will MMS notify about 580.31. activities within the
environmental issues? scope of oil, gas, and
sulphur prospecting on
the OCS under BOEM.
Sec. 280.32 What Moved to BOEM, Sec. This section addresses
penalties may I be 580.32. activities within the
subject to? scope of oil, gas, and
sulphur prospecting on
the OCS under BOEM.
Sec. 280.33 How can Moved to BOEM, Sec. This section addresses
I appeal a penalty? 580.33. activities within the
scope of oil, gas, and
sulphur prospecting on
the OCS under BOEM.
Sec. 280.34 How can Moved to BOEM, Sec. This section addresses
I appeal an order or 580.34. activities within the
decision? scope of oil, gas, and
sulphur prospecting on
the OCS under BOEM.
------------------------------------------------------------------------
Subpart D--Data Requirements
------------------------------------------------------------------------
Sec. 280.40 When do Moved to BOEM, Sec. This section addresses
I notify MMS that 580.40. activities within the
geological data and scope of oil, gas, and
information are sulphur prospecting on
available for the OCS under BOEM.
submission,
inspection, and
selection?
Sec. 280.41 What Moved to BOEM, Sec. This section addresses
types of geological 580.41. activities within the
data and information scope of oil, gas, and
must I submit to MMS? sulphur prospecting on
the OCS under BOEM.
Sec. 280.42 When Moved to BOEM, Sec. This section addresses
geological data and 580.42. activities within the
information are scope of oil, gas, and
obtained by a third sulphur prospecting on
party, what must we the OCS under BOEM.
both do?
[[Page 64456]]
Sec. 280.50 When do Moved to BOEM, Sec. This section addresses
I notify MMS that 580.50. activities within the
geophysical data and scope of oil, gas, and
information are sulphur prospecting on
available for the OCS under BOEM.
submission,
inspection, and
selection?
Sec. 280.51 What Moved to BOEM, Sec. This section addresses
types of geophysical 580.51. activities within the
data and information scope of oil, gas, and
must I submit to MMS? sulphur prospecting on
the OCS under BOEM.
Sec. 280.52 When Moved to BOEM, Sec. This section addresses
geophysical data and 580.52. activities within the
information are scope of oil, gas, and
obtained by a third sulphur prospecting on
party, what must we the OCS under BOEM.
both do?
Sec. 280.60 Which of Moved to BOEM, Sec. This section addresses
my costs will be 580.60. activities within the
reimbursed? scope of oil, gas, and
sulphur prospecting on
the OCS under BOEM.
Sec. 280.61 Which of Moved to BOEM, Sec. This section addresses
my costs will not be 580.61. activities within the
reimbursed? scope of oil, gas, and
sulphur prospecting on
the OCS under BOEM.
Sec. 280.70 What Moved to BOEM, Sec. This section addresses
data and information 580.70. activities within the
will be protected scope of oil, gas, and
from public sulphur prospecting on
disclosure? the OCS under BOEM.
Sec. 280.71 What is Moved to BOEM, Sec. This section addresses
the timetable for 580.71. activities within the
release of data and scope of oil, gas, and
information? sulphur prospecting on
the OCS under BOEM.
Sec. 280.72 What Moved to BOEM, Sec. This section addresses
procedure will MMS 580.72. activities within the
follow to disclose scope of oil, gas, and
acquired data and sulphur prospecting on
information to a the OCS under BOEM.
contractor for
reproduction,
processing, and
interpretation?
Sec. 280.73 Will MMS Moved to BOEM, Sec. This section addresses
share data and 580.73. activities within the
information with scope of oil, gas, and
coastal States? sulphur prospecting on
the OCS under BOEM.
------------------------------------------------------------------------
Subpart E--Information Collection
------------------------------------------------------------------------
Sec. 280.80 Moved to BOEM, Sec. This section addresses
Paperwork Reduction 580.80. activities within the
Act statement-- scope of oil, gas and
information sulphur prospecting on
collection the OCS under BOEM.
------------------------------------------------------------------------
Part 281--Leasing of Minerals Other Than Oil, Gas, and Sulphur in the
Outer Continental Shelf--Moved to BOEM in Its Entirety, Chapter V, Part
581
The Office of Natural Resources Revenue (ONRR) is the office that
has the authority to determine the value for royalty purposes of
minerals and other products produced on the OCS under Secretarial Order
No. 3299. Because ONRR is responsible for valuation, technical
corrections were made to this part to reflect that authority. This rule
does not change the valuation authority possessed by ONRR or the
procedures by which that authority is implemented. It merely revises
the references in the regulations to conform to those in current
Secretarial delegations. It has no effect on the rights, obligations,
or interests of affected parties. It affects solely the organization,
procedure, and practice of the agencies.
Table L--Detailed Table for Part 281
------------------------------------------------------------------------
Implementing
Current citation and BSEE bureau and BOEM
citation (if applicable) citation (if Explanation
applicable)
------------------------------------------------------------------------
Subpart A--General
------------------------------------------------------------------------
Sec. 281.0 Authority for Moved to BOEM, This section
information collection. Sec. 581.0. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
Sec. 281.1 Purpose and Moved to BOEM, This section
applicability. Sec. 581.1. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
Sec. 281.2 Authority........ Moved to BOEM, This section
Sec. 581.2. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
Sec. 281.3 Definitions...... Moved to BOEM, This section
Sec. 581.3. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
Sec. 281.4 Qualifications of Moved to BOEM, This section
lessees. Sec. 581.4. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
Sec. 281.5 False statements. Moved to BOEM, This section
Sec. 581.5. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
Sec. 281.6 Appeals.......... Moved to BOEM, This section
Sec. 581.6. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
Sec. 281.7 Disclosure of Moved to BOEM, This section
information to the public. Sec. 581.7. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
[[Page 64457]]
Sec. 281.8 Rights to Moved to BOEM, This section
minerals. Sec. 581.8. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
Sec. 281.9 Jurisdictional Moved to BOEM, This section
controversies. Sec. 581.9. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
------------------------------------------------------------------------
Subpart B--Leasing Procedures
------------------------------------------------------------------------
Sec. 281.11 Unsolicited Moved to BOEM, This section
request for a lease sale. Sec. 581.11. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
Sec. 281.12 Request for OCS Moved to BOEM, This section
mineral information and Sec. 581.12. addresses activities
interest. within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
Sec. 281.13 Joint State/ Moved to BOEM, This section
Federal coordination. Sec. 581.13. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
Sec. 281.14 OCS mining area Moved to BOEM, This section
identification. Sec. 581.14. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
Sec. 281.15 Tract size...... Moved to BOEM, This section
Sec. 581.15. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
Sec. 281.16 Proposed leasing Moved to BOEM, This section
notice. Sec. 581.16. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
Sec. 281.17 Leasing notice.. Moved to BOEM, This section
Sec. 581.17. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
Sec. 281.18 Bidding system.. Moved to BOEM, This section
Sec. 581.18. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
Sec. 281.19 Lease term...... Moved to BOEM, This section
Sec. 581.19. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
Sec. 281.20 Submission of Moved to BOEM, This section
bids. Sec. 581.20. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
Sec. 281.21 Award of leases. Moved to BOEM, This section
Sec. 581.21. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
Sec. 281.22 Lease form...... Moved to BOEM, This section
Sec. 581.22. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
Sec. 281.23 Effective date Moved to BOEM, This section
of leases. Sec. 581.23. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
------------------------------------------------------------------------
Subpart C--Financial Considerations
------------------------------------------------------------------------
Sec. 281.26 Payments........ Moved to BOEM, This section
Sec. 581.26. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
Sec. 281.27 Annual rental... Moved to BOEM, This section
Sec. 581.27. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
Sec. 281.28 Royalty......... Moved to BOEM, This section
Sec. 581.28. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
Sec. 281.29 Royalty Moved to BOEM, This section
valuation. Sec. 581 29. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
Sec. 281.30 Minimum royalty. Moved to BOEM, This section
Sec. 581.30. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
Sec. 281.31 Overriding Moved to BOEM, This section
royalties. Sec. 581.31. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
Sec. 281.32 Waiver, Moved to BOEM, This section
suspension, or reduction of Sec. 581.32. addresses activities
rental, minimum royalty or within the scope of
production royalty. leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
Sec. 281.33 Bonds and Moved to BOEM, This section
bonding requirements. Sec. 581.33. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
------------------------------------------------------------------------
Subpart D--Assignments and Lease Extensions
------------------------------------------------------------------------
Sec. 281.40 Assignment of Moved to BOEM, This section
leases or interests therein. Sec. 581.40. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
Sec. 281.41 Requirements for Moved to BOEM, This section
filing for transfers. Sec. 581.41. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
Sec. 281.42 Effect of Moved to BOEM, This section
assignment on particular Sec. 581.42. addresses activities
lease. within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
Sec. 281.43 Effect of Moved to BOEM, This section
suspensions on lease term. Sec. 581.43. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
------------------------------------------------------------------------
Subpart E--Termination of Leases
------------------------------------------------------------------------
Sec. 281.46 Relinquishment Moved to BOEM, This section
of leases or parts of leases. Sec. 581.46. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
Sec. 281.47 Cancellation of Moved to BOEM, This section
leases. Sec. 581.47. addresses activities
within the scope of
leasing of minerals
other than oil, gas,
and sulphur on the
OCS under BOEM.
------------------------------------------------------------------------
[[Page 64458]]
Part 282--Operations in the Outer Continental Shelf for Minerals Other
Than Oil, Gas, and Sulphur
Both BOEM and BSEE have responsibilities for operations conducted
under a mineral lease for OCS minerals other than oil, gas, or sulphur.
As stated previously, ONRR has the authority to determine the value
for royalty purposes of minerals and other products produced on the OCS
under Secretarial Order No. 3299. Because ONRR is the office
responsible for valuation, technical corrections were made to this part
to reflect that authority. This rule does not change the valuation
authority possessed by ONRR or the procedures by which that authority
is implemented. It merely revises the references in the regulations to
conform to those in current Secretarial delegations. It has no effect
on the rights, obligations, or interests of affected parties. It
affects solely the organization, procedure, and practice of the
agencies.
These responsibilities were divided between the bureaus as follows:
Table M--Detailed Table for Part 282
------------------------------------------------------------------------
Implementing
Current citation and BSEE bureau and BOEM
citation (if applicable) citation (if Explanation
applicable)
------------------------------------------------------------------------
Subpart A--General
------------------------------------------------------------------------
Sec. 282.0 Authority for Both BSEE and Both agencies need
information collection. BOEM Sec. the authority for
582.0. information
collection.
Sec. 282.1 Purpose and Both BSEE and Needed by both
authority. BOEM Sec. agencies.
582.1.
Sec. 282.2 Scope............ Both BSEE and Needed by both
BOEM Sec. agencies.
582.2.
Sec. 282.3 Definitions...... Both BSEE and Needed by both
BOEM Sec. agencies.
582.3.
Sec. 282.4 Opportunities for Moved to BOEM, BOEM responsibility.
review and comment. Sec. 582.4.
Sec. 282.5 Disclosure of Both BSEE and Needed by both
data and information to the BOEM Sec. agencies.
public. 582.5.
Sec. 282.6 Disclosure of Both BSEE and Needed by both
data and information to an BOEM Sec. agencies.
adjacent State. 582.6.
Sec. 282.7 Jurisdictional Both BSEE and Needed by both
controversies. BOEM Sec. agencies.
582.7.
------------------------------------------------------------------------
Subpart B--Jurisdiction and Responsibilities of Director
------------------------------------------------------------------------
Sec. 282.10 Jurisdiction and Both BSEE and Needed by both
responsibilities of Director. BOEM Sec. agencies.
582.10.
Sec. 282.11 Director's Moved to BOEM, Paragraph (d)
authority. Sec. 582.11. involves units,
Paragraph (d) on which is a BSEE
mining units is function. Paragraph
in both. (d) also contains
BOEM
responsibilities as
it mentions plans.
Sec. 282.12 Director's Responsibilities Paragraphs (a), (e),
responsibilities. are shared by (f), and (h) are
both BSEE and retained in BSEE.
BOEM. Paragraphs (a), (b),
(c), (d) and (g) are
in BOEM. This
section contains,
but is not limited
to, general
statements on the
Director's
responsibilities;
language on mining
plan approvals,
delineation testing
and lease
operations; and
conditions under
which the Director
may prescribe or
approve departures.
Sec. 282.13 Suspension of Retained in BSEE. Suspensions are under
production or other the authority of
operations. BSEE.
Sec. 282.14 Noncompliance, Both BSEE and BSEE is responsible
remedies, and penalties. BOEM Sec. for addressing
582.14. noncompliance,
remedies, and
penalties. Needed in
both agencies.
Sec. 282.15 Cancellation of Moved to BOEM, BOEM is responsible
leases. Sec. 582.15. for lease
administration.
------------------------------------------------------------------------
Subpart C--Obligations and Responsibilities of Lessees
------------------------------------------------------------------------
Sec. 282.20 Obligations and Moved to BOEM, This section
responsibilities of lessees. Sec. 582.20. addresses
obligations and
responsibilities of
lessees that are the
responsibility of
BOEM.
Sec. 282.21 Plans, general.. Moved to BOEM, This section
Sec. 582.21, addresses plans that
except paragraph are the
(e), which is in responsibility of
both. BOEM. Paragraph (e)
addresses leasehold
activities and how
those activities
must be carried out.
Leasehold activities
are generally
operational in
nature (i.e.,
drilling,
production) and
therefore these
responsibilities are
also vested in BSEE.
Sec. 282.22 Delineation Plan Moved to BOEM, This section
Sec. 582.22. addresses plans that
are the
responsibility of
BOEM.
Sec. 282.23 Testing Plan.... Moved to BOEM, This section
Sec. 582.23. addresses plans that
are the
responsibility of
BOEM.
Sec. 282.24 Mining Plan..... Moved to BOEM, This section
Sec. 582.24. addresses plans that
are the
responsibility of
BOEM.
Sec. 282.25 Plan Moved to BOEM, This section
modification. Sec. 582.25. addresses plans that
are the
responsibility of
BOEM.
Sec. 282.26 Contingency Plan Moved to BOEM, This section
Sec. 582.26. addresses plans that
are the
responsibility of
BOEM.
Sec. 282.27 Conduct of Retained in BSEE. Paragraph (i)
operations. Paragraph (i) addresses plans that
also in BOEM, are the
Sec. 582.27. responsibility of
BOEM.
Sec. 282.28 Environmental Moved to BOEM Paragraphs (c)(1),
protection measures. Sec. 582.28. (c)(3) and (c)(4)
Paragraphs pertain to
(c)(1), (c)(2), mitigation,
(c)(3), (c)(4) observations, and
and (c)(6), and testing activities.
(d) are retained Paragraph (d)
in BSEE. describes ways to
Paragraphs minimize
(c)(2) and environmental
(c)(6) are in impacts. Overseeing
both. these activities is
a BSEE
responsibility. Both
BOEM and BSEE have
discrete monitoring
functions under
(c)(2) and (c)(6).
Sec. 282.29 Reports and Moved to BOEM, A resource evaluation
records. Sec. 582.29. function under BOEM.
Sec. 282.30 Right of use and Moved to BOEM, BOEM has the
easement. Sec. 582.30. authority to grant
rights of use and
easement.
[[Page 64459]]
Sec. 282.31 Suspension of Retained in BSEE. BSEE has the
production or other authority to suspend
operations. production or other
operations.
------------------------------------------------------------------------
Subpart D--Payments
------------------------------------------------------------------------
Sec. 282.40 Bonds........... Moved to BOEM, Financial assurance
Sec. 582.40. is a BOEM function
with a cross
reference provided
for BSEE.
Sec. 282.41 Method of Both BSEE and ONRR regulations at
royalty calculation. BOEM, Sec. 30 CFR part 1206 may
582.41. apply. Otherwise,
lessees must comply
with BOEM's
procedures specified
in lease notices.
Sec. 282.42 Payments........ Moved to BOEM, BOEM.
Sec. 582.42.
------------------------------------------------------------------------
Subpart E--Appeals
------------------------------------------------------------------------
Sec. 282.50 Appeals......... Both BSEE and Both agencies need
BOEM, Sec. the procedures for
582.50. addressing appeals.
------------------------------------------------------------------------
Part 285--Renewable Energy Alternate Uses of Existing Facilities on the
Outer Continental Shelf--Moved in Its Entirety to BOEM, Chapter V, Part
585
BOEM will manage the Renewable Energy Program for the near future.
Once this program is more established and larger scale operations
begin, it will be reorganized and a determination will be made
regarding what functions will be distributed between the two bureaus;
BSEE and BOEM.
Subchapter C--Appeals
Part 290--Appeals Procedures--Both BSEE and BOEM Will Have This Part in
Its Entirety
Table N--Detailed Table for Part 290
------------------------------------------------------------------------
Current citation and Implementing bureau
BSEE citation (if and BOEM citation (if Explanation
applicable) applicable)
------------------------------------------------------------------------
Subpart A--Offshore Minerals Management Appeal Procedures
------------------------------------------------------------------------
Sec. 290.1 What is Both BSEE and BOEM Both BSEE and BOEM need
the purpose of this Sec. 590.1. to provide opportunity
subpart? for appeals of
decisions.
Sec. 290.2 Who may Both BSEE and BOEM Both BSEE and BOEM need
appeal? Sec. 590.2. to provide opportunity
for appeals of
decisions.
Sec. 290.3 What is Both BSEE and BOEM Both BSEE and BOEM. need
the time limit for Sec. 590.3. to provide opportunity
filing an appeal? for appeals of
decisions.
Sec. 290.4 How do I Both BSEE and BOEM Both BSEE and BOEM need
file an appeal? Sec. 590.4. to provide opportunity
for appeals of
decisions.
Sec. 290.5 Can I Both BSEE and BOEM Both BSEE and BOEM need
obtain an extension Sec. 590.5. to provide opportunity
for filing my Notice for appeals of
of Appeal? decisions.
Sec. 290.6 Are Both BSEE and BOEM Both BSEE and BOEM need
informal resolutions Sec. 590.6. to provide opportunity
permitted? for appeals of
decisions.
Sec. 290.7 Do I have Both BSEE and BOEM Both BSEE and BOEM need
to comply with the Sec. 590.7. to provide opportunity
decision or order for appeals of
while my appeal is decisions.
pending?
Sec. 290.8 How do I Both BSEE and BOEM Both BSEE and BOEM need
exhaust my Sec. 590.8. to provide opportunity
administrative for appeals of
remedies? decisions.
------------------------------------------------------------------------
Subpart B--[Reserved]
------------------------------------------------------------------------
Part 291--Open and Nondiscriminatory Access to Oil and Gas Pipelines
Under the Outer Continental Shelf Lands Act--Retained by BSEE in Its
Entirety
Table O--Detailed Table for Part 291
------------------------------------------------------------------------
Implementing
Current citation and BSEE bureau and BOEM
citation (if applicable) citation (if Justification
applicable)
------------------------------------------------------------------------
SUBCHAPTER C--APPEALS
------------------------------------------------------------------------
Sec. 291.1 What is MMS's Retained in its This section
authority to collect entirety in addresses
information? BSEE, chapter II. information
collection authority
for open and
nondiscriminatory
access to oil and
gas pipelines under
OCSLA. Offshore
operations are under
the authority of
BSEE.
[[Page 64460]]
Sec. 291.100 What is the Retained in its This section
purpose of this part? entirety in addresses purpose of
BSEE, chapter II. open and
nondiscriminatory
access to oil and
gas pipelines under
OCSLA. Offshore
operations are under
the authority of
BSEE.
Sec. 291.101 What Retained in its This section
definitions apply to this entirety in addresses the
part? BSEE, chapter II. definitions that
pertain to open and
nondiscriminatory
access to oil and
gas pipelines under
OCSLA. Offshore
operations are under
the authority of
BSEE.
Sec. 291.102 May I call the Retained in its This section
MMS Hotline to informally entirety in addresses open and
resolve an allegation that BSEE, chapter II. nondiscriminatory
open and nondiscriminatory access to oil and
access was denied? gas pipelines under
OCSLA. Offshore
operations are under
the authority of
BSEE.
Sec. 291.103 May I use Retained in its This section
alternative dispute entirety in addresses open and
resolution to informally BSEE, chapter II. nondiscriminatory
resolve an allegation that access to oil and
open and nondiscriminatory gas pipelines under
access was denied? OCSLA. Offshore
operations are under
the authority of
BSEE.
Sec. 291.104 Who may file a Retained in its This section
complaint or a third-party entirety in addresses open and
brief? BSEE, chapter II. nondiscriminatory
access to oil and
gas pipelines under
OCSLA. Offshore
operations are under
the authority of
BSEE.
Sec. 291.105 What must a Retained in its This section
complaint contain? entirety in addresses open and
BSEE, chapter II. nondiscriminatory
access to oil and
gas pipelines under
OCSLA. Offshore
operations are under
the authority of
BSEE.
Sec. 291.106 How do I file a Retained in its This section
complaint? entirety in addresses open and
BSEE, chapter II. nondiscriminatory
access to oil and
gas pipelines under
OCSLA. Offshore
operations are under
the authority of
BSEE.
Sec. 291.107 How do I answer Retained in its This section
a complaint? entirety in addresses open and
BSEE, chapter II. nondiscriminatory
access to oil and
gas pipelines under
OCSLA. Offshore
operations are under
the authority of
BSEE.
Sec. 291.108 How do I pay Retained in its This section
the processing fee? entirety in addresses open and
BSEE, chapter II. nondiscriminatory
access to oil and
gas pipelines under
OCSLA. Offshore
operations are under
the authority of
BSEE.
Sec. 291.109 Can I ask for a Retained in its This section
fee waiver or a reduced entirety in addresses open and
processing fee? BSEE, chapter II. nondiscriminatory
access to oil and
gas pipelines under
OCSLA. Offshore
operations are under
the authority of
BSEE.
Sec. 291.110 Who may MMS Retained in its This section
require to produce entirety in addresses open and
information? BSEE, chapter II. nondiscriminatory
access to oil and
gas pipelines under
OCSLA. Offshore
operations are under
the authority of
BSEE.
Sec. 291.111 How does MMS Retained in its This section
treat the confidential entirety in addresses open and
information I provide? BSEE, chapter II. nondiscriminatory
access to oil and
gas pipelines under
OCSLA. Offshore
operations are under
the authority of
BSEE.
Sec. 291.112 What process Retained in its This section
will MMS follow in rendering entirety in addresses open and
a decision on whether a BSEE, chapter II. nondiscriminatory
grantee or transporter has access to oil and
provided open and gas pipelines under
nondiscriminatory access? OCSLA. Offshore
operations are under
the authority of
BSEE.
Sec. 291.113 What actions Retained in its This section
may MMS take to remedy denial entirety in addresses open and
of open and nondiscriminatory BSEE, chapter II. nondiscriminatory
access? access to oil and
gas pipelines under
OCSLA. Offshore
operations are under
the authority of
BSEE.
Sec. 291.114 How do I appeal Retained in its This section
to the IBLA? entirety in addresses open and
BSEE, chapter II. nondiscriminatory
access to oil and
gas pipelines under
OCSLA. Offshore
operations are under
the authority of
BSEE.
Sec. 291.115 How do I Retained in its This section
exhaust administrative entirety in addresses open and
remedies? BSEE, chapter II. nondiscriminatory
access to oil and
gas pipelines under
OCSLA. Offshore
operations are under
the authority of
BSEE.
------------------------------------------------------------------------
Procedural Matters
Regulatory Planning and Review (Executive Order (E.O.) 12866)
This direct final rule is not a significant rule as determined by
the Office of Management and Budget (OMB) and is not subject to review
under E.O. 12866. This direct final rule reorganizes the title 30 CFR
chapter II regulations; this rule does not change existing regulatory
requirements.
(1) This direct final rule will not have an annual effect of $100
million or more on the economy. It will not adversely affect in a
material way the economy, productivity, competition: jobs; the
environment; public health or safety; or state, local, or Tribal
governments or communities.
(2) This direct final rule will not create a serious inconsistency
or otherwise interfere with an action taken or planned by another
agency.
(3) This direct final rule will not alter the budgetary effects of
entitlements, grants, user fees, or loan programs or the rights or
obligations of their recipients.
(4) This direct final rule will not raise novel legal or policy
issues arising out of legal mandates, the President's priorities, or
the principles set forth in E.O. 12866.
Regulatory Flexibility Act
This direct final rule is exempt from the notice and comment
provisions of
[[Page 64461]]
the Administrative Procedure Act (APA), 5 U.S.C. 553; therefore, the
requirements of the Regulatory Flexibility Act do not apply, 5 U.S.C.
603(a).
Small Business Regulatory Enforcement Fairness Act
This direct final rule is not a major rule under the Small Business
Regulatory Enforcement Fairness Act (5 U.S.C. 801 et seq.). This direct
final rule:
a. Will not have an annual effect on the economy of $100 million or
more.
b. Will not cause a major increase in costs or prices for
consumers; individual industries; Federal, state, or local government
agencies; or geographic regions.
c. Will not have significant adverse effects on competition,
employment, investment, productivity, innovation, or the ability of
U.S.-based enterprises to compete with foreign-based enterprises.
The requirements apply to all entities operating on the OCS. This
direct final rule reorganizes the title 30 CFR chapter II regulations
and does not change existing regulatory requirements.
Unfunded Mandates Reform Act of 1995
This direct final rule will not impose an unfunded mandate on
state, local, or Tribal governments, or the private sector of more than
$100 million per year. This direct final rule will not have a
significant or unique effect on state, local, or Tribal governments, or
the private sector. A statement containing the information required by
the Unfunded Mandates Reform Act (2 U.S.C. 1501 et seq.) is not
required.
Takings Implication Assessment (E.O. 12630)
Under the criteria in E.O. 12630, this direct final rule does not
have significant takings implications. This direct final 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 direct final rule does not
have federalism implications. This direct final rule will 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 direct final rule will not affect
that role. A Federalism Assessment is not required.
Civil Justice Reform (E.O. 12988)
This direct final rule complies with the requirements of E.O.
12988. Specifically, this rule:
(a) Meets the criteria of section 3(a) requiring that all
regulations be reviewed to eliminate errors and ambiguity and be
written to minimize litigation; and
(b) Meets the criteria of section 3(b)(2) requiring that all
regulations be written in clear language and contain clear legal
standards.
Consultation With Indian Tribes (E.O. 13175)
Under the criteria in E.O. 13175, we have evaluated this direct
final rule and determined that it has no substantial effects on
federally recognized Indian Tribes.
Paperwork Reduction Act (PRA) of 1995
This final rule does not contain new information collection
requirements, and a submission to OMB is not required under 44 U.S.C.
3501 et seq. All information collections referred to in this rulemaking
are in the 1010 numbering series and are unchanged.
National Environmental Policy Act of 1969
This rule does not constitute a major Federal action significantly
affecting the quality of the human environment. We evaluated this rule
under the criteria of the National Environmental Policy Act, 43 CFR
Part 46 and 516 Departmental Manual 15. This rule meets the criteria
set forth in 43 CFR 46.210(i) in that this proposed rule is ``* * * of
an administrative, financial, legal, technical, or procedural nature *
* *.'' This rule also meets the criteria set forth in 516 Departmental
Manual 15.4(C)(1) for a ``Categorical Exclusion'' in that its impacts
are limited to administrative, economic or technological effects.
Further, we have evaluated this proposed rule to determine if it
involves any of the extraordinary circumstances that would require an
environmental assessment or an environmental impact statement as set
forth in 43 CFR 46.215. We concluded that this rule does not meet any
of the criteria for extraordinary circumstances as set forth therein.
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 section 515, 114 Stat. 2763, 2763A-153-154).
Effects of the Nation's Energy Supply (E.O. 13211)
This direct final rule is not a significant energy action under the
definition in E.O. 13211. A Statement of Energy Effects is not
required.
List of Subjects
30 CFR Part 203
Continental shelf, Government contracts, Indians--lands, Mineral
royalties, Oil and gas exploration, Public lands--mineral resources,
Sulphur.
30 CFR Part 250
Administrative practice and procedure, Continental shelf, Oil and
gas exploration, Public lands--mineral resources, Reporting and
recordkeeping requirements.
30 CFR Part 251
Continental shelf, Freedom of information, Oil and gas exploration,
Public lands--mineral resources, Reporting and recordkeeping
requirements, Research.
30 CFR Part 252
Continental shelf, Freedom of information, Intergovernmental
relations, Oil and gas exploration, Public lands--mineral resources,
Reporting and recordkeeping requirements.
30 CFR Part 254
Continental shelf, Intergovernmental relations, Oil and gas
exploration, Oil pollution, Pipelines, Public lands--mineral resources,
Reporting and recordkeeping requirements.
30 CFR Part 256
Administrative practice and procedure, Continental shelf,
Environmental protection, Government contracts, Intergovernmental
relations, Oil and gas exploration, Public lands--mineral resources,
Public lands--rights-of-way, Reporting and recordkeeping requirements,
Surety bonds.
30 CFR Part 270
Administrative practice and procedure, Civil rights, Continental
shelf, Government contracts, Oil and gas exploration, Public lands--
mineral resources.
30 CFR Part 282
Administrative practice and procedure, Continental shelf,
Environmental protection, Government contracts, Intergovernmental
relations, Mineral royalties, Penalties, Public lands--mineral
resources, Reporting
[[Page 64462]]
and recordkeeping requirements, Surety bonds.
30 CFR Part 290
Administrative practice and procedure.
30 CFR Part 291
Administrative practice and procedure.
30 CFR Part 519
Continental shelf, Government contracts, Indians--lands, Mineral
royalties, Oil and gas exploration, Public lands--mineral resources,
Sulphur.
30 CFR Part 550
Administrative practice and procedure, Continental shelf,
Environmental impact statements, Environmental protection, Government
contracts, Investigations, Oil and gas exploration, Penalties,
Pipelines, Public lands--mineral resources, Public lands--rights-of-
way, Reporting and recordkeeping requirements, Sulphur.
30 CFR Part 551
Continental shelf, Freedom of information, Oil and gas exploration,
Public lands--mineral resources, Reporting and recordkeeping
requirements, Research.
30 CFR Part 552
Continental shelf, Freedom of information, Intergovernmental
relations, Oil and gas exploration, Public lands--mineral resources,
Reporting and recordkeeping requirements.
30 CFR Part 553
Continental shelf, Environmental protection, Intergovernmental
relations, Oil and gas exploration, Oil pollution, Penalties,
Pipelines, Public lands--mineral resources, Reporting and recordkeeping
requirements, Surety bonds.
30 CFR Part 556
Administrative practice and procedure, Continental shelf,
Environmental protection, Government contracts, Intergovernmental
relations, Oil and gas exploration, Public lands--mineral resources,
Public lands--rights-of-way, Reporting and recordkeeping requirements,
Surety bonds.
30 CFR Part 559
Continental shelf, Government contracts, Mineral royalties, Oil and
gas exploration, Public lands--mineral resources.
30 CFR Part 560
Continental shelf, Government contracts, Mineral royalties, Oil and
gas exploration, Public lands--mineral resources, Reporting and
recordkeeping requirements.
30 CFR Part 570
Administrative practice and procedure, Civil rights, Continental
shelf, Government contracts, Oil and gas exploration, Public lands--
mineral resources.
30 CFR Part 580
Continental shelf, Public lands--mineral resources, Reporting and
recordkeeping requirements, Research.
30 CFR Part 581
Administrative practice and procedure, Continental shelf,
Government contracts, Intergovernmental relations, Mineral royalties,
Public lands--mineral resources, Reporting and recordkeeping
requirements, Surety bonds.
30 CFR Part 582
Administrative practice and procedure, Continental shelf,
Environmental protection, Government contracts, Intergovernmental
relations, Mineral royalties, Penalties, Public lands--mineral
resources, Reporting and recordkeeping requirements, Surety bonds.
30 CFR Part 585
Continental shelf, Environmental protection, Incorporation by
reference, Public lands.
30 CFR Part 590
Administrative practice and procedure.
Dated: August 18, 2011.
Ned Farquhar,
Deputy Assistant Secretary--Land and Minerals Management.
For the reasons stated in the preamble, under the authority of 5
U.S.C. 901 et seq., the Bureau of Safety and Environmental Enforcement
(BSEE) reassigns chapter II and Bureau of Ocean Energy Management
(BOEM) establishes chapter V as follows:
TITLE 30--MINERAL RESOURCES
0
1. Chapter II is revised to read as follows:
CHAPTER II--BUREAU OF SAFETY AND ENVIRONMENTAL ENFORCEMENT, DEPARTMENT
OF THE INTERIOR
SUBCHAPTER A--MINERALS REVENUE MANAGEMENT
Part
203 RELIEF OR REDUCTION IN ROYALTY RATES
219 RESERVED
SUBCHAPTER B--OFFSHORE
250 OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER CONTINENTAL
SHELF
251 GEOLOGICAL AND GEOPHYSICAL (G&G) EXPLORATIONS OF THE OUTER
CONTINENTAL SHELF
252 OUTER CONTINENTAL SHELF (OCS) OIL AND GAS INFORMATION PROGRAM
253 RESERVED
254 OIL-SPILL RESPONSE REQUIREMENTS FOR FACILITIES LOCATED SEAWARD
OF THE COAST LINE
256 LEASING OF SULPHUR OR OIL AND GAS IN THE OUTER CONTINENTAL SHELF
259 RESERVED
260 RESERVED
270 NONDISCRIMINATION IN THE OUTER CONTINENTAL SHELF
280 RESERVED
281 RESERVED
282 OPERATIONS IN THE OUTER CONTINENTAL SHELF FOR MINERALS OTHER
THAN OIL, GAS, AND SULPHUR
285 RESERVED
SUBCHAPTER C--APPEALS
290 APPEAL PROCEDURES
291 OPEN AND NONDISCRIMINATORY ACCESS TO OIL AND GAS PIPELINES UNDER
THE OUTER CONTINENTAL SHELF LANDS ACT
SUBCHAPTER A--MINERALS REVENUE MANAGEMENT
PART 203--RELIEF OR REDUCTION IN ROYALTY RATES
Subpart A--General Provisions
Sec.
203.0 What definitions apply to this part?
203.1 What is BSEE's authority to grant royalty relief?
203.2 How can I obtain royalty relief?
203.3 Do I have to pay a fee to request royalty relief?
203.4 How do the provisions in this part apply to different types of
leases and projects?
203.5 What is BSEE's authority to collect information?
Subpart B--OCS Oil, Gas, and Sulfur General
Royalty Relief for Drilling Ultra-Deep Wells on Leases Not Subject to
Deep Water Royalty Relief
203.30 Which leases are eligible for royalty relief as a result of
drilling a phase 2 or phase 3 ultra-deep well?
[[Page 64463]]
203.31 If I have a qualified phase 2 or qualified phase 3 ultra-deep
well, what royalty relief would that well earn for my lease?
203.32 What other requirements or restrictions apply to royalty
relief for a qualified phase 2 or phase 3 ultra-deep well?
203.33 To which production do I apply the RSV earned by qualified
phase 2 and phase 3 ultra-deep wells on my lease or in my unit?
203.34 To which production may an RSV earned by qualified phase 2
and phase 3 ultra-deep wells on my lease not be applied?
203.35 What administrative steps must I take to use the RSV earned
by a qualified phase 2 or phase 3 ultra-deep well?
203.36 Do I keep royalty relief if prices rise significantly?
Royalty Relief for Drilling Deep Gas Wells on Leases Not Subject to
Deep Water Royalty Relief
203.40 Which leases are eligible for royalty relief as a result of
drilling a deep well or a phase 1 ultra-deep well?
203.41 If I have a qualified deep well or a qualified phase 1 ultra-
deep well, what royalty relief would my lease earn?
203.42 What conditions and limitations apply to royalty relief for
deep wells and phase 1 ultra-deep wells?
203.43 To which production do I apply the RSV earned from qualified
deep wells or qualified phase 1 ultra-deep wells on my lease?
203.44 What administrative steps must I take to use the royalty
suspension volume?
203.45 If I drill a certified unsuccessful well, what royalty relief
will my lease earn?
203.46 To which production do I apply the royalty suspension
supplements from drilling one or two certified unsuccessful wells on
my lease?
203.47 What administrative steps do I take to obtain and use the
royalty suspension supplement?
203.48 Do I keep royalty relief if prices rise significantly?
203.49 May I substitute the deep gas drilling provisions in this
part for the deep gas royalty relief provided in my lease terms?
Royalty Relief for End-of-Life Leases
203.50 Who may apply for end-of-life royalty relief?
203.51 How do I apply for end-of-life royalty relief?
203.52 What criteria must I meet to get relief?
203.53 What relief will BSEE grant?
203.54 How does my relief arrangement for an oil and gas lease
operate if prices rise sharply?
203.55 Under what conditions can my end-of-life royalty relief
arrangement for an oil and gas lease be ended?
203.56 Does relief transfer when a lease is assigned?
Royalty Relief for Pre-Act Deep Water Leases and for Development and
Expansion Projects
203.60 Who may apply for royalty relief on a case-by-case basis in
deep water in the Gulf of Mexico or offshore of Alaska?
203.61 How do I assess my chances for getting relief?
203.62 How do I apply for relief?
203.63 Does my application have to include all leases in the field?
203.64 How many applications may I file on a field or a development
project?
203.65 How long will BSEE take to evaluate my application?
203.66 What happens if BSEE does not act in the time allowed?
203.67 What economic criteria must I meet to get royalty relief on
an authorized field or project?
203.68 What pre-application costs will BSEE consider in determining
economic viability?
203.69 If my application is approved, what royalty relief will I
receive?
203.70 What information must I provide after BSEE approves relief?
203.71 How does BSEE allocate a field's suspension volume between my
lease and other leases on my field?
203.72 Can my lease receive more than one suspension volume?
203.73 How do suspension volumes apply to natural gas?
203.74 When will BSEE reconsider its determination?
203.75 What risk do I run if I request a redetermination?
203.76 When might BSEE withdraw or reduce the approved size of my
relief?
203.77 May I voluntarily give up relief if conditions change?
203.78 Do I keep relief approved by BSEE under this part for my
lease, unit or project if prices rise significantly?
203.79 How do I appeal BSEE's decisions related to royalty relief
for a deepwater lease or a development or expansion project?
203.80 When can I get royalty relief if I am not eligible for
royalty relief under other sections in the subpart?
Required Reports
203.81 What supplemental reports do royalty-relief applications
require?
203.82 What is BSEE's authority to collect this information?
203.83 What is in an administrative information report?
203.84 What is in a net revenue and relief justification report?
203.85 What is in an economic viability and relief justification
report?
203.86 What is in a G&G report?
203.87 What is in an engineering report?
203.88 What is in a production report?
203.89 What is in a cost report?
203.90 What is in a fabricator's confirmation report?
203.91 What is in a post-production development report?
Subpart C--Federal and Indian Oil [Reserved]
Subpart D--Federal and Indian Gas [Reserved]
Subpart E--Solid Minerals, General [Reserved]
Subpart F [Reserved]
Subpart G--Other Solid Minerals [Reserved]
Subpart H--Geothermal Resources [Reserved]
Subpart I--OCS Sulfur [Reserved]
Authority: 25 U.S.C. 396 et seq.; 25 U.S.C. 396a et seq.; 25
U.S.C. 2101 et seq.; 30 U.S.C. 181 et seq.; 30 U.S.C. 351 et seq.;
30 U.S.C. 1001 et seq.; 30 U.S.C. 1701 et seq.; 31 U.S.C. 9701; 42
U.S.C. 15903-15906; 43 U.S.C. 1301 et seq.; 43 U.S.C. 1331 et seq.;
and 43 U.S.C. 1801 et seq.
Subpart A--General Provisions
Sec. 203.0 What definitions apply to this part?
Authorized field means a field:
(1) Located in a water depth of at least 200 meters and in the Gulf
of Mexico (GOM) west of 87 degrees, 30 minutes West longitude;
(2) That includes one or more pre-Act leases; and
(3) From which no current pre-Act lease produced, other than test
production, before November 28, 1995.
Certified unsuccessful well means an original well or a sidetrack
with a sidetrack measured depth (i.e., length) of at least 10,000 feet,
on your lease that:
(1) You begin drilling on or after March 26, 2003, and before May
3, 2009, on a lease that is located in water partly or entirely less
than 200 meters deep and that is not a non-converted lease, or on or
after May 18, 2007, and before May 3, 2013, on a lease that is located
in water entirely more than 200 meters and entirely less than 400
meters deep;
(2) You begin drilling before your lease produces gas or oil from a
well with a perforated interval the top of which is at least 18,000
feet true vertical depth subsea (TVD SS), (i.e., below the datum at
mean sea level);
(3) You drill to at least 18,000 feet TVD SS with a target
reservoir on your lease, identified from seismic and related data,
deeper than that depth;
(4) Fails to meet the producibility requirements of 30 CFR part
550, subpart A, and does not produce gas or oil, or meets those
producibility requirements and Bureau of Ocean Energy Management (BOEM)
agrees it is not commercially producible; and
(5) For which you have provided the notices and information
required under Sec. 203.47.
Complete application means an original and two copies of the six
[[Page 64464]]
reports consisting of the data specified in Sec. Sec. 203.81, 203.83,
and 203.85 through 203.89, along with one set of digital information,
which Bureau of Safety and Environmental Enforcement (BSEE) has
reviewed and found complete.
Deep well means either an original well or a sidetrack with a
perforated interval the top of which is at least 15,000 feet TVD SS and
less than 20,000 feet TVD SS. A deep well subsequently re-perforated at
less than 15,000 feet TVD SS in the same reservoir is still a deep
well.
Determination means the binding decision by BSEE on whether your
field qualifies for relief or how large a royalty-suspension volume
must be to make the field economically viable.
Development project means a project to develop one or more oil or
gas reservoirs located on one or more contiguous leases that have had
no production (other than test production) before the current
application for royalty relief and are either:
(1) Located in a planning area offshore Alaska; or
(2) Located in the GOM in a water depth of at least 200 meters and
wholly west of 87 degrees, 30 minutes West longitude, and were issued
in a sale held after November 28, 2000.
Draft application means the preliminary set of information and
assumptions you submit to seek a nonbinding assessment on whether a
field could be expected to qualify for royalty relief.
Eligible lease means a lease that:
(1) Is issued as part of an OCS lease sale held after November 28,
1995, and before November 28, 2000;
(2) Is located in the Gulf of Mexico in water depths of 200 meters
or deeper;
(3) Lies wholly west of 87 degrees, 30 minutes West longitude; and
(4) Is offered subject to a royalty suspension volume.
Expansion project means a project that meets the following
requirements:
(1) You must propose the project in a (BOEM) Development and
Production Plan, a BOEM Development Operations Coordination Document
(DOCD), or a BOEM Supplement to a DOCD, approved by the Secretary of
the Interior after November 28, 1995.
(2) The project must be located on either:
(i) A pre-Act lease in the GOM, or a lease in the GOM issued in a
sale held after November 28, 2000, located wholly west of 87 degrees,
30 minutes West longitude; or
(ii) A lease in a planning area offshore Alaska.
(3) On a pre-Act lease in the GOM, the project:
(i) Must significantly increase the ultimate recovery of resources
from one or more reservoirs that have not previously produced
(extending recovery from reservoirs already in production does not
constitute a significant increase); and
(ii) Must involve a substantial capital investment (e.g., fixed-leg
platform, subsea template and manifold, tension-leg platform, multiple
well project, etc.).
(4) For a lease issued in a planning area offshore Alaska, or in
the GOM after November 28, 2000, the project must involve a new well
drilled into a reservoir that has not previously produced.
(5) On a lease in the GOM, the project must not include a reservoir
the production from which an RSV under Sec. Sec. 203.30 through 203.36
or Sec. Sec. 203.40 through 203.48 would be applied.
Fabrication (or start of construction) means evidence of an
irreversible commitment to a concept and scale of development. Evidence
includes copies of a binding contract between you (as applicant) and a
fabrication yard, a letter from a fabricator certifying that continuous
construction has begun, and a receipt for the customary down payment.
Field means an area consisting of a single reservoir or multiple
reservoirs all grouped on, or related to, the same general geological
structural feature or stratigraphic trapping condition. Two or more
reservoirs may be in a field, separated vertically by intervening
impervious strata or laterally by local geologic barriers, or both.
Lease means a lease or unit.
New production means any production from a current pre-Act lease
from which no royalties are due on production, other than test
production, before November 28, 1995. Also, it means any additional
production resulting from new lease-development activities on a lease
issued in a sale after November 28, 2000, or a current pre-Act lease
under a BOEM DOCD or a BOEM Supplement approved by the Secretary of the
Interior after November 28, 1995.
Nonbinding assessment means an opinion by BSEE of whether your
field could qualify for royalty relief. It is based on your draft
application and does not entitle the field to relief.
Non-converted lease means a lease located partly or entirely in
water less than 200 meters deep issued in a lease sale held after
January 1, 2001, and before January 1, 2004, whose original lease terms
provided for an RSV for deep gas production and the lessee has not
exercised the option under Sec. 203.49 to replace the lease terms for
royalty relief with those in Sec. 203.0 and Sec. Sec. 203.40 through
203.48.
Original well means a well that is drilled without utilizing an
existing wellbore. An original well includes all sidetracks drilled
from the original wellbore either before the drilling rig moves off the
well location or after a temporary rig move that BSEE agrees was forced
by a weather or safety threat and drilling resumes within 1 year. A
bypass from an original well (e.g., drilling around material blocking
the hole or to straighten crooked holes) is part of the original well.
Participating area means that part of the unit area that BSEE
determines is reasonably proven by drilling and completion of
producible wells, geological and geophysical information, and
engineering data to be capable of producing hydrocarbons in paying
quantities.
Performance conditions mean minimum conditions you must meet, after
we have granted relief and before production begins, to remain
qualified for that relief. If you do not meet each one of these
performance conditions, we consider it a change in material fact
significant enough to invalidate our original evaluation and approval.
Phase 1 ultra-deep well means an ultra-deep well on a lease that is
located in water partly or entirely less than 200 meters deep for which
drilling began before May 18, 2007, and that begins production before
May 3, 2009, or that meets the requirements to be a certified
unsuccessful well.
Phase 2 ultra-deep well means an ultra-deep well for which drilling
began on or after May 18, 2007; and that either meets the requirements
to be a certified unsuccessful well or that begins production:
(1) Before the date which is 5 years after the lease issuance date
on a non-converted lease; or
(2) Before May 3, 2009, on all other leases located in water partly
or entirely less than 200 meters deep; or
(3) Before May 3, 2013, on a lease that is located in water
entirely more than 200 meters and entirely less than 400 meters deep.
Phase 3 ultra-deep well means an ultra-deep well for which drilling
began on or after May 18, 2007, and that begins production:
(1) On or after the date which is 5 years after the lease issuance
date on a non-converted lease; or
(2) On or after May 3, 2009, on all other leases located in water
partly or entirely less than 200 meters deep; or
(3) On or after May 3, 2013, on a lease that is located in water
entirely more
[[Page 64465]]
than 200 meters and entirely less than 400 meters deep.
Pre-Act lease means a lease that:
(1) Results from a sale held before November 28, 1995;
(2) Is located in the GOM in water depths of 200 meters or deeper;
and
(3) Lies wholly west of 87 degrees, 30 minutes West longitude.
Production means all oil, gas, and other relevant products you
save, remove, or sell from a tract or those quantities allocated to
your tract under a unitization formula, as measured for the purposes of
determining the amount of royalty payable to the United States.
Project means any activity that requires at least a permit to
drill.
Qualified deep well means:
(1) On a lease that is located in water partly or entirely less
than 200 meters deep that is not a non-converted lease, a deep well for
which drilling began on or after March 26, 2003, that produces natural
gas (other than test production), including gas associated with oil
production, before May 3, 2009, and for which you have met the
requirements prescribed in Sec. 203.44;
(2) On a non-converted lease, a deep well that produces natural gas
(other than test production) before the date which is 5 years after the
lease issuance date from a reservoir that has not produced from a deep
well on any lease; or
(3) On a lease that is located in water entirely more than 200
meters but entirely less than 400 meters deep, a deep well for which
drilling began on or after May 18, 2007, that produces natural gas
(other than test production), including gas associated with oil
production before May 3, 2013, and for which you have met the
requirements prescribed in Sec. 203.44.
Qualified ultra-deep well means:
(1) On a lease that is located in water partly or entirely less
than 200 meters deep that is not a non-converted lease, an ultra-deep
well for which drilling began on or after March 26, 2003, that produces
natural gas (other than test production), including gas associated with
oil production, and for which you have met the requirements prescribed
in Sec. 203.35 or Sec. 203.44, as applicable; or
(2) On a lease that is located in water entirely more than 200
meters and entirely less than 400 meters deep, or on a non-converted
lease, an ultra-deep well for which drilling began on or after May 18,
2007, that produces natural gas (other than test production), including
gas associated with oil production, and for which you have met the
requirements prescribed in Sec. 203.35.
Qualified well means either a qualified deep well or a qualified
ultra-deep well.
Redetermination means our reconsideration of our determination on
royalty relief because you request it after:
(1) We have rejected your application;
(2) We have granted relief but you want a larger suspension volume;
(3) We withdraw approval; or
(4) You renounce royalty relief.
Renounce means action you take to give up relief after we have
granted it and before you start production.
Reservoir means an underground accumulation of oil or natural gas,
or both, characterized by a single pressure system and segregated from
other such accumulations.
Royalty suspension (RS) lease means a lease that:
(1) Is issued as part of an OCS lease sale held after November 28,
2000;
(2) Is in locations or planning areas specified in a particular
Notice of OCS Lease Sale offering that lease; and
(3) Is offered subject to a royalty suspension specified in a
Notice of OCS Lease Sale published in the Federal Register.
Royalty suspension supplement (RSS) means a royalty suspension
volume resulting from drilling a certified unsuccessful well that is
applied to future natural gas and oil production generated at any
drilling depth on, or allocated under a BSEE-approved unit agreement
to, the same lease.
Royalty suspension volume (RSV) means a volume of production from a
lease that is not subject to royalty under the provisions of this part.
Sidetrack means, for the purpose of this subpart, a well resulting
from drilling an additional hole to a new objective bottom-hole
location by leaving a previously drilled hole. A sidetrack also
includes drilling a well from a platform slot reclaimed from a
previously drilled well or re-entering and deepening a previously
drilled well. A bypass from a sidetrack (e.g., drilling around material
blocking the hole, or to straighten crooked holes) is part of the
sidetrack.
Sidetrack measured depth means the actual distance or length in
feet a sidetrack is drilled beginning where it exits a previously
drilled hole to the bottom hole of the sidetrack, that is, to its total
depth.
Sunk costs for an authorized field means the after-tax eligible
costs that you (not third parties) incur for exploration, development,
and production from the spud date of the first discovery on the field
to the date we receive your complete application for royalty relief.
The discovery well must be qualified as producible under 30 CFR part
550, subpart A. Sunk costs include the rig mobilization and material
costs for the discovery well that you incurred before its spud date.
Sunk costs for an expansion or development project means the after-
tax eligible costs that you (not third parties) incur for only the
first well that encounters hydrocarbons in the reservoir(s) included in
the application and that meets the producibility requirements under 30
CFR part 550, subpart A on each lease participating in the application.
Sunk costs include rig mobilization and material costs for the
discovery wells that you incurred before their spud dates.
Ultra-deep well means either an original well or a sidetrack
completed with a perforated interval the top of which is at least
20,000 feet TVD SS. An ultra-deep well subsequently re-perforated less
than 20,000 feet TVD SS in the same reservoir is still an ultra-deep
well.
Withdraw means action we take on a field that has qualified for
relief if you have not met one or more of the performance conditions.
Sec. 203.1 What is BSEE's authority to grant royalty relief?
The Outer Continental Shelf (OCS) Lands Act, 43 U.S.C. 1337, as
amended by the OCS Deep Water Royalty Relief Act (DWRRA), Public Law
104-58 and the Energy Policy Act of 2005, Public Law 109-058 authorizes
us to grant royalty relief in four situations.
(a) Under 43 U.S.C. 1337(a)(3)(A), we may reduce or eliminate any
royalty or a net profit share specified for an OCS lease to promote
increased production.
(b) Under 43 U.S.C. 1337(a)(3)(B), we may reduce, modify, or
eliminate any royalty or net profit share to promote development,
increase production, or encourage production of marginal resources on
certain leases or categories of leases. This authority is restricted to
leases in the GOM that are west of 87 degrees, 30 minutes West
longitude, and in the planning areas offshore Alaska.
(c) Under 43 U.S.C. 1337(a)(3)(C), we may suspend royalties for
designated volumes of new production from any lease if:
(1) Your lease is in deep water (water at least 200 meters deep);
(2) Your lease is in designated areas of the GOM (west of 87
degrees, 30 minutes West longitude);
(3) Your lease was acquired in a lease sale held before the DWRRA
(before November 28, 1995);
[[Page 64466]]
(4) We find that your new production would not be economic without
royalty relief; and
(5) Your lease is on a field that did not produce before enactment
of the DWRRA, or if you propose a project to significantly expand
production under a Development Operations Coordination Document (DOCD)
or a supplementary DOCD, that the Bureau of Ocean Energy Management
(BOEM) approved after November 28, 1995.
(d) Under 42 U.S.C. 15904-15905, we may suspend royalties for
designated volumes of gas production from deep and ultra-deep wells on
a lease if:
(1) Your lease is in shallow water (water less than 400 meters
deep) and you produce from an ultra-deep well (top of the perforated
interval is at least 20,000 feet TVD SS) or your lease is in waters
entirely more than 200 meters and entirely less than 400 meters deep
and you produce from a deep well (top of the perforated interval is at
least 15,000 feet TVD SS);
(2) Your lease is in the designated area of the GOM (wholly west of
87 degrees, 30 minutes west longitude); and
(3) Your lease is not eligible for deep water royalty relief.
Sec. 203.2 How can I obtain royalty relief?
We may reduce or suspend royalties for Outer Continental Shelf
(OCS) leases or projects that meet the criteria in the following table.
----------------------------------------------------------------------------------------------------------------
Then we may grant you . . .
If you have a lease . . . And if you . . .
----------------------------------------------------------------------------------------------------------------
(a) With earnings that cannot sustain Would abandon otherwise potentially A reduced royalty rate on
production (i.e., End-of-life lease), recoverable resources but seek to current monthly production
increase production by operating beyond and a higher royalty rate
the point at which the lease is on additional monthly
economic under the existing royalty production (see Sec. Sec.
rate, 203.50 through 203.56).
(b) Located in a designated GOM deep Propose an expansion project and can A royalty suspension for a
water area (i.e., 200 meters or greater) demonstrate your project is uneconomic minimum production volume
and acquired in a lease sale held before without royalty relief, plus any additional
November 28, 1995, or after November 28, production large enough to
2000, make the project economic
(see Sec. Sec. 203.60
through 203.79).
(c) Located in a designated GOM deep Are on a field from which no current pre- A royalty suspension for a
water area and acquired in a lease sale Act lease produced (other than test minimum production volume
held before November 28, 1995 (Pre-Act production) before November 28, 1995, plus any additional volume
lease), (Authorized field,) needed to make the field
economic (see Sec. Sec.
203.60 through 203.79).
(d) Located in a designated GOM deep Propose a development project and can A royalty suspension for a
water area and acquired in a lease sale demonstrate that the suspension volume, minimum production volume
held after November 28, 2000, if any, for your lease is not enough to plus any additional volume
make development economic, needed to make your
project economic (see Sec.
Sec. 203.60 through
203.79).
(e) Where royalty relief would recover Are not eligible to apply for end-of- A royalty modification in
significant additional resources or, life or deep water royalty relief, but size, duration, or form
offshore Alaska or in certain areas of show us you meet certain eligibility that makes your lease or
the GOM, would enable development, conditions, project economic (see Sec.
203.80).
(f) Located in a designated GOM shallow Drill a deep well on a lease that is not A royalty suspension for a
water area and acquired in a lease sale eligible for deep water royalty relief volume of gas produced
held before January 1, 2001, or after and you have not previously produced from successful deep and
January 1, 2004, or have exercised an oil or gas from a deep well or an ultra- ultra-deep wells, or, for
option to substitute for royalty relief deep well, certain unsuccessful deep
in your lease terms, and ultra-deep wells, a
smaller royalty suspension
for a volume of gas or oil
produced by all wells on
your lease (see Sec. Sec.
203.40 through 203.49).
(g) Located in a designated GOM shallow Drill and produce gas from an ultra-deep A royalty suspension for a
water area, well on a lease that is not eligible volume of gas produced
for deep water royalty relief and you from successful ultra-deep
have not previously produced oil or gas and deep wells on your
from an ultra-deep well, lease (see Sec. Sec.
.203.30 through 203.36).
(h) Located in planning areas offshore Propose an expansion project or propose A royalty suspension for a
Alaska, a development project and can minimum production volume
demonstrate that the project is plus any additional volume
uneconomic without relief or that the needed to make your
suspension volume, if any, for your project economic (see Sec.
lease is not enough to make development Sec. 203.60, 203.62,
economic, 203.67 through 203.70,
203.73, and 203.76 through
203.79).
----------------------------------------------------------------------------------------------------------------
Sec. 203.3 Do I have to pay a fee to request royalty relief?
When you submit an application or ask for a preview assessment, you
must include a fee to reimburse us for our costs of processing your
application or assessment. Federal policy and law require us to recover
the cost of services that confer special benefits to identifiable non-
Federal recipients. The Independent Offices Appropriation Act (31
U.S.C. 9701), Office of Management and Budget Circular A-25, and the
Omnibus Appropriations Bill (Pub. L. 104-134, 110 Stat. 1321, April 26,
1996) authorize us to collect these fees.
(a) We will specify the necessary fees for each of the types of
royalty relief applications and possible BSEE audits in a Notice to
Lessees. We will periodically update the fees to reflect changes in
costs, as well as provide other information necessary to administer
royalty relief.
(b) You must file all payments electronically through the Pay.gov
Web site and you must include a copy of the Pay.gov confirmation
receipt page with your application or assessment. The Pay.gov Web site
may be accessed through a link on the BSEE Offshore Web site at: http://www.bsee.gov/offshore/ homepage or directly through Pay.gov at:
https://www.pay.gov/paygov/.
Sec. 203.4 How do the provisions in this part apply to different
types of leases and projects?
The tables in this section summarize the similar application and
approval provisions for the discretionary end-of-life and deep water
royalty relief programs in Sec. Sec. 203.50 to 203.91.
[[Page 64467]]
Because royalty relief for deep gas on leases not subject to deep water
royalty relief, as provided for under Sec. Sec. 203.40 to 203.48, does
not involve an application, its provisions do not parallel the other
two royalty relief programs and are not summarized in this section.
(a) We require the information elements indicated by an X in the
following table and described in Sec. Sec. 203.51, 203.62, and 203.81
through 203.89 for applications for royalty relief.
----------------------------------------------------------------------------------------------------------------
Deep water
End-of-life -----------------------------------------
Information elements lease Expansion Pre-act Development
project lease project
----------------------------------------------------------------------------------------------------------------
(1) Administrative information report................. X X X X
(2) Net revenue and relief justification report X ........... ........... ..............
(prescribed format)..................................
(3) Economic viability and relief justification report .............. X X X
(Royalty Suspension Viability Program (RSVP) model
inputs justified with Geological and Geophysical
(G&G), Engineering, Production, & Cost reports)......
(4) G&G report........................................ .............. X X X
(5) Engineering report................................ .............. X X X
(6) Production report................................. .............. X X X
(7) Deep water cost report............................ .............. X X X
----------------------------------------------------------------------------------------------------------------
(b) We require the confirmation elements indicated by an X in the
following table and described in Sec. Sec. 203.70, 203.81, 203.90 and
203.91 to retain royalty relief.
----------------------------------------------------------------------------------------------------------------
Deep water
End-of-life -----------------------------------------
Confirmation elements lease Expansion Pre-act Development
project lease project
----------------------------------------------------------------------------------------------------------------
(1) Fabricator's confirmation report.................. .............. X X X
(2) Post-production development report approved by an .............. X X X
independent certified public accountant (CPA) * * *..
----------------------------------------------------------------------------------------------------------------
(c) The following table indicates by an X, and Sec. Sec. 203.50,
203.52, 203.60 and 203.67 describe, the prerequisites for our approval
of your royalty relief application.
----------------------------------------------------------------------------------------------------------------
Deep water
End-of-life -----------------------------------------
Approval conditions lease Pre-act Development
Expansion lease project
----------------------------------------------------------------------------------------------------------------
(1) At least 12 of the last 15 months have the X ........... ........... ..............
required level of production.........................
(2) Already producing................................. X ........... ........... ..............
(3) A producible well into a reservoir that has not .............. X X X
produced before......................................
(4) Royalties for qualifying months exceed 75 percent X ........... ........... ..............
of net revenue (NR)..................................
(5) Substantial investment on a pre-Act lease (e.g., .............. ........... ........... ..............
platform, subsea template)...........................
(6) Determined to be economic only with relief........ .............. X X X
----------------------------------------------------------------------------------------------------------------
(d) The following table indicates by an X, and Sec. Sec. 203.52,
203.74, and 203.75 describe, the prerequisites for a redetermination of
our royalty relief decision.
----------------------------------------------------------------------------------------------------------------
Deep water
End-of-life -----------------------------------------
Redetermination conditions lease Expansion Pre-act Development
project lease project
----------------------------------------------------------------------------------------------------------------
(1) After 12 months under current rate, criteria same X ........... ........... ..............
as for approval......................................
(2) For material change in geologic data, prices, .............. X X X
costs, or available technology.......................
----------------------------------------------------------------------------------------------------------------
(e) The following table indicates by an X, and Sec. Sec. 203.53
and 203.69 describe, the characteristics of approved royalty relief.
[[Page 64468]]
----------------------------------------------------------------------------------------------------------------
Deep water
End-of-life -----------------------------------------
Relief rate and volume, subject to certain conditions lease Expansion Pre-act Development
project lease project
----------------------------------------------------------------------------------------------------------------
(1) One-half pre-application effective lease rate on X ........... ........... ..............
the qualifying amount, 1.5 times pre-application
effective lease rate on additional production up to
twice the qualifying amount, and the pre-application
effective lease rate for any larger volumes..........
(2) Qualifying amount is the average monthly X ........... ........... ..............
production for 12 qualifying months..................
(3) Zero royalty rate on the suspension volume and the .............. X X X
original lease rate on additional production.........
(4) Suspension volume is at least 17.5, 52.5 or 87.5 .............. ........... X ..............
million barrels of oil equivalent (MMBOE)............
(5) Suspension volume is at least the minimum set in .............. X ........... X
the Notice of Sale, the lease, or the regulations....
(6) Amount needed to become economic.................. .............. X X X
----------------------------------------------------------------------------------------------------------------
(f) The following table indicates by an X, and Sec. Sec. 203.54
and 203.78 describe, circumstances under which we discontinue your
royalty relief.
----------------------------------------------------------------------------------------------------------------
Deep water
End-of-life -----------------------------------------
Full royalty resumes when lease Expansion Pre-act Development
project lease project
----------------------------------------------------------------------------------------------------------------
(1) Average NYMEX price for last 12 months is at least X ........... ........... ..............
25 percent above the average for the qualifying
months...............................................
(2) Average NYMEX price for last calendar year exceeds .............. X X ..............
$28/bbl or $3.50/mcf, escalated by the gross domestic
product (GDP) deflator since 1994....................
(3) Average prices for designated periods exceed .............. X ........... X
levels we specify in the Notice of Sale or the lease.
----------------------------------------------------------------------------------------------------------------
(g) The following table indicates by an X, and Sec. Sec. 203.55,
203.76, and 203.77 describe, circumstances under which we end or reduce
royalty relief.
----------------------------------------------------------------------------------------------------------------
Deep water
End-of-life -----------------------------------------
Relief withdrawn or reduced lease Expansion Pre-act Development
project lease project
----------------------------------------------------------------------------------------------------------------
(1) If recipient requests............................. X X X X
(2) Lease royalty rate is at the effective rate for 12 X ........... ........... ..............
consecutive months...................................
(3) Conditions occur that we specified in the approval X ........... ........... ..............
letter in individual cases...........................
(4) Recipient does not submit post-production report .............. X X X
that compares expected to actual costs...............
(5) Recipient changes development system.............. .............. X X X
(6) Recipient excessively delays starting fabrication. .............. X X X
(7) Recipient spends less than 80 percent of proposed .............. X X X
pre-production costs prior to start of production....
(8) Amount of relief volume is produced............... .............. X X X
----------------------------------------------------------------------------------------------------------------
Sec. 203.5 What is BSEE's authority to collect information?
(a) The Office of Management and Budget (OMB) has approved the
information collection requirements in this part under 44 U.S.C. 3501
et seq., and assigned OMB Control Number 1010-0071. The title of this
information collection is ``30 CFR part 203, Relief or Reduction in
Royalty Rates.''
(b) BSEE collects this information to make decisions on the
economic viability of leases requesting a suspension or elimination of
royalty or net profit share. Responses are required to obtain a benefit
or are mandatory according to 43 U.S.C. 1331 et seq. BSEE will protect
information considered proprietary under applicable law and under
regulations at Sec. 203.61, ``How do I assess my chances for getting
relief?'' and 30 CFR 250.197, ``Data and information to be made
available to the public or for limited inspection.''
(c) An agency may not conduct or sponsor, and a person is not
required to respond to a collection of information unless it displays a
currently valid OMB control number.
(d) Send comments regarding any aspect of the collection of
information under this part, including suggestions for reducing the
burden, to the Information Collection Clearance Officer, Bureau of
Safety and Environmental Enforcement, 381 Elden Street, Herndon, VA
20170.
Subpart B--OCS Oil, Gas, and Sulfur General
Royalty Relief for Drilling Ultra-Deep Wells on Leases Not Subject to
Deep Water Royalty Relief
Sec. 203.30 Which leases are eligible for royalty relief as a result
of drilling a phase 2 or phase 3 ultra-deep well?
Your lease may receive a royalty suspension volume (RSV) under
Sec. Sec. 203.31 through 203.36 if the lease meets all the
requirements of this section.
[[Page 64469]]
(a) The lease is located in the GOM wholly west of 87 degrees, 30
minutes West longitude in water depths entirely less than 400 meters
deep.
(b) The lease has not produced gas or oil from a deep well or an
ultra-deep well, except as provided in Sec. 203.31(b).
(c) If the lease is located entirely in more than 200 meters and
entirely less than 400 meters of water, it must either:
(1) Have been issued before November 28, 1995, and not been granted
deep water royalty relief under 43 U.S.C. 1337(a)(3)(C), added by
section 302 of the Deep Water Royalty Relief Act; or
(2) Have been issued after November 28, 2000, and not been granted
deep water royalty relief under Sec. Sec. 203.60 through 203.79.
Sec. 203.31 If I have a qualified phase 2 or qualified phase 3 ultra-
deep well, what royalty relief would that well earn for my lease?
(a) Subject to the administrative requirements of Sec. 203.35 and
the price conditions in Sec. 203.36, your qualified well earns your
lease an RSV shown in the following table in billions of cubic feet
(BCF) or in thousands of cubic feet (MCF) as prescribed in Sec.
203.33:
------------------------------------------------------------------------
If you have a qualified phase 2 or Then your lease earns an RSV on
qualified phase 3 ultra-deep well that this volume of gas production:
is:
------------------------------------------------------------------------
(1) An original well, 35 BCF.
(2) A sidetrack with a sidetrack 35 BCF.
measured depth of at least 20,000
feet,
(3) An ultra-deep short sidetrack that 4 BCF plus 600 MCF times
is a phase 2 ultra-deep well, sidetrack measured depth
(rounded to the nearest 100
feet) but no more than 25 BCF.
(4) An ultra-deep short sidetrack that 0 BCF.
is a phase 3 ultra-deep well,
------------------------------------------------------------------------
(b)(1) This paragraph applies if your lease:
(i) Has produced gas or oil from a deep well with a perforated
interval the top of which is less than 18,000 feet TVD SS;
(ii) Was issued in a lease sale held between January 1, 2004, and
December 31, 2005; and
(iii) The terms of your lease expressly incorporate the provisions
of Sec. Sec. 203.41 through 203.47 as they existed at the time the
lease was issued.
(2) Subject to the administrative requirements of Sec. 203.35 and
the price conditions in Sec. 203.36, your qualified well earns your
lease an RSV shown in the following table in BCF or MCF as prescribed
in Sec. 203.33:
------------------------------------------------------------------------
Then your lease earns an RSV on
If you have a qualified phase 2 ultra- this volume of gas production:
deep well that is . . .
------------------------------------------------------------------------
(i) An original well or a sidetrack 10 BCF.
with a sidetrack measured depth of at
least 20,000 feet TVD SS,
(ii) An ultra-deep short sidetrack, 4 BCF plus 600 MCF times
sidetrack measured depth
(rounded to the nearest 100
feet) but no more than 10 BCF.
------------------------------------------------------------------------
(c) Lessees may request a refund of or recoup royalties paid on
production from qualified phase 2 or phase 3 ultra-deep wells that:
(1) Occurs before December 18, 2008, and
(2) Is subject to application of an RSV under either Sec. 203.31
or Sec. 203.41.
(d) The following examples illustrate how this section applies.
These examples assume that your lease is located in the GOM west of 87
degrees, 30 minutes West longitude and in water less than 400 meters
deep (see Sec. 203.30(a)), has no existing deep or ultra-deep wells
and that the price thresholds prescribed in Sec. 203.36 have not been
exceeded.
Example 1: In 2008, you drill and begin producing from an ultra-
deep well with a perforated interval the top of which is 25,000 feet
TVD SS, and your lease has had no prior production from a deep or
ultra-deep well. Assuming your lease has no deepwater royalty relief
(see Sec. 203.30(c)), your lease is eligible (according to Sec.
203.30(b)) to earn an RSV under Sec. 203.31 because it has not yet
produced from a deep well. Your lease earns an RSV of 35 BCF under
this section when this well begins producing. According to Sec.
203.31(a), your 25,000 foot well qualifies your lease for this RSV
because the well was drilled after the relief authorized here became
effective (when the proposed version of this rule was published on
May 18, 2007) and produced from an interval that meets the criteria
for an ultra-deep well (i.e., is a phase 2 ultra-deep well as
defined in Sec. 203.0). Then in 2014, you drill and produce from
another ultra-deep well with a perforated interval the top of which
is 29,000 feet TVD SS. Your lease earns no additional RSV under this
section when this second ultra-deep well produces, because your
lease no longer meets the condition in (Sec. 203.30(b)) of no
production from a deep well. However, any remaining RSV earned by
the first ultra-deep well on your lease would be applied to
production from both the first and the second ultra-deep wells as
prescribed in Sec. 203.33(a)(2), or Sec. 203.33(b)(2) if your
lease is part of a unit.
Example 2: In 2005, you spudded and began producing from an
ultra-deep well with a perforated interval the top of which is
23,000 feet TVD SS. Your lease earns no RSV under this section from
this phase 1 ultra-deep well (as defined in Sec. 203.0) because you
spudded the well before the publication date (May 18, 2007) of the
proposed rule when royalty relief under Sec. 203.31(a) became
effective. However, this ultra-deep well may earn an RSV of 25 BCF
for your lease under Sec. 203.41 (that became effective May 3,
2004), if the lease is located in water depths partly or entirely
less than 200 meters and has not previously produced from a deep
well (Sec. 203.30(b)).
Example 3: In 2000, you began producing from a deep well with a
perforated interval the top of which is 16,000 feet TVD SS and your
lease is located in water 100 meters deep. Then in 2008, you drill
and produce from a new ultra-deep well with a perforated interval
the top of which is 24,000 feet TVD SS. Your lease earns no RSV
under either this section or Sec. 203.41 because the 16,000-foot
well was drilled before we offered any way to earn an RSV for
producing from a deep well (see dates in the definition of qualified
well in Sec. 203.0) and because the existence of the 16,000-foot
well means the lease is not eligible (see Sec. 203.30(b)) to earn
an RSV for the 24,000-foot well. Because the lease existed in the
year 2000, it cannot be eligible for the exception to this
eligibility condition provided in Sec. 203.31(b).
Example 4: In 2008, you spud and produce from an ultra-deep well
with a perforated interval the top of which is 22,000 feet TVD SS,
your lease is located in water 300 meters deep, and your lease has
had no previous production from a deep or ultra-deep well. Your
lease earns an RSV of 35 BCF under this section when this well
begins producing because your lease meets the conditions in Sec.
203.30 and the well fits the definition of a phase 2 ultra-deep well
(in Sec. 203.0). Then in 2010, you spud and produce from a deep
well with a perforated interval the top of
[[Page 64470]]
which is 16,000 feet TVD SS. Your 16,000-foot well earns no RSV
because it is on a lease that already has a producing well at least
18,000 feet subsea (see Sec. 203.42(a)), but any remaining RSV
earned by the ultra-deep well would also be applied to production
from the deep well as prescribed in Sec. 203.33(a)(2), or Sec.
203.33(b)(2) if your lease is part of a unit and Sec. 203.43(a)(2),
or Sec. 203.43(b)(2) if your lease is part of a unit. However, if
the 16,000-foot deep well does not begin production until 2016 (or
if your lease were located in water less than 200 meters deep), then
the 16,000-foot well would not be a qualified deep well because this
well does not begin production within the interval specified in the
definition of a qualified well in Sec. 203.0, and the RSV earned by
the ultra-deep well would not be applied to production from this
(unqualified) deep well.
Example 5: In 2008, you spud a deep well with a perforated
interval the top of which is 17,000 feet TVD SS that becomes a
qualified well and earns an RSV of 15 BCF under Sec. 203.41 when it
begins producing. Then in 2011, you spud an ultra-deep well with a
perforated interval the top of which is 26,000 feet TVD SS. Your
26,000-foot well becomes a qualified ultra-deep well because it
meets the date and depth conditions in this definition under Sec.
203.0 when it begins producing, but your lease earns no additional
RSV under this section or Sec. 203.41 because it is on a lease that
already has production from a deep well (see Sec. 203.30(b)). Both
the qualified deep well and the qualified ultra-deep well would
share your lease's total RSV of 15 BCF in the manner prescribed in
Sec. Sec. 203.33 and 203.43.
Example 6: In 2008, you spud a qualified ultra-deep well that is
a sidetrack with a sidetrack measured depth of 21,000 feet and a
perforated interval the top of which is 25,000 feet TVD SS. This
well meets the definition of an ultra-deep well but is too long to
be classified an ultra-deep short sidetrack in Sec. 203.0. If your
lease is located in 150 meters of water and has not previously
produced from a deep well, your lease earns an RSV of 35 BCF because
it was drilled after the effective date for earning this RSV.
Further, this RSV applies to gas production from this and any future
qualified deep and qualified ultra-deep wells on your lease, as
prescribed in Sec. 203.33. The absence of an expiration date for
earning an RSV on an ultra-deep well means this long sidetrack well
becomes a qualified well whenever it starts production. If your
sidetrack has a sidetrack measured depth of 14,000 feet and begins
production in March 2009, it earns an RSV of 12.4 BCF under this
section because it meets the definitions of a phase 2 ultra-deep
well (production begins before the expiration date for the pre-
existing relief in its water depth category) and an ultra-deep short
sidetrack in Sec. 203.0. However, if it does not begin production
until 2010, it earns no RSV because it is too short as a phase 3
ultra-deep well to be a qualified ultra-deep well.
Example 7: Your lease was issued in June 2004 and expressly
incorporates the provisions of Sec. Sec. 203.41 through 203.47 as
they existed at that time. In January 2005, you spud a deep well
(well no. 1) with a perforated interval the top of which is 16,800
feet TVD SS that becomes a qualified well and earns an RSV of 15 BCF
under Sec. 203.41 when it begins producing. Then in February 2008,
you spud an ultra-deep well (well no. 2) with a perforated interval
the top of which is 22,300 feet that begins producing in November
2008, after well no. 1 has started production. Well no. 2 earns your
lease an additional RSV of 10 BCF under paragraph (b) of this
section because it begins production in time to be classified as a
phase 2 ultra-deep well. If, on the other hand, well no. 2 had begun
producing in June 2009, it would earn no additional RSV for the
lease because it would be classified as a phase 3 ultra-deep well
and thus is not entitled to the exception under paragraph (b) of
this section.
Sec. 203.32 What other requirements or restrictions apply to royalty
relief for a qualified phase 2 or phase 3 ultra-deep well?
(a) If a qualified ultra-deep well on your lease is within a
unitized portion of your lease, the RSV earned by that well under this
section applies only to your lease and not to other leases within the
unit or to the unit as a whole.
(b) If your qualified ultra-deep well is a directional well (either
an original well or a sidetrack) drilled across a lease line, then
either:
(1) The lease with the perforated interval that initially produces
earns the RSV or
(2) If the perforated interval crosses a lease line, the lease
where the surface of the well is located earns the RSV.
(c) Any RSV earned under Sec. 203.31 is in addition to any royalty
suspension supplement (RSS) for your lease under Sec. 203.45 that
results from a different wellbore.
(d) If your lease earns an RSV under Sec. 203.31 and later
produces from a deep well that is not a qualified well, the RSV is not
forfeited or terminated, but you may not apply the RSV earned under
Sec. 203.31 to production from the non-qualified well.
(e) You owe minimum royalties or rentals in accordance with your
lease terms notwithstanding any RSVs allowed under paragraphs (a) and
(b) of Sec. 203.31.
(f) Unused RSVs transfer to a successor lessee and expire with the
lease.
Sec. 203.33 To which production do I apply the RSV earned by
qualified phase 2 and phase 3 ultra-deep wells on my lease or in my
unit?
(a) You must apply the RSV allowed in Sec. 203.31(a) and (b) to
gas volumes produced from qualified wells on or after May 18, 2007,
reported on the Oil and Gas Operations Report, Part A (OGOR-A) for your
lease under 30 CFR 1210.102. All gas production from qualified wells
reported on the OGOR-A, including production not subject to royalty,
counts toward the total lease RSV earned by both deep or ultra-deep
wells on the lease.
(b) This paragraph applies to any lease with a qualified phase 2 or
phase 3 ultra-deep well that is not within a BSEE-approved unit.
Subject to the price conditions of Sec. 203.36, you must apply the RSV
prescribed in Sec. 203.31 as required under the following paragraphs
(b)(1) and (b)(2) of this section.
(1) You must apply the RSV to the earliest gas production occurring
on and after the later of May 18, 2007, or the date the first qualified
phase 2 or phase 3 ultra-deep well that earns your lease the RSV begins
production (other than test production).
(2) You must apply the RSV to only gas production from qualified
wells on your lease, regardless of their depth, for which you have met
the requirements in Sec. 203.35 or Sec. 203.44.
(c) This paragraph applies to any lease with a qualified phase 2 or
phase 3 ultra-deep well where all or part of the lease is within a
BSEE-approved unit. Under the unit agreement, a share of the production
from all the qualified wells in the unit participating area would be
allocated to your lease each month according to the participating area
percentages. Subject to the price conditions of Sec. 203.36, you must
apply the RSV prescribed in Sec. 203.31 as follows:
(1) You must apply the RSV to the earliest gas production occurring
on and after the later of May 18, 2007, or the date that the first
qualified phase 2 or phase 3 ultra-deep well that earns your lease the
RSV begins production (other than test production).
(2) You must apply the RSV to only gas production:
(i) From qualified wells on the non-unitized area of your lease,
regardless of their depth, for which you have met the requirements in
Sec. 203.35 or Sec. 203.44; and
(ii) Allocated to your lease under a BSEE-approved unit agreement
from qualified wells on unitized areas of your lease and on other
leases in participating areas of the unit, regardless of their depth,
for which the requirements in Sec. 203.35 or Sec. 203.44 have been
met. The allocated share under paragraph (a)(2)(ii) of this section
does not increase the RSV for your lease.
Example: The east half of your lease A is unitized with all of
lease B. There is one qualified phase 2 ultra-deep well on the non-
unitized portion of lease A that earns lease A an RSV of 35 BCF
under Sec. 203.31, one qualified deep well on the unitized portion
[[Page 64471]]
of lease A (drilled after the ultra-deep well on the non-unitized
portion of that lease) and a qualified phase 2 ultra-deep well on
lease B that earns lease B a 35 BCF RSV under Sec. 203.31. The
participating area percentages allocate 40 percent of production
from both of the unit qualified wells to lease A and 60 percent to
lease B. If the non-unitized qualified phase 2 ultra-deep well on
lease A produces 12 BCF, and the unitized qualified well on lease A
produces 18 BCF, and the qualified well on lease B produces 37 BCF,
then the production volume from and allocated to lease A to which
the lease A RSV applies is 34 BCF [12 + (18 + 37)(0.40)]. The
production volume allocated to lease B to which the lease B RSV
applies is 33 BCF [(18 + 37)(0.60)]. None of the volumes produced
from a well that is not within a unit participating area may be
allocated to other leases in the unit.
(d) You must begin paying royalties when the cumulative production
of gas from all qualified wells on your lease, or allocated to your
lease under paragraph (b) of this section, reaches the applicable RSV
allowed under Sec. 203.31 or Sec. 203.41. For the month in which
cumulative production reaches this RSV, you owe royalties on the
portion of gas production from or allocated to your lease that exceeds
the RSV remaining at the beginning of that month.
Sec. 203.34 To which production may an RSV earned by qualified phase
2 and phase 3 ultra-deep wells on my lease not be applied?
You may not apply an RSV earned under Sec. 203.31:
(a) To production from completions less than 15,000 feet TVD SS,
except in cases where the qualified well is re-perforated in the same
reservoir previously perforated deeper than 15,000 feet TVD SS;
(b) To production from a deep well or ultra-deep well on any other
lease, except as provided in paragraph (c) of Sec. 203.33;
(c) To any liquid hydrocarbon (oil and condensate) volumes; or
(d) To production from a deep well or ultra-deep well that
commenced drilling before:
(1) March 26, 2003, on a lease that is located entirely or partly
in water less than 200 meters deep; or
(2) May 18, 2007, on a lease that is located entirely in water more
than 200 meters deep.
Sec. 203.35 What administrative steps must I take to use the RSV
earned by a qualified phase 2 or phase 3 ultra-deep well?
To use an RSV earned under Sec. 203.31:
(a) You must notify the BSEE Regional Supervisor for Production and
Development in writing of your intent to begin drilling operations on
all your ultra-deep wells.
(b) Before beginning production, you must meet any production
measurement requirements that the BSEE Regional Supervisor for
Production and Development has determined are necessary under 30 CFR
part 250, subpart L.
(c)(1) Within 30 days of the beginning of production from any wells
that would become qualified phase 2 or phase 3 ultra-deep wells by
satisfying the requirements of this section:
(i) Provide written notification to the BSEE Regional Supervisor
for Production and Development that production has begun; and
(ii) Request confirmation of the size of the RSV earned by your
lease.
(2) If you produced from a qualified phase 2 or phase 3 ultra-deep
well before December 18, 2008, you must provide the information in
paragraph (c)(1) of this section no later than January 20, 2009.
(d) If you cannot produce from a well that otherwise meets the
criteria for a qualified phase 2 ultra-deep well that is an ultra-deep
short sidetrack before May 3, 2009, on a lease that is located entirely
or partly in water less than 200 meters deep, or before May 3, 2013, on
a lease that is located entirely in water more than 200 meters but less
than 400 meters deep, the BSEE Regional Supervisor for Production and
Development may extend the deadline for beginning production for up to
1 year, based on the circumstances of the particular well involved, if
it meets all the following criteria.
(1) The delay occurred after drilling reached the total depth in
your well.
(2) Production (other than test production) was expected to begin
from the well before May 3, 2009, on a lease that is located entirely
or partly in water less than 200 meters deep or before May 3, 2013, on
a lease that is located entirely in water more than 200 meters but less
than 400 meters deep. You must provide a credible activity schedule
with supporting documentation.
(3) The delay in beginning production is for reasons beyond your
control, such as adverse weather and accidents which BSEE deems were
unavoidable.
Sec. 203.36 Do I keep royalty relief if prices rise significantly?
(a) You must pay the Office of Natural Resources Revenue royalties
on all gas production to which an RSV otherwise would be applied under
Sec. 203.33 for any calendar year in which the average daily closing
New York Mercantile Exchange (NYMEX) natural gas price exceeds the
applicable threshold price shown in the following table.
------------------------------------------------------------------------
A price threshold in year 2007 dollars
of . . . Applies to . . .
------------------------------------------------------------------------
(1) $10.15 per MMBtu, (i) The first 25 BCF of RSV
earned under Sec. 203.31(a)
by a phase 2 ultra-deep well
on a lease that is located in
water partly or entirely less
than 200 meters deep issued
before December 18, 2008; and
(ii) Any RSV earned under Sec.
203.31(b) by a phase 2 ultra-
deep well.
(2) $4.55 per MMBtu, (i) Any RSV earned under Sec.
203.31(a) by a phase 3 ultra-
deep well unless the lease
terms prescribe a different
price threshold;
(ii) The last 10 BCF of the 35
BCF of RSV earned under Sec.
203.31(a) by a phase 2 ultra-
deep well on a lease that is
located in water partly or
entirely less than 200 meters
deep issued before December
18, 2008, and that is not a
non-converted lease;
(iii) The last 15 BCF of the 35
BCF of RSV earned under Sec.
203.31(a) by a phase 2 ultra-
deep well on a non-converted
lease;
(iv) Any RSV earned under Sec.
203.31(a) by a phase 2 ultra-
deep well on a lease in water
partly or entirely less than
200 meters deep issued on or
after December 18, 2008,
unless the lease terms
prescribe a different price
threshold; and
(v) Any RSV earned under Sec.
203.31(a) by a phase 2 ultra-
deep well on a lease in water
entirely more than 200 meters
deep and entirely less than
400 meters deep.
(3) $4.08 per MMBtu, (i) The first 20 BCF of RSV
earned by a well that is
located on a non-converted
lease issued in OCS Lease Sale
178.
[[Page 64472]]
(4) $5.83 per MMBtu, (i) The first 20 BCF of RSV
earned by a well that is
located on a non-converted
lease issued in OCS Lease
Sales 180, 182, 184, 185, or
187.
------------------------------------------------------------------------
(b) For purposes of paragraph (a) of this section, determine the
threshold price for any calendar year after 2007 by:
(1) Determining the percentage of change during the year in the
Department of Commerce's implicit price deflator for the gross domestic
product; and
(2) Adjusting the threshold price for the previous year by that
percentage.
(c) The following examples illustrate how this section applies.
Example 1: Assume that a lessee drills and begins producing from
a qualified phase 2 ultra-deep well in 2008 on a lease issued in
2004 in less than 200 meters of water that earns the lease an RSV of
35 BCF. Further, assume the well produces a total of 18 BCF by the
end of 2009 and in both of those years, the average daily NYMEX
closing natural gas price is less than $10.15 (adjusted for
inflation after 2007). The lessee does not pay royalty on the 18 BCF
because the gas price threshold under paragraph (a)(1) of this
section applies to the first 25 BCF of this RSV earned by this phase
2 ultra-deep well. In 2010, the well produces another 13 BCF. In
that year, the average daily closing NYMEX natural gas price is
greater than $4.55 per MMBtu (adjusted for inflation after 2007),
but less than $10.15 per MMBtu (adjusted for inflation after 2007).
The first 7 BCF produced in 2010 will exhaust the first 25 BCF (that
is subject to the $10.15 threshold) of the 35 BCF RSV that the well
earned. The lessee must pay royalty on the remaining 6 BCF produced
in 2010, because it is subject to the $4.55 per MMBtu threshold
under paragraph (a)(2)(ii) of this section which was exceeded.
Example 2: Assume that a lessee:
(1) Drills and produces from well no.1, a qualified deep well in
2008 to a depth of 15,500 feet TVD SS that earns a 15 BCF RSV for
the lease under Sec. 203.41, which would be subject to a price
threshold of $10.15 per MMBtu (adjusted for inflation after 2007),
meaning the lease is partly or entirely in less than 200 meters of
water;
(2) Later in 2008, drills and produces from well no. 2, a second
qualified deep well to a depth of 17,000 feet TVD SS that earns no
additional RSV (see Sec. 203.41(c)(1)); and
(3) In 2015, drills and produces from well no. 3, a qualified
phase 3 ultra-deep well that earns no additional RSV since the lease
already has an RSV established by prior deep well production.
Further assume that in 2015, the average daily closing NYMEX natural
gas price exceeds $4.55 per MMBtu (adjusted for inflation after
2007) but does not exceed $10.15 per MMBtu (adjusted for inflation
after 2007). In 2015, any remaining RSV earned by well no. 1 (which
would have been applied to production from well nos. 1 and 2 in the
intervening years), would be applied to production from all three
qualified wells. Because the price threshold applicable to that RSV
was not exceeded, the production from all three qualified wells
would be royalty-free until the 15 BCF RSV earned by well no. 1 is
exhausted.
Example 3: Assume the same initial facts regarding the three
wells as in Example 2. Further assume that well no. 1 stopped
producing in 2011 after it had produced 8 BCF, and that well no. 2
stopped producing in 2012 after it had produced 5 BCF. Two BCF of
the RSV earned by well no. 1 remain. That RSV would be applied to
production from well no. 3 until it is exhausted, and the lessee
therefore would not pay royalty on those 2 BCF produced in 2015,
because the $10.15 per MMBtu (adjusted for inflation after 2007)
price threshold is not exceeded. The determination of which price
threshold applies to deep gas production depends on when the first
qualified well earned the RSV for the lease, not on which wells use
the RSV.
Example 4: Assume that in February 2010, a lessee completes and
begins producing from an ultra-deep well (at a depth of 21,500 feet
TVD SS) on a lease located in 325 meters of water with no prior
production from any deep well and no deep water royalty relief. The
ultra-deep well would be a phase 2 ultra-deep well (see definition
in Sec. 203.0), and would earn the lease an RSV of 35 BCF under
Sec. Sec. 203.30 and 203.31. Further assume that the average daily
closing NYMEX natural gas price exceeds $4.55 per MMBtu (adjusted
for inflation after 2007) but does not exceed $10.15 per MMBtu
(adjusted for inflation after 2007) during 2010. Because the lease
is located in more than 200 but less than 400 meters of water, the
$4.55 per MMBtu price threshold applies to the whole RSV (see
paragraph (a)(2)(v) of this section), and the lessee will owe
royalty on all gas produced from the ultra-deep well in 2010.
(d) You must pay any royalty due under this section no later than
March 31 of the year following the calendar year for which you owe
royalty. If you do not pay by that date, you must pay late payment
interest under 30 CFR 1218.54 from April 1 until the date of payment.
(e) Production volumes on which you must pay royalty under this
section count as part of your RSV.
Royalty Relief for Drilling Deep Gas Wells on Leases Not Subject to
Deep Water Royalty Relief
Sec. 203.40 Which leases are eligible for royalty relief as a result
of drilling a deep well or a phase 1 ultra-deep well?
Your lease may receive an RSV under Sec. Sec. 203.41 through
203.44, and may receive an RSS under Sec. Sec. 203.45 through 203.47,
if it meets all the requirements of this section.
(a) The lease is located in the GOM wholly west of 87 degrees, 30
minutes West longitude in water depths entirely less than 400 meters
deep.
(b) The lease has not produced gas or oil from a well with a
perforated interval the top of which is 18,000 feet TVD SS or deeper
that commenced drilling either:
(1) Before March 26, 2003, on a lease that is located partly or
entirely in water less than 200 meters deep; or
(2) Before May 18, 2007, on a lease that is located in water
entirely more than 200 meters and entirely less than 400 meters deep.
(c) In the case of a lease located partly or entirely in water less
than 200 meters deep, the lease was issued in a lease sale held either:
(1) Before January 1, 2001;
(2) On or after January 1, 2001, and before January 1, 2004, and,
in cases where the original lease terms provided for an RSV for deep
gas production, the lessee has exercised the option provided for in
Sec. 203.49; or
(3) On or after January 1, 2004, and the lease terms provide for
royalty relief under Sec. Sec. 203.41 through 203.47. (Note: Because
the original Sec. 203.41 has been divided into new Sec. Sec. 203.41
and 203.42 and subsequent sections have been redesignated as Sec. Sec.
203.43 through 203.48, royalty relief in lease terms for leases issued
on or after January 1, 2004, should be read as referring to Sec. Sec.
203.41 through 203.48.)
(d) If the lease is located entirely in more than 200 meters and
less than 400 meters of water, it must either:
(1) Have been issued before November 28, 1995, and not been granted
deep water royalty relief under 43 U.S.C. 1337(a)(3)(C), added by
section 302 of the Deep Water Royalty Relief Act; or
(2) Have been issued after November 28, 2000, and not been granted
deep water royalty relief under Sec. Sec. 203.60 through 203.79.
Sec. 203.41 If I have a qualified deep well or a qualified phase 1
ultra-deep well, what royalty relief would my lease earn?
(a) To qualify for a suspension volume under paragraphs (b) or (c)
of this section, your lease must meet the requirements in Sec. 203.40
and the requirements in the following table.
[[Page 64473]]
------------------------------------------------------------------------
And if it later . . Then your lease . .
If your lease has not . . . . .
------------------------------------------------------------------------
(1) produced gas or oil from Has a qualified deep earns an RSV
any deep well or ultra-deep well or qualified specified in
well, phase 1 ultra-deep paragraph (b) of
well, this section.
(2) produced gas or oil from Has a qualified deep earns an RSV
a well with a perforated well with a specified in
interval whose top is perforated interval paragraph (c) of
18,000 feet TVD SS or whose top is 18,000 this section.
deeper, feet TVD SS or
deeper or a
qualified phase 1
ultra-deep well,
------------------------------------------------------------------------
(b) If your lease meets the requirements in paragraph (a)(1) of
this section, it earns the RSV prescribed in the following table:
------------------------------------------------------------------------
If you have a qualified deep well or a Then your lease earns an RSV on
qualified phase 1 ultra-deep well that this volume of gas production:
is:
------------------------------------------------------------------------
(1) An original well with a perforated 15 BCF.
interval the top of which is from
15,000 to less than 18,000 feet TVD
SS,
(2) A sidetrack with a perforated 4 BCF plus 600 MCF times
interval the top of which is from sidetrack measured depth
15,000 to less than 18,000 feet TVD (rounded to the nearest 100
SS, feet) but no more than 15 BCF.
(3) An original well with a perforated 25 BCF.
interval the top of which is at least
18,000 feet TVD SS,
(4) A sidetrack with a perforated 4 BCF plus 600 MCF times
interval the top of which is at least sidetrack measured depth
18,000 feet TVD SS, (rounded to the nearest 100
feet) but no more than 25 BCF.
------------------------------------------------------------------------
(c) If your lease meets the requirements in paragraph (a)(2) of
this section, it earns the RSV prescribed in the following table. The
RSV specified in this paragraph is in addition to any RSV your lease
already may have earned from a qualified deep well with a perforated
interval whose top is from 15,000 feet to less than 18,000 feet TVD SS.
------------------------------------------------------------------------
If you have a qualified deep well or a
qualified phase 1 ultra-deep well that Then you earn an RSV on this
is . . . amount of gas production:
------------------------------------------------------------------------
(1) An original well or a sidetrack 0 BCF.
with a perforated interval the top of
which is from 15,000 to less than
18,000 feet TVD SS,
(2) An original well with a perforated 10 BCF.
interval the top of which is 18,000
feet TVD SS or deeper,
(3) A sidetrack with a perforated 4 BCF plus 600 MCF times
interval the top of which is 18,000 sidetrack measured depth
feet TVD SS or deeper, (rounded to the nearest 100
feet) but no more than 10 BCF.
------------------------------------------------------------------------
(d) Lessees may request a refund of or recoup royalties paid on
production from qualified wells on a lease that is located in water
entirely deeper than 200 meters but entirely less than 400 meters deep
that:
(1) Occurs before December 18, 2008; and
(2) Is subject to application of an RSV under either Sec. 203.31
or Sec. 203.41.
(e) The following examples illustrate how this section applies,
assuming your lease meets the location, prior production, and lease
issuance conditions in Sec. 203.40 and paragraph (a) of this section:
Example 1: If you have a qualified deep well that is an original
well with a perforated interval the top of which is 16,000 feet TVD
SS, your lease earns an RSV of 15 BCF under paragraph (b)(1) of this
section. This RSV must be applied to gas production from all
qualified wells on your lease, as prescribed in Sec. Sec. 203.43
and 203.48. However, if the top of the perforated interval is 18,500
feet TVD SS, the RSV is 25 BCF according to paragraph (b)(3) of this
section.
Example 2: If you have a qualified deep well that is a
sidetrack, with a perforated interval the top of which is 16,000
feet TVD SS and a sidetrack measured depth of 6,789 feet, we round
the measured depth to 6,800 feet and your lease earns an RSV of 8.08
BCF under paragraph (b)(2) of this section. This RSV would be
applied to gas production from all qualified wells on your lease, as
prescribed in Sec. Sec. 203.43 and 203.48.
Example 3: If you have a qualified deep well that is a
sidetrack, with a perforated interval the top of which is 16,000
feet TVD SS and a sidetrack measured depth of 19,500 feet, your
lease earns an RSV of 15 BCF. This RSV would be applied to gas
production from all qualified wells on your lease, as prescribed in
Sec. Sec. 203.43 and 203.48, even though 4 BCF plus 600 MCF per
foot of sidetrack measured depth equals 15.7 BCF because paragraph
(b)(2) of this section limits the RSV for a sidetrack at the amount
an original well to the same depth would earn.
Example 4: If you have drilled and produced a deep well with a
perforated interval the top of which is 16,000 feet TVD SS before
March 26, 2003 (and the well therefore is not a qualified well and
has earned no RSV under this section), and later drill:
(i) A deep well with a perforated interval the top of which is
17,000 feet TVD SS, your lease earns no RSV (see paragraph (c)(1) of
this section);
(ii) A qualified deep well that is an original well with a
perforated interval the top of which is 19,000 feet TVD SS, your
lease earns an RSV of 10 BCF under paragraph (c)(2) of this section.
This RSV would be applied to gas production from qualified wells on
your lease, as prescribed in Sec. Sec. 203.43 and 203.48; or
(iii) A qualified deep well that is a sidetrack with a
perforated interval the top of which is 19,000 feet TVD SS, that has
a sidetrack measured depth of 7,000 feet, your lease earns an RSV of
8.2 BCF under paragraph (c)(3) of this section. This RSV would be
applied to gas production from qualified wells on your lease, as
prescribed in Sec. Sec. 203.43 and 203.48.
Example 5: If you have a qualified deep well that is an original
well with a perforated interval the top of which is 16,000 feet TVD
SS, and later drill a second qualified well that is an original well
with a perforated interval the top of which is 19,000 feet TVD SS,
we increase the total RSV for your lease from 15 BCF to 25 BCF under
paragraph (c)(2) of this section. We will apply that RSV to gas
production from all qualified wells on your lease, as prescribed in
Sec. Sec. 203.43 and 203.48. If the second well has a perforated
interval the top of which is 22,000 feet TVD SS (instead of 19,000
feet), the total RSV for your lease would increase to 25 BCF only in
[[Page 64474]]
2 situations: (1) If the second well was a phase 1 ultra-deep well,
i.e., if drilling began before May 18, 2007, or (2) the exception in
Sec. 203.31(b) applies. In both situations, your lease must be
partly or entirely in less than 200 meters of water and production
must begin on this well before May 3, 2009. If drilling of the
second well began on or after May 18, 2007, the second well would be
qualified as a phase 2 or phase 3 ultra-deep well and, unless the
exception in Sec. 203.31(b) applies, would not earn any additional
RSV (as prescribed in Sec. 203.30), so the total RSV for your lease
would remain at 15 BCF.
Example 6: If you have a qualified deep well that is a
sidetrack, with a perforated interval the top of which is 16,000
feet TVD SS and a sidetrack measured depth of 4,000 feet, and later
drill a second qualified well that is a sidetrack, with a perforated
interval the top of which is 19,000 feet TVD SS and a sidetrack
measured depth of 8,000 feet, we increase the total RSV for your
lease from 6.4 BCF [4 + (600 * 4,000)/1,000,000] to 15.2 BCF {6.4 +
[4 + (600 * 8,000)/1,000,000)]{time} under paragraphs (b)(2) and
(c)(3) of this section. We would apply that RSV to gas production
from all qualified wells on your lease, as prescribed in Sec. Sec.
203.43 and 203.48. The difference of 8.8 BCF represents the RSV
earned by the second sidetrack that has a perforated interval the
top of which is deeper than 18,000 feet TVD SS.
Sec. 203.42 What conditions and limitations apply to royalty relief
for deep wells and phase 1 ultra-deep wells?
The conditions and limitations in the following table apply to
royalty relief under Sec. 203.41.
------------------------------------------------------------------------
If . . . Then . . .
------------------------------------------------------------------------
(a) Your lease has produced gas or oil your lease cannot earn an
from a well with a perforated interval RSV under Sec. 203.41 as
the top of which is 18,000 feet TVD SS or a result of drilling any
deeper, subsequent deep wells or
phase 1 ultra-deep wells.
(b) You determine RSV under Sec. 203.41 that determination
for the first qualified deep well or establishes the total RSV
qualified phase 1 ultra-deep well on your available for that drilling
lease (whether an original well or a depth interval on your
sidetrack) because you drilled and lease (i.e., either 15,000-
produced it within the time intervals set 18,000 feet TVD SS, or
forth in the definitions for qualified 18,000 feet TVD SS and
wells, deeper), regardless of the
number of subsequent
qualified wells you drill
to that depth interval.
(c) A qualified deep well or qualified the RSV earned by that well
phase 1 ultra-deep well on your lease is under Sec. 203.41 applies
within a unitized portion of your lease, only to production from
qualified wells on or
allocated to your lease and
not to other leases within
the unit.
(d) Your qualified deep well or qualified the lease with the
phase 1 ultra-deep well is a directional perforated interval that
well (either an original well or a initially produces earns
sidetrack) drilled across a lease line, the RSV. However, if the
perforated interval crosses
a lease line, the lease
where the surface of the
well is located earns the
RSV.
(e) You earn an RSV under Sec. 203.41, that RSV is in addition to
any RSS for your lease
under Sec. 203.45 that
results from a different
wellbore.
(f) Your lease earns an RSV under Sec. the RSV is not forfeited or
203.41 and later produces from a well terminated, but you may not
that is not a qualified well, apply the RSV under Sec.
203.41 to production from
the non-qualified well.
(g) You qualify for an RSV under you still owe minimum
paragraphs (b) or (c) of Sec. 203.41, royalties or rentals in
accordance with your lease
terms.
(h) You transfer your lease, unused RSVs transfer to a
successor lessee and expire
with the lease.
------------------------------------------------------------------------
Example to paragraph (b): If your first qualified deep well is a
sidetrack with a perforated interval whose top is 16,000 feet TVD SS
and earns an RSV of 12.5 BCF, and you later drill a qualified original
deep well to 17,000 feet TVD SS, the RSV for your lease remains at 12.5
BCF and does not increase to 15 BCF. However, under paragraph (c) of
Sec. 203.41, if you subsequently drill a qualified deep well to a
depth of 18,000 feet or greater TVD SS, you may earn an additional RSV.
Sec. 203.43 To which production do I apply the RSV earned from
qualified deep wells or qualified phase 1 ultra-deep wells on my lease?
(a) You must apply the RSV prescribed in Sec. 203.41(b) and (c) to
gas volumes produced from qualified wells on or after May 3, 2004,
reported on the OGOR-A for your lease under 30 CFR 1210.102, as and to
the extent prescribed in Sec. Sec. 203.43 and 203.48.
(1) Except as provided in paragraph (a)(2) of this section, all gas
production from qualified wells reported on the OGOR-A, including
production that is not subject to royalty, counts toward the lease RSV.
(2) Production to which an RSS applies under Sec. Sec. 203.45 and
203.46 does not count toward the lease RSV.
(b) This paragraph applies to any lease with a qualified deep well
or qualified phase 1 ultra-deep well when no part of the lease is
within a BSEE-approved unit. Subject to the price conditions in Sec.
203.48, you must apply the RSV prescribed in Sec. 203.41 as required
under the following paragraphs (b)(1) and (b)(2) of this section.
(1) You must apply the RSV to the earliest gas production occurring
on and after the later of:
(i) May 3, 2004, for an RSV earned by a qualified deep well or
qualified phase 1 ultra-deep well on a lease that is located entirely
or partly in water less than 200 meters deep;
(ii) May 18, 2007, for an RSV earned by a qualified deep well on a
lease that is located entirely in water more than 200 meters deep; or
(iii) The date that the first qualified well that earns your lease
the RSV begins production (other than test production).
(2) You must apply the RSV to only gas production from qualified
wells on your lease, regardless of their depth, for which you have met
the requirements in Sec. 203.35 or Sec. 203.44.
Example 1: On a lease in water less than 200 meters deep, you
began drilling an original deep well with a perforated interval the
top of which is 18,200 feet TVD SS in September 2003, that became a
qualified deep well in July 2004, when it began producing and using
the RSV that it earned. You subsequently drill another original deep
well with a perforated interval the top of which is 16,600 feet TVD
SS, which becomes a qualified deep well when production begins in
August 2008. The first well earned an RSV of 25 BCF (see Sec.
203.41(a)(1) and (b)(3)). You must apply any remaining RSV each
month beginning in August 2008 to production from both wells until
the 25 BCF RSV is fully utilized according to paragraph (b)(2) of
this section. If the second well had begun production in August
2009, it would not be a qualified deep well because it started
production after expiration in May 2009 of the ability to qualify
for royalty relief in this water depth, and could not share any of
the remaining RSV (see definition of a qualified deep well in Sec.
203.0).
Example 2: On a lease in water between 200 and 400 meters deep,
you begin drilling an original deep well with a perforated interval
the top of which is 17,100 feet TVD SS in November 2010 that becomes
a qualified deep well in June 2011 when it begins producing and
using the RSV. You subsequently drill another original deep well
with a perforated interval the top of which is 15,300 feet TVD SS
which becomes a qualified deep well by beginning production in
October 2011 (see definition of a qualified deep well in Sec.
203.0). Only the first well earns an RSV equal to 15 BCF (see Sec.
203.41(a) and (b)). You must apply any remaining RSV each month
beginning in October 2011 to production from both qualified deep
wells
[[Page 64475]]
until the 15 BCF RSV is fully utilized according to paragraph (b)(2)
of this section.
(c) This paragraph applies to any lease with a qualified deep well
or qualified phase 1 ultra-deep well when all or part of the lease is
within a BSEE-approved unit. Under the unit agreement, a share of the
production from all the qualified wells in the unit participating area
would be allocated to your lease each month according to the
participating area percentages. Subject to the price conditions in
Sec. 203.48, you must apply the RSV prescribed under Sec. 203.41 as
required under the following paragraphs (c)(1) through (3) of this
section.
(1) You must apply the RSV to the earliest gas production occurring
on and after the later of:
(i) May 3, 2004, for an RSV earned by a qualified well or qualified
phase 1 ultra-deep well on a lease that is located entirely or partly
in water less than 200 meters deep;
(ii) May 18, 2007, for an RSV earned by a qualified deep well on a
lease that is located entirely in water more than 200 meters deep; or
(iii) The date that the first qualified well that earns your lease
the RSV begins production (other than test production).
(2) You must apply the RSV to only gas production:
(i) From all qualified wells on the non-unitized area of your
lease, regardless of their depth, for which you have met the
requirements in Sec. 203.35 or Sec. 203.44; and,
(ii) Allocated to your lease under a BSEE-approved unit agreement
from qualified wells on unitized areas of your lease and on unitized
areas of other leases in the unit, regardless of their depth, for which
the requirements in Sec. 203.35 or Sec. 203.44 have been met.
(3) The allocated share under paragraph (c)(2)(ii) of this section
does not increase the RSV for your lease. None of the volumes produced
from a well that is not within a unit participating area may be
allocated to other leases in the unit.
Example: The east half of your lease A is unitized with all of
lease B. There is one qualified 19,000-foot TVD SS deep well on the
non-unitized portion of lease A, one qualified 18,500-foot TVD SS
deep well on the unitized portion of lease A, and a qualified
19,400-foot TVD SS deep well on lease B. The participating area
percentages allocate 32 percent of production from both of the unit
qualified deep wells to lease A and 68 percent to lease B. If the
non-unitized qualified deep well on lease A produces 12 BCF and the
unitized qualified deep well on lease A produces 15 BCF, and the
qualified deep well on lease B produces 10 BCF, then the production
volume from and allocated to lease A to which the lease an RSV
applies is 20 BCF [12 + (15 + 10) * (0.32)]. The production volume
allocated to lease B to which the lease B RSV applies is 17 BCF [(15
+ 10) * (0.68)].
(d) You must begin paying royalties when the cumulative production
of gas from all qualified wells on your lease, or allocated to your
lease under paragraph (c) of this section, reaches the applicable RSV
allowed under Sec. 203.31 or Sec. 203.41. For the month in which
cumulative production reaches this RSV, you owe royalties on the
portion of gas production that exceeds the RSV remaining at the
beginning of that month.
(e) You may not apply the RSV allowed under Sec. 203.41 to:
(1) Production from completions less than 15,000 feet TVD SS,
except in cases where the qualified deep well is re-perforated in the
same reservoir previously perforated deeper than 15,000 feet TVD SS;
(2) Production from a deep well or phase 1 ultra-deep well on any
other lease, except as provided in paragraph (c) of this section;
(3) Any liquid hydrocarbon (oil and condensate) volumes; or
(4) Production from a deep well or phase 1 ultra-deep well that
commenced drilling before:
(i) March 26, 2003, on a lease that is located entirely or partly
in water less than 200 meters deep, or
(ii) May 18, 2007, on a lease that is located entirely in water
more than 200 meters deep.
Sec. 203.44 What administrative steps must I take to use the royalty
suspension volume?
(a) You must notify the BSEE Regional Supervisor for Production and
Development in writing of your intent to begin drilling operations on
all deep wells and phase 1 ultra-deep wells; and
(b) Within 30 days of the beginning of production from all wells
that would become qualified wells by satisfying the requirements of
this section, you must:
(1) Provide written notification to the BSEE Regional Supervisor
for Production and Development that production has begun; and
(2) Request confirmation of the size of the royalty suspension
volume earned by your lease.
(c) Before beginning production, you must meet any production
measurement requirements that the BSEE Regional Supervisor for
Production and Development has determined are necessary under 30 CFR
part 250, subpart L.
(d) You must provide the information in paragraph (b) of this
section by January 20, 2009, if you produced before December 18, 2008,
from a qualified deep well or qualified phase 1 ultra-deep well on a
lease that is located entirely in water more than 200 meters and less
than 400 meters deep.
(e) The BSEE Regional Supervisor for Production and Development may
extend the deadline for beginning production for up to one year for a
well that cannot begin production before the applicable date prescribed
in the definition of ``qualified deep well'' in Sec. 203.0 if it meets
all of the following criteria.
(1) The well otherwise meets the criteria in the definition of a
qualified deep well in Sec. 203.0.
(2) The delay in production occurred after reaching total depth in
the well.
(3) Production (other than test production) was expected to begin
from the well before the applicable deadline in the definition of a
qualified deep well in Sec. 203.0. You must provide a credible
activity schedule with supporting documentation.
(4) The delay in beginning production is for reasons beyond your
control, such as adverse weather and accidents which BSEE deems were
unavoidable.
Sec. 203.45 If I drill a certified unsuccessful well, what royalty
relief will my lease earn?
Your lease may earn a royalty suspension supplement. Subject to
paragraph (d) of this section, the royalty suspension supplement is in
addition to any royalty suspension volume your lease may earn under
Sec. 203.41.
(a) If you drill a certified unsuccessful well and you satisfy the
administrative requirements of Sec. 203.47, subject to the price
conditions in Sec. 203.48, your lease earns an RSS shown in the
following table. The RSS is shown in billions of cubic feet of gas
equivalent (BCFE) or in thousands of cubic feet of gas equivalent
(MCFE) and is applicable to oil and gas production as prescribed in
Sec. 203.46.
------------------------------------------------------------------------
Then your lease earns an RSS
on this volume of oil and
If you have a certified unsuccessful well gas production as prescribed
that is:-- in this section and Sec.
203.46:--
------------------------------------------------------------------------
(1) An original well and your lease has 5 BCFE.
not produced gas or oil from a deep well
or an ultra-deep well,
[[Page 64476]]
(2) A sidetrack (with a sidetrack measured 0.8 BCFE plus 120 MCFE times
depth of at least 10,000 feet) and your sidetrack measured depth
lease has not produced gas or oil from a (rounded to the nearest 100
deep well or an ultra-deep well, feet) but no more than 5
BCFE.
(3) An original well or a sidetrack (with 2 BCFE.
a sidetrack measured depth of at least
10,000 feet) and your lease has produced
gas or oil from a deep well with a
perforated interval the top of which is
from 15,000 to less than 18,000 feet TVD
SS,
------------------------------------------------------------------------
(b) This paragraph applies to oil and gas volumes you report on
the OGOR-A for your lease under 30 CFR 1210.102.
(1) You must apply the RSS prescribed in paragraph (a) of this
section, in accordance with the requirements in Sec. 203.46, to all
oil and gas produced from the lease:
(i) On or after December 18, 2008, if your lease is located in
water more than 200 meters but less than 400 meters deep; or
(ii) On or after May 3, 2004, if your lease is located in water
partly or entirely less than 200 meters deep.
(2) Production to which an RSV applies under Sec. Sec. 203.31
through 203.33 and Sec. Sec. 203.41 through 203.43 does not count
toward the lease RSS. All other production, including production that
is not subject to royalty, counts toward the lease RSS.
Example 1: If you drill a certified unsuccessful well that is an
original well to a target 19,000 feet TVD SS, your lease earns an
RSS of 5 BCFE that would be applied to gas and oil production if
your lease has not previously produced from a deep well or an ultra-
deep well, or you earn an RSS of 2 BCFE of gas and oil production if
your lease has previously produced from a deep well with a
perforated interval from 15,000 to less than 18,000 feet TVD SS, as
prescribed in Sec. 203.46.
Example 2: If you drill a certified unsuccessful well that is a
sidetrack that reaches a target 19,000 feet TVD SS, that has a
sidetrack measured depth of 12,545 feet, and your lease has not
produced gas or oil from any deep well or ultra-deep well, BSEE
rounds the sidetrack measured depth to 12,500 feet and your lease
earns an RSS of 2.3 BCFE of gas and oil production as prescribed in
Sec. 203.45.
(c) The conversion from oil to gas for using the royalty suspension
supplement is specified in Sec. 203.73.
(d) Each lease is eligible for up to two royalty suspension
supplements. Therefore, the total royalty suspension supplement for a
lease cannot exceed 10 BCFE.
(1) You may not earn more than one royalty suspension supplement
from a single wellbore.
(2) If you begin drilling a certified unsuccessful well on one
lease but the completion target is on a second lease, the entire
royalty suspension supplement belongs to the second lease. However, if
the target straddles a lease line, the lease where the surface of the
well is located earns the royalty suspension supplement.
(e) If the same wellbore that earns an RSS as a certified
unsuccessful well later produces from a perforated interval the top of
which is 15,000 feet TVD or deeper and becomes a qualified well, it
will be subject to the following conditions:
(1) Beginning on the date production starts, you must stop applying
the royalty suspension supplement earned by that wellbore to your lease
production.
(2) If the completion of this qualified well is on your lease or,
in the case of a directional well, is on another lease, then you must
subtract from the royalty suspension volume earned by that qualified
well the royalty suspension supplement amounts earned by that wellbore
that have already been applied either on your lease or any other lease.
The difference represents the royalty suspension volume earned by the
qualified well.
(f) If the same wellbore that earned a royalty suspension
supplement later has a sidetrack drilled from that wellbore, you are
not required to subtract any royalty suspension supplement earned by
that wellbore from the royalty suspension volume that may be earned by
the sidetrack.
(g) You owe minimum royalties or rentals in accordance with your
lease terms notwithstanding any royalty suspension supplements under
this section.
Sec. 203.46 To which production do I apply the royalty suspension
supplements from drilling one or two certified unsuccessful wells on my
lease?
(a) Subject to the requirements of Sec. Sec. 203.40, 203.43,
203.45, 203.47, and 203.48 you must apply an RSS in Sec. 203.45 to the
earliest oil and gas production:
(1) Occurring on and after the day you file the information under
Sec. 203.47(b),
(2) From, or allocated under a BSEE-approved unit agreement to, the
lease on which the certified unsuccessful well was drilled, without
regard to the drilling depth of the well producing the gas or oil.
(b) If you have a royalty suspension volume for the lease under
Sec. 203.41, you must use the royalty suspension volumes for gas
produced from qualified wells on the lease before using royalty
suspension supplements for gas produced from qualified wells.
Example to paragraph (b): You have two shallow oil wells on your
lease. Then you drill a certified unsuccessful well and earn a
royalty suspension supplement of 5 BCFE. Thereafter, you begin
production from an original well that is a qualified well that earns
a royalty suspension volume of 15 BCF. You use only 2 BCFE of the
royalty suspension supplement before the oil wells deplete. You must
use up the 15 BCF of royalty suspension volume before you use the
remaining 3 BCFE of the royalty suspension supplement for gas
produced from the qualified well.
(c) If you have no current production on which to apply the RSS
allowed under Sec. 203.45, your RSS applies to the earliest subsequent
production of gas and oil from, or allocated under a BSEE-approved unit
agreement to, your lease.
(d) Unused royalty suspension supplements transfer to a successor
lessee and expire with the lease.
(e) You may not apply the RSS allowed under Sec. 203.45 to
production from any other lease, except for production allocated to
your lease from a BSEE-approved unit agreement. If your certified
unsuccessful well is on a lease subject to a BSEE-approved unit
agreement, the lessees of other leases in the unit may not apply any
portion of the RSS for your lease to production from the other leases
in the unit.
(f) You must begin or resume paying royalties when cumulative gas
and oil production from, or allocated under a BSEE-approved unit
agreement to, your lease (excluding any gas produced from qualified
wells subject to a royalty suspension volume allowed under Sec.
203.41) reaches the applicable royalty suspension supplement. For the
month in which the cumulative production reaches this royalty
suspension supplement, you owe royalties on the portion of gas or oil
production that exceeds the amount of the royalty
[[Page 64477]]
suspension supplement remaining at the beginning of that month.
Sec. 203.47 What administrative steps do I take to obtain and use the
royalty suspension supplement?
(a) Before you start drilling a well on your lease targeted to a
reservoir at least 18,000 feet TVD SS, you must notify, in writing, the
BSEE Regional Supervisor for Production and Development of your intent
to begin drilling operations and the depth of the target.
(b) After drilling the well, you must provide the BSEE Regional
Supervisor for Production and Development within 60 days after reaching
the total depth in your well:
(1) Information that allows BSEE to confirm that you drilled a
certified unsuccessful well as defined under Sec. 203.0, including:
(i) Well log data, if your original well or sidetrack does not meet
the producibility requirements of 30 CFR part 550, subpart A; or
(ii) Well log, well test, seismic, and economic data, if your well
does meet the producibility requirements of 30 CFR part 550, subpart A;
and
(2) Information that allows BSEE to confirm the size of the royalty
suspension supplement for a sidetrack, including sidetrack measured
depth and supporting documentation.
(c) If you commenced drilling a well that otherwise meets the
criteria for a certified unsuccessful well on a lease located entirely
in more than 200 meters and entirely less than 400 meters of water on
or after May 18, 2007, and finished it before December 18, 2008, you
must provide the information in paragraph (b) of this section no later
than February 17, 2009.
Sec. 203.48 Do I keep royalty relief if prices rise significantly?
(a) You must pay royalties on all gas and oil production for which
an RSV or an RSS otherwise would be allowed under Sec. Sec. 203.40
through 203.47 for any calendar year when the average daily closing
NYMEX natural gas price exceeds the applicable threshold price shown in
the following table.
------------------------------------------------------------------------
For a lease located in The applicable threshold
water . . . And issued . . . price is . . .
------------------------------------------------------------------------
(1) Partly or entirely before December 18, $10.15 per MMBtu,
less than 200 meters 2008, adjusted annually after
deep, calendar year 2007 for
inflation.
(2) Partly or entirely after December 18, $4.55 per MMBtu, adjusted
less than 200 meters 2008, annually after calendar
deep, year 2007 for inflation
unless the lease terms
prescribe a different
price threshold.
(3) Entirely more than on any date, $4.55 per MMBtu, adjusted
200 meters and annually after calendar
entirely less than year 2007 for inflation
400 meters deep, unless the lease terms
prescribe a different
price threshold.
------------------------------------------------------------------------
(b) Determine the threshold price for any calendar year after 2007
by adjusting the threshold price in the previous year by the percentage
that the implicit price deflator for the gross domestic product, as
published by the Department of Commerce, changed during the calendar
year.
(c) You must pay any royalty due under this section no later than
March 31 of the year following the calendar year for which you owe
royalty. If you do not pay by that date, you must pay late payment
interest under 30 CFR 1218.54 from April 1 until the date of payment.
(d) Production volumes on which you must pay royalty under this
section count as part of your RSV and RSS.
Sec. 203.49 May I substitute the deep gas drilling provisions in this
part for the deep gas royalty relief provided in my lease terms?
(a) You may exercise an option to replace the applicable lease
terms for royalty relief related to deep-well drilling with those in
Sec. 203.0 and Sec. Sec. 203.40 through 203.48 if you have a lease
issued with royalty relief provisions for deep-well drilling. Such
leases:
(1) Must be issued as part of an OCS lease sale held after January
1, 2001, and before April 1, 2004; and
(2) Must be located wholly west of 87 degrees, 30 minutes West
longitude in the GOM entirely or partly in water less than 200 meters
deep.
(b) To exercise the option under paragraph (a) of this section, you
must notify, in writing, the BSEE Regional Supervisor for Production
and Development of your decision before September 1, 2004, or 180 days
after your lease is issued, whichever is later, and specify the lease
and block number.
(c) Once you exercise the option under paragraph (a) of this
section, you are subject to all the activity, timing, and
administrative requirements pertaining to deep gas royalty relief as
specified in Sec. Sec. 203.40 through 203.48.
(d) Exercising the option under paragraph (a) of this section is
irrevocable. If you do not exercise this option, then the terms of your
lease apply.
Royalty Relief for End-of-Life Leases
Sec. 203.50 Who may apply for end-of-life royalty relief?
You may apply for royalty relief in two situations.
(a) Your end-of-life lease (as defined in Sec. 203.2) is an oil
and gas lease and has average daily production of at least 100 barrels
of oil equivalent (BOE) per month (as calculated in Sec. 203.73) in at
least 12 of the past 15 months. The most recent of these 12 months are
considered the qualifying months. These 12 months should reflect the
basic operation you intend to use until your resources are depleted. If
you changed your operation significantly (e.g., begin re-injecting
rather than recovering gas) during the qualifying months, or if you do
so while we are processing your application, we may defer action on
your application until you revise it to show the new circumstances.
(b) Your end-of-life lease is other than an oil and gas lease
(e.g., sulphur) and has production in at least 12 of the past 15
months. The most recent of these 12 months are considered the
qualifying months.
Sec. 203.51 How do I apply for end-of-life royalty relief?
You must submit a complete application and the required fee to the
appropriate BSEE Regional Director. Your BSEE regional office will
provide specific guidance on the report formats. A complete application
for relief includes:
(a) An administrative information report (specified in Sec.
203.83) and
(b) A net revenue and relief justification report (specified in
Sec. 203.84).
Sec. 203.52 What criteria must I meet to get relief?
(a) To qualify for relief, you must demonstrate that the sum of
royalty payments over the 12 qualifying months exceeds 75 percent of
the sum of net revenues (before-royalty revenues minus allowable costs,
as defined in Sec. 203.84).
(b) To re-qualify for relief, e.g., either applying for additional
relief on top of relief already granted, or applying for
[[Page 64478]]
relief sometime after your earlier agreement terminated, you must
demonstrate that:
(1) You have met the criterion listed in paragraph (a) of this
section, and
(2) The 12 required qualifying months of operation have occurred
under the current royalty arrangement.
Sec. 203.53 What relief will BSEE grant?
(a) If we approve your application and you meet certain conditions,
we will reduce the pre-application effective royalty rate by one-half
on production up to the relief volume amount. If you produce more than
the relief volume amount:
(1) We will impose a royalty rate equal to 1.5 times the effective
royalty rate on your additional production up to twice the relief
volume amount; and
(2) We will impose a royalty rate equal to the effective rate on
all production greater than twice the relief volume amount.
(b) Regardless of the level of production or prices (see Sec.
203.54), royalty payments due under end-of-life relief will not exceed
the royalty obligations that would have been due at the effective
royalty rate.
(1) The effective royalty rate is the average lease rate paid on
production during the 12 qualifying months.
(2) The relief volume amount is the average monthly BOE production
for the 12 qualifying months.
Sec. 203.54 How does my relief arrangement for an oil and gas lease
operate if prices rise sharply?
In those months when your current reference price rises by at least
25 percent above your base reference price, you must pay the effective
royalty rate on all monthly production.
(a) Your current reference price is a weighted average of daily
closing prices on the NYMEX for light sweet crude oil and natural gas
over the most recent full 12 calendar months;
(b) Your base reference price is a weighted average of daily
closing prices on the NYMEX for light sweet crude oil and natural gas
during the qualifying months; and
(c) Your weighting factors are the proportions of your total
production volume (in BOE) provided by oil and gas during the
qualifying months.
Sec. 203.55 Under what conditions can my end-of-life royalty relief
arrangement for an oil and gas lease be ended?
(a) If you have an end-of-life royalty relief arrangement, you may
renounce it at any time. The lease rate will return to the effective
rate during the qualifying period in the first full month following our
receipt of your renouncement of the relief arrangement.
(b) If you pay the effective lease rate for 12 consecutive months,
we will terminate your relief. The lease rate will return to the
effective rate in the first full month following this termination.
(c) We may stipulate in the letter of approval for individual cases
certain events that would cause us to terminate relief because they are
inconsistent with an end-of-life situation.
Sec. 203.56 Does relief transfer when a lease is assigned?
Yes. Royalty relief is based on the lease circumstances, not
ownership. It transfers upon lease assignment.
Royalty Relief for Pre-Act Deep Water Leases and for Development and
Expansion Projects
Sec. 203.60 Who may apply for royalty relief on a case-by-case basis
in deep water in the Gulf of Mexico or offshore of Alaska?
You may apply for royalty relief under Sec. Sec. 203.61(b) and
203.62 for an individual lease, unit or project if you:
(a) Hold a pre-Act lease (as defined in Sec. 203.0) that we have
assigned to an authorized field (as defined in Sec. 203.0);
(b) Propose an expansion project (as defined in Sec. 203.0); or
(c) Propose a development project (as defined in Sec. 203.0).
Sec. 203.61 How do I assess my chances for getting relief?
You may ask for a nonbinding assessment (a formal opinion on
whether a field would qualify for royalty relief) before turning in
your first complete application on an authorized field. This field must
have a qualifying well under 30 CFR part 550, subpart A, or be on a
lease that has allocated production under an approved unit agreement.
(a) To request a nonbinding assessment, you must:
(1) Submit a draft application in the format and detail specified
in guidance from the BSEE regional office for the GOM;
(2) Propose to drill at least one more appraisal well if you get a
favorable assessment; and
(3) Pay a fee under Sec. 203.3.
(b) You must wait at least 90 days after receiving our assessment
to apply for relief under Sec. 203.62.
(c) This assessment is not binding because a complete application
may contain more accurate information that does not support our
original assessment. It will help you decide whether your proposed
inputs for evaluating economic viability and your supporting data and
assumptions are adequate.
Sec. 203.62 How do I apply for relief?
(a) You must send a complete application and the required fee to
the BSEE Regional Director for your region.
(b) Your application for royalty relief offshore Alaska or in deep
water in the GOM must include an original and two copies (one set of
digital information) of:
(1) Administrative information report;
(2) Economic viability and relief justification report;
(3) G&G report;
(4) Engineering report;
(5) Production report; and
(6) Cost report.
(c) Section 203.82 explains why we are authorized to require these
reports.
(d) Sections 203.81, 203.83, and 203.85 through 203.89 describe
what these reports must include. The BSEE regional office for your
region will guide you on the format for the required reports, and we
encourage you to contact this office before preparing your application
for this guidance.
Sec. 203.63 Does my application have to include all leases in the
field?
(a) For authorized fields, we will accept only one joint
application for all leases that are part of the designated field on the
date of application, except as provided in paragraph (a)(3) of this
section and Sec. 203.64. However, we will evaluate all acreage that
may eventually become part of the authorized field. Therefore, if you
have any other leases that you believe may eventually be part of the
authorized field, you must submit data for these leases according to
Sec. 203.81.
(1) The Regional Director maintains a Field Names Master List with
updates of all leases in each designated field.
(2) To avoid sharing proprietary data with other lessees on the
field, you may submit your proprietary G&G report separately from the
rest of your application. Your application is not complete until we
receive all the required information for each lease on the field. We
will not disclose proprietary data when explaining our assumptions and
reasons for our determinations under Sec. 203.67.
(3) We will not require a joint application if you show good cause
and honest effort to get all lessees in the field to participate. If
you must exclude a lease from your application because its lessee will
not participate, that lease is ineligible for the royalty relief for
the designated field.
(b) If your application seeks only relief for a development project
or an expansion project, your application does not have to include all
leases in the field.
[[Page 64479]]
Sec. 203.64 How many applications may I file on a field or a
development project?
You may file one complete application for royalty relief during the
life of the field or for a development project or an expansion project
designed to produce a reservoir or set of reservoirs. However, you may
send another application if:
(a) You are eligible to apply for a redetermination under Sec.
203.74;
(b) You apply for royalty relief for an expansion project;
(c) You withdraw the application before we make a determination; or
(d) You apply for end-of-life royalty relief.
Sec. 203.65 How long will BSEE take to evaluate my application?
(a) We will determine within 20 working days if your application
for royalty relief is complete. If your application is incomplete, we
will explain in writing what it needs. If you withdraw a complete
application, you may reapply.
(b) We will evaluate your first application on a field within 180
days, evaluate your first application on a development project or an
expansion project within 150 days and evaluate a redetermination under
Sec. 203.75 within 120 days after we determine that it is complete.
(c) We may ask to extend the review period for your application
under the conditions in the following table.
----------------------------------------------------------------------------------------------------------------
If . . . Then we may . . .
----------------------------------------------------------------------------------------------------------------
(1) We need more records to audit sunk Ask to extend the 120-day or 180-day evaluation period. The
costs, extension we request will equal the number of days between when
you receive our request for records and the day we receive the
records.
(2) We cannot evaluate your application for Add another 30 days. We may add more than 30 days, but only if you
a valid reason, such as missing vital agree.
information or inconsistent or inconclusive
supporting data,
(3) We need more data, explanations, or Ask to extend the 120-day or 180-day evaluation period. The
revision, extension we request will equal the number of days between when
you receive our request and the day we receive the information.
----------------------------------------------------------------------------------------------------------------
(d) We may change your assumptions under Sec. 203.62 if our
technical evaluation reveals others that are more appropriate. We may
consult with you before a final decision and will explain any changes.
(e) We will notify all designated lease operators within a field
when royalty relief is granted.
Sec. 203.66 What happens if BSEE does not act in the time allowed?
If we do not act within the timeframes established under Sec.
203.65, you get royalty relief according to the following table.
----------------------------------------------------------------------------------------------------------------
If you apply for royalty And we do not decide within the time
relief for specified, As long as you
----------------------------------------------------------------------------------------------------------------
(a) An authorized field, You get the minimum suspension volumes Abide by Sec. Sec. 203.70 and 203.76.
specified in Sec. 203.69,
(b) An expansion project, You get a royalty suspension for the Abide by Sec. Sec. 203.70 and 203.76.
first year of production,
(c) A development project, You get a royalty suspension for initial Abide by Sec. Sec. 203.70 and 203.76.
production for the number of months
that a decision is delayed beyond the
stipulated timeframes set by Sec.
203.65, plus all the royalty suspension
volume for which you qualify,
----------------------------------------------------------------------------------------------------------------
Sec. 203.67 What economic criteria must I meet to get royalty relief
on an authorized field or project?
We will not approve applications if we determine that royalty
relief cannot make the field, development project, or expansion project
economically viable. Your field or project must be uneconomic while you
are paying royalties and must become economic with royalty relief.
Sec. 203.68 What pre-application costs will BSEE consider in
determining economic viability?
(a) We will not consider ineligible costs as set forth in Sec.
203.89(h) in determining economic viability for purposes of royalty
relief.
(b) We will consider sunk costs according to the following table.
----------------------------------------------------------------------------------------------------------------
We will . . . When determining . . .
----------------------------------------------------------------------------------------------------------------
(1) Include sunk costs, Whether a field that includes a pre-Act lease which has
not produced, other than test production, before the
application or redetermination submission date needs
relief to become economic.
(2) Not include sunk costs, Whether an authorized field, a development project, or an
expansion project can become economic with full relief
(see Sec. 203.67).
(3) Not include sunk costs, How much suspension volume is necessary to make the field,
a development project, or an expansion project economic
(see Sec. 203.69(c)).
(4) Include sunk costs for the project discovery Whether a development project or an expansion project
well on each lease, needs relief to become economic.
----------------------------------------------------------------------------------------------------------------
Sec. 203.69 If my application is approved, what royalty relief will I
receive?
If we approve your application, subject to certain conditions, we
will not collect royalties on a specified suspension volume for your
field, development project, or expansion project. Suspension volumes
include volumes allocated to a lease under an approved unit agreement,
but exclude any volumes of production that are not normally royalty-
bearing under the lease
[[Page 64480]]
or the regulations of this chapter (e.g., fuel gas).
(a) For authorized fields, the minimum royalty-suspension volumes
are:
(1) 17.5 million barrels of oil equivalent (MMBOE) for fields in
200 to 400 meters of water;
(2) 52.5 MMBOE for fields in 400 to 800 meters of water; and
(3) 87.5 MMBOE for fields in more than 800 meters of water.
(b) For development projects, any relief we grant applies only to
project wells and replaces the royalty relief, if any, with which we
issued your lease.
(c) If your project is economic given the royalty relief with which
we issued your lease, we will reject the application.
(d) If the lease has earned or may earn deep gas royalty relief
under Sec. Sec. 203.40 through 203.49 or ultra-deep gas royalty relief
under Sec. Sec. 203.30 through 203.36, we will take the deep gas
royalty relief or ultra-deep gas royalty relief into account in
determining whether further royalty relief for a development project is
necessary for production to be economic.
(e) If neither paragraph (c) nor (d) of this section apply, the
minimum royalty suspension volumes are as shown in the following table:
----------------------------------------------------------------------------------------------------------------
For . . . The minimum royalty suspension volume is . . . Plus . . .
----------------------------------------------------------------------------------------------------------------
(1) RS leases in the GOM or leases A volume equal to the combined royalty 10 percent of the median
offshore Alaska, suspension volumes (or the volume equivalent of the distribution of
based on the data in your approved application known recoverable
for other forms of royalty suspension) with resources upon which BSEE
which BSEE issued the leases participating in based approval of your
the application that have or plan a well into application from all
a reservoir identified in the application, reservoirs included in
the project.
(2) Leases offshore Alaska or other A volume equal to 10 percent of the median of
deep water GOM leases issued in the distribution of known recoverable
sales after November 28, 2000, resources upon which BSEE based approval of
your application from all reservoirs included
in the project.
----------------------------------------------------------------------------------------------------------------
(f) If your application includes pre-Act leases in different
categories of water depth, we apply the minimum royalty suspension
volume for the deepest such lease then assigned to the field. We base
the water depth and makeup of a field on the water-depth delineations
in the ``Lease Terms and Economic Conditions'' map and the ``Fields
Directory'' documents and updates in effect at the time your
application is deemed complete. These publications are available from
the BSEE Gulf of Mexico Regional Office.
(g) You will get a royalty suspension volume above the minimum if
we determine that you need more to make the field or development
project economic.
(h) For expansion projects, the minimum royalty suspension volume
equals 10 percent of the median of the distribution of known
recoverable resources upon which we based approval of your application
from all reservoirs included in your project plus any suspension
volumes required under Sec. 203.66. If we determine that your
expansion project may be economic only with more relief, we will
determine and grant you the royalty suspension volume necessary to make
the project economic.
(i) The royalty suspension volume applicable to specific leases
will continue through the end of the month in which cumulative
production reaches that volume. You must calculate cumulative
production from all the leases in the authorized field or project that
are entitled to share the royalty suspension volume.
Sec. 203.70 What information must I provide after BSEE approves
relief?
You must submit reports to us as indicated in the following table.
Sections 203.81, 203.90, and 203.91 describe what these reports must
include. The BSEE Regional Office for your region will prescribe the
formats.
------------------------------------------------------------------------
Required report When due to BSEE Due date extensions
------------------------------------------------------------------------
(a) Fabricator's Within 18 months BSEE Director may
confirmation report. after approval of grant you an
relief. extension under
Sec. 203.79(c)
for up to 6 months.
(b) Post-production report. Within 120 days With acceptable
after the start of justification from
production that is you, the BSEE
subject to the Regional Director
approved royalty for your region may
suspension volume. extend the due date
up to 30 days.
------------------------------------------------------------------------
Sec. 203.71 How does BSEE allocate a field's suspension volume
between my lease and other leases on my field?
The allocation depends on when production occurs, when we issued
the lease, when we assigned it to the field, and whether we award the
volume suspension by an approved application or establish it in the
lease terms, as prescribed in this section.
(a) If your authorized field has an approved royalty suspension
volume under Sec. Sec. 203.67 and 203.69, we will suspend payment of
royalties on production from all leases in the field that participate
in the application until their cumulative production equals the
approved volume. The following conditions also apply:
----------------------------------------------------------------------------------------------------------------
If . . . Then . . . And . . .
----------------------------------------------------------------------------------------------------------------
(1) We assign an eligible lease to We will not change your authorized Production from the assigned
your authorized field after we field's royalty suspension volume eligible lease(s) counts toward the
approve relief, determined under Sec. 203.69, royalty suspension volume for the
authorized field, but the eligible
lease will not share any remaining
royalty suspension volume for the
authorized field after the eligible
lease has produced the volume
applicable under 30 CFR 560.114.
[[Page 64481]]
(2) We assign a pre-Act or post- We will not change your field's The assigned lease(s) may share in
November 2000 deep water lease to royalty suspension volume, any remaining royalty relief by
your field after we approve your filing the short-form application
application, specified in Sec. 203.83 and
authorized in Sec. 203.82. An
assigned RS lease also gets any
portion of its royalty suspension
volume remaining even after the
field has produced the approved
relief volume.
(3) We assign another lease that In our evaluation of your authorized (i) You toll the time period for
you operate to your field while we field, we will take into account the evaluation until you modify your
are evaluating your application, value of any royalty relief the application to be consistent with
added lease already has under 30 CFR the newly constituted field;
560.114 or its lease document. If we (ii) We have an additional 60 days
find your authorized field still to review the new information; and
needs additional royalty suspension (iii) The assigned pre-Act lease or
volume, that volume will be at least royalty suspension lease shares the
the combined royalty suspension royalty suspension we grant to the
volume to which all added leases on newly constituted field. An
the field are entitled, or the eligible lease does not share the
minimum suspension volume of the royalty suspension we grant to the
authorized field, whichever is new field. If you do not agree to
greater, toll, we will have to reject your
application due to incomplete
information. Production from an
assigned eligible lease counts
toward the royalty suspension
volume that we grant under Sec.
203.69 for your authorized field,
but you will not owe royalty on
production from the eligible lease
until it has produced the volume
applicable under 30 CFR 560.114.
(4) We assign another operator's We will change your field's minimum (i) You both toll the time period
lease to your field while we are suspension volume provided the for evaluation until both of you
evaluating your application, assigned lease joins the application modify your application to be
and is entitled to a larger minimum consistent with the new field;
suspension volume, (ii) We have an additional 60 days
to review the new information; and
(iii) The assigned lease(s) shares
the royalty suspension we grant to
the new field. If you (the original
applicant) do not agree to toll,
the other operator's lease retains
any suspension volume it has or may
share in any relief that we grant
by filing the short form
application specified in Sec.
203.83 and authorized in Sec.
203.82.
(5) We reassign a well on a pre- The past production from the well For any field based relief, the past
Act, eligible, or royalty counts toward the royalty suspension production for that well will not
suspension lease from field A to volume that we grant under Sec. count toward any royalty suspension
field B, 203.69 to field B, volume that we grant under Sec.
203.69 to field A. Moreover, past
production from that well will
count toward the royalty suspension
volume applicable for the lease
under 30 CFR 560.114 if the well is
on an eligible lease or under 30
CFR 560.124 if the well is on a
royalty suspension lease.
----------------------------------------------------------------------------------------------------------------
(b) When a project has more than one lease, the royalty suspension
volume for each lease equals that lease's actual production from the
project (or production allocated under an approved unit agreement)
until total production for all leases in the project equals the
project's approved royalty suspension volume.
(c) You may receive a royalty-suspension volume only if your entire
lease is west of 87 degrees, 30 minutes West longitude. If the field
lies on both sides of this meridian, only leases located entirely west
of the meridian will receive a royalty-suspension volume.
Sec. 203.72 Can my lease receive more than one suspension volume?
Yes. You may apply for royalty relief that involves more than one
suspension volume under Sec. 203.62 in two circumstances.
(a) Each field that includes your lease may receive a separate
royalty-suspension volume, if it meets the evaluation criteria of Sec.
203.67.
(b) An expansion project on your lease may receive a separate
royalty-suspension volume, even if we have already granted a royalty-
suspension volume to the field that encompasses the project. But the
reserves associated with the project must not have been part of our
original determination, and the project must meet the evaluation
criteria of Sec. 203.67.
Sec. 203.73 How do suspension volumes apply to natural gas?
You must measure natural gas production under the royalty-
suspension volume as follows: 5.62 thousand cubic feet of natural gas,
measured in accordance with 30 CFR part 250, subpart L, equals one
barrel of oil equivalent.
Sec. 203.74 When will BSEE reconsider its determination?
You may request a redetermination after we withdraw approval or
after you renounce royalty relief, unless we withdraw approval due to
your providing false or intentionally inaccurate information. Under
certain conditions you may also request a redetermination if we deny
your application or if you want your approved royalty suspension volume
to change. In these instances, to be eligible for a redetermination, at
least one of the following four conditions must occur.
(a) You have significant new G&G data and you previously have not
either requested a redetermination or reapplied for relief after we
withdrew
[[Page 64482]]
approval or you relinquished royalty relief. ``Significant'' means that
the new G&G data:
(1) Results from drilling new wells or getting new three-
dimensional seismic data and information (but not reinterpreting old
data);
(2) Did not exist at the time of the earlier application; and
(3) Changes your estimates of gross resource size, quality, or
projected flow rates enough to materially affect the results of our
earlier determination.
(b) You demonstrate in your new application that the technology
that most efficiently develops this field or lease was not considered
or deemed feasible in the original application. Your newly proposed
technology must improve the profitability, under equivalent market
conditions, of the field or lease relative to the development system
proposed in the prior application.
(c) Your current reference price decreases by more than 25 percent
from your base reference price as calculated under this paragraph.
(1) Your current reference price is a weighted-average of daily
closing prices on the NYMEX for light sweet crude oil and natural gas
over the most recent full 12 calendar months;
(2) Your base reference price is a weighted average of daily
closing prices on the NYMEX for light sweet crude oil and natural gas
for the full 12 calendar months preceding the date of your most
recently approved application for this royalty relief; and
(3) The weighting factors are the proportions of the total
production volume (in BOE) for oil and gas associated with the most
likely scenario (identified in Sec. Sec. 203.85 and 203.88) from your
most recently approved application for this royalty relief.
(d) Before starting to build your development and production
system, you have revised your estimated development costs, and they are
more than 120 percent of the eligible development costs associated with
the most likely scenario from your most recently approved application
for this royalty relief.
Sec. 203.75 What risk do I run if I request a redetermination?
If you request a redetermination after we have granted you a
suspension volume, you could lose some or all of the previously granted
relief. This can happen because you must file a new complete
application and pay the required fee, as discussed in Sec. 203.62. We
will evaluate your application under Sec. 203.67 using the conditions
prevailing at the time of your redetermination request. In our
evaluation, we may find that you should receive a larger, equivalent,
smaller, or no suspension volume. This means we could find that you do
not qualify for the amount of relief previously granted or for any
relief at all.
Sec. 203.76 When might BSEE withdraw or reduce the approved size of
my relief?
We will withdraw approval of relief for any of the following
reasons.
(a) You change the type of development system proposed in your
application (e.g., change from a fixed platform to floating production
system, or from an independent development and production system to one
with subsea wells tied back to a host production facility, etc.).
(b) You do not start building the proposed development and
production system within 18 months of the date we approved your
application, unless the BSEE Director grants you an extension under
Sec. 203.79(c). If you start building the proposed system and then
suspend its construction before completion, and you do not restart
continuous building of the proposed system within 18 months of our
approval, we will withdraw the relief we granted.
(c) Your actual development costs are less than 80 percent of the
eligible development costs estimated in your application's most likely
scenario, and you do not report that fact in your post-production
development report (Sec. 203.70). Development costs are those
expenditures defined in Sec. 203.89(b) incurred between the
application submission date and start of production. If you report this
fact in the post-production development report, you may retain the
lesser of 50 percent of the original royalty suspension volume or 50
percent of the median of the distribution of the potentially
recoverable resources anticipated in your application.
(d) We granted you a royalty-suspension volume after you qualified
for a redetermination under Sec. 203.74(c), and we find out your
actual development costs are less than 90 percent of the eligible
development costs associated with your application's most likely
scenario. Development costs are those expenditures defined in Sec.
203.89(b) incurred between your application submission date and start
of production.
(e) You do not send us the fabrication confirmation report or the
post-production development report, or you provide false or
intentionally inaccurate information that was material to our granting
royalty relief under this section. You must pay royalties and late-
payment interest determined under 30 U.S.C. 1721 and 30 CFR 1218.54 on
all volumes for which you used the royalty suspension. You also may be
subject to penalties under other provisions of law.
Sec. 203.77 May I voluntarily give up relief if conditions change?
Yes, you may voluntarily give up relief by sending a letter to that
effect to the BSEE Regional office for your region.
Sec. 203.78 Do I keep relief approved by BSEE under this part for my
lease, unit or project if prices rise significantly?
If prices rise above a base price threshold for light sweet crude
oil or natural gas, you must pay full royalties on production otherwise
subject to royalty relief approved by BSEE under Sec. Sec. 203.60-
203.77 for your lease, unit or project as prescribed in this section.
(a) The following table shows the base price threshold for various
types of leases, subject to paragraph (b) of this section. Note that,
for post-November 2000 deepwater leases in the GOM, price thresholds
apply on a lease basis, so different leases on the same development
project or expansion project approved for royalty relief may have
different price thresholds.
------------------------------------------------------------------------
The base price threshold is
For . . . . . .
------------------------------------------------------------------------
(1) Pre-Act leases in the GOM, set by statute.
(2) Post-November 2000 deep water leases indicated in your original
in the GOM or leases offshore of Alaska lease agreement or, if
for which the lease or Notice of Sale set none, those in the Notice
a base price threshold, of Sale under which your
lease was issued.
(3) Post-November 2000 deep water leases the threshold set by statute
in the GOM or leases offshore of Alaska for pre-Act leases.
for which the lease or Notice of Sale did
not set a base price threshold,
------------------------------------------------------------------------
[[Page 64483]]
(b) An exception may occur if we determine that the price
thresholds in paragraphs (a)(2) or (a)(3) of this section mean the
royalty suspension volume set under Sec. 203.69 and in lease terms
would provide inadequate encouragement to increase production or
development, in which circumstance we could specify a different set of
price thresholds on a case-by-case basis.
(c) Suppose your base oil price threshold set under paragraph (a)
is $28.00 per barrel, and the daily closing NYMEX light sweet crude oil
prices for the previous calendar year exceeds $28.00 per barrel, as
adjusted in paragraph (h) of this section. In this case, we retract the
royalty relief authorized in this subpart and you must:
(1) Pay royalties on all oil production for the previous year at
the lease stipulated royalty rate plus interest (under 30 U.S.C. 1721
and 30 CFR 1218.54) by March 31 of the current calendar year, and
(2) Pay royalties on all your oil production in the current year.
(d) Suppose your base gas price threshold set under paragraph (a)
is $3.50 per million British thermal units (Btu), and the daily closing
NYMEX light sweet crude oil prices for the previous calendar year
exceeds $3.50 per million Btu, as adjusted in paragraph (h) of this
section. In this case, we retract the royalty relief authorized in this
subpart and you must:
(1) Pay royalties on all gas production for the previous year at
the lease stipulated royalty rate plus interest (under 30 U.S.C. 1721
and 30 CFR 1218.54) by March 31 of the current calendar year, and
(2) Pay royalties on all your gas production in the current year.
(e) Production under both paragraphs (c) and (d) of this section
counts as part of the royalty-suspension volume.
(f) You are entitled to a refund or credit, with interest, of
royalties paid on any production (that counts as part of the royalty-
suspension volume):
(1) Of oil if the arithmetic average of the closing prices for the
current calendar year is $28.00 per barrel or less, as adjusted in
paragraph (h) of this section, and
(2) Of gas if the arithmetic average of the closing natural gas
prices for the current calendar year is $3.50 per million Btu or less,
as adjusted in paragraph (h) of this section.
(g) You must follow our regulations in the Office of Natural
Resources Revenue, 30 CFR chapter XII, for receiving refunds or
credits.
(h) We change the prices referred to in paragraphs (c), (d), and
(f) of this section periodically. For pre-Act leases, these prices
change during each calendar year after 1994 by the percentage that the
implicit price deflator for the gross domestic product changed during
the preceding calendar year. For post-November 2000 deepwater leases,
these prices change as indicated in the lease instrument or in the
Notice of Sale under which we issued the lease.
Sec. 203.79 How do I appeal BSEE's decisions related to royalty
relief for a deepwater lease or a development or expansion project?
(a) Once we have designated your lease as part of a field and
notified you and other affected operators of the designation, you can
request reconsideration by sending the BSEE Director a letter within 15
days that also states your reasons. The BSEE Director's response is the
final agency action.
(b) Our decisions on your application for relief from paying
royalty under Sec. 203.67 and the royalty-suspension volumes under
Sec. 203.69 are final agency actions.
(c) If you cannot start construction by the deadline in Sec.
203.76(b) for reasons beyond your control (e.g., strike at the
fabrication yard), you may request an extension up to 1 year by writing
the BSEE Director and stating your reasons. The BSEE Director's
response is the final agency action.
(d) We will notify you of all final agency actions by certified
mail, return receipt requested. Final agency actions are not subject to
appeal to the Interior Board of Land Appeals under 30 CFR part 290 and
43 CFR part 4. They are judicially reviewable under section 10(a) of
the Administrative Procedure Act (5 U.S.C. 702) only if you file an
action within 30 days of the date you receive our decision.
Sec. 203.80 When can I get royalty relief if I am not eligible for
royalty relief under other sections in the subpart?
We may grant royalty relief when it serves the statutory purposes
summarized in Sec. 203.1 and our formal relief programs, including but
not limited to the applicable levels of the royalty suspension volumes
and price thresholds, provide inadequate encouragement to promote
development or increase production. Unless your lease lies offshore of
Alaska or wholly west of 87 degrees, 30 minutes West longitude in the
GOM, your lease must be producing to qualify for relief. Before you may
apply for royalty relief apart from our programs for end-of-life leases
or for pre-Act deep water leases and development and expansion
projects, we must agree that your lease or project has two or more of
the following characteristics:
(a) The lease has produced for a substantial period and the lessee
can recover significant additional resources. Significant additional
resources mean enough to allow production for at least a year more than
would be profitable without royalty relief.
(b) Valuable facilities (e.g., a platform or pipeline that would be
removed upon lease relinquishment) exist that we do not expect a
successor lessee to use. If the facilities are located off the lease,
their preservation must depend on continued production from the lease
applying for royalty relief. We will only consider an allocable share
of costs for off-lease facilities in the relief application.
(c) A substantial risk exists that no new lessee will recover the
resources.
(d) The lessee made major efforts to reduce operating costs too
recently to use the formal program for royalty relief (e.g., recent
significant change in operations).
(e) Circumstances beyond the lessee's control, other than water
depth, preclude reliance on one of the existing royalty relief
programs.
Required Reports
Sec. 203.81 What supplemental reports do royalty-relief applications
require?
(a) You must send us the supplemental reports, indicated in the
following table by an X, that apply to your field. Sections 203.83
through 203.91 describe these reports in detail.
----------------------------------------------------------------------------------------------------------------
Deep water
End-of-life --------------------------------------------------
Required reports lease Expansion Development
project Pre-act lease project
----------------------------------------------------------------------------------------------------------------
(1) Administrative information Report....... X X X X
(2) Net revenue & relief justification X ............... ............... ...............
report.....................................
[[Page 64484]]
(3) Economic viability & relief ............... X X X
justification report (RSVP model inputs
justified by other required reports).......
(4) G&G report.............................. ............... X X X
(5) Engineering report...................... ............... X X X
(6) Production report....................... ............... X X X
(7) Deep water cost report.................. ............... X X X
(8) Fabricator's confirmation report........ ............... X X X
(9) Post-production development report...... ............... X X X
----------------------------------------------------------------------------------------------------------------
(b) You must certify that all information in your application,
fabricator's confirmation and post-production development reports is
accurate, complete, and conforms to the most recent content and
presentation guidelines available from the BSEE Regional office for
your region.
(c) With your application and post-production development report,
you must submit an additional report prepared by an independent CPA
that:
(1) Assesses the accuracy of the historical financial information
in your report; and
(2) Certifies that the content and presentation of the financial
data and information conform to our most recent guidelines on royalty
relief. This means the data and information must:
(i) Include only eligible costs that are incurred during the
qualification months; and
(ii) Be shown in the proper format.
(d) You must identify the people in the CPA firm who prepared the
reports referred to in paragraph (c) of this section and make them
available to us to respond to questions about the historical financial
information. We may also further review your records to support this
information.
Sec. 203.82 What is BSEE's authority to collect this information?
The Office of Management and Budget (OMB) approved the information
collection requirements in part 203 under 44 U.S.C. 3501 et seq., and
assigned OMB control number 1010-0071.
(a) We use the information to determine whether royalty relief will
result in production that wouldn't otherwise occur. We rely largely on
your information to make these determinations.
(1) Your application for royalty relief must contain enough
information on finances, economics, reservoirs, G&G characteristics,
production, and engineering estimates for us to determine whether:
(i) We should grant relief under the law, and
(ii) The requested relief will ultimately recover more resources
and return a reasonable profit on project investments.
(2) Your fabricator confirmation and post-production development
reports must contain enough information for us to verify that your
application reasonably represented your plans.
(b) Applicants (respondents) are Federal OCS oil and gas lessees.
Applications are required to obtain or retain a benefit. Therefore, if
you apply for royalty relief, you must provide this information. We
will protect information considered proprietary under applicable law
and under regulations at Sec. 203.63 and 30 CFR part 250.
(c) The Paperwork Reduction Act of 1995 requires us to inform you
that 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.
(d) Send comments regarding any aspect of the collection of
information under this part, including suggestions for reducing the
burden, to the Information Collection Clearance Officer, Bureau of
Safety and Environmental Enforcement, 381 Elden Street, Herndon, VA
20170.
Sec. 203.83 What is in an administrative information report?
This report identifies the field or lease for which royalty relief
is requested and must contain the following items:
(a) The field or lease name;
(b) The serial number of leases we have assigned to the field,
names of the lease title holders of record, the lease operators, and
whether any lease is part of a unit;
(c) Well number, API number, location, and status of each well that
has been drilled on the field or lease or project (not required for
non-oil and gas leases);
(d) The location of any new wells proposed under the terms of the
application (not required for non-oil and gas leases);
(e) A description of field or lease history;
(f) Full information as to whether you will pay royalties or a
share of production to anyone other than the United States, the amount
you will pay, and how much you will reduce this payment if we grant
relief;
(g) The type of royalty relief you are requesting;
(h) Confirmation that BOEM approved a DOCD or supplemental DOCD
(Deep Water expansion project applications only); and
(i) A narrative description of the development activities
associated with the proposed capital investments and an explanation of
proposed timing of the activities and the effect on production (Deep
Water applications only).
Sec. 203.84 What is in a net revenue and relief justification report?
This report presents cash flow data for 12 qualifying months, using
the format specified in the ``Guidelines for the Application, Review,
Approval, and Administration of Royalty Relief for End-of-Life
Leases'', U.S. Department of the Interior, BSEE. Qualifying months for
an oil and gas lease are the most recent 12 months out of the last 15
months that you produced at least 100 BOE per day on average.
Qualifying months for other than oil and gas leases are the most recent
12 of the last 15 months having some production.
(a) The cash flow table you submit must include historical data
for:
(1) Lease production subject to royalty;
(2) Total revenues;
(3) Royalty payments out of production;
(4) Total allowable costs; and
(5) Transportation and processing costs.
(b) Do not include in your cash flow table the non-allowable costs
listed at 30 CFR 1220.013 or:
(1) OCS rental payments on the lease(s) in the application;
(2) Damages and losses;
(3) Taxes;
(4) Any costs associated with exploratory activities;
[[Page 64485]]
(5) Civil or criminal fines or penalties;
(6) Fees for your royalty relief application; and
(7) Costs associated with existing obligations (e.g., royalty
overrides or other forms of payment for acquiring the lease,
depreciation on previously acquired equipment or facilities).
(c) We may, in reviewing and evaluating your application, disallow
costs when you have not shown they are necessary to operate the lease,
or if they are inconsistent with end-of-life operations.
Sec. 203.85 What is in an economic viability and relief justification
report?
This report should show that your project appears economic without
royalties and sunk costs using the RSVP model we provide. The format of
the report and the assumptions and parameters we specify are found in
the ``Guidelines for the Application, Review, Approval and
Administration of the Deep Water Royalty Relief Program,'' U.S.
Department of the Interior, BSEE. Clearly justify each parameter you
set in every scenario you specify in the RSVP. You may provide
supplemental information, including your own model and results. The
economic viability and relief justification report must contain the
following items for an oil and gas lease.
(a) Economic assumptions we provide which include:
(1) Starting oil and gas prices;
(2) Real price growth;
(3) Real cost growth or decline rate, if any;
(4) Base year;
(5) Range of discount rates; and
(6) Tax rate (for use in determining after-tax sunk costs).
(b) Analysis of projected cash flow (from the date of the
application using annual totals and constant dollar values) which
shows:
(1) Oil and gas production;
(2) Total revenues;
(3) Capital expenditures;
(4) Operating costs;
(5) Transportation costs; and
(6) Before-tax net cash flow without royalties, overrides, sunk
costs, and ineligible costs.
(c) Discounted values which include:
(1) Discount rate used (selected from within the range we specify).
(2) Before-tax net present value without royalties, overrides, sunk
costs, and ineligible costs.
(d) Demonstrations that:
(1) All costs, gross production, and scheduling are consistent with
the data in the G&G, engineering, production, and cost reports
(Sec. Sec. 203.86 through 203.89) and
(2) The development and production scenarios provided in the
various reports are consistent with each other and with the proposed
development system. You can use up to three scenarios (conservative,
most likely, and optimistic), but you must link each to a specific
range on the distribution of resources from the RSVP Resource Module.
Sec. 203.86 What is in a G&G report?
This report supports the reserve and resource estimates used in the
economic evaluation and must contain each of the following elements.
(a) Seismic data which includes:
(1) Non-interpreted 2D/3D survey lines reflecting any available
state-of-the-art processing technique in a format readable by BSEE and
specified by the deep water royalty relief guidelines;
(2) Interpreted 2D/3D seismic survey lines reflecting any available
state-of-the-art processing technique identifying all known and
prospective pay horizons, wells, and fault cuts;
(3) Digital velocity surveys in the format of the GOM region's
letter to lessees of 10/1/90;
(4) Plat map of ``shot points;'' and
(5) ``Time slices'' of potential horizons.
(b) Well data which includes:
(1) Hard copies of all well logs in which--
(i) The 1-inch electric log shows pay zones and pay counts and
lithologic and paleo correlation markers at least every 500-feet,
(ii) The 1-inch type log shows missing sections from other logs
where faulting occurs,
(iii) The 5-inch electric log shows pay zones and pay counts and
labeled points used in establishing resistivity of the formation, 100
percent water saturated (Ro) and the resistivity of the
undisturbed formation (Rt), and
(iv) The 5-inch porosity logs show pay zones and pay counts and
labeled points used in establishing reservoir porosity or labeled
points showing values used in calculating reservoir porosity such as
bulk density or transit time;
(2) Digital copies of all well logs spudded before December 1,
1995;
(3) Core data, if available;
(4) Well correlation sections;
(5) Pressure data;
(6) Production test results;
(7) Pressure-volume-temperature analysis, if available; and
(8) A table listing the wells and completions, and indicating which
sands and fault blocks will be targeted for completion or recompletion.
(c) Map interpretations which includes for each reservoir in the
field:
(1) Structure maps consisting of top and base of sand maps showing
well and seismic shot point locations;
(2) Isopach maps for net sand, net oil, net gas, all with well
locations;
(3) Maps indicating well surface and bottom hole locations,
location of development facilities, and shot points; and
(4) An explanation for excluding the reservoirs you are not
planning to develop.
(d) Reservoir-specific data which includes:
(1) Probability of reservoir occurrence with hydrocarbons;
(2) Probability the hydrocarbon in the reservoir is all oil and the
probability it is all gas;
(3) Distributions or point estimates (accompanied by explanations
of why distributions less appropriately reflect the uncertainty) for
the parameters used to estimate reservoir size, i.e., acres and net
thickness;
(4) Most likely values for porosity, salt water saturation, volume
factor for oil formation, and volume factor for gas formation;
(5) Distributions or point estimates (accompanied by explanations
of why distributions less appropriately reflect the uncertainty) for
recovery efficiency (in percent) and oil or gas recovery (in stock-
tank-barrels per acre-foot or in thousands of cubic feet per acre
foot);
(6) A gas/oil ratio distribution or point estimate (accompanied by
explanations of why distributions less appropriately reflect the
uncertainty) for each reservoir;
(7) A yield distribution or point estimate (accompanied by
explanations of why distributions less appropriately reflect the
uncertainty) for each gas reservoir; and
(8) Reserve or resource distribution by reservoir.
(e) Aggregated reserve and resource data which includes:
(1) The aggregated distributions for reserves and resources (in
BOE) and oil fraction for your field computed by the resource module of
our RSVP model;
(2) A description of anticipated hydrocarbon quality (i.e.,
specific gravity); and
(3) The ranges within the aggregated distribution for reserves and
resources that define the development and production scenarios
presented in the engineering and production reports. Typically there
will be three ranges specified by two positive reserve and resource
points on the aggregated distribution. The range at the low end of the
distribution will be associated with the conservative development and
production scenario; the middle range
[[Page 64486]]
will be related to the most likely development and production scenario;
and, the high end range will be consistent with the optimistic
development and production scenario.
Sec. 203.87 What is in an engineering report?
This report defines the development plan and capital requirements
for the economic evaluation and must contain the following elements.
(a) A description of the development concept (e.g., tension leg
platform, fixed platform, floater type, subsea tieback, etc.) which
includes:
(1) Its size along with basic design specifications and drawings;
and
(2) The construction schedule.
(b) An identification of planned wells which includes:
(1) The number;
(2) The type (platform, subsea, vertical, deviated, horizontal);
(3) The well depth;
(4) The drilling schedule;
(5) The kind of completion (single, dual, horizontal, etc.); and
(6) The completion schedule.
(c) A description of the production system equipment which
includes:
(1) The production capacity for oil and gas and a description of
limiting component(s);
(2) Any unusual problems (low gravity, paraffin, etc.);
(3) All subsea structures;
(4) All flowlines; and
(5) Schedule for installing the production system.
(d) A discussion of any plans for multi-phase development which
includes the conceptual basis for developing in phases and goals or
milestones required for starting later phases.
(e) A set of development scenarios consisting of activity timing
and scale associated with each of up to three production profiles
(conservative, most likely, optimistic) provided in the production
report for your field (Sec. 203.88). Each development scenario and
production profile must denote the likely events should the field size
turn out to be within a range represented by one of the three segments
of the field size distribution. If you send in fewer than three
scenarios, you must explain why fewer scenarios are more efficient
across the whole field size distribution.
Sec. 203.88 What is in a production report?
This report supports your development and production timing and
product quality expectations and must contain the following elements.
(a) Production profiles by well completion and field that specify
the actual and projected production by year for each of the following
products: oil, condensate, gas, and associated gas. The production from
each profile must be consistent with a specific level of reserves and
resources on the aggregated distribution of field size.
(b) Production drive mechanisms for each reservoir.
Sec. 203.89 What is in a cost report?
This report lists all actual and projected costs for your field,
must explain and document the source of each cost estimate, and must
identify the following elements.
(a) Sunk costs. Report sunk costs in dollars not adjusted for
inflation and only if you have documentation.
(b) Appraisal, delineation and development costs. Base them on
actual spending, current authorization for expenditure, engineering
estimates, or analogous projects. These costs cover:
(1) Platform well drilling and average depth;
(2) Platform well completion;
(3) Subsea well drilling and average depth;
(4) Subsea well completion;
(5) Production system (platform); and
(6) Flowline fabrication and installation.
(c) Production costs based on historical costs, engineering
estimates, or analogous projects. These costs cover:
(1) Operation;
(2) Equipment; and
(3) Existing royalty overrides (we will not use the royalty
overrides in evaluations).
(d) Transportation costs, based on historical costs, engineering
estimates, or analogous projects. These costs cover:
(1) Oil or gas tariffs from pipeline or tankerage;
(2) Trunkline and tieback lines; and
(3) Gas plant processing for natural gas liquids.
(e) Abandonment costs, based on historical costs, engineering
estimates, or analogous projects. You should provide the costs to plug
and abandon only wells and to remove only production systems for which
you have not incurred costs as of the time of application submission.
You should also include a point estimate or distribution of prospective
salvage value for all potentially reusable facilities and materials,
along with the source and an explanation of the figures provided.
(f) A set of cost estimates consistent with each one of up to three
field-development scenarios and production profiles (conservative, most
likely, optimistic). You should express costs in constant real dollar
terms for the base year. You may also express the uncertainty of each
cost estimate with a minimum and maximum percentage of the base value.
(g) A spending schedule. You should provide costs for each year (in
real dollars) for each category in paragraphs (a) through (f) of this
section.
(h) A summary of other costs which are ineligible for evaluating
your need for relief. These costs cover:
(1) Expenses before first discovery on the field;
(2) Cash bonuses;
(3) Fees for royalty relief applications;
(4) Lease rentals, royalties, and payments of net profit share and
net revenue share;
(5) Legal expenses;
(6) Damages and losses;
(7) Taxes;
(8) Interest or finance charges, including those embedded in
equipment leases;
(9) Fines or penalties; and
(10) Money spent on previously existing obligations (e.g., royalty
overrides or other forms of payment for acquiring a financial position
in a lease, expenditures for plugging wells and removing and abandoning
facilities that existed on the application submission date).
Sec. 203.90 What is in a fabricator's confirmation report?
This report shows you have committed in a timely way to the
approved system for production. This report must include the following
(or its equivalent for unconventionally acquired systems):
(a) A copy of the contract(s) under which the fabrication yard is
building the approved system for you;
(b) A letter from the contractor building the system to the BSEE
Regional Director for your region certifying when construction started
on your system; and
(c) Evidence of an appropriate down payment or equal action that
you've started acquiring the approved system.
Sec. 203.91 What is in a post-production development report?
For each cost category in the deep water cost report, you must
compare actual costs up to the date when production starts to your
planned pre-production costs. If your application included more than
one development scenario, you need to compare actual costs with those
in your scenario of most likely development. Also, you must have this
report certified by an independent CPA according to Sec. 203.81(c).
[[Page 64487]]
Subpart C--Federal and Indian Oil [Reserved]
Subpart D--Federal and Indian Gas [Reserved]
Subpart E--Solid Minerals, General [Reserved]
Subpart F--[Reserved]
Subpart G--Other Solid Minerals [Reserved]
Subpart H--Geothermal Resources [Reserved]
Subpart I--OCS Sulfur [Reserved]
PART 219--[RESERVED]
Subchapter B--Offshore
PART 250--OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER
CONTINENTAL SHELF
Subpart A--General
Authority and Definition of Terms
Sec.
250.101 Authority and applicability.
250.102 What does this part do?
250.103 Where can I find more information about the requirements in
this part?
250.104 How may I appeal a decision made under BSEE regulations?
250.105 Definitions.
Performance Standards
250.106 What standards will the Director use to regulate lease
operations?
250.107 What must I do to protect health, safety, property, and the
environment?
250.108 What requirements must I follow for cranes and other
material-handling equipment?
250.109 What documents must I prepare and maintain related to
welding?
250.110 What must I include in my welding plan?
250.111 Who oversees operations under my welding plan?
250.112 What standards must my welding equipment meet?
250.113 What procedures must I follow when welding?
250.114 How must I install and operate electrical equipment?
250.115-250.117 [Reserved]
250.118 Will BSEE approve gas injection?
250.119 [Reserved]
250.120 How does injecting, storing, or treating gas affect my
royalty payments?
250.121 What happens when the reservoir contains both original gas
in place and injected gas?
250.122 What effect does subsurface storage have on the lease term?
250.123 [Reserved]
250.124 Will BSEE approve gas injection into the cap rock containing
a sulphur deposit?
Fees
250.125 Service fees.
250.126 Electronic payment instructions.
Inspection of Operations
250.130 Why does BSEE conduct inspections?
250.131 Will BSEE notify me before conducting an inspection?
250.132 What must I do when BSEE conducts an inspection?
250.133 Will BSEE reimburse me for my expenses related to
inspections?
Disqualification
250.135 What will BSEE do if my operating performance is
unacceptable?
250.136 How will BSEE determine if my operating performance is
unacceptable?
Special Types of Approvals
250.140 When will I receive an oral approval?
250.141 May I ever use alternate procedures or equipment?
250.142 How do I receive approval for departures?
250.143 [Reserved]
250.144 [Reserved]
250.145 How do I designate an agent or a local agent?
250.146 Who is responsible for fulfilling leasehold obligations?
Naming and Identifying Facilities and Wells (Does Not Include MODUs)
250.150 How do I name facilities and wells in the Gulf of Mexico
Region?
250.151 How do I name facilities in the Pacific Region?
250.152 How do I name facilities in the Alaska Region?
250.153 Do I have to rename an existing facility or well?
250.154 What identification signs must I display?
250.160-250.167 [Reserved]
Suspensions
250.168 May operations or production be suspended?
250.169 What effect does suspension have on my lease?
250.170 How long does a suspension last?
250.171 How do I request a suspension?
250.172 When may the Regional Supervisor grant or direct an SOO or
SOP?
250.173 When may the Regional Supervisor direct an SOO or SOP?
250.174 When may the Regional Supervisor grant or direct an SOP?
250.175 When may the Regional Supervisor grant an SOO?
250.176 Does a suspension affect my royalty payment?
250.177 What additional requirements may the Regional Supervisor
order for a suspension?
Primary Lease Requirements, Lease Term Extensions, and Lease
Cancellations
250.180 What am I required to do to keep my lease term in effect?
250.181-250.185 [Reserved]
Information and Reporting Requirements
250.186 What reporting information and report forms must I submit?
250.187 What are BSEE's incident reporting requirements?
250.188 What incidents must I report to BSEE and when must I report
them?
250.189 Reporting requirements for incidents requiring immediate
notification.
250.190 Reporting requirements for incidents requiring written
notification.
250.191 How does BSEE conduct incident investigations?
250.192 What reports and statistics must I submit relating to a
hurricane, earthquake, or other natural occurrence?
250.193 Reports and investigations of apparent violations.
250.194 How must I protect archaeological resources?
250.195 What notification does BSEE require on the production status
of wells?
250.196 Reimbursements for reproduction and processing costs.
250.197 Data and information to be made available to the public or
for limited inspection.
References
250.198 Documents incorporated by reference.
250.199 Paperwork Reduction Act statements--information collection.
Subpart B--Plans and Information
General Information
250.200 Definitions.
250.201 What plans and information must I submit before I conduct
any activities on my lease or unit?
250.202 [Reserved]
250.203 [Reserved]
250.204 How must I protect the rights of the Federal government?
250.205 Are there special requirements if my well affects an
adjacent property?
Post-Approval Requirements for the EP, DPP, and DOCD
250.282 Do I have to conduct post-approval monitoring?
Deepwater Operations Plans (DWOP)
250.286 What is a DWOP?
250.287 For what development projects must I submit a DWOP?
250.288 When and how must I submit the Conceptual Plan?
250.289 What must the Conceptual Plan contain?
250.290 What operations require approval of the Conceptual Plan?
250.291 When and how must I submit the DWOP?
250.292 What must the DWOP contain?
250.293 What operations require approval of the DWOP?
250.294 May I combine the Conceptual Plan and the DWOP?
250.295 When must I revise my DWOP?
Subpart C--Pollution Prevention and Control
250.300 Pollution prevention.
[[Page 64488]]
250.301 Inspection of facilities.
Subpart D--Oil and Gas Drilling Operations
General Requirements
250.400 Who is subject to the requirements of this subpart?
250.401 What must I do to keep wells under control?
250.402 When and how must I secure a well?
250.403 What drilling unit movements must I report?
250.404 What are the requirements for the crown block?
250.405 What are the safety requirements for diesel engines used on
a drilling rig?
250.406 What additional safety measures must I take when I conduct
drilling operations on a platform that has producing wells or has
other hydrocarbon flow?
250.407 What tests must I conduct to determine reservoir
characteristics?
250.408 May I use alternative procedures or equipment during
drilling operations?
250.409 May I obtain departures from these drilling requirements?
Applying for a Permit to Drill
250.410 How do I obtain approval to drill a well?
250.411 What information must I submit with my application?
250.412 What requirements must the location plat meet?
250.413 What must my description of well drilling design criteria
address?
250.414 What must my drilling prognosis include?
250.415 What must my casing and cementing programs include?
250.416 What must I include in the diverter and BOP descriptions?
250.417 What must I provide if I plan to use a mobile offshore
drilling unit (MODU)?
250.418 What additional information must I submit with my APD?
Casing and Cementing Requirements
250.420 What well casing and cementing requirements must I meet?
250.421 What are the casing and cementing requirements by type of
casing string?
250.422 When may I resume drilling after cementing?
250.423 What are the requirements for pressure testing casing?
250.424 What are the requirements for prolonged drilling operations?
250.425 What are the requirements for pressure testing liners?
250.426 What are the recordkeeping requirements for casing and liner
pressure tests?
250.427 What are the requirements for pressure integrity tests?
250.428 What must I do in certain cementing and casing situations?
Diverter System Requirements
250.430 When must I install a diverter system?
250.431 What are the diverter design and installation requirements?
250.432 How do I obtain a departure to diverter design and
installation requirements?
250.433 What are the diverter actuation and testing requirements?
250.434 What are the recordkeeping requirements for diverter
actuations and tests?
Blowout Preventer (BOP) System Requirements
250.440 What are the general requirements for BOP systems and system
components?
250.441 What are the requirements for a surface BOP stack?
250.442 What are the requirements for a subsea BOP system?
250.443 What associated systems and related equipment must all BOP
systems include?
250.444 What are the choke manifold requirements?
250.445 What are the requirements for kelly valves, inside BOPs, and
drill-string safety valves?
250.446 What are the BOP maintenance and inspection requirements?
250.447 When must I pressure test the BOP system?
250.448 What are the BOP pressure tests requirements?
250.449 What additional BOP testing requirements must I meet?
250.450 What are the recordkeeping requirements for BOP tests?
250.451 What must I do in certain situations involving BOP equipment
or systems?
Drilling Fluid Requirements
250.455 What are the general requirements for a drilling fluid
program?
250.456 What safe practices must the drilling fluid program follow?
250.457 What equipment is required to monitor drilling fluids?
250.458 What quantities of drilling fluids are required?
250.459 What are the safety requirements for drilling fluid-handling
areas?
Other Drilling Requirements
250.460 What are the requirements for conducting a well test?
250.461 What are the requirements for directional and inclination
surveys?
250.462 What are the requirements for well-control drills?
250.463 Who establishes field drilling rules?
Applying for a Permit To Modify and Well Records
250.465 When must I submit an Application for Permit to Modify (APM)
or an End of Operations Report to BSEE?
250.466 What records must I keep?
250.467 How long must I keep records?
250.468 What well records am I required to submit?
250.469 What other well records could I be required to submit?
Hydrogen Sulfide
250.490 Hydrogen sulfide.
Subpart E--Oil and Gas Well-Completion Operations
250.500 General requirements.
250.501 Definition.
250.502 Equipment movement.
250.503 Emergency shutdown system.
250.504 Hydrogen sulfide.
250.505 Subsea completions.
250.506 Crew instructions.
250.507 [Reserved]
250.508 [Reserved]
250.509 Well-completion structures on fixed platforms.
250.510 Diesel engine air intakes.
250.511 Traveling-block safety device.
250.512 Field well-completion rules.
250.513 Approval and reporting of well-completion operations.
250.514 Well-control fluids, equipment, and operations.
250.515 Blowout prevention equipment.
250.516 Blowout preventer system tests, inspections, and
maintenance.
250.517 Tubing and wellhead equipment.
Casing Pressure Management
250.518 What are the requirements for casing pressure management?
250.519 How often do I have to monitor for casing pressure?
250.520 When do I have to perform a casing diagnostic test?
250.521 How do I manage the thermal effects caused by initial
production on a newly completed or recompleted well?
250.522 When do I have to repeat casing diagnostic testing?
250.523 How long do I keep records of casing pressure and diagnostic
tests?
250.524 When am I required to take action from my casing diagnostic
test?
250.525 What do I submit if my casing diagnostic test requires
action?
250.526 What must I include in my notification of corrective action?
250.527 What must I include in my casing pressure request?
250.528 What are the terms of my casing pressure request?
250.529 What if my casing pressure request is denied?
250.530 When does my casing pressure request approval become
invalid?
Subpart F--Oil and Gas Well-Workover Operations
250.600 General requirements.
250.601 Definitions.
250.602 Equipment movement.
250.603 Emergency shutdown system.
250.604 Hydrogen sulfide.
250.605 Subsea workovers.
250.606 Crew instructions.
250.607 [Reserved]
250.608 [Reserved]
250.609 Well-workover structures on fixed platforms.
250.610 Diesel engine air intakes.
250.611 Traveling-block safety device.
250.612 Field well-workover rules.
250.613 Approval and reporting for well-workover operations.
250.614 Well-control fluids, equipment, and operations.
250.615 Blowout prevention equipment.
250.616 Blowout preventer system testing, records, and drills.
250.617 What are my BOP inspection and maintenance requirements?
[[Page 64489]]
250.618 Tubing and wellhead equipment.
250.619 Wireline operations.
Subpart G--[Reserved]
Subpart H--Oil and Gas Production Safety Systems
250.800 General requirements.
250.801 Subsurface safety devices.
250.802 Design, installation, and operation of surface production-
safety systems.
250.803 Additional production system requirements.
250.804 Production safety-system testing and records.
250.805 Safety device training.
250.806 Safety and pollution prevention equipment quality assurance
requirements.
250.807 Additional requirements for subsurface safety valves and
related equipment installed in high pressure high temperature (HPHT)
environments.
250.808 Hydrogen sulfide.
Subpart I--Platforms and Structures
General Requirements for Platforms
250.900 What general requirements apply to all platforms?
250.901 What industry standards must your platform meet?
250.902 What are the requirements for platform removal and location
clearance?
250.903 What records must I keep?
Platform Approval Program
250.904 What is the Platform Approval Program?
250.905 How do I get approval for the installation, modification, or
repair of my platform?
250.906 What must I do to obtain approval for the proposed site of
my platform?
250.907 Where must I locate foundation boreholes?
250.908 What are the minimum structural fatigue design requirements?
Platform Verification Program
250.909 What is the Platform Verification Program?
250.910 Which of my facilities are subject to the Platform
Verification Program?
250.911 If my platform is subject to the Platform Verification
Program, what must I do?
250.912 What plans must I submit under the Platform Verification
Program?
250.913 When must I resubmit Platform Verification Program plans?
250.914 How do I nominate a CVA?
250.915 What are the CVA's primary responsibilities?
250.916 What are the CVA's primary duties during the design phase?
250.917 What are the CVA's primary duties during the fabrication
phase?
250.918 What are the CVA's primary duties during the installation
phase?
Inspection, Maintenance, and Assessment of Platforms
250.919 What in-service inspection requirements must I meet?
250.920 What are the BSEE requirements for assessment of fixed
platforms?
250.921 How do I analyze my platform for cumulative fatigue?
Subpart J--Pipelines and Pipeline Rights-of-Way
250.1000 General requirements.
250.1001 Definitions.
250.1002 Design requirements for DOI pipelines.
250.1003 Installation, testing, and repair requirements for DOI
pipelines.
250.1004 Safety equipment requirements for DOI pipelines.
250.1005 Inspection requirements for DOI pipelines.
250.1006 How must I decommission and take out of service a DOI
pipeline?
250.1007 What to include in applications.
250.1008 Reports.
250.1009 Requirements to obtain pipeline right-of-way grants.
250.1010 General requirements for pipeline right-of-way holders.
250.1011 [Reserved]
250.1012 Required payments for pipeline right-of-way holders.
250.1013 Grounds for forfeiture of pipeline right-of-way grants.
250.1014 When pipeline right-of-way grants expire.
250.1015 Applications for pipeline right-of-way grants.
250.1016 Granting pipeline rights-of-way.
250.1017 Requirements for construction under pipeline right-of-way
grants.
250.1018 Assignment of pipeline right-of-way grants.
250.1019 Relinquishment of pipeline right-of-way grants.
Subpart K--Oil and Gas Production Requirements
General
250.1150 What are the general reservoir production requirements?
Well Tests and Surveys
250.1151 How often must I conduct well production tests?
250.1152 How do I conduct well tests?
250.1153 [Reserved]
Classifying Reservoirs
250.1154 [Reserved]
250.1155 [Reserved]
Approvals Prior to Production
250.1156 What steps must I take to receive approval to produce
within 500 feet of a unit or lease line?
250.1157 How do I receive approval to produce gas-cap gas from an
oil reservoir with an associated gas cap?
250.1158 How do I receive approval to downhole commingle
hydrocarbons?
Production Rates
250.1159 May the Regional Supervisor limit my well or reservoir
production rates?
Flaring, Venting, and Burning Hydrocarbons
250.1160 When may I flare or vent gas?
250.1161 When may I flare or vent gas for extended periods of time?
250.1162 When may I burn produced liquid hydrocarbons?
250.1163 How must I measure gas flaring or venting volumes and
liquid hydrocarbon burning volumes, and what records must I
maintain?
250.1164 What are the requirements for flaring or venting gas
containing H2S?
Other Requirements
250.1165 What must I do for enhanced recovery operations?
250.1166 What additional reporting is required for developments in
the Alaska OCS Region?
250.1167 What information must I submit with forms and for
approvals?
Subpart L--Oil and Gas Production Measurement, Surface Commingling, and
Security
250.1200 Question index table.
250.1201 Definitions.
250.1202 Liquid hydrocarbon measurement.
250.1203 Gas measurement.
250.1204 Surface commingling.
250.1205 Site security.
Subpart M--Unitization
250.1300 What is the purpose of this subpart?
250.1301 What are the requirements for unitization?
250.1302 What if I have a competitive reservoir on a lease?
250.1303 How do I apply for voluntary unitization?
250.1304 How will BSEE require unitization?
Subpart N--Outer Continental Shelf Civil Penalties
Outer Continental Shelf Lands Act Civil Penalties
250.1400 How does BSEE begin the civil penalty process?
250.1401 Index table.
250.1402 Definitions.
250.1403 What is the maximum civil penalty?
250.1404 Which violations will BSEE review for potential civil
penalties?
250.1405 When is a case file developed?
250.1406 When will BSEE notify me and provide penalty information?
250.1407 How do I respond to the letter of notification?
250.1408 When will I be notified of the Reviewing Officer's
decision?
250.1409 What are my appeal rights?
Federal Oil and Gas Royalty Management Act Civil Penalties Definitions
250.1450 What definitions apply to this subpart?
Penalties After a Period To Correct
250.1451 What may BSEE do if I violate a statute, regulation, order,
or lease term relating to a Federal oil and gas lease?
250.1452 What if I correct the violation?
250.1453 What if I do not correct the violation?
250.1454 How may I request a hearing on the record on a Notice of
Noncompliance?
250.1455 Does my request for a hearing on the record affect the
penalties?
[[Page 64490]]
250.1456 May I request a hearing on the record regarding the amount
of a civil penalty if I did not request a hearing on the Notice of
Noncompliance?
Penalties Without a Period To Correct
250.1460 May I be subject to penalties without prior notice and an
opportunity to correct?
250.1461 How will BSEE inform me of violations without a period to
correct?
250.1462 How may I request a hearing on the record on a Notice of
Noncompliance regarding violations without a period to correct?
250.1463 Does my request for a hearing on the record affect the
penalties?
250.1464 May I request a hearing on the record regarding the amount
of a civil penalty if I did not request a hearing on the Notice of
Noncompliance?
General Provisions
250.1470 How does BSEE decide what the amount of the penalty should
be?
250.1471 Does the penalty affect whether I owe interest?
250.1472 How will the Office of Hearings and Appeals conduct the
hearing on the record?
250.1473 How may I appeal the Administrative Law Judge's decision?
250.1474 May I seek judicial review of the decision of the Interior
Board of Land Appeals?
250.1475 When must I pay the penalty?
250.1476 Can BSEE reduce my penalty once it is assessed?
250.1477 How may BSEE collect the penalty?
Criminal Penalties
250.1480 May the United States criminally prosecute me for
violations under Federal oil and gas leases?
Bonding Requirements
250.1490 What standards must my BOEM-specified surety instrument
meet?
250.1491 How will BOEM determine the amount of my bond or other
surety instrument?
Financial Solvency Requirements
250.1495 How do I demonstrate financial solvency?
250.1496 How will BOEM determine if I am financially solvent?
250.1497 When will BOEM monitor my financial solvency?
Subpart O--Well Control and Production Safety Training
250.1500 Definitions.
250.1501 What is the goal of my training program?
250.1503 What are my general responsibilities for training?
250.1504 May I use alternative training methods?
250.1505 Where may I get training for my employees?
250.1506 How often must I train my employees?
250.1507 How will BSEE measure training results?
250.1508 What must I do when BSEE administers written or oral tests?
250.1509 What must I do when BSEE administers or requires hands-on,
simulator, or other types of testing?
250.1510 What will BSEE do if my training program does not comply
with this subpart?
Subpart P--Sulphur Operations
250.1600 Performance standard.
250.1601 Definitions.
250.1602 Applicability.
250.1603 Determination of sulphur deposit.
250.1604 General requirements.
250.1605 Drilling requirements.
250.1606 Control of wells.
250.1607 Field rules.
250.1608 Well casing and cementing.
250.1609 Pressure testing of casing.
250.1610 Blowout preventer systems and system components.
250.1611 Blowout preventer systems tests, actuations, inspections,
and maintenance.
250.1612 Well-control drills.
250.1613 Diverter systems.
250.1614 Mud program.
250.1615 Securing of wells.
250.1616 Supervision, surveillance, and training.
250.1617 Application for permit to drill.
250.1618 Application for permit to modify.
250.1619 Well records.
250.1620 Well-completion and well-workover requirements.
250.1621 Crew instructions.
250.1622 Approvals and reporting of well-completion and well-
workover operations.
250.1623 Well-control fluids, equipment, and operations.
250.1624 Blowout prevention equipment.
250.1625 Blowout preventer system testing, records, and drills.
250.1626 Tubing and wellhead equipment.
250.1627 Production requirements.
250.1628 Design, installation, and operation of production systems.
250.1629 Additional production and fuel gas system requirements.
250.1630 Safety-system testing and records.
250.1631 Safety device training.
250.1632 Production rates.
250.1633 Production measurement.
250.1634 Site security.
Subpart Q--Decommissioning Activities
General
250.1700 What do the terms ``decommissioning'', ``obstructions'',
and ``facility'' mean?
250.1701 Who must meet the decommissioning obligations in this
subpart?
250.1702 When do I accrue decommissioning obligations?
250.1703 What are the general requirements for decommissioning?
250.1704 When must I submit decommissioning applications and
reports?
Permanently Plugging Wells
250.1710 When must I permanently plug all wells on a lease?
250.1711 When will BSEE order me to permanently plug a well?
250.1712 What information must I submit before I permanently plug a
well or zone?
250.1713 Must I notify BSEE before I begin well plugging operations?
250.1714 What must I accomplish with well plugs?
250.1715 How must I permanently plug a well?
250.1716 To what depth must I remove wellheads and casings?
250.1717 After I permanently plug a well, what information must I
submit?
Temporary Abandoned Wells
250.1721 If I temporarily abandon a well that I plan to re-enter,
what must I do?
250.1722 If I install a subsea protective device, what requirements
must I meet?
250.1723 What must I do when it is no longer necessary to maintain a
well in temporary abandoned status?
Removing Platforms and Other Facilities
250.1725 When do I have to remove platforms and other facilities?
250.1726 When must I submit an initial platform removal application
and what must it include?
250.1727 What information must I include in my final application to
remove a platform or other facility?
250.1728 To what depth must I remove a platform or other facility?
250.1729 After I remove a platform or other facility, what
information must I submit?
250.1730 When might BSEE approve partial structure removal or
toppling in place?
250.1731 Who is responsible for decommissioning an OCS facility
subject to an Alternate Use RUE?
Site Clearance for Wells, Platforms, and Other Facilities
250.1740 How must I verify that the site of a permanently plugged
well, removed platform, or other removed facility is clear of
obstructions?
250.1741 If I drag a trawl across a site, what requirements must I
meet?
250.1742 What other methods can I use to verify that a site is
clear?
250.1743 How do I certify that a site is clear of obstructions?
Pipeline Decommissioning
250.1750 When may I decommission a pipeline in place?
250.1751 How do I decommission a pipeline in place?
250.1752 How do I remove a pipeline?
250.1753 After I decommission a pipeline, what information must I
submit?
250.1754 When must I remove a pipeline decommissioned in place?
Subpart R--[Reserved]
Subpart S--Safety and Environmental Management Systems (SEMS)
250.1900 Must I have a SEMS program?
250.1901 What is the goal of my SEMS program?
250.1902 What must I include in my SEMS program?
250.1903 Definitions.
250.1904 Documents incorporated by reference.
[[Page 64491]]
250.1905-250.1908 [Reserved]
250.1909 What are management's general responsibilities for the SEMS
program?
250.1910 What safety and environmental information is required?
250.1911 What criteria for hazards analyses must my SEMS program
meet?
250.1912 What criteria for management of change must my SEMS program
meet?
250.1913 What criteria for operating procedures must my SEMS program
meet?
250.1914 What criteria must be documented in my SEMS program for
safe work practices and contractor selection?
250.1915 What criteria for training must be in my SEMS program?
250.1916 What criteria for mechanical integrity must my SEMS program
meet?
250.1917 What criteria for pre-startup review must be in my SEMS
program?
250.1918 What criteria for emergency response and control must be in
my SEMS program?
250.1919 What criteria for investigation of incidents must be in my
SEMS program?
250.1920 What are the auditing requirements for my SEMS program?
250.1921-250.1923 [Reserved]
250.1924 How will BSEE determine if my SEMS program is effective?
250.1925 May BSEE direct me to conduct additional audits?
250.1926 What qualifications must an independent third party or my
designated and qualified personnel meet?
250.1927 What happens if BSEE finds shortcomings in my SEMS program?
250.1928 What are my recordkeeping and documentation requirements?
250.1929 What are my responsibilities for submitting OCS performance
measure data?
Authority: 30 U.S.C. 1751; 31 U.S.C. 9701; 43 U.S.C. 1334.
Subpart A--General
Authority and Definition of Terms
Sec. 250.101 Authority and applicability.
The Secretary of the Interior (Secretary) authorized the Bureau of
Safety and Environmental Enforcement (BSEE) to regulate oil, gas, and
sulphur exploration, development, and production operations on the
Outer Continental Shelf (OCS). Under the Secretary's authority, the
Director requires that all operations:
(a) Be conducted according to the OCS Lands Act (OCSLA), the
regulations in this part, BSEE orders, the lease or right-of-way, and
other applicable laws, regulations, and amendments; and
(b) Conform to sound conservation practice to preserve, protect,
and develop mineral resources of the OCS to:
(1) Make resources available to meet the Nation's energy needs;
(2) Balance orderly energy resource development with protection of
the human, marine, and coastal environments;
(3) Ensure the public receives a fair and equitable return on the
resources of the OCS;
(4) Preserve and maintain free enterprise competition; and
(5) Minimize or eliminate conflicts between the exploration,
development, and production of oil and natural gas and the recovery of
other resources.
Sec. 250.102 What does this part do?
(a) This part 250 contains the regulations of the BSEE Offshore
program that govern oil, gas, and sulphur exploration, development, and
production operations on the OCS. When you conduct operations on the
OCS, you must submit requests, applications, and notices, or provide
supplemental information for BSEE approval.
(b) The following table of general references shows where to look
for information about these processes.
Table--Where To Find Information for Conducting Operations
------------------------------------------------------------------------
For information about . . . Refer to . . .
------------------------------------------------------------------------
(1) Applications for permit to drill, 30 CFR 250, subpart D.
(2) Development and Production Plans 30 CFR 550, subpart B.
(DPP),
(3) Downhole commingling, 30 CFR 250, subpart K.
(4) Exploration Plans (EP), 30 CFR, 550, subpart B.
(5) Flaring, 30 CFR 250, subpart K.
(6) Gas measurement, 30 CFR 250, subpart L.
(7) Off-lease geological and geophysical 30 CFR 551.
permits,
(8) Oil spill financial responsibility 30 CFR 553.
coverage,
(9) Oil and gas production safety systems, 30 CFR 250, subpart H.
(10) Oil spill response plans, 30 CFR 254.
(11) Oil and gas well-completion 30 CFR 250, subpart E.
operations,
(12) Oil and gas well-workover operations, 30 CFR 250, subpart F.
(13) Decommissioning Activities, 30 CFR 250, subpart Q.
(14) Platforms and structures, 30 CFR 250, subpart I.
(15) Pipelines and Pipeline Rights-of-Way, 30 CFR 250, subpart J and 30
CFR 550, subpart J.
(16) Sulphur operations, 30 CFR 250, subpart P.
(17) Training, 30 CFR 250, subpart O.
(18) Unitization, 30 CFR 250, subpart M.
------------------------------------------------------------------------
Sec. 250.103 Where can I find more information about the requirements
in this part?
BSEE may issue Notices to Lessees and Operators (NTLs) that
clarify, supplement, or provide more detail about certain requirements.
NTLs may also outline what you must provide as required information in
your various submissions to BSEE.
Sec. 250.104 How may I appeal a decision made under BSEE regulations?
To appeal orders or decisions issued under BSEE regulations in 30
CFR parts 250 to 282, follow the procedures in 30 CFR part 290.
Sec. 250.105 Definitions.
Terms used in this part will have the meanings given in the Act and
as defined in this section:
Act means the OCS Lands Act, as amended (43 U.S.C. 1331 et seq.).
Affected State means with respect to any program, plan, lease sale,
or other activity proposed, conducted, or approved under the provisions
of the Act, any State:
(1) The laws of which are declared, under section 4(a)(2) of the
Act, to be the law of the United States for the portion of the OCS on
which such activity is, or is proposed to be, conducted;
(2) Which is, or is proposed to be, directly connected by
transportation
[[Page 64492]]
facilities to any artificial island or installation or other device
permanently or temporarily attached to the seabed;
(3) Which is receiving, or according to the proposed activity, will
receive oil for processing, refining, or transshipment that was
extracted from the OCS and transported directly to such State by means
of vessels or by a combination of means including vessels;
(4) Which is designated by the Secretary as a State in which there
is a substantial probability of significant impact on or damage to the
coastal, marine, or human environment, or a State in which there will
be significant changes in the social, governmental, or economic
infrastructure, resulting from the exploration, development, and
production of oil and gas anywhere on the OCS; or
(5) In which the Secretary finds that because of such activity
there is, or will be, a significant risk of serious damage, due to
factors such as prevailing winds and currents to the marine or coastal
environment in the event of any oil spill, blowout, or release of oil
or gas from vessels, pipelines, or other transshipment facilities.
Air pollutant means any airborne agent or combination of agents for
which the Environmental Protection Agency (EPA) has established, under
section 109 of the Clean Air Act, national primary or secondary ambient
air quality standards.
Analyzed geological information means data collected under a permit
or a lease that have been analyzed. Analysis may include, but is not
limited to, identification of lithologic and fossil content, core
analysis, laboratory analyses of physical and chemical properties, well
logs or charts, results from formation fluid tests, and descriptions of
hydrocarbon occurrences or hazardous conditions.
Ancillary activities mean those activities on your lease or unit
that you:
(1) Conduct to obtain data and information to ensure proper
exploration or development of your lease or unit; and
(2) Can conduct without Bureau of Ocean Energy Management (BOEM)
approval of an application or permit.
Archaeological interest means capable of providing scientific or
humanistic understanding of past human behavior, cultural adaptation,
and related topics through the application of scientific or scholarly
techniques, such as controlled observation, contextual measurement,
controlled collection, analysis, interpretation, and explanation.
Archaeological resource means any material remains of human life or
activities that are at least 50 years of age and that are of
archaeological interest.
Attainment area means, for any air pollutant, an area that is shown
by monitored data or that is calculated by air quality modeling (or
other methods determined by the Administrator of EPA to be reliable)
not to exceed any primary or secondary ambient air quality standards
established by EPA.
Best available and safest technology (BAST) means the best
available and safest technologies that the BSEE Director determines to
be economically feasible wherever failure of equipment would have a
significant effect on safety, health, or the environment.
Best available control technology (BACT) means an emission
limitation based on the maximum degree of reduction for each air
pollutant subject to regulation, taking into account energy,
environmental and economic impacts, and other costs. The Regional
Supervisor will verify the BACT on a case-by-case basis, and it may
include reductions achieved through the application of processes,
systems, and techniques for the control of each air pollutant.
Coastal environment means the physical, atmospheric, and biological
components, conditions, and factors that interactively determine the
productivity, state, condition, and quality of the terrestrial
ecosystem from the shoreline inward to the boundaries of the coastal
zone.
Coastal zone means the coastal waters (including the lands therein
and thereunder) and the adjacent shorelands (including the waters
therein and thereunder) strongly influenced by each other and in
proximity to the shorelands of the several coastal States. The coastal
zone includes islands, transition and intertidal areas, salt marshes,
wetlands, and beaches. The coastal zone extends seaward to the outer
limit of the U.S. territorial sea and extends inland from the
shorelines to the extent necessary to control shorelands, the uses of
which have a direct and significant impact on the coastal waters, and
the inward boundaries of which may be identified by the several coastal
States, under the authority in section 305(b)(1) of the Coastal Zone
Management Act (CZMA) of 1972.
Competitive reservoir means a reservoir in which there are one or
more producible or producing well completions on each of two or more
leases or portions of leases, with different lease operating interests,
from which the lessees plan future production.
Correlative rights when used with respect to lessees of adjacent
leases, means the right of each lessee to be afforded an equal
opportunity to explore for, develop, and produce, without waste,
minerals from a common source.
Data means facts and statistics, measurements, or samples that have
not been analyzed, processed, or interpreted.
Departures mean approvals granted by the appropriate BSEE or BOEM
representative for operating requirements/procedures other than those
specified in the regulations found in this part. These requirements/
procedures may be necessary to control a well; properly develop a
lease; conserve natural resources, or protect life, property, or the
marine, coastal, or human environment.
Development means those activities that take place following
discovery of minerals in paying quantities, including but not limited
to geophysical activity, drilling, platform construction, and operation
of all directly related onshore support facilities, and which are for
the purpose of producing the minerals discovered.
Development geological and geophysical (G&G) activities mean those
G&G and related data-gathering activities on your lease or unit that
you conduct following discovery of oil, gas, or sulphur in paying
quantities to detect or imply the presence of oil, gas, or sulphur in
commercial quantities.
Director means the Director of BSEE of the U.S. Department of the
Interior, or an official authorized to act on the Director's behalf.
District Manager means the BSEE officer with authority and
responsibility for operations or other designated program functions for
a district within a BSEE Region.
Easement means an authorization for a nonpossessory, nonexclusive
interest in a portion of the OCS, whether leased or unleased, which
specifies the rights of the holder to use the area embraced in the
easement in a manner consistent with the terms and conditions of the
granting authority.
Eastern Gulf of Mexico means all OCS areas of the Gulf of Mexico
the BOEM Director decides are adjacent to the State of Florida. The
Eastern Gulf of Mexico is not the same as the Eastern Planning Area, an
area established for OCS lease sales.
Emission offsets mean emission reductions obtained from facilities,
either onshore or offshore, other than the facility or facilities
covered by the proposed Exploration Plan (EP) or Development and
Production Plan (DPP).
Enhanced recovery operations mean pressure maintenance operations,
[[Page 64493]]
secondary and tertiary recovery, cycling, and similar recovery
operations that alter the natural forces in a reservoir to increase the
ultimate recovery of oil or gas.
Existing facility, as used in 30 CFR 550.303, means an OCS facility
described in an Exploration Plan or a Development and Production Plan
approved before June 2, 1980.
Exploration means the commercial search for oil, gas, or sulphur.
Activities classified as exploration include but are not limited to:
(1) Geophysical and geological (G&G) surveys using magnetic,
gravity, seismic reflection, seismic refraction, gas sniffers, coring,
or other systems to detect or imply the presence of oil, gas, or
sulphur; and
(2) Any drilling conducted for the purpose of searching for
commercial quantities of oil, gas, and sulphur, including the drilling
of any additional well needed to delineate any reservoir to enable the
lessee to decide whether to proceed with development and production.
Facility means:
(1) As used in Sec. 250.130, all installations permanently or
temporarily attached to the seabed on the OCS (including manmade
islands and bottom-sitting structures). They include mobile offshore
drilling units (MODUs) or other vessels engaged in drilling or downhole
operations, used for oil, gas or sulphur drilling, production, or
related activities. They include all floating production systems
(FPSs), variously described as column-stabilized-units (CSUs); floating
production, storage and offloading facilities (FPSOs); tension-leg
platforms (TLPs); spars, etc. They also include facilities for product
measurement and royalty determination (e.g., lease Automatic Custody
Transfer Units, gas meters) of OCS production on installations not on
the OCS. Any group of OCS installations interconnected with walkways,
or any group of installations that includes a central or primary
installation with processing equipment and one or more satellite or
secondary installations is a single facility. The Regional Supervisor
may decide that the complexity of the individual installations
justifies their classification as separate facilities.
(2) As used in 30 CFR 550.303, means all installations or devices
permanently or temporarily attached to the seabed. They include mobile
offshore drilling units (MODUs), even while operating in the ``tender
assist'' mode (i.e., with skid-off drilling units) or other vessels
engaged in drilling or downhole operations. They are used for
exploration, development, and production activities for oil, gas, or
sulphur and emit or have the potential to emit any air pollutant from
one or more sources. They include all floating production systems
(FPSs), including column-stabilized-units (CSUs); floating production,
storage and offloading facilities (FPSOs); tension-leg platforms
(TLPs); spars, etc. During production, multiple installations or
devices are a single facility if the installations or devices are at a
single site. Any vessel used to transfer production from an offshore
facility is part of the facility while it is physically attached to the
facility.
(3) As used in Sec. 250.490(b), means a vessel, a structure, or an
artificial island used for drilling, well completion, well-workover, or
production operations.
(4) As used in Sec. Sec. 250.900 through 250.921, means all
installations or devices permanently or temporarily attached to the
seabed. They are used for exploration, development, and production
activities for oil, gas, or sulphur and emit or have the potential to
emit any air pollutant from one or more sources. They include all
floating production systems (FPSs), including column-stabilized-units
(CSUs); floating production, storage and offloading facilities (FPSOs);
tension-leg platforms (TLPs); spars, etc. During production, multiple
installations or devices are a single facility if the installations or
devices are at a single site. Any vessel used to transfer production
from an offshore facility is part of the facility while it is
physically attached to the facility.
Flaring means the burning of natural gas as it is released into the
atmosphere.
Gas reservoir means a reservoir that contains hydrocarbons
predominantly in a gaseous (single-phase) state.
Gas-well completion means a well completed in a gas reservoir or in
the associated gas-cap of an oil reservoir.
Geological and geophysical (G&G) explorations mean those G&G
surveys on your lease or unit that use seismic reflection, seismic
refraction, magnetic, gravity, gas sniffers, coring, or other systems
to detect or imply the presence of oil, gas, or sulphur in commercial
quantities.
Governor means the Governor of a State, or the person or entity
designated by, or under, State law to exercise the powers granted to
such Governor under the Act.
H2S absent means:
(1) Drilling, logging, coring, testing, or producing operations
have confirmed the absence of H2S in concentrations that
could potentially result in atmospheric concentrations of 20 ppm or
more of H2S; or
(2) Drilling in the surrounding areas and correlation of geological
and seismic data with equivalent stratigraphic units have confirmed an
absence of H2S throughout the area to be drilled.
H2S present means drilling, logging, coring, testing, or producing
operations have confirmed the presence of H2S in
concentrations and volumes that could potentially result in atmospheric
concentrations of 20 ppm or more of H2S.
H2S unknown means the designation of a zone or geologic formation
where neither the presence nor absence of H2S has been
confirmed.
Human environment means the physical, social, and economic
components, conditions, and factors that interactively determine the
state, condition, and quality of living conditions, employment, and
health of those affected, directly or indirectly, by activities
occurring on the OCS.
Interpreted geological information means geological knowledge,
often in the form of schematic cross sections, 3-dimensional
representations, and maps, developed by determining the geological
significance of data and analyzed geological information.
Interpreted geophysical information means geophysical knowledge,
often in the form of schematic cross sections, 3-dimensional
representations, and maps, developed by determining the geological
significance of geophysical data and analyzed geophysical information.
Lease means an agreement that is issued under section 8 or
maintained under section 6 of the Act and that authorizes exploration
for, and development and production of, minerals. The term also means
the area covered by that authorization, whichever the context requires.
Lease term pipelines mean those pipelines owned and operated by a
lessee or operator that are completely contained within the boundaries
of a single lease, unit, or contiguous (not cornering) leases of that
lessee or operator.
Lessee means a person who has entered into a lease with the United
States to explore for, develop, and produce the leased minerals. The
term lessee also includes the BOEM-approved assignee of the lease, and
the owner or the BOEM-approved assignee of operating rights for the
lease.
Major Federal action means any action or proposal by the Secretary
that is subject to the provisions of section 102(2)(C) of the National
Environmental Policy Act of 1969, 42 U.S.C. (2)(C) (i.e.,
[[Page 64494]]
an action that will have a significant impact on the quality of the
human environment requiring preparation of an environmental impact
statement under section 102(2)(C) of the National Environmental Policy
Act).
Marine environment means the physical, atmospheric, and biological
components, conditions, and factors that interactively determine the
productivity, state, condition, and quality of the marine ecosystem.
These include the waters of the high seas, the contiguous zone,
transitional and intertidal areas, salt marshes, and wetlands within
the coastal zone and on the OCS.
Material remains mean physical evidence of human habitation,
occupation, use, or activity, including the site, location, or context
in which such evidence is situated.
Maximum efficient rate (MER) means the maximum sustainable daily
oil or gas withdrawal rate from a reservoir that will permit economic
development and depletion of that reservoir without detriment to
ultimate recovery.
Maximum production rate (MPR) means the approved maximum daily rate
at which oil or gas may be produced from a specified oil-well or gas-
well completion.
Minerals include oil, gas, sulphur, geopressured-geothermal and
associated resources, and all other minerals that are authorized by an
Act of Congress to be produced.
Natural resources include, without limiting the generality thereof,
oil, gas, and all other minerals, and fish, shrimp, oysters, clams,
crabs, lobsters, sponges, kelp, and other marine animal and plant life
but does not include water power or the use of water for the production
of power.
Nonattainment area means, for any air pollutant, an area that is
shown by monitored data or that is calculated by air quality modeling
(or other methods determined by the Administrator of EPA to be
reliable) to exceed any primary or secondary ambient air quality
standard established by EPA.
Nonsensitive reservoir means a reservoir in which ultimate recovery
is not decreased by high reservoir production rates.
Oil reservoir means a reservoir that contains hydrocarbons
predominantly in a liquid (single-phase) state.
Oil reservoir with an associated gas cap means a reservoir that
contains hydrocarbons in both a liquid and gaseous (two-phase) state.
Oil-well completion means a well completed in an oil reservoir or
in the oil accumulation of an oil reservoir with an associated gas cap.
Operating rights mean any interest held in a lease with the right
to explore for, develop, and produce leased substances.
Operator means the person the lessee(s) designates as having
control or management of operations on the leased area or a portion
thereof. An operator may be a lessee, the BSEE-approved or BOEM-
approved designated agent of the lessee(s), or the holder of operating
rights under a BOEM-approved operating rights assignment.
Outer Continental Shelf (OCS) means all submerged lands lying
seaward and outside of the area of lands beneath navigable waters as
defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301) whose
subsoil and seabed appertain to the United States and are subject to
its jurisdiction and control.
Person includes a natural person, an association (including
partnerships, joint ventures, and trusts), a State, a political
subdivision of a State, or a private, public, or municipal corporation.
Pipelines are the piping, risers, and appurtenances installed for
transporting oil, gas, sulphur, and produced waters.
Processed geological or geophysical information means data
collected under a permit or a lease that have been processed or
reprocessed. Processing involves changing the form of data to
facilitate interpretation. Processing operations may include, but are
not limited to, applying corrections for known perturbing causes,
rearranging or filtering data, and combining or transforming data
elements. Reprocessing is the additional processing other than ordinary
processing used in the general course of evaluation. Reprocessing
operations may include varying identified parameters for the detailed
study of a specific problem area.
Production means those activities that take place after the
successful completion of any means for the removal of minerals,
including such removal, field operations, transfer of minerals to
shore, operation monitoring, maintenance, and workover operations.
Production areas are those areas where flammable petroleum gas,
volatile liquids or sulphur are produced, processed (e.g., compressed),
stored, transferred (e.g., pumped), or otherwise handled before
entering the transportation process.
Projected emissions mean emissions, either controlled or
uncontrolled, from a source or sources.
Prospect means a geologic feature having the potential for mineral
deposits.
Regional Director means the BSEE officer with responsibility and
authority for a Region within BSEE.
Regional Supervisor means the BSEE officer with responsibility and
authority for operations or other designated program functions within a
BSEE Region.
Right-of-use means any authorization issued under 30 CFR Part 550
to use OCS lands.
Right-of-way pipelines are those pipelines that are contained
within:
(1) The boundaries of a single lease or unit, but are not owned and
operated by a lessee or operator of that lease or unit;
(2) The boundaries of contiguous (not cornering) leases that do not
have a common lessee or operator;
(3) The boundaries of contiguous (not cornering) leases that have a
common lessee or operator but are not owned and operated by that common
lessee or operator; or
(4) An unleased block(s).
Routine operations, for the purposes of subpart F, mean any of the
following operations conducted on a well with the tree installed:
(1) Cutting paraffin;
(2) Removing and setting pump-through-type tubing plugs, gas-lift
valves, and subsurface safety valves that can be removed by wireline
operations;
(3) Bailing sand;
(4) Pressure surveys;
(5) Swabbing;
(6) Scale or corrosion treatment;
(7) Caliper and gauge surveys;
(8) Corrosion inhibitor treatment;
(9) Removing or replacing subsurface pumps;
(10) Through-tubing logging (diagnostics);
(11) Wireline fishing;
(12) Setting and retrieving other subsurface flow-control devices;
and
(13) Acid treatments.
Sensitive reservoir means a reservoir in which the production rate
will affect ultimate recovery.
Significant archaeological resource means those archaeological
resources that meet the criteria of significance for eligibility to the
National Register of Historic Places as defined in 36 CFR 60.4, or its
successor.
Suspension means a granted or directed deferral of the requirement
to produce (Suspension of Production (SOP)) or to conduct leaseholding
operations (Suspension of Operations (SOO)).
Venting means the release of gas into the atmosphere without
igniting it. This includes gas that is released underwater and bubbles
to the atmosphere.
Waste of oil, gas, or sulphur means:
(1) The physical waste of oil, gas, or sulphur;
[[Page 64495]]
(2) The inefficient, excessive, or improper use, or the unnecessary
dissipation of reservoir energy;
(3) The locating, spacing, drilling, equipping, operating, or
producing of any oil, gas, or sulphur well(s) in a manner that causes
or tends to cause a reduction in the quantity of oil, gas, or sulphur
ultimately recoverable under prudent and proper operations or that
causes or tends to cause unnecessary or excessive surface loss or
destruction of oil or gas; or
(4) The inefficient storage of oil.
Welding means all activities connected with welding, including hot
tapping and burning.
Wellbay is the area on a facility within the perimeter of the
outermost wellheads.
Well-completion operations mean the work conducted to establish
production from a well after the production-casing string has been set,
cemented, and pressure-tested.
Well-control fluid means drilling mud, completion fluid, or
workover fluid as appropriate to the particular operation being
conducted.
Western Gulf of Mexico means all OCS areas of the Gulf of Mexico
except those the BOEM Director decides are adjacent to the State of
Florida. The Western Gulf of Mexico is not the same as the Western
Planning Area, an area established for OCS lease sales.
Workover operations mean the work conducted on wells after the
initial well-completion operation for the purpose of maintaining or
restoring the productivity of a well.
You means a lessee, the owner or holder of operating rights, a
designated operator or agent of the lessee(s), a pipeline right-of-way
holder, or a State lessee granted a right-of-use and easement.
Performance Standards
Sec. 250.106 What standards will the Director use to regulate lease
operations?
The Director will regulate all operations under a lease, right-of-
use and easement, or right-of-way to:
(a) Promote orderly exploration, development, and production of
mineral resources;
(b) Prevent injury or loss of life;
(c) Prevent damage to or waste of any natural resource, property,
or the environment; and
(d) Cooperate and consult with affected States, local governments,
other interested parties, and relevant Federal agencies.
Sec. 250.107 What must I do to protect health, safety, property, and
the environment?
(a) You must protect health, safety, property, and the environment
by:
(1) Performing all operations in a safe and workmanlike manner; and
(2) Maintaining all equipment and work areas in a safe condition.
(b) You must immediately control, remove, or otherwise correct any
hazardous oil and gas accumulation or other health, safety, or fire
hazard.
(c) You must use the best available and safest technology (BAST)
whenever practical on all exploration, development, and production
operations. In general, we consider your compliance with BSEE
regulations to be the use of BAST.
(d) The Director may require additional measures to ensure the use
of BAST:
(1) To avoid the failure of equipment that would have a significant
effect on safety, health, or the environment;
(2) If it is economically feasible; and
(3) If the benefits outweigh the costs.
Sec. 250.108 What requirements must I follow for cranes and other
material-handling equipment?
(a) All cranes installed on fixed platforms must be operated in
accordance with American Petroleum Institute's Recommended Practice for
Operation and Maintenance of Offshore Cranes, API RP 2D (as
incorporated by reference in Sec. 250.198).
(b) All cranes installed on fixed platforms must be equipped with a
functional anti-two block device.
(c) If a fixed platform is installed after March 17, 2003, all
cranes on the platform must meet the requirements of American Petroleum
Institute Specification for Offshore Pedestal Mounted Cranes, API Spec
2C (as incorporated by reference in Sec. 250.198).
(d) All cranes manufactured after March 17, 2003, and installed on
a fixed platform, must meet the requirements of API Spec 2C.
(e) You must maintain records specific to a crane or the operation
of a crane installed on an OCS fixed platform, as follows:
(1) Retain all design and construction records, including
installation records for any anti-two block safety devices, for the
life of the crane. The records must be kept at the OCS fixed platform.
(2) Retain all inspection, testing, and maintenance records of
cranes for at least 4 years. The records must be kept at the OCS fixed
platform.
(3) Retain the qualification records of the crane operator and all
rigger personnel for at least 4 years. The records must be kept at the
OCS fixed platform.
(f) You must operate and maintain all other material-handling
equipment in a manner that ensures safe operations and prevents
pollution.
Sec. 250.109 What documents must I prepare and maintain related to
welding?
(a) You must submit a Welding Plan to the District Manager before
you begin drilling or production activities on a lease. You may not
begin welding until the District Manager has approved your plan.
(b) You must keep the following at the site where welding occurs:
(1) A copy of the plan and its approval letter; and
(2) Drawings showing the designated safe-welding areas.
Sec. 250.110 What must I include in my welding plan?
You must include all of the following in the welding plan that you
prepare under Sec. 250.109:
(a) Standards or requirements for welders;
(b) How you will ensure that only qualified personnel weld;
(c) Practices and procedures for safe welding that address:
(1) Welding in designated safe areas;
(2) Welding in undesignated areas, including wellbay;
(3) Fire watches;
(4) Maintenance of welding equipment; and
(5) Plans showing all designated safe-welding areas.
(d) How you will prevent spark-producing activities (i.e.,
grinding, abrasive blasting/cutting and arc-welding) in hazardous
locations.
Sec. 250.111 Who oversees operations under my welding plan?
A welding supervisor or a designated person in charge must be
thoroughly familiar with your welding plan. This person must ensure
that each welder is properly qualified according to the welding plan.
This person also must inspect all welding equipment before welding.
Sec. 250.112 What standards must my welding equipment meet?
Your welding equipment must meet the following requirements:
(a) All engine-driven welding equipment must be equipped with spark
arrestors and drip pans;
(b) Welding leads must be completely insulated and in good
condition;
(c) Hoses must be leak-free and equipped with proper fittings,
gauges, and regulators; and
(d) Oxygen and fuel gas bottles must be secured in a safe place.
Sec. 250.113 What procedures must I follow when welding?
(a) Before you weld, you must move any equipment containing
hydrocarbons or other flammable substances at least
[[Page 64496]]
35 feet horizontally from the welding area. You must move similar
equipment on lower decks at least 35 feet from the point of impact
where slag, sparks, or other burning materials could fall. If moving
this equipment is impractical, you must protect that equipment with
flame-proofed covers, shield it with metal or fire-resistant guards or
curtains, or render the flammable substances inert.
(b) While you weld, you must monitor all water-discharge-point
sources from hydrocarbon-handling vessels. If a discharge of flammable
fluids occurs, you must stop welding.
(c) If you cannot weld in one of the designated safe-welding areas
that you listed in your safe welding plan, you must meet the following
requirements:
(1) You may not begin welding until:
(i) The welding supervisor or designated person in charge advises
in writing that it is safe to weld.
(ii) You and the designated person in charge inspect the work area
and areas below it for potential fire and explosion hazards.
(2) During welding, the person in charge must designate one or more
persons as a fire watch. The fire watch must:
(i) Have no other duties while actual welding is in progress;
(ii) Have usable firefighting equipment;
(iii) Remain on duty for 30 minutes after welding activities end;
and
(iv) Maintain a continuous surveillance with a portable gas
detector during the welding and burning operation if welding occurs in
an area not equipped with a gas detector.
(3) You may not weld piping, containers, tanks, or other vessels
that have contained a flammable substance unless you have rendered the
contents inert and the designated person in charge has determined it is
safe to weld. This does not apply to approved hot taps.
(4) You may not weld within 10 feet of a wellbay unless you have
shut in all producing wells in that wellbay.
(5) You may not weld within 10 feet of a production area, unless
you have shut in that production area.
(6) You may not weld while you drill, complete, workover, or
conduct wireline operations unless:
(i) The fluids in the well (being drilled, completed, worked over,
or having wireline operations conducted) are noncombustible; and
(ii) You have precluded the entry of formation hydrocarbons into
the wellbore by either mechanical means or a positive overbalance
toward the formation.
Sec. 250.114 How must I install and operate electrical equipment?
The requirements in this section apply to all electrical equipment
on all platforms, artificial islands, fixed structures, and their
facilities.
(a) You must classify all areas according to API RP 500,
Recommended Practice for Classification of Locations for Electrical
Installations at Petroleum Facilities Classified as Class I, Division 1
and Division 2, or API RP 505, Recommended Practice for Classification
of Locations for Electrical Installations at Petroleum Facilities
Classified as Class I, Zone 0, Zone 1, and Zone 2 (as incorporated by
reference in Sec. 250.198).
(b) Employees who maintain your electrical systems must have
expertise in area classification and the performance, operation and
hazards of electrical equipment.
(c) You must install all electrical systems according to API RP
14F, Recommended Practice for Design and Installation of Electrical
Systems for Fixed and Floating Offshore Petroleum Facilities for
Unclassified and Class I, Division 1, and Division 2 Locations (as
incorporated by reference in Sec. 250.198), or API RP 14FZ,
Recommended Practice for Design and Installation of Electrical Systems
for Fixed and Floating Offshore Petroleum Facilities for Unclassified
and Class I, Zone 0, Zone 1, and Zone 2 Locations (as incorporated by
reference in Sec. 250.198).
(d) On each engine that has an electric ignition system, you must
use an ignition system designed and maintained to reduce the release of
electrical energy.
Sec. Sec. 250.115-250.117 [Reserved]
Sec. 250.118 Will BSEE approve gas injection?
The Regional Supervisor may authorize you to inject gas on the OCS,
on and off-lease, to promote conservation of natural resources and to
prevent waste.
(a) To receive BSEE approval for injection, you must:
(1) Show that the injection will not result in undue interference
with operations under existing leases; and
(2) Submit a written application to the Regional Supervisor for
injection of gas.
(b) The Regional Supervisor will approve gas injection applications
that:
(1) Enhance recovery;
(2) Prevent flaring of casinghead gas; or
(3) Implement other conservation measures approved by the Regional
Supervisor.
Sec. 250.119 [Reserved]
Sec. 250.120 How does injecting, storing, or treating gas affect my
royalty payments?
(a) If you produce gas from an OCS lease and inject it into a
reservoir on the lease or unit for the purposes cited in Sec.
250.118(b), you are not required to pay royalties until you remove or
sell the gas from the reservoir.
(b) If you produce gas from an OCS lease and store it according to
30 CFR 550.119, you must pay royalty before injecting it into the
storage reservoir.
(c) If you produce gas from an OCS lease and treat it at an off-
lease or off-unit location, you must pay royalties when the gas is
first produced.
Sec. 250.121 What happens when the reservoir contains both original
gas in place and injected gas?
If the reservoir contains both original gas in place and injected
gas, when you produce gas from the reservoir you must use a BSEE-
approved formula to determine the amounts of injected or stored gas and
gas original to the reservoir.
Sec. 250.122 What effect does subsurface storage have on the lease
term?
If you use a lease area for subsurface storage of gas, it does not
affect the continuance or expiration of the lease.
Sec. 250.123 [Reserved]
Sec. 250.124 Will BSEE approve gas injection into the cap rock
containing a sulphur deposit?
To receive the Regional Supervisor's approval to inject gas into
the cap rock of a salt dome containing a sulphur deposit, you must show
that the injection:
(a) Is necessary to recover oil and gas contained in the cap rock;
and
(b) Will not significantly increase potential hazards to present or
future sulphur mining operations.
Fees
Sec. 250.125 Service fees.
(a) The table in this paragraph (a) shows the fees that you must
pay to BSEE for the services listed. The fees will be adjusted
periodically according to the Implicit Price Deflator for Gross
Domestic Product by publication of a document in the Federal Register.
If a significant adjustment is needed to arrive at the new actual cost
for any reason other than inflation, then a proposed rule containing
the new fees will be published in the Federal Register for comment.
[[Page 64497]]
------------------------------------------------------------------------
Service--processing of the
following: Fee amount 30 CFR citation
------------------------------------------------------------------------
(1) [Reserved]
(2) [Reserved]
(3) Suspension of Operations/ $1,968............ Sec. 250.171(e).
Suspension of Production (SOO/
SOP) Request.
(4) [Reserved]
(5) [Reserved]
(6) Deepwater Operations Plan... $3,336............ Sec. 250.292(p).
(7) [Reserved]
(8) Application for Permit to $1,959 for initial Sec. 250.410(d);
Drill (APD; Form BSEE-0123). applications Sec.
only; no fee for 250.513(b); Sec.
revisions. 250.515; Sec.
250.1605; Sec.
250.1617(a); Sec.
250.1622.
(9) Application for Permit to $116.............. Sec. 250.460;
Modify (APM; Form BSEE-0124). Sec.
250.513(b); Sec.
250.613(b);
250.1618(a); Sec.
250.1622; Sec.
250.1704(g).
(10) New Facility Production $5,030 A component Sec. 250.802(e).
Safety System Application for is a piece of
facility with more than 125 equipment or
components. ancillary system
that is protected
by one or more of
the safety
devices required
by API RP 14C (as
incorporated by
reference in Sec.
250.198);
$13,238
additional fee
will be charged
if BSEE deems it
necessary to
visit a facility
offshore, and
$6,884 to visit a
facility in a
shipyard.
(11) New Facility Production $1,218 Additional Sec. 250.802(e).
Safety System Application for fee of $8,313
facility with 25-125 components. will be charged
if BSEE deems it
necessary to
visit a facility
offshore, and
$4,766 to visit a
facility in a
shipyard.
(12) New Facility Production $604.............. Sec. 250.802(e).
Safety System Application for
facility with fewer than 25
components.
(13) Production Safety System $561.............. Sec. 250.802(e).
Application--Modification with
more than 125 components
reviewed.
(14) Production Safety System $201.............. Sec. 250.802(e).
Application--Modification with
25-125 components reviewed.
(15) Production Safety System $85............... Sec. 250.802(e).
Application--Modification with
fewer than 25 components
reviewed.
(16) Platform Application-- $21,075........... Sec. 250.905(l).
Installation--Under the
Platform Verification Program.
(17) Platform Application-- $3,018............ Sec. 250.905(l).
Installation--Fixed Structure
Under the Platform Approval
Program.
(18) Platform Application-- $1,536............ Sec. 250.905(l)
Installation--Caisson/Well
Protector.
(19) Platform Application-- $3,601............ Sec. 250.905(l).
Modification/Repair.
(20) New Pipeline Application $3,283............ Sec.
(Lease Term). 250.1000(b).
(21) Pipeline Application-- $1,906............ Sec.
Modification (Lease Term). 250.1000(b).
(22) Pipeline Application-- $3,865............ Sec.
Modification (ROW). 250.1000(b).
(23) Pipeline Repair $360.............. Sec.
Notification. 250.1008(e).
(24) Pipeline Right-of-Way (ROW) $2,569............ Sec.
Grant Application. 250.1015(a).
(25) Pipeline Conversion of $219.............. Sec.
Lease Term to ROW. 250.1015(a).
(26) Pipeline ROW Assignment.... $186.............. Sec.
250.1018(b).
(27) 500 Feet From Lease/Unit $3,608............ Sec.
Line Production Request. 250.1156(a).
(28) Gas Cap Production Request. $4,592............ Sec. 250.1157.
(29) Downhole Commingling $5,357............ Sec.
Request. 250.1158(a).
(30) Complex Surface Commingling $3,760............ Sec.
and Measurement Application. 250.1202(a); Sec.
250.1203(b);
Sec.
250.1204(a).
(31) Simple Surface Commingling $1,271............ Sec.
and Measurement Application. 250.1202(a); Sec.
250.1203(b);
Sec.
250.1204(a).
(32) Voluntary Unitization $11,698........... Sec.
Proposal or Unit Expansion. 250.1303(d).
(33) Unitization Revision....... $831.............. Sec.
250.1303(d).
(34) Application to Remove a $4,342............ Sec. 250.1727.
Platform or Other Facility.
(35) Application to Decommission $1,059............ Sec. 250.1751(a)
a Pipeline (Lease Term). or Sec.
250.1752(a).
(36) Application to Decommission $2,012............ Sec. 250.1751(a)
a Pipeline (ROW). or Sec.
250.1752(a).
------------------------------------------------------------------------
(b) Payment of the fees listed in paragraph (a) of this section
must accompany the submission of the document for approval or be sent
to an office identified by the Regional Director. Once a fee is paid,
it is nonrefundable, even if an application or other request is
withdrawn. If your application is returned to you as incomplete, you
are not required to submit a new fee when you submit the amended
application.
(c) Verbal approvals are occasionally given in special
circumstances. Any action that will be considered a verbal permit
approval requires either a paper permit application to follow the
verbal approval or an electronic application submittal within 72 hours.
Payment must be made with the completed paper or electronic
application.
[[Page 64498]]
Sec. 250.126 Electronic payment instructions.
You must file all payments electronically through Pay.gov. This
includes, but is not limited to, all OCS applications or filing fee
payments. The Pay.gov Web site may be accessed through a link on the
BSEE Offshore Web site at: http://www.bsee.gov/offshore/ homepage or
directly through Pay.gov at: https://www.pay.gov/paygov/.
(a) If you submitted an application through eWell, you must use the
interactive payment feature in that system, which directs you through
Pay.gov.
(b) For applications not submitted electronically through eWell,
you must use credit card or automated clearing house (ACH) payments
through the Pay.gov Web site, and you must include a copy of the
Pay.gov confirmation receipt page with your application.
Inspections of Operations
Sec. 250.130 Why does BSEE conduct inspections?
BSEE will inspect OCS facilities and any vessels engaged in
drilling or other downhole operations. These include facilities under
jurisdiction of other Federal agencies that we inspect by agreement. We
conduct these inspections:
(a) To verify that you are conducting operations according to the
Act, the regulations, the lease, right-of-way, the BOEM-approved
Exploration Plan or Development and Production Plans; or right-of-use
and easement, and other applicable laws and regulations; and
(b) To determine whether equipment designed to prevent or
ameliorate blowouts, fires, spillages, or other major accidents has
been installed and is operating properly according to the requirements
of this part.
Sec. 250.131 Will BSEE notify me before conducting an inspection?
BSEE conducts both scheduled and unscheduled inspections.
Sec. 250.132 What must I do when BSEE conducts an inspection?
(a) When BSEE conducts an inspection, you must provide:
(1) Access to all platforms, artificial islands, and other
installations on your leases or associated with your lease, right-of-
use and easement, or right-of-way; and
(2) Helicopter landing sites and refueling facilities for any
helicopters we use to regulate offshore operations.
(b) You must make the following available for us to inspect:
(1) The area covered under a lease, right-of-use and easement,
right-of-way, or permit;
(2) All improvements, structures, and fixtures on these areas; and
(3) All records of design, construction, operation, maintenance,
repairs, or investigations on or related to the area.
Sec. 250.133 Will BSEE reimburse me for my expenses related to
inspections?
Upon request, BSEE will reimburse you for food, quarters, and
transportation that you provide for BSEE representatives while they
inspect lease facilities and operations. You must send us your
reimbursement request within 90 days of the inspection.
Disqualification
Sec. 250.135 What will BSEE do if my operating performance is
unacceptable?
BSEE will determine if your operating performance is unacceptable.
BSEE will refer a determination of unacceptable performance to BOEM,
who may disapprove or revoke your designation as operator on a single
facility or multiple facilities. We will give you adequate notice and
opportunity for a review by BSEE officials before making a
determination that your operating performance is unacceptable.
Sec. 250.136 How will BSEE determine if my operating performance is
unacceptable?
In determining if your operating performance is unacceptable, BSEE
will consider, individually or collectively:
(a) Accidents and their nature;
(b) Pollution events, environmental damages and their nature;
(c) Incidents of noncompliance;
(d) Civil penalties;
(e) Failure to adhere to OCS lease obligations; or
(f) Any other relevant factors.
Special Types of Approvals
Sec. 250.140 When will I receive an oral approval?
When you apply for BSEE approval of any activity, we normally give
you a written decision. The following table shows circumstances under
which we may give an oral approval.
------------------------------------------------------------------------
When you . . . We may . . . And . . .
------------------------------------------------------------------------
(a) Request approval Give you an oral You must then confirm the
orally approval, oral request by sending
us a written request
within 72 hours.
(b) Request approval Give you an oral We will send you a
in writing, approval if quick written approval
action is needed, afterward. It will
include any conditions
that we place on the
oral approval.
(c) Request approval Give you an oral You don't have to follow
orally for gas approval, up with a written
flaring, request unless the
Regional Supervisor
requires it. When you
stop the approved
flaring, you must
promptly send a letter
summarizing the
location, dates and
hours, and volumes of
liquid hydrocarbons
produced and gas flared
by the approved flaring
(see 30 CFR 250, subpart
K).
------------------------------------------------------------------------
Sec. 250.141 May I ever use alternate procedures or equipment?
You may use alternate procedures or equipment after receiving
approval as described in this section.
(a) Any alternate procedures or equipment that you propose to use
must provide a level of safety and environmental protection that equals
or surpasses current BSEE requirements.
(b) You must receive the District Manager's or Regional
Supervisor's written approval before you can use alternate procedures
or equipment.
(c) To receive approval, you must either submit information or give
an oral presentation to the appropriate Regional Supervisor. Your
presentation must describe the site-specific application(s),
performance characteristics, and safety features of the proposed
procedure or equipment.
Sec. 250.142 How do I receive approval for departures?
We may approve departures to the operating requirements. You may
apply for a departure by writing to the District Manager or Regional
Supervisor.
Sec. 250.143 [Reserved]
Sec. 250.144 [Reserved]
Sec. 250.145 How do I designate an agent or a local agent?
(a) You or your designated operator may designate for the Regional
Supervisor's approval, or the Regional Director may require you to
designate an agent empowered to fulfill your
[[Page 64499]]
obligations under the Act, the lease, or the regulations in this part.
(b) You or your designated operator may designate for the Regional
Supervisor's approval a local agent empowered to receive notices and
submit requests, applications, notices, or supplemental information.
Sec. 250.146 Who is responsible for fulfilling leasehold obligations?
(a) When you are not the sole lessee, you and your co-lessee(s) are
jointly and severally responsible for fulfilling your obligations under
the provisions of 30 CFR parts 250 through 282 and 30 CFR parts 550
through 582 unless otherwise provided in these regulations.
(b) If your designated operator fails to fulfill any of your
obligations under 30 CFR parts 250 through 282 and 30 CFR parts 550
through 582, the Regional Supervisor may require you or any or all of
your co-lessees to fulfill those obligations or other operational
obligations under the Act, the lease, or the regulations.
(c) Whenever the regulations in 30 CFR parts 250 through 282 and 30
CFR parts 550 through 582 require the lessee to meet a requirement or
perform an action, the lessee, operator (if one has been designated),
and the person actually performing the activity to which the
requirement applies are jointly and severally responsible for complying
with the regulation.
Naming and Identifying Facilities and Wells (Does Not Include MODUs)
Sec. 250.150 How do I name facilities and wells in the Gulf of Mexico
Region?
(a) Assign each facility a letter designation except for those
types of facilities identified in paragraph (c)(1) of this section. For
example, A, B, CA, or CB.
(1) After a facility is installed, rename each predrilled well that
was assigned only a number and was suspended temporarily at the mudline
or at the surface. Use a letter and number designation. The letter used
must be the same as that of the production facility, and the number
used must correspond to the order in which the well was completed, not
necessarily the number assigned when it was drilled. For example, the
first well completed for production on Facility A would be renamed Well
A-1, the second would be Well A-2, and so on; and
(2) When you have more than one facility on a block, each facility
installed, and not bridge-connected to another facility, must be named
using a different letter in sequential order. For example, EC 222A, EC
222B, EC 222C.
(3) When you have more than one facility on multiple blocks in a
local area being co-developed, each facility installed and not
connected with a walkway to another facility should be named using a
different letter in sequential order with the block number
corresponding to the block on which the platform is located. For
example, EC 221A, EC 222B, and EC 223C.
(b) In naming multiple well caissons, you must assign a letter
designation.
(c) In naming single well caissons, you must use certain criteria
as follows:
(1) For single well caissons not attached to a facility with a
walkway, use the well designation. For example, Well No. 1;
(2) For single well caissons attached to a facility with a walkway,
use the same designation as the facility. For example, rename Well
No.10 as A-10; and
(3) For single well caissons with production equipment, use a
letter designation for the facility name and a letter plus number
designation for the well. For example, the Well No. 1 caisson would be
designated as Facility A, and the well would be Well A-1.
Sec. 250.151 How do I name facilities in the Pacific Region?
The operator assigns a name to the facility.
Sec. 250.152 How do I name facilities in the Alaska Region?
Facilities will be named and identified according to the Regional
Director's directions.
Sec. 250.153 Do I have to rename an existing facility or well?
You do not have to rename facilities installed and wells drilled
before January 27, 2000, unless the Regional Director requires it.
Sec. 250.154 What identification signs must I display?
(a) You must identify all facilities, artificial islands, and
mobile offshore drilling units with a sign maintained in a legible
condition.
(1) You must display an identification sign that can be viewed from
the waterline on at least one side of the platform. The sign must use
at least 3-inch letters and figures.
(2) When helicopter landing facilities are present, you must
display an additional identification sign that is visible from the air.
The sign must use at least 12-inch letters and figures and must also
display the weight capacity of the helipad unless noted on the top of
the helipad. If this sign is visible to both helicopter and boat
traffic, then the sign in paragraph (a)(1) of this section is not
required.
(3) Your identification sign must:
(i) List the name of the lessee or designated operator;
(ii) In the GOM OCS Region, list the area designation or
abbreviation and the block number of the facility location as depicted
on OCS Official Protraction Diagrams or leasing maps;
(iii) In the Pacific OCS Region, list the lease number on which the
facility is located; and
(iv) List the name of the platform, structure, artificial island,
or mobile offshore drilling unit.
(b) You must identify singly completed wells and multiple
completions as follows:
(1) For each singly completed well, list the lease number and well
number on the wellhead or on a sign affixed to the wellhead;
(2) For wells with multiple completions, downhole splitter wells,
and multilateral wells, identify each completion in addition to the
well name and lease number individually on the well flowline at the
wellhead; and
(3) For subsea wells that flow individually into separate
pipelines, affix the required sign on the pipeline or surface flowline
dedicated to that subsea well at a convenient location on the receiving
platform. For multiple subsea wells that flow into a common pipeline or
pipelines, no sign is required.
Sec. 250.160-250.167 [Reserved]
Suspensions
Sec. 250.168 May operations or production be suspended?
(a) You may request approval of a suspension, or the Regional
Supervisor may direct a suspension (Directed Suspension), for all or
any part of a lease or unit area.
(b) Depending on the nature of the suspended activity, suspensions
are labeled either Suspensions of Operations (SOO) or Suspensions of
Production (SOP).
Sec. 250.169 What effect does suspension have on my lease?
(a) A suspension may extend the term of a lease (see Sec.
250.180(b), (d), and (e)). The extension is equal to the length of time
the suspension is in effect, except as provided in paragraph (b) of
this section.
(b) A Directed Suspension does not extend the term of a lease when
the Regional Supervisor directs a suspension because of:
(1) Gross negligence; or
[[Page 64500]]
(2) A willful violation of a provision of the lease or governing
statutes and regulations.
Sec. 250.170 How long does a suspension last?
(a) BSEE may issue suspensions for up to 5 years per suspension.
The Regional Supervisor will set the length of the suspension based on
the conditions of the individual case involved. BSEE may grant
consecutive suspension periods.
(b) An SOO ends automatically when the suspended operation
commences.
(c) An SOP ends automatically when production begins.
(d) A Directed Suspension normally ends as specified in the letter
directing the suspension.
(e) BSEE may terminate any suspension when the Regional Supervisor
determines the circumstances that justified the suspension no longer
exist or that other lease conditions warrant termination. The Regional
Supervisor will notify you of the reasons for termination and the
effective date.
Sec. 250.171 How do I request a suspension?
You must submit your request for a suspension to the Regional
Supervisor, and BSEE must receive the request before the end of the
lease term (i.e., end of primary term, end of the 180-day period
following the last leaseholding operation, and end of a current
suspension). Your request must include:
(a) The justification for the suspension including the length of
suspension requested;
(b) A reasonable schedule of work leading to the commencement or
restoration of the suspended activity;
(c) A statement that a well has been drilled on the lease and
determined to be producible according to Sec. 250.1603 (SOP only), 30
CFR 550.115, or 30 CFR 550.116;
(d) A commitment to production (SOP only); and
(e) The service fee listed in Sec. 250.125 of this subpart.
Sec. 250.172 When may the Regional Supervisor grant or direct an SOO
or SOP?
The Regional Supervisor may grant or direct an SOO or SOP under any
of the following circumstances:
(a) When necessary to comply with judicial decrees prohibiting any
activities or the permitting of those activities. The effective date of
the suspension will be the effective date required by the action of the
court;
(b) When activities pose a threat of serious, irreparable, or
immediate harm or damage. This would include a threat to life
(including fish and other aquatic life), property, any mineral deposit,
or the marine, coastal, or human environment. BSEE may require you to
do a site-specific study (see Sec. 250.177(a)).
(c) When necessary for the installation of safety or environmental
protection equipment;
(d) When necessary to carry out the requirements of NEPA or to
conduct an environmental analysis; or
(e) When necessary to allow for inordinate delays encountered in
obtaining required permits or consents, including administrative or
judicial challenges or appeals.
Sec. 250.173 When may the Regional Supervisor direct an SOO or SOP?
The Regional Supervisor may direct a suspension when:
(a) You failed to comply with an applicable law, regulation, order,
or provision of a lease or permit; or
(b) The suspension is in the interest of National security or
defense.
Sec. 250.174 When may the Regional Supervisor grant or direct an SOP?
The Regional Supervisor may grant or direct an SOP when the
suspension is in the National interest, and it is necessary because the
suspension will meet one of the following criteria:
(a) It will allow you to properly develop a lease, including time
to construct and install production facilities;
(b) It will allow you time to obtain adequate transportation
facilities;
(c) It will allow you time to enter a sales contract for oil, gas,
or sulphur. You must show that you are making an effort to enter into
the contract(s); or
(d) It will avoid continued operations that would result in
premature abandonment of a producing well(s).
Sec. 250.175 When may the Regional Supervisor grant an SOO?
(a) The Regional Supervisor may grant an SOO when necessary to
allow you time to begin drilling or other operations when you are
prevented by reasons beyond your control, such as unexpected weather,
unavoidable accidents, or drilling rig delays.
(b) The Regional Supervisor may grant an SOO when all of the
following conditions are met:
(1) The lease was issued with a primary lease term of 5 years, or
with a primary term of 8 years with a requirement to drill within 5
years;
(2) Before the end of the third year of the primary term, you or
your predecessor in interest must have acquired and interpreted
geophysical information that indicates:
(i) The presence of a salt sheet;
(ii) That all or a portion of a potential hydrocarbon-bearing
formation may lie beneath or adjacent to the salt sheet; and
(iii) The salt sheet interferes with identification of the
potential hydrocarbon-bearing formation.
(3) The interpreted geophysical information required under
paragraph (b)(2) of this section must include full 3-D depth migration
beneath the salt sheet and over the entire lease area.
(4) Before requesting the suspension, you have conducted or are
conducting additional data processing or interpretation of the
geophysical information with the objective of identifying a potential
hydrocarbon-bearing formation.
(5) You demonstrate that additional time is necessary to:
(i) Complete current processing or interpretation of existing
geophysical data or information;
(ii) Acquire, process, or interpret new geophysical data or
information; or
(iii) Drill into the potential hydrocarbon-bearing formation
identified as a result of the activities conducted in paragraphs
(b)(2), (b)(4), and (b)(5) of this section.
(c) The Regional Supervisor may grant an SOO to conduct additional
geological and geophysical data analysis that may lead to the drilling
of a well below 25,000 feet true vertical depth below the datum at mean
sea level (TVD SS) when all of the following conditions are met:
(1) The lease was issued with a primary lease term of:
(i) Five years; or
(ii) Eight years with a requirement to drill within 5 years.
(2) Before the end of the fifth year of the primary term, you or
your predecessor in interest must have acquired and interpreted
geophysical information that:
(i) Indicates that all or a portion of a potential hydrocarbon-
bearing formation lies below 25,000 feet TVD SS; and
(ii) Includes full 3-D depth migration over the entire lease area.
(3) Before requesting the suspension, you have conducted or are
conducting additional data processing or interpretation of the
geophysical information with the objective of identifying a potential
hydrocarbon-bearing geologic structure or stratigraphic trap lying
below 25,000 feet TVD SS.
(4) You demonstrate that additional time is necessary to:
(i) Complete current processing or interpretation of existing
geophysical data or information;
(ii) Acquire, process, or interpret new geophysical or geological
data or
[[Page 64501]]
information that would affect the decision to drill the same geologic
structure or stratigraphic trap, as determined by the Regional
Supervisor, identified in paragraphs (c)(2) and (c)(3) of this section;
or
(iii) Drill a well below 25,000 feet TVD SS into the geologic
structure or stratigraphic trap identified as a result of the
activities conducted in paragraphs (c)(2), (c)(3), and (c)(4)(i) and
(ii) of this section.
Sec. 250.176 Does a suspension affect my royalty payment?
A directed suspension may affect the payment of rental or royalties
for the lease as provided in 30 CFR 1218.154.
Sec. 250.177 What additional requirements may the Regional Supervisor
order for a suspension?
If BSEE grants or directs a suspension under paragraph Sec.
250.172(b), the Regional Supervisor may require you to:
(a) Conduct a site-specific study.
(1) The Regional Supervisor must approve or prescribe the scope for
any site-specific study that you perform.
(2) The study must evaluate the cause of the hazard, the potential
damage, and the available mitigation measures.
(3) You must pay for the study unless you request, and the Regional
Supervisor agrees to arrange, payment by another party.
(4) You must furnish copies and results of the study to the
Regional Supervisor.
(5) BSEE will make the results available to other interested
parties and to the public.
(6) The Regional Supervisor will use the results of the study and
any other information that becomes available:
(i) To decide if the suspension can be lifted; and
(ii) To determine any actions that you must take to mitigate or
avoid any damage to the environment, life, or property.
(b) Submit a revised Exploration Plan (including any required
mitigating measures);
(c) Submit a revised Development and Production Plan (including any
required mitigating measures); or
(d) Submit a revised Development Operations Coordination Document
according to 30 CFR part 550, subpart B.
Primary Lease Requirements, Lease Term Extensions, and Lease
Cancellations
Sec. 250.180 What am I required to do to keep my lease term in
effect?
(a) If your lease is in its primary term:
(1) You must submit a report to the District Manager according to
paragraphs (h) and (i) of this section whenever production begins
initially, whenever production ceases during the last 180 days of the
primary term, and whenever production resumes during the last 180 days
of the primary term.
(2) Your lease expires at the end of its primary term unless you
are conducting operations on your lease (see 30 CFR part 556). For
purposes of this section, the term operations means, drilling, well-
reworking, or production in paying quantities. The objective of the
drilling or well-reworking must be to establish production in paying
quantities on the lease.
(b) If you stop conducting operations during the last 180 days of
your primary lease term, your lease will expire unless you either
resume operations or receive an SOO or an SOP from the Regional
Supervisor under Sec. Sec. 250.172, 250.173, 250.174, or 250.175
before the end of the 180th day after you stop operations.
(c) If you extend your lease term under paragraph (b) of this
section, you must pay rental or minimum royalty, as appropriate, for
each year or part of the year during which your lease continues in
force beyond the end of the primary lease term.
(d) If you stop conducting operations on a lease that has continued
beyond its primary term, your lease will expire unless you resume
operations or receive an SOO or an SOP from the Regional Supervisor
under Sec. 250.172, 250.173, 250.174, or 250.175 before the end of the
180th day after you stop operations.
(e) You may ask the Regional Supervisor to allow you more than 180
days to resume operations on a lease continued beyond its primary term
when operating conditions warrant. The request must be in writing and
explain the operating conditions that warrant a longer period. In
allowing additional time, the Regional Supervisor must determine that
the longer period is in the National interest, and it conserves
resources, prevents waste, or protects correlative rights.
(f) When you begin conducting operations on a lease that has
continued beyond its primary term, you must immediately notify the
District Manager either orally or by fax or e-mail and follow up with a
written report according to paragraph (g) of this section.
(g) If your lease is continued beyond its primary term, you must
submit a report to the District Manager under paragraphs (h) and (i) of
this section whenever production begins initially, whenever production
ceases, whenever production resumes before the end of the 180-day
period after having ceased, or whenever drilling or well-reworking
operations begin before the end of the 180-day period.
(h) The reports required by paragraphs (a) and (g) of this section
must contain:
(1) Name of lessee or operator;
(2) The well number, lease number, area, and block;
(3) As appropriate, the unit agreement name and number; and
(4) A description of the operation and pertinent dates.
(i) You must submit the reports required by paragraphs (a) and (g)
of this section within the following timeframes:
(1) Initialization of production--within 5 days of initial
production.
(2) Cessation of production--within 15 days after the first full
month of zero production.
(3) Resumption of production--within 5 days of resuming production
after ceasing production under paragraph (i)(2) of this section.
(4) Drilling or well reworking operations--within 5 days of
beginning and completing the leaseholding operations.
(j) For leases continued beyond the primary term, you must
immediately report to the District Manager if operations do not begin
before the end of the 180-day period.
Sec. Sec. 250.181-250.185 [Reserved]
Information and Reporting Requirements
Sec. 250.186 What reporting information and report forms must I
submit?
(a) You must submit information and reports as BSEE requires.
(1) You may obtain copies of forms from, and submit completed forms
to, the District Manager or Regional Supervisor.
(2) Instead of paper copies of forms available from the District
Manager or Regional Supervisor, you may use your own computer-generated
forms that are equal in size to BSEE's forms. You must arrange the data
on your form identical to the BSEE form. If you generate your own form
and it omits terms and conditions contained on the official BSEE form,
we will consider it to contain the omitted terms and conditions.
(3) You may submit digital data when the Region/District is
equipped to accept it.
(b) When BSEE specifies, you must include, for public information,
an additional copy of such reports.
(1) You must mark it Public Information
(2) You must include all required information, except information
exempt from public disclosure under Sec. 250.197
[[Page 64502]]
or otherwise exempt from public disclosure under law or regulation.
Sec. 250.187 What are BSEE's incident reporting requirements?
(a) You must report all incidents listed in Sec. 250.188(a) and
(b) to the District Manager. The specific reporting requirements for
these incidents are contained in Sec. Sec. 250.189 and 250.190.
(b) These reporting requirements apply to incidents that occur on
the area covered by your lease, right-of-use and easement, pipeline
right-of-way, or other permit issued by BOEM or BSEE, and that are
related to operations resulting from the exercise of your rights under
your lease, right-of-use and easement, pipeline right-of-way, or
permit.
(c) Nothing in this subpart relieves you from making notifications
and reports of incidents that may be required by other regulatory
agencies.
(d) You must report all spills of oil or other liquid pollutants in
accordance with 30 CFR 254.46.
Sec. 250.188 What incidents must I report to BSEE and when must I
report them?
(a) You must report the following incidents to the District Manager
immediately via oral communication, and provide a written follow-up
report (hard copy or electronically transmitted) within 15 calendar
days after the incident:
(1) All fatalities.
(2) All injuries that require the evacuation of the injured
person(s) from the facility to shore or to another offshore facility.
(3) All losses of well control. ``Loss of well control'' means:
(i) Uncontrolled flow of formation or other fluids. The flow may be
to an exposed formation (an underground blowout) or at the surface (a
surface blowout);
(ii) Flow through a diverter; or
(iii) Uncontrolled flow resulting from a failure of surface
equipment or procedures.
(4) All fires and explosions.
(5) All reportable releases of hydrogen sulfide (H2S)
gas, as defined in Sec. 250.490(l).
(6) All collisions that result in property or equipment damage
greater than $25,000. ``Collision'' means the act of a moving vessel
(including an aircraft) striking another vessel, or striking a
stationary vessel or object (e.g., a boat striking a drilling rig or
platform). ``Property or equipment damage'' means the cost of labor and
material to restore all affected items to their condition before the
damage, including, but not limited to, the OCS facility, a vessel,
helicopter, or equipment. It does not include the cost of salvage,
cleaning, gas-freeing, dry docking, or demurrage.
(7) All incidents involving structural damage to an OCS facility.
``Structural damage'' means damage severe enough so that operations on
the facility cannot continue until repairs are made.
(8) All incidents involving crane or personnel/material handling
operations.
(9) All incidents that damage or disable safety systems or
equipment (including firefighting systems).
(b) You must provide a written report of the following incidents to
the District Manager within 15 calendar days after the incident:
(1) Any injuries that result in one or more days away from work or
one or more days on restricted work or job transfer. One or more days
means the injured person was not able to return to work or to all of
their normal duties the day after the injury occurred;
(2) All gas releases that initiate equipment or process shutdown;
(3) All incidents that require operations personnel on the facility
to muster for evacuation for reasons not related to weather or drills;
(4) All other incidents, not listed in paragraph (a) of this
section, resulting in property or equipment damage greater than
$25,000.
Sec. 250.189 Reporting requirements for incidents requiring immediate
notification.
For an incident requiring immediate notification under Sec.
250.188(a), you must notify the District Manager via oral communication
immediately after aiding the injured and stabilizing the situation.
Your oral communication must provide the following information:
(a) Date and time of occurrence;
(b) Operator, and operator representative's, name and telephone
number;
(c) Contractor, and contractor representative's name and telephone
number (if a contractor is involved in the incident or injury/
fatality);
(d) Lease number, OCS area, and block;
(e) Platform/facility name and number, or pipeline segment number;
(f) Type of incident or injury/fatality;
(g) Operation or activity at time of incident (i.e., drilling,
production, workover, completion, pipeline, crane, etc.); and
(h) Description of the incident, damage, or injury/fatality.
Sec. 250.190 Reporting requirements for incidents requiring written
notification.
(a) For any incident covered under Sec. 250.188, you must submit a
written report within 15 calendar days after the incident to the
District Manager. The report must contain the following information:
(1) Date and time of occurrence;
(2) Operator, and operator representative's name and telephone
number;
(3) Contractor, and contractor representative's name and telephone
number (if a contractor is involved in the incident or injury);
(4) Lease number, OCS area, and block;
(5) Platform/facility name and number, or pipeline segment number;
(6) Type of incident or injury;
(7) Operation or activity at time of incident (i.e., drilling,
production, workover, completion, pipeline, crane etc.);
(8) Description of incident, damage, or injury (including days away
from work, restricted work or job transfer), and any corrective action
taken; and
(9) Property or equipment damage estimate (in U.S. dollars).
(b) You may submit a report or form prepared for another agency in
lieu of the written report required by paragraph (a) of this section,
provided the report or form contains all required information.
(c) The District Manager may require you to submit additional
information about an incident on a case-by-case basis.
Sec. 250.191 How does BSEE conduct incident investigations?
Any investigation that BSEE conducts under the authority of
sections 22(d)(1) and (2) of the Act (43 U.S.C. 1348(d)(1) and (2)) is
a fact-finding proceeding with no adverse parties. The purpose of the
investigation is to prepare a public report that determines the cause
or causes of the incident. The investigation may involve panel meetings
conducted by a chairperson appointed by BSEE. The following
requirements apply to any panel meetings involving persons giving
testimony:
(a) A person giving testimony may have legal or other
representative(s) present to provide advice or counsel while the person
is giving testimony. The chairperson may require a verbatim transcript
to be made of all oral testimony. The chairperson also may accept a
sworn written statement in lieu of oral testimony.
(b) Only panel members, and any experts the panel deems necessary,
may address questions to any person giving testimony.
(c) The chairperson may issue subpoenas to persons to appear and
provide testimony or documents at a
[[Page 64503]]
panel meeting. A subpoena may not require a person to attend a panel
meeting held at a location more than 100 miles from where a subpoena is
served.
(d) Any person giving testimony may request compensation for
mileage, and fees for services, within 90 days after the panel meeting.
The compensated expenses must be similar to mileage and fees the U.S.
District Courts allow.
Sec. 250.192 What reports and statistics must I submit relating to a
hurricane, earthquake, or other natural occurrence?
(a) You must submit evacuation statistics to the Regional
Supervisor for a natural occurrence, such as a hurricane, a tropical
storm, or an earthquake. Statistics include facilities and rigs
evacuated and the amount of production shut-in for gas and oil. You
must:
(1) Submit the statistics by fax or e-mail (for activities in the
BSEE GOM OCS Region, use Form BSEE-0132) as soon as possible when
evacuation occurs. In lieu of submitting your statistics by fax or e-
mail, you may submit them electronically in accordance with 30 CFR
250.186(a)(3);
(2) Submit the statistics on a daily basis by 11 a.m., as
conditions allow, during the period of shut-in and evacuation;
(3) Inform BSEE when you resume production; and
(4) Submit the statistics either by BSEE district, or the total
figures for your operations in a BSEE region.
(b) If your facility, production equipment, or pipeline is damaged
by a natural occurrence, you must:
(1) Submit an initial damage report to the Regional Supervisor
within 48 hours after you complete your initial evaluation of the
damage. You must use Form BSEE-0143, Facility/Equipment Damage Report,
to make this and all subsequent reports. In lieu of submitting Form
BSEE-0143 by fax or e-mail, you may submit the damage report
electronically in accordance with 30 CFR 250.186(a)(3). In the report,
you must:
(i) Name the items damaged (e.g., platform or other structure,
production equipment, pipeline);
(ii) Describe the damage and assess the extent of the damage
(major, medium, minor); and
(iii) Estimate the time it will take to replace or repair each
damaged structure and piece of equipment and return it to service. The
initial estimate need not be provided on the form until availability of
hardware and repair capability has been established (not to exceed 30
days from your initial report).
(2) Submit subsequent reports monthly and immediately whenever
information submitted in previous reports changes until the damaged
structure or equipment is returned to service. In the final report, you
must provide the date the item was returned to service.
Sec. 250.193 Reports and investigations of apparent violations.
Any person may report to BSEE an apparent violation or failure to
comply with any provision of the Act, any provision of a lease,
license, or permit issued under the Act, or any provision of any
regulation or order issued under the Act. When BSEE receives a report
of an apparent violation, or when a BSEE employee detects an apparent
violation after making an initial determination of the validity, BSEE
will investigate according to BSEE procedures.
Sec. 250.194 How must I protect archaeological resources?
(a) [Reserved]
(b) [Reserved]
(c) If you discover any archaeological resource while conducting
operations in the lease or right-of-way area, you must immediately halt
operations within the area of the discovery and report the discovery to
the BSEE Regional Director. If investigations determine that the
resource is significant, the Regional Director will tell you how to
protect it.
Sec. 250.195 What notification does BSEE require on the production
status of wells?
You must notify the appropriate BSEE District Manager when you
successfully complete or recomplete a well for production. You must:
(a) Notify the District Manager within 5 working days of placing
the well in a production status. You must confirm oral notification by
telefax or e-mail within those 5 working days.
(b) Provide the following information in your notification:
(1) Lessee or operator name;
(2) Well number, lease number, and OCS area and block designations;
(3) Date you placed the well on production (indicate whether or not
this is first production on the lease);
(4) Type of production; and
(5) Measured depth of the production interval.
Sec. 250.196 Reimbursements for reproduction and processing costs.
(a) BSEE will reimburse you for costs of reproducing data and
information that the Regional Director requests if:
(1) You deliver geophysical and geological (G&G) data and
information to BSEE for the Regional Director to inspect or select and
retain;
(2) BSEE receives your request for reimbursement and the Regional
Director determines that the requested reimbursement is proper; and
(3) The cost is at your lowest rate or at the lowest commercial
rate established in the area, whichever is less.
(b) BSEE will reimburse you for the costs of processing geophysical
information (that does not include cost of data acquisition):
(1) If, at the request of the Regional Director, you processed the
geophysical data or information in a form or manner other than that
used in the normal conduct of business; or
(2) If you collected the information under a permit that BSEE
issued to you before October 1, 1985, and the Regional Director
requests and retains the information.
(c) When you request reimbursement, you must identify reproduction
and processing costs separately from acquisition costs.
(d) BSEE will not reimburse you for data acquisition costs or for
the costs of analyzing or processing geological information or
interpreting geological or geophysical information.
Sec. 250.197 Data and information to be made available to the public
or for limited inspection.
BSEE will protect data and information that you submit under this
part, and 30 CFR part 203, as described in this section. Paragraphs (a)
and (b) of this section describe what data and information will be made
available to the public without the consent of the lessee, under what
circumstances, and in what time period. Paragraph (c) of this section
describes what data and information will be made available for limited
inspection without the consent of the lessee, and under what
circumstances.
(a) All data and information you submit on BSEE forms will be made
available to the public upon submission, except as specified in the
following table:
[[Page 64504]]
------------------------------------------------------------------------
Data and information
not immediately Excepted data will
On form . . . available are . . . be made available .
. .
------------------------------------------------------------------------
(1) BSEE-0123, Application Items 15, 16, 22 When the well goes
for Permit to Drill, through 25, on production or
according to the
table in paragraph
(b) of this
section, whichever
is earlier.
(2) BSEE-0123S, Supplemental Items 3, 7, 8, 15 When the well goes
APD Information Sheet, and 17, on production or
according to the
table in paragraph
(b) of this
section, whichever
is earlier.
(3) BSEE-0124, Application Item 17, When the well goes
for Permit to Modify, on production or
according to the
table in paragraph
(b) of this
section, whichever
is earlier.
(4) BSEE-0125, End of Items 12, 13, 17, When the well goes
Operations Report, 21, 22, 26 through on production or
38, according to the
table in paragraph
(b) of this
section, whichever
is earlier.
However, items 33
through 38 will not
be released when
the well goes on
production unless
the period of time
in the table in
paragraph (b) has
expired.
(5) BSEE-0126, Well Item 101, 2 years after you
Potential Test Report, submit it.
(6) [Reserved]
(7) BSEE-0133 Well Activity Item 10 Fields When the well goes
Report, [WELLBORE START on production or
DATE, TD DATE, OP according to the
STATUS, END DATE, table in paragraph
MD, TVD, AND MW (b) of this
PPG]. Item 11 section, whichever
Fields [WELLBORE is earlier.
START DATE, TD
DATE, PLUGBACK
DATE, FINAL MD, AND
FINAL TVD] and
Items 12 through
15,
(8) BSEE-0133S Open Hole Boxes 7 and 8, When the well goes
Data Report, on production or
according to the
table in paragraph
(b) of this
section, whichever
is earlier.
(9) [Reserved]
(10) [Reserved]
------------------------------------------------------------------------
(b) BSEE will release lease and permit data and information that
you submit and BSEE retains, but that are not normally submitted on
BSEE forms, according to the following table:
------------------------------------------------------------------------
Special
If . . . BSEE will release At this time . . provisions . .
. . . . .
------------------------------------------------------------------------
(1) The Director Geophysical data, At any time, BSEE will
determines that Geological data release data
data and Interpreted G&G and
information are information, information
needed for Processed G&G only if
specific information, release would
scientific or Analyzed further the
research geological National
purposes for the information, interest
Government, without unduly
damaging the
competitive
position of
the lessee.
(2) Data or Geophysical data, 60 days after BSEE will
information is Geological data, BSEE receives release the
collected with Interpreted G&G the data or data and
high-resolution information, information, if information
systems (e.g., Processed the Regional earlier than
bathymetry, side- geological Supervisor deems 60 days if the
scan sonar, information, it necessary, Regional
subbottom Analyzed Supervisor
profiler, and geological determines it
magnetometer) to information, is needed by
comply with affected
safety or States to make
environmental decisions
protection under 30 CFR
requirements, 550, subpart
B. The
Regional
Supervisor
will
reconsider
earlier
release if you
satisfy him/
her that it
would unduly
damage your
competitive
position.
(3) Your lease is Geophysical data, When your lease This release
no longer in Geological data, terminates, time applies
effect, Processed G&G only if the
information provisions in
Interpreted G&G this table
information, governing high-
Analyzed resolution
geological systems and
information, the provisions
in 30 CFR
552.7 do not
apply. The
release time
applies to the
geophysical
data and
information
only if
acquired
postlease for
a lessee's
exclusive use.
[[Page 64505]]
(4) Your lease is Geophysical data, 10 years after This release
still in effect, Processed you submit the time applies
geophysical data and only if the
information, information, provisions in
Interpreted G&G this table
information, governing high-
resolution
systems and
the provisions
in 30 CFR
552.7 do not
apply. This
release time
applies to the
geophysical
data and
information
only if
acquired
postlease for
a lessee's
exclusive use.
(5) Your lease is Geological data, 2 years after the These release
still in effect Analyzed required times apply
and within the geological submittal date only if the
primary term information, or 60 days after provisions in
specified in the a lease sale if this table
lease, any portion of governing high-
an offered lease resolution
is within 50 systems and
miles of a well, the provisions
whichever is in 30 CFR
later, 552.7 do not
apply. If the
primary term
specified in
the lease is
extended under
the heading of
``Suspensions'
' in this
subpart, the
extension
applies to
this
provision.
(6) Your lease is Geological data, 2 years after the None.
in effect and Analyzed required
beyond the geological submittal date,
primary term information,
specified in the
lease,
(7) Data or Descriptions of When the well Directional
information is downhole goes on survey data
submitted on locations, production or may be
well operations, operations, and when geological released
equipment, data is released earlier to the
according to owner of an
Sec. Sec. adjacent lease
250.197(b)(5) according to
and (b)(6), Subpart D of
whichever occurs this part.
earlier,
(8) Data and Any data or At any time, None.
information are information
obtained from obtained,
beneath unleased
land as a result
of a well
deviation that
has not been
approved by the
District Manager
or Regional
Supervisor,
(9) Except for G&G data, Geological data None.
high-resolution analyzed and information:
data and geological 10 years after
information information, BOEM issues the
released under processed and permit;
paragraph (b)(2) interpreted G&G Geophysical
of this section information, data: 50 years
data and after BOEM
information issues the
acquired by a permit;
permit under 30 Geophysical
CFR part 551 are information: 25
submitted by a years after BOEM
lessee under 30 issues the
CFR part 203, 30 permit,
CFR part 250, or
30 CFR part 550,
------------------------------------------------------------------------
(c) BSEE may allow limited inspection, but only by persons with a
direct interest in related BSEE decisions and issues in specific
geographic areas, and who agree in writing to its confidentiality, of
G&G data and information submitted under this part or 30 CFR part 203
that BSEE uses to:
(1) Make unitization determinations on two or more leases;
(2) Make competitive reservoir determinations;
(3) Ensure proper plans of development for competitive reservoirs;
(4) Promote operational safety;
(5) Protect the environment;
(6) [Reserved]; or
(7) Determine eligibility for royalty relief.
References
Sec. 250.198 Documents incorporated by reference.
(a) The BSEE is incorporating by reference the documents listed in
paragraphs (e) through (k) of this section. Paragraphs (e) through (k)
identify the publishing organization of the documents, the address and
phone number where you may obtain these documents, and the documents
incorporated by reference. The Director of the Federal Register has
approved the incorporations by reference according to 5 U.S.C. 552(a)
and 1 CFR part 51.
(1) Incorporation by reference of a document is limited to the
edition of the publication that is cited in this section. Future
amendments or revisions of the document are not included. The BSEE will
publish any changes to a document in the Federal Register and amend
this section.
(2) The BSEE may make the rule amending the document effective
without prior opportunity for public comment when BSEE determines:
(i) That the revisions to a document result in safety improvements
or represent new industry standard technology and do not impose undue
costs on the affected parties; and
(ii) The BSEE meets the requirements for making a rule immediately
effective under 5 U.S.C. 553.
(3) The effect of incorporation by reference of a document into the
regulations in this part is that the incorporated document is a
requirement. When a section in this part incorporates all of a
document, you are responsible for complying with the provisions of that
entire document, except to the extent that section provides otherwise.
When a section in this part incorporates part of a document, you are
responsible for complying with that part of the document as provided in
that section. If any incorporated document uses the word should, it
means must for purposes of these regulations.
(b) The BSEE incorporated each document or specific portion by
reference in the sections noted. The entire document is incorporated by
reference, unless the text of the corresponding sections in this part
calls for compliance with specific portions of
[[Page 64506]]
the listed documents. In each instance, the applicable document is the
specific edition or specific edition and supplement or addendum cited
in this section.
(c) Under Sec. Sec. 250.141 and 250.142, you may comply with a
later edition of a specific document incorporated by reference,
provided:
(1) You show that complying with the later edition provides a
degree of protection, safety, or performance equal to or better than
would be achieved by compliance with the listed edition; and
(2) You obtain the prior written approval for alternative
compliance from the authorized BSEE official.
(d) You may inspect these documents at the Bureau of Safety and
Environmental Enforcement, 381 Elden Street, Room 3313, Herndon,
Virginia 20170; phone: 703-787-1587; or at the National Archives and
Records Administration (NARA). For information on the availability of
this material at NARA, call 202-741-6030, or go to: http://www.archives.gov/federal_register/code_of_federal_regulations/ibr_locations.htm.
(e) American Concrete Institute (ACI), ACI Standards, P. O. Box
9094, Farmington Hill, MI 48333-9094: http://www.concrete.org; phone:
248-848-3700:
(1) ACI Standard 318-95, Building Code Requirements for Reinforced
Concrete (ACI 318-95), incorporated by reference at Sec. 250.901.
(2) ACI 318R-95, Commentary on Building Code Requirements for
Reinforced Concrete, incorporated by reference at Sec. 250.901.
(3) ACI 357R-84, Guide for the Design and Construction of Fixed
Offshore Concrete Structures, 1984; reapproved 1997, incorporated by
reference at Sec. 250.901.
(f) American Institute of Steel Construction, Inc. (AISC), AISC
Standards, One East Wacker Drive, Suite 700, Chicago, IL 60601-1802;
http://www.aisc.org; phone: 312-670-2400:
(1) ANSI/AISC 360-05, Specification for Structural Steel Buildings
incorporated by reference at Sec. 250.901.
(2) [Reserved]
(g) American National Standards Institute (ANSI), ANSI/ASME Codes,
ATTN: Sales Department, 25 West 43rd Street, 4th Floor, New York, NY
10036; http://www.ansi.org; phone: 212-642-4900; and/or American
Society of Mechanical Engineers (ASME), 22 Law Drive, P.O. Box 2900,
Fairfield, NJ 07007-2900; http://www.asme.org; phone: 973-882-5155:
(1) ANSI/ASME Boiler and Pressure Vessel Code, Section I, Rules for
Construction of Power Boilers; including Appendices, 2004 Edition; and
July 1, 2005 Addenda, and all Section I Interpretations Volume 55,
incorporated by reference at Sec. 250.803 and Sec. 250.1629;
(2) ANSI/ASME Boiler and Pressure Vessel Code, Section IV, Rules
for Construction of Heating Boilers; including Appendices 1, 2, 3, 5,
6, and Non-mandatory Appendices B, C, D, E, F, H, I, K, L, and M, and
the Guide to Manufacturers Data Report Forms, 2004 Edition; July 1,
2005 Addenda, and all Section IV Interpretations Volume 55,
incorporated by reference at Sec. Sec. 250.803 and 250.1629;
(3) ANSI/ASME Boiler and Pressure Vessel Code, Section VIII, Rules
for Construction of Pressure Vessels; Divisions 1 and 2, 2004 Edition;
July 1, 2005 Addenda, Divisions 1 and 2, and all Section VIII
Interpretations Volumes 54 and 55, incorporated by reference at
Sec. Sec. 250.803 and 250.1629;
(4) ANSI/ASME B 16.5-2003, Pipe Flanges and Flanged Fittings
incorporated by reference at Sec. 250.1002;
(5) ANSI/ASME B 31.8-2003, Gas Transmission and Distribution Piping
Systems incorporated by reference at Sec. 250.1002;
(6) ANSI/ASME SPPE-1-1994, Quality Assurance and Certification of
Safety and Pollution Prevention Equipment Used in Offshore Oil and Gas
Operations, incorporated by reference at Sec. 250.806;
(7) ANSI/ASME SPPE-1d-1996 Addenda, Quality Assurance and
Certification of Safety and Pollution Prevention Equipment Used in
Offshore Oil and Gas Operations, incorporated by reference at Sec.
250.806;
(8) ANSI Z88.2-1992, American National Standard for Respiratory
Protection, incorporated by reference at, Sec. 250.490.
(h) American Petroleum Institute (API), API Recommended Practices
(RP), Specs, Standards, Manual of Petroleum Measurement Standards
(MPMS) chapters, 1220 L Street, NW., Washington, DC 20005-4070; http://www.api.org; phone: 202-682-8000:
(1) API 510, Pressure Vessel Inspection Code: In-Service
Inspection, Rating, Repair, and Alteration, Downstream Segment, Ninth
Edition, June 2006; incorporated by reference at Sec. Sec. 250.803 and
250.1629;
(2) API Bulletin 2INT-DG, Interim Guidance for Design of Offshore
Structures for Hurricane Conditions, May 2007; incorporated by
reference at Sec. 250.901;
(3) API Bulletin 2INT-EX, Interim Guidance for Assessment of
Existing Offshore Structures for Hurricane Conditions, May 2007;
incorporated by reference at Sec. 250.901;
(4) API Bulletin 2INT-MET, Interim Guidance on Hurricane Conditions
in the Gulf of Mexico, May 2007; incorporated by reference at Sec.
250.901;
(5) API MPMS, Chapter 1--Vocabulary, Second Edition, July 1994;
incorporated by reference at Sec. 250.1201;
(6) API MPMS, Chapter 2--Tank Calibration, Section 2A--Measurement
and Calibration of Upright Cylindrical Tanks by the Manual Tank
Strapping Method, First Edition, February 1995; reaffirmed February
2007; incorporated by reference at Sec. 250.1202;
(7) API MPMS, Chapter 2--Tank Calibration, Section 2B--Calibration
of Upright Cylindrical Tanks Using the Optical Reference Line Method,
First Edition, March 1989; reaffirmed, December 2007; incorporated by
reference at Sec. 250.1202;
(8) API MPMS, Chapter 3--Tank Gauging, Section 1A--Standard
Practice for the Manual Gauging of Petroleum and Petroleum Products,
Second Edition, August 2005; incorporated by reference at Sec.
250.1202;
(9) API MPMS, Chapter 3--Tank Gauging, Section 1B--Standard
Practice for Level Measurement of Liquid Hydrocarbons in Stationary
Tanks by Automatic Tank Gauging, Second Edition, June 2001, reaffirmed,
October 2006; incorporated by reference at Sec. 250.1202;
(10) API MPMS, Chapter 4--Proving Systems, Section 1--Introduction,
Third Edition, February 2005; incorporated by reference at Sec.
250.1202;
(11) API MPMS, Chapter 4--Proving Systems, Section 2--Displacement
Provers, Third Edition, September 2003; incorporated by reference at
Sec. 250.1202;
(12) API MPMS, Chapter 4--Proving Systems, Section 4--Tank Provers,
Second Edition, May 1998, reaffirmed November 2005; incorporated by
reference at Sec. 250.1202;
(13) API MPMS, Chapter 4--Proving Systems, Section 5--Master-Meter
Provers, Second Edition, May 2000, reaffirmed: August 2005;
incorporated by reference at Sec. 250.1202;
(14) API MPMS, Chapter 4--Proving Systems, Section 6--Pulse
Interpolation, Second Edition, May 1999; reaffirmed 2003; incorporated
by reference at Sec. 250.1202;
(15) API MPMS, Chapter 4--Proving Systems, Section 7--Field
Standard Test Measures, Second Edition, December 1998; reaffirmed 2003;
incorporated by reference at Sec. 250.1202;
[[Page 64507]]
(16) API MPMS, Chapter 5--Metering, Section 1--General
Considerations for Measurement by Meters, Fourth Edition, September
2005; incorporated by reference at Sec. 250.1202;
(17) API MPMS, Chapter 5--Metering, Section 2--Measurement of
Liquid Hydrocarbons by Displacement Meters, Third Edition, September
2005; incorporated by reference at Sec. 250.1202;
(18) API MPMS Chapter 5--Metering, Section 3--Measurement of Liquid
Hydrocarbons by Turbine Meters, Fifth Edition, September 2005;
incorporated by reference at Sec. 250.1202;
(19) API MPMS, Chapter 5--Metering, Section 4--Accessory Equipment
for Liquid Meters, Fourth Edition, September 2005; incorporated by
reference at Sec. 250.1202;
(20) API MPMS, Chapter 5--Metering, Section 5--Fidelity and
Security of Flow Measurement Pulsed-Data Transmission Systems, Second
Edition, August 2005; incorporated by reference at Sec. 250.1202;
(21) API MPMS, Chapter 6--Metering Assemblies, Section 1--Lease
Automatic Custody Transfer (LACT) Systems, Second Edition, May 1991;
reaffirmed, April 2007; incorporated by reference at Sec. 250.1202;
(22) API MPMS, Chapter 6--Metering Assemblies, Section 6--Pipeline
Metering Systems, Second Edition, May 1991; reaffirmed, February 2007;
incorporated by reference at Sec. 250.1202;
(23) API MPMS, Chapter 6--Metering Assemblies, Section 7--Metering
Viscous Hydrocarbons, Second Edition, May 1991; reaffirmed, April 2007;
incorporated by reference at Sec. 250.1202;
(24) API MPMS, Chapter 7--Temperature Determination, First Edition,
June 2001; reaffirmed, March 2007; incorporated by reference at Sec.
250.1202;
(25) API MPMS, Chapter 8--Sampling, Section 1--Standard Practice
for Manual Sampling of Petroleum and Petroleum Products, Third Edition,
October 1995; reaffirmed, March 2006; incorporated by reference at
Sec. 250.1202;
(26) API MPMS, Chapter 8--Sampling, Section 2--Standard Practice
for Automatic Sampling of Liquid Petroleum and Petroleum Products,
Second Edition, October 1995; reaffirmed, June 2005; incorporated by
reference at Sec. 250.1202;
(27) API MPMS, Chapter 9--Density Determination, Section 1--
Standard Test Method for Density, Relative Density (Specific Gravity),
or API Gravity of Crude Petroleum and Liquid Petroleum Products by
Hydrometer Method, Second Edition, December 2002; reaffirmed October
2005; incorporated by reference at Sec. 250.1202(a)(3) and (l)(4);
(28) API MPMS, Chapter 9--Density Determination, Section 2--
Standard Test Method for Density or Relative Density of Light
Hydrocarbons by Pressure Hydrometer, Second Edition, March 2003;
incorporated by reference at Sec. 250.1202;
(29) API MPMS, Chapter 10--Sediment and Water, Section 1--Standard
Test Method for Sediment in Crude Oils and Fuel Oils by the Extraction
Method, Third Edition, November 2007; incorporated by reference at
Sec. 250.1202;
(30) API MPMS, Chapter 10--Sediment and Water, Section 2--Standard
Test Method for Water in Crude Oil by Distillation, Second Edition,
November 2007; incorporated by reference at Sec. 250.1202;
(31) API MPMS, Chapter 10--Sediment and Water, Section 3--Standard
Test Method for Water and Sediment in Crude Oil by the Centrifuge
Method (Laboratory Procedure), Third Edition, May 2008; incorporated by
reference at Sec. 250.1202;
(32) API MPMS, Chapter 10--Sediment and Water, Section 4--
Determination of Water and/or Sediment in Crude Oil by the Centrifuge
Method (Field Procedure), Third Edition, December 1999; incorporated by
reference at Sec. 250.1202;
(33) API MPMS, Chapter 10--Sediment and Water, Section 9--Standard
Test Method for Water in Crude Oils by Coulometric Karl Fischer
Titration, Second Edition, December 2002; reaffirmed 2005; incorporated
by reference at Sec. 250.1202;
(34) API MPMS, Chapter 11.1--Volume Correction Factors, Volume 1,
Table 5A--Generalized Crude Oils and JP-4 Correction of Observed API
Gravity to API Gravity at 60 [deg]F, and Table 6A--Generalized Crude
Oils and JP-4 Correction of Volume to 60 [deg]F Against API Gravity at
60 [deg]F, API Standard 2540, First Edition, August 1980; reaffirmed
March 1997; incorporated by reference at Sec. 250.1202;
(35) API MPMS, Chapter 11.2.2--Compressibility Factors for
Hydrocarbons: 0.350-0.637 Relative Density (60 [deg]F/60 [deg]F) and -
50 [deg]F to 140 [deg]F Metering Temperature, Second Edition, October
1986; reaffirmed: December 2007; incorporated by reference at Sec.
250.1202;
(36) API MPMS, Chapter 11--Physical Properties Data, Addendum to
Section 2, Part 2--Compressibility Factors for Hydrocarbons,
Correlation of Vapor Pressure for Commercial Natural Gas Liquids, First
Edition, December 1994; reaffirmed, December 2002; incorporated by
reference at Sec. 250.1202;
(37) API MPMS, Chapter 12--Calculation of Petroleum Quantities,
Section 2--Calculation of Petroleum Quantities Using Dynamic
Measurement Methods and Volumetric Correction Factors, Part 1--
Introduction, Second Edition, May 1995; reaffirmed March 2002;
incorporated by reference at Sec. 250.1202;
(38) API MPMS, Chapter 12--Calculation of Petroleum Quantities,
Section 2--Calculation of Petroleum Quantities Using Dynamic
Measurement Methods and Volumetric Correction Factors, Part 2--
Measurement Tickets, Third Edition, June 2003; incorporated by
reference at Sec. 250.1202;
(39) API MPMS, Chapter 14--Natural Gas Fluids Measurement, Section
3--Concentric, Square-Edged Orifice Meters, Part 1--General Equations
and Uncertainty Guidelines, Third Edition, September 1990; reaffirmed
January 2003; incorporated by reference at Sec. 250.1203;
(40) API MPMS, Chapter 14--Natural Gas Fluids Measurement, Section
3--Concentric, Square-Edged Orifice Meters, Part 2--Specification and
Installation Requirements, Fourth Edition, April 2000; reaffirmed March
2006; incorporated by reference at Sec. 250.1203;
(41) API MPMS, Chapter 14--Natural Gas Fluids Measurement, Section
3--Concentric, Square-Edged Orifice Meters; Part 3--Natural Gas
Applications; Third Edition, August 1992; Errata March 1994,
reaffirmed, February 2009; incorporated by reference at Sec. 250.1203;
(42) API MPMS, Chapter 14.5/GPA Standard 2172-09; Calculation of
Gross Heating Value, Relative Density, Compressibility and Theoretical
Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody
Transfer; Third Edition, January 2009; incorporated by reference at
Sec. 250.1203;
(43) API MPMS, Chapter 14--Natural Gas Fluids Measurement, Section
6--Continuous Density Measurement, Second Edition, April 1991;
reaffirmed, February 2006; incorporated by reference at Sec. 250.1203;
(44) API MPMS, Chapter 14--Natural Gas Fluids Measurement, Section
8--Liquefied Petroleum Gas Measurement, Second Edition, July 1997;
reaffirmed, March 2006; incorporated by reference at Sec. 250.1203;
(45) API MPMS, Chapter 20--Section 1--Allocation Measurement, First
Edition, September 1993; reaffirmed October 2006; incorporated by
reference at Sec. 250.1202;
[[Page 64508]]
(46) API MPMS, Chapter 21--Flow Measurement Using Electronic
Metering Systems, Section 1--Electronic Gas Measurement, First Edition,
August 1993; reaffirmed, July 2005; incorporated by reference at Sec.
250.1203;
(47) API RP 2A-WSD, Recommended Practice for Planning, Designing
and Constructing Fixed Offshore Platforms--Working Stress Design,
Twenty-first Edition, December 2000; Errata and Supplement 1, December
2002; Errata and Supplement 2, September 2005; Errata and Supplement 3,
October 2007; incorporated by reference at Sec. Sec. 250.901, 250.908,
250.919, and 250.920;
(48) API RP 2D, Operation and Maintenance of Offshore Cranes, Sixth
Edition, May 2007; incorporated by reference at Sec. 250.108;
(49) API RP 2FPS, RP for Planning, Designing, and Constructing
Floating Production Systems; First Edition, March 2001; incorporated by
reference at Sec. 250.901;
(50) API RP 2I, In-Service Inspection of Mooring Hardware for
Floating Structures; Third Edition, April 2008; incorporated by
reference at Sec. 250.901(a) and (d);
(51) API RP 2RD, Recommended Practice for Design of Risers for
Floating Production Systems (FPSs) and Tension-Leg Platforms (TLPs),
First Edition, June 1998; reaffirmed, May 2006, Errata, June 2009;
incorporated by reference at Sec. Sec. 250.800; 250.901 and 250.1002;
(52) API RP 2SK, Design and Analysis of Stationkeeping Systems for
Floating Structures, Third Edition, October 2005, Addendum, May 2008;
incorporated by reference at Sec. Sec. 250.800 and 250.901;
(53) API RP 2SM, Recommended Practice for Design, Manufacture,
Installation, and Maintenance of Synthetic Fiber Ropes for Offshore
Mooring, First Edition, March 2001, Addendum, May 2007; incorporated by
reference at Sec. 250.901;
(54) API RP 2T, Recommended Practice for Planning, Designing, and
Constructing Tension Leg Platforms, Second Edition, August 1997;
incorporated by reference at Sec. 250.901;
(55) API RP 14B, Recommended Practice for Design, Installation,
Repair and Operation of Subsurface Safety Valve Systems, Fifth Edition,
October 2005, also available as ISO 10417: 2004, (Identical) Petroleum
and natural gas industries--Subsurface safety valve systems--Design,
installation, operation and redress; incorporated by reference at
Sec. Sec. 250.801 and 250.804;
(56) API RP 14C, Recommended Practice for Analysis, Design,
Installation, and Testing of Basic Surface Safety Systems for Offshore
Production Platforms, Seventh Edition, March 2001, reaffirmed: March
2007; incorporated by reference at Sec. Sec. 250.125, 250.292,
250.802, 250.803, 250.804, 250.1002, 250.1004, 250.1628, 250.1629, and
250.1630;
(57) API RP 14E, Recommended Practice for Design and Installation
of Offshore Production Platform Piping Systems, Fifth Edition, October
1991; reaffirmed, March 2007; incorporated by reference at Sec. Sec.
250.802 and 250.1628;
(58) API RP 14F, Design, Installation, and Maintenance of
Electrical Systems for Fixed and Floating Offshore Petroleum Facilities
for Unclassified and Class I, Division 1 and Division 2 Locations,
Fifth Edition, July 2008; incorporated by reference at Sec. Sec.
250.114, 250.803, and 250.1629;
(59) API RP 14FZ, Recommended Practice for Design and Installation
of Electrical Systems for Fixed and Floating Offshore Petroleum
Facilities for Unclassified and Class I, Zone 0, Zone 1 and Zone 2
Locations, First Edition, September 2001, reaffirmed: March 2007;
incorporated by reference at Sec. Sec. 250.114, 250.803, and 250.1629;
(60) API RP 14G, Recommended Practice for Fire Prevention and
Control on Fixed Open-type Offshore Production Platforms, Fourth
Edition, April 2007; incorporated by reference at Sec. Sec. 250.803
and 250.1629;
(61) API RP 14H, Recommended Practice for Installation, Maintenance
and Repair of Surface Safety Valves and Underwater Safety Valves
Offshore, Fifth Edition, August 2007; incorporated by reference at
Sec. Sec. 250.802 and 250.804;
(62) API RP 14J, Recommended Practice for Design and Hazards
Analysis for Offshore Production Facilities, Second Edition, May 2001;
reaffirmed: March 2007; incorporated by reference at Sec. Sec. 250.800
and 250.901;
(63) API RP 53, Recommended Practices for Blowout Prevention
Equipment Systems for Drilling Wells, Third Edition, March 1997;
reaffirmed September 2004; incorporated by reference at Sec. Sec.
250.442, 250.446, 250.516, and 250.617,
(64) API RP 65, Recommended Practice for Cementing Shallow Water
Flow Zones in Deepwater Wells, First Edition, September 2002;
incorporated by reference at Sec. 250.415;
(65) API RP 500, Recommended Practice for Classification of
Locations for Electrical Installations at Petroleum Facilities
Classified as Class I, Division 1 and Division 2, Second Edition,
November 1997; reaffirmed November 2002; incorporated by reference at
Sec. Sec. 250.114, 250.459, 250.802, 250.803, 250.1628, and 250.1629;
(66) API RP 505, Recommended Practice for Classification of
Locations for Electrical Installations at Petroleum Facilities
Classified as Class I, Zone 0, Zone 1, and Zone 2, First Edition,
November 1997; reaffirmed November 2002; incorporated by reference at
Sec. Sec. 250.114, 250.459, 250.802, 250.803, 250.1628, and 250.1629;
(67) API RP 2556, Recommended Practice for Correcting Gauge Tables
for Incrustation, Second Edition, August 1993; reaffirmed November
2003; incorporated by reference at Sec. 250.1202;
(68) ANSI/API Spec. Q1, Specification for Quality Programs for the
Petroleum, Petrochemical and Natural Gas Industry, ISO TS 29001:2007
(Identical), Petroleum, petrochemical and natural gas industries--
Sector specific requirements--Requirements for product and service
supply organizations, Eighth Edition, December 2007, Effective Date:
June 15, 2008; incorporated by reference at Sec. 250.806;
(69) API Spec. 2C, Specification for Offshore Pedestal Mounted
Cranes, Sixth Edition, March 2004, Effective Date: September 2004;
incorporated by reference at Sec. 250.108;
(70) ANSI/API Spec. 6A, Specification for Wellhead and Christmas
Tree Equipment, Nineteenth Edition, July 2004; Effective Date: February
1, 2005; Contains API Monogram Annex as Part of U.S. National Adoption;
ISO 10423:2003 (Modified), Petroleum and natural gas industries--
Drilling and production equipment--Wellhead and Christmas tree
equipment; Errata 1, September 2004, Errata 2, April 2005, Errata 3,
June 2006, Errata 4, August 2007, Errata 5, May 2009; Addendum 1,
February 2008; Addendum 2, 3, and 4, December 2008; incorporated by
reference at Sec. Sec. 250.806 and 250.1002;
(71) API Spec. 6AV1, Specification for Verification Test of
Wellhead Surface Safety Valves and Underwater Safety Valves for
Offshore Service, First Edition, February 1, 1996; reaffirmed January
2003; incorporated by reference at Sec. 250.806;
(72) ANSI/API Spec. 6D, Specification for Pipeline Valves, Twenty-
third Edition, April 2008; Effective Date: October 1, 2008, Errata 1,
June 2008; Errata 2, November 2008; Errata 3, February 2009; Addendum
1, October 2009; Contains API Monogram Annex as Part of U.S. National
Adoption; ISO 14313:2007 (Identical), Petroleum and natural gas
industries--Pipeline transportation systems--Pipeline valves;
incorporated by reference at Sec. 250.1002;
(73) ANSI/API Spec. 14A, Specification for Subsurface Safety Valve
Equipment, Eleventh Edition, October 2005, Effective Date: May 1,
[[Page 64509]]
2006; also available as ISO 10432:2004; incorporated by reference at
Sec. 250.806;
(74) ANSI/API Spec. 17J, Specification for Unbonded Flexible Pipe,
Third Edition, July 2008; Effective Date: January 1, 2009, Contains API
Monogram Annex as Part of U.S. National Adoption; ISO 13628-2:2006
(Identical), Petroleum and natural gas industries--Design and operation
of subsea production systems--Part 2: Unbonded flexible pipe systems
for subsea and marine application; incorporated by reference at
Sec. Sec. 250.803, 250.1002, and 250.1007;
(75) API Standard 2551, Measurement and Calibration of Horizontal
Tanks, First Edition, 1965; reaffirmed March 2002; incorporated by
reference at Sec. 250.1202;
(76) API Standard 2552, USA Standard Method for Measurement and
Calibration of Spheres and Spheroids, First Edition, 1966; reaffirmed,
October 2007; incorporated by reference at Sec. 250.1202;
(77) API Standard 2555, Method for Liquid Calibration of Tanks,
First Edition, September 1966; reaffirmed March 2002; incorporated by
reference at Sec. 250.1202.
(78) API RP 90, Annular Casing Pressure Management for Offshore
Wells, First Edition, August 2006, incorporated by reference at Sec.
250.518.
(79) API RP 65-Part 2, Isolating Potential Flow Zones During Well
Construction; First Edition, May 2010; incorporated by reference at
Sec. 250.415.
(80) API RP 75, Recommended Practice for Development of a Safety
and Environmental Management Program for Offshore Operations and
Facilities, Third Edition, May 2004, Reaffirmed May 2008; incorporated
by reference at Sec. Sec. 250.1900, 250.1902, 250.1903, 250.1909,
250.1920.
(i) American Society for Testing and Materials (ASTM), ASTM
Standards, 100 Bar Harbor Drive, P. O. Box C700, West Conshohocken, PA
19428-2959; http://www.astm.org; phone: 610-832-9500:
(1) ASTM Standard C 33-07, approved December 15, 2007, Standard
Specification for Concrete Aggregates; incorporated by reference at
Sec. 250.901;
(2) ASTM Standard C 94/C 94M-07, approved January 1, 2007, Standard
Specification for Ready-Mixed Concrete; incorporated by reference at
Sec. 250.901;
(3) ASTM Standard C 150-07, approved May 1, 2007, Standard
Specification for Portland Cement; incorporated by reference at Sec.
250.901;
(4) ASTM Standard C 330-05, approved December 15, 2005, Standard
Specification for Lightweight Aggregates for Structural Concrete;
incorporated by reference at Sec. 250.901;
(5) ASTM Standard C 595-08, approved January 1, 2008, Standard
Specification for Blended Hydraulic Cements; incorporated by reference
at Sec. 250.901;
(j) American Welding Society (AWS), AWS Codes, 550 NW, LeJeune
Road, Miami, FL 33126; http://www.aws.org; phone: 800-443-9353:
(1) AWS D1.1:2000, Structural Welding Code--Steel, 17th Edition,
October 18, 1999; incorporated by reference at Sec. 250.901;
(2) AWS D1.4-98, Structural Welding Code--Reinforcing Steel, 1998
Edition; incorporated by reference at Sec. 250.901;
(3) AWS D3.6M:1999, Specification for Underwater Welding (1999);
incorporated by reference at Sec. 250.901.
(k) National Association of Corrosion Engineers (NACE), NACE
Standards, 1440 South Creek Drive, Houston, TX 77084; http://www.nace.org; phone: 281-228-6200:
(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. 250.901 and 250.490;
(2) NACE Standard RP0176-2003, Standard Recommended Practice,
Corrosion Control of Steel Fixed Offshore Structures Associated with
Petroleum Production; incorporated by reference at Sec. 250.901.
Sec. 250.199 Paperwork Reduction Act statements--information
collection.
(a) OMB has approved the information collection requirements in
part 250 under 44 U.S.C. 3501 et seq. The table in paragraph (e) of
this section lists the subpart in the rule requiring the information
and its title, provides the OMB control number, and summarizes the
reasons for collecting the information and how BSEE uses the
information. The associated BSEE forms required by this part are listed
at the end of this table with the relevant information.
(b) Respondents are OCS oil, gas, and sulphur lessees and
operators. The requirement to respond to the information collections in
this part is mandated under the Act (43 U.S.C. 1331 et seq.) and the
Act's Amendments of 1978 (43 U.S.C. 1801 et seq.). Some responses are
also required to obtain or retain a benefit or may be voluntary.
Proprietary information will be protected under Sec. 250.197, Data and
information to be made available to the public or for limited
inspection; parts 30 CFR Parts 251, 252; and the Freedom of Information
Act (5 U.S.C. 552) and its implementing regulations at 43 CFR part 2.
(c) The Paperwork Reduction Act of 1995 requires us to inform the
public that an agency 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.
(d) Send comments regarding any aspect of the collections of
information under this part, including suggestions for reducing the
burden, to the Information Collection Clearance Officer, Bureau of
Safety and Environmental Enforcement, 381 Elden Street, Herndon, VA
20170.
(e) BSEE is collecting this information for the reasons given in
the following table:
------------------------------------------------------------------------
30 CFR subpart, title and/or BSEE Form Reasons for collecting
(OMB Control No.) information and how used
------------------------------------------------------------------------
(1) Subpart A, General (1010-0114), To inform BSEE of actions taken
including Forms BSEE-0132, Evacuation to comply with general
Statistics; BSEE-0143, Facility/ operational requirements on
Equipment Damage Report; BSEE-1832, the OCS. To ensure that
Notification of Incidents of operations on the OCS meet
Noncompliance. statutory and regulatory
requirements, are safe and
protect the environment, and
result in diligent
exploration, development, and
production on OCS leases. To
support the unproved and
proved reserve estimation,
resource assessment, and fair
market value determinations.
To allow BSEE to rapidly
assess damage and project any
disruption of oil and gas
production from the OCS after
a major natural occurrence.
[[Page 64510]]
(2) Subpart B, Exploration and To inform BSEE, States, and the
Development and Production Plans (1010- public of planned exploration,
0151). development, and production
operations on the OCS. To
ensure that operations on the
OCS are planned to comply with
statutory and regulatory
requirements, will be safe and
protect the human, marine, and
coastal environment, and will
result in diligent
exploration, development, and
production of leases.
(3) Subpart C, Pollution Prevention and To inform BSEE of measures to
Control (1010-0057). be taken to prevent water
pollution. To ensure that
appropriate measures are taken
to prevent water pollution.
(4) Subpart D, Oil and Gas and Drilling To inform BSEE of the equipment
Operations (1010-0141), including and procedures to be used in
Forms BSEE-0123, Application for drilling operations on the
Permit to Drill; BSEE-0123S, OCS. To ensure that drilling
Supplemental APD Information Sheet; operations are safe and
BSEE-0124, Application for Permit to protect the human, marine, and
Modify; BSEE-0125, End of Operations coastal environment.
Report; BSEE-0133, Well Activity
Report; BSEE-0133S, Open Hole Data
Report; and BSEE-144, Rig Movement
Notification Report.
(5) Subpart E, Oil and Gas Well- To inform BSEE of the equipment
Completion Operations (1010-0067). and procedures to be used in
well-completion operations on
the OCS. To ensure that well-
completion operations are safe
and protect the human, marine,
and coastal environment.
(6) Subpart F, Oil and Gas Well To inform BSEE of the equipment
Workover Operations (1010-0043). and procedures to be used
during well-workover
operations on the OCS. To
ensure that well-workover
operations are safe and
protect the human, marine, and
coastal environment.
(7) Subpart H, Oil and Gas Production To inform BSEE of the equipment
Safety Systems (1010-0059). and procedures to be used
during production operations
on the OCS. To ensure that
production operations are safe
and protect the human, marine,
and coastal environment.
(8) Subpart I, Platforms and Structures To provide BSEE with
(1010-0149). information regarding the
design, fabrication, and
installation of platforms on
the OCS. To ensure the
structural integrity of
platforms installed on the
OCS.
(9) Subpart J, Pipelines and Pipeline To provide BSEE with
Rights-of-Way (1010-0050), including information regarding the
Form BSEE-0149, Assignment of Federal design, installation, and
OCS Pipeline Right-of-Way Grant. operation of pipelines on the
OCS. To ensure that pipeline
operations are safe and
protect the human, marine, and
coastal environment.
(10) Subpart K, Oil and Gas Production To inform BSEE of production
Rates (1010-0041), including Forms rates for hydrocarbons
BSEE-0126, Well Potential Test Report produced on the OCS. To ensure
and BSEE-0128, Semiannual Well Test economic maximization of
Report. ultimate hydrocarbon recovery
(11) Subpart L, Oil and Gas Production To inform BSEE of the
Measurement, Surface Commingling, and measurement of production,
Security (1010-0051). commingling of hydrocarbons,
and site security plans. To
ensure that produced
hydrocarbons are measured and
commingled to provide for
accurate royalty payments and
security is maintained.
(12) Subpart M, Unitization (1010-0068) To inform BSEE of the
unitization of leases. To
ensure that unitization
prevents waste, conserves
natural resources, and
protects correlative rights.
(13) Subpart N, Remedies and Penalties. The requirements in subpart N
are exempt from the Paperwork
Reduction Act of 1995
according to 5 CFR 1320.4.
(14) Subpart O, Well Control and To inform BSEE of training
Production Safety Training (1010-0128). program curricula, course
schedules, and attendance. To
ensure that training programs
are technically accurate and
sufficient to meet safety and
environmental requirements,
and that workers are properly
trained to operate on the OCS.
(15) Subpart P, Sulphur Operations To inform BSEE of sulphur
(1010-0086). exploration and development
operations on the OCS. To
ensure that OCS sulphur
operations are safe; protect
the human, marine, and coastal
environment; and will result
in diligent exploration,
development, and production of
sulphur leases.
(16) Subpart Q, Decommissioning To determine that
Activities (1010-0142). decommissioning activities
comply with regulatory
requirements and approvals. To
ensure that site clearance and
platform or pipeline removal
are properly performed to
protect marine life and the
environment and do not
conflict with other users of
the OCS.
(17) Subpart S, Safety and The SEMS program will describe
Environmental Management Systems (1010- management commitment to
0186), including Form BSEE-0131, safety and the environment, as
Performance Measures Data. well as policies and
procedures to assure safety
and environmental protection
while conducting OCS
operations (including those
operations conducted by
contractor and subcontractor
personnel). The information
collected is the form to
gather the raw Performance
Measures Data relating to risk
and number of accidents,
injuries, and oil spills
during OCS activities.
------------------------------------------------------------------------
[[Page 64511]]
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:
BOEM means Bureau of Ocean Energy Management of the Department of
the Interior.
BSEE means Bureau of Safety and Environmental Enforcement of the
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.
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)).
Modification means a change required by the Regional Supervisor to
an EP, DPP, or DOCD (see 30 CFR 550.233(b)(2) and 550.270(b)(2)) that
is pending before BOEM for a decision because the OCS plan is
inconsistent with applicable requirements.
New or unusual technology means equipment or procedures that:
(1) Have not been used previously or extensively in a BSEE OCS
Region;
(2) Have not been used previously under the anticipated operating
conditions; or
(3) Have operating characteristics that are outside the performance
parameters established by this part.
Non-conventional production or completion technology includes, but
is not limited to, floating production systems, tension leg platforms,
spars, floating production, storage, and offloading systems, guyed
towers, compliant towers, subsea manifolds, and other subsea production
components that rely on a remote site or host facility for utility and
well control services.
Offshore vehicle means a vehicle that is capable of being driven on
ice.
Resubmitted OCS plan means an EP, DPP, or DOCD that contains
changes you make to an OCS plan that BOEM has disapproved (see 30 CFR
550.234(b), 550.272(a), and 550.273(b)).
Revised OCS plan means an EP, DPP, or DOCD that proposes changes to
an approved OCS plan, such as those in the location of a well or
platform, type of drilling unit, or location of the onshore support
base (see 30 CFR 550.283(a)).
Supplemental OCS plan means an EP, DPP, or DOCD that proposes the
addition to an approved OCS plan of an activity that requires approval
of an application or permit (see 30 CFR 550.283(b)).
Sec. 250.201 What plans and information must I submit before I
conduct any activities on my lease or unit?
(a) Plans and documents. 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 documents. Your plans and documents
may cover one or more leases or units.
------------------------------------------------------------------------
You must submit a(n) . . . Before you . . .
------------------------------------------------------------------------
(1) [Reserved]
(2) [Reserved]
(3) [Reserved]
(4) Deepwater Operations Plan (DWOP), Conduct post-drilling
installation activities in
any water depth associated
with a development project
that will involve the use
of a non-conventional
production or completion
technology.
(5) [Reserved]
(6) [Reserved]
------------------------------------------------------------------------
(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 document.
(c) Limiting information. The Regional Director may limit the
amount of information or analyses that you otherwise must provide in
your proposed plan or document under this subpart when:
(1) Sufficient applicable information or analysis is readily
available to BSEE;
(2) Other coastal or marine resources are not present or affected;
(3) Other factors such as technological advances affect information
needs; or
(4) Information is not necessary or required for a State to
determine consistency with their CZMA Plan.
(d) Referencing. In preparing your proposed plan or document, you
may reference information and data discussed in other plans or
documents you previously submitted or that are otherwise readily
available to BSEE.
Sec. 250.202 [Reserved]
Sec. 250.203 [Reserved]
Sec. 250.204 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. 250.205 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.
[[Page 64512]]
Post-Approval Requirements for the EP, DPP, and DOCD
Sec. 250.282 Do I have to conduct post-approval monitoring?
The Regional Supervisor may direct you to conduct monitoring
programs. 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) Monitoring plans. Submit monitoring plans for approval before
you begin work; and
(b) Monitoring reports. 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.
Deepwater Operations Plan (DWOP)
Sec. 250.286 What is a DWOP?
(a) A DWOP is a plan that provides sufficient information for BSEE
to review a deepwater development project, and any other project that
uses non-conventional production or completion technology, from a total
system approach. The DWOP does not replace, but supplements other
submittals required by the regulations such as BOEM Exploration Plans,
Development and Production Plans, and Development Operations
Coordination Documents. BSEE will use the information in your DWOP to
determine whether the project will be developed in an acceptable
manner, particularly with respect to operational safety and
environmental protection issues involved with non-conventional
production or completion technology.
(b) The DWOP process consists of two parts: a Conceptual Plan and
the DWOP. Section 250.289 prescribes what the Conceptual Plan must
contain, and Sec. 250.292 prescribes what the DWOP must contain.
Sec. 250.287 For what development projects must I submit a DWOP?
You must submit a DWOP for each development project in which you
will use non-conventional production or completion technology,
regardless of water depth. If you are unsure whether BSEE considers the
technology of your project non-conventional, you must contact the
Regional Supervisor for guidance.
Sec. 250.288 When and how must I submit the Conceptual Plan?
You must submit four copies, or one hard copy and one electronic
version, of the Conceptual Plan to the Regional Director after you have
decided on the general concept(s) for development and before you begin
engineering design of the well safety control system or subsea
production systems to be used after well completion.
Sec. 250.289 What must the Conceptual Plan contain?
In the Conceptual Plan, you must explain the general design basis
and philosophy that you will use to develop the field. You must include
the following information:
(a) An overview of the development concept(s);
(b) A well location plat;
(c) The system control type (i.e., direct hydraulic or electro-
hydraulic); and
(d) The distance from each of the wells to the host platform.
Sec. 250.290 What operations require approval of the Conceptual Plan?
You may not complete any production well or install the subsea
wellhead and well safety control system (often called the tree) before
BSEE has approved the Conceptual Plan.
Sec. 250.291 When and how must I submit the DWOP?
You must submit four copies, or one hard copy and one electronic
version, of the DWOP to the Regional Director after you have
substantially completed safety system design and before you begin to
procure or fabricate the safety and operational systems (other than the
tree), production platforms, pipelines, or other parts of the
production system.
Sec. 250.292 What must the DWOP contain?
You must include the following information in your DWOP:
(a) A description and schematic of the typical wellbore, casing,
and completion;
(b) Structural design, fabrication, and installation information
for each surface system, including host facilities;
(c) Design, fabrication, and installation information on the
mooring systems for each surface system;
(d) Information on any active stationkeeping system(s) involving
thrusters or other means of propulsion used with a surface system;
(e) Information concerning the drilling and completion systems;
(f) Design and fabrication information for each riser system (e.g.,
drilling, workover, production, and injection);
(g) Pipeline information;
(h) Information about the design, fabrication, and operation of an
offtake system for transferring produced hydrocarbons to a transport
vessel;
(i) Information about subsea wells and associated systems that
constitute all or part of a single project development covered by the
DWOP;
(j) Flow schematics and Safety Analysis Function Evaluation (SAFE)
charts (API RP 14C, subsection 4.3c, incorporated by reference in Sec.
250.198) of the production system from the Surface Controlled
Subsurface Safety Valve (SCSSV) downstream to the first item of
separation equipment;
(k) A description of the surface/subsea safety system and emergency
support systems to include a table that depicts what valves will close,
at what times, and for what events or reasons;
(l) A general description of the operating procedures, including a
table summarizing the curtailment of production and offloading based on
operational considerations;
(m) A description of the facility installation and commissioning
procedure;
(n) A discussion of any new technology that affects hydrocarbon
recovery systems;
(o) A list of any alternate compliance procedures or departures for
which you anticipate requesting approval; and
(p) Payment of the service fee listed in Sec. 250.125.
Sec. 250.293 What operations require approval of the DWOP?
You may not begin production until BSEE approves your DWOP.
Sec. 250.294 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 on or before the deadline for
submitting the Conceptual Plan.
(a) The project is located in water depths of less than 400 meters
(1,312 feet); and
(b) The project is similar to projects involving non-conventional
production or completion technology for which you have obtained
approval previously.
Sec. 250.295 When must I revise my DWOP?
You must revise either the Conceptual Plan or your DWOP to reflect
changes in your development project that materially alter the
facilities, equipment, and systems described in your plan. You must
submit the revision within 60 days after any material change to the
information required for that part of your plan.
Subpart C--Pollution Prevention and Control
Sec. 250.300 Pollution prevention.
(a) During the exploration, development, production, and
transportation of oil and gas or sulphur,
[[Page 64513]]
the lessee shall take measures to prevent unauthorized discharge of
pollutants into the offshore waters. The lessee shall not create
conditions that will pose unreasonable risk to public health, life,
property, aquatic life, wildlife, recreation, navigation, commercial
fishing, or other uses of the ocean.
(1) When pollution occurs as a result of operations conducted by or
on behalf of the lessee and the pollution damages or threatens to
damage life (including fish and other aquatic life), property, any
mineral deposits (in areas leased or not leased), or the marine,
coastal, or human environment, the control and removal of the pollution
to the satisfaction of the District Manager shall be at the expense of
the lessee. Immediate corrective action shall be taken in all cases
where pollution has occurred. Corrective action shall be subject to
modification when directed by the District Manager.
(2) If the lessee fails to control and remove the pollution, the
Director, in cooperation with other appropriate Agencies of Federal,
State, and local governments, or in cooperation with the lessee, or
both, shall have the right to control and remove the pollution at the
lessee's expense. Such action shall not relieve the lessee of any
responsibility provided for by law.
(b)(1) The District Manager may restrict the rate of drilling fluid
discharges or prescribe alternative discharge methods. The District
Manager may also restrict the use of components which could cause
unreasonable degradation to the marine environment. No petroleum-based
substances, including diesel fuel, may be added to the drilling mud
system without prior approval of the District Manager.
(2) Approval of the method of disposal of drill cuttings, sand, and
other well solids shall be obtained from the District Manager.
(3) All hydrocarbon-handling equipment for testing and production
such as separators, tanks, and treaters shall be designed, installed,
and operated to prevent pollution. Maintenance or repairs which are
necessary to prevent pollution of offshore waters shall be undertaken
immediately.
(4) Curbs, gutters, drip pans, and drains shall be installed in
deck areas in a manner necessary to collect all contaminants not
authorized for discharge. Oil drainage shall be piped to a properly
designed, operated, and maintained sump system which will automatically
maintain the oil at a level sufficient to prevent discharge of oil into
offshore waters. All gravity drains shall be equipped with a water trap
or other means to prevent gas in the sump system from escaping through
the drains. Sump piles shall not be used as processing devices to treat
or skim liquids but may be used to collect treated-produced water,
treated-produced sand, or liquids from drip pans and deck drains and as
a final trap for hydrocarbon liquids in the event of equipment upsets.
Improperly designed, operated, or maintained sump piles which do not
prevent the discharge of oil into offshore waters shall be replaced or
repaired.
(5) On artificial islands, all vessels containing hydrocarbons
shall be placed inside an impervious berm or otherwise protected to
contain spills. Drainage shall be directed away from the drilling rig
to a sump. Drains and sumps shall be constructed to prevent seepage.
(6) Disposal of equipment, cables, chains, containers, or other
materials into offshore waters is prohibited.
(c) Materials, equipment, tools, containers, and other items used
in the Outer Continental Shelf (OCS) which are of such shape or
configuration that they are likely to snag or damage fishing devices
shall be handled and marked as follows:
(1) All loose material, small tools, and other small objects shall
be kept in a suitable storage area or a marked container when not in
use and in a marked container before transport over offshore waters;
(2) All cable, chain, or wire segments shall be recovered after use
and securely stored until suitable disposal is accomplished;
(3) Skid-mounted equipment, portable containers, spools or reels,
and drums shall be marked with the owner's name prior to use or
transport over offshore waters; and
(4) All markings must clearly identify the owner and must be
durable enough to resist the effects of the environmental conditions to
which they may be exposed.
(d) Any of the items described in paragraph (c) of this section
that are lost overboard shall be recorded on the facility's daily
operations report, as appropriate, and reported to the District
Manager.
Sec. 250.301 Inspection of facilities.
Drilling and production facilities shall be inspected daily or at
intervals approved or prescribed by the District Manager to determine
if pollution is occurring. Necessary maintenance or repairs shall be
made immediately. Records of such inspections and repairs shall be
maintained at the facility or at a nearby manned facility for 2 years.
Subpart D--Oil and Gas Drilling Operations
General Requirements
Sec. 250.400 Who is subject to the requirements of this subpart?
The requirements of this subpart apply to lessees, operating rights
owners, operators, and their contractors and subcontractors.
Sec. 250.401 What must I do to keep wells under control?
You must take necessary precautions to keep wells under control at
all times. You must:
(a) Use the best available and safest drilling technology to
monitor and evaluate well conditions and to minimize the potential for
the well to flow or kick;
(b) Have a person onsite during drilling operations who represents
your interests and can fulfill your responsibilities;
(c) Ensure that the toolpusher, operator's representative, or a
member of the drilling crew maintains continuous surveillance on the
rig floor from the beginning of drilling operations until the well is
completed or abandoned, unless you have secured the well with blowout
preventers (BOPs), bridge plugs, cement plugs, or packers;
(d) Use personnel trained according to the provisions of subpart O;
and
(e) Use and maintain equipment and materials necessary to ensure
the safety and protection of personnel, equipment, natural resources,
and the environment.
Sec. 250.402 When and how must I secure a well?
Whenever you interrupt drilling operations, you must install a
downhole safety device, such as a cement plug, bridge plug, or packer.
You must install the device at an appropriate depth within a properly
cemented casing string or liner.
(a) Among the events that may cause you to interrupt drilling
operations are:
(1) Evacuation of the drilling crew;
(2) Inability to keep the drilling rig on location; or
(3) Repair to major drilling or well-control equipment.
(b) For floating drilling operations, the District Manager may
approve the use of blind or blind-shear rams or pipe rams and an inside
BOP if you don't have time to install a downhole safety device or if
special circumstances occur.
Sec. 250.403 What drilling unit movements must I report?
(a) You must report the movement of all drilling units on and off
drilling
[[Page 64514]]
locations to the District Manager. This includes both MODU and platform
rigs. You must inform the District Manager 24 hours before:
(1) The arrival of an MODU on location;
(2) The movement of a platform rig to a platform;
(3) The movement of a platform rig to another slot;
(4) The movement of an MODU to another slot; and
(5) The departure of an MODU from the location.
(b) You must provide the District Manager with the rig name, lease
number, well number, and expected time of arrival or departure.
(c) In the Gulf of Mexico OCS Region, you must report drilling unit
movements on form BSEE-0144, Rig Movement Notification Report.
Sec. 250.404 What are the requirements for the crown block?
You must have a crown block safety device that prevents the
traveling block from striking the crown block. You must check the
device for proper operation at least once per week and after each
drill-line slipping operation and record the results of this
operational check in the driller's report.
Sec. 250.405 What are the safety requirements for diesel engines used
on a drilling rig?
You must equip each diesel engine with an air take device to shut
down the diesel engine in the event of a runaway.
(a) For a diesel engine that is not continuously manned, you must
equip the engine with an automatic shutdown device;
(b) For a diesel engine that is continuously manned, you may equip
the engine with either an automatic or remote manual air intake
shutdown device;
(c) You do not have to equip a diesel engine with an air intake
device if it meets one of the following criteria:
(1) Starts a larger engine;
(2) Powers a firewater pump;
(3) Powers an emergency generator;
(4) Powers a BOP accumulator system;
(5) Provides air supply to divers or confined entry personnel;
(6) Powers temporary equipment on a nonproducing platform;
(7) Powers an escape capsule; or
(8) Powers a portable single-cylinder rig washer.
Sec. 250.406 What additional safety measures must I take when I
conduct drilling operations on a platform that has producing wells or
has other hydrocarbon flow?
You must take the following safety measures when you conduct
drilling operations on a platform with producing wells or that has
other hydrocarbon flow:
(a) You must install an emergency shutdown station near the
driller's console;
(b) You must shut in all producible wells located in the affected
wellbay below the surface and at the wellhead when:
(1) You move a drilling rig or related equipment on and off a
platform. This includes rigging up and rigging down activities within
500 feet of the affected platform;
(2) You move or skid a drilling unit between wells on a platform;
(3) A mobile offshore drilling unit (MODU) moves within 500 feet of
a platform. You may resume production once the MODU is in place,
secured, and ready to begin drilling operations.
Sec. 250.407 What tests must I conduct to determine reservoir
characteristics?
You must determine the presence, quantity, quality, and reservoir
characteristics of oil, gas, sulphur, and water in the formations
penetrated by logging, formation sampling, or well testing.
Sec. 250.408 May I use alternative procedures or equipment during
drilling operations?
You may use alternative procedures or equipment during drilling
operations after receiving approval from the District Manager. You must
identify and discuss your proposed alternative procedures or equipment
in your Application for Permit to Drill (APD) (Form BSEE-0123) (see
Sec. 250.414(h)). Procedures for obtaining approval are described in
Sec. 250.141 of this part.
Sec. 250.409 May I obtain departures from these drilling
requirements?
The District Manager may approve departures from the drilling
requirements specified in this subpart. You may apply for a departure
from drilling requirements by writing to the District Manager. You
should identify and discuss the departure you are requesting in your
APD (see Sec. 250.414(h)).
Applying for a Permit To Drill
Sec. 250.410 How do I obtain approval to drill a well?
You must obtain written approval from the District Manager before
you begin drilling any well or before you sidetrack, bypass, or deepen
a well. To obtain approval, you must:
(a) Submit the information required by Sec. Sec. 250.411 through
250.418;
(b) Include the well in your approved Exploration Plan (EP),
Development and Production Plan (DPP), or Development Operations
Coordination Document (DOCD);
(c) Meet the oil spill financial responsibility requirements for
offshore facilities as required by 30 CFR part 553; and
(d) Submit the following to the District Manager:
(1) An original and two complete copies of Form BSEE-0123,
Application for Permit to Drill (APD), and Form BSEE-0123S,
Supplemental APD Information Sheet;
(2) A separate public information copy of forms BSEE-0123 and BSEE-
0123S that meets the requirements of Sec. 250.186; and
(3) Payment of the service fee listed in Sec. 250.125.
Sec. 250.411 What information must I submit with my application?
In addition to forms BSEE-0123 and BSEE-0123S, you must include the
information described in the following table.
------------------------------------------------------------------------
Information that you must include with
an APD Where to find a description
------------------------------------------------------------------------
(a) Plat that shows locations of the Sec. 250.412
proposed well.
(b) Design criteria used for the proposed Sec. 250.413
well.
(c) Drilling prognosis................... Sec. 250.414
(d) Casing and cementing programs........ Sec. 250.415
(e) Diverter and BOP systems descriptions Sec. 250.416
(f) Requirements for using an MODU....... Sec. 250.417
(g) Additional information............... Sec. 250.418
------------------------------------------------------------------------
Sec. 250.412 What requirements must the location plat meet?
The location plat must:
(a) Have a scale of 1:24,000 (1 inch = 2,000 feet);
(b) Show the surface and subsurface locations of the proposed well
and all the wells in the vicinity;
(c) Show the surface and subsurface locations of the proposed well
in feet or meters from the block line;
(d) Contain the longitude and latitude coordinates, and either
Universal Transverse Mercator grid-system coordinates or state plane
coordinates in the Lambert or Transverse Mercator Projection system for
the surface and subsurface locations of the proposed well; and
(e) State the units and geodetic datum (including whether the datum
is North American Datum 27 or 83) for these coordinates. If the datum
was converted, you must state the method used for this conversion,
since the various methods may produce different values.
[[Page 64515]]
Sec. 250.413 What must my description of well drilling design
criteria address?
Your description of well drilling design criteria must address:
(a) Pore pressures;
(b) Formation fracture gradients, adjusted for water depth;
(c) Potential lost circulation zones;
(d) Drilling fluid weights;
(e) Casing setting depths;
(f) Maximum anticipated surface pressures. For this section,
maximum anticipated surface pressures are the pressures that you
reasonably expect to be exerted upon a casing string and its related
wellhead equipment. In calculating maximum anticipated surface
pressures, you must consider: drilling, completion, and producing
conditions; drilling fluid densities to be used below various casing
strings; fracture gradients of the exposed formations; casing setting
depths; total well depth; formation fluid types; safety margins; and
other pertinent conditions. You must include the calculations used to
determine the pressures for the drilling and the completion phases,
including the anticipated surface pressure used for designing the
production string;
(g) A single plot containing estimated pore pressures, formation
fracture gradients, proposed drilling fluid weights, and casing setting
depths in true vertical measurements;
(h) A summary report of the shallow hazards site survey that
describes the geological and manmade conditions if not previously
submitted; and
(i) Permafrost zones, if applicable.
Sec. 250.414 What must my drilling prognosis include?
Your drilling prognosis must include a brief description of the
procedures you will follow in drilling the well. This prognosis
includes but is not limited to the following:
(a) Projected plans for coring at specified depths;
(b) Projected plans for logging;
(c) Planned safe drilling margin between proposed drilling fluid
weights and estimated pore pressures. This safe drilling margin may be
shown on the plot required by Sec. 250.413(g);
(d) Estimated depths to the top of significant marker formations;
(e) Estimated depths to significant porous and permeable zones
containing fresh water, oil, gas, or abnormally pressured formation
fluids;
(f) Estimated depths to major faults;
(g) Estimated depths of permafrost, if applicable;
(h) A list and description of all requests for using alternative
procedures or departures from the requirements of this subpart in one
place in the APD. You must explain how the alternative procedures
afford an equal or greater degree of protection, safety, or
performance, or why you need the departures; and
(i) Projected plans for well testing (refer to Sec. 250.460 for
safety requirements).
Sec. 250.415 What must my casing and cementing programs include?
Your casing and cementing programs must include:
(a) Hole sizes and casing sizes, including: weights; grades;
collapse, and burst values; types of connection; and setting depths
(measured and true vertical depth (TVD));
(b) Casing design safety factors for tension, collapse, and burst
with the assumptions made to arrive at these values;
(c) Type and amount of cement (in cubic feet) planned for each
casing string;
(d) In areas containing permafrost, setting depths for conductor
and surface casing based on the anticipated depth of the permafrost.
Your program must provide protection from thaw subsidence and
freezeback effect, proper anchorage, and well control;
(e) A statement of how you evaluated the best practices included in
API RP 65, Recommended Practice for Cementing Shallow Water Flow Zones
in Deep Water Wells (as incorporated by reference in Sec. 250.198), if
you drill a well in water depths greater than 500 feet and are in
either of the following two areas:
(1) An ``area with an unknown shallow water flow potential'' is a
zone or geologic formation where neither the presence nor absence of
potential for a shallow water flow has been confirmed.
(2) An ``area known to contain a shallow water flow hazard'' is a
zone or geologic formation for which drilling has confirmed the
presence of shallow water flow; and
(f) A written description of how you evaluated the best practices
included in API RP 65-Part 2, Isolating Potential Flow Zones During
Well Construction (as incorporated by reference in Sec. 250.198). Your
written description must identify the mechanical barriers and cementing
practices you will use for each casing string (reference API RP 65-Part
2, Sections 3 and 4).
Sec. 250.416 What must I include in the diverter and BOP
descriptions?
You must include in the diverter and BOP descriptions:
(a) A description of the diverter system and its operating
procedures;
(b) A schematic drawing of the diverter system (plan and elevation
views) that shows:
(1) The size of the annular BOP installed in the diverter housing;
(2) Spool outlet internal diameter(s);
(3) Diverter-line lengths and diameters; burst strengths and radius
of curvature at each turn; and
(4) Valve type, size, working pressure rating, and location;
(c) A description of the BOP system and system components,
including pressure ratings of BOP equipment and proposed BOP test
pressures;
(d) A schematic drawing of the BOP system that shows the inside
diameter of the BOP stack, number and type of preventers, all control
systems and pods, location of choke and kill lines, and associated
valves;
(e) Independent third party verification and supporting
documentation that show the blind-shear rams installed in the BOP stack
are capable of shearing any drill pipe in the hole under maximum
anticipated surface pressure. The documentation must include test
results and calculations of shearing capacity of all pipe to be used in
the well including correction for MASP;
(f) When you use a subsea BOP stack, independent third party
verification that shows:
(1) The BOP stack is designed for the specific equipment on the rig
and for the specific well design;
(2) The BOP stack has not been compromised or damaged from previous
service;
(3) The BOP stack will operate in the conditions in which it will
be used; and
(g) The qualifications of the independent third party referenced in
paragraphs (e) and (f) of this section:
(1) The independent third party in paragraph (e) in this section
must be a technical classification society; an API-licensed
manufacturing, inspection, or certification firm; or a licensed
professional engineering firm capable of providing the verifications
required under this part. The independent third party must not be the
original equipment manufacturer (OEM).
(2) You must:
(i) Include evidence that the firm you are using is reputable, the
firm or its employees hold appropriate licenses to perform the
verification in the appropriate jurisdiction, the firm carries
industry-standard levels of professional liability insurance, and the
firm has no record of violations of applicable law.
(ii) Ensure that an official representative of BSEE will have
access to the location to witness any testing or inspections, and
verify information
[[Page 64516]]
submitted to BSEE. Prior to any shearing ram tests or inspections, you
must notify the District Manager at least 24 hours in advance.
Sec. 250.417 What must I provide if I plan to use a mobile offshore
drilling unit (MODU)?
If you plan to use a MODU, you must provide:
(a) Fitness requirements. You must provide information and data to
demonstrate the drilling unit's capability to perform at the proposed
drilling location. This information must include the maximum
environmental and operational conditions that the unit is designed to
withstand, including the minimum air gap necessary for both hurricane
and non-hurricane seasons. If sufficient environmental information and
data are not available at the time you submit your APD, the District
Manager may approve your APD but require you to collect and report this
information during operations. Under this circumstance, the District
Manager has the right to revoke the approval of the APD if information
collected during operations show that the drilling unit is not capable
of performing at the proposed location.
(b) Foundation requirements. You must provide information to show
that site-specific soil and oceanographic conditions are capable of
supporting the proposed drilling unit. If you provided sufficient site-
specific information in your EP, DPP, or DOCD submitted to BOEM, you
may reference that information. The District Manager may require you to
conduct additional surveys and soil borings before approving the APD if
additional information is needed to make a determination that the
conditions are capable of supporting the drilling unit.
(c) Frontier areas. (1) If the design of the drilling unit you plan
to use in a frontier area is unique or has not been proven for use in
the proposed environment, the District Manager may require you to
submit a third-party review of the unit's design. If required, you must
obtain the third-party review according to Sec. Sec. 250.915 through
250.918. You may submit this information before submitting an APD.
(2) If you plan to drill in a frontier area, you must have a
contingency plan that addresses design and operating limitations of the
drilling unit. Your plan must identify the actions necessary to
maintain safety and prevent damage to the environment. Actions must
include the suspension, curtailment, or modification of drilling or rig
operations to remedy various operational or environmental situations
(e.g., vessel motion, riser offset, anchor tensions, wind speed, wave
height, currents, icing or ice-loading, settling, tilt or lateral
movement, resupply capability).
(d) U.S. Coast Guard (USCG) documentation. You must provide the
current Certificate of Inspection or Letter of Compliance from the
USCG. You must also provide current documentation of any operational
limitations imposed by an appropriate classification society.
(e) Floating drilling unit. If you use a floating drilling unit,
you must indicate that you have a contingency plan for moving off
location in an emergency situation.
(f) Inspection of unit. The drilling unit must be available for
inspection by the District Manager before commencing operations.
(g) Once the District Manager has approved a MODU for use, you do
not need to re-submit the information required by this section for
another APD to use the same MODU unless changes in equipment affect its
rated capacity to operate in the District.
Sec. 250.418 What additional information must I submit with my APD?
You must include the following with the APD:
(a) Rated capacities of the drilling rig and major drilling
equipment, if not already on file with the appropriate District office;
(b) A drilling fluids program that includes the minimum quantities
of drilling fluids and drilling fluid materials, including weight
materials, to be kept at the site;
(c) A proposed directional plot if the well is to be directionally
drilled;
(d) A Hydrogen Sulfide Contingency Plan (see Sec. 250.490), if
applicable, and not previously submitted;
(e) A welding plan (see Sec. Sec. 250.109 to 250.113) if not
previously submitted;
(f) In areas subject to subfreezing conditions, evidence that the
drilling equipment, BOP systems and components, diverter systems, and
other associated equipment and materials are suitable for operating
under such conditions;
(g) A request for approval if you plan to wash out or displace some
cement to facilitate casing removal upon well abandonment;
(h) Certification of your casing and cementing program as required
in Sec. 250.420(a)(6);
(i) Description of qualifications required by Sec. 250.416(f) of
any independent third party; and
(j) Such other information as the District Manager may require.
Casing and Cementing Requirements
Sec. 250.420 What well casing and cementing requirements must I meet?
You must case and cement all wells. Your casing and cementing
programs must meet the requirements of this section and of Sec. Sec.
250.421 through 250.428.
(a) Casing and cementing program requirements. Your casing and
cementing programs must:
(1) Properly control formation pressures and fluids;
(2) Prevent the direct or indirect release of fluids from any
stratum through the wellbore into offshore waters;
(3) Prevent communication between separate hydrocarbon-bearing
strata;
(4) Protect freshwater aquifers from contamination;
(5) Support unconsolidated sediments; and
(6) Include certification signed by a Registered Professional
Engineer that there will be at least two independent tested barriers,
including one mechanical barrier, across each flow path during well
completion activities and that the casing and cementing design is
appropriate for the purpose for which it is intended under expected
wellbore conditions. The Registered Professional Engineer must be
registered in a State in the United States. Submit this certification
with your APD (Form BSEE-0123).
(b) Casing requirements. (1) You must design casing (including
liners) to withstand the anticipated stresses imposed by tensile,
compressive, and buckling loads; burst and collapse pressures; thermal
effects; and combinations thereof.
(2) The casing design must include safety measures that ensure well
control during drilling and safe operations during the life of the
well.
(3) For the final casing string (or liner if it is your final
string), you must install dual mechanical barriers in addition to
cement, to prevent flow in the event of a failure in the cement. These
may include dual float valves, or one float valve and a mechanical
barrier. You must submit documentation to BSEE 30 days after
installation of the dual mechanical barriers.
(c) Cementing requirements. You must design and conduct your
cementing jobs so that cement composition, placement techniques, and
waiting times ensure that the cement placed behind the bottom 500 feet
of casing attains a minimum compressive strength of 500 psi before
drilling out of the casing or before commencing completion operations.
[[Page 64517]]
Sec. 250.421 What are the casing and cementing requirements by type
of casing string?
The table in this section identifies specific design, setting, and
cementing requirements for casing strings and liners. For the purposes
of subpart D, the casing strings in order of normal installation are as
follows: drive or structural, conductor, surface, intermediate, and
production casings (including liners). The District Manager may approve
or prescribe other casing and cementing requirements where appropriate.
------------------------------------------------------------------------
Cementing
Casing type Casing requirements requirements
------------------------------------------------------------------------
(a) Drive or Structural..... Set by driving, If you drilled a
jetting, or portion of this
drilling to the hole, you must use
minimum depth as enough cement to
approved or fill the annular
prescribed by the space back to the
District Manager. mudline.
(b) Conductor............... Design casing and Use enough cement to
select setting fill the calculated
depths based on annular space back
relevant to the mudline.
engineering and Verify annular fill
geologic factors. by observing cement
These factors returns. If you
include the cannot observe
presence or absence cement returns, use
of hydrocarbons, additional cement
potential hazards, to ensure fill-back
and water depths; to the mudline.
Set casing For drilling on an
immediately before artificial island
drilling into or when using a
formations known to glory hole, you
contain oil or gas. must discuss the
If you encounter cement fill level
oil or gas or with the District
unexpected Manager.
formation pressure
before the planned
casing point, you
must set casing
immediately.
(c) Surface................. Design casing and Use enough cement to
select setting fill the calculated
depths based on annular space to at
relevant least 200 feet
engineering and inside the
geologic factors. conductor casing.
These factors When geologic
include the conditions such as
presence or absence near-surface
of hydrocarbons, fractures and
potential hazards, faulting exist, you
and water depths. must use enough
cement to fill the
calculated annular
space to the
mudline.
(d) Intermediate............ Design casing and Use enough cement to
select setting cover and isolate
depth based on all hydrocarbon-
anticipated or bearing zones and
encountered isolate abnormal
geologic pressure intervals
characteristics or from normal
wellbore conditions. pressure intervals
in the well.
As a minimum, you
must cement the
annular space 500
feet above the
casing shoe and 500
feet above each
zone to be
isolated.
(e) Production.............. Design casing and Use enough cement to
select setting cover or isolate
depth based on all hydrocarbon-
anticipated or bearing zones above
encountered the shoe.
geologic As a minimum, you
characteristics or must cement the
wellbore conditions. annular space at
least 500 feet
above the casing
shoe and 500 feet
above the uppermost
hydrocarbon-bearing
zone.
(f) Liners.................. If you use a liner Same as cementing
as conductor or requirements for
surface casing, you specific casing
must set the top of types. For example,
the liner at least a liner used as
200 feet above the intermediate casing
previous casing/ must be cemented
liner shoe. according to the
If you use a liner cementing
as an intermediate requirements for
string below a intermediate
surface string or casing.
production casing
below an
intermediate
string, you must
set the top of the
liner at least 100
feet above the
previous casing
shoe.
------------------------------------------------------------------------
Sec. 250.422 When may I resume drilling after cementing?
(a) After cementing surface, intermediate, or production casing (or
liners), you may resume drilling after the cement has been held under
pressure for 12 hours. For conductor casing, you may resume drilling
after the cement has been held under pressure for 8 hours. One
acceptable method of holding cement under pressure is to use float
valves to hold the cement in place.
(b) If you plan to nipple down your diverter or BOP stack during
the 8- or 12-hour waiting time, you must determine, before nippling
down, when it will be safe to do so. You must base your determination
on a knowledge of formation conditions, cement composition, effects of
nippling down, presence of potential drilling hazards, well conditions
during drilling, cementing, and post cementing, as well as past
experience.
Sec. 250.423 What are the requirements for pressure testing casing?
(a) The table in this section describes the minimum test pressures
for each string of casing. You may not resume drilling or other down-
hole operations until you obtain a satisfactory pressure test. If the
pressure declines more than 10 percent in a 30-minute test, or if there
is another indication of a leak, you must re-cement, repair the casing,
or run additional casing to provide a proper seal. The District Manager
may approve or require other casing test pressures.
------------------------------------------------------------------------
Casing type Minimum test pressure
------------------------------------------------------------------------
(1) Drive or Structural................ Not required.
(2) Conductor.......................... 200 psi.
(3) Surface, Intermediate, and 70 percent of its minimum
Production. internal yield.
------------------------------------------------------------------------
(b) You must ensure proper installation of casing or liner in the
subsea wellhead or liner hanger.
(1) You must ensure that the latching mechanisms or lock down
mechanisms are engaged upon installation of each casing string or
liner.
(2) You must perform a pressure test on the casing seal assembly to
ensure proper installation of casing or liner. You must perform this
test for the
[[Page 64518]]
intermediate and production casing strings or liner.
(3) You must submit for approval with your APD, test procedures and
criteria for a successful test.
(4) You must document all your test results and make them available
to BSEE upon request.
(c) You must perform a negative pressure test on all wells to
ensure proper casing installation. You must perform this test for the
intermediate and production casing strings.
(1) You must submit for approval with your APD, test procedures and
criteria for a successful test.
(2) You must document all your test results and make them available
to BSEE upon request.
Sec. 250.424 What are the requirements for prolonged drilling
operations?
If wellbore operations continue for more than 30 days within a
casing string run to the surface:
(a) You must stop drilling operations as soon as practicable, and
evaluate the effects of the prolonged operations on continued drilling
operations and the life of the well. At a minimum, you must:
(1) Caliper or pressure test the casing; and
(2) Report the results of your evaluation to the District Manager
and obtain approval of those results before resuming operations.
(b) If casing integrity has deteriorated to a level below minimum
safety factors, you must:
(1) Repair the casing or run another casing string; and
(2) Obtain approval from the District Manager before you begin
repairs.
Sec. 250.425 What are the requirements for pressure testing liners?
(a) You must test each drilling liner (and liner-lap) to a pressure
at least equal to the anticipated pressure to which the liner will be
subjected during the formation pressure-integrity test below that liner
shoe, or subsequent liner shoes if set. The District Manager may
approve or require other liner test pressures.
(b) You must test each production liner (and liner-lap) to a
minimum of 500 psi above the formation fracture pressure at the casing
shoe into which the liner is lapped.
(c) You may not resume drilling or other down-hole operations until
you obtain a satisfactory pressure test. If the pressure declines more
than 10 percent in a 30-minute test or if there is another indication
of a leak, you must re-cement, repair the liner, or run additional
casing/liner to provide a proper seal.
Sec. 250.426 What are the recordkeeping requirements for casing and
liner pressure tests?
You must record the time, date, and results of each pressure test
in the driller's report maintained under standard industry practice. In
addition, you must record each test on a pressure chart and have your
onsite representative sign and date the test as being correct.
Sec. 250.427 What are the requirements for pressure integrity tests?
You must conduct a pressure integrity test below the surface casing
or liner and all intermediate casings or liners. The District Manager
may require you to run a pressure-integrity test at the conductor
casing shoe if warranted by local geologic conditions or the planned
casing setting depth. You must conduct each pressure integrity test
after drilling at least 10 feet but no more than 50 feet of new hole
below the casing shoe. You must test to either the formation leak-off
pressure or to an equivalent drilling fluid weight if identified in an
approved APD.
(a) You must use the pressure integrity test and related hole-
behavior observations, such as pore-pressure test results, gas-cut
drilling fluid, and well kicks to adjust the drilling fluid program and
the setting depth of the next casing string. You must record all test
results and hole-behavior observations made during the course of
drilling related to formation integrity and pore pressure in the
driller's report.
(b) While drilling, you must maintain the safe drilling margin
identified in the approved APD. When you cannot maintain this safe
margin, you must suspend drilling operations and remedy the situation.
Sec. 250.428 What must I do in certain cementing and casing
situations?
The table in this section describes actions that lessees must take
when certain situations occur during casing and cementing activities.
------------------------------------------------------------------------
If you encounter the following situation: Then you must . . .
------------------------------------------------------------------------
(a) Have unexpected formation pressures or Submit a revised casing
conditions that warrant revising your program to the District
casing design, Manager for approval.
(b) Need to increase casing setting depths Submit those changes to the
more than 100 feet true vertical depth District Manager for
(TVD) from the approved APD due to approval.
conditions encountered during drilling
operations,
(c) Have indication of inadequate cement (1) Pressure test the casing
job (such as lost returns, cement shoe; (2) Run a temperature
channeling, or failure of equipment), survey; (3) Run a cement
bond log; or (4) Use a
combination of these
techniques.
(d) Inadequate cement job, Re-cement or take other
remedial actions as
approved by the District
Manager.
(e) Primary cement job that did not Isolate those intervals from
isolate abnormal pressure intervals, normal pressures by squeeze
cementing before you
complete; suspend
operations; or abandon the
well, whichever occurs
first.
(f) Decide to produce a well that was not Have at least two cemented
originally contemplated for production, casing strings (does not
include liners) in the
well. Note: All producing
wells must have at least
two cemented casing
strings.
(g) Want to drill a well without setting Submit geologic data and
conductor casing, information to the District
Manager that demonstrates
the absence of shallow
hydrocarbons or hazards.
This information must
include logging and
drilling fluid-monitoring
from wells previously
drilled within 500 feet of
the proposed well path down
to the next casing point.
(h) Need to use less than required cement Submit information to the
for the surface casing during floating District Manager that
drilling operations to provide protection demonstrates the use of
from burst and collapse pressures, less cement is necessary.
(i) Cement across a permafrost zone, Use cement that sets before
it freezes and has a low
heat of hydration.
[[Page 64519]]
(j) Leave the annulus opposite a Fill the annulus with a
permafrost zone uncemented, liquid that has a freezing
point below the minimum
permafrost temperature and
minimizes opposite a
corrosion.
------------------------------------------------------------------------
Diverter System Requirements
Sec. 250.430 When must I install a diverter system?
You must install a diverter system before you drill a conductor or
surface hole. The diverter system consists of a diverter sealing
element, diverter lines, and control systems. You must design, install,
use, maintain, and test the diverter system to ensure proper diversion
of gases, water, drilling fluid, and other materials away from
facilities and personnel.
Sec. 250.431 What are the diverter design and installation
requirements?
You must design and install your diverter system to:
(a) Use diverter spool outlets and diverter lines that have a
nominal diameter of at least 10 inches for surface wellhead
configurations and at least 12 inches for floating drilling operations;
(b) Use dual diverter lines arranged to provide for downwind
diversion capability;
(c) Use at least two diverter control stations. One station must be
on the drilling floor. The other station must be in a readily
accessible location away from the drilling floor;
(d) Use only remote-controlled valves in the diverter lines. All
valves in the diverter system must be full-opening. You may not install
manual or butterfly valves in any part of the diverter system;
(e) Minimize the number of turns (only one 90-degree turn allowed
for each line for bottom-founded drilling units) in the diverter lines,
maximize the radius of curvature of turns, and target all right angles
and sharp turns;
(f) Anchor and support the entire diverter system to prevent
whipping and vibration; and
(g) Protect all diverter-control instruments and lines from
possible damage by thrown or falling objects.
Sec. 250.432 How do I obtain a departure to diverter design and
installation requirements?
The table below describes possible departures from the diverter
requirements and the conditions required for each departure. To obtain
one of these departures, you must have discussed the departure in your
APD and received approval from the District Manager.
------------------------------------------------------------------------
If you want a departure to: Then you must . . .
------------------------------------------------------------------------
(a) Use flexible hose for diverter lines Use flexible hose that has
instead of rigid pipe, integral end couplings.
(b) Use only one spool outlet for your (1) Have branch lines that
diverter system, meet the minimum internal
diameter requirements; and
(2) Provide downwind
diversion capability.
(c) Use a spool with an outlet with an Use a spool that has dual
internal diameter of less than 10 inches outlets with an internal
on a surface wellhead, diameter of at least 8
inches.
(d) Use a single diverter line for Maintain an appropriate
floating drilling operations on a vessel heading to provide
dynamically positioned drillship, for downwind diversion.
------------------------------------------------------------------------
Sec. 250.433 What are the diverter actuation and testing
requirements?
When you install the diverter system, you must actuate the diverter
sealing element, diverter valves, and diverter-control systems and
control stations. You must also flow-test the vent lines.
(a) For drilling operations with a surface wellhead configuration,
you must actuate the diverter system at least once every 24-hour period
after the initial test. After you have nippled up on conductor casing,
you must pressure-test the diverter-sealing element and diverter valves
to a minimum of 200 psi. While the diverter is installed, you must
conduct subsequent pressure tests within 7 days after the previous
test.
(b) For floating drilling operations with a subsea BOP stack, you
must actuate the diverter system within 7 days after the previous
actuation.
(c) You must alternate actuations and tests between control
stations.
Sec. 250.434 What are the recordkeeping requirements for diverter
actuations and tests?
You must record the time, date, and results of all diverter
actuations and tests in the driller's report. In addition, you must:
(a) Record the diverter pressure test on a pressure chart;
(b) Require your onsite representative to sign and date the
pressure test chart;
(c) Identify the control station used during the test or actuation;
(d) Identify problems or irregularities observed during the testing
or actuations and record actions taken to remedy the problems or
irregularities; and
(e) Retain all pressure charts and reports pertaining to the
diverter tests and actuations at the facility for the duration of
drilling the well.
Blowout Preventer (BOP) System Requirements
Sec. 250.440 What are the general requirements for BOP systems and
system components?
You must design, install, maintain, test, and use the BOP system
and system components to ensure well control. The working-pressure
rating of each BOP component must exceed maximum anticipated surface
pressures. The BOP system includes the BOP stack and associated BOP
systems and equipment.
Sec. 250.441 What are the requirements for a surface BOP stack?
(a) When you drill with a surface BOP stack, you must install the
BOP system before drilling below surface casing. The surface BOP stack
must include at least four remote-controlled, hydraulically operated
BOPs, consisting of an annular BOP, two BOPs equipped with pipe rams,
and one BOP equipped with blind or blind-shear rams.
(b) Your surface BOP stack must include at least four remote-
controlled, hydraulically operated BOPs consisting of an annular BOP,
two BOPs equipped with pipe rams, and one BOP equipped with blind-shear
rams. The blind-shear rams must be capable of shearing the drill pipe
that is in the hole.
(c) You must install an accumulator system that provides 1.5 times
the volume of fluid capacity necessary to close and hold closed all BOP
components. The system must perform with a minimum pressure of 200 psi
above the precharge pressure without assistance from a charging system.
If you supply the accumulator regulators by rig air and do not have a
secondary source of pneumatic supply, you must equip the regulators
with manual
[[Page 64520]]
overrides or other devices to ensure capability of hydraulic operations
if rig air is lost.
(d) In addition to the stack and accumulator system, you must
install the associated BOP systems and equipment required by the
regulations in this subpart.
Sec. 250.442 What are the requirements for a subsea BOP system?
When you drill with a subsea BOP system, you must install the BOP
system before drilling below the surface casing. The District Manager
may require you to install a subsea BOP system before drilling below
the conductor casing if proposed casing setting depths or local geology
indicate the need. The table in this paragraph outlines your
requirements.
------------------------------------------------------------------------
When drilling with a subsea BOP system,
you must: Additional requirements
------------------------------------------------------------------------
(a) Have at least four remote- You must have at least one
controlled, hydraulically operated annular BOP, two BOPs equipped
BOPs. with pipe rams, and one BOP
equipped with blind-shear
rams. The blind-shear rams
must be capable of shearing
any drill pipe in the hole
under maximum anticipated
surface pressures.
(b) Have an operable dual-pod control ...............................
system to ensure proper and
independent operation of the BOP
system.
(c) Have an accumulator system to The accumulator system must
provide fast closure of the BOP meet or exceed the provisions
components and to operate all critical of Section 13.3, Accumulator
functions in case of a loss of the Volumetric Capacity, in API RP
power fluid connection to the surface. 53, Recommended Practices for
Blowout Prevention Equipment
Systems for Drilling Wells (as
incorporated by reference in
Sec. 250.198). The District
Manager may approve a suitable
alternate method.
(d) Have a subsea BOP stack equipped At a minimum, the ROV must be
with remotely operated vehicle (ROV) capable of closing one set of
intervention capability. pipe rams, closing one set of
blind-shear rams and
unlatching the LMRP.
(e) Maintain an ROV and have a trained The crew must be trained in the
ROV crew on each floating drilling rig operation of the ROV. The
on a continuous basis. The crew must training must include
examine all ROV related well control simulator training on stabbing
equipment (both surface and subsea) to into an ROV intervention panel
ensure that it is properly maintained on a subsea BOP stack.
and capable of shutting in the well
during emergency operations.
(f) Provide autoshear and deadman (1) Autoshear system means a
systems for dynamically positioned safety system that is designed
rigs. to automatically shut in the
wellbore in the event of a
disconnect of the LMRP. When
the autoshear is armed, a
disconnect of the LMRP closes
the shear rams. This is
considered a ``rapid
discharge'' system.
(2) Deadman System means a
safety system that is designed
to automatically close the
wellbore in the event of a
simultaneous absence of
hydraulic supply and signal
transmission capacity in both
subsea control pods. This is
considered a ``rapid
discharge'' system.
(3) You may also have an
acoustic system.
(g) Have operational or physical Incorporate enable buttons on
barrier(s) on BOP control panels to control panels to ensure two-
prevent accidental disconnect handed operation for all
functions. critical functions.
(h) Clearly label all control panels Label other BOP control panels
for the subsea BOP system. such as hydraulic control
panel.
(i) Develop and use a management system The management system must
for operating the BOP system, include written procedures for
including the prevention of accidental operating the BOP stack and
or unplanned disconnects of the system. LMRP (including proper
techniques to prevent
accidental disconnection of
these components) and minimum
knowledge requirements for
personnel authorized to
operate and maintain BOP
components.
(j) Establish minimum requirements for Personnel must have:
personnel authorized to operate
critical BOP equipment.
(1) Training in deepwater well
control theory and practice
according to the requirements
of 30 CFR 250, subpart O; and
(2) A comprehensive knowledge
of BOP hardware and control
systems.
(k) Before removing the marine riser, You must maintain sufficient
displace the fluid in the riser with hydrostatic pressure or take
seawater. other suitable precautions to
compensate for the reduction
in pressure and to maintain a
safe and controlled well
condition.
(l) Install the BOP stack in a glory Your glory hole must be deep
hole when in ice-scour area. enough to ensure that the top
of the stack is below the
deepest probable ice-scour
depth.
------------------------------------------------------------------------
Sec. 250.443 What associated systems and related equipment must all
BOP systems include?
All BOP systems must include the following associated systems and
related equipment:
(a) An automatic backup to the primary accumulator-charging system.
The power source must be independent from the power source for the
primary accumulator-charging system. The independent power source must
possess sufficient capability to close and hold closed all BOP
components.
(b) At least two BOP control stations. One station must be on the
drilling floor. You must locate the other station in a readily
accessible location away from the drilling floor.
(c) Side outlets on the BOP stack for separate kill and choke
lines. If your stack does not have side outlets, you must install a
drilling spool with side outlets.
(d) A choke and a kill line on the BOP stack. You must equip each
line with two full-opening valves, one of which must be remote-
controlled. For a subsea BOP system, both valves in each line must be
remote-controlled. In addition:
(1) You must install the choke line above the bottom ram;
(2) You may install the kill line below the bottom ram; and
(3) For a surface BOP system, on the kill line you may install a
check valve and a manual valve instead of the
[[Page 64521]]
remote-controlled valve. To use this configuration, both manual valves
must be readily accessible and you must install the check valve between
the manual valves and the pump.
(e) A fill-up line above the uppermost BOP.
(f) Locking devices installed on the ram-type BOPs.
(g) A wellhead assembly with a rated working pressure that exceeds
the maximum anticipated surface pressure.
Sec. 250.444 What are the choke manifold requirements?
(a) Your BOP system must include a choke manifold that is suitable
for the anticipated surface pressures, anticipated methods of well
control, the surrounding environment, and the corrosiveness, volume,
and abrasiveness of drilling fluids and well fluids that you may
encounter.
(b) Choke manifold components must have a rated working pressure at
least as great as the rated working pressure of the ram BOPs. If your
choke manifold has buffer tanks downstream of choke assemblies, you
must install isolation valves on any bleed lines.
(c) Valves, pipes, flexible steel hoses, and other fittings
upstream of the choke manifold must have a rated working pressure at
least as great as the rated working pressure of the ram BOPs.
Sec. 250.445 What are the requirements for kelly valves, inside BOPs,
and drill-string safety valves?
You must use or provide the following BOP equipment during drilling
operations:
(a) A kelly valve installed below the swivel (upper kelly valve);
(b) A kelly valve installed at the bottom of the kelly (lower kelly
valve). You must be able to strip the lower kelly valve through the BOP
stack;
(c) If you drill with a mud motor and use drill pipe instead of a
kelly, you must install one kelly valve above, and one strippable kelly
valve below, the joint of drill pipe used in place of a kelly;
(d) On a top-drive system equipped with a remote-controlled valve,
you must install a strippable kelly-type valve below the remote-
controlled valve;
(e) An inside BOP in the open position located on the rig floor.
You must be able to install an inside BOP for each size connection in
the drill string;
(f) A drill-string safety valve in the open position located on the
rig floor. You must have a drill-string safety valve available for each
size connection in the drill string;
(g) When running casing, you must have a safety valve in the open
position available on the rig floor to fit the casing string being run
in the hole;
(h) All required manual and remote-controlled kelly valves, drill-
string safety valves, and comparable-type valves (i.e., kelly-type
valve in a top-drive system) must be essentially full-opening; and
(i) The drilling crew must have ready access to a wrench to fit
each manual valve.
Sec. 250.446 What are the BOP maintenance and inspection
requirements?
(a) You must maintain and inspect your BOP system to ensure that
the equipment functions properly. The BOP maintenance and inspections
must meet or exceed the provisions of Sections 17.10 and 18.10,
Inspections; Sections 17.11 and 18.11, Maintenance; and Sections 17.12
and 18.12, Quality Management, described in API RP 53, Recommended
Practices for Blowout Prevention Equipment Systems for Drilling Wells
(as incorporated by reference in Sec. 250.198). You must document the
procedures used, record the results of your BOP inspections and
maintenance actions, and make available to BSEE upon request. You must
maintain your records on the rig for 2 years or from the date of your
last major inspection, whichever is longer;
(b) You must visually inspect your surface BOP system on a daily
basis. You must visually inspect your subsea BOP system and marine
riser at least once every 3 days if weather and sea conditions permit.
You may use television cameras to inspect subsea equipment.
Sec. 250.447 When must I pressure test the BOP system?
You must pressure test your BOP system (this includes the choke
manifold, kelly valves, inside BOP, and drill-string safety valve):
(a) When installed;
(b) Before 14 days have elapsed since your last BOP pressure test.
You must begin to test your BOP system before midnight on the 14th day
following the conclusion of the previous test. However, the District
Manager may require more frequent testing if conditions or BOP
performance warrant; and
(c) Before drilling out each string of casing or a liner. The
District Manager may allow you to omit this test if you didn't remove
the BOP stack to run the casing string or liner and the required BOP
test pressures for the next section of the hole are not greater than
the test pressures for the previous BOP test. You must indicate in your
APD which casing strings and liners meet these criteria.
Sec. 250.448 What are the BOP pressure tests requirements?
When you pressure test the BOP system, you must conduct a low-
pressure and a high-pressure test for each BOP component. You must
conduct the low-pressure test before the high-pressure test. Each
individual pressure test must hold pressure long enough to demonstrate
that the tested component(s) holds the required pressure. Required test
pressures are as follows:
(a) Low-pressure test. All low-pressure tests must be between 200
and 300 psi. Any initial pressure above 300 psi must be bled back to a
pressure between 200 and 300 psi before starting the test. If the
initial pressure exceeds 500 psi, you must bleed back to zero and
reinitiate the test.
(b) High-pressure test for ram-type BOPs, the choke manifold, and
other BOP components. The high-pressure test must equal the rated
working pressure of the equipment or be 500 psi greater than your
calculated maximum anticipated surface pressure (MASP) for the
applicable section of hole. Before you may test BOP equipment to the
MASP plus 500 psi, the District Manager must have approved those test
pressures in your APD.
(c) High pressure test for annular-type BOPs. The high pressure
test must equal 70 percent of the rated working pressure of the
equipment or to a pressure approved in your APD.
(d) Duration of pressure test. Each test must hold the required
pressure for 5 minutes. However, for surface BOP systems and surface
equipment of a subsea BOP system, a 3-minute test duration is
acceptable if you record your test pressures on the outermost half of a
4-hour chart, on a 1-hour chart, or on a digital recorder. If the
equipment does not hold the required pressure during a test, you must
correct the problem and retest the affected component(s).
Sec. 250.449 What additional BOP testing requirements must I meet?
You must meet the following additional BOP testing requirements:
(a) Use water to test a surface BOP system;
(b) Stump test a subsea BOP system before installation. You must
use water to conduct this test. You may use drilling fluids to conduct
subsequent tests of a subsea BOP system;
(c) Alternate tests between control stations and pods;
(d) Pressure test the blind or blind-shear ram BOP during stump
tests and at all casing points;
[[Page 64522]]
(e) The interval between any blind or blind-shear ram BOP pressure
tests may not exceed 30 days;
(f) Pressure test variable bore-pipe ram BOPs against the largest
and smallest sizes of pipe in use, excluding drill collars and bottom-
hole tools;
(g) Pressure test affected BOP components following the
disconnection or repair of any well-pressure containment seal in the
wellhead or BOP stack assembly;
(h) Function test annular and ram BOPs every 7 days between
pressure tests;
(i) Actuate safety valves assembled with proper casing connections
before running casing;
(j) Test all ROV intervention functions on your subsea BOP stack
during the stump test. You must also test at least one set of rams
during the initial test on the seafloor. You must submit test
procedures with your APD or APM for District Manager approval. You
must:
(1) ensure that the ROV hot stabs are function tested and are
capable of actuating, at a minimum, one set of pipe rams and one set of
blind-shear rams and unlatching the LMRP; and
(2) document all your test results and make them available to BSEE
upon request;
(k) Function test autoshear and deadman systems on your subsea BOP
stack during the stump test. You must also test the deadman system
during the initial test on the seafloor.
(1) You must submit test procedures with your APD or APM for
District Manager approval.
(2) You must document all your test results and make them available
to BSEE upon request.
Sec. 250.450 What are the recordkeeping requirements for BOP tests?
You must record the time, date, and results of all pressure tests,
actuations, and inspections of the BOP system, system components, and
marine riser in the driller's report. In addition, you must:
(a) Record BOP test pressures on pressure charts;
(b) Require your onsite representative to sign and date BOP test
charts and reports as correct;
(c) Document the sequential order of BOP and auxiliary equipment
testing and the pressure and duration of each test. For subsea BOP
systems, you must also record the closing times for annular and ram
BOPs. You may reference a BOP test plan if it is available at the
facility;
(d) Identify the control station and pod used during the test;
(e) Identify any problems or irregularities observed during BOP
system testing and record actions taken to remedy the problems or
irregularities; and
(f) Retain all records, including pressure charts, driller's
report, and referenced documents pertaining to BOP tests, actuations,
and inspections at the facility for the duration of drilling.
Sec. 250.451 What must I do in certain situations involving BOP
equipment or systems?
The table in this section describes actions that lessees must take
when certain situations occur with BOP systems during drilling
activities.
------------------------------------------------------------------------
If you encounter the following situation: Then you must . . .
------------------------------------------------------------------------
(a) BOP equipment does not hold the Correct the problem and
required pressure during a test, retest the affected
equipment.
(b) Need to repair or replace a surface or First place the well in a
subsea BOP system, safe, controlled condition
(e.g., before drilling out
a casing shoe or after
setting a cement plug,
bridge plug, or a packer).
(c) Need to postpone a BOP test due to Record the reason for
well-control problems such as lost postponing the test in the
circulation, formation fluid influx, or driller's report and
stuck drill pipe, conduct the required BOP
test on the first trip out
of the hole.
(d) BOP control station or pod that does Suspend further drilling
not function properly, operations until that
station or pod is operable.
(e) Want to drill with a tapered drill- Install two or more sets of
string, conventional or variable-
bore pipe rams in the BOP
stack to provide for the
following: two sets of rams
must be capable of sealing
around the larger-size
drill string and one set of
pipe rams must be capable
of sealing around the
smaller-size drill string.
(f) Install casing rams in a BOP stack, Test the ram bonnets before
running casing.
(g) Want to use an annular BOP with a Demonstrate that your well
rated working pressure less than the control procedures or the
anticipated surface pressure, anticipated well conditions
will not place demands
above its rated working
pressure and obtain
approval from the District
Manager.
(h) Use a subsea BOP system in an ice- Install the BOP stack in a
scour area, glory hole. The glory hole
must be deep enough to
ensure that the top of the
stack is below the deepest
probable ice-scour depth.
(i) You activate blind-shear rams or Retrieve, physically
casing shear rams during a well control inspect, and conduct a full
situation, in which pipe or casing is pressure test of the BOP
sheared, stack after the situation
is fully controlled.
------------------------------------------------------------------------
Drilling Fluid Requirements
Sec. 250.455 What are the general requirements for a drilling fluid
program?
You must design and implement your drilling fluid program to
prevent the loss of well control. This program must address drilling
fluid safe practices, testing and monitoring equipment, drilling fluid
quantities, and drilling fluid-handling areas.
Sec. 250.456 What safe practices must the drilling fluid program
follow?
Your drilling fluid program must include the following safe
practices:
(a) Before starting out of the hole with drill pipe, you must
properly condition the drilling fluid. You must circulate a volume of
drilling fluid equal to the annular volume with the drill pipe just
off-bottom. You may omit this practice if documentation in the
driller's report shows:
(1) No indication of formation fluid influx before starting to pull
the drill pipe from the hole;
(2) The weight of returning drilling fluid is within 0.2 pounds per
gallon (1.5 pounds per cubic foot) of the drilling fluid entering the
hole; and
(3) Other drilling fluid properties are within the limits
established by the program approved in the APD.
(b) Record each time you circulate drilling fluid in the hole in
the driller's report;
(c) When coming out of the hole with drill pipe, you must fill the
annulus with drilling fluid before the hydrostatic pressure decreases
by 75 psi, or every five stands of drill pipe, whichever gives a lower
decrease in hydrostatic pressure. You must calculate the number of
stands of drill pipe and drill collars that you may pull before you
[[Page 64523]]
must fill the hole. You must also calculate the equivalent drilling
fluid volume needed to fill the hole. Both sets of numbers must be
posted near the driller's station. You must use a mechanical,
volumetric, or electronic device to measure the drilling fluid required
to fill the hole;
(d) You must run and pull drill pipe and downhole tools at
controlled rates so you do not swab or surge the well;
(e) When there is an indication of swabbing or influx of formation
fluids, you must take appropriate measures to control the well. You
must circulate and condition the well, on or near-bottom, unless well
or drilling-fluid conditions prevent running the drill pipe back to the
bottom;
(f) You must calculate and post near the driller's console the
maximum pressures that you may safely contain under a shut-in BOP for
each casing string. The pressures posted must consider the surface
pressure at which the formation at the shoe would break down, the rated
working pressure of the BOP stack, and 70 percent of casing burst (or
casing test as approved by the District Manager). As a minimum, you
must post the following two pressures:
(1) The surface pressure at which the shoe would break down. This
calculation must consider the current drilling fluid weight in the
hole; and
(2) The lesser of the BOP's rated working pressure or 70 percent of
casing-burst pressure (or casing test otherwise approved by the
District Manager);
(g) You must install an operable drilling fluid-gas separator and
degasser before you begin drilling operations. You must maintain this
equipment throughout the drilling of the well;
(h) Before pulling drill-stem test tools from the hole, you must
circulate or reverse-circulate the test fluids in the hole. If
circulating out test fluids is not feasible, you may bullhead test
fluids out of the drill-stem test string and tools with an appropriate
kill weight fluid;
(i) When circulating, you must test the drilling fluid at least
once each tour, or more frequently if conditions warrant. Your tests
must conform to industry-accepted practices and include density,
viscosity, and gel strength; hydrogenion concentration; filtration; and
any other tests the District Manager requires for monitoring and
maintaining drilling fluid quality, prevention of downhole equipment
problems and for kick detection. You must record the results of these
tests in the drilling fluid report;
(j) Before displacing kill-weight drilling fluid from the wellbore,
you must obtain prior approval from the District Manager. To obtain
approval, you must submit with your APD or APM your reasons for
displacing the kill-weight drilling fluid and provide detailed step-by-
step written procedures describing how you will safely displace these
fluids. The step-by-step displacement procedures must address the
following:
(1) number and type of independent barriers that are in place for
each flow path,
(2) tests you will conduct to ensure integrity of independent
barriers,
(3) BOP procedures you will use while displacing kill weight
fluids, and
(4) procedures you will use to monitor fluids entering and leaving
the wellbore; and
(k) In areas where permafrost and/or hydrate zones are present or
may be present, you must control drilling fluid temperatures to drill
safely through those zones.
Sec. 250.457 What equipment is required to monitor drilling fluids?
Once you establish drilling fluid returns, you must install and
maintain the following drilling fluid-system monitoring equipment
throughout subsequent drilling operations. This equipment must have the
following indicators on the rig floor:
(a) Pit level indicator to determine drilling fluid-pit volume
gains and losses. This indicator must include both a visual and an
audible warning device;
(b) Volume measuring device to accurately determine drilling fluid
volumes required to fill the hole on trips;
(c) Return indicator devices that indicate the relationship between
drilling fluid-return flow rate and pump discharge rate. This indicator
must include both a visual and an audible warning device; and
(d) Gas-detecting equipment to monitor the drilling fluid returns.
The indicator may be located in the drilling fluid-logging compartment
or on the rig floor. If the indicators are only in the logging
compartment, you must continually man the equipment and have a means of
immediate communication with the rig floor. If the indicators are on
the rig floor only, you must install an audible alarm.
Sec. 250.458 What quantities of drilling fluids are required?
(a) You must use, maintain, and replenish quantities of drilling
fluid and drilling fluid materials at the drill site as necessary to
ensure well control. You must determine those quantities based on known
or anticipated drilling conditions, rig storage capacity, weather
conditions, and estimated time for delivery.
(b) You must record the daily inventories of drilling fluid and
drilling fluid materials, including weight materials and additives in
the drilling fluid report.
(c) If you do not have sufficient quantities of drilling fluid and
drilling fluid material to maintain well control, you must suspend
drilling operations.
Sec. 250.459 What are the safety requirements for drilling fluid-
handling areas?
You must classify drilling fluid-handling areas according to API RP
500, Recommended Practice for Classification of Locations for
Electrical Installations at Petroleum Facilities, Classified as Class
I, Division 1 and Division 2 (as incorporated by reference in Sec.
250.198); or API RP 505, Recommended Practice for Classification of
Locations for Electrical Installations at Petroleum Facilities,
Classified as Class 1, Zone 0, Zone 1, and Zone 2 (as incorporated by
reference in Sec. 250.198). In areas where dangerous concentrations of
combustible gas may accumulate, you must install and maintain a
ventilation system and gas monitors. Drilling fluid-handling areas must
have the following safety equipment:
(a) A ventilation system capable of replacing the air once every 5
minutes or 1.0 cubic feet of air-volume flow per minute, per square
foot of area, whichever is greater. In addition:
(1) If natural means provide adequate ventilation, then a
mechanical ventilation system is not necessary;
(2) If a mechanical system does not run continuously, then it must
activate when gas detectors indicate the presence of 1 percent or more
of combustible gas by volume; and
(3) If discharges from a mechanical ventilation system may be
hazardous, then you must maintain the drilling fluid-handling area at a
negative pressure. You must protect the negative pressure area by using
at least one of the following: a pressure-sensitive alarm, open-door
alarms on each access to the area, automatic door-closing devices, air
locks, or other devices approved by the District Manager;
(b) Gas detectors and alarms except in open areas where adequate
ventilation is provided by natural means. You must test and recalibrate
gas detectors quarterly. No more than 90 days may elapse between tests;
(c) Explosion-proof or pressurized electrical equipment to prevent
the ignition of explosive gases. Where you use air for pressuring
equipment, you must locate the air intake outside of and
[[Page 64524]]
as far as practicable from hazardous areas; and
(d) Alarms that activate when the mechanical ventilation system
fails.
Other Drilling Requirements
Sec. 250.460 What are the requirements for conducting a well test?
(a) If you intend to conduct a well test, you must include your
projected plans for the test with your APD (form BSEE-0123) or in an
Application for Permit to Modify (APM) (form BSEE-0124). Your plans
must include at least the following information:
(1) Estimated flowing and shut-in tubing pressures;
(2) Estimated flow rates and cumulative volumes;
(3) Time duration of flow, buildup, and drawdown periods;
(4) Description and rating of surface and subsurface test
equipment;
(5) Schematic drawing, showing the layout of test equipment;
(6) Description of safety equipment, including gas detectors and
fire-fighting equipment;
(7) Proposed methods to handle or transport produced fluids; and
(8) Description of the test procedures.
(b) You must give the District Manager at least 24-hours notice
before starting a well test.
Sec. 250.461 What are the requirements for directional and
inclination surveys?
For this subpart, BSEE classifies a well as vertical if the
calculated average of inclination readings does not exceed 3 degrees
from the vertical.
(a) Survey requirements for a vertical well. (1) You must conduct
inclination surveys on each vertical well and record the results.
Survey intervals may not exceed 1,000 feet during the normal course of
drilling;
(2) You must also conduct a directional survey that provides both
inclination and azimuth, and digitally record the results in electronic
format:
(i) Within 500 feet of setting surface or intermediate casing;
(ii) Within 500 feet of setting any liner; and
(iii) When you reach total depth.
(b) Survey requirements for directional well. You must conduct
directional surveys on each directional well and digitally record the
results. Surveys must give both inclination and azimuth at intervals
not to exceed 500 feet during the normal course of drilling. Intervals
during angle-changing portions of the hole may not exceed 100 feet.
(c) Measurement while drilling. You may use measurement-while-
drilling technology if it meets the requirements of this section.
(d) Composite survey requirements. (1) Your composite directional
survey must show the interval from the bottom of the conductor casing
to total depth. In the absence of conductor casing, the survey must
show the interval from the bottom of the drive or structural casing to
total depth; and
(2) You must correct all surveys to Universal-Transverse-Mercator-
Grid-north or Lambert-Grid-north after making the magnetic-to-true-
north correction. Surveys must show the magnetic and grid corrections
used and include a listing of the directionally computed inclinations
and azimuths.
(e) If you drill within 500 feet of an adjacent lease, the Regional
Supervisor may require you to furnish a copy of the well's directional
survey to the affected leaseholder. This could occur when the adjoining
leaseholder requests a copy of the survey for the protection of
correlative rights.
Sec. 250.462 What are the requirements for well-control drills?
You must conduct a weekly well-control drill with each drilling
crew. Your drill must familiarize the crew with its roles and functions
so that all crew members can perform their duties promptly and
efficiently.
(a) Well-control drill plan. You must prepare a well control drill
plan for each well. Your plan must outline the assignments for each
crew member and establish times to complete each portion of the drill.
You must post a copy of the well control drill plan on the rig floor or
bulletin board.
(b) Timing of drills. You must conduct each drill during a period
of activity that minimizes the risk to drilling operations. The timing
of your drills must cover a range of different operations, including
drilling with a diverter, on-bottom drilling, and tripping.
(c) Recordkeeping requirements. For each drill, you must record the
following in the driller's report:
(1) The time to be ready to close the diverter or BOP system; and
(2) The total time to complete the entire drill.
(d) BSEE ordered drill. A BSEE authorized representative may
require you to conduct a well control drill during a BSEE inspection.
The BSEE representative will consult with your onsite representative
before requiring the drill.
Sec. 250.463 Who establishes field drilling rules?
(a) The District Manager may establish field drilling rules
different from the requirements of this subpart when geological and
engineering information shows that specific operating requirements are
appropriate. You must comply with field drilling rules and
nonconflicting requirements of this subpart. The District Manager may
amend or cancel field drilling rules at any time.
(b) You may request the District Manager to establish, amend, or
cancel field drilling rules.
Applying for a Permit To Modify and Well Records
Sec. 250.465 When must I submit an Application for Permit to Modify
(APM) or an End of Operations Report to BSEE?
(a) You must submit an APM (form BSEE-0124) or an End of Operations
Report (form BSEE-0125) and other materials to the Regional Supervisor
as shown in the following table. You must also submit a public
information copy of each form.
------------------------------------------------------------------------
When you . . . Then you must . . . And . . .
------------------------------------------------------------------------
(1) Intend to revise Submit form BSEE-0124 Receive written or oral
your drilling plan, or request oral approval from the
change major drilling approval, District Manager before
equipment, or you begin the intended
plugback, operation. If you get an
approval, you must
submit form BSEE-0124 no
later than the end of
the 3rd business day
following the oral
approval. In all cases,
or you must meet the
additional requirements
in paragraph (b) of this
section.
(2) Determine a well's Immediately Submit a Submit a plat certified
final surface form BSEE-0124, by a registered land
location, water surveyor that meets the
depth, and the rotary requirements of Sec.
kelly bushing 250.412.
elevation,
(3) Move a drilling Submit forms BSEE- Submit appropriate copies
unit from a wellbore 0124 and BSEE-0125 of the well records.
before completing a within 30 days after
well, the suspension of
wellbore operations,
------------------------------------------------------------------------
[[Page 64525]]
(b) If you intend to perform any of the actions specified in
paragraph (a)(1) of this section, you must meet the following
additional requirements:
(1) Your APM (Form BSEE-0124) must contain a detailed statement of
the proposed work that would materially change from the approved APD.
The submission of your APM must be accompanied by payment of the
service fee listed in Sec. 250.125;
(2) Your form BSEE-0124 must include the present status of the
well, depth of all casing strings set to date, well depth, present
production zones and productive capability, and all other information
specified; and
(3) Within 30 days after completing this work, you must submit form
BSEE-0124 with detailed information about the work to the District
Manager, unless you have already provided sufficient information in a
Well Activity Report, form BSEE-0133 (Sec. 250.468(b)).
Sec. 250.466 What records must I keep?
You must keep complete, legible, and accurate records for each
well. You must keep drilling records onsite while drilling activities
continue. After completion of drilling activities, you must keep all
drilling and other well records for the time periods shown in Sec.
250.467. You may keep these records at a location of your choice. The
records must contain complete information on all of the following:
(a) Well operations;
(b) Descriptions of formations penetrated;
(c) Content and character of oil, gas, water, and other mineral
deposits in each formation;
(d) Kind, weight, size, grade, and setting depth of casing;
(e) All well logs and surveys run in the wellbore;
(f) Any significant malfunction or problem; and
(g) All other information required by the District Manager in the
interests of resource evaluation, waste prevention, conservation of
natural resources, and the protection of correlative rights, safety,
and environment.
Sec. 250.467 How long must I keep records?
You must keep records for the time periods shown in the following
table.
------------------------------------------------------------------------
You must keep records relating to . . . Until . . .
------------------------------------------------------------------------
(a) Drilling, Ninety days after you
complete drilling
operations.
(b) Casing and liner pressure tests, Two years after the
diverter tests, and BOP tests, completion of drilling
operations.
(c) Completion of a well or of any You permanently plug and
workover activity that materially alters abandon the well or until
the completion configuration or affects a you forward the records
hydrocarbon-bearing zone, with a lease assignment.
------------------------------------------------------------------------
Sec. 250.468 What well records am I required to submit?
(a) You must submit copies of logs or charts of electrical,
radioactive, sonic, and other well-logging operations; directional and
vertical-well surveys; velocity profiles and surveys; and analysis of
cores to BSEE. Each Region will provide specific instructions for
submitting well logs and surveys.
(b) For drilling operations in the GOM OCS Region, you must submit
form BSEE-0133, Well Activity Report, to the District Manager on a
weekly basis.
(c) For drilling operations in the Pacific or Alaska OCS Regions,
you must submit form BSEE-0133, Well Activity Report, to the District
Manager on a daily basis.
Sec. 250.469 What other well records could I be required to submit?
The District Manager or Regional Supervisor may require you to
submit copies of any or all of the following well records.
(a) Well records as specified in Sec. 250.466;
(b) Paleontological interpretations or reports identifying
microscopic fossils by depth and/or washed samples of drill cuttings
that you normally maintain for paleontological determinations. The
Regional Supervisor may issue a Notice to Lessees that prescribes the
manner, timeframe, and format for submitting this information;
(c) Service company reports on cementing, perforating, acidizing,
testing, or other similar services; or
(d) Other reports and records of operations.
Hydrogen Sulfide
Sec. 250.490 Hydrogen sulfide.
(a) What precautions must I take when operating in an H2S area? You
must:
(1) Take all necessary and feasible precautions and measures to
protect personnel from the toxic effects of H2S and to
mitigate damage to property and the environment caused by
H2S. You must follow the requirements of this section when
conducting drilling, well-completion/well-workover, and production
operations in zones with H2S present and when conducting
operations in zones where the presence of H2S is unknown.
You do not need to follow these requirements when operating in zones
where the absence of H2S has been confirmed; and
(2) Follow your approved contingency plan.
(b) Definitions. Terms used in this section have the following
meanings:
Facility means a vessel, a structure, or an artificial island used
for drilling, well-completion, well-workover, and/or production
operations.
H2S absent means:
(1) Drilling, logging, coring, testing, or producing operations
have confirmed the absence of H2S in concentrations that
could potentially result in atmospheric concentrations of 20 ppm or
more of H2S; or
(2) Drilling in the surrounding areas and correlation of geological
and seismic data with equivalent stratigraphic units have confirmed an
absence of H2S throughout the area to be drilled.
H2S present means that drilling, logging, coring, testing, or
producing operations have confirmed the presence of H2S in
concentrations and volumes that could potentially result in atmospheric
concentrations of 20 ppm or more of H2S.
H2S unknown means the designation of a zone or geologic formation
where neither the presence nor absence of H2S has been
confirmed.
Well-control fluid means drilling mud and completion or workover
fluid as appropriate to the particular operation being conducted.
(c) Classifying an area for the presence of H2S. You must:
(1) Request and obtain an approved classification for the area from
the Regional Supervisor before you begin operations. Classifications
are ``H2S absent,'' H2S present,'' or
``H2S unknown'';
(2) Submit your request with your application for permit to drill;
(3) Support your request with available information such as
geologic and geophysical data and correlations, well logs, formation
tests, cores and analysis of formation fluids; and
(4) Submit a request for reclassification of a zone when additional
data indicate a different classification is needed.
[[Page 64526]]
(d) What do I do if conditions change? If you encounter
H2S that could potentially result in atmospheric
concentrations of 20 ppm or more in areas not previously classified as
having H2S present, you must immediately notify BSEE and
begin to follow requirements for areas with H2S present.
(e) What are the requirements for conducting simultaneous
operations? When conducting any combination of drilling, well-
completion, well-workover, and production operations simultaneously,
you must follow the requirements in the section applicable to each
individual operation.
(f) Requirements for submitting an H2S Contingency Plan. Before you
begin operations, you must submit an H2S Contingency Plan to
the District Manager for approval. Do not begin operations before the
District Manager approves your plan. You must keep a copy of the
approved plan in the field, and you must follow the plan at all times.
Your plan must include:
(1) Safety procedures and rules that you will follow concerning
equipment, drills, and smoking;
(2) Training you provide for employees, contractors, and visitors;
(3) Job position and title of the person responsible for the
overall safety of personnel;
(4) Other key positions, how these positions fit into your
organization, and what the functions, duties, and responsibilities of
those job positions are;
(5) Actions that you will take when the concentration of
H2S in the atmosphere reaches 20 ppm, who will be
responsible for those actions, and a description of the audible and
visual alarms to be activated;
(6) Briefing areas where personnel will assemble during an H2S
alert. You must have at least two briefing areas on each facility and
use the briefing area that is upwind of the H2S source at
any given time;
(7) Criteria you will use to decide when to evacuate the facility
and procedures you will use to safely evacuate all personnel from the
facility by vessel, capsule, or lifeboat. If you use helicopters during
H2S alerts, describe the types of H2S emergencies
during which you consider the risk of helicopter activity to be
acceptable and the precautions you will take during the flights;
(8) Procedures you will use to safely position all vessels
attendant to the facility. Indicate where you will locate the vessels
with respect to wind direction. Include the distance from the facility
and what procedures you will use to safely relocate the vessels in an
emergency;
(9) How you will provide protective-breathing equipment for all
personnel, including contractors and visitors;
(10) The agencies and facilities you will notify in case of a
release of H2S (that constitutes an emergency), how you will
notify them, and their telephone numbers. Include all facilities that
might be exposed to atmospheric concentrations of 20 ppm or more of
H2S;
(11) The medical personnel and facilities you will use if needed,
their addresses, and telephone numbers;
(12) H2S detector locations in production facilities
producing gas containing 20 ppm or more of H2S. Include an
``H2S Detector Location Drawing'' showing:
(i) All vessels, flare outlets, wellheads, and other equipment
handling production containing H2S;
(ii) Approximate maximum concentration of H2S in the gas
stream; and
(iii) Location of all H2S sensors included in your
contingency plan;
(13) Operational conditions when you expect to flare gas containing
H2S including the estimated maximum gas flow rate,
H2S concentration, and duration of flaring;
(14) Your assessment of the risks to personnel during flaring and
what precautionary measures you will take;
(15) Primary and alternate methods to ignite the flare and
procedures for sustaining ignition and monitoring the status of the
flare (i.e., ignited or extinguished);
(16) Procedures to shut off the gas to the flare in the event the
flare is extinguished;
(17) Portable or fixed sulphur dioxide (SO2)-detection
system(s) you will use to determine SO2 concentration and
exposure hazard when H2S is burned;
(18) Increased monitoring and warning procedures you will take when
the SO2 concentration in the atmosphere reaches 2 ppm;
(19) Personnel protection measures or evacuation procedures you
will initiate when the SO2 concentration in the atmosphere
reaches 5 ppm;
(20) Engineering controls to protect personnel from SO2;
and
(21) Any special equipment, procedures, or precautions you will use
if you conduct any combination of drilling, well-completion, well-
workover, and production operations simultaneously.
(g) Training program: (1) When and how often do employees need to
be trained? All operators and contract personnel must complete an
H2S training program to meet the requirements of this
section:
(i) Before beginning work at the facility; and
(ii) Each year, within 1 year after completion of the previous
class.
(2) What training documentation do I need? For each individual
working on the platform, either:
(i) You must have documentation of this training at the facility
where the individual is employed; or
(ii) The employee must carry a training completion card.
(3) What training do I need to give to visitors and employees
previously trained on another facility?
(i) Trained employees or contractors transferred from another
facility must attend a supplemental briefing on your H2S
equipment and procedures before beginning duty at your facility;
(ii) Visitors who will remain on your facility more than 24 hours
must receive the training required for employees by paragraph (g)(4) of
this section; and
(iii) Visitors who will depart before spending 24 hours on the
facility are exempt from the training required for employees, but they
must, upon arrival, complete a briefing that includes:
(A) Information on the location and use of an assigned respirator;
practice in donning and adjusting the assigned respirator; information
on the safe briefing areas, alarm system, and hazards of H2S
and SO2; and
(B) Instructions on their responsibilities in the event of an
H2S release.
(4) What training must I provide to all other employees? You must
train all individuals on your facility on the:
(i) Hazards of H2S and of SO2 and the
provisions for personnel safety contained in the H2S
Contingency Plan;
(ii) Proper use of safety equipment which the employee may be
required to use;
(iii) Location of protective breathing equipment, H2S
detectors and alarms, ventilation equipment, briefing areas, warning
systems, evacuation procedures, and the direction of prevailing winds;
(iv) Restrictions and corrective measures concerning beards,
spectacles, and contact lenses in conformance with ANSI Z88.2, American
National Standard for Respiratory Protection (as specified in Sec.
250.198);
(v) Basic first-aid procedures applicable to victims of
H2S exposure. During all drills and training sessions, you
must address procedures for rescue and first aid for H2S
victims;
(vi) Location of:
(A) The first-aid kit on the facility;
(B) Resuscitators; and
[[Page 64527]]
(C) Litter or other device on the facility.
(vii) Meaning of all warning signals.
(5) Do I need to post safety information? You must prominently post
safety information on the facility and on vessels serving the facility
(i.e., basic first-aid, escape routes, instructions for use of life
boats, etc.).
(h) Drills. (1) When and how often do I need to conduct drills on
H2S safety discussions on the facility? You must:
(i) Conduct a drill for each person at the facility during normal
duty hours at least once every 7-day period. The drills must consist of
a dry-run performance of personnel activities related to assigned jobs.
(ii) At a safety meeting or other meetings of all personnel,
discuss drill performance, new H2S considerations at the
facility, and other updated H2S information at least
monthly.
(2) What documentation do I need? You must keep records of
attendance for:
(i) Drilling, well-completion, and well-workover operations at the
facility until operations are completed; and
(ii) Production operations at the facility or at the nearest field
office for 1 year.
(i) Visual and audible warning systems: (1) How must I install wind
direction equipment? You must install wind-direction equipment in a
location visible at all times to individuals on or in the immediate
vicinity of the facility.
(2) When do I need to display operational danger signs, display
flags, or activate visual or audible alarms?
(i) You must display warning signs at all times on facilities with
wells capable of producing H2S and on facilities that
process gas containing H2S in concentrations of 20 ppm or
more.
(ii) In addition to the signs, you must activate audible alarms and
display flags or activate flashing red lights when atmospheric
concentration of H2S reaches 20 ppm.
(3) What are the requirements for signs? Each sign must be a high-
visibility yellow color with black lettering as follows:
------------------------------------------------------------------------
Letter height Wording
------------------------------------------------------------------------
12 inches................................. Danger.
Poisonous Gas.
Hydrogen Sulfide.
7 inches.................................. Do not approach if red flag
is flying.
(Use appropriate wording at right)........ Do not approach if red
lights are flashing.
------------------------------------------------------------------------
(4) May I use existing signs? You may use existing signs
containing the words ``Danger-Hydrogen Sulfide-H2S,''
provided the words ``Poisonous Gas. Do Not Approach if Red Flag is
Flying'' or ``Red Lights are Flashing'' in lettering of a minimum of 7
inches in height are displayed on a sign immediately adjacent to the
existing sign.
(5) What are the requirements for flashing lights or flags? You
must activate a sufficient number of lights or hoist a sufficient
number of flags to be visible to vessels and aircraft. Each light must
be of sufficient intensity to be seen by approaching vessels or
aircraft any time it is activated (day or night). Each flag must be
red, rectangular, a minimum width of 3 feet, and a minimum height of 2
feet.
(6) What is an audible warning system? An audible warning system is
a public address system or siren, horn, or other similar warning device
with a unique sound used only for H2S.
(7) Are there any other requirements for visual or audible warning
devices? Yes, you must:
(i) Illuminate all signs and flags at night and under conditions of
poor visibility; and
(ii) Use warning devices that are suitable for the electrical
classification of the area.
(8) What actions must I take when the alarms are activated? When
the warning devices are activated, the designated responsible persons
must inform personnel of the level of danger and issue instructions on
the initiation of appropriate protective measures.
(j) H2S-detection and H2S monitoring
equipment: (1) What are the requirements for an H2S
detection system? An H2S detection system must:
(i) Be capable of sensing a minimum of 10 ppm of H2S in
the atmosphere; and
(ii) Activate audible and visual alarms when the concentration of
H2S in the atmosphere reaches 20 ppm.
(2) Where must I have sensors for drilling, well-completion, and
well-workover operations? You must locate sensors at the:
(i) Bell nipple;
(ii) Mud-return line receiver tank (possum belly);
(iii) Pipe-trip tank;
(iv) Shale shaker;
(v) Well-control fluid pit area;
(vi) Driller's station;
(vii) Living quarters; and
(viii) All other areas where H2S may accumulate.
(3) Do I need mud sensors? The District Manager may require mud
sensors in the possum belly in cases where the ambient air sensors in
the mud-return system do not consistently detect the presence of
H2S.
(4) How often must I observe the sensors? During drilling, well-
completion and well-workover operations, you must continuously observe
the H2S levels indicated by the monitors in the work areas
during the following operations:
(i) When you pull a wet string of drill pipe or workover string;
(ii) When circulating bottoms-up after a drilling break;
(iii) During cementing operations;
(iv) During logging operations; and
(v) When circulating to condition mud or other well-control fluid.
(5) Where must I have sensors for production operations? On a
platform where gas containing H2S of 20 ppm or greater is
produced, processed, or otherwise handled:
(i) You must have a sensor in rooms, buildings, deck areas, or low-
laying deck areas not otherwise covered by paragraph (j)(2) of this
section, where atmospheric concentrations of H2S could reach
20 ppm or more. You must have at least one sensor per 400 square feet
of deck area or fractional part of 400 square feet;
(ii) You must have a sensor in buildings where personnel have their
living quarters;
(iii) You must have a sensor within 10 feet of each vessel,
compressor, wellhead, manifold, or pump, which could release enough
H2S to result in atmospheric concentrations of 20 ppm at a
distance of 10 feet from the component;
(iv) You may use one sensor to detect H2S around
multiple pieces of equipment, provided the sensor is located no more
than 10 feet from each piece, except that you need to use at least two
sensors to monitor compressors exceeding 50 horsepower;
(v) You do not need to have sensors near wells that are shut in at
the master valve and sealed closed;
(vi) When you determine where to place sensors, you must consider:
(A) The location of system fittings, flanges, valves, and other
devices subject to leaks to the atmosphere; and
(B) Design factors, such as the type of decking and the location of
fire walls; and
(vii) The District Manager may require additional sensors or other
monitoring capabilities, if warranted by site specific conditions.
(6) How must I functionally test the H2S Detectors? (i) Personnel
trained to calibrate the particular H2S detector equipment
being used must test detectors by exposing them to a known
concentration in the range of 10 to 30 ppm of H2S.
(ii) If the results of any functional test are not within 2 ppm or
10 percent, whichever is greater, of the applied
[[Page 64528]]
concentration, recalibrate the instrument.
(7) How often must I test my detectors? (i) When conducting
drilling, drill stem testing, well-completion, or well-workover
operations in areas classified as H2S present or
H2S unknown, test all detectors at least once every 24
hours. When drilling, begin functional testing before the bit is 1,500
feet (vertically) above the potential H2S zone.
(ii) When conducting production operations, test all detectors at
least every 14 days between tests.
(iii) If equipment requires calibration as a result of two
consecutive functional tests, the District Manager may require that
H2S-detection and H2S-monitoring equipment be
functionally tested and calibrated more frequently.
(8) What documentation must I keep? (i) You must maintain records
of testing and calibrations (in the drilling or production operations
report, as applicable) at the facility to show the present status and
history of each device, including dates and details concerning:
(A) Installation;
(B) Removal;
(C) Inspection;
(D) Repairs;
(E) Adjustments; and
(F) Reinstallation.
(ii) Records must be available for inspection by BSEE personnel.
(9) What are the requirements for nearby vessels? If vessels are
stationed overnight alongside facilities in areas of H2S
present or H2S unknown, you must equip vessels with an
H2S-detection system that activates audible and visual
alarms when the concentration of H2S in the atmosphere
reaches 20 ppm. This requirement does not apply to vessels positioned
upwind and at a safe distance from the facility in accordance with the
positioning procedure described in the approved H2S
Contingency Plan.
(10) What are the requirements for nearby facilities? The District
Manager may require you to equip nearby facilities with portable or
fixed H2S detector(s) and to test and calibrate those
detectors. To invoke this requirement, the District Manager will
consider dispersion modeling results from a possible release to
determine if 20 ppm H2S concentration levels could be
exceeded at nearby facilities.
(11) What must I do to protect against SO2 if I burn gas containing
H2S? You must:
(i) Monitor the SO2concentration in the air with
portable or strategically placed fixed devices capable of detecting a
minimum of 2 ppm of SO2;
(ii) Take readings at least hourly and at any time personnel detect
SO2 odor or nasal irritation;
(iii) Implement the personnel protective measures specified in the
H2S Contingency Plan if the SO2 concentration in
the work area reaches 2 ppm; and
(iv) Calibrate devices every 3 months if you use fixed or portable
electronic sensing devices to detect SO2.
(12) May I use alternative measures? You may follow alternative
measures instead of those in paragraph (j)(11) of this section if you
propose and the Regional Supervisor approves the alternative measures.
(13) What are the requirements for protective-breathing equipment?
In an area classified as H2S present or H2S
unknown, you must:
(i) Provide all personnel, including contractors and visitors on a
facility, with immediate access to self-contained pressure-demand-type
respirators with hoseline capability and breathing time of at least 15
minutes.
(ii) Design, select, use, and maintain respirators in conformance
with ANSI Z88.2 (as specified in Sec. 250.198).
(iii) Make available at least two voice-transmission devices, which
can be used while wearing a respirator, for use by designated
personnel.
(iv) Make spectacle kits available as needed.
(v) Store protective-breathing equipment in a location that is
quickly and easily accessible to all personnel.
(vi) Label all breathing-air bottles as containing breathing-
quality air for human use.
(vii) Ensure that vessels attendant to facilities carry appropriate
protective-breathing equipment for each crew member. The District
Manager may require additional protective-breathing equipment on
certain vessels attendant to the facility.
(viii) During H2S alerts, limit helicopter flights to
and from facilities to the conditions specified in the H2S
Contingency Plan. During authorized flights, the flight crew and
passengers must use pressure-demand-type respirators. You must train
all members of flight crews in the use of the particular type(s) of
respirator equipment made available.
(ix) As appropriate to the particular operation(s), (production,
drilling, well-completion or well-workover operations, or any
combination of them), provide a system of breathing-air manifolds,
hoses, and masks at the facility and the briefing areas. You must
provide a cascade air-bottle system for the breathing-air manifolds to
refill individual protective-breathing apparatus bottles. The cascade
air-bottle system may be recharged by a high-pressure compressor
suitable for providing breathing-quality air, provided the compressor
suction is located in an uncontaminated atmosphere.
(k) Personnel safety equipment: (1) What additional personnel-
safety equipment do I need? You must ensure that your facility has:
(i) Portable H2S detectors capable of detecting a 10 ppm
concentration of H2S in the air available for use by all
personnel;
(ii) Retrieval ropes with safety harnesses to retrieve
incapacitated personnel from contaminated areas;
(iii) Chalkboards and/or note pads for communication purposes
located on the rig floor, shale-shaker area, the cement-pump rooms,
well-bay areas, production processing equipment area, gas compressor
area, and pipeline-pump area;
(iv) Bull horns and flashing lights; and
(v) At least three resuscitators on manned facilities, and a number
equal to the personnel on board, not to exceed three, on normally
unmanned facilities, complete with face masks, oxygen bottles, and
spare oxygen bottles.
(2) What are the requirements for ventilation equipment? You must:
(i) Use only explosion-proof ventilation devices;
(ii) Install ventilation devices in areas where H2S or
SO2 may accumulate; and
(iii) Provide movable ventilation devices in work areas. The
movable ventilation devices must be multidirectional and capable of
dispersing H2S or SO2 vapors away from working
personnel.
(3) What other personnel safety equipment do I need? You must have
the following equipment readily available on each facility:
(i) A first-aid kit of appropriate size and content for the number
of personnel on the facility; and
(ii) At least one litter or an equivalent device.
(l) Do I need to notify BSEE in the event of an H2S release? You
must notify BSEE without delay in the event of a gas release which
results in a 15-minute time-weighted average atmospheric concentration
of H2S of 20 ppm or more anywhere on the OCS facility. You
must report these gas releases to the District Manager immediately by
oral communication, with a written follow-up report within 15 days,
pursuant to Sec. Sec. 250.188 through 250.190.
(m) Do I need to use special drilling, completion and workover
fluids or
[[Page 64529]]
procedures? When working in an area classified as H2S
present or H2S unknown:
(1) You may use either water- or oil-base muds in accordance with
Sec. 250.300(b)(1).
(2) If you use water-base well-control fluids, and if ambient air
sensors detect H2S, you must immediately conduct either the
Garrett-Gas-Train test or a comparable test for soluble sulfides to
confirm the presence of H2S.
(3) If the concentration detected by air sensors in over 20 ppm,
personnel conducting the tests must don protective-breathing equipment
conforming to paragraph (j)(13) of this section.
(4) You must maintain on the facility sufficient quantities of
additives for the control of H2S, well-control fluid pH, and
corrosion equipment.
(i) Scavengers. You must have scavengers for control of
H2S available on the facility. When H2S is
detected, you must add scavengers as needed. You must suspend drilling
until the scavenger is circulated throughout the system.
(ii) Control pH. You must add additives for the control of pH to
water-base well-control fluids in sufficient quantities to maintain pH
of at least 10.0.
(iii) Corrosion inhibitors. You must add additives to the well-
control fluid system as needed for the control of corrosion.
(5) You must degas well-control fluids containing H2S at
the optimum location for the particular facility. You must collect the
gases removed and burn them in a closed flare system conforming to
paragraph (q)(6) of this section.
(n) What must I do in the event of a kick? In the event of a kick,
you must use one of the following alternatives to dispose of the well-
influx fluids giving consideration to personnel safety, possible
environmental damage, and possible facility well-equipment damage:
(1) Contain the well-fluid influx by shutting in the well and
pumping the fluids back into the formation.
(2) Control the kick by using appropriate well-control techniques
to prevent formation fracturing in an open hole within the pressure
limits of the well equipment (drill pipe, work string, casing,
wellhead, BOP system, and related equipment). The disposal of
H2S and other gases must be through pressurized or
atmospheric mud-separator equipment depending on volume, pressure and
concentration of H2S. The equipment must be designed to
recover well-control fluids and burn the gases separated from the well-
control fluid. The well-control fluid must be treated to neutralize
H2S and restore and maintain the proper quality.
(o) Well testing in a zone known to contain H2S. When testing a
well in a zone with H2S present, you must do all of the
following:
(1) Before starting a well test, conduct safety meetings for all
personnel who will be on the facility during the test. At the meetings,
emphasize the use of protective-breathing equipment, first-aid
procedures, and the Contingency Plan. Only competent personnel who are
trained and are knowledgeable of the hazardous effects of
H2S must be engaged in these tests.
(2) Perform well testing with the minimum number of personnel in
the immediate vicinity of the rig floor and with the appropriate test
equipment to safely and adequately perform the test. During the test,
you must continuously monitor H2S levels.
(3) Not burn produced gases except through a flare which meets the
requirements of paragraph (q)(6) of this section. Before flaring gas
containing H2S, you must activate SO2 monitoring
equipment in accordance with paragraph (j)(11) of this section. If you
detect SO2 in excess of 2 ppm, you must implement the
personnel protective measures in your H2S Contingency Plan,
required by paragraph (f) of this section. You must also follow the
requirements of Sec. 250.1164. You must pipe gases from stored test
fluids into the flare outlet and burn them.
(4) Use downhole test tools and wellhead equipment suitable for
H2S service.
(5) Use tubulars suitable for H2S service. You must not
use drill pipe for well testing without the prior approval of the
District Manager. Water cushions must be thoroughly inhibited in order
to prevent H2S attack on metals. You must flush the test
string fluid treated for this purpose after completion of the test.
(6) Use surface test units and related equipment that is designed
for H2S service.
(p) Metallurgical properties of equipment. When operating in a zone
with H2S present, 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:
(1) Use tubulars and other equipment, casing, tubing, drill pipe,
couplings, flanges, and related equipment that is designed for
H2S service.
(2) Use BOP system components, wellhead, pressure-control
equipment, and related equipment exposed to H2S-bearing
fluids in conformance with NACE Standard MR0175-03 (as specified in
Sec. 250.198).
(3) Use temporary downhole well-security devices such as
retrievable packers and bridge plugs that are designed for
H2S service.
(4) When producing in zones bearing H2S, use equipment
constructed of materials capable of resisting or preventing sulfide
stress cracking.
(5) Keep the use of welding to a minimum during the installation or
modification of a production facility. Welding must be done in a manner
that ensures resistance to sulfide stress cracking.
(q) General requirements when operating in an H2S zone: (1) Coring
operations. When you conduct coring operations in H2S-
bearing zones, all personnel in the working area must wear protective-
breathing equipment at least 10 stands in advance of retrieving the
core barrel. Cores to be transported must be sealed and marked for the
presence of H2S.
(2) Logging operations. You must treat and condition well-control
fluid in use for logging operations to minimize the effects of
H2S on the logging equipment.
(3) Stripping operations. Personnel must monitor displaced well-
control fluid returns and wear protective-breathing equipment in the
working area when the atmospheric concentration of H2S
reaches 20 ppm or if the well is under pressure.
(4) Gas-cut well-control fluid or well kick from H2S-bearing zone.
If you decide to circulate out a kick, personnel in the working area
during bottoms-up and extended-kill operations must wear protective-
breathing equipment.
(5) Drill- and workover-string design and precautions. Drill- and
workover-strings must be designed consistent with the anticipated
depth, conditions of the hole, and reservoir environment to be
encountered. You must minimize exposure of the drill- or workover-
string to high stresses as much as practical and consistent with well
conditions. Proper handling techniques must be taken to minimize
notching and stress concentrations. Precautions must be taken to
minimize stresses caused by doglegs, improper stiffness ratios,
improper torque, whip, abrasive wear on tool joints, and joint
imbalance.
(6) Flare system. The flare outlet must be of a diameter that
allows easy nonrestricted flow of gas. You must locate flare line
outlets on the downside
[[Page 64530]]
of the facility and as far from the facility as is feasible, taking
into account the prevailing wind directions, the wake effects caused by
the facility and adjacent structure(s), and the height of all such
facilities and structures. You must equip the flare outlet with an
automatic ignition system including a pilot-light gas source or an
equivalent system. You must have alternate methods for igniting the
flare. You must pipe to the flare system used for H2S all
vents from production process equipment, tanks, relief valves, burst
plates, and similar devices.
(7) Corrosion mitigation. You must use effective means of
monitoring and controlling corrosion caused by acid gases
(H2S and CO2) in both the downhole and surface
portions of a production system. You must take specific corrosion
monitoring and mitigating measures in areas of unusually severe
corrosion where accumulation of water and/or higher concentration of
H2S exists.
(8) Wireline lubricators. Lubricators which may be exposed to
fluids containing H2S must be of H2S-resistant
materials.
(9) Fuel and/or instrument gas. You must not use gas containing
H2S for instrument gas. You must not use gas containing
H2S for fuel gas without the prior approval of the District
Manager.
(10) Sensing lines and devices. Metals used for sensing line and
safety-control devices which are necessarily exposed to H2S-
bearing fluids must be constructed of H2S-corrosion
resistant materials or coated so as to resist H2S corrosion.
(11) Elastomer seals. You must use H2S-resistant
materials for all seals which may be exposed to fluids containing
H2S.
(12) Water disposal. If you dispose of produced water by means
other than subsurface injection, you must submit to the District
Manager an analysis of the anticipated H2S content of the
water at the final treatment vessel and at the discharge point. The
District Manager may require that the water be treated for removal of
H2S. The District Manager may require the submittal of an
updated analysis if the water disposal rate or the potential
H2S content increases.
(13) Deck drains. You must equip open deck drains with traps or
similar devices to prevent the escape of H2S gas into the
atmosphere.
(14) Sealed voids. You must take precautions to eliminate sealed
spaces in piping designs (e.g., slip-on flanges, reinforcing pads)
which can be invaded by atomic hydrogen when H2S is present.
Subpart E--Oil and Gas Well-Completion Operations
Sec. 250.500 General requirements.
Well-completion operations shall be conducted in a manner to
protect against harm or damage to life (including fish and other
aquatic life), property, natural resources of the OCS including any
mineral deposits (in areas leased and not leased), the National
security or defense, or the marine, coastal, or human environment.
Sec. 250.501 Definition.
When used in this subpart, the following term shall have the
meaning given below:
Well-completion operations means the work conducted to establish
the production of a well after the production-casing string has been
set, cemented, and pressure-tested.
Sec. 250.502 Equipment movement.
The movement of well-completion rigs and related equipment on and
off a platform or from well to well on the same platform, including
rigging up and rigging down, shall be conducted in a safe manner. All
wells in the same well-bay which are capable of producing hydrocarbons
shall be shut in below the surface with a pump-through-type tubing plug
and at the surface with a closed master valve prior to moving well-
completion rigs and related equipment, unless otherwise approved by the
District Manager. A closed surface-controlled subsurface safety valve
of the pump-through type may be used in lieu of the pump-through-type
tubing plug, provided that the surface control has been locked out of
operation. The well from which the rig or related equipment is to be
moved shall also be equipped with a back-pressure valve prior to
removing the blowout preventer (BOP) system and installing the tree.
Sec. 250.503 Emergency shutdown system.
When well-completion operations are conducted on a platform where
there are other hydrocarbon-producing wells or other hydrocarbon flow,
an emergency shutdown system (ESD) manually controlled station shall be
installed near the driller's console or well-servicing unit operator's
work station.
Sec. 250.504 Hydrogen sulfide.
When a well-completion operation is conducted in zones known to
contain hydrogen sulfide (H2S) or in zones where the
presence of H2S is unknown (as defined in Sec. 250.490 of
this part), the lessee shall take appropriate precautions to protect
life and property on the platform or completion unit, including, but
not limited to operations such as blowing the well down, dismantling
wellhead equipment and flow lines, circulating the well, swabbing, and
pulling tubing, pumps, and packers. The lessee shall comply with the
requirements in Sec. 250.490 of this part as well as the appropriate
requirements of this subpart.
Sec. 250.505 Subsea completions.
No subsea well completion shall be commenced until the lessee
obtains written approval from the District Manager in accordance with
Sec. 250.513 of this part. That approval shall be based upon a case-
by-case determination that the proposed equipment and procedures will
adequately control the well and permit safe production operations.
Sec. 250.506 Crew instructions.
Prior to engaging in well-completion operations, crew members shall
be instructed in the safety requirements of the operations to be
performed, possible hazards to be encountered, and general safety
considerations to protect personnel, equipment, and the environment.
Date and time of safety meetings shall be recorded and available at the
facility for review by BSEE representatives.
Sec. 250.507 [Reserved]
Sec. 250.508 [Reserved]
Sec. 250.509 Well-completion structures on fixed platforms.
Derricks, masts, substructures, and related equipment shall be
selected, designed, installed, used, and maintained so as to be
adequate for the potential loads and conditions of loading that may be
encountered during the proposed operations. Prior to moving a well-
completion rig or equipment onto a platform, the lessee shall determine
the structural capability of the platform to safely support the
equipment and proposed operations, taking into consideration the
corrosion protection, age of platform, and previous stresses to the
platform.
Sec. 250.510 Diesel engine air intakes.
Diesel engine air intakes must be equipped with a device to shut
down the diesel engine in the event of runaway. Diesel engines that are
continuously attended must be equipped with either remote operated
manual or automatic-shutdown devices. Diesel engines that are not
continuously attended must be equipped with automatic-shutdown devices.
[[Page 64531]]
Sec. 250.511 Traveling-block safety device.
All units being used for well-completion operations that have both
a traveling block and a crown block must be equipped with a safety
device that is designed to prevent the traveling block from striking
the crown block. The device must be checked for proper operation weekly
and after each drill-line slipping operation. The results of the
operational check must be entered in the operations log.
Sec. 250.512 Field well-completion rules.
When geological and engineering information available in a field
enables the District Manager to determine specific operating
requirements, field well-completion rules may be established on the
District Manager's initiative or in response to a request from a
lessee. Such rules may modify the specific requirements of this
subpart. After field well-completion rules have been established, well-
completion operations in the field shall be conducted in accordance
with such rules and other requirements of this subpart. Field well-
completion rules may be amended or canceled for cause at any time upon
the initiative of the District Manager or upon the request of a lessee.
Sec. 250.513 Approval and reporting of well-completion operations.
(a) No well-completion operation may begin until the lessee
receives written approval from the District Manager. If completion is
planned and the data are available at the time you submit the
Application for Permit to Drill and Supplemental APD Information Sheet
(Forms BSEE-0123 and BSEE-0123S), you may request approval for a well-
completion on those forms (see Sec. Sec. 250.410 through 250.418 of
this part). If the District Manager has not approved the completion or
if the completion objective or plans have significantly changed, you
must submit an Application for Permit to Modify (Form BSEE-0124) for
approval of such operations.
(b) You must submit the following with Form BSEE-0124 (or with Form
BSEE-0123; Form BSEE-0123S):
(1) A brief description of the well-completion procedures to be
followed, a statement of the expected surface pressure, and type and
weight of completion fluids;
(2) A schematic drawing of the well showing the proposed producing
zone(s) and the subsurface well-completion equipment to be used;
(3) For multiple completions, a partial electric log showing the
zones proposed for completion, if logs have not been previously
submitted;
(4) When the well-completion is in a zone known to contain
H2S or a zone where the presence of H2S is
unknown, information pursuant to Sec. 250.490 of this part; and
(5) Payment of the service fee listed in Sec. 250.125.
(c) Within 30 days after completion, you must submit to the
District Manager an End of Operations Report (Form BSEE-0125),
including a schematic of the tubing and subsurface equipment.
(d) You must submit public information copies of Form BSEE-0125
according to Sec. 250.186.
Sec. 250.514 Well-control fluids, equipment, and operations.
(a) Well-control fluids, equipment, and operations shall be
designed, utilized, maintained, and/or tested as necessary to control
the well in foreseeable conditions and circumstances, including
subfreezing conditions. The well shall be continuously monitored during
well-completion operations and shall not be left unattended at any time
unless the well is shut in and secured.
(b) The following well-control-fluid equipment shall be installed,
maintained, and utilized:
(1) A fill-up line above the uppermost BOP;
(2) A well-control, fluid-volume measuring device for determining
fluid volumes when filling the hole on trips; and
(3) A recording mud-pit-level indicator to determine mud-pit-volume
gains and losses. This indicator shall include both a visual and an
audible warning device.
(c) When coming out of the hole with drill pipe, the annulus shall
be filled with well-control fluid before the change in such fluid level
decreases the hydrostatic pressure 75 pounds per square inch (psi) or
every five stands of drill pipe, whichever gives a lower decrease in
hydrostatic pressure. The number of stands of drill pipe and drill
collars that may be pulled prior to filling the hole and the equivalent
well-control fluid volume shall be calculated and posted near the
operator's station. A mechanical, volumetric, or electronic device for
measuring the amount of well-control fluid required to fill the hole
shall be utilized.
Sec. 250.515 Blowout prevention equipment.
(a) The BOP system and system components and related well-control
equipment shall be designed, used, maintained, and tested in a manner
necessary to assure well control in foreseeable conditions and
circumstances, including subfreezing conditions. The working pressure
rating of the BOP system and BOP system components shall exceed the
expected surface pressure to which they may be subjected. If the
expected surface pressure exceeds the rated working pressure of the
annular preventer, the lessee shall submit with Form BSEE-0124 or Form
BSEE-0123, as appropriate, a well-control procedure that indicates how
the annular preventer will be utilized, and the pressure limitations
that will be applied during each mode of pressure control.
(b) The minimum BOP system for well-completion operations must meet
the appropriate standards from the following table:
------------------------------------------------------------------------
The minimum BOP stack must
When . . . include . . .
------------------------------------------------------------------------
(1) The expected pressure is less than Three BOPs consisting of an
5,000 psi, annular, one set of pipe
rams, and one set of blind-
shear rams.
(2) The expected pressure is 5,000 psi or Four BOPs consisting of an
greater or you use multiple tubing annular, two sets of pipe
strings, rams, and one set of blind-
shear rams.
(3) You handle multiple tubing strings Four BOPs consisting of an
simultaneously, annular, one set of pipe
rams, one set of dual pipe
rams, and one set of blind-
shear rams.
(4) You use a tapered drill string, At least one set of pipe
rams that are capable of
sealing around each size of
drill string. If the
expected pressure is
greater than 5,000 psi,
then you must have at least
two sets of pipe rams that
are capable of sealing
around the larger size
drill string. You may
substitute one set of
variable bore rams for two
sets of pipe rams.
(5) You use a subsea BOP stack, The requirements in Sec.
250.442(a) of this part.
------------------------------------------------------------------------
[[Page 64532]]
(c) The BOP systems for well completions must be equipped with the
following:
(1) A hydraulic-actuating system that provides sufficient
accumulator capacity to supply 1.5 times the volume necessary to close
all BOP equipment units with a minimum pressure of 200 psi above the
precharge pressure without assistance from a charging system.
Accumulator regulators supplied by rig air and without a secondary
source of pneumatic supply, must be equipped with manual overrides, or
alternately, other devices provided to ensure capability of hydraulic
operations if rig air is lost.
(2) A secondary power source, independent from the primary power
source, with sufficient capacity to close all BOP system components and
hold them closed.
(3) Locking devices for the pipe-ram preventers.
(4) At least one remote BOP-control station and one BOP-control
station on the rig floor.
(5) A choke line and a kill line each equipped with two full
opening valves and a choke manifold. At least one of the valves on the
choke line shall be remotely controlled. At least one of the valves on
the kill line shall be remotely controlled, except that a check valve
on the kill line in lieu of the remotely controlled valve may be
installed provided that two readily accessible manual valves are in
place and the check valve is placed between the manual valves and the
pump. This equipment shall have a pressure rating at least equivalent
to the ram preventers.
(d) An inside BOP or a spring-loaded, back-pressure safety valve
and an essentially full-opening, work-string safety valve in the open
position shall be maintained on the rig floor at all times during well-
completion operations. A wrench to fit the work-string safety valve
shall be readily available. Proper connections shall be readily
available for inserting valves in the work string.
(e) The subsea BOP system for well-completions must meet the
requirements in Sec. 250.442 of this part.
Sec. 250.516 Blowout preventer system tests, inspections, and
maintenance.
(a) BOP pressure testing timeframes. You must pressure test your
BOP system:
(1) When installed; and
(2) Before 14 days have elapsed since your last BOP pressure test.
You must begin to test your BOP system before 12 a.m. (midnight) on the
14th day following the conclusion of the previous test. However, the
District Manager may require testing every 7 days if conditions or BOP
performance warrant.
(b) BOP test pressures. When you test the BOP system, you must
conduct a low pressure and a high pressure test for each BOP component.
Each individual pressure test must hold pressure long enough to
demonstrate that the tested component(s) holds the required pressure.
The District Manager may approve or require other test pressures or
practices. Required test pressures are as follows:
(1) All low pressure tests must be between 200 and 300 psi. Any
initial pressure above 300 psi must be bled back to a pressure between
200 and 300 psi before starting the test. If the initial pressure
exceeds 500 psi, you must bleed back to zero and reinitiate the test.
You must conduct the low pressure test before the high pressure test.
(2) For ram-type BOP's, choke manifold, and other BOP equipment,
the high pressure test must equal the rated working pressure of the
equipment.
(3) For annular-type BOP's, the high pressure test must equal 70
percent of the rated working pressure of the equipment.
(c) Duration of pressure test. Each test must hold the required
pressure for 5 minutes.
(1) For surface BOP systems and surface equipment of a subsea BOP
system, a 3-minute test duration is acceptable if you record your test
pressures on the outermost half of a 4-hour chart, on a 1-hour chart,
or on a digital recorder.
(2) If the equipment does not hold the required pressure during a
test, you must remedy the problem and retest the affected component(s).
(d) Additional BOP testing requirements. You must:
(1) Use water to test the surface BOP system;
(2) Stump test a subsurface BOP system before installation. You
must use water to stump test a subsea BOP system. You may use drilling
or completion fluids to conduct subsequent tests of a subsea BOP
system;
(3) Alternate tests between control stations and pods. If a control
station or pod is not functional, you must suspend further completion
operations until that station or pod is operable;
(4) Pressure test the blind or blind-shear ram at least every 30
days;
(5) Function test annulars and rams every 7 days;
(6) Pressure-test variable bore-pipe rams against all sizes of pipe
in use, excluding drill collars and bottom-hole tools;
(7) Test affected BOP components following the disconnection or
repair of any well-pressure containment seal in the wellhead or BOP
stack assembly;
(8) Test all ROV intervention functions on your subsea BOP stack
during the stump test. You must also test at least one set of rams
during the initial test on the seafloor. You must submit test
procedures with your APM for District Manager approval. You must:
(i) Ensure that the ROV hot stabs are function tested and are
capable of actuating, at a minimum, one set of pipe rams and one set of
blind-shear rams and unlatching the LMRP;
(ii) Document all your test results and make them available to BSEE
upon request; and
(9) Function test autoshear and deadman systems on your subsea BOP
stack during the stump test. You must also test the deadman system
during the initial test on the seafloor.
(i) You must submit test procedures with your APM for District
Manager approval.
(ii) You must document all your test results and make them
available to BSEE upon request.
(e) Postponing BOP tests. You may postpone a BOP test if you have
well-control problems. You must conduct the required BOP test as soon
as possible (i.e., first trip out of the hole) after the problem has
been remedied. You must record the reason for postponing any test in
the driller's report.
(f) Weekly crew drills. You must conduct a weekly drill to
familiarize all personnel engaged in well-completion operations with
appropriate safety measures.
(g) BOP inspections. (1) You must inspect your BOP system to ensure
that the equipment functions properly. The BOP inspections must meet or
exceed the provisions of Sections 17.10 and 18.10, Inspections,
described in API RP 53, Recommended Practices for Blowout Prevention
Equipment Systems for Drilling Wells (as incorporated by reference in
Sec. 250.198). You must document the procedures used, record the
results, and make them available to BSEE upon request. You must
maintain your records on the rig for 2 years or from the date of your
last major inspection, whichever is longer.
(2) You must visually inspect your BOP system and marine riser at
least once each day if weather and sea conditions permit. You may use
television cameras to inspect this equipment. The District Manager may
approve alternate methods and frequencies to inspect a marine riser.
[[Page 64533]]
(h) BOP maintenance. You must maintain your BOP system to ensure
that the equipment functions properly. The BOP maintenance must meet or
exceed the provisions of Sections 17.11 and 18.11, Maintenance; and
Sections 17.12 and 18.12, Quality Management, described in API RP 53,
Recommended Practices for Blowout Prevention Equipment Systems for
Drilling Wells (as incorporated by reference in Sec. 250.198). You
must document the procedures used, record the results, and make
available to BSEE upon request. You must maintain your records on the
rig for 2 years or from the date of your last major inspection,
whichever is longer.
(i) BOP test records. You must record the time, date, and results
of all pressure tests, actuations, crew drills, and inspections of the
BOP system, system components, and marine riser in the driller's
report. In addition, you must:
(1) Record BOP test pressures on pressure charts;
(2) Have your onsite representative certify (sign and date) BOP
test charts and reports as correct;
(3) Document the sequential order of BOP and auxiliary equipment
testing and the pressure and duration of each test. You may reference a
BOP test plan if it is available at the facility;
(4) Identify the control station or pod used during the test;
(5) Identify any problems or irregularities observed during BOP
system and equipment testing and record actions taken to remedy the
problems or irregularities;
(6) Retain all records including pressure charts, driller's report,
and referenced documents pertaining to BOP tests, actuations, and
inspections at the facility for the duration of the completion
activity; and
(7) After completion of the well, you must retain all the records
listed in paragraph (i)(6) of this section for a period of 2 years at
the facility, at the lessee's field office nearest the OCS facility, or
at another location conveniently available to the District Manager.
(j) Alternate methods. The District Manager may require, or
approve, more frequent testing, as well as different test pressures and
inspection methods, or other practices.
Sec. 250.517 Tubing and wellhead equipment.
(a) No tubing string shall 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.
(b) In the event of prolonged operations such as milling, fishing,
jarring, or washing over that could damage the casing, the casing shall
be pressure-tested, calipered, or otherwise evaluated every 30 days and
the results submitted to the District Manager.
(c) When the tree is installed, you must equip wells to monitor for
casing pressure according to the following chart:
------------------------------------------------------------------------
If you . . . you must equip . . . so you can monitor . . .
------------------------------------------------------------------------
(1) fixed platform the wellhead, all annuli (A, B, C, D,
wells, etc., annuli).
(2) subsea wells, the tubing head, the production casing
annulus (A annulus).
(3) hybrid * wells, the surface wellhead, all annuli at the surface
(A and B riser annuli).
If the production casing
below the mudline and
the production casing
riser above the mudline
are pressure isolated
from each other,
provisions must be made
to monitor the
production casing below
the mudline for casing
pressure.
------------------------------------------------------------------------
* Characterized as a well drilled with a subsea wellhead and completed
with a surface casing head, a surface tubing head, a surface tubing
hanger, and a surface christmas tree.
(d) Wellhead, tree, and related equipment shall have a pressure
rating greater than the shut-in tubing pressure and shall be designed,
installed, used, maintained, and tested so as to achieve and maintain
pressure control. New wells completed as flowing or gas-lift wells
shall be equipped with a minimum of one master valve and one surface
safety valve, installed above the master valve, in the vertical run of
the tree.
(e) Subsurface safety equipment shall be installed, maintained, and
tested in compliance with Sec. 250.801 of this part.
Casing Pressure Management
Sec. 250.518 What are the requirements for casing pressure
management?
Once you install your wellhead, you must meet the casing pressure
management requirements of API RP 90 (as incorporated by reference in
Sec. 250.198) and the requirements of Sec. Sec. 250.519 through
250.530. If there is a conflict between API RP 90 and the casing
pressure requirements of this subpart, you must follow the requirements
of this subpart.
Sec. 250.519 How often do I have to monitor for casing pressure?
You must monitor for casing pressure in your well according to the
following table:
----------------------------------------------------------------------------------------------------------------
with a minimum one pressure data
If you have . . . you must monitor . . . point recorded per . . .
----------------------------------------------------------------------------------------------------------------
(a) fixed platform wells, monthly, month for each casing.
(b) subsea wells, continuously, day for the production casing.
(c) hybrid wells, continuously, day for each riser and/or the
production casing.
(d) wells operating under a casing pressure daily, day for each casing.
request on a manned fixed platform,
(e) wells operating under a casing pressure weekly, week for each casing.
request on an unmanned fixed platform,
----------------------------------------------------------------------------------------------------------------
Sec. 250.520 When do I have to perform a casing diagnostic test?
(a) You must perform a casing diagnostic test within 30 days after
first observing or imposing casing pressure according to the following
table:
[[Page 64534]]
------------------------------------------------------------------------
you must perform a casing
If you have a . . . diagnostic test if . . .
------------------------------------------------------------------------
(1) fixed platform well, the casing pressure is
greater than 100 psig.
(2) subsea well, the measurable casing
pressure is greater than
the external hydrostatic
pressure plus 100 psig
measured at the subsea
wellhead.
(3) hybrid well, a riser or the production
casing pressure is greater
than 100 psig measured at
the surface.
------------------------------------------------------------------------
(b) You are exempt from performing a diagnostic pressure test for
the production casing on a well operating under active gas lift.
Sec. 250.521 How do I manage the thermal effects caused by initial
production on a newly completed or recompleted well?
A newly completed or recompleted well often has thermal casing
pressure during initial startup. Bleeding casing pressure during the
startup process is considered a normal and necessary operation to
manage thermal casing pressure; therefore, you do not need to evaluate
these operations as a casing diagnostic test. After 30 days of
continuous production, the initial production startup operation is
complete and you must perform casing diagnostic testing as required in
Sec. Sec. 250.520 and 250.522.
Sec. 250.522 When do I have to repeat casing diagnostic testing?
Casing diagnostic testing must be repeated according to the
following table:
------------------------------------------------------------------------
you must repeat diagnostic
When . . . testing . . .
------------------------------------------------------------------------
(a) your casing pressure request approved immediately.
term has expired,
(b) your well, previously on gas lift, has immediately on the
been shut-in or returned to flowing production casing (A
status without gas lift for more than 180 annulus). The production
days, casing (A annulus) of wells
on active gas lift are
exempt from diagnostic
testing.
(c) your casing pressure request becomes within 30 days.
invalid,
(d) a casing or riser has an increase in within 30 days.
pressure greater than 200 psig over the
previous casing diagnostic test,
(e) after any corrective action has been within 30 days.
taken to remediate undesirable casing
pressure, either as a result of a casing
pressure request denial or any other
action,
(f) your fixed platform well production once per year, not to exceed
casing (A annulus) has pressure exceeding 12 months between tests.
10 percent of its minimum internal yield
pressure (MIYP), except for production
casings on active gas lift,
(g) your fixed platform well's outer once every 5 years, at a
casing (B, C, D, etc., annuli) has a minimum.
pressure exceeding 20 percent of its
MIYP,
------------------------------------------------------------------------
Sec. 250.523 How long do I keep records of casing pressure and
diagnostic tests?
Records of casing pressure and diagnostic tests must be kept at the
field office nearest the well for a minimum of 2 years. The last casing
diagnostic test for each casing or riser must be retained at the field
office nearest the well until the well is abandoned.
Sec. 250.524 When am I required to take action from my casing
diagnostic test?
You must take action if you have any of the following conditions:
(a) Any fixed platform well with a casing pressure exceeding its
maximum allowable wellhead operating pressure (MAWOP);
(b) Any fixed platform well with a casing pressure that is greater
than 100 psig and that cannot bleed to 0 psig through a \1/2\-inch
needle valve within 24 hours, or is not bled to 0 psig during a casing
diagnostic test;
(c) Any well that has demonstrated tubing/casing, tubing/riser,
casing/casing, riser/casing, or riser/riser communication;
(d) Any well that has sustained casing pressure (SCP) and is bled
down to prevent it from exceeding its MAWOP, except during initial
startup operations described in Sec. 250.521;
(e) Any hybrid well with casing or riser pressure exceeding 100
psig; or
(f) Any subsea well with a casing pressure 100 psig greater than
the external hydrostatic pressure at the subsea wellhead.
Sec. 250.525 What do I submit if my casing diagnostic test requires
action?
Within 14 days after you perform a casing diagnostic test requiring
action under Sec. 250.524:
----------------------------------------------------------------------------------------------------------------
You must submit either . . and it must include . . .
. to the appropriate . . . You must also . . .
----------------------------------------------------------------------------------------------------------------
(a) a notification of District Manager and copy requirements under Sec. submit an Application for
corrective action; or, the Regional Supervisor, 250.526, Permit to Modify or
Field Operations, Corrective Action Plan
within 30 days of the
diagnostic test.
(b) a casing pressure Regional Supervisor, Field requirements under Sec. .............................
request, Operations, 250.527.
----------------------------------------------------------------------------------------------------------------
Sec. 250.526 What must I include in my notification of corrective
action?
The following information must be included in the notification of
corrective action:
(a) Lessee or Operator name;
(b) Area name and OCS block number;
(c) Well name and API number; and
(d) Casing diagnostic test data.
Sec. 250.527 What must I include in my casing pressure request?
The following information must be included in the casing pressure
request:
(a) API number;
(b) Lease number;
[[Page 64535]]
(c) Area name and OCS block number;
(d) Well number;
(e) Company name and mailing address;
(f) All casing, riser, and tubing sizes, weights, grades, and MIYP;
(g) All casing/riser calculated MAWOPs;
(h) All casing/riser pre-bleed down pressures;
(i) Shut-in tubing pressure;
(j) Flowing tubing pressure;
(k) Date and the calculated daily production rate during last well
test (oil, gas, basic sediment, and water);
(l) Well status (shut-in, temporarily abandoned, producing,
injecting, or gas lift);
(m) Well type (dry tree, hybrid, or subsea);
(n) Date of diagnostic test;
(o) Well schematic;
(p) Water depth;
(q) Volumes and types of fluid bled from each casing or riser
evaluated;
(r) Type of diagnostic test performed:
(1) Bleed down/buildup test;
(2) Shut-in the well and monitor the pressure drop test;
(3) Constant production rate and decrease the annular pressure
test;
(4) Constant production rate and increase the annular pressure
test;
(5) Change the production rate and monitor the casing pressure
test; and
(6) Casing pressure and tubing pressure history plot;
(s) The casing diagnostic test data for all casing exceeding 100
psig;
(t) Associated shoe strengths for casing shoes exposed to annular
fluids;
(u) Concentration of any H2S that may be present;
(v) Whether the structure on which the well is located is manned or
unmanned;
(w) Additional comments; and
(x) Request date.
Sec. 250.528 What are the terms of my casing pressure request?
Casing pressure requests are approved by the Regional Supervisor,
Field Operations, for a term to be determined by the Regional
Supervisor on a case-by-case basis. The Regional Supervisor may impose
additional restrictions or requirements to allow continued operation of
the well.
Sec. 250.529 What if my casing pressure request is denied?
(a) If your casing pressure request is denied, then the operating
company must submit plans for corrective action to the respective
District Manager within 30 days of receiving the denial. The District
Manager will establish a specific time period in which this corrective
action will be taken. You must notify the respective District Manager
within 30 days after completion of your corrected action.
(b) You must submit the casing diagnostic test data to the
appropriate Regional Supervisor, Field Operations, within 14 days of
completion of the diagnostic test required under Sec. 250.522(e).
Sec. 250.530 When does my casing pressure request approval become
invalid?
A casing pressure request becomes invalid when:
(a) The casing or riser pressure increases by 200 psig over the
approved casing pressure request pressure;
(b) The approved term ends;
(c) The well is worked-over, side-tracked, redrilled, recompleted,
or acid stimulated;
(d) A different casing or riser on the same well requires a casing
pressure request; or
(e) A well has more than one casing operating under a casing
pressure request and one of the casing pressure requests become
invalid, then all casing pressure requests for that well become
invalid.
Subpart F--Oil and Gas Well-Workover Operations
Sec. 250.600 General requirements.
Well-workover operations shall be conducted in a manner to protect
against harm or damage to life (including fish and other aquatic life),
property, natural resources of the Outer Continental Shelf (OCS)
including any mineral deposits (in areas leased and not leased), the
National security or defense, or the marine, coastal, or human
environment.
Sec. 250.601 Definitions.
When used in this subpart, the following terms shall have the
meanings given below:
Expected surface pressure means the highest pressure predicted to
be exerted upon the surface of a well. In calculating expected surface
pressure, you must consider reservoir pressure as well as applied
surface pressure.
Routine operations mean any of the following operations conducted
on a well with the tree installed:
(a) Cutting paraffin;
(b) Removing and setting pump-through-type tubing plugs, gas-lift
valves, and subsurface safety valves which can be removed by wireline
operations;
(c) Bailing sand;
(d) Pressure surveys;
(e) Swabbing;
(f) Scale or corrosion treatment;
(g) Caliper and gauge surveys;
(h) Corrosion inhibitor treatment;
(i) Removing or replacing subsurface pumps;
(j) Through-tubing logging (diagnostics);
(k) Wireline fishing; and
(l) Setting and retrieving other subsurface flow-control devices.
Workover operations mean the work conducted on wells after the
initial completion for the purpose of maintaining or restoring the
productivity of a well.
Sec. 250.602 Equipment movement.
The movement of well-workover rigs and related equipment on and off
a platform or from well to well on the same platform, including rigging
up and rigging down, shall be conducted in a safe manner. All wells in
the same well-bay which are capable of producing hydrocarbons shall be
shut in below the surface with a pump-through-type tubing plug and at
the surface with a closed master valve prior to moving well-workover
rigs and related equipment unless otherwise approved by the District
Manager. A closed surface-controlled subsurface safety valve of the
pump-through-type may be used in lieu of the pump-through-type tubing
plug provided that the surface control has been locked out of
operation. The well to which a well-workover rig or related equipment
is to be moved shall also be equipped with a back-pressure valve prior
to removing the tree and installing and testing the blowout-preventer
(BOP) system. The well from which a well-workover rig or related
equipment is to be moved shall also be equipped with a back pressure
valve prior to removing the BOP system and installing the tree. Coiled
tubing units, snubbing units, or wireline units may be moved onto a
platform without shutting in wells.
Sec. 250.603 Emergency shutdown system.
When well-workover operations are conducted on a well with the tree
removed, an emergency shutdown system (ESD) manually controlled station
shall be installed near the driller's console or well-servicing unit
operator's work station, except when there is no other hydrocarbon-
producing well or other hydrocarbon flow on the platform.
Sec. 250.604 Hydrogen sulfide.
When a well-workover operation is conducted in zones known to
contain hydrogen sulfide (H2S) or in zones where the
presence of H2S is unknown (as defined in Sec. 250.490 of
this part), the lessee shall take appropriate precautions
[[Page 64536]]
to protect life and property on the platform or rig, including but not
limited to operations such as blowing the well down, dismantling
wellhead equipment and flow lines, circulating the well, swabbing, and
pulling tubing, pumps and packers. The lessee shall comply with the
requirements in Sec. 250.490 of this part as well as the appropriate
requirements of this subpart.
Sec. 250.605 Subsea workovers.
No subsea well-workover operation including routine operations
shall be commenced until the lessee obtains written approval from the
District Manager in accordance with Sec. 250.613 of this part. That
approval shall be based upon a case-by-case determination that the
proposed equipment and procedures will maintain adequate control of the
well and permit continued safe production operations.
Sec. 250.606 Crew instructions.
Prior to engaging in well-workover operations, crew members shall
be instructed in the safety requirements of the operations to be
performed, possible hazards to be encountered, and general safety
considerations to protect personnel, equipment, and the environment.
Date and time of safety meetings shall be recorded and available at the
facility for review by a BSEE representative.
Sec. 250.607 [Reserved]
Sec. 250.608 [Reserved]
Sec. 250.609 Well-workover structures on fixed platforms.
Derricks, masts, substructures, and related equipment shall be
selected, designed, installed, used, and maintained so as to be
adequate for the potential loads and conditions of loading that may be
encountered during the operations proposed. Prior to moving a well-
workover rig or well-servicing equipment onto a platform, the lessee
shall determine the structural capability of the platform to safely
support the equipment and proposed operations, taking into
consideration the corrosion protection, age of the platform, and
previous stresses to the platform.
Sec. 250.610 Diesel engine air intakes.
No later than May 31, 1989, diesel engine air intakes shall be
equipped with a device to shut down the diesel engine in the event of
runaway. Diesel engines which are continuously attended shall be
equipped with either remote operated manual or automatic shutdown
devices. Diesel engines which are not continuously attended shall be
equipped with automatic shutdown devices.
Sec. 250.611 Traveling-block safety device.
After May 31, 1989, all units being used for well-workover
operations which have both a traveling block and a crown block shall be
equipped with a safety device which is designed to prevent the
traveling block from striking the crown block. The device shall be
checked for proper operation weekly and after each drill-line slipping
operation. The results of the operational check shall be entered in the
operations log.
Sec. 250.612 Field well-workover rules.
When geological and engineering information available in a field
enables the District Manager to determine specific operating
requirements, field well-workover rules may be established on the
District Manager's initiative or in response to a request from a
lessee. Such rules may modify the specific requirements of this
subpart. After field well-workover rules have been established, well-
workover operations in the field shall be conducted in accordance with
such rules and other requirements of this subpart. Field well-workover
rules may be amended or canceled for cause at any time upon the
initiative of the District Manager or upon the request of a lessee.
Sec. 250.613 Approval and reporting for well-workover operations.
(a) No well-workover operation except routine ones, as defined in
Sec. 250.601 of this part, shall begin until the lessee receives
written approval from the District Manager. Approval for these
operations must be requested on Form BSEE-0124, Application for Permit
to Modify.
(b) You must submit the following with Form BSEE-0124:
(1) A brief description of the well-workover procedures to be
followed, a statement of the expected surface pressure, and type and
weight of workover fluids;
(2) When changes in existing subsurface equipment are proposed, a
schematic drawing of the well showing the zone proposed for workover
and the workover equipment to be used;
(3) Where the well-workover is in a zone known to contain
H2S or a zone where the presence of H2S is unknown,
information pursuant to Sec. 250.490 of this part; and
(4) Payment of the service fee listed in Sec. 250.125.
(c) The following additional information shall be submitted with
Form BSEE-0124 if completing to a new zone is proposed:
(1) Reason for abandonment of present producing zone including
supportive well test data, and
(2) A statement of anticipated or known pressure data for the new
zone.
(d) Within 30 days after completing the well-workover operation,
except routine operations, Form BSEE-0124, Application for Permit to
Modify, shall be submitted to the District Manager, showing the work as
performed. In the case of a well-workover operation resulting in the
initial recompletion of a well into a new zone, a Form BSEE-0125, End
of Operations Report, shall be submitted to the District Manager and
shall include a new schematic of the tubing subsurface equipment if any
subsurface equipment has been changed.
Sec. 250.614 Well-control fluids, equipment, and operations.
The following requirements apply during all well-workover
operations with the tree removed:
(a) Well-control fluids, equipment, and operations shall be
designed, utilized, maintained, and/or tested as necessary to control
the well in foreseeable conditions and circumstances, including
subfreezing conditions. The well shall be continuously monitored during
well-workover operations and shall not be left unattended at anytime
unless the well is shut in and secured.
(b) When coming out of the hole with drill pipe or a workover
string, the annulus shall be filled with well-control fluid before the
change in such fluid level decreases the hydrostatic pressure 75 pounds
per square inch (psi) or every five stands of drill pipe or workover
string, whichever gives a lower decrease in hydrostatic pressure. The
number of stands of drill pipe or workover string and drill collars
that may be pulled prior to filling the hole and the equivalent well-
control fluid volume shall be calculated and posted near the operator's
station. A mechanical, volumetric, or electronic device for measuring
the amount of well-control fluid required to fill the hold shall be
utilized.
(c) The following well-control-fluid equipment shall be installed,
maintained, and utilized:
(1) A fill-up line above the uppermost BOP;
(2) A well-control, fluid-volume measuring device for determining
fluid volumes when filling the hole on trips; and
(3) A recording mud-pit-level indicator to determine mud-pit-volume
[[Page 64537]]
gains and losses. This indicator shall include both a visual and an
audible warning device.
Sec. 250.615 Blowout prevention equipment.
(a) The BOP system, system components and related well-control
equipment shall be designed, used, maintained, and tested in a manner
necessary to assure well control in foreseeable conditions and
circumstances, including subfreezing conditions. The working pressure
rating of the BOP system and system components shall exceed the
expected surface pressure to which they may be subjected. If the
expected surface pressure exceeds the rated working pressure of the
annular preventer, the lessee shall submit with Form BSEE-0124,
requesting approval of the well-workover operation, a well-control
procedure that indicates how the annular preventer will be utilized,
and the pressure limitations that will be applied during each mode of
pressure control.
(b) The minimum BOP system for well-workover operations with the
tree removed must meet the appropriate standards from the following
table:
------------------------------------------------------------------------
The minimum BOP stack must
When . . . include . . .
------------------------------------------------------------------------
(1) The expected pressure is less than Three BOPs consisting of an
5,000 psi, annular, one set of pipe
rams, and one set of blind-
shear rams.
(2) The expected pressure is 5,000 psi or Four BOPs consisting of an
greater or you use multiple tubing annular, two sets of pipe
strings, rams, and one set of blind-
shear rams.
(3) You handle multiple tubing strings Four BOPs consisting of an
simultaneously, annular, one set of pipe
rams, one set of dual pipe
rams, and one set of blind-
shear rams.
(4) You use a tapered drill string, At least one set of pipe
rams that are capable of
sealing around each size of
drill string. If the
expected pressure is
greater than 5,000 psi,
then you must have at least
two sets of pipe rams that
are capable of sealing
around the larger size
drill string. You may
substitute one set of
variable bore rams for two
sets of pipe rams.
(5) You use a subsea BOP stack, The requirements in Sec.
250.442(a) of this part.
------------------------------------------------------------------------
(c) The BOP systems for well-workover operations with the tree
removed must be equipped with the following:
(1) A hydraulic-actuating system that provides sufficient
accumulator capacity to supply 1.5 times the volume necessary to close
all BOP equipment units with a minimum pressure of 200 psi above the
precharge pressure without assistance from a charging system.
Accumulator regulators supplied by rig air and without a secondary
source of pneumatic supply, must be equipped with manual overrides, or
alternately, other devices provided to ensure capability of hydraulic
operations if rig air is lost;
(2) A secondary power source, independent from the primary power
source, with sufficient capacity to close all BOP system components and
hold them closed;
(3) Locking devices for the pipe-ram preventers;
(4) At least one remote BOP-control station and one BOP-control
station on the rig floor; and
(5) A choke line and a kill line each equipped with two full
opening valves and a choke manifold. At least one of the valves on the
choke-line shall be remotely controlled. At least one of the valves on
the kill line shall be remotely controlled, except that a check valve
on the kill line in lieu of the remotely controlled valve may be
installed provided two readily accessible manual valves are in place
and the check valve is placed between the manual valves and the pump.
This equipment shall have a pressure rating at least equivalent to the
ram preventers.
(d) The minimum BOP-system components for well-workover operations
with the tree in place and performed through the wellhead inside of
conventional tubing using small-diameter jointed pipe (usually \3/4\
inch to 1\1/4\ inch) as a work string, i.e., small-tubing operations,
shall include the following:
(1) Two sets of pipe rams, and
(2) One set of blind rams.
(e) The subsea BOP system for well-workover operations must meet
the requirements in Sec. 250.442 of this part.
(f) For coiled tubing operations with the production tree in place,
you must meet the following minimum requirements for the BOP system:
(1) BOP system components must be in the following order from the
top down:
------------------------------------------------------------------------
BOP system when
BOP system when expected expected surface BOP system for wells
surface pressures are less pressures are with returns taken
than or equal to 3,500 psi greater than 3,500 through an outlet on
psi the BOP stack
------------------------------------------------------------------------
Stripper or annular-type Stripper or annular- Stripper or annular-
well control component. type well control type well control
component. component.
Hydraulically-operated blind Hydraulically- Hydraulically-
rams. operated blind rams. operated blind rams
Hydraulically-operated shear Hydraulically- Hydraulically-
rams. operated shear rams. operated shear
rams.
Kill line inlet............. Kill line inlet..... Kill line inlet.
Hydraulically-operated two- Hydraulically- Hydraulically-
way slip rams. operated two-way operated two-way
slip rams. slip rams.
Hydraulically-
operated pipe rams.
Hydraulically-operated pipe Hydraulically- A flow tee or cross.
rams. operated pipe rams. Hydraulically-
Hydraulically- operated pipe rams.
operated blind- Hydraulically-
shear rams. These operated blind-
rams should be shear rams on wells
located as close to with surface
the tree as pressures > 3,500
practical. psi. As an option,
the pipe rams can
be placed below the
blind-shear rams.
The blind-shear
rams should be
located as close to
the tree as
practical.
------------------------------------------------------------------------
[[Page 64538]]
(2) You may use a set of hydraulically-operated combination rams
for the blind rams and shear rams.
(3) You may use a set of hydraulically-operated combination rams
for the hydraulic two-way slip rams and the hydraulically-operated pipe
rams.
(4) You must attach a dual check valve assembly to the coiled
tubing connector at the downhole end of the coiled tubing string for
all coiled tubing well-workover operations. If you plan to conduct
operations without downhole check valves, you must describe alternate
procedures and equipment in Form BSEE-0124, Application for Permit to
Modify and have it approved by the District Manager.
(5) You must have a kill line and a separate choke line. You must
equip each line with two full-opening valves and at least one of the
valves must be remotely controlled. You may use a manual valve instead
of the remotely controlled valve on the kill line if you install a
check valve between the two full-opening manual valves and the pump or
manifold. The valves must have a working pressure rating equal to or
greater than the working pressure rating of the connection to which
they are attached, and you must install them between the well control
stack and the choke or kill line. For operations with expected surface
pressures greater than 3,500 psi, the kill line must be connected to a
pump or manifold. You must not use the kill line inlet on the BOP stack
for taking fluid returns from the wellbore.
(6) You must have a hydraulic-actuating system that provides
sufficient accumulator capacity to close-open-close each component in
the BOP stack. This cycle must be completed with at least 200 psi above
the pre-charge pressure, without assistance from a charging system.
(7) All connections used in the surface BOP system from the tree to
the uppermost required ram must be flanged, including the connections
between the well control stack and the first full-opening valve on the
choke line and the kill line.
(g) The minimum BOP-system components for well-workover operations
with the tree in place and performed by moving tubing or drill pipe in
or out of a well under pressure utilizing equipment specifically
designed for that purpose, i.e., snubbing operations, shall include the
following:
(1) One set of pipe rams hydraulically operated, and
(2) Two sets of stripper-type pipe rams hydraulically operated with
spacer spool.
(h) An inside BOP or a spring-loaded, back-pressure safety valve
and an essentially full-opening, work-string safety valve in the open
position shall be maintained on the rig floor at all times during well-
workover operations when the tree is removed or during well-workover
operations with the tree installed and using small tubing as the work
string. A wrench to fit the work-string safety valve shall be readily
available. Proper connections shall be readily available for inserting
valves in the work string. The full-opening safety valve is not
required for coiled tubing or snubbing operations.
Sec. 250.616 Blowout preventer system testing, records, and drills.
(a) BOP pressure tests. When you pressure test the BOP system you
must conduct a low-pressure test and a high-pressure test for each
component. You must conduct the low-pressure test before the high-
pressure test. For purposes of this section, BOP system components
include ram-type BOP's, related control equipment, choke and kill
lines, and valves, manifolds, strippers, and safety valves. Surface BOP
systems must be pressure tested with water.
(1) Low pressure tests. All BOP system components must be
successfully tested to a low pressure between 200 and 300 psi. Any
initial pressure equal to or greater than 300 psi must be bled back to
a pressure between 200 and 300 psi before starting the test. If the
initial pressure exceeds 500 psi, you must bleed back to zero before
starting the test.
(2) High pressure tests. All BOP system components must be
successfully tested to the rated working pressure of the BOP equipment,
or as otherwise approved by the District Manager. The annular-type BOP
must be successfully tested at 70 percent of its rated working pressure
or as otherwise approved by the District Manager.
(3) Other testing requirements. Variable bore pipe rams must be
pressure tested against the largest and smallest sizes of tubulars in
use (jointed pipe, seamless pipe) in the well.
(b) Times. The BOP systems shall be tested at the following times:
(1) When installed;
(2) At least every 7 days, alternating between control stations and
at staggered intervals to allow each crew to operate the equipment. If
either control system is not functional, further operations shall be
suspended until the nonfunctional, system is operable. The test every 7
days is not required for blind or blind-shear rams. The blind or blind-
shear rams shall be tested at least once every 30 days during
operation. A longer period between blowout preventer tests is allowed
when there is a stuck pipe or pressure-control operation and remedial
efforts are being performed. The tests shall be conducted as soon as
possible and before normal operations resume. The reason for postponing
testing shall be entered into the operations log.
(3) Following repairs that require disconnecting a pressure seal in
the assembly, the affected seal will be pressure tested.
(c) Drills. All personnel engaged in well-workover operations shall
participate in a weekly BOP drill to familiarize crew members with
appropriate safety measures.
(d) Stump tests. You may conduct a stump test for the BOP system on
location. A plan describing the stump test procedures must be included
in your Form BSEE-0124, Application for Permit to Modify, and must be
approved by the District Manager.
(e) Coiled tubing tests. You must test the coiled tubing connector
to a low pressure of 200 to 300 psi, followed by a high pressure test
to the rated working pressure of the connector or the expected surface
pressure, whichever is less. You must successfully pressure test the
dual check valves to the rated working pressure of the connector, the
rated working pressure of the dual check valve, expected surface
pressure, or the collapse pressure of the coiled tubing, whichever is
less.
(f) Recordings. You must record test pressures during BOP and
coiled tubing tests on a pressure chart, or with a digital recorder,
unless otherwise approved by the District Manager. The test interval
for each BOP system component must be 5 minutes, except for coiled
tubing operations, which must include a 10 minute high-pressure test
for the coiled tubing string. Your representative at the facility must
certify that the charts are correct.
(g) Operations log. The time, date, and results of all pressure
tests, actuations, inspections, and crew drills of the BOP system,
system components, and marine risers shall be recorded in the
operations log. The BOP tests shall be documented in accordance with
the following:
(1) The documentation shall indicate the sequential order of BOP
and auxiliary equipment testing and the pressure and duration of each
test. As an alternate, the documentation in the operations log may
reference a BOP test plan that contains the required information and is
retained on file at the facility.
[[Page 64539]]
(2) The control station used during the test shall be identified in
the operations log. For a subsea system, the pod used during the test
shall be identified in the operations log.
(3) Any problems or irregularities observed during BOP and
auxiliary equipment testing and any actions taken to remedy such
problems or irregularities shall be noted in the operations log.
(4) Documentation required to be entered in the operation log may
instead be referenced in the operations log. All records including
pressure charts, operations log, and referenced documents pertaining to
BOP tests, actuations, and inspections, shall be available for BSEE
review at the facility for the duration of well-workover activity.
Following completion of the well-workover activity, all such records
shall be retained for a period of 2 years at the facility, at the
lessee's filed office nearest the OCS facility, or at another location
conveniently available to the District Manager.
(h) Subsea BOPs. Stump test a subsea BOP system before
installation. You must:
(1) Test all ROV intervention functions on your subsea BOP stack
during the stump test. You must also test at least one set of rams
during the initial test on the seafloor. You must submit test
procedures with your APM for District Manager approval. You must:
(i) Ensure that the ROV hot stabs are function tested and are
capable of actuating, at a minimum, one set of pipe rams and one set of
blind-shear rams and unlatching the LMRP;
(ii) Document all your test results and make them available to BSEE
upon request; and
(2) Function test autoshear and deadman systems on your subsea BOP
stack during the stump test. You must also test the deadman system
during the initial test on the seafloor. You must:
(i) Submit test procedures with your APM for District Manager
approval.
(ii) Document the results of each test and make them available to
BSEE upon request.
(3) Use water to stump test a subsea BOP system. You may use
drilling or completion fluids to conduct subsequent tests of a subsea
BOP system.
Sec. 250.617 What are my BOP inspection and maintenance requirements?
(a) BOP inspections. (1) You must inspect your BOP system to ensure
that the equipment functions properly. The BOP inspections must meet or
exceed the provisions of Sections 17.10 and 18.10, Inspections,
described in API RP 53, Recommended Practices for Blowout Prevention
Equipment Systems for Drilling Wells (as incorporated by reference in
Sec. 250.198). You must document the procedures used, record the
results, and make them available to BSEE upon request. You must
maintain your records on the rig for 2 years or from the date of your
last major inspection, whichever is longer.
(2) You must visually inspect your BOP system and marine riser at
least once each day if weather and sea conditions permit. You may use
television cameras to inspect this equipment. The District Manager may
approve alternate methods and frequencies to inspect a marine riser.
(b) BOP maintenance. You must maintain your BOP system to ensure
that the equipment functions properly. The BOP maintenance must meet or
exceed the provisions of Sections 17.11 and 18.11, Maintenance; and
Sections 17.12 and 18.12, Quality Management, described in API RP 53,
Recommended Practices for Blowout Prevention Equipment Systems for
Drilling Wells (as incorporated by reference in Sec. 250.198). You
must document the procedures used, record the results, and make them
available to BSEE upon request. You must maintain your records on the
rig for 2 years or from the date of your last major inspection,
whichever is longer.
Sec. 250.618 Tubing and wellhead equipment.
The lessee shall comply with the following requirements during
well-workover operations with the tree removed:
(a) No tubing string shall 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.
(b) In the event of prolonged operations such as milling, fishing,
jarring, or washing over that could damage the casing, the casing shall
be pressure tested, calipered, or otherwise evaluated every 30 days and
the results submitted to the District Manager.
(c) When reinstalling the tree, you must:
(1) Equip wells to monitor for casing pressure according to the
following chart:
------------------------------------------------------------------------
If you have . . . you must equip . . . so you can monitor . . .
------------------------------------------------------------------------
(i) fixed platform the wellhead, all annuli (A, B, C, D,
wells, etc., annuli).
(ii) subsea wells, the tubing head, the production casing
annulus (A annulus).
(iii) hybrid* wells, the surface wellhead, all annuli at the surface
(A and B riser annuli).
If the production casing
below the mudline and
the production casing
riser above the mudline
are pressure isolated
from each other,
provisions must be made
to monitor the
production casing below
the mudline for casing
pressure.
------------------------------------------------------------------------
* Characterized as a well drilled with a subsea wellhead and completed
with a surface casing head, a surface tubing head, a surface tubing
hanger, and a surface christmas tree.
(2) Follow the casing pressure management requirements in subpart E
of this part.
(d) Wellhead, tree, and related equipment shall have a pressure
rating greater than the shut-in tubing pressure and shall be designed,
installed, used, maintained, and tested so as to achieve and maintain
pressure control. The tree shall be equipped with a minimum of one
master valve and one surface safety valve in the vertical run of the
tree when it is reinstalled.
(e) Subsurface safety equipment shall be installed, maintained, and
tested in compliance with Sec. 250.801 of this part.
Sec. 250.619 Wireline operations.
The lessee shall comply with the following requirements during
routine, as defined in Sec. 250.601 of this part, and nonroutine
wireline workover operations:
(a) Wireline operations shall be conducted so as to minimize
leakage of well fluids. Any leakage that does occur shall be contained
to prevent pollution.
(b) All wireline perforating operations and all other wireline
operations where communication exists between the completed
hydrocarbon-bearing zone(s) and the wellbore shall use a lubricator
assembly containing at least one wireline valve.
[[Page 64540]]
(c) When the lubricator is initially installed on the well, it
shall be successfully pressure tested to the expected shut-in surface
pressure.
Subpart G [Reserved]
Subpart H--Oil and Gas Production Safety Systems
Sec. 250.800 General requirements.
(a) Production safety equipment shall be designed, installed, used,
maintained, and tested in a manner to assure the safety and protection
of the human, marine, and coastal environments. Production safety
systems operated in subfreezing climates shall utilize equipment and
procedures selected with consideration of floating ice, icing, and
other extreme environmental conditions that may occur in the area.
Production shall not commence until the production safety system has
been approved and a preproduction inspection has been requested by the
lessee.
(b) For all new floating production systems (FPSs) (e.g., column-
stabilized-units (CSUs); floating production, storage and offloading
facilities (FPSOs); tension-leg platforms (TLPs); spars, etc.), you
must do all of the following:
(1) Comply with API RP 14J (as incorporated by reference in 30 CFR
250.198);
(2) Meet the drilling and production riser standards of API RP 2RD
(as incorporated by reference in 30 CFR 250.198);
(3) Design all stationkeeping systems for floating facilities to
meet the standards of API RP 2SK (as incorporated by reference in 30
CFR 250.198), as well as relevant U.S. Coast Guard regulations; and
(4) Design stationkeeping systems for floating facilities to meet
structural requirements in subpart I, Sec. Sec. 250.900 through
250.921 of this part.
Sec. 250.801 Subsurface safety devices.
(a) General. All tubing installations open to hydrocarbon-bearing
zones shall be equipped with subsurface safety devices that will shut
off the flow from the well in the event of an emergency unless, after
application and justification, the well is determined by the District
Manager to be incapable of natural flowing. These devices may consist
of a surface-controlled subsurface safety valve (SSSV), a subsurface-
controlled SSSV, an injection valve, a tubing plug, or a tubing/annular
subsurface safety device, and any associated safety valve lock or
landing nipple.
(b) Specifications for SSSVs. Surface-controlled and subsurface-
controlled SSSVs and safety valve locks and landing nipples installed
in the OCS shall conform to the requirements in Sec. 250.806 of this
part.
(c) Surface-controlled SSSVs. All tubing installations open to a
hydrocarbon-bearing zone which is capable of natural flow shall be
equipped with a surface-controlled SSSV, except as specified in
paragraphs (d), (f), and (g) of this section. The surface controls may
be located on the site or a remote location. Wells not previously
equipped with a surface-controlled SSSV and wells in which a surface-
controlled SSSV has been replaced with a subsurface-controlled SSSV in
accordance with paragraph (d)(2) of this section shall be equipped with
a surface-controlled SSSV when the tubing is first removed and
reinstalled.
(d) Subsurface-controlled SSSVs. Wells may be equipped with
subsurface-controlled SSSVs in lieu of a surface-controlled SSSV
provided the lessee demonstrates to the District Manager's satisfaction
that one of the following criteria are met:
(1) Wells not previously equipped with surface-controlled SSSVs
shall be so equipped when the tubing is first removed and reinstalled,
(2) The subsurface-controlled SSSV is installed in wells completed
from a single-well or multiwell satellite caisson or seafloor
completions, or
(3) The subsurface-controlled SSSV is installed in wells with a
surface-controlled SSSV that has become inoperable and cannot be
repaired without removal and reinstallation of the tubing.
(e) Design, installation, and operation of SSSVs. The SSSVs shall
be designed, installed, operated, and maintained to ensure reliable
operation.
(1) The device shall be installed at a depth of 100 feet or more
below the seafloor within 2 days after production is established. When
warranted by conditions such as permafrost, unstable bottom conditions,
hydrate formation, or paraffins, an alternate setting depth of the
subsurface safety device may be approved by the District Manager.
(2) Until a subsurface safety device is installed, the well shall
be attended in the immediate vicinity so that emergency actions may be
taken while the well is open to flow. During testing and inspection
procedures, the well shall not be left unattended while open to
production unless a properly operating subsurface-safety device has
been installed in the well.
(3) The well shall not be open to flow while the subsurface safety
device is removed, except when flowing of the well is necessary for a
particular operation such as cutting paraffin, bailing sand, or similar
operations.
(4) All SSSVs must be inspected, installed, maintained, and tested
in accordance with American Petroleum Institute Recommended Practice
14B, Recommended Practice for Design, Installation, Repair, and
Operation of Subsurface Safety Valve Systems (as specified in Sec.
250.198).
(f) Subsurface safety devices in shut-in wells. (1) New completions
(perforated but not placed on production) and completions shut in for a
period of 6 months shall be equipped with either--
(i) A pump-through-type tubing plug;
(ii) A surface-controlled SSSV, provided the surface control has
been rendered inoperative; or
(iii) An injection valve capable of preventing backflow.
(2) The setting depth of the subsurface safety device shall be
approved by the District Manager on a case-by-case basis, when
warranted by conditions such as permafrost, unstable bottom conditions,
hydrate formations, and paraffins.
(g) Subsurface safety devices in injection wells. A surface-
controlled SSSV or an injection valve capable of preventing backflow
shall be installed in all injection wells. This requirement is not
applicable if the District Manager concurs that the well is incapable
of flowing. The lessee shall verify the no-flow condition of the well
annually.
(h) Temporary removal for routine operations. (1) Each wireline- or
pumpdown-retrievable subsurface safety device may be removed, without
further authorization or notice, for a routine operation which does not
require the approval of a Form BSEE-0124, Application for Permit to
Modify, in Sec. 250.601 of this part for a period not to exceed 15
days.
(2) The well shall be identified by a sign on the wellhead stating
that the subsurface safety device has been removed. The removal of the
subsurface safety device shall be noted in the records as required in
Sec. 250.804(b) of this part. If the master valve is open, a trained
person shall be in the immediate vicinity of the well to attend the
well so that emergency actions may be taken, if necessary.
(3) A platform well shall be monitored, but a person need not
remain in the well-bay area continuously if the master valve is closed.
If the well is on a satellite structure, it must be attended or a pump-
through plug installed in the tubing at least 100 feet below the mud
line and the master valve closed, unless
[[Page 64541]]
otherwise approved by the District Manager.
(4) The well shall not be allowed to flow while the subsurface
safety device is removed, except when flowing the well is necessary for
that particular operation. The provisions of this paragraph are not
applicable to the testing and inspection procedures in Sec. 250.804 of
this part.
(i) Additional safety equipment. All tubing installations in which
a wireline- or pumpdown-retrievable subsurface safety device is
installed after the effective date of this subpart shall be equipped
with a landing nipple with flow couplings or other protective equipment
above and below to provide for the setting of the SSSV. The control
system for all surface-controlled SSSVs shall be an integral part of
the platform Emergency Shutdown System (ESD). In addition to the
activation of the ESD by manual action on the platform, the system may
be activated by a signal from a remote location. Surface-controlled
SSSVs shall close in response to shut-in signals from the ESD and in
response to the fire loop or other fire detection devices.
(j) Emergency action. In the event of an emergency, such as an
impending storm, any well not equipped with a subsurface safety device
and which is capable of natural flow shall have the device properly
installed as soon as possible with due consideration being given to
personnel safety.
Sec. 250.802 Design, installation, and operation of surface
production-safety systems.
(a) General. All production facilities, including separators,
treaters, compressors, headers, and flowlines shall be designed,
installed, and maintained in a manner which provides for efficiency,
safety of operation, and protection of the environment.
(b) Platforms. You must protect all platform production facilities
with a basic and ancillary surface safety system designed, analyzed,
installed, tested, and maintained in operating condition in accordance
with API RP 14C (as incorporated by reference in Sec. 250.198). If you
use processing components other than those for which Safety Analysis
Checklists are included in API RP 14C you must utilize the analysis
technique and documentation specified therein to determine the effects
and requirements of these components on the safety system. Safety
device requirements for pipelines are under Sec. 250.1004.
(c) Specification for surface safety valves (SSV) and underwater
safety valves (USV). All wellhead SSVs, USVs, and their actuators which
are installed in the OCS shall conform to the requirements in Sec.
250.806 of this part.
(d) Use of SSVs and USV's. All SSVs and USVs must be inspected,
installed, maintained, and tested in accordance with API RP 14H,
Recommended Practice for Installation, Maintenance, and Repair of
Surface Safety Valves and Underwater Safety Valves Offshore (as
incorporated by reference in Sec. 250.198). If any SSV or USV does not
operate properly or if any fluid flow is observed during the leakage
test, the valve shall be repaired or replaced.
(e) Approval of safety-systems design and installation features.
Prior to installation, the lessee shall submit, in duplicate for
approval to the District Manager a production safety system application
containing information relative to design and installation features.
Information concerning approved design and installation features shall
be maintained by the lessee at the lessee's offshore field office
nearest the OCS facility or other location conveniently available to
the District Manager. All approvals are subject to field verifications.
The application shall include the following:
(1) A schematic flow diagram showing tubing pressure, size,
capacity, design working pressure of separators, flare scrubbers,
treaters, storage tanks, compressors, pipeline pumps, metering devices,
and other hydrocarbon-handling vessels.
(2) A schematic piping flow diagram (API RP 14C, Figure E, as
incorporated by reference in Sec. 250.198) and the related Safety
analysis Function Evaluation chart (API RP 14C, subsection 4.3c, as
incorporated by reference in Sec. 250.198).
(3) A schematic piping diagram showing the size and maximum
allowable working pressures as determined in accordance with API RP
14E, Design and Installation of Offshore Production Platform Piping
Systems (as incorporated by reference in Sec. 250.198).
(4) Electrical system information including the following:
(i) A plan for each platform deck outlining all hazardous areas
classified according to API RP 500, Recommended Practice for
Classification of Locations for Electrical Installations at Petroleum
Facilities Classified as Class I, Division 1 and Division 2, or API RP
505, Recommended Practice for Classification of Locations for
Electrical Installations at Petroleum Facilities Classified as Class I,
Zone 0, Zone 1, and Zone 2 (as incorporated by reference in Sec.
250.198), and outlining areas in which potential ignition sources,
other than electrical, are to be installed. The area outlined will
include the following information:
(A) All major production equipment, wells, and other significant
hydrocarbon sources and a description of the type of decking, ceiling,
walls (e.g., grating or solid) and firewalls; and
(B) Location of generators, control rooms, panel boards, major
cabling/conduit routes, and identification of the primary wiring method
(e.g., type cable, conduit, or wire).
(ii) Elementary electrical schematic of any platform safety shut-
down system with a functional legend.
(5) Certification that the design for the mechanical and electrical
systems to be installed were approved by registered professional
engineers. After these systems are installed, the lessee shall submit a
statement to the District Manager certifying that new installations
conform to the approved designs of this subpart.
(6) The design and schematics of the installation and maintenance
of all fire- and gas-detection systems shall include the following:
(i) Type, location, and number of detection sensors;
(ii) Type and kind of alarms, including emergency equipment to be
activated;
(iii) Method used for detection;
(iv) Method and frequency of calibration; and
(v) A functional block diagram of the detection system, including
the electric power supply.
(7) The service fee listed in Sec. 250.125. The fee you must pay
will be determined by the number of components involved in the review
and approval process.
Sec. 250.803 Additional production system requirements.
(a) For all production platforms, you must comply with the
following production safety system requirements, in addition to the
requirements of Sec. 250.802 of this subpart and the requirements of
API RP 14C (as incorporated by reference in Sec. 250.198).
(b) Design, installation, and operation of additional production
systems--(1) Pressure and fired vessels. Pressure and fired vessels
must be designed, fabricated, and code stamped in accordance with the
applicable provisions of Sections I, IV, and VIII of the American
Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code.
Pressure and fired vessels must have maintenance inspection, rating,
repair, and alteration performed in accordance with the applicable
provisions of API Pressure Vessel Inspections Code: In-Service
Inspection,
[[Page 64542]]
Rating, Repair, and Alteration, API 510 (except Sections 5.8 and 9.5)
(as incorporated by reference in Sec. 250.198).
(i) Pressure relief valves shall be designed, installed, and
maintained in accordance with applicable provisions of sections I, IV,
and VIII of the ASME Boiler and Pressure Vessel Code. The relief valves
shall conform to the valve-sizing and pressure-relieving requirements
specified in these documents; however, the relief valves, except
completely redundant relief valves, shall be set no higher than the
maximum-allowable working pressure of the vessel. All relief valves and
vents shall be piped in such a way as to prevent fluid from striking
personnel or ignition sources.
(ii) Steam generators operating at less than 15 pounds per square
inch gauge (psig) shall be equipped with a level safety low (LSL)
sensor which will shut off the fuel supply when the water level drops
below the minimum safe level. Steam generators operating at greater
than 15 psig require, in addition to an LSL, a water-feeding device
which will automatically control the water level.
(iii) The lessee shall use pressure recorders to establish the new
operating pressure ranges of pressure vessels at any time when there is
a change in operating pressures that requires new settings for the
high-pressure shut-in sensor and/or the low-pressure shut-in sensor as
provided herein. The pressure-recorder charts used to determine current
operating pressure ranges shall be maintained at the lessee's field
office nearest the OCS facility or at other locations conveniently
available to the District Manager. The high-pressure shut-in sensor
shall be set no higher than 15 percent or 5 psi, whichever is greater,
above the highest operating pressure of the vessel. This setting shall
also be set sufficiently below (5 percent or 5 psi, whichever is
greater) the relief valve's set pressure to assure that the pressure
source is shut in before the relief valve activates. The low-pressure
shut-in sensor shall activate no lower than 15 percent or 5 psi,
whichever is greater, below the lowest pressure in the operating range.
The activation of low-pressure sensors on pressure vessels which
operate at less than 5 psi shall be approved by the District Manager on
a case-by-case basis.
(2) Flowlines. (i) You must equip flowlines from wells with high-
and low-pressure shut-in sensors located in accordance with section A.1
and Figure A1 of API RP 14C (as incorporated by reference in Sec.
250.198). The lessee shall use pressure recorders to establish the new
operating pressure ranges of flowlines at any time when there is a
significant change in operating pressures. The most recent pressure-
recorder charts used to determine operating pressure ranges shall be
maintained at the lessee's field office nearest the OCS facility or at
other locations conveniently available to the District Manager. The
high-pressure shut-in sensor(s) shall be set no higher than 15 percent
or 5 psi, whichever is greater, above the highest operating pressure of
the line. But in all cases, it shall be set sufficiently below the
maximum shut-in wellhead pressure or the gas-lift supply pressure to
assure actuation of the SSV. The low-pressure shut-in sensor(s) shall
be set no lower than 15 percent or 5 psi, whichever is greater, below
the lowest operating pressure of the line in which it is installed.
(ii) If a well flows directly to the pipeline before separation,
the flowline and valves from the well located upstream of and including
the header inlet valve(s) shall have a working pressure equal to or
greater than the maximum shut-in pressure of the well unless the
flowline is protected by one of the following:
(A) A relief valve which vents into the platform flare scrubber or
some other location approved by the District Manager. The platform
flare scrubber shall be designed to handle, without liquid-hydrocarbon
carryover to the flare, the maximum-anticipated flow of liquid
hydrocarbons which may be relieved to the vessel.
(B) Two SSV's with independent high-pressure sensors installed with
adequate volume upstream of any block valve to allow sufficient time
for the valve(s) to close before exceeding the maximum allowable
working pressure.
(iii) If you are installing flowlines constructed of unbonded
flexible pipe on a floating platform, you must:
(A) Review the manufacturer's Design Methodology Verification
Report and the independent verification agent's (IVA's) certificate for
the design methodology contained in that report to ensure that the
manufacturer has complied with the requirements of API Spec 17J (as
incorporated by reference in Sec. 250.198);
(B) Determine that the unbonded flexible pipe is suitable for its
intended purpose on the lease or pipeline right-of-way;
(C) Submit to the BSEE District Manager the manufacturer's design
specifications for the unbonded flexible pipe; and
(D) Submit to the BSEE District Manager a statement certifying that
the pipe is suitable for its intended use and that the manufacturer has
complied with the IVA requirements of API Spec 17J (as incorporated by
reference in Sec. 250.198).
(3) Safety sensors. All shutdown devices, valves, and pressure
sensors shall function in a manual reset mode. Sensors with integral
automatic reset shall be equipped with an appropriate device to
override the automatic reset mode. All pressure sensors shall be
equipped to permit testing with an external pressure source.
(4) ESD. The ESD must conform to the requirements of Appendix C,
section C1, of API RP 14C (as incorporated by reference in Sec.
250.198), and the following:
(i) The manually operated ESD valve(s) shall be quick-opening and
nonrestricted to enable the rapid actuation of the shutdown system.
Only ESD stations at the boat landing may utilize a loop of breakable
synthetic tubing in lieu of a valve.
(ii) Closure of the SSV shall not exceed 45 seconds after automatic
detection of an abnormal condition or actuation of an ESD. The surface-
controlled SSSV shall close in not more than 2 minutes after the shut-
in signal has closed the SSV. Design-delayed closure time greater than
2 minutes shall be justified by the lessee based on the individual
well's mechanical/production characteristics and be approved by the
District Manager.
(iii) A schematic of the ESD which indicates the control functions
of all safety devices for the platforms shall be maintained by the
lessee on the platform or at the lessee's field office nearest the OCS
facility or other location conveniently available to the District
Manager.
(5) Engines: (i) Engine exhaust. You must equip engine exhausts to
comply with the insulation and personnel protection requirements of API
RP 14C, section 4.2c(4) (as incorporated by reference in Sec.
250.198). Exhaust piping from diesel engines must be equipped with
spark arresters.
(ii) Diesel engine air intake. All diesel engine air intakes must
be equipped with a device to shutdown the diesel engine in the event of
runaway. Diesel engines that are continuously attended must be equipped
with either remote operated manual or automatic shutdown devices.
Diesel engines that are not continuously attended must be equipped with
automatic shutdown devices.
(6) Glycol dehydration units. A pressure relief system or an
adequate vent shall be installed on the glycol regenerator (reboiler)
which will prevent overpressurization. The
[[Page 64543]]
discharge of the relief valve shall be vented in a nonhazardous manner.
(7) Gas compressors. You must equip compressor installations with
the following protective equipment as required in API RP 14C, Sections
A4 and A8 (as incorporated by reference in Sec. 250.198).
(i) A Pressure Safety High (PSH), a Pressure Safety Low (PSL), a
Pressure Safety Valve (PSV), and a Level Safety High (LSH), and an LSL
to protect each interstage and suction scrubber.
(ii) A Temperature Safety High (TSH) on each compressor discharge
cylinder.
(iii) The PSH and PSL shut-in sensors and LSH shut-in controls
protecting compressor suction and interstage scrubbers shall be
designated to actuate automatic shutdown valves (SDV) located in each
compressor suction and fuel gas line so that the compressor unit and
the associated vessels can be isolated from all input sources. All
automatic SDV's installed in compressor suction and fuel gas piping
shall also be actuated by the shutdown of the prime mover. Unless
otherwise approved by the District Manager, gas--well gas affected by
the closure of the automatic SDV on a compressor suction shall be
diverted to the pipeline or shut in at the wellhead.
(iv) A blowdown valve is required on the discharge line of all
compressor installations of 1,000 horsepower (746 kilowatts) or
greater.
(8) Firefighting systems. Firefighting systems for both open and
totally enclosed platforms installed for extreme weather conditions or
other reasons shall conform to subsection 5.2, Firewater systems, of
API RP 14G (as incorporated by reference in Sec. 250.198), Fire
Prevention and Control Open Type Offshore Production Platforms, and
shall require approval of the District Manager. The following
additional requirements shall apply for both open- and closed-
production platforms:
(i) A firewater system consisting of rigid pipe with firehose
stations or fixed firewater monitors shall be installed. The firewater
system shall be installed to provide needed protection in all areas
where production-handling equipment is located. A fixed waterspray
system shall be installed in enclosed well-bay areas where hydrocarbon
vapors may accumulate.
(ii) Fuel or power for firewater pump drivers shall be available
for at least 30 minutes of run time during a platform shut-in. If
necessary, an alternate fuel or power supply shall be installed to
provide for this pump-operating time unless an alternate firefighting
system has been approved by the District Manager.
(iii) A firefighting system using chemicals may be used in lieu of
a water system if the District Manager determines that the use of a
chemical system provides equivalent fire-protection control.
(iv) A diagram of the firefighting system showing the location of
all firefighting equipment shall be posted in a prominent place on the
facility or structure.
(v) For operations in subfreezing climates, the lessee shall
furnish evidence to the District Manager that the firefighting system
is suitable for the conditions.
(9) Fire- and gas-detection system. (i) Fire (flame, heat, or
smoke) sensors shall be installed in all enclosed classified areas. Gas
sensors shall be installed in all inadequately ventilated, enclosed
classified areas. Adequate ventilation is defined as ventilation which
is sufficient to prevent accumulation of significant quantities of
vapor-air mixture in concentrations over 25 percent of the lower
explosive limit (LEL). One approved method of providing adequate
ventilation is a change of air volume each 5 minutes or 1 cubic foot of
air-volume flow per minute per square foot of solid floor area,
whichever is greater. Enclosed areas (e.g., buildings, living quarters,
or doghouses) are defined as those areas confined on more than four of
their six possible sides by walls, floors, or ceilings more restrictive
to air flow than grating or fixed open louvers and of sufficient size
to all entry of personnel. A classified area is any area classified
Class I, Group D, Division 1 or 2, following the guidelines of API RP
500 (as incorporated by reference in Sec. 250.198), or any area
classified Class I, Zone 0, Zone 1, or Zone 2, following the guidelines
of API RP 505 (as incorporated by reference in Sec. 250.198).
(ii) All detection systems shall be capable of continuous
monitoring. Fire-detection systems and portions of combustible gas-
detection systems related to the higher gas concentration levels shall
be of the manual-reset type. Combustible gas-detection systems related
to the lower gas-concentration level may be of the automatic-reset
type.
(iii) A fuel-gas odorant or an automatic gas-detection and alarm
system is required in enclosed, continuously manned areas of the
facility which are provided with fuel gas. Living quarters and
doghouses not containing a gas source and not located in a classified
area do not require a gas detection system.
(iv) The District Manager may require the installation and
maintenance of a gas detector or alarm in any potentially hazardous
area.
(v) Fire- and gas-detection systems must be an approved type,
designed and installed according to API RP 14C, API RP 14G, and either
API RP 14F or API RP 14FZ (the preceding four documents as incorporated
by reference in Sec. 250.198).
(10) Electrical equipment. Electrical equipment and systems shall
be designed, installed, and maintained in accordance with the
requirements in Sec. 250.114 of this part.
(11) Erosion. A program of erosion control shall be in effect for
wells or fields having a history of sand production. The erosion-
control program may include sand probes, X-ray, ultrasonic, or other
satisfactory monitoring methods. Records by lease, indicating the wells
which have erosion-control programs in effect and the results of the
programs, shall be maintained by the lessee for a period of 2 years and
shall be made available to BSEE upon request.
(c) General platform operations. (1) Surface or subsurface safety
devices shall not be bypassed or blocked out of service unless they are
temporarily out of service for startup, maintenance, or testing
procedures. Only the minimum number of safety devices shall be taken
out of service. Personnel shall monitor the bypassed or blocked-out
functions until the safety devices are placed back in service. Any
surface or subsurface safety device which is temporarily out of service
shall be flagged.
(2) When wells are disconnected from producing facilities and blind
flanged, equipped with a tubing plug, or the master valves have been
locked closed, you are not required to comply with the provisions of
API RP 14C (as incorporated by reference in Sec. 250.198) or this
regulation concerning the following:
(i) Automatic fail-close SSV's on wellhead assemblies, and
(ii) The PSH and PSL shut-in sensors in flowlines from wells.
(3) When pressure or atmospheric vessels are isolated from
production facilities (e.g., inlet valve locked closed or inlet blind-
flanged) and are to remain isolated for an extended period of time,
safety device compliance with API RP 14C or this subpart is not
required.
(4) All open-ended lines connected to producing facilities and
wells shall be plugged or blind-flanged, except those lines designed to
be open-ended such as flare or vent lines.
(d) Welding and burning practices and procedures. All welding,
burning, and hot-tapping activities shall be conducted according to the
specific
[[Page 64544]]
requirements in Sec. Sec. 250.109 through 250.113 of this part.
Sec. 250.804 Production safety-system testing and records.
(a) Inspection and testing. The safety-system devices shall be
successfully inspected and tested by the lessee at the interval
specified below or more frequently if operating conditions warrant.
Testing must be in accordance with API RP 14C, Appendix D (as
incorporated by reference in Sec. 250.198), and the following:
(1) Testing requirements for subsurface safety devices are as
follows:
(i) Each surface-controlled subsurface safety device installed in a
well, including such devices in shut-in and injection wells, shall be
tested in place for proper operation when installed or reinstalled and
thereafter at intervals not exceeding 6 months. If the device does not
operate properly, or if a liquid leakage rate in excess of 200 cubic
centimeters per minute or a gas leakage rate in excess of 5 cubic feet
per minute is observed, the device shall be removed, repaired and
reinstalled, or replaced. Testing shall be in accordance with API RP
14B (as incorporated by reference in Sec. 250.198) to ensure proper
operation.
(ii) Each subsurface-controlled SSSV installed in a well shall be
removed, inspected, and repaired or adjusted, as necessary, and
reinstalled or replaced at intervals not exceeding 6 months for those
valves not installed in a landing nipple and 12 months for those valves
installed in a landing nipple.
(iii) Each tubing plug installed in a well shall be inspected for
leakage by opening the well to possible flow at intervals not exceeding
6 months. If a liquid leakage rate in excess of 200 cubic centimeters
per minute or a gas leakage rate in excess of 5 cubic feet per minute
is observed, the device shall be removed, repaired and reinstalled, or
replaced. An additional tubing plug may be installed in lieu of
removal.
(iv) Injection valves shall be tested in the manner as outlined for
testing tubing plugs in paragraph (a)(1)(iii) of this section. Leakage
rates outlined in paragraph (a)(1)(iii) of this section shall apply.
(2) All PSV's shall be tested for operation at least once every 12
months. These valves shall be either bench-tested or equipped to permit
testing with an external pressure source. Weighted disk vent valves
used as PSV's on atmospheric tanks may be disassembled and inspected in
lieu of function testing.
(3) The following safety devices (excluding electronic pressure
transmitters and level sensors) must be tested at least once each
calendar month, but at no time will more than 6 weeks elapse between
tests:
(i) All PSH and PSL,
(ii) All LSH and LSL controls,
(iii) All automatic inlet SDV's which are actuated by a sensor on a
vessel or compressor, and
(iv) All SDV's in liquid discharge lines and actuated by vessel
low-level sensors.
(4) The following electronic pressure transmitters and level
sensors must be tested at least once every 3 months, but at no time may
more than 120 days elapse between tests:
(i) All PSH and PSL, and
(ii) All LSH and LSL controls.
(5) All SSV's and USV's shall be tested for operation and for
leakage at least once each calendar month, but at no time shall more
than 6 weeks elapse between tests. The SSV's and USV's must be tested
in accordance with the test procedures specified in API RP 14H (as
incorporated by reference in Sec. 250.198). If the SSV or USV does not
operate properly or if any fluid flow is observed during the leakage
test, the valve shall be repaired or replaced.
(6) All flowline Flow Safety Valves (FSV) shall be checked for
leakage at least once each calendar month, but at no time shall more
than 6 weeks elapse between tests. The FSV's must be tested for leakage
in accordance with the test procedures specified in API RP 14C,
Appendix D, section D4, table D2, subsection D (as incorporated by
reference in Sec. 250.198). If the leakage measured exceeds a liquid
flow of 200 cubic centimeters per minute or a gas flow of 5 cubic feet
per minute, the FSV's shall be repaired or replaced.
(7) The TSH shutdown controls installed on compressor installations
which can be nondestructively tested shall be tested every 6 months and
repaired or replaced as necessary.
(8) All pumps for firewater systems shall be inspected and operated
weekly.
(9) All fire- (flame, heat, or smoke) detection systems shall be
tested for operation and recalibrated every 3 months provided that
testing can be performed in a nondestructive manner. Open flame or
devices operating at temperatures which could ignite a methane-air
mixture shall not be used. All combustible gas-detection systems shall
be calibrated every 3 months.
(10) All TSH devices shall be tested at least once every 12 months,
excluding those addressed in paragraph (a)(7) of this section and those
which would be destroyed by testing. Burner safety low and flow safety
low devices shall also be tested at least once every 12 months.
(11) The ESD shall be tested for operation at least once each
calendar month, but at no time shall more than 6 weeks elapse between
tests. The test shall be conducted by alternating ESD stations monthly
to close at least one wellhead SSV and verify a surface-controlled SSSV
closure for that well as indicated by control circuitry actuation.
(12) Prior to the commencement of production, the lessee shall
notify the District Manager when the lessee is ready to conduct a
preproduction test and inspection of the integrated safety system. The
lessee shall also notify the District Manager upon commencement of
production in order that a complete inspection may be conducted.
(b) Records. The lessee shall maintain records for a period of 2
years for each subsurface and surface safety device installed. These
records shall be maintained by the lessee at the lessee's field office
nearest the OCS facility or other locations conveniently available to
the District Manager. These records shall be available for review by a
representative of BSEE. The records shall show the present status and
history of each device, including dates and details of installation,
removal, inspection, testing, repairing, adjustments, and
reinstallation.
Sec. 250.805 Safety device training.
Personnel installing, inspecting, testing, and maintaining these
safety devices and personnel operating the production platforms shall
be qualified in accordance with 30 CFR 250, subpart O.
Sec. 250.806 Safety and pollution prevention equipment quality
assurance requirements.
(a) General requirements. (1) Except as provided in paragraph
(b)(1) of this section, you may install only certified safety and
pollution prevention equipment (SPPE) in wells located on the OCS. SPPE
includes the following:
(i) Surface safety valves (SSV) and actuators;
(ii) Underwater safety valves (USV) and actuators; and
(iii) Subsurface safety valves (SSSV) and associated safety valve
locks and landing nipples.
(2) Certified SPPE is equipment the manufacturer certifies as
manufactured under a quality assurance program BSEE recognizes. BSEE
considers all other SPPE as noncertified. BSEE recognizes two quality
assurance programs:
(i) ANSI/ASME SPPE-1-1994 and SPPE-1d-1996 Addenda, Quality
Assurance and Certification of Safety and Pollution Prevention
Equipment Used in Offshore Oil and Gas Operations (as incorporated by
reference in Sec. 250.198); and
[[Page 64545]]
(ii) API Spec Q1, Specification for Quality Programs for the
Petroleum, Petrochemical and Natural Gas Industry (as incorporated by
reference in Sec. 250.198).
(3) All SSV's and USV's must meet the technical specifications of
API Spec 6A and 6AV1. All SSSVs must meet the technical specifications
of API Specification 14A (as incorporated by reference in Sec.
250.198). However, SSSVs and related equipment planned to be used in
high pressure high temperature environments must meet the additional
requirements set forth in Sec. 250.807.
(4) For information on all standards mentioned in this section, see
Sec. 250.198.
(b) Use of noncertified SPPE. (1) Before April 1, 1998, you may
continue to use and install noncertified SPPE if it was in your
inventory as of April 1, 1988, and was included in a list of
noncertified SPPE submitted to BSEE prior to August 29, 1988.
(2) On or after April 1, 1998:
(i) You may not install additional noncertified SPPE; and
(ii) When noncertified SPPE that is already in service requires
offsite repair, remanufacturing, or hot work such as welding, you must
replace it with certified SPPE.
(c) Recognizing other quality assurance programs. The BSEE will
consider recognizing other quality assurance programs covering the
manufacture of SPPE. If you want BSEE to evaluate other quality
assurance programs, submit relevant information about the program and
reasons for recognition by BSEE to the Chief, Office of Offshore
Regulatory Programs; Bureau of Safety and Environmental Enforcement;
MS-4020; 381 Elden Street, Herndon, Virginia 20170-4817.
Sec. 250.807 Additional requirements for subsurface safety valves and
related equipment installed in high pressure high temperature (HPHT)
environments.
(a) If you plan to install SSSVs and related equipment in an HPHT
environment, you must submit detailed information with your Application
for Permit to Drill (APD), Application for Permit to Modify (APM), or
Deepwater Operations Plan (DWOP) that demonstrates the SSSVs and
related equipment are capable of performing in the applicable HPHT
environment. Your detailed information must include the following:
(1) A discussion of the SSSVs' and related equipment's design
verification analysis;
(2) A discussion of the SSSVs' and related equipment's design
validation and functional testing process and procedures used; and
(3) An explanation of why the analysis, process, and procedures
ensure that the SSSVs and related equipment are fit-for-service in the
applicable HPHT environment.
(b) For this section, HPHT environment means when one or more of
the following well conditions exist:
(1) The completion of the well requires completion equipment or
well control equipment assigned a pressure rating greater than 15,000
psig or a temperature rating greater than 350 degrees Fahrenheit;
(2) The maximum anticipated surface pressure or shut-in tubing
pressure is greater than 15,000 psig on the seafloor for a well with a
subsea wellhead or at the surface for a well with a surface wellhead;
or
(3) The flowing temperature is equal to or greater than 350 degrees
Fahrenheit on the seafloor for a well with a subsea wellhead or at the
surface for a well with a surface wellhead.
(c) For this section, related equipment includes wellheads, tubing
heads, tubulars, packers, threaded connections, seals, seal assemblies,
production trees, chokes, well control equipment, and any other
equipment that will be exposed to the HPHT environment.
Sec. 250.808 Hydrogen sulfide.
Production operations in zones known to contain hydrogen sulfide
(H2S) or in zones where the presence of H2S is
unknown, as defined in Sec. 250.490 of this part, shall be conducted
in accordance with that section and other relevant requirements of
subpart H, Production Safety Systems.
Subpart I--Platforms and Structures
General Requirements for Platforms
Sec. 250.900 What general requirements apply to all platforms?
(a) You must design, fabricate, install, use, maintain, inspect,
and assess all platforms and related structures on the Outer
Continental Shelf (OCS) so as to ensure their structural integrity for
the safe conduct of drilling, workover, and production operations. In
doing this, you must consider the specific environmental conditions at
the platform location.
(b) You must also submit an application under Sec. 250.905 of this
subpart and obtain the approval of the Regional Supervisor before
performing any of the activities described in the following table:
------------------------------------------------------------------------
Activity requiring application and Conditions for conducting the
approval activity
------------------------------------------------------------------------
(1) Install a platform. This includes (i) You must adhere to the
placing a newly constructed platform requirements of this subpart,
at a location or moving an existing including the industry
platform to a new site. standards in Sec. 250.901.
(ii) If you are installing a
floating platform, you must
also adhere to U.S. Coast
Guard (USCG) regulations for
the fabrication, installation,
and inspection of floating OCS
facilities.
(2) Major modification to any platform. (i) You must adhere to the
This includes any structural changes requirements of this subpart,
that materially alter the approved including the industry
plan or cause a major deviation from standards in Sec. 250.901.
approved operations and any (ii) Before you make a major
modification that increases loading on modification to a floating
a platform by 10 percent or more. platform, you must obtain
approval from both the BSEE
and the USCG for the
modification.
(3) Major repair of damage to any (i) You must adhere to the
platform. This includes any corrective requirements of this subpart,
operations involving structural including the industry
members affecting the structural standards in Sec. 250.901.
integrity of a portion or all of the (ii) Before you make a major
platform. repair to a floating platform,
you must obtain approval from
both the BSEE and the USCG for
the repair.
(4) Convert an existing platform at the (i) The Regional Supervisor
current location for a new purpose. will determine on a case-by-
case basis the requirements
for an application for
conversion of an existing
platform at the current
location.
(ii) At a minimum, your
application must include: the
converted platform's intended
use; and a demonstration of
the adequacy of the design and
structural condition of the
converted platform.
(iii) If a floating platform,
you must also adhere to USCG
regulations for the
fabrication, installation, and
inspection of floating OCS
facilities.
[[Page 64546]]
(5) Convert an existing mobile offshore (i) The Regional Supervisor
drilling unit (MODU) for a new purpose. will determine on a case-by-
case basis the requirements
for an application for
conversion of an existing
MODU.
(ii) At a minimum, your
application must include: the
converted MODU's intended
location and use; a
demonstration of the adequacy
of the design and structural
condition of the converted
MODU; and a demonstration that
the level of safety for the
converted MODU is at least
equal to that of re-used
platforms.
(iii) You must also adhere to
USCG regulations for the
fabrication, installation, and
inspection of floating OCS
facilities.
------------------------------------------------------------------------
(c) Under emergency conditions, you may make repairs to primary
structural elements to restore an existing permitted condition without
submitting an application or receiving prior BSEE approval for up to
120-calendar days following an event. You must notify the Regional
Supervisor of the damage that occurred within 24 hours of its
discovery, and you must provide a written completion report to the
Regional Supervisor of the repairs that were made within 1 week after
completing the repairs. If you make emergency repairs on a floating
platform, you must also notify the USCG.
(d) You must determine if your new platform or major modification
to an existing platform is subject to the Platform Verification Program
(PVP). Section 250.910 of this subpart fully describes the facilities
that are subject to the PVP. If you determine that your platform is
subject to the PVP, you must follow the requirements of Sec. Sec.
250.909 through 250.918 of this subpart.
(e) You must submit notification of the platform installation date
and the final as-built location data to the Regional Supervisor within
45-calendar days of completion of platform installation.
(1) For platforms not subject to the Platform Verification Program
(PVP), BSEE will cancel the approved platform application 1 year after
the approval has been granted if the platform has not been installed.
If BSEE cancels the approval, you must resubmit your platform
application and receive BSEE approval if you still plan to install the
platform.
(2) For platforms subject to the PVP, cancellation of an approval
will be on an individual platform basis. For these platforms, BSEE will
identify the date when the installation approval will be cancelled (if
installation has not occurred) during the application and approval
process. If BSEE cancels your installation approval, you must resubmit
your platform application and receive BSEE approval if you still plan
to install the platform.
Sec. 250.901 What industry standards must your platform meet?
(a) In addition to the other requirements of this subpart, your
plans for platform design, analysis, fabrication, installation, use,
maintenance, inspection and assessment must, as appropriate, conform
to:
(1) ACI Standard 318-95, Building Code Requirements for Reinforced
Concrete (ACI 318-95) and Commentary (ACI 318R-95) (incorporated by
reference at Sec. 250.198);
(2) ACI 357R-84, Guide for the Design and Construction of Fixed
Offshore Concrete Structures, 1984; reapproved 1997 (incorporated by
reference at Sec. 250.198);
(3) ANSI/AISC 360-05, Specification for Structural Steel Buildings,
(as specified in Sec. 250.198);
(4) American Petroleum Institute (API) Bulletin 2INT-DG, Interim
Guidance for Design of Offshore Structures for Hurricane Conditions,
(as incorporated by reference in Sec. 250.198);
(5) API Bulletin 2INT-EX, Interim Guidance for Assessment of
Existing Offshore Structures for Hurricane Conditions, (as incorporated
by reference in Sec. 250.198);
(6) API Bulletin 2INT-MET, Interim Guidance on Hurricane Conditions
in the Gulf of Mexico, (as incorporated by reference in Sec. 250.198);
(7) API Recommend Practice (RP) 2A-WSD, RP for Planning, Designing,
and Constructing Fixed Offshore Platforms--Working Stress Design (as
incorporated by reference in Sec. 250.198);
(8) API RP 2FPS, Recommended Practice for Planning, Designing, and
Constructing Floating Production Systems, (as incorporated by reference
in Sec. 250.198);
(9) API RP 2I, In-Service Inspection of Mooring Hardware for
Floating Drilling Units (as incorporated by reference in Sec.
250.198);
(10) API RP 2RD, Design of Risers for Floating Production Systems
(FPSs) and Tension-Leg Platforms (TLPs), (as incorporated by reference
in Sec. 250.198);
(11) API RP 2SK, Recommended Practice for Design and Analysis of
Station Keeping Systems for Floating Structures, (as incorporated by
reference in Sec. 250.198);
(12) API RP 2SM, Recommended Practice for Design, Manufacture,
Installation, and Maintenance of Synthetic Fiber Ropes for Offshore
Mooring, (as incorporated by reference in Sec. 250.198);
(13) API RP 2T, Recommended Practice for Planning, Designing and
Constructing Tension Leg Platforms, (as incorporated by reference in
Sec. 250.198);
(14) API RP 14J, Recommended Practice for Design and Hazards
Analysis for Offshore Production Facilities, (as incorporated by
reference in Sec. 250.198);
(15) American Society for Testing and Materials (ASTM) Standard C
33-07, approved December 15, 2007, Standard Specification for Concrete
Aggregates (as incorporated by reference in Sec. 250.198);
(16) ASTM Standard C 94/C 94M-07, approved January 1, 2007,
Standard Specification for Ready-Mixed Concrete (as incorporated by
reference in Sec. 250.198);
(17) ASTM Standard C 150-07, approved May 1, 2007, Standard
Specification for Portland Cement (as incorporated by reference in
Sec. 250.198);
(18) ASTM Standard C 330-05, approved December 15, 2005, Standard
Specification for Lightweight Aggregates for Structural Concrete (as
incorporated by reference in Sec. 250.198);
(19) ASTM Standard C 595-08, approved January 1, 2008, Standard
Specification for Blended Hydraulic Cements (as incorporated by
reference in Sec. 250.198);
(20) AWS D1.1, Structural Welding Code--Steel, including
Commentary, (as incorporated by reference in Sec. 250.198);
(21) AWS D1.4, Structural Welding Code--Reinforcing Steel, (as
incorporated by reference in Sec. 250.198);
(22) AWS D3.6M, Specification for Underwater Welding, (as
incorporated by reference in Sec. 250.198);
(23) NACE Standard MR0175, Sulfide Stress Cracking Resistant
Metallic Materials for Oilfield Equipment, (as incorporated by
reference in Sec. 250.198);
(24) NACE Standard RP0176-2003, Item No. 21018, Standard
[[Page 64547]]
Recommended Practice, Corrosion Control of Steel Fixed Offshore
Structures Associated with Petroleum Production.
(b) You must follow the requirements contained in the documents
listed under paragraph (a) of this section insofar as they do not
conflict with other provisions of 30 CFR part 250. You may use
applicable provisions of these documents, as approved by the Regional
Supervisor, for the design, fabrication, and installation of platforms
such as spars, since standards specifically written for such structures
do not exist. You may also use alternative codes, rules, or standards,
as approved by the Regional Supervisor, under the conditions enumerated
in Sec. 250.141.
(c) For information on the standards mentioned in this section, and
where they may be obtained, see Sec. 250.198 of this part.
(d) The following chart summarizes the applicability of the
industry standards listed in this section for fixed and floating
platforms:
------------------------------------------------------------------------
Applicable to . .
Industry standard .
------------------------------------------------------------------------
(1) ACI Standard 318-95, Building Code Requirements Fixed and
for Reinforced Concrete (ACI 318-95) and Commentary floating
(ACI 318R-95), platform, as
appropriate.
(2) ANSI/AISC 360-05, Specification for Structural .................
Steel Buildings;
(3) API Bulletin 2INT-DG, Interim Guidance for Design .................
of Offshore Structures for Hurricane Conditions;
(4) API Bulletin 2INT-EX, Interim Guidance for .................
Assessment of Existing Offshore Structures for
Hurricane Conditions;
(5) API Bulletin 2INT-MET, Interim Guidance on .................
Hurricane Conditions in the Gulf of Mexico;
(6) API RP 2A-WSD, RP for Planning, Designing, and .................
Constructing Fixed Offshore Platforms--Working
Stress Design;
(7) ASTM Standard C 33-07, approved December 15, .................
2007, Standard Specification for Concrete
Aggregates;
(8) ASTM Standard C 94/C 94M-07, approved January 1, .................
2007, Standard Specification for Ready-Mixed
Concrete;
(9) ASTM Standard C 150-07, approved May 1, 2007, .................
Standard Specification for Portland Cement;
(10) ASTM Standard C 330-05, approved December 15, .................
2005, Standard Specification for Lightweight
Aggregates for Structural Concrete;
(11) ASTM Standard C 595-08, approved January 1, .................
2008, Standard Specification for Blended Hydraulic
Cements;
(12) AWS D1.1, Structural Welding Code--Steel;
(13) AWS D1.4, Structural Welding Code--Reinforcing .................
Steel;
(14) AWS D3.6M, Specification for Underwater Welding; .................
(15) NACE Standard RP 0176-2003, Standard Recommended .................
Practice (RP), Corrosion Control of Steel Fixed
Offshore Platforms Associated with Petroleum
Production;
(16) ACI 357R-84, Guide for the Design and Fixed platforms.
Construction of Fixed Offshore Concrete Structures,
1984; reapproved 1997,
(17) API RP 14J, RP for Design and Hazards Analysis Floating
for Offshore Production Facilities; platforms.
(18) API RP 2FPS, RP for Planning, Designing, and .................
Constructing, Floating Production Systems;
(19) API RP 2RD, Design of Risers for Floating .................
Production Systems (FPSs) and Tension-Leg Platforms
(TLPs);
(20) API RP 2SK, RP for Design and Analysis of .................
Station Keeping Systems for Floating Structures;
(21) API RP 2T, RP for Planning, Designing, and .................
Constructing Tension Leg Platforms;
(22) API RP 2SM, RP for Design, Manufacture, .................
Installation, and Maintenance of Synthetic Fiber
Ropes for Offshore Mooring;
(23) API RP 2I, In-Service Inspection of Mooring .................
Hardware for Floating Drilling Units
------------------------------------------------------------------------
Sec. 250.902 What are the requirements for platform removal and
location clearance?
You must remove all structures according to Sec. Sec. 250.1725
through 250.1730 of Subpart Q--Decommissioning Activities of this part.
Sec. 250.903 What records must I keep?
(a) You must compile, retain, and make available to BSEE
representatives for the functional life of all platforms:
(1) The as-built drawings;
(2) The design assumptions and analyses;
(3) A summary of the fabrication and installation nondestructive
examination records;
(4) The inspection results from the inspections required by Sec.
250.919 of this subpart; and
(5) Records of repairs not covered in the inspection report
submitted under Sec. 250.919(b).
(b) You must record and retain the original material test results
of all primary structural materials during all stages of construction.
Primary material is material that, should it fail, would lead to a
significant reduction in platform safety, structural reliability, or
operating capabilities. Items such as steel brackets, deck stiffeners
and secondary braces or beams would not generally be considered primary
structural members (or materials).
(c) You must provide BSEE with the location of these records in the
certification statement of your application for platform approval as
required in Sec. 250.905(j).
Platform Approval Program
Sec. 250.904 What is the Platform Approval Program?
(a) The Platform Approval Program is the BSEE basic approval
process for platforms on the OCS. The requirements of the Platform
Approval Program are described in Sec. Sec. 250.904 through 250.908 of
this subpart. Completing these requirements will satisfy BSEE criteria
for approval of fixed platforms of a proven design that will be placed
in the shallow water areas (<= 400 ft.) of the Gulf of Mexico OCS.
(b) The requirements of the Platform Approval Program must be met
by all platforms on the OCS. Additionally, if you want approval for a
floating platform; a platform of unique design; or a platform being
installed in deepwater (> 400 ft.) or a frontier area, you must also
meet the requirements of the
[[Page 64548]]
Platform Verification Program. The requirements of the Platform
Verification Program are described in Sec. Sec. 250.909 through
250.918 of this subpart.
Sec. 250.905 How do I get approval for the installation,
modification, or repair of my platform?
The Platform Approval Program requires that you submit the
information, documents, and fee listed in the following table for your
proposed project. In lieu of submitting the paper copies specified in
the table, you may submit your application electronically in accordance
with 30 CFR 250.186(a)(3).
------------------------------------------------------------------------
Required submittal Required contents Other requirements
------------------------------------------------------------------------
(a) Application cover letter Proposed structure You must submit
designation, lease three copies. If,
number, area, name, your facility is
and block number, subject to the
and the type of Platform
facility your Verification
facility (e.g., Program (PVP), you
drilling, must submit four
production, copies.
quarters). The
structure
designation must be
unique for the
field (some fields
are made up of
several blocks);
i.e. once a
platform ``A'' has
been used in the
field there should
never be another
platform ``A'' even
if the old platform
``A'' has been
removed. Single
well free standing
caissons should be
given the same
designation as the
well. All other
structures are to
be designated by
letter designations.
(b) Location plat........... Latitude and Your plat must be
longitude drawn to a scale of
coordinates, 1 inch equals 2,000
Universal Mercator feet and include
grid-system the coordinates of
coordinates, state the lease block
plane coordinates boundary lines. You
in the Lambert or must submit three
Transverse Mercator copies.
Projection System,
and distances in
feet from the
nearest block
lines. These
coordinates must be
based on the NAD
(North American
Datum) 27 datum
plane coordinate
system.
(c) Front, Side, and Plan Platform dimensions Your drawing sizes
View drawings. and orientation, must not exceed
elevations relative 11'' x 17''. You
to M.L.L.W. (Mean must submit three
Lower Low Water), copies (four copies
and pile sizes and for PVP
penetration. applications).
(d) Complete set of The approved for Your drawing sizes
structural drawings. construction must not exceed
fabrication 11'' x 17''. You
drawings should be must submit one
submitted copy.
including; e.g.,
cathodic protection
systems; jacket
design; pile
foundations;
drilling,
production, and
pipeline risers and
riser tensioning
systems; turrets
and turret-and-hull
interfaces; mooring
and tethering
systems;
foundations and
anchoring systems.
(e) Summary of environmental A summary of the You must submit one
data. environmental data copy.
described in the
applicable
standards
referenced under
Sec. 250.901(a)
of this subpart and
in Sec. 250.198
of Subpart A, where
the data is used in
the design or
analysis of the
platform. Examples
of relevant data
include information
on waves, wind,
current, tides,
temperature, snow
and ice effects,
marine growth, and
water depth.
(f) Summary of the Loading information You must submit one
engineering design data. (e.g., live, dead, copy.
environmental),
structural
information (e.g.,
design-life;
material types;
cathodic protection
systems; design
criteria; fatigue
life; jacket
design; deck
design; production
component design;
pile foundations;
drilling,
production, and
pipeline risers and
riser tensioning
systems; turrets
and turret-and-hull
interfaces;
foundations,
foundation pilings
and templates, and
anchoring systems;
mooring or
tethering systems;
fabrication and
installation
guidelines), and
foundation
information (e.g.,
soil stability,
design criteria).
(g) Project-specific studies All studies You must submit one
used in the platform design pertinent to copy of each study.
or installation. platform design or
installation, e.g.,
oceanographic and/
or soil reports
including the
overall site
investigative
report required in
Sec. 250.906.
(h) Description of the loads Loads imposed by You must submit one
imposed on the facility. jacket; decks; copy.
production
components;
drilling,
production, and
pipeline risers,
and riser
tensioning systems;
turrets and turret-
and-hull
interfaces;
foundations,
foundation pilings
and templates, and
anchoring systems;
and mooring or
tethering systems.
[[Page 64549]]
(i) Summary of safety A summary of You must submit one
factors utilized. pertinent derived copy.
factors of safety
against failure for
major structural
members, e.g.,
unity check ratios
exceeding 0.85 for
steel-jacket
platform members,
indicated on
``line'' sketches
of jacket sections.
(j) A copy of the in-service This plan is You must submit one
inspection plan. described in Sec. copy.
250.919.
(k) Certification statement. The following An authorized
statement: ``The company
design of this representative must
structure has been sign the statement.
certified by a You must submit one
recognized copy.
classification
society, or a
registered civil or
structural engineer
or equivalent, or a
naval architect or
marine engineer or
equivalent,
specializing in the
design of offshore
structures. The
certified design
and as-built plans
and specifications
will be on file at
(give location)''.
(l) Payment of the service
fee listed in Sec.
250.125.
------------------------------------------------------------------------
Sec. 250.906 What must I do to obtain approval for the proposed site
of my platform?
(a) Shallow hazards surveys. You must perform a high-resolution or
acoustic-profiling survey to obtain information on the conditions
existing at and near the surface of the seafloor. You must collect
information through this survey sufficient to determine the presence of
the following features and their likely effects on your proposed
platform:
(1) Shallow faults;
(2) Gas seeps or shallow gas;
(3) Slump blocks or slump sediments;
(4) Shallow water flows;
(5) Hydrates; or
(6) Ice scour of seafloor sediments.
(b) Geologic surveys. You must perform a geological survey relevant
to the design and siting of your platform. Your geological survey must
assess:
(1) Seismic activity at your proposed site;
(2) Fault zones, the extent and geometry of faulting, and
attenuation effects of geologic conditions near your site; and
(3) For platforms located in producing areas, the possibility and
effects of seafloor subsidence.
(c) Subsurface surveys. Depending upon the design and location of
your proposed platform and the results of the shallow hazard and
geologic surveys, the Regional Supervisor may require you to perform a
subsurface survey. This survey will include a testing program for
investigating the stratigraphic and engineering properties of the soil
that may affect the foundations or anchoring systems for your facility.
The testing program must include adequate in situ testing, boring, and
sampling to examine all important soil and rock strata to determine its
strength classification, deformation properties, and dynamic
characteristics. If required to perform a subsurface survey, you must
prepare and submit to the Regional Supervisor a summary report to
briefly describe the results of your soil testing program, the various
field and laboratory test methods employed, and the applicability of
these methods as they pertain to the quality of the samples, the type
of soil, and the anticipated design application. You must explain how
the engineering properties of each soil stratum affect the design of
your platform. In your explanation you must describe the uncertainties
inherent in your overall testing program, and the reliability and
applicability of each test method.
(d) Overall site investigation report. You must prepare and submit
to the Regional Supervisor an overall site investigation report for
your platform that integrates the findings of your shallow hazards
surveys and geologic surveys, and, if required, your subsurface
surveys. Your overall site investigation report must include analyses
of the potential for:
(1) Scouring of the seafloor;
(2) Hydraulic instability;
(3) The occurrence of sand waves;
(4) Instability of slopes at the platform location;
(5) Liquefaction, or possible reduction of soil strength due to
increased pore pressures;
(6) Degradation of subsea permafrost layers;
(7) Cyclic loading;
(8) Lateral loading;
(9) Dynamic loading;
(10) Settlements and displacements;
(11) Plastic deformation and formation collapse mechanisms; and
(12) Soil reactions on the platform foundations or anchoring
systems.
Sec. 250.907 Where must I locate foundation boreholes?
(a) For fixed or bottom-founded platforms and tension leg
platforms, your maximum distance from any foundation pile to a soil
boring must not exceed 500 feet.
(b) For deepwater floating platforms which utilize catenary or
taut-leg moorings, you must take borings at the most heavily loaded
anchor location, at the anchor points approximately 120 and 240 degrees
around the anchor pattern from that boring, and, as necessary, other
points throughout the anchor pattern to establish the soil profile
suitable for foundation design purposes.
Sec. 250.908 What are the minimum structural fatigue design
requirements?
(a) API RP 2A-WSD, Recommended Practice for Planning, Designing and
Constructing Fixed Offshore Platforms (as incorporated by reference in
Sec. 250.198), requires that the design fatigue life of each joint and
member be twice the intended service life of the structure. When
designing your platform, the following table provides minimum fatigue
life safety factors for critical structural members and joints.
------------------------------------------------------------------------
If . . . Then . . .
------------------------------------------------------------------------
(1) There is sufficient structural The results of the analysis
redundancy to prevent catastrophic must indicate a maximum
failure of the platform or structure calculated life of twice
under consideration, the design life of the
platform.
(2) There is not sufficient structural The results of a fatigue
redundancy to prevent catastrophic analysis must indicate a
failure of the platform or structure, minimum calculated life or
three times the design life
of the platform.
[[Page 64550]]
(3) The desirable degree of redundancy is The results of a fatigue
significantly reduced as a result of analysis must indicate a
fatigue damage, minimum calculated life of
three times the design life
of the platform.
------------------------------------------------------------------------
(b) The documents incorporated by reference in Sec. 250.901 may
require larger safety factors than indicated in paragraph (a) of this
section for some key components. When the documents incorporated by
reference require a larger safety factor than the chart in paragraph
(a) of this section, the requirements of the incorporated document will
prevail.
Platform Verification Program
Sec. 250.909 What is the Platform Verification Program?
The Platform Verification Program is the BSEE approval process for
ensuring that floating platforms; platforms of a new or unique design;
platforms in seismic areas; or platforms located in deepwater or
frontier areas meet stringent requirements for design and construction.
The program is applied during construction of new platforms and major
modifications of, or repairs to, existing platforms. These requirements
are in addition to the requirements of the Platform Approval Program
described in Sec. Sec. 250.904 through 250.908 of this subpart.
Sec. 250.910 Which of my facilities are subject to the Platform
Verification Program?
(a) All new fixed or bottom-founded platforms that meet any of the
following five conditions are subject to the Platform Verification
Program:
(1) Platforms installed in water depths exceeding 400 feet (122
meters);
(2) Platforms having natural periods in excess of 3 seconds;
(3) Platforms installed in areas of unstable bottom conditions;
(4) Platforms having configurations and designs which have not
previously been used or proven for use in the area; or
(5) Platforms installed in seismically active areas.
(b) All new floating platforms are subject to the Platform
Verification Program to the extent indicated in the following table:
------------------------------------------------------------------------
If . . . Then . . .
------------------------------------------------------------------------
(1) Your new floating platform is a The entire platform is
buoyant offshore facility that does not subject to the Platform
have a ship-shaped hull, Verification Program
including the following
associated structures:
(i) Drilling, production,
and pipeline risers, and
riser tensioning systems
(each platform must be
designed to accommodate all
the loads imposed by all
risers and riser does not
have tensioning systems);
(ii) Turrets and turret-and-
hull interfaces;
(iii) Foundations,
foundation pilings and
templates, and anchoring
systems; and
(iv) Mooring or tethering
systems.
(2) Your new floating platform is a Only the following
buoyant offshore facility with a ship- structures that may be
shaped hull, associated with a floating
platform are subject to the
Platform Verification
Program:
(i) Drilling, production,
and pipeline risers, and
riser tensioning systems
(each platform must be
designed to accommodate all
the loads imposed by all
risers and riser tensioning
systems);
(ii) Turrets and turret-and-
hull interfaces;
(iii) Foundations,
foundation pilings and
templates, and anchoring
systems; and
(iv) Mooring or tethering
systems.
------------------------------------------------------------------------
(c) If a platform is originally subject to the Platform
Verification Program, then the conversion of that platform at that same
site for a new purpose, or making a major modification of, or major
repair to, that platform, is also subject to the Platform Verification
Program. A major modification includes any modification that increases
loading on a platform by 10 percent or more. A major repair is a
corrective operation involving structural members affecting the
structural integrity of a portion or all of the platform. Before you
make a major modification or repair to a floating platform, you must
obtain approval from both the BSEE and the USCG.
(d) The applicability of Platform Verification Program requirements
to other types of facilities will be determined by BSEE on a case-by-
case basis.
Sec. 250.911 If my platform is subject to the Platform Verification
Program, what must I do?
If your platform, conversion, or major modification or repair meets
the criteria in Sec. 250.910, you must:
(a) Design, fabricate, install, use, maintain and inspect your
platform, conversion, or major modification or repair to your platform
according to the requirements of this subpart, and the applicable
documents listed in Sec. 250.901(a) of this subpart;
(b) Comply with all the requirements of the Platform Approval
Program found in Sec. Sec. 250.904 through 250.908 of this subpart.
(c) Submit for the Regional Supervisor's approval three copies each
of the design verification, fabrication verification, and installation
verification plans required by Sec. 250.912;
(d) Submit a complete schedule of all phases of design,
fabrication, and installation for the Regional Supervisor's approval.
You must include a project management timeline, Gantt Chart, that
depicts when interim and final reports required by Sec. Sec. 250.916,
250.917, and 250.918 will be submitted to the Regional Supervisor for
each phase. On the timeline, you must break-out the specific scopes of
work that inherently stand alone (e.g., deck, mooring systems, tendon
systems, riser systems, turret systems).
(e) Include your nomination of a Certified Verification Agent (CVA)
as a part of each verification plan required by Sec. 250.912;
(f) Follow the additional requirements in Sec. Sec. 250.913
through 250.918;
(g) Obtain approval for modifications to approved plans and for
major deviations from approved installation
[[Page 64551]]
procedures from the Regional Supervisor; and
(h) Comply with applicable USCG regulations for floating OCS
facilities.
Sec. 250.912 What plans must I submit under the Platform Verification
Program?
If your platform, associated structure, or major modification meets
the criteria in Sec. 250.910, you must submit the following plans to
the Regional Supervisor for approval:
(a) Design verification plan. You may submit your design
verification plan to BSEE with or subsequent to the submittal of your
Development and Production Plan (DPP) or Development Operations
Coordination Document (DOCD) to BOEM. Your design verification must be
conducted by, or be under the direct supervision of, a registered
professional civil or structural engineer or equivalent, or a naval
architect or marine engineer or equivalent, with previous experience in
directing the design of similar facilities, systems, structures, or
equipment. For floating platforms, you must ensure that the
requirements of the USCG for structural integrity and stability, e.g.,
verification of center of gravity, etc., have been met. Your design
verification plan must include the following:
(1) All design documentation specified in Sec. 250.905 of this
subpart;
(2) Abstracts of the computer programs used in the design process;
and
(3) A summary of the major design considerations and the approach
to be used to verify the validity of these design considerations.
(b) Fabrication verification plan. The Regional Supervisor must
approve your fabrication verification plan before you may initiate any
related operations. Your fabrication verification plan must include the
following:
(1) Fabrication drawings and material specifications for artificial
island structures and major members of concrete-gravity and steel-
gravity structures;
(2) For jacket and floating structures, all the primary load-
bearing members included in the space-frame analysis; and
(3) A summary description of the following:
(i) Structural tolerances;
(ii) Welding procedures;
(iii) Material (concrete, gravel, or silt) placement methods;
(iv) Fabrication standards;
(v) Material quality-control procedures;
(vi) Methods and extent of nondestructive examinations for welds
and materials; and
(vii) Quality assurance procedures.
(c) Installation verification plan. The Regional Supervisor must
approve your installation verification plan before you may initiate any
related operations. Your installation verification plan must include:
(1) A summary description of the planned marine operations;
(2) Contingencies considered;
(3) Alternative courses of action; and
(4) An identification of the areas to be inspected. You must
specify the acceptance and rejection criteria to be used for any
inspections conducted during installation, and for the post-
installation verification inspection.
(d) You must combine fabrication verification and installation
verification plans for manmade islands or platforms fabricated and
installed in place.
Sec. 250.913 When must I resubmit Platform Verification Program
plans?
(a) You must resubmit any design verification, fabrication
verification, or installation verification plan to the Regional
Supervisor for approval if:
(1) The CVA changes;
(2) The CVA's or assigned personnel's qualifications change; or
(3) The level of work to be performed changes.
(b) If only part of a verification plan is affected by one of the
changes described in paragraph (a) of this section, you can resubmit
only the affected part. You do not have to resubmit the summary of
technical details unless you make changes in the technical details.
Sec. 250.914 How do I nominate a CVA?
(a) As part of your design verification, fabrication verification,
or installation verification plan, you must nominate a CVA for the
Regional Supervisor's approval. You must specify whether the nomination
is for the design, fabrication, or installation phase of verification,
or for any combination of these phases.
(b) For each CVA, you must submit a list of documents to be
forwarded to the CVA, and a qualification statement that includes the
following:
(1) Previous experience in third-party verification or experience
in the design, fabrication, installation, or major modification of
offshore oil and gas platforms. This should include fixed platforms,
floating platforms, manmade islands, other similar marine structures,
and related systems and 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.
This should include computer programs, hardware, and testing materials
and equipment;
(5) Ability to perform the CVA functions for the specific project
considering current commitments;
(6) Previous experience with BSEE requirements and procedures;
(7) The level of work to be performed by the CVA.
Sec. 250.915 What are the CVA's primary responsibilities?
(a) The CVA must conduct specified reviews according to Sec. Sec.
250.916, 250.917, and 250.918 of this subpart.
(b) Individuals or organizations acting as CVAs must not function
in any capacity that would create a conflict of interest, or the
appearance of a conflict of interest.
(c) The CVA must consider the applicable provisions of the
documents listed in Sec. 250.901(a); the alternative codes, rules, and
standards approved under Sec. 250.901(b); and the requirements of this
subpart.
(d) The CVA is the primary contact with the Regional Supervisor and
is directly responsible for providing immediate reports of all
incidents that affect the design, fabrication and installation of the
platform.
Sec. 250.916 What are the CVA's primary duties during the design
phase?
(a) The CVA must use good engineering judgment and practices in
conducting an independent assessment of the design of the platform,
major modification, or repair. The CVA must ensure that the platform,
major modification, or repair is designed to withstand the
environmental and functional load conditions appropriate for the
intended service life at the proposed location.
(b) Primary duties of the CVA during the design phase include the
following:
----------------------------------------------------------------------------------------------------------------
Type of facility . . . The CVA must . . .
----------------------------------------------------------------------------------------------------------------
(1) For fixed platforms and non-ship-shaped floating Conduct an independent assessment of all proposed:
facilities, (i) Planning criteria;
(ii) Operational requirements;
[[Page 64552]]
(iii) Environmental loading data;
(iv) Load determinations;
(v) Stress analyses;
(vi) Material designations;
(vii) Soil and foundation conditions;
(viii) Safety factors; and
(ix) Other pertinent parameters of the proposed design.
(2) For all floating facilities, Ensure that the requirements of the U.S. Coast Guard for
structural integrity and stability, e.g., verification of
center of gravity, etc., have been met. The CVA must also
consider:
(i) Drilling, production, and pipeline risers, and riser
tensioning systems;
(ii) Turrets and turret-and-hull interfaces;
(iii) Foundations, foundation pilings and templates, and
anchoring systems; and
(iv) Mooring or tethering systems.
----------------------------------------------------------------------------------------------------------------
(c) The CVA must submit interim reports and a final report to the
Regional Supervisor, and to you, during the design phase in accordance
with the approved schedule required by Sec. 250.911(d). In each
interim and final report the CVA must:
(1) Provide a summary of the material reviewed and the CVA's
findings;
(2) In the final CVA report, make a recommendation that the
Regional Supervisor either accept, request modifications, or reject the
proposed design unless such a recommendation has been previously made
in an interim report;
(3) Describe the particulars of how, by whom, and when the
independent review was conducted; and
(4) Provide any additional comments the CVA deems necessary.
Sec. 250.917 What are the CVA's primary duties during the fabrication
phase?
(a) The CVA must use good engineering judgment and practices in
conducting an independent assessment of the fabrication activities. The
CVA must monitor the fabrication of the platform or major modification
to ensure that it has been built according to the approved design and
the fabrication plan. If the CVA finds that fabrication procedures are
changed or design specifications are modified, the CVA must inform you.
If you accept the modifications, then the CVA must so inform the
Regional Supervisor.
(b) Primary duties of the CVA during the fabrication phase include
the following:
----------------------------------------------------------------------------------------------------------------
Type of facility . . . The CVA must . . .
----------------------------------------------------------------------------------------------------------------
(1) For all fixed platforms and non-ship-shaped Make periodic onsite inspections while fabrication is in
floating facilities, progress and must verify the following fabrication items,
as appropriate:
(i) Quality control by lessee and builder;
(ii) Fabrication site facilities;
(iii) Material quality and identification methods;
(iv) Fabrication procedures specified in the approved
plan, and adherence to such procedures;
(v) Welder and welding procedure qualification and
identification;
(vi) Structural tolerances specified and adherence to
those tolerances;
(vii) The nondestructive examination requirements, and
evaluation results of the specified examinations;
(viii) Destructive testing requirements and results;
(ix) Repair procedures;
(x) Installation of corrosion-protection systems and
splash-zone protection;
(xi) Erection procedures to ensure that overstressing of
structural members does not occur;
(xii) Alignment procedures;
(xiii) Dimensional check of the overall structure,
including any turrets, turret-and-hull interfaces, any
mooring line and chain and riser tensioning line
segments; and
(xiv) Status of quality-control records at various stages
of fabrication.
(2) For all floating facilities, Ensure that the requirements of the U.S. Coast Guard
floating for structural integrity and stability, e.g.,
verification of center of gravity, etc., have been met.
The CVA must also consider:
(i) Drilling, production, and pipeline risers, and riser
tensioning systems (at least for the initial fabrication
of these elements);
(ii) Turrets and turret-and-hull interfaces;
(iii) Foundation pilings and templates, and anchoring
systems; and
(iv) Mooring or tethering systems.
----------------------------------------------------------------------------------------------------------------
(c) The CVA must submit interim reports and a final report to the
Regional Supervisor, and to you, during the fabrication phase in
accordance with the approved schedule required by Sec. 250.911(d). In
each interim and final report the CVA must:
(1) Give details of how, by whom, and when the independent
monitoring activities were conducted;
(2) Describe the CVA's activities during the verification process;
(3) Summarize the CVA's findings;
(4) Confirm or deny compliance with the design specifications and
the approved fabrication plan;
(5) In the final CVA report, make a recommendation to accept or
reject the fabrication unless such a recommendation has been previously
made in an interim report; and
(6) Provide any additional comments that the CVA deems necessary.
Sec. 250.918 What are the CVA's primary duties during the
installation phase?
(a) The CVA must use good engineering judgment and practice in
[[Page 64553]]
conducting an independent assessment of the installation activities.
(b) Primary duties of the CVA during the installation phase include
the following:
----------------------------------------------------------------------------------------------------------------
The CVA must . . . Operation or equipment to be inspected . . .
----------------------------------------------------------------------------------------------------------------
(1) Verify, as appropriate, (i) Loadout and initial flotation operations;
(ii) Towing operations to the specified location, and
review the towing records;
(iii) Launching and uprighting operations;
(iv) Submergence operations;
(v) Pile or anchor installations;
(vi) Installation of mooring and tethering systems;
(vii) Final deck and component installations; and
(viii) Installation at the approved location according to
the approved design and the installation plan.
(2) Witness (for a fixed or floating platform), (i) The loadout of the jacket, decks, piles, or structures
from each fabrication site;
(ii) The actual installation of the platform or major
modification and the related installation activities.
(3) Witness (for a floating platform), (i) The loadout of the platform;
(ii) The installation of drilling, production, and
pipeline risers, and riser tensioning systems (at least
for the initial installation of these elements);
(iii) The installation of turrets and turret-and-hull
interfaces;
(iv) The installation of foundation pilings and templates,
and anchoring systems; and
(v) The installation of the mooring and tethering systems.
(4) Conduct an onsite survey, Survey the platform after transportation to the approved
location.
(5) Spot-check as necessary to determine compliance (i) Equipment;
with the applicable documents listed in Sec. (ii) Procedures; and
250.901(a); the alternative codes, rules and (iii) Recordkeeping.
standards approved under Sec. 250.901(b); the
requirements listed in Sec. 250.903 and Sec.
Sec. 250.906 through 250.908 of this subpart and
the approved plans,
----------------------------------------------------------------------------------------------------------------
(c) The CVA must submit interim reports and a final report to the
Regional Supervisor, and to you, during the installation phase in
accordance with the approved schedule required by Sec. 250.911(d). In
each interim and final report the CVA must:
(1) Give details of how, by whom, and when the independent
monitoring activities were conducted;
(2) Describe the CVA's activities during the verification process;
(3) Summarize the CVA's findings;
(4) Confirm or deny compliance with the approved installation plan;
(5) In the final report, make a recommendation to accept or reject
the installation unless such a recommendation has been previously made
in an interim report; and
(6) Provide any additional comments that the CVA deems necessary.
Inspection, Maintenance, and Assessment of Platforms
Sec. 250.919 What in-service inspection requirements must I meet?
(a) You must submit a comprehensive in-service inspection report
annually by November 1 to the Regional Supervisor that must include:
(1) A list of fixed and floating platforms you inspected in the
preceding 12 months;
(2) The extent and area of inspection for both the above-water and
underwater portions of the platform and the pertinent components of the
mooring system for floating platforms;
(3) The type of inspection employed (e.g., visual, magnetic
particle, ultrasonic testing);
(4) The overall structural condition of each platform, including a
corrosion protection evaluation; and
(5) A summary of the inspection results indicating what repairs, if
any, were needed.
(b) If any of your structures have been exposed to a natural
occurrence (e.g., hurricane, earthquake, or tropical storm), the
Regional Supervisor may require you to submit an initial report of all
structural damage, followed by subsequent updates, which include the
following:
(1) A list of affected structures;
(2) A timetable for conducting the inspections described in section
14.4.3 of API RP 2A-WSD (as incorporated by reference in Sec.
250.198); and
(3) An inspection plan for each structure that describes the work
you will perform to determine the condition of the structure.
(c) The Regional Supervisor may also require you to submit the
results of the inspections referred to in paragraph (b)(2) of this
section, including a description of any detected damage that may
adversely affect structural integrity, an assessment of the structure's
ability to withstand any anticipated environmental conditions, and any
remediation plans. Under Sec. Sec. 250.900(b)(3) and 250.905, you must
obtain approval from BSEE before you make major repairs of any damage
unless you meet the requirements of Sec. 250.900(c).
Sec. 250.920 What are the BSEE requirements for assessment of fixed
platforms?
(a) You must document all wells, equipment, and pipelines supported
by the platform if you intend to use either the A-2 or A-3 assessment
category. Assessment categories are defined in API RP 2A-WSD, Section
17.3 (as incorporated by reference in Sec. 250.198). If BSEE objects
to the assessment category you used for your assessment, you may need
to redesign and/or modify the platform to adequately demonstrate that
the platform is able to withstand the environmental loadings for the
appropriate assessment category.
(b) You must perform an analysis check when your platform will have
additional personnel, additional topside facilities, increased
environmental or operational loading, or inadequate deck height your
platform suffered significant damage (e.g., experienced damage to
primary structural members or conductor guide trays or global
structural integrity is adversely affected); or the exposure category
changes to a more restrictive level (see Sections 17.2.1 through 17.2.5
of API RP 2A-WSD, incorporated by reference in
[[Page 64554]]
Sec. 250.198, for a description of assessment initiators).
(c) You must initiate mitigation actions for platforms that do not
pass the assessment process of API RP 2A-WSD. You must submit
applications for your mitigation actions (e.g., repair, modification,
decommissioning) to the Regional Supervisor for approval before you
conduct the work.
(d) The BSEE may require you to conduct a platform design basis
check when the reduced environmental loading criteria contained in API
RP 2A-WSD Section 17.6 are not applicable.
(e) By November 1, 2009, you must submit a complete list of all the
platforms you operate, together with all the appropriate data to
support the assessment category you assign to each platform and the
platform assessment initiators (as defined in API RP 2A-WSD) to the
Regional Supervisor. You must submit subsequent complete lists and the
appropriate data to support the consequence-of-failure category every 5
years thereafter, or as directed by the Regional Supervisor.
(f) The use of Section 17, Assessment of Existing Platforms, of API
RP 2A-WSD is limited to existing fixed structures that are serving
their original approved purpose. You must obtain approval from the
Regional Supervisor for any change in purpose of the platform,
following the provisions of API RP 2A-WSD, Section 15, Re-use.
Sec. 250.921 How do I analyze my platform for cumulative fatigue?
(a) If you are required to analyze cumulative fatigue on your
platform because of the results of an inspection or platform
assessment, you must ensure that the safety factors for critical
elements listed in Sec. 250.908 are met or exceeded.
(b) If the calculated life of a joint or member does not meet the
criteria of Sec. 250.908, you must either mitigate the load,
strengthen the joint or member, or develop an increased inspection
process.
Subpart J--Pipelines and Pipeline Rights-of-Way
Sec. 250.1000 General requirements.
(a) Pipelines and associated valves, flanges, and fittings shall be
designed, installed, operated, maintained, and abandoned to provide
safe and pollution-free transportation of fluids in a manner which does
not unduly interfere with other uses in the Outer Continental Shelf
(OCS).
(b) An application must be accompanied by payment of the service
fee listed in Sec. 250.125 and submitted to the Regional Supervisor
and approval obtained before:
(1) Installation, modification, or abandonment of a lease term
pipeline;
(2) Installation or modification of a right-of-way (other than
lease term) pipeline; or
(3) Modification or relinquishment of a pipeline right-of way.
(c)(1) Department of the Interior (DOI) pipelines, as defined in
Sec. 250.1001, must meet the requirements in Sec. Sec. 250.1000
through 250.1008.
(2) A pipeline right-of-way grant holder must identify in writing
to the Regional Supervisor the operator of any pipeline located on its
right-of-way, if the operator is different from the right-of-way grant
holder.
(3) A producing operator must identify for its own records, on all
existing pipelines located on its lease or right-of-way, the specific
points at which operating responsibility transfers to a transporting
operator.
(i) Each producing operator must, if practical, durably mark all of
its above-water transfer points by April 14, 1999, or the date a
pipeline begins service, whichever is later.
(ii) If it is not practical to durably mark a transfer point, and
the transfer point is located above water, then the operator must
identify the transfer point on a schematic located on the facility.
(iii) If a transfer point is located below water, then the operator
must identify the transfer point on a schematic and provide the
schematic to BSEE upon request.
(iv) If adjoining producing and transporting operators cannot agree
on a transfer point by April 14, 1999, the BSEE Regional Supervisor and
the Department of Transportation (DOT) Office of Pipeline Safety (OPS)
Regional Director may jointly determine the transfer point.
(4) The transfer point serves as a regulatory boundary. An operator
may write to the BSEE Regional Supervisor to request an exception to
this requirement for an individual facility or area. The Regional
Supervisor, in consultation with the OPS Regional Director and affected
parties, may grant the request.
(5) Pipeline segments designed, constructed, maintained, and
operated under DOT regulations but transferring to DOI regulation as of
October 16, 1998, may continue to operate under DOT design and
construction requirements until significant modifications or repairs
are made to those segments. After October 16, 1998, BSEE operational
and maintenance requirements will apply to those segments.
(6) Any producer operating a pipeline that crosses into State
waters without first connecting to a transporting operator's facility
on the OCS must comply with this subpart. Compliance must extend from
the point where hydrocarbons are first produced, through and including
the last valve and associated safety equipment (e.g., pressure safety
sensors) on the last production facility on the OCS.
(7) Any producer operating a pipeline that connects facilities on
the OCS must comply with this subpart.
(8) Any operator of a pipeline that has a valve on the OCS
downstream (landward) of the last production facility may ask in
writing that the BSEE Regional Supervisor recognize that valve as the
last point BSEE will exercise its regulatory authority.
(9) A pipeline segment is not subject to BSEE regulations for
design, construction, operation, and maintenance if:
(i) It is downstream (generally shoreward) of the last valve and
associated safety equipment on the last production facility on the OCS;
and
(ii) It is subject to regulation under 49 CFR parts 192 and 195.
(10) DOT may inspect all upstream safety equipment (including
valves, over-pressure protection devices, cathodic protection
equipment, and pigging devices, etc.) that serve to protect the
integrity of DOT-regulated pipeline segments.
(11) OCS pipeline segments not subject to DOT regulation under 49
CFR parts 192 and 195 are subject to all BSEE regulations.
(12) A producer may request that its pipeline operate under DOT
regulations governing pipeline design, construction, operation, and
maintenance.
(i) The operator's request must be in the form of a written
petition to the BSEE Regional Supervisor that states the justification
for the pipeline to operate under DOT regulation.
(ii) The Regional Supervisor will decide, on a case-by-case basis,
whether to grant the operator's request. In considering each petition,
the Regional Supervisor will consult with the Office of Pipeline Safety
(OPS) Regional Director.
(13) A transporter who operates a pipeline regulated by DOT may
request to operate under BSEE regulations governing pipeline operation
and maintenance. Any subsequent repairs or modifications will also be
subject to BSEE regulations governing design and construction.
(i) The operator's request must be in the form of a written
petition to the OPS
[[Page 64555]]
Regional Director and the BSEE Regional Supervisor.
(ii) The BSEE Regional Supervisor and the OPS Regional Director
will decide how to act on this petition.
(d) A pipeline which qualifies as a right-of-way pipeline (see
Sec. 250.1001, Definitions) shall not be installed until a right-of-
way has been requested and granted in accordance with this subpart.
(e)(1) The Regional Supervisor may suspend any pipeline operation
upon a determination by the Regional Supervisor that continued activity
would threaten or result in serious, irreparable, or immediate harm or
damage to life (including fish and other aquatic life), property,
mineral deposits, or the marine, coastal, or human environment.
(2) The Regional Supervisor may also suspend pipeline operations or
a right-of-way grant if the Regional Supervisor determines that the
lessee or right-of-way holder has failed to comply with a provision of
the Act or any other applicable law, a provision of these or other
applicable regulations, or a condition of a permit or right-of-way
grant.
(3) The Secretary of the Interior (Secretary) may cancel a pipeline
permit or right-of-way grant in accordance with 43 U.S.C. 1334(a)(2). A
right-of-way grant may be forfeited in accordance with 43 U.S.C.
1334(e).
Sec. 250.1001 Definitions.
Terms used in this subpart shall have the meanings given below:
DOI pipelines include:
(1) Producer-operated pipelines extending upstream (generally
seaward) from each point on the OCS at which operating responsibility
transfers from a producing operator to a transporting operator;
(2) Producer-operated pipelines extending upstream (generally
seaward) of the last valve (including associated safety equipment) on
the last production facility on the OCS that do not connect to a
transporter-operated pipeline on the OCS before crossing into State
waters;
(3) Producer-operated pipelines connecting production facilities on
the OCS;
(4) Transporter-operated pipelines that DOI and DOT have agreed are
to be regulated as DOI pipelines; and
(5) All OCS pipelines not subject to regulation under 49 CFR parts
192 and 195.
DOT pipelines include:
(1) Transporter-operated pipelines currently operated under DOT
requirements governing design, construction, maintenance, and
operation;
(2) Producer-operated pipelines that DOI and DOT have agreed are to
be regulated under DOT requirements governing design, construction,
maintenance, and operation; and
(3) Producer-operated pipelines downstream (generally shoreward) of
the last valve (including associated safety equipment) on the last
production facility on the OCS that do not connect to a transporter-
operated pipeline on the OCS before crossing into State waters and that
are regulated under 49 CFR parts 192 and 195.
Lease term pipelines are those pipelines owned and operated by a
lessee or operator and are wholly contained within the boundaries of a
single lease, unitized leases, or contiguous (not cornering) leases of
that lessee or operator.
Out-of-service pipelines are those pipelines that have not been
used to transport oil, natural gas, sulfur, or produced water for more
than 30 consecutive days.
Pipelines are the piping, risers, and appurtenances installed for
the purpose of transporting oil, gas, sulphur, and produced water.
(Piping confined to a production platform or structure is covered in
Subpart H, Production Safety Systems, and is excluded from this
subpart.)
Production facilities means OCS facilities that receive hydrocarbon
production either directly from wells or from other facilities that
produce hydrocarbons from wells. They may include processing equipment
for treating the production or separating it into its various liquid
and gaseous components before transporting it to shore.
Right-of-way pipelines are those pipelines which--
(1) Are contained within the boundaries of a single lease or group
of unitized leases but are not owned and operated by the lessee or
operator of that lease or unit,
(2) Are contained within the boundaries of contiguous (not
cornering) leases which do not have a common lessee or operator,
(3) Are contained within the boundaries of contiguous (not
cornering) leases which have a common lessee or operator but are not
owned and operated by that common lessee or operator, or
(4) Cross any portion of an unleased block(s).
Sec. 250.1002 Design requirements for DOI pipelines.
(a) The internal design pressure for steel pipe shall be determined
in accordance with the following formula:
[GRAPHIC] [TIFF OMITTED] TR18OC11.000
For limitations see section 841.121 of American National Standards
Institute (ANSI) B31.8 (as incorporated by reference in Sec. 250.198)
where--
P = Internal design pressure in pounds per square inch (psi).
S = Specified minimum yield strength, in psi, stipulated in the
specification under which the pipe was purchased from the
manufacturer or determined in accordance with section 811.253(h) of
ANSI B31.8.
D = Nominal outside diameter of pipe, in inches.
t = Nominal wall thickness, in inches.
F = Construction design factor of 0.72 for the submerged component
and 0.60 for the riser component.
E = Longitudinal joint factor obtained from Table 841.1B of ANSI
B31.8 (see also section 811.253(d)).
T = Temperature derating factor obtained from Table 841.1C of ANSI
B31.8.
(b)(1) Pipeline valves shall meet the minimum design requirements
of American Petroleum Institute (API) Spec 6A (as incorporated by
reference in Sec. 250.198), API Spec 6D (as incorporated by reference
in Sec. 250.198), or the equivalent. A valve may not be used under
operating conditions that exceed the applicable pressure-temperature
ratings contained in those standards.
(2) Pipeline flanges and flange accessories shall meet the minimum
design requirements of ANSI B16.5, API Spec 6A, or the equivalent (as
incorporated by reference in 30 CFR 250.198). Each flange assembly must
be able to withstand the maximum pressure at which the pipeline is to
be operated and to maintain its physical and chemical properties at any
temperature to which it is anticipated that it might be subjected in
service.
(3) Pipeline fittings shall have pressure-temperature ratings based
on stresses for pipe of the same or equivalent material. The actual
bursting strength of the fitting shall at least be equal to the
computed bursting strength of the pipe.
(4) If you are installing pipelines constructed of unbonded
flexible pipe, you must design them according to the standards and
procedures of API Spec 17J, as incorporated by reference in 30 CFR
250.198.
(5) You must design pipeline risers for tension leg platforms and
other floating platforms according to the design standards of API RP
2RD, Design of Risers for Floating Production Systems (FPSs) and
Tension Leg Platforms (TLPs) (as incorporated by reference in Sec.
250.198).
[[Page 64556]]
(c) The maximum allowable operating pressure (MAOP) shall not
exceed the least of the following:
(1) Internal design pressure of the pipeline, valves, flanges, and
fittings;
(2) Eighty percent of the hydrostatic pressure test (HPT) pressure
of the pipeline; or
(3) If applicable, the MAOP of the receiving pipeline when the
proposed pipeline and the receiving pipeline are connected at a subsea
tie-in.
(d) If the maximum source pressure (MSP) exceeds the pipeline's
MAOP, you must install and maintain redundant safety devices meeting
the requirements of section A9 of API RP 14C (as incorporated by
reference in Sec. 250.198). Pressure safety valves (PSV) may be used
only after a determination by the Regional Supervisor that the pressure
will be relieved in a safe and pollution-free manner. The setting level
at which the primary and redundant safety equipment actuates shall not
exceed the pipeline's MAOP.
(e) Pipelines shall be provided with an external protective coating
capable of minimizing underfilm corrosion and a cathodic protection
system designed to mitigate corrosion for at least 20 years.
(f) Pipelines shall be designed and maintained to mitigate any
reasonably anticipated detrimental effects of water currents, storm or
ice scouring, soft bottoms, mud slides, earthquakes, subfreezing
temperatures, and other environmental factors.
Sec. 250.1003 Installation, testing, and repair requirements for DOI
pipelines.
(a)(1) Pipelines greater than 8\5/8\ inches in diameter and
installed in water depths of less than 200 feet shall be buried to a
depth of at least 3 feet unless they are located in pipeline congested
areas or seismically active areas as determined by the Regional
Supervisor. Nevertheless, the Regional Supervisor may require burial of
any pipeline if the Regional Supervisor determines that such burial
will reduce the likelihood of environmental degradation or that the
pipeline may constitute a hazard to trawling operations or other uses.
A trawl test or diver survey may be required to determine whether or
not pipeline burial is necessary or to determine whether a pipeline has
been properly buried.
(2) Pipeline valves, taps, tie-ins, capped lines, and repaired
sections that could be obstructive shall be provided with at least 3
feet of cover unless the Regional Supervisor determines that such items
present no hazard to trawling or other operations. A protective device
may be used to cover an obstruction in lieu of burial if it is approved
by the Regional Supervisor prior to installation.
(3) Pipelines shall be installed with a minimum separation of 18
inches at pipeline crossings and from obstructions.
(4) Pipeline risers installed after April 1, 1988, shall be
protected from physical damage that could result from contact with
floating vessels. Riser protection on pipelines installed on or before
April 1, 1988, may be required when the Regional Supervisor determines
that significant damage potential exists.
(b)(1) Pipelines shall be pressure tested with water at a
stabilized pressure of at least 1.25 times the MAOP for at least 8
hours when installed, relocated, uprated, or reactivated after being
out-of-service for more than 1 year.
(2) Prior to returning a pipeline to service after a repair, the
pipeline shall be pressure tested with water or processed natural gas
at a minimum stabilized pressure of at least 1.25 times the MAOP for at
least 2 hours.
(3) Pipelines shall not be pressure tested at a pressure which
produces a stress in the pipeline in excess of 95 percent of the
specified minimum-yield strength of the pipeline. A temperature
recorder measuring test fluid temperature synchronized with a pressure
recorder along with deadweight test readings shall be employed for all
pressure testing. When a pipeline is pressure tested, no observable
leakage shall be allowed. Pressure gauges and recorders shall be of
sufficient accuracy to verify that leakage is not occurring.
(4) The Regional Supervisor may require pressure testing of
pipelines to verify the integrity of the system when the Regional
Supervisor determines that there is a reasonable likelihood that the
line has been damaged or weakened by external or internal conditions.
(c) When a pipeline is repaired utilizing a clamp, the clamp shall
be a full encirclement clamp able to withstand the anticipated pipeline
pressure.
Sec. 250.1004 Safety equipment requirements for DOI pipelines.
(a) The lessee shall ensure the proper installation, operation, and
maintenance of safety devices required by this section on all incoming,
departing, and crossing pipelines on platforms.
(b)(1)(i) Incoming pipelines to a platform shall be equipped with a
flow safety valve (FSV).
(ii) For sulphur operations, incoming pipelines delivering gas to
the power plant platform may be equipped with high- and low-pressure
sensors (PSHL), which activate audible and visual alarms in lieu of
requirements in paragraph (b)(1)(i) of this section. The PSHL shall be
set at 15 percent or 5 psi, whichever is greater, above and below the
normal operating pressure range.
(2) Incoming pipelines boarding a production platform shall be
equipped with an automatic shutdown valve (SDV) immediately upon
boarding the platform. The SDV shall be connected to the automatic- and
remote-emergency shut-in systems.
(3) Departing pipelines receiving production from production
facilities shall be protected by high- and low-pressure sensors (PSHL)
to directly or indirectly shut in all production facilities. The PSHL
shall be set not to exceed 15 percent above and below the normal
operating pressure range. However, high pilots shall not be set above
the pipeline's MAOP.
(4) Crossing pipelines on production or manned nonproduction
platforms which do not receive production from the platform shall be
equipped with an SDV immediately upon boarding the platform. The SDV
shall be operated by a PSHL on the departing pipelines and connected to
the platform automatic- and remote-emergency shut-in systems.
(5) The Regional Supervisor may require that oil pipelines be
equipped with a metering system to provide a continuous volumetric
comparison between the input to the line at the structure(s) and the
deliveries onshore. The system shall include an alarm system and shall
be of adequate sensitivity to detect variations between input and
discharge volumes. In lieu of the foregoing, a system capable of
detecting leaks in the pipeline may be substituted with the approval of
the Regional Supervisor.
(6) Pipelines incoming to a subsea tie-in shall be equipped with a
block valve and an FSV. Bidirectional pipelines connected to a subsea
tie-in shall be equipped with only a block valve.
(7) Gas-lift or water-injection pipelines on unmanned platforms
need only be equipped with an FSV installed immediately upstream of
each casing annulus or the first inlet valve on the christmas tree.
(8) Bidirectional pipelines shall be equipped with a PSHL and an
SDV immediately upon boarding each platform.
(9) Pipeline pumps must comply with section A7 of API RP 14C (as
incorporated by reference in Sec. 250.198). The setting levels for the
PSHL devices are specified in paragraph (b)(3) of this section.
[[Page 64557]]
(c) If the required safety equipment is rendered ineffective or
removed from service on pipelines which are continued in operation, an
equivalent degree of safety shall be provided. The safety equipment
shall be identified by the placement of a sign on the equipment stating
that the equipment is rendered ineffective or removed from service.
Sec. 250.1005 Inspection requirements for DOI pipelines.
(a) Pipeline routes shall be inspected at time intervals and
methods prescribed by the Regional Supervisor for indication of
pipeline leakage. The results of these inspections shall be retained
for at least 2 years and be made available to the Regional Supervisor
upon request.
(b) When pipelines are protected by rectifiers or anodes for which
the initial life expectancy of the cathodic protection system either
cannot be calculated or calculations indicate a life expectancy of less
than 20 years, such pipelines shall be inspected annually by taking
measurements of pipe-to-electrolyte potential.
Sec. 250.1006 How must I decommission and take out of service a DOI
pipeline?
(a) The requirements for decommissioning pipelines are listed in
Sec. 250.1750 through Sec. 250.1754.
(b) The table in this section lists the requirements if you take a
DOI pipeline out of service:
----------------------------------------------------------------------------------------------------------------
If you have the pipeline out of service for: Then you must:
----------------------------------------------------------------------------------------------------------------
(1) 1 year or less, Isolate the pipeline with a blind flange or a closed block
valve at each end of the pipeline.
(2) More than 1 year but less than 5 years, Flush and fill the pipeline with inhibited seawater.
(3) 5 or more years, Decommission the pipeline according to Sec. Sec.
250.1750-250.1754.
----------------------------------------------------------------------------------------------------------------
Sec. 250.1007 What to include in applications.
(a) Applications to install a lease term pipeline or for a pipeline
right-of-way grant must be submitted in quadruplicate to the Regional
Supervisor. Right-of-way grant applications must include an
identification of the operator of the pipeline. Each application must
include the following:
(1) Plat(s) drawn to a scale specified by the Regional Supervisor
showing major features and other pertinent data including area, lease,
and block designations; water depths; route; length in Federal waters;
width of right-of-way, if applicable; connecting facilities; size;
product(s) to be transported with anticipated gravity or density;
burial depth; direction of flow; X-Y coordinates of key points; and the
location of other pipelines that will be connected to or crossed by the
proposed pipeline(s). The initial and terminal points of the pipeline
and any continuation into State jurisdiction shall be accurately
located even if the pipeline is to have an onshore terminal point. A
plat(s) submitted for a pipeline right-of-way shall bear a signed
certificate upon its face by the engineer who made the map that
certifies that the right-of-way is accurately represented upon the map
and that the design characteristics of the associated pipeline are in
accordance with applicable regulations.
(2) A schematic drawing showing the size, weight, grade, wall
thickness, and type of line pipe and risers; pressure-regulating
devices (including back-pressure regulators); sensing devices with
associated pressure-control lines; PSV's and settings; SDV's, FSV's,
and block valves; and manifolds. This schematic drawing shall also show
input source(s), e.g., wells, pumps, compressors, and vessels; maximum
input pressure(s); the rated working pressure, as specified by ANSI or
API, of all valves, flanges, and fittings; the initial receiving
equipment and its rated working pressure; and associated safety
equipment and pig launchers and receivers. The schematic must indicate
the point on the OCS at which operating responsibility transfers
between a producing operator and a transporting operator.
(3) General information as follows:
(i) Description of cathodic protection system. If pipeline anodes
are to be used, specify the type, size, weight, number, spacing, and
anticipated life;
(ii) Description of external pipeline coating system;
(iii) Description of internal protective measures;
(iv) Specific gravity of the empty pipe;
(v) MSP;
(vi) MAOP and calculations used in its determination;
(vii) Hydrostatic test pressure, medium, and period of time that
the line will be tested;
(viii) MAOP of the receiving pipeline or facility,
(ix) Proposed date for commencing installation and estimated time
for construction; and
(x) Type of protection to be afforded crossing pipelines, subsea
valves, taps, and manifold assemblies, if applicable.
(4) A description of any additional design precautions you took to
enable the pipeline to withstand the effects of water currents, storm
or ice scouring, soft bottoms, mudslides, earthquakes, permafrost, and
other environmental factors.
(i) If you propose to use unbonded flexible pipe, your application
must include:
(A) The manufacturer's design specification sheet;
(B) The design pressure (psi);
(C) An identification of the design standards you used; and
(D) A review by a third-party independent verification agent (IVA)
according to API Spec 17J (as incorporated by reference in Sec.
250.198), if applicable.
(ii) If you propose to use one or more pipeline risers for a
tension leg platform or other floating platform, your application must
include:
(A) The design fatigue life of the riser, with calculations, and
the fatigue point at which you would replace the riser;
(B) The results of your vortex-induced vibration (VIV) analysis;
(C) An identification of the design standards you used; and
(D) A description of any necessary mitigation measures such as the
use of helical strakes or anchoring devices.
(5) The application shall include a shallow hazards survey report
and, if required by the Regional Director, an archaeological resource
report that covers the entire length of the pipeline. A shallow hazards
analysis may be included in a lease term pipeline application in lieu
of the shallow hazards survey report with the approval of the Regional
Director. The Regional Director may require the submission of the data
upon which the report or analysis is based.
(b) Applications to modify an approved lease term pipeline or
right-of-way grant shall be submitted in quadruplicate to the Regional
Supervisor. These applications need only address those items in the
original application affected by the proposed modification.
Sec. 250.1008 Reports.
(a) The lessee, or right-of-way holder, shall notify the Regional
Supervisor at
[[Page 64558]]
least 48 hours prior to commencing the installation or relocation of a
pipeline or conducting a pressure test on a pipeline.
(b) The lessee or right-of-way holder shall submit a report to the
Regional Supervisor within 90 days after completion of any pipeline
construction. The report, submitted in triplicate, shall include an
``as-built'' location plat drawn to a scale specified by the Regional
Supervisor showing the location, length in Federal waters, and X-Y
coordinates of key points; the completion date; the proposed date of
first operation; and the HPT data. Pipeline right-of-way ``as-built''
location plats shall be certified by a registered engineer or land
surveyor and show the boundaries of the right-of-way as granted. If
there is a substantial deviation of the pipeline route as granted in
the right-of-way, the report shall include a discussion of the reasons
for such deviation.
(c) The lessee or right-of-way holder shall report to the Regional
Supervisor any pipeline taken out of service. If the period of time in
which the pipeline is out of service is greater than 60 days, written
confirmation is also required.
(d) The lessee or right-of-way holder shall report to the Regional
Supervisor when any required pipeline safety equipment is taken out of
service for more than 12 hours. The Regional Supervisor shall be
notified when the equipment is returned to service.
(e) The lessee or right-of-way holder must notify the Regional
Supervisor before the repair of any pipeline or as soon as practicable.
Your notification must be accompanied by payment of the service fee
listed in Sec. 250.125. You must submit a detailed report of the
repair of a pipeline or pipeline component to the Regional Supervisor
within 30 days after the completion of the repairs. In the report you
must include the following:
(1) Description of repairs;
(2) Results of pressure test; and
(3) Date returned to service.
(f) The Regional Supervisor may require that DOI pipeline failures
be analyzed and that samples of a failed section be examined in a
laboratory to assist in determining the cause of the failure. A
comprehensive written report of the information obtained shall be
submitted by the lessee to the Regional Supervisor as soon as
available.
(g) If the effects of scouring, soft bottoms, or other
environmental factors are observed to be detrimentally affecting a
pipeline, a plan of corrective action shall be submitted to the
Regional Supervisor for approval within 30 days of the observation. A
report of the remedial action taken shall be submitted to the Regional
Supervisor by the lessee or right-of-way holder within 30 days after
completion.
(h) The results and conclusions of measurements of pipe-to-
electrolyte potential measurements taken annually on DOI pipelines in
accordance with Sec. 250.1005(b) of this part shall be submitted to
the Regional Supervisor by the lessee before March of each year.
Sec. 250.1009 Requirements to obtain pipeline right-of-way grants.
(a) In addition to applicable requirements of Sec. Sec. 250.1000
through 250.1008 and other regulations of this part, regulations of the
Department of Transportation, Department of the Army, and the Federal
Energy Regulatory Commission (FERC), when a pipeline qualifies as a
right-of-way pipeline, the pipeline shall not be installed until a
right-of-way has been requested and granted in accordance with this
subpart. The right-of-way grant is issued pursuant to 43 U.S.C. 1334(e)
and may be acquired and held only by citizens and nationals of the
United States; aliens lawfully admitted for permanent residence in the
United States as defined in 8 U.S.C. 1101(a)(20); private, public, or
municipal corporations organized under the laws of the United States or
territory thereof, the District of Columbia, or of any State; or
associations of such citizens, nationals, resident aliens, or private,
public, or municipal corporations, States, or political subdivisions of
States.
(b) A right-of-way shall include the site on which the pipeline and
associated structures are to be situated, shall not exceed 200 feet in
width unless safety and environmental factors during construction and
operation of the associated right-of-way pipeline require a greater
width, and shall be limited to the area reasonably necessary for
pumping stations or other accessory structures.
Sec. 250.1010 General requirements for pipeline right-of-way holders.
An applicant, by accepting a right-of-way grant, agrees to comply
with the following requirements:
(a) The right-of-way holder shall comply with applicable laws and
regulations and the terms of the grant.
(b) The granting of the right-of-way shall be subject to the
express condition that the rights granted shall not prevent or
interfere in any way with the management, administration, or the
granting of other rights by the United States, either prior or
subsequent to the granting of the right-of-way. Moreover, the holder
agrees to allow the occupancy and use by the United States, its
lessees, or other right-of-way holders, of any part of the right-of-way
grant not actually occupied or necessarily incident to its use for any
necessary operations involved in the management, administration, or the
enjoyment of such other granted rights.
(c) If the right-of-way holder discovers any archaeological
resource while conducting operations within the right-of-way, the
right-of-way holder shall immediately halt operations within the area
of the discovery and report the discovery to the Regional Director. If
investigations determine that the resource is significant, the Regional
Director will inform the right-of-way holder how to protect it.
(d) The Regional Supervisor shall be kept informed at all times of
the right-of-way holder's address and, if a corporation, the address of
its principal place of business and the name and address of the officer
or agent authorized to be served with process.
(e) The right-of-way holder shall pay the United States or its
lessees or right-of-way holders, as the case may be, the full value of
all damages to the property of the United States or its said lessees or
right-of-way holders and shall indemnify the United States against any
and all liability for damages to life, person, or property arising from
the occupation and use of the area covered by the right-of-way grant.
(f)(1) The holder of a right-of-way oil or gas pipeline shall
transport or purchase oil or natural gas produced from submerged lands
in the vicinity of the pipeline without discrimination and in such
proportionate amounts as the FERC may, after a full hearing with due
notice thereof to the interested parties, determine to be reasonable,
taking into account, among other things, conservation and the
prevention of waste.
(2) Unless otherwise exempted by FERC pursuant to 43 U.S.C.
1334(f)(2), the holder shall:
(i) Provide open and nondiscriminatory access to a right-of-way
pipeline to both owner and nonowner shippers, and
(ii) Comply with the provisions of 43 U.S.C. 1334(f)(1)(B) under
which FERC may order an expansion of the throughput capacity of a
right-of-way pipeline which is approved after September 18, 1978, and
which is not located in the Gulf of Mexico or the Santa Barbara
Channel.
(g) The area covered by a right-of-way and all improvements thereon
shall be kept open at all reasonable times for inspection by the Bureau
of Safety and Environmental Enforcement (BSEE).
[[Page 64559]]
The right-of-way holder shall make available all records relative to
the design, construction, operation, maintenance and repair, and
investigations on or with regard to such area.
(h) Upon relinquishment, forfeiture, or cancellation of a right-of-
way grant, the right-of-way holder shall remove all platforms,
structures, domes over valves, pipes, taps, and valves along the right-
of-way. All of these improvements shall be removed by the holder within
1 year of the effective date of the relinquishment, forfeiture, or
cancellation unless this requirement is waived in writing by the
Regional Supervisor. All such improvements not removed within the time
provided herein shall become the property of the United States but that
shall not relieve the holder of liability for the cost of their removal
or for restoration of the site. Furthermore, the holder is responsible
for accidents or damages which might occur as a result of failure to
timely remove improvements and equipment and restore a site. An
application for relinquishment of a right-of-way grant shall be filed
in accordance with Sec. 250.1019 of this part.
Sec. 250.1011 [Reserved]
Sec. 250.1012 Required payments for pipeline right-of-way holders.
(a) You must pay ONRR, under the regulations at 30 CFR part 1218,
an annual rental of $15 for each statute mile, or part of a statute
mile, of the OCS that your pipeline right-of-way crosses.
(b) This paragraph applies to you if you obtain a pipeline right-
of-way that includes a site for an accessory to the pipeline, including
but not limited to a platform. This paragraph also applies if you apply
to modify a right-of-way to change the site footprint. In either case,
you must pay the amounts shown in the following table.
----------------------------------------------------------------------------------------------------------------
If . . . Then . . .
----------------------------------------------------------------------------------------------------------------
(1) Your accessory site is located in water depths You must pay ONRR, under the regulations at 30 CFR part
of less than 200 meters; 1218, a rental of $5 per acre per year with a minimum of
$450 per year. The area subject to annual rental includes
the areal extent of anchor chains, pipeline risers, and
other facilities and devices associated with the
accessory.
(2) Your accessory site is located in water depths You must pay ONRR, under the regulations at 30 CFR part
of 200 meters or greater; 1218, a rental of $7.50 per acre per year with a minimum
of $675 per year. The area subject to annual rental
includes the areal extent of anchor chains, pipeline
risers, and other facilities and devices associated with
the accessory.
----------------------------------------------------------------------------------------------------------------
(c) If you hold a pipeline right-of-way that includes a site for
an accessory to your pipeline and you are not covered by paragraph (b)
of this section, then you must pay ONRR, under the regulations at 30
CFR part 1218, an annual rental of $75 for use of the affected area.
(d) You may make the rental payments required by paragraphs (a),
(b)(1), (b)(2), and (c) of this section on an annual basis, for a 5-
year period, or for multiples of 5 years. You must make the first
payment at the time you submit the pipeline right-of-way application.
You must make all subsequent payments before the respective time
periods begin.
(e) Late payments. An interest charge will be assessed on unpaid
and underpaid amounts from the date the amounts are due, in accordance
with the provisions found in 30 CFR 1218.54. If you fail to make a
payment that is late after written notice from ONRR, BSEE may initiate
cancellation of the right-of-use grant and easement under Sec.
250.1013.
Sec. 250.1013 Grounds for forfeiture of pipeline right-of-way grants.
Failure to comply with the Act, regulations, or any conditions of
the right-of-way grant prescribed by the Regional Supervisor shall be
grounds for forfeiture of the grant in an appropriate judicial
proceeding instituted by the United States in any U.S. District Court
having jurisdiction in accordance with the provisions of 43 U.S.C.
1349.
Sec. 250.1014 When pipeline right-of-way grants expire.
Any right-of-way granted under the provisions of this subpart
remains in effect as long as the associated pipeline is properly
maintained and used for the purpose for which the grant was made,
unless otherwise expressly stated in the grant. Temporary cessation or
suspension of pipeline operations shall not cause the grant to expire.
However, if the purpose of the grant ceases to exist or use of the
associated pipeline is permanently discontinued for any reason, the
grant shall be deemed to have expired.
Sec. 250.1015 Applications for pipeline right-of-way grants.
(a) You must submit an original and three copies of an application
for a new or modified pipeline ROW grant to the Regional Supervisor.
The application must address those items required by Sec. 250.1007(a)
or (b) of this subpart, as applicable. It must also state the primary
purpose for which you will use the ROW grant. If the ROW has been used
before the application is made, the application must state the date
such use began, by whom, and the date the applicant obtained control of
the improvement. When you file your application, you must pay the
rental required under Sec. 250.1012 of this subpart, as well as the
service fees listed in Sec. 250.125 of this part for a pipeline ROW
grant to install a new pipeline, or to convert an existing lease term
pipeline into a ROW pipeline. An application to modify an approved ROW
grant must be accompanied by the additional rental required under Sec.
250.1012 if applicable. You must file a separate application for each
ROW.
(b)(1) An individual applicant shall submit a statement of
citizenship or nationality with the application. An applicant who is an
alien lawfully admitted for permanent residence in the United States
shall also submit evidence of such status with the application.
(2) If the applicant is an association (including a partnership),
the application shall also be accompanied by a certified copy of the
articles of association or appropriate reference to a copy of such
articles already filed with BSEE and a statement as to any subsequent
amendments.
(3) If the applicant is a corporation, the application shall also
include the following:
(i) A statement certified by the Secretary or Assistant Secretary
of the corporation with the corporate seal showing the State in which
it is incorporated and the name of the person(s) authorized to act on
behalf of the corporation, or
(ii) In lieu of such a statement, an appropriate reference to
statements or records previously submitted to BSEE
[[Page 64560]]
(including material submitted in compliance with prior regulations).
(c) The application shall include a list of every lessee and right-
of-way holder whose lease or right-of-way is intersected by the
proposed right-of-way. The application shall also include a statement
that a copy of the application has been sent by registered or certified
mail to each such lessee or right-of-way holder.
(d) The applicant shall include in the application an original and
three copies of a completed Nondiscrimination in Employment form (YN
3341-1 dated July 1982). These forms are available at each BSEE
regional office.
(e) Notwithstanding the provisions of paragraph (a) of this
section, the requirements to pay filing fees under that paragraph are
suspended until January 3, 2006.
Sec. 250.1016 Granting pipeline rights-of-way.
(a) In considering an application for a right-of-way, the Regional
Supervisor shall consider the potential effect of the associated
pipeline on the human, marine, and coastal environments, life
(including aquatic life), property, and mineral resources in the entire
area during construction and operational phases. The Regional
Supervisor shall prepare an environmental analysis in accordance with
applicable policies and guidelines. To aid in the evaluation and
determinations, the Regional Supervisor may request and consider views
and recommendations of appropriate Federal Agencies, hold public
meetings after appropriate notice, and consult, as appropriate, with
State agencies, organizations, industries, and individuals. Before
granting a pipeline right-of-way, the Regional Supervisor shall give
consideration to any recommendation by the intergovernmental planning
program, or similar process, for the assessment and management of OCS
oil and gas transportation.
(b) Should the proposed route of a right-of-way adjoin and
subsequently cross any State submerged lands, the applicant shall
submit evidence to the Regional Supervisor that the State(s) so
affected has reviewed the application. The applicant shall also submit
any comment received as a result of that review. In the event of a
State recommendation to relocate the proposed route, the Regional
Supervisor may consult with the appropriate State officials.
(c)(1) The applicant shall submit photocopies of return receipts to
the Regional Supervisor that indicate the date that each lessee or
right-of-way holder referenced in Sec. 250.1015(c) of this part has
received a copy of the application. Letters of no objection may be
submitted in lieu of the return receipts.
(2) The Regional Supervisor shall not take final action on a right-
of-way application until the Regional Supervisor is satisfied that each
such lessee or right-of-way holder has been afforded at least 30 days
from the date determined in paragraph (c)(1) of this section in which
to submit comments.
(d) If a proposed right-of-way crosses any lands not subject to
disposition by mineral leasing or restricted from oil and gas
activities, it shall be rejected by the Regional Supervisor unless the
Federal Agency with jurisdiction over such excluded or restricted area
gives its consent to the granting of the right-of-way. In such case,
the applicant, upon a request filed within 30 days after receipt of the
notification of such rejection, shall be allowed an opportunity to
eliminate the conflict.
(e)(1) If the application and other required information are found
to be in compliance with applicable laws and regulations, the right-of-
way may be granted. The Regional Supervisor may prescribe, as
conditions to the right-of-way grant, stipulations necessary to protect
human, marine, and coastal environments, life (including aquatic life),
property, and mineral resources located on or adjacent to the right-of-
way.
(2) If the Regional Supervisor determines that a change in the
application should be made, the Regional Supervisor shall notify the
applicant that an amended application shall be filed subject to
stipulated changes. The Regional Supervisor shall determine whether the
applicant shall deliver copies of the amended application to other
parties for comment.
(3) A decision to reject an application shall be in writing and
shall state the reasons for the rejection.
Sec. 250.1017 Requirements for construction under pipeline right-of-
way grants.
(a) Failure to construct the associated right-of-way pipeline
within 5 years of the date of the granting of a right-of-way shall
cause the grant to expire.
(b)(1) A right-of-way holder shall ensure that the right-of-way
pipeline is constructed in a manner that minimizes deviations from the
right-of-way as granted.
(2) If, after constructing the right-of-way pipeline, it is
determined that a deviation from the proposed right-of-way as granted
has occurred, the right-of-way holder shall--
(i) Notify the operators of all leases and holders of all right-of-
way grants in which a deviation has occurred, and within 60 days of the
date of the acceptance by the Regional Supervisor of the completion of
pipeline construction report, provide the Regional Supervisor with
evidence of such notification; and
(ii) Relinquish any unused portion of the right-of-way.
(3) Substantial deviation of a right-of-way pipeline as constructed
from the proposed right-of-way as granted may be grounds for forfeiture
of the right-of-way.
(c) If the Regional Supervisor determines that a significant change
in conditions has occurred subsequent to the granting of a right-of-way
but prior to the commencement of construction of the associated
pipeline, the Regional Supervisor may suspend or temporarily prohibit
the commencement of construction until the right-of-way grant is
modified to the extent necessary to address the changed conditions.
Sec. 250.1018 Assignment of pipeline right-of-way grants.
(a) Assignment may be made of a right-of-way grant, in whole or of
any lineal segment thereof, subject to the approval of the Regional
Supervisor. An application for approval of an assignment of a right-of-
way or of a lineal segment thereof, shall be filed in triplicate with
the Regional Supervisor.
(b) Any application for approval for an assignment, in whole or in
part, of any right, title, or interest in a right-of-way grant must be
accompanied by the same showing of qualifications of the assignees as
is required of an applicant for a ROW in Sec. 250.1015 of this subpart
and must be supported by a statement that the assignee agrees to comply
with and to be bound by the terms and conditions of the ROW grant. The
assignee must satisfy the bonding requirements in 30 CFR 550.1011. No
transfer will be recognized unless and until it is first approved, in
writing, by the Regional Supervisor. The assignee must pay the service
fee listed in Sec. 250.125 of this part for a pipeline ROW assignment
request.
(c) Notwithstanding the provisions of paragraph (b) of this
section, the requirement to pay a filing fee under that paragraph is
suspended until January 3, 2006.
Sec. 250.1019 Relinquishment of pipeline right-of-way grants.
A right-of-way grant or a portion thereof may be surrendered by the
holder by filing a written relinquishment in triplicate with the
[[Page 64561]]
Regional Supervisor. It must contain those items addressed in
Sec. Sec. 250.1751 and 250.1752 of this part. A relinquishment shall
take effect on the date it is filed subject to the satisfaction of all
outstanding debts, fees, or fines and the requirements in Sec.
250.1010(h) of this part.
Subpart K--Oil and Gas Production Requirements
General
Sec. 250.1150 What are the general reservoir production requirements?
You must produce wells and reservoirs at rates that provide for
economic development while maximizing ultimate recovery and without
adversely affecting correlative rights.
Well Tests and Surveys
Sec. 250.1151 How often must I conduct well production tests?
(a) You must conduct well production tests as shown in the
following table:
------------------------------------------------------------------------
And you must submit to the
You must conduct: Regional Supervisor:
------------------------------------------------------------------------
(1) A well-flow potential test on all new, Form BSEE-0126, Well
recompleted, or reworked well completions Potential Test Report,
within 30 days of the date of first along with the supporting
continuous production, data as listed in the table
in Sec. 250.1167, within
15 days after the end of
the test period.
(2) At least one well test during a Results on Form BSEE-0128,
calendar half-year for each producing Semiannual Well Test
completion, Report, of the most recent
well test obtained. This
must be submitted within 45
days after the end of the
calendar half-year.
------------------------------------------------------------------------
(b) You may request an extension from the Regional Supervisor if
you cannot submit the results of a semiannual well test within the
specified time.
(c) You must submit to the Regional Supervisor an original and two
copies of the appropriate form required by paragraph (a) of this
section; one of the copies of the form must be a public information
copy in accordance with Sec. Sec. 250.186 and 250.197, and marked
``Public Information.'' You must submit two copies of the supporting
information as listed in the table in Sec. 250.1167 with form BSEE-
0126.
Sec. 250.1152 How do I conduct well tests?
(a) When you conduct well tests you must:
(1) Recover fluid from the well completion equivalent to the amount
of fluid introduced into the formation during completion, recompletion,
reworking, or treatment operations before you start a well test;
(2) Produce the well completion under stabilized rate conditions
for at least 6 consecutive hours before beginning the test period;
(3) Conduct the test for at least 4 consecutive hours;
(4) Adjust measured gas volumes to the standard conditions of 14.73
pounds per square inch absolute (psia) and 60 [deg]F for all tests; and
(5) Use measured specific gravity values to calculate gas volumes.
(b) You may request approval from the Regional Supervisor to
conduct a well test using alternative procedures if you can demonstrate
test reliability under those procedures.
(c) The Regional Supervisor may also require you to conduct the
following tests and complete them within a specified time period:
(1) A retest or a prolonged test of a well completion if it is
determined to be necessary for the proper establishment of a Maximum
Production Rate (MPR) or a Maximum Efficient Rate (MER); and
(2) A multipoint back-pressure test to determine the theoretical
open-flow potential of a gas well.
(d) A BSEE representative may witness any well test. Upon request,
you must provide advance notice to the Regional Supervisor of the times
and dates of well tests.
Sec. Sec. 250.1153--250.1155 [Reserved]
Approvals Prior to Production
Sec. 250.1156 What steps must I take to receive approval to produce
within 500 feet of a unit or lease line?
(a) You must obtain approval from the Regional Supervisor before
you start producing from a reservoir within a well that has any portion
of the completed interval less than 500 feet from a unit or lease line.
Submit to BSEE the service fee listed in Sec. 250.125, according to
the instructions in Sec. 250.126, and the supporting information, as
listed in the table in Sec. 250.1167, with your request. The Regional
Supervisor will determine whether approval of your request will
maximize ultimate recovery, avoid the waste of natural resources, or
protect correlative rights. You do not need to obtain approval if the
adjacent leases or units have the same unit, lease (record title and
operating rights), and royalty interests as the lease or unit you plan
to produce. You do not need to obtain approval if the adjacent block is
unleased.
(b) You must notify the operator(s) of adjacent property(ies) that
are within 500 feet of the completion, if the adjacent acreage is a
leased block in the Federal OCS. You must provide the Regional
Supervisor proof of the date of the notification. The operators of the
adjacent properties have 30 days after receiving the notification to
provide the Regional Supervisor letters of acceptance or objection. If
an adjacent operator does not respond within 30 days, the Regional
Supervisor will presume there are no objections and proceed with a
decision. The notification must include:
(1) The well name;
(2) The rectangular coordinates (x, y) of the location of the top
and bottom of the completion or target completion referenced to the
North American Datum 1983, and the subsea depths of the top and bottom
of the completion or target completion;
(3) The distance from the completion or target completion to the
unit or lease line at its nearest point; and
(4) A statement indicating whether or not it will be a high-
capacity completion having a perforated or open hole interval greater
than 150 feet measured depth.
Sec. 250.1157 How do I receive approval to produce gas-cap gas from
an oil reservoir with an associated gas cap?
(a) You must request and receive approval from the Regional
Supervisor:
(1) Before producing gas-cap gas from each completion in an oil
reservoir that is known to have an associated gas cap.
(2) To continue production from a well if the oil reservoir is not
initially known to have an associated gas cap, but the oil well begins
to show characteristics of a gas well.
(b) For either request, you must submit the service fee listed in
Sec. 250.125, according to the instructions in Sec. 250.126, and the
supporting information, as listed in the table in Sec. 250.1167, with
your request.
(c) The Regional Supervisor will determine whether your request
maximizes ultimate recovery.
[[Page 64562]]
Sec. 250.1158 How do I receive approval to downhole commingle
hydrocarbons?
(a) Before you perforate a well, you must request and receive
approval from the Regional Supervisor to commingle hydrocarbons
produced from multiple reservoirs within a common wellbore. The
Regional Supervisor will determine whether your request maximizes
ultimate recovery. You must include the service fee listed in Sec.
250.125, according to the instructions in Sec. 250.126, and the
supporting information, as listed in the table in Sec. 250.1167, with
your request.
(b) If one or more of the reservoirs proposed for commingling is a
competitive reservoir, you must notify the operators of all leases that
contain the reservoir that you intend to downhole commingle the
reservoirs. Your request for approval of downhole commingling must
include proof of the date of this notification. The notified operators
have 30 days after notification to provide the Regional Supervisor with
letters of acceptance or objection. If the notified operators do not
respond within the specified period, the Regional Supervisor will
assume the operators do not object and proceed with a decision.
Production Rates
Sec. 250.1159 May the Regional Supervisor limit my well or reservo