Rule2023-11742
Onshore Oil and Gas Operations; Federal and Indian Oil and Gas Leases; Codification of Onshore Orders 1, 2, 6, and 7
Primary source
Metadata and text below are from the Federal Register, a public-domain U.S. government work. Always verify the official published version before relying on it for any legal matter.
Published
June 16, 2023
Effective
June 16, 2023
Issuing agencies
Interior DepartmentLand Management Bureau
Abstract
This final rule codifies Onshore Order 1--Approval of Operations; Onshore Order 2--Drilling Operations on Federal and Indian Oil and Gas Leases; Onshore Order 6--Hydrogen Sulfide Operations; and Onshore Order 7--Disposal of Produced Water. This rule places the existing regulations, which were promulgated over the years through various notice and comment rulemakings but not codified in the Code of Federal Regulations (CFR), into the CFR in their entirety without making any substantive changes.
Full Text
<html>
<head>
<title>Federal Register, Volume 88 Issue 116 (Friday, June 16, 2023)</title>
</head>
<body><pre>
[Federal Register Volume 88, Number 116 (Friday, June 16, 2023)]
[Rules and Regulations]
[Pages 39514-39566]
From the Federal Register Online via the Government Publishing Office [<a href="http://www.gpo.gov">www.gpo.gov</a>]
[FR Doc No: 2023-11742]
[[Page 39513]]
Vol. 88
Friday,
No. 116
June 16, 2023
Part II
Department of the Interior
-----------------------------------------------------------------------
Bureau of Land Management
-----------------------------------------------------------------------
43 CFR Part 3170
Onshore Oil and Gas Operations; Federal and Indian Oil and Gas Leases;
Codification of Onshore Orders 1, 2, 6, and 7
Federal Register / Vol. 88 , No. 116 / Friday, June 16, 2023 / Rules
and Regulations
[[Page 39514]]
-----------------------------------------------------------------------
DEPARTMENT OF THE INTERIOR
Bureau of Land Management
43 CFR Part 3170
[BLM_HQ_FRN_MO4500171611]
RIN 1004-AE90
Onshore Oil and Gas Operations; Federal and Indian Oil and Gas
Leases; Codification of Onshore Orders 1, 2, 6, and 7
AGENCY: Bureau of Land Management, Interior.
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: This final rule codifies Onshore Order 1--Approval of
Operations; Onshore Order 2--Drilling Operations on Federal and Indian
Oil and Gas Leases; Onshore Order 6--Hydrogen Sulfide Operations; and
Onshore Order 7--Disposal of Produced Water. This rule places the
existing regulations, which were promulgated over the years through
various notice and comment rulemakings but not codified in the Code of
Federal Regulations (CFR), into the CFR in their entirety without
making any substantive changes.
DATES: This final rule is effective on June 16, 2023.
The incorporation by reference of certain publications listed in
the rule is approved by the Director of the Federal Register as of June
16, 2023.
ADDRESSES: You may send inquiries or suggestions to Director (630),
Bureau of Land Management, 1849 C St. NW, Room 5646, Washington, DC
20240; Attention: RIN 1004-AE86.
FOR FURTHER INFORMATION CONTACT: Matthew Warren, Acting Chief, Division
of Fluid Minerals, 505-216-8832, <a href="/cdn-cgi/l/email-protection#630e14021111060d23010f0e4d040c15"><span class="__cf_email__" data-cfemail="056872647777606b456769682b626a73">[email protected]</span></a>; or Faith Bremner,
Regulatory Analyst, Division of Regulatory Affairs, <a href="/cdn-cgi/l/email-protection#2e484c5c4b43404b5c6e4c424300494158"><span class="__cf_email__" data-cfemail="7b1d19091e16151e093b191716551c140d">[email protected]</span></a>.
Individuals in the United States who are deaf, blind, hard of hearing,
or have a speech disability may dial 711 (TTY, TDD, or TeleBraille) to
access telecommunications relay services for contacting Mr. Warren.
Individuals outside the United States should use the relay services
offered within their country to make international calls to the point-
of-contact in the United States.
SUPPLEMENTARY INFORMATION:
I. Background
The Bureau of Land Management's (BLM) regulations at 43 CFR part
3160 authorize the agency to issue onshore oil and gas orders to
``implement and supplement'' the oil and gas operations regulations in
part 3160. See 43 CFR 3164.1. The Onshore Orders apply nationwide to
all Federal onshore and Indian (except the Osage Nation) oil and gas
leases and are documents of general applicability and legal effect. All
the Onshore Orders were published in the Federal Register and adopted
through prior notice-and-comment rulemaking, but were never codified in
the CFR.
Beginning in 1983, the BLM issued and revised a total of seven
Onshore Orders. The four Orders that are the subject of this final rule
were published and revised as follows:
Onshore Order 1--Approval of Operations, published October 21, 1983
(48 FR 48916); revised March 7, 2007 (72 FR 10308), and January 10,
2017 (82 FR 2906). This Onshore Order supplements regulations at 43 CFR
3162.3, Conduct of operations, and Sec. 3162.5, Environment and
safety.
Onshore Order 2--Drilling Operations on Federal and Indian Oil and
Gas Leases, published November 18, 1988 (53 FR 46798); revised
September 27, 1989 (54 FR 39528); and January 27, 1992 (57 FR 3023).
This Onshore Order supplements regulations at: 43 CFR 3162.3-1,
Drilling applications and plans; 3162.3-4, Well abandonment; 3162.4-1,
Well records and reports; 3162.4-2, Samples, tests, and surveys;
3162.5-1, Environmental obligations; 3162.5-2, Control of wells;
3162.5-3, Safety precautions.
Onshore Order 6--Hydrogen Sulfide Operations, published November
23, 1990 (55 FR 48958); revised January 17, 1992 (57 FR 2039 and 57 FR
2136); and February 12, 1992 (57 FR 5211). This Onshore Order
supplements regulations at: 43 CFR 3162.1, General requirements;
3162.5-1, Environmental obligations; 3162.5-2, Control of wells; and
3162.5-3, Safety precautions.
Onshore Order 7--Disposal of Produced Water, published September 8,
1993 (58 FR 47354); revised November 2, 1993 (58 FR 58505). This
Onshore Order supplements the regulations at 43 CFR 3162.5-1,
Environmental obligations.
Several years ago, the Office of the Federal Register (OFR)
informed the BLM that it would no longer allow the BLM to revise the
existing Onshore Orders unless the agency codified the Orders in the
CFR. The OFR cited as its justification the Federal Register Act (44
U.S.C. 1510), which requires documents of general applicability and
legal effect to be codified in the CFR.
As a result, when the BLM made major revisions to three of the
Onshore Orders in 2016, it codified the Orders in the CFR after
publishing proposed and final rules for each. Those three Onshore
Orders were: Onshore Order 3--Site Security; Onshore Order 4--
Measurement of Oil; and Onshore Order 5--Measurement of Gas.\1\
---------------------------------------------------------------------------
\1\ On November 17, 2016, the BLM published in the Federal
Register three final rules: (1) ``Onshore Oil and Gas Operations;
Federal and Indian Oil and Gas Leases; Site Security'' (81 FR
81365), codified at 43 CFR part 3170, subparts 3170 and 3173; (2)
``Onshore Oil and Gas Operations; Federal and Indian Oil and Gas
Leases; Measurement of Oil'' (81 FR 81462), codified at 43 CFR part
3170, subpart 3174; and (3) ``Onshore Oil and Gas Operations;
Federal and Indian Oil and Gas Leases; Measurement of Gas'' (81 FR
81516), codified at 43 CFR part 3170, subpart 3175.
---------------------------------------------------------------------------
This final rule codifies the remaining four Onshore Orders without
making any substantive changes to their content. The only changes made
to the four Onshore Orders pertain to formatting, such as adding new
section and paragraph designations, so that the Orders conform to the
OFR's Document Drafting Handbook requirements. This final codification
rule also includes a new section at 43 CFR 3176.11 to reflect the
incorporation by reference (IBR) requirements of the Office of the
Federal Register consistent with 5 U.S.C. 552(a) and 1 CFR part 51. The
IBR section does not alter the substance of the Onshore Orders
themselves.
All of the materials that the BLM is incorporating by reference are
available for inspection at all BLM offices with jurisdiction over oil
and gas activities. Contact the BLM at: Office of Energy, Minerals, and
Realty Management, 1849 C Street Northwest, Washington, DC 20240;
telephone 202-208-3801; email Ben Gruber at <a href="/cdn-cgi/l/email-protection#6f0d0a081d1a0d0a1d2f0d030241080019"><span class="__cf_email__" data-cfemail="5a383f3d282f383f281a383637743d352c">[email protected]</span></a>; website
<a href="http://www.blm.gov/programs/energy-and-minerals/oil-and-gas">www.blm.gov/programs/energy-and-minerals/oil-and-gas</a>.
The American National Standards Institute (ANSI) materials should
be available for inspection at ANSI, 25 West 43rd St, 4th floor, New
York., NY 10036; telephone: 212-642-4980; email: <a href="/cdn-cgi/l/email-protection#432a2d252c03222d302a6d2c3124"><span class="__cf_email__" data-cfemail="c1a8afa7ae81a0afb2a8efaeb3a6">[email protected]</span></a>;
website: <a href="http://www.ansi.org">www.ansi.org</a>. If the ANSI material is not available from
document resellers, contact the BLM to obtain a copy.
The American Petroleum Institute (API) materials are available for
inspection and purchase at API, 200 Massachusetts Avenue NW, Suite
1100, Washington, DC 20001; telephone: 202-682-8000; email:
<a href="/cdn-cgi/l/email-protection#2e4f5e475e5b4c5d6e4f5e4700415c49"><span class="__cf_email__" data-cfemail="3e5f4e574e4b5c4d7e5f4e5710514c59">[email protected]</span></a>; website: <a href="http://www.api.org">www.api.org</a>. API also offers free, read-only
access to some of the material at <a href="http://publications.api.org">http://publications.api.org</a>.
The material published by the Association for Materials Protection
and Performance (AMPP), formerly known as NACE International, is
available from AMPP, 15835 Park Ten Place, Houston, TX 77084;
telephone: 1-800-797-6223; website: <a href="http://www.ampp.org">www.ampp.org</a>.
[[Page 39515]]
The following describes the ANSI, API, and AMPP standards that the
BLM is incorporating by reference into this rule.
<bullet> ANSI Standard Z88.2-1992 for Respiratory Protection,
Approved August 6, 1992 (``ANSI Z88.2-1992''). This standard sets forth
accepted practices for respirator users. It provides information and
guidance on the proper selection, use, and care of respirators, and
contains requirements for establishing and regulating respirator
programs.
<bullet> API Recommended Practice 49--Recommended Practice for
Drilling and Well Servicing Operations Involving Hydrogen Sulfide;
Third Edition, May 2001; Reaffirmed, January 2013 (``API RP 49'').
These recommendations apply to oil and gas well drilling and servicing
operations that involve hydrogen sulfide, including well drilling,
completion, servicing, workover, downhole maintenance, and plug and
abandonment procedures conducted with hydrogen sulfide present in the
fluids being handled.
<bullet> ANSI/NACE MR0175-2021/ISO 15156-1:2020; Petroleum and
natural gas industries--Materials for use in H<INF>2</INF>S-containing
environments in oil and gas production; Part 1: General principles for
selection of cracking-resistant materials; Fourth Edition, Approved
September 21, 2022 (``NACE MR 0175-2021''). This standard provides
requirements and recommendations for the selection and qualification of
metallic minerals for service in equipment used in oil and gas
production and in natural-gas sweetening plants in H<INF>2</INF>S-
containing environments.
The BLM may consider making substantive changes to the four Onshore
Orders in the future but would do so through notice and comment
rulemakings. This final rule to codify the remaining Onshore Orders is
a proactive measure to facilitate future amendments. Because these four
Onshore Orders were duly promulgated through prior notice-and-comment
rulemakings, and this final rule does not change them, it is
appropriate that the BLM codify the orders in the CFR as a final rule
without any further public comment.
II. Discussion of Final Rule
This final rule codifies existing Onshore Orders 1, 2, 6, and 7 in
their entirety. Oil and gas operators have been following these
regulations for many years. They are not new. Only the section and
paragraph designations have been changed to conform with CFR style
requirements. Technical diagrams and figures that are a part of the
four existing Onshore Orders are included in this final rule as
appendices.
The four Onshore Orders will now be located in 43 CFR part 3170--
Onshore Oil and Gas Production. The Onshore Order 1 regulations will
appear under subpart 3171--Approval of Operations; Onshore Order 2
under subpart 3172--Drilling Operations on Federal and Indian Oil and
Gas Leases; Onshore Order 6 under subpart 3176--Hydrogen Sulfide
Operations; and Onshore Order 7 under subpart 3177--Disposal of
Produced Water.
Subpart 3171 describes the procedure for filing Applications for
Permit to Drill and required approvals of subsequent well operations
and other lease operations. Subpart 3172 provides the requirements and
standards for drilling and abandonment operations. Subpart 3176
provides the requirements and standards for conducting oil and gas
operations in an environment known or expected to contain hydrogen
sulfide gas (H<INF>2</INF>S). Subpart 3177 provides the methods and
approvals necessary to dispose of produced water associated with oil
and gas operations.
Subparts 3172, 3176, and 3177 identify violations, corrective
actions, normal abatement periods, and enforcement actions that may
result if violations of the associated requirements are not abated in a
timely manner.
This rule removes the table located in 43 CFR 3164.1 that lists the
four Onshore Orders that are being codified in this regulation. Since
the Onshore Orders will now be contained in title 43 of the CFR, this
table is no longer valid.
III. Procedural Matters
Regulatory Planning and Review (Executive Order 12866)
This document is not a significant rule, and the Office of
Management and Budget has not reviewed this final rule under Executive
Order 12866.
The BLM has determined that this final rule will not have an annual
effect on the economy of $100 million or more. It will not adversely
affect in a material way the economy, a sector of the economy,
productivity, competition, jobs, the environment, public health or
safety, or State, local, or tribal governments or communities. The
final rule merely codifies into the CFR regulations that are already in
effect.
This final rule will not create inconsistencies or otherwise
interfere with an action taken or planned by another agency. This rule
does not change the relationships of the onshore minerals programs with
other agencies' actions. These relationships are included in agreements
and memoranda of understanding that will not change with this rule.
In addition, this final rule does not materially affect the
budgetary impact of entitlements, grants, or loan programs, or the
rights and obligations of their recipients.
Finally, this final rule will not raise novel legal or policy
issues. As explained earlier, this final rule simply places into the
CFR regulations that have been in effect for many years, some dating
back to 1983.
The Regulatory Flexibility Act
This final rule will not have a significant economic effect on a
substantial number of small entities as defined under the Regulatory
Flexibility Act (5 U.S.C. 601 et seq.). As a result, a Regulatory
Flexibility Analysis is not required. The Small Business Administration
defines small entities as individual, limited partnerships, or small
companies considered to be at arm's length from the control of any
parent companies if they meet the following size requirements as
established for each North American Industry Classification System
(NAICS) code:
<bullet> Crude Petroleum Extraction (NAICS code 211120): 1,250 or
fewer employees
<bullet> Natural Gas Extraction (NAICS code 211130): 1,250 or fewer
employees
The Small Business Administration (SBA) would consider many, if not
most, of the operators with whom the BLM works in the onshore minerals
programs to be small entities. The BLM notes that this final rule does
not affect service industries, for which the SBA has a different
definition of ``small entity.''
The final rule will not affect a large number of small entities
because these entities are already subject to, and should be complying
with, the regulations. This rule merely codifies regulations that have
been in effect for many years.
The Small Business Regulatory Enforcement Fairness Act
This final rule is not a ``major rule'' as defined at 5 U.S.C.
804(2). The final rule will not have an annual effect on the economy
greater than $100 million; it will not result in major cost or price
increases for consumers, industries, government agencies, or regions;
and it 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.
[[Page 39516]]
Accordingly, a Small Entity Compliance Guide is not required.
Executive Order 13132, Federalism
This final rule will not have a substantial direct effect on the
States, on the relationship between the National Government and the
States, or on the distribution of power and responsibilities among the
various levels of government. In accordance with Executive Order 13132,
the BLM therefore finds that the final rule does not have federalism
implications, and a federalism assessment is not required.
The Paperwork Reduction Act of 1995
The Paperwork Reduction Act (PRA) (44 U.S.C. 3501-3521) generally
provides that an agency may not conduct or sponsor, and not
withstanding any other provision of law, a person is not required to
respond to a collection of information, unless it displays a currently
valid Office of Management and Budget (OMB) control number. Collections
of information include any request or requirement that persons obtain,
maintain, retain, or report information to an agency, or disclose
information to a third party or to the public (44 U.S.C. 3502(3) and 5
CFR 1320.3(c)). OMB has generally approved the information collection
requirements contained in this final rule; including the required forms
3160-3, Application for Permit to Drill or Re-enter, 3160-4, Well
Completion or Recompletion Report and Log, and 3160-5, Sundry Notices
and Reports on Wells, under OMB control number 1004-0137.
The information collection requirements contained in final 43 CFR
parts 3171, 3172, 3176, and 3177 are consistent with those also
currently contained in the BLM's regulations at 43 CFR parts 3160 and
3170 and the existing Onshore Order Nos. 1, 2, 6, and 7. This final
rule does not change any of these approved information collection
requirements nor the public burdens associated with those information
collection requirements; therefore, no information collection request
has been submitted to OMB in association with this final rule.
Takings Implication Assessment (Executive Order 12630)
As required by Executive Order 12630, the BLM has determined that
this final rule will not cause a taking of private property. The BLM
therefore certifies that this final rule does not represent a
governmental action capable of interference with constitutionally
protected property rights.
Civil Justice Reform (Executive Order 12988)
In accordance with Executive Order 12988, the BLM finds that this
final rule will not unduly burden the judicial system and meets the
requirements of sections 3(a) and 3(b)(2) of the Executive order.
The National Environmental Policy Act (NEPA)
The BLM has determined that this final rule qualifies as an
administrative, housekeeping action that is categorically excluded from
environmental review under NEPA pursuant to 43 CFR 46.205 and
46.210(i). The final rule does not meet any of the 12 criteria for
exceptions to categorical exclusions listed at 43 CFR 46.215.
Therefore, neither an environmental assessment nor an environmental
impact statement is required in connection with the rule (40 CFR
1501.3).
The Unfunded Mandates Reform Act of 1995
The BLM has determined that this final rule is not significant
under the Unfunded Mandates Reform Act of 1995, 2 U.S.C. 1501 et seq.,
because it will not result in State, local, private sector, or tribal
government expenditures of $100 million or more in any one year, 2
U.S.C. 1532. This rule will not significantly or uniquely affect small
governments. Therefore, the BLM is not required to prepare a statement
containing the information required by the Unfunded Mandates Reform
Act.
Consultation and Coordination With Indian Tribal Governments (Executive
Order 13175)
In accordance with Executive Order 13175, the BLM has determined
that this final rule does not include policies that have tribal
implications. Specifically, the rule would not have substantial direct
effects on one or more Indian Tribes. Consequently, the BLM did not use
the consultation process set forth in section 5 of the Executive order.
Information Quality Act
In developing this final rule, the BLM did not conduct or use a
study, experiment, or survey requiring peer review under the
Information Quality Act (Pub. L. 106-554).
Effects on the Nation's Energy Supply (Executive Order 13211)
In accordance with Executive Order 13211, the BLM has determined
that this final rule will not have a significant adverse effect on the
supply, distribution, or use of energy. It merely codifies regulations
that have been in effect for many years.
Delegation of Signing Authority
The action taken herein is pursuant to an existing delegation of
authority.
List of Subjects in 43 CFR Part 3170
Administrative practice and procedure, Disposal of produced water,
Drilling operations, Flaring, Government contracts, Hydrogen sulfide
operations, Incorporation by reference, Indians-lands, Immediate
assessments, Mineral royalties, Oil and gas exploration, Oil and gas
measurement, Public lands--mineral resources, Reporting and record
keeping requirements, Royalty-free use, Venting.
Laura Daniel-Davis,
Principal Deputy Assistant Secretary, Land and Minerals Management.
43 CFR Chapter II
For the reasons set out in the preamble, the Bureau of Land
Management is amending 43 CFR part 3170 as follows:
PART 3170--ONSHORE OIL AND GAS PRODUCTION
0
1. The authority citation for part 3170 continues to read as follows:
Authority: 25 U.S.C. 396d and 2107; 30 U.S.C. 189, 306, 359,
and 1751; and 43 U.S.C. 1732(b), 1733, and 1740.
0
2. Add subparts 3171 and 3172 to read as follows:
Subpart 3171--Approval of Operations
Sec.
3171.1 Authority.
3171.2 Purpose.
3171.3 Scope.
3171.4 Definitions.
3171.5 Application for Permit to Drill (APD).
3171.6 Components of a complete APD package.
3171.7 Drilling plan.
3171.8 Surface Use Plan of Operations.
3171.9 Bonding.
3171.10 Operator certification.
3171.11 Onsite inspection.
3171.12 APD posting and processing.
3171.13 Approval of APDs.
3171.14 Valid period of approved APD.
3171.15 Master Development Plans.
3171.16 Waiver from electronic submission requirements.
3171.17 General operating requirements--operator responsibilities.
3171.18 Rights-of-Way and Special Use Authorizations.
3171.19 Operating on lands with non-Federal surface and Federal oil
and gas.
3171.20 Leases for Indian oil and gas.
3171.21 Subsequent operations and Sundry Notices.
3171.22 Well conversions.
[[Page 39517]]
3171.23 Variances.
3171.24 Waivers, exceptions, or modifications.
3171.25 Abandonment.
3171.26 Appeal procedures.
Appendix A to Subpart 3171--Sample Format for Notice of Staking
Sec. 3171.1 Authority.
(a) The Secretaries of the Interior and Agriculture have authority
under various Federal and Indian mineral leasing laws, as defined in 30
U.S.C. 1702, to manage oil and gas operations. The Secretary of the
Interior has delegated this authority to the Bureau of Land Management
(BLM), which has issued onshore oil and gas operating regulations
codified at 43 CFR part 3160. For leases on Indian lands, the
delegation to the BLM appears at 25 CFR parts 211, 212, 213, 225, and
227.
(b) The Secretary of Agriculture has authority under the Federal
Onshore Oil and Gas Leasing Reform Act of 1987 (Pub. L. 100-203)
(Reform Act) to regulate surface disturbing activities conducted
pursuant to a Federal oil and gas lease on National Forest Service
(NFS) lands. This authority has been delegated to the Forest Service
(FS). Its regulatory authority is at 36 CFR chapter II, including, but
not limited to, part 228, subpart E, part 251, subpart B, and part 261.
The FS is responsible only for approving and regulating surface
disturbing activities on NFS lands and appeals related to FS decisions
or approvals.
Sec. 3171.2 Purpose.
The purpose of this subpart is to state the application
requirements for the approval of all proposed oil and gas and service
wells, certain subsequent well operations, and abandonment.
Sec. 3171.3 Scope.
This subpart applies to all onshore leases of Federal and Indian
oil and gas (other than those of the Osage Tribe). It also applies to
Indian Mineral Development Act agreements. For proposed operations on a
committed State or fee tract in a federally supervised unit or
communitized tract, the operator must furnish a copy of the approved
State permit to the authorized officer of the BLM which will be
accepted for record purposes.
Sec. 3171.4 Definitions.
As used in this subpart, the following definitions apply:
Best Management Practices (BMP) means practices that provide for
state-of-the-art mitigation of specific impacts that result from
surface operations. Best Management Practices are voluntary unless they
have been analyzed as a mitigation measure in the environmental review
for a Master Development Plan, Application for Permit to Drill (APD),
Right-of-Way, or other related facility and included as a Condition of
Approval.
Blooie line means a discharge line used in conjunction with a
rotating head in drilling operations when air or gas is used as the
circulating medium.
Casual use means activities involving practices that do not
ordinarily lead to any appreciable disturbance or damage to lands,
resources, or improvements. This term does not apply to private
surface. Casual use includes surveying activities.
Complete APD means that the information in the APD package is
accurate and addresses all of the requirements of this subpart. The
onsite inspection verifies important information that is part of the
APD package and is a critical step in determining if the package is
complete. Therefore, the onsite inspection must be conducted, and any
deficiencies identified at the onsite corrected, before the APD package
can be considered to be complete. While cultural, biological, or other
inventories and environmental assessments (EA) or environmental impact
statements (EIS) may be required to approve the APD, they are not
required before an APD package is considered to be complete.
(1) The APD package must contain:
(i) A completed Form 3160-3 (Application for Permit to Drill or
Reenter) (see 43 CFR 3162.3-1(d));
(ii) A well plat certified by a registered surveyor with a
surveyor's original stamp (see Sec. 3171.6(b));
(iii) A drilling plan (see 43 CFR 3162.3-1(d) and 3171.7);
(iv) A Surface Use Plan of Operations (see 43 CFR 3162.3-1(d) and
3171.8);
(v) Evidence of bond coverage (see 43 CFR 3162.3-1(d) and 3171.9);
(vi) Operator certification with original signature (see Sec.
3171.10); and
(vii) Other information that may be required by order or notice
(see 43 CFR 3162.3-1(d)(4)).
(2) The BLM and the surface managing agency, as appropriate, will
review the APD package and determine that the drilling plan, the
Surface Use Plan of Operations, and other information that the BLM may
require (43 CFR 3162.3-1(d)(4)), including the well location plat and
geospatial databases, completely describe the proposed action.
Condition of Approval (COA) means a site-specific requirement
included in an approved APD or Sundry Notice that may limit or amend
the specific actions proposed by the operator. Conditions of Approval
minimize, mitigate, or prevent impacts to public lands or other
resources. Best Management Practices may be incorporated as a Condition
of Approval.
Days means all calendar days including holidays.
Emergency repairs means actions necessary to correct an unforeseen
problem that could cause or threaten immediate substantial adverse
impact on public health and safety or the environment.
Geospatial database means a set of georeferenced computer data that
contains both spatial and attribute data. The spatial data defines the
geometry of the object and the attribute data defines all other
characteristics.
Indian lands means any lands or interest in lands of an Indian
tribe or an Indian allottee held in trust by the United States or which
is subject to a Federal restriction against alienation.
Indian oil and gas means any oil and gas interest of an Indian
tribe or on allotted lands where the interest is held in trust by the
United States or is subject to Federal restrictions against alienation.
It does not include minerals subject to the provisions of section 3 of
the Act of June 28, 1906 (34 Stat. 539), but does include oil and gas
on lands administered by the United States under section 14(g) of
Public Law 92-203, as amended.
Master Development Plan means information common to multiple
planned wells, including drilling plans, Surface Use Plans of
Operations, and plans for future production.
National Forest System lands means those Federal lands administered
by the U.S. Forest Service, such as the National Forests and the
National Grasslands.
Onsite inspection means an inspection of the proposed drill pad,
access road, flowline route, and any associated Right-of-Way or Special
Use Authorization needed for support facilities, conducted before the
approval of the APD or Surface Use Plan of Operations and construction
activities.
Private surface owner means a non-Federal or non-State owner of the
surface estate and includes any Indian owner of surface estate not held
in trust by the United States.
Reclamation means returning disturbed land as near to its
predisturbed condition as is reasonably practical.
Split estate means lands where the surface is owned by an entity or
person other than the owner of the Federal or Indian oil and gas.
Surface managing agency means any Federal or State agency having
[[Page 39518]]
jurisdiction over the surface overlying Federal or Indian oil and gas.
Variance means an approved alternative to a provision or standard
of an order or Notice to Lessee.
Sec. 3171.5 Application for Permit to Drill (APD).
An Application for Permit to Drill or Reenter, on Form 3160-3, is
required for each proposed well, and for reentry of existing wells
(including disposal and service wells), to develop an onshore lease for
Federal or Indian oil and gas.
(a) Where to file. On or after March 13, 2017, the operator must
file an APD and associated documents using the BLM's electronic
commerce application for oil and gas permitting and reporting. The
operator may contact the local BLM Field Office for information on how
to gain access to the electronic commerce application. Prior to March
13, 2017, an operator may file an APD and associated documents in the
BLM Field Office having jurisdiction over the application.
(b) Early notification. The operator may wish to contact the BLM
and any applicable surface managing agency, as well as all private
surface owners, to request an initial planning conference as soon as
the operator has identified a potential area of development. Early
notification is voluntary and would precede the Notice of Staking
option or filing of an APD. It allows the involved surface managing
agency or private surface owner to apprise the prospective operator of
any unusual conditions on the lease area. Early notification also
provides both the surface managing agency or private surface owner and
the prospective operator with the earliest possible identification of
seasonal restrictions and determination of potential areas of conflict.
The prospective operator should have a map of the proposed project
available for surface managing agency review to determine if a cultural
or biological inventory or other information may be required.
Inventories are not the responsibility of the operator.
(c) Notice of Staking option. (1) Before filing an APD or Master
Development Plan, the operator may file a Notice of Staking with the
BLM. The purpose of the Notice of Staking is to provide the operator
with an opportunity to gather information to better address site-
specific resource concerns while preparing the APD package. This may
expedite approval of the APD. On or after March 13, 2017, if an
operator chooses to file a Notice of Staking (NOS), the operator must
file the NOS using the BLM's electronic commerce application for oil
and gas permitting and reporting. Attachment I, Sample Format for
Notice of Staking, provides the information required for the Notice of
Staking option. Prior to March 13, 2017, an operator may file a Notice
of Staking in the BLM Field Office having jurisdiction.
(2) For Federal lands managed by other surface managing agencies,
the BLM will provide a copy of the Notice of Staking to the appropriate
surface managing agency office. In Alaska, when a subsistence
stipulation is part of the lease, the operator must also send a copy of
the Notice of Staking to the appropriate Borough and/or Native Regional
or Village Corporation.
(3) Within 10 days of receiving the Notice of Staking, the BLM or
the FS will review it for required information and schedule a date for
the onsite inspection. The onsite inspection will be conducted as soon
as weather and other conditions permit. The operator must stake the
proposed drill pad and ancillary facilities, and flag new or
reconstructed access routes, before the onsite inspection. The staking
must include a center stake for the proposed well, two reference
stakes, and a flagged access road centerline. Staking activities are
considered casual use unless the particular activity is likely to cause
more than negligible disturbance or damage. Offroad vehicular use for
the purposes of staking is casual use unless, in a particular case, it
is likely to cause more than negligible disturbance or damage, or
otherwise prohibited.
(4) On non-NFS lands, the BLM will invite the surface managing
agency and private surface owner, if applicable, to participate in the
onsite inspection. If the surface is privately owned, the operator must
furnish to the BLM the name, address, and telephone number of the
surface owner if known. All parties who attend the onsite inspection
will jointly develop a list of resource concerns that the operator must
address in the APD. The operator will be provided a list of these
concerns either during the onsite inspection or within 7 days of the
onsite inspection. Surface owner concerns will be considered to the
extent practical within the law. Failure to submit an APD within 60
days of the onsite inspection will result in the Notice of Staking
being returned to the operator.
Sec. 3171.6 Components of a complete APD package.
Operators are encouraged to consider and incorporate Best
Management Practices into their APDs because Best Management Practices
can result in reduced processing times and reduced number of Conditions
of Approval. An APD package must include the following information that
will be reviewed by technical specialists of the appropriate agencies
to determine the technical adequacy of the package:
(a) A completed Form 3160-3; and
(b) Operators must include in the APD package a well plat and
geospatial database prepared by a registered surveyor depicting the
proposed location of the well and identifying the points of control and
datum used to establish the section lines or metes and bounds. The
purpose of this plat is to ensure that operations are within the
boundaries of the lease or agreement and that the depiction of these
operations is accurately recorded both as to location (latitude and
longitude) and in relation to the surrounding lease or agreement
boundaries (public land survey corner and boundary ties). The
registered surveyor should coordinate with the cadastral survey
division of the appropriate BLM State Office, particularly where the
lands have not been surveyed under the Public Land Survey System.
(1) The plat and geospatial database must describe the location of
operations in:
(i) Geographical coordinates referenced to the National Spatial
Reference System, North American Datum 1983 or latest edition; and
(ii) In feet and direction from the nearest two adjacent section
lines, or, if not within the Rectangular Survey System, the nearest two
adjacent property lines, generated from the BLM's current Geographic
Coordinate Data Base.
(2) The surveyor who prepared the plat must sign it, certifying
that the location has been staked on the ground as shown on the plat.
(3) Surveying and staking are necessary casual uses, typically
involving negligible surface disturbance. The operator is responsible
for making access arrangements with the appropriate surface managing
agency (other than the BLM and the FS) or private surface owner. On
tribal or allotted lands, the operator must contact the appropriate
office of the Bureau of Indian Affairs (BIA) to make access
arrangements with the Indian surface owners. In the event that not all
of the Indian owners consent or may be located, but a majority of those
who can be located consent, or the owners of interests are so numerous
that it would be impracticable to obtain their consent and the BIA
finds that the issuance of the APD will cause no substantive injury to
the land or any owner thereof, the BIA may approve access. Typical off-
road vehicular use, when conducted in conjunction with these
activities, is a
[[Page 39519]]
necessary action for obtaining a permit and may be done without advance
approval from the surface managing agency, except for:
(i) Lands administered by the Department of Defense;
(ii) Other lands used for military purposes;
(iii) Indian lands; or
(iv) Where more than negligible surface disturbance is likely to
occur or is otherwise prohibited.
(4) No entry on split estate lands for surveying and staking should
occur without the operator first making a good faith effort to notify
the surface owner. Also, operators are encouraged to notify the BLM or
the FS, as appropriate, before entering private lands to stake for
Federal mineral estate locations.
Sec. 3171.7 Drilling plan.
With each copy of Form 3160-3, the operator must submit to the BLM
either a drilling plan or reference a previously submitted field-wide
drilling plan (a drilling plan that can be used for all the wells in a
field, any differences for specific wells will be described in the APD
specific to that well). The drilling plans must be in sufficient detail
to permit a complete appraisal of the technical adequacy of, and
environmental effects associated with, the proposed project. The
drilling plan must adhere to the provisions and standards of subpart
3172 of this part and, if applicable, subpart 3176 of this part and
must include the following information:
(a) Names and estimated tops of all geologic groups, formations,
members, or zones.
(b) Estimated depth and thickness of formations, members, or zones
potentially containing usable water, oil, gas, or prospectively
valuable deposits of other minerals that the operator expects to
encounter, and the operator's plans for protecting such resources.
(c) The operator's minimum specifications for blowout prevention
equipment and diverter systems to be used, including size, pressure
rating, configuration, and the testing procedure and frequency. Blowout
prevention equipment must meet the minimum standards outlined in
subpart 3172 of this part.
(d) The operator's proposed casing program, including size, grade,
weight, type of thread and coupling, the setting depth of each string,
and its condition. The operator must include the minimum design
criteria, including casing loading assumptions and corresponding safety
factors for burst, collapse, and tensions (body yield and joint
strength). The operator must also include the lengths and setting depth
of each casing when a tapered casing string is proposed. The hole size
for each well bore section of hole drilled must be included. Special
casing designs such as the use of coiled tubing or expandable casing
may necessitate additional information.
(e) The estimated amount and type(s) of cement expected to be used
in the setting of each casing string. If stage cementing will be used,
provide the setting depth of the stage tool(s) and amount and type of
cement, including additives, to be used for each stage. Provide the
yield of each cement slurry and the expected top of cement, with
excess, for each cemented string or stage.
(f) Type and characteristics of the proposed circulating medium or
mediums proposed for the drilling of each well bore section, the
quantities and types of mud and weighting material to be maintained,
and the monitoring equipment to be used on the circulating system. The
operator must submit the following information when air or gas drilling
is proposed:
(1) Length, size, and location of the blooie line, including the
gas ignition and dust suppression systems;
(2) Location and capacity of the compressor equipment, including
safety devices, describe the distance from the well bore, and location
within the drill site; and
(3) Anticipated amounts, types, and other characteristics as
defined in this section, of the stand by mud or kill fluid and
associated circulating equipment.
(g) The testing, logging, and coring procedures proposed, including
drill stem testing procedures, equipment, and safety measures.
(h) The expected bottom-hole pressure and any anticipated abnormal
pressures, temperatures, or potential hazards that the operator expects
to encounter, such as lost circulation and hydrogen sulfide (see
subpart 3176 of this part). A description of the operator's plans for
mitigating such hazards must be included.
(i) Any other facets of the proposed operation that the operator
would like the BLM to consider in reviewing the application. Examples
include, but are not limited to:
(1) For directional wells, proposed directional design, plan view,
and vertical section in true vertical and measured depths;
(2) Horizontal drilling; and
(3) Coil tubing operations.
Sec. 3171.8 Surface Use Plan of Operations.
(a) The Surface Use Plan of Operations must:
(1) Describe the access road(s) and drill pad, the construction
methods that the operator plans to use, and the proposed means for
containment and disposal of all waste materials;
(2) Provide for safe operations, adequate protection of surface
resources, groundwater, and other environmental components;
(3) Include adequate measures for stabilization and reclamation of
disturbed lands:
(4) Describe any Best Management Practices the operator plans to
use; and
(5) Where the surface is privately owned, include a certification
of Surface Access Agreement or an adequate bond, as described in Sec.
3171.19.
(b) All maps that are included in the Surface Use Plan of
Operations must be of a scale no smaller than 1:24,000, unless
otherwise stated in paragraph (e) of this section. Geospatial vector
and raster data must include appropriate attributes and metadata.
Georeferenced raster images must be from the same source as hardcopy
plats and maps submitted in the APD package. All proposed on-lease
surface disturbance must be surveyed and staked as described in
paragraphs (e)(1) through (12) of this section, including:
(1) The well location;
(2) Two 200-foot (61-meter) directional reference stakes;
(3) The exterior pad dimensions;
(4) The reserve pit;
(5) Cuts and fills;
(6) Outer limits of the area to be disturbed (catch points); and
(7) Any off-location facilities.
(c) Proposed new roads require centerline flagging with stakes
clearly visible from one to the next. In rugged terrain, cut and fill
staking and/or slope staking of proposed new access roads and locations
for ancillary facilities that may be necessary, as determined by the
BLM or the FS.
(d) The onsite inspection will not occur until the required
surveying and staking is complete, and any new access road(s) have been
flagged, unless a variance is first granted under Sec. 3171.23.
(e) Information required by the Surface Use Plan of Operations may
be shown on the same map if it is appropriately labeled or on separate
diagrams or maps and must include the following:
(1) Existing roads. The operator must submit a legible map such as
a highway or county road, United States Geological Survey (USGS)
topographic, Alaska Borough, or other such map that shows the proposed
well site and access route to the proposed well in relation to a town,
village, or other locatable public access point.
[[Page 39520]]
(i) The operator must improve or maintain existing roads in a
condition the same as or better than before operations began. The
operator must provide any plans for improvement and/or maintenance of
existing roads. The information provided by the operator for
construction and use of roads will be used by the BLM for any Right-of-
Way application, as described in Sec. 3171.18. The operator may use
existing terrain and two-track trails, where appropriate, to assure
environmental protection. The operator should consider using Best
Management Practices in improving or maintaining existing roads.
(ii) The operator may use existing roads under the jurisdiction of
the FS for access if they meet the transportation objectives of the FS.
When access involves the use of existing roads, the FS may require that
the operator contribute to road maintenance. This is usually authorized
by a Road Use Permit or a joint road use agreement. The FS will charge
the operator a pro rata share of the costs of road maintenance and
improvement, based upon the anticipated use of the road.
(2) New or reconstructed access roads. The operator must identify
on a map all permanent and temporary access roads that it plans to
construct or reconstruct in connection with the drilling of the
proposed well. Locations of all existing and proposed road structures
(culverts, bridges, low water crossings, etc.) must be shown. The
proposed route to the proposed drill site must be shown, including
distances from the point where the access route exits established
roads. All permanent and temporary access roads must be located and
designed to meet the applicable standards of the appropriate surface
managing agency, and be consistent with the needs of the operator. The
operator should consider using Best Management Practices in designing
and constructing roads. The operator must design roads based upon the
class or type of road, the safety requirements, traffic
characteristics, environmental conditions, and the vehicles the road is
expected to carry. The operator must describe for all road construction
or reconstruction:
(i) Road width;
(ii) Maximum grade;
(iii) Crown design;
(iv) Turnouts;
(v) Drainage and ditch design;
(vi) On-site and off-site erosion control;
(vii) Revegetation of disturbed areas;
(viii) Location and size of culverts and/or bridges;
(ix) Fence cuts and/or cattleguards;
(x) Major cuts and fills;
(xi) Source and storage of topsoil; and
(xii) Type of surfacing materials, if any, that will be used.
(3) Location of existing wells. The operator must include a map and
may include a geospatial database that includes all known wells,
regardless of the well status (producing, abandoned, etc.), within a
one-mile radius of the proposed location.
(4) Location of existing and/or proposed production facilities. The
operator must include a map or diagram of facilities planned either on
or off the well pad that shows, to the extent known or anticipated, the
location of all production facilities and lines likely to be installed
if the well is successfully completed for production.
(i) The map or diagram and optional geospatial database must show
and differentiate between proposed and existing flow lines, overhead
and buried power lines, and water lines. If facilities will be located
on the well pad, the information should be consistent with the layout
provided in paragraph (e)(9) of this section.
(ii) The operator must show the dimensions of the facility layouts
for all new construction. This information may be used by the BLM or
the FS for Right- of-Way or Special Use Authorization application
information, as specified in Sec. 3171.18.
(iii) If the operator has not developed information regarding
production facilities, it may defer submission of that information
until a production well is completed, in which case the operator will
follow the procedures in Sec. 3171.21. However, for purposes of the
National Environmental Policy Act (NEPA) analysis, the BLM or the FS
will need a reasonable estimate of the facilities to be employed.
(5) Location and types of water supply. Information concerning
water supply, such as rivers, creeks, springs, lakes, ponds, and wells,
may be shown by quarter-quarter section on a map or plat, or may be
described in writing. The operator must identify the source, access
route, and transportation method for all water anticipated for use in
drilling the proposed well. The operator must describe any newly
constructed or reconstructed access roads crossing Federal or Indian
lands that are needed to haul the water as provided in paragraph (e)(2)
of this section. The operator must indicate if it plans to drill a
water supply well on the lease and, if so, the operator must describe
the location, construction details, and expected production
requirements, including a description of how water will be transported
and procedures for well abandonment.
(6) Construction materials. The operator must state the character
and intended use of all construction materials, such as sand, gravel,
stone, and soil material. The proposed source must be shown on a
quarter-quarter section of a map or plat or in a written description.
(7) Methods for handling waste. The Surface Use Plan of Operations
must contain a written description of the methods and locations
proposed for safe containment and disposal of each type of waste
material (e.g., cuttings, garbage, salts, chemicals, sewage, etc.) that
results from drilling the proposed well. The narrative must include
plans for the eventual disposal of drilling fluids and any produced oil
or water recovered during testing operations. The operator must
describe plans for the construction and lining, if necessary, of the
reserve pit.
(8) Ancillary facilities. The operator must identify on a map the
location and construction methods and materials for all anticipated
ancillary facilities such as camps, airstrips, and staging areas. The
operator must stake on the ground the approximate center of proposed
camps and the centerline of airstrips. If the ancillary facilities are
located off- lease, depending on surface managing agency policy, the
BLM or the FS may require the operator to obtain an additional
authorization, such as a Right-of-Way or Special Use Authorization.
(9) Well site layout. A diagram of the well site layout must have
an arrow indicating the north direction. Diagrams with cuts and fills
must be surveyed, designed, drawn, digitized, and certified by licensed
professional surveyors or engineers.
(i) The operator must submit a plat of a scale of not less than 1
inch = 50 feet showing the location and orientation of:
(A) The proposed drill pad;
(B) Reserve pit/blooie line/flare pit location;
(C) Access road entry points and their approximate location with
respect to topographic features and with cross section diagrams of the
drill pad; and
(D) The reserve pit showing all cuts; and fills and the relation to
topography.
(ii) The plat must also include the approximate proposed location
and orientation of the:
(A) Drilling rig;
(B) Dikes and ditches to be constructed; and
(C) Topsoil and/or spoil material stockpiles.
(10) Plans for surface reclamation. The operator must submit a plan
for the surface reclamation or stabilization of all disturbed areas.
This plan must
[[Page 39521]]
address interim (during production) reclamation for the area of the
well pad not needed for production, as well as final abandonment of the
well location.
(i) Such plans must include, as appropriate:
(A) Configuration of the reshaped topography;
(B) Drainage systems;
(C) Segregation of spoil materials (stockpiles);
(D) Surface disturbances;
(E) Backfill requirements;
(F) Proposals for pit/sump closures;
(G) Redistribution of topsoil;
(H) Soil treatments;
(I) Seeding or other steps to reestablish vegetation;
(J) Weed control; and
(K) Practices necessary to reclaim all disturbed areas, including
any access roads and pipelines.
(ii) The operator may amend this reclamation plan at the time of
abandonment. Further details for reclamation are contained in Sec.
3171.25.
(11) Surface ownership. The operator must indicate (in a narrative)
the surface ownership at the well location, and of all lands crossed by
roads that the operator plans to construct or upgrade, including, if
known, the name of the agency or owner, phone number, and address. The
operator must certify that they have provided a copy of the Surface Use
Plan of Operations required in this section to the private surface
owner of the well site location, if applicable, or that they made a
good faith effort if unable to provide the document to the surface
owner.
(12) Other information. The operator must include other information
required by applicable orders and notices (43 CFR 3162.3-1(d)(4)). When
an integrated pest management program is needed for weed or insect
control, the operator must coordinate plans with State or local
management agencies and include the pest management program in the
Surface Use Plan of Operations. The BLM also encourages the operator to
submit any additional information that may be helpful in processing the
application.
Sec. 3171.9 Bonding.
(a) Most bonding needs for oil and gas operations on Federal leases
are discussed in 43 CFR part 3100, subpart 3104. The operator must
obtain a bond in its own name as principal, or a bond in the name of
the lessee or sublessee. If the operator uses the lessee or sublessee's
bond, the operator must furnish a rider (consent of surety and
principal) that includes the operator under the coverage of the bond.
The operator must specify on the APD, Form 3160-3, the type of bond and
bond number under which the operations will be conducted.
(1) For Indian oil and gas, the appropriate provisions at 25 CFR
chapter I, subchapter I, govern bonding.
(2) Under the regulations at 43 CFR 3104.5 and 36 CFR 228.109, the
BLM or the FS may require additional bond coverage for specific APDs.
Other factors that the BLM or the FS may consider include:
(i) History of previous violations;
(ii) Location and depth of wells;
(iii) The total number of wells involved;
(iv) The age and production capability of the field; and
(v) Unique environmental issues.
(3) These bonds may be in addition to any statewide, nationwide, or
separate lease bond already applicable to the lease. In determining the
bond amount, the BLM may consider impacts of activities on both Federal
and non-Federal lands required to develop the lease that impact lands,
waters, and other resources off the lease.
(4) Separate bonds may be required for associated Rights-of-Way
and/or Special Use Authorizations that authorize activities not covered
by the approved APD.
(b) On Federal leases, operators may request a phased release of an
individual lease bond. The BLM will grant this reduction after
reclamation of some portion of the lease only if the operator:
(1) Has satisfied the terms and conditions in the plan for surface
reclamation for that particular operation; and
(2) No longer has any down-hole liability.
(c) If appropriate, the BLM may reduce the bond in the amount
requested by the operator or appropriate surface managing agency. The
FS also may reduce bonds it requires (but not the BLM-required bonds).
The BLM and the FS will base the amount of the bond reduction on a
calculation of the sum that is sufficient to cover the remaining
operations (including royalty payments) and abandonment (including
reclamation) as authorized by the Surface Use Plan of Operations.
Sec. 3171.10 Operator certification.
(a) The operator must include its name, address, and telephone
number, and the same information for its field representative, in the
APD package.
(b) The following certification must carry the operator's original
signature or be submitted to the BLM using the BLM's electronic
reporting system:
I hereby certify that I, or someone under my direct supervision,
have inspected the drill site and access route proposed herein; that
I am familiar with the conditions which currently exist; that I have
full knowledge of state and Federal laws applicable to this
operation; that the statements made in this APD package are, to the
best of my knowledge, true and correct; and that the work associated
with the operations proposed herein will be performed in conformity
with this APD package and the terms and conditions under which it is
approved. I also certify that I, or the company I represent, am
responsible for the operations conducted under this application.
These statements are subject to the provisions of 18 U.S.C. 1001 for
the filing of false statements.
Executed this _ day of ___, 20__.
Name-------------------------------------------------------------------
Position---------------------------------------------------------------
Title------------------------------------------------------------------
Address----------------------------------------------------------------
Telephone--------------------------------------------------------------
Field representative (if not above signatory)--------------------------
Address (if different from above)--------------------------------------
Telephone (if different from above)------------------------------------
Email (optional)-------------------------------------------------------
(c) Agents not directly employed by the operator must submit a
letter from the operator authorizing that agent to act or file this
application on their behalf.
Sec. 3171.11 Onsite inspection.
The onsite inspection must be conducted before the APD will be
considered complete.
Sec. 3171.12 APD posting and processing.
(a) Posting. The BLM and the Federal surface managing agency, if
other than the BLM, must provide at least 30 days public notice before
the BLM may approve an APD or Master Development Plan on a Federal oil
and gas lease. Posting is not required for an APD for an Indian oil and
gas lease or agreement.
(1) The BLM will post information about the APD or Notice of
Staking for Federal oil and gas leases to the internet and in an area
of the BLM Field Office having jurisdiction that is readily accessible
to the public. Posting to the internet under this provision will not be
required until after March 13, 2017. If the surface is managed by a
Federal agency other than the BLM, that agency also is required to post
the notice for at least 30 days. This would include the BIA where the
surface is held in trust but the mineral estate is federally owned. The
posting is for informational purposes only and is not an appealable
decision. The purpose of the posting is to give any interested party
notification that a Federal approval of mineral operations has been
requested. The BLM or the FS will not post confidential information.
[[Page 39522]]
(2) Reposting of the proposal may be necessary if the posted
location of the proposed well is:
(i) Moved to a different quarter-quarter section;
(ii) Moved more than 660 feet for lands that are not covered by a
Public Land Survey; or
(iii) If the BLM or the FS determine that the move is substantial.
(b) Processing. The timeframes established in this paragraph apply
to both individual APDs and to the multiple APDs included in Master
Development Plans and to leases of Indian minerals as well as leases of
Federal minerals. If there is enough information to begin processing
the application, the BLM (and the FS if applicable) will process it up
to the point that missing information or uncorrected deficiencies
render further processing impractical or impossible.
(1) Within 10 days of receiving an application, the BLM (in
consultation with the FS if the application concerns NFS lands) will
notify the operator as to whether or not the application is complete.
The BLM will request additional information and correction of any
material submitted, if necessary, in the 10-day notification. If an
onsite inspection has not been performed, the applicant will be
notified that the application is not complete. Within 10 days of
receiving the application, the BLM, in coordination with the operator
and surface managing agency, including the private surface owner in the
case of split estate minerals, will schedule a date for the onsite
inspection (unless the onsite inspection has already been conducted as
part of a Notice of Staking). The onsite inspection will be held as
soon as practicable based on participants' schedules and weather
conditions. The operator will be notified at the onsite inspection of
any additional deficiencies that are discovered during the inspection.
The operator has 45 days after receiving notice from the BLM to provide
any additional information necessary to complete the APD, or the APD
may be returned to the operator.
(2) Within 30 days after the operator has submitted a complete
application, including incorporating any changes that resulted from the
onsite inspection, the BLM will:
(i) Approve the application, subject to reasonable Conditions of
Approval, if the appropriate requirements of the NEPA, National
Historic Preservation Act, Endangered Species Act, and other applicable
law have been met and, if on NFS lands, the FS has approved the Surface
Use Plan of Operations;
(ii) Notify the operator that it is deferring action on the permit;
or
(iii) Deny the permit if it cannot be approved and the BLM cannot
identify any actions that the operator could take that would enable the
BLM to issue the permit or the FS to approve the Surface Use Plan of
Operations, if applicable.
(3) The notice of deferral in paragraph (b)(2)(ii) of this section
must specify:
(i) Any action the operator could take that would enable the BLM
(in consultation with the FS if applicable) to issue a final decision
on the application. The FS will notify the applicant of any action the
applicant could take that would enable the FS to issue a final decision
on the Surface Use Plan of Operations on NFS lands. Actions may
include, but are not limited to, assistance with:
(A) Data gathering; and
(B) Preparing analyses and documents.
(ii) If applicable, a list of actions that the BLM or the FS need
to take before making a final decision on the application, including
appropriate analysis under NEPA or other applicable law and a schedule
for completing these actions.
(4) The operator has 2 years from the date of the notice under
paragraph (b)(3)(i) of this section to take the action specified in the
notice. If the appropriate analyses required by NEPA, National Historic
Preservation Act, Endangered Species Act, and other applicable laws
have been completed, the BLM (and the FS if applicable), will make a
decision on the permit and the Surface Use Plan of Operations within 10
days of receiving a report from the operator addressing all of the
issues or actions specified in the notice under paragraph (b)(3)(i) of
this section and certifying that all required actions have been taken.
If the operator has not completed the actions specified in the notice
within 2 years from the operator's receipt of the notice under
paragraph (b)(3)(i), the BLM will deny the permit.
(5) For APDs on NFS lands, the decision to approve a Surface Use
Plan of Operations or Master Development Plan may be subject to FS
appeal procedures. The BLM cannot approve an APD until the appeal of
the Surface Use Plan of Operations is resolved.
Sec. 3171.13 Approval of APDs.
(a) The BLM has the lead responsibility for completing the
environmental review process, except in the case of NFS lands.
(1) The BLM cannot approve an APD or Master Development Plan until
the requirements of certain other laws and regulations including NEPA,
the National Historic Preservation Act, and the Endangered Species Act
have been met. The BLM must document that the needed reviews have been
adequately conducted. In some cases, operators conduct these reviews,
but the BLM remains responsible for their scope and content and makes
its own evaluation of the environmental issues, as required by 40 CFR
1506.5(b).
(2) The approved APD will contain Conditions of Approval that
reflect necessary mitigation measures. In accordance with 43 CFR
3101.1-2 and 36 CFR 228.107, the BLM or the FS may require reasonable
mitigation measures to ensure that the proposed operations minimize
adverse impacts to other resources, uses, and users, consistent with
granted lease rights. The BLM will incorporate any mitigation
requirements, including Best Management Practices, identified through
the APD review and appropriate NEPA and related analyses, as Conditions
of Approval to the APD.
(3) The BLM will establish the terms and Conditions of Approval for
any associated Right-of-Way when the application is approved.
(b) For NFS lands, the FS will establish the terms and Conditions
of Approval for both the Surface Use Plan of Operations and any
associated Surface Use Authorization. On NFS lands the FS has principal
responsibility for compliance with NEPA, the National Historic
Preservation Act, and the Endangered Species Act, but the BLM should be
a cooperating or co-lead agency for this purpose and adopt the analysis
as the basis for its decision. After the FS notifies the BLM it has
approved a Surface Use Plan of Operations on NFS lands, the BLM must
approve the APD before the operator may begin any surface-disturbing
activity.
(c) On Indian lands, BIA has responsibility for approving Rights-
of-Way.
(d) In the case of Indian lands, the BLM may be a cooperating or
co-lead agency for NEPA compliance or may adopt the NEPA analysis
prepared by the BIA (516 Department of the Interior Manual (DM) 3).
Sec. 3171.14 Valid period of approved APD.
(a) An APD approval is valid for 2 years from the date that it is
approved, or until lease expiration, whichever occurs first. If the
operator submits a written request before the expiration of the
original approval, the BLM, in coordination with the FS, as appropriate
may extend the APD's validity for up to 2 additional years.
[[Page 39523]]
(b) The operator is responsible for reclaiming any surface
disturbance that resulted from its actions, even if a well was not
drilled.
Sec. 3171.15 Master Development Plans.
(a) An operator may elect to submit a Master Development Plan
addressing two or more APDs that share a common drilling plan, Surface
Use Plan of Operations, and plans for future development and
production. Submitting a Master Development Plan facilitates early
planning, orderly development, and the cumulative effects analysis for
all the APDs expected to be drilled by an operator in a developing
field. Approval of a Master Development Plan serves as approval of all
of the APDs submitted with the Plan. Processing of a Master Development
Plan follows the procedures in Sec. 3171.12(b).
(b) After the Master Development Plan is approved, subsequent APDs
can reference the Master Development Plan and be approved using the
NEPA analysis for the Master Development Plan, absent substantial
deviation from the Master Development Plan previously analyzed or
significant new information relevant to environmental effects.
Therefore, an approved Master Development Plan results in timelier
processing of subsequent APDs. Each subsequent proposed well must have
a survey plat and an APD (Form 3160-3) that references the Master
Development Plan and any specific variations for that well.
Sec. 3171.16 Waiver from electronic submission requirements.
The operator may request a waiver from the electronic submission
requirement for an APD or Notice of Staking if compliance would cause
hardship or the operator is unable to file these documents
electronically. In the request, the operator must explain the reason(s)
that prevent its use of the electronic system, plans for complying with
the electronic submission requirement, and a timeframe for compliance.
If the request applies to a particular set of APDs or Notices of
Staking, then the request must identify the APDs or Notices of Staking
to which the waiver applies. The waiver request is subject to BLM
approval. If the request does not specify a particular set of APDs or
Notices of Staking, then the waiver will apply to all submissions made
by the operator during the compliance timeframe included as part of the
BLM's waiver approval. The BLM will not consider an APD or Notice of
Staking that the operator did not submit through the electronic system,
unless the BLM approves a waiver.
Sec. 3171.17 General operating requirements--operator
responsibilities.
(a) In the APD package, the operator must describe or show, as set
forth in this subpart, the procedures, equipment, and materials to be
used in the proposed operations. The operator must conduct operations
to minimize adverse effects to surface and subsurface resources,
prevent unnecessary surface disturbance, and conform with currently
available technology and practice. While appropriate compliance with
certain statutes, such as NEPA, the National Historic Preservation Act,
and the Endangered Species Act, are Federal responsibilities, the
operator may choose to conduct inventories and provide documentation to
assist the BLM or the surface managing agency to meet the requirements
of this paragraph (a). The inventories and other work may require
entering the lease and adjacent lands before approval of the APD. As in
staking and surveying, the operator should make a good faith effort to
contact the surface managing agency or surface owner before entry upon
the lands for these purposes.
(b) The operator cannot commence either drilling operations or
preliminary construction activities before the BLM's approval of the
APD. A copy of the approved APD and any Conditions of Approval must be
available for review at the drill site. Operators are responsible for
their contractor and subcontractor's compliance with the requirements
of the approved APD and/or Surface Use Plan of Operations. Drilling
without approval or causing surface disturbance without approval is a
violation of 43 CFR 3162.3-1(c) and is subject to a monetary assessment
under 43 CFR 3163.1(b)(2).
(c) The operator must comply with the provisions of the approved
APD and applicable laws, regulations, and Notices to Lessees,
including, but not limited to, those that address the issues described
in paragraphs (c)(1) through (5) of this section.
(1) Cultural and historic resources. If historic or archaeological
materials are uncovered during construction, the operator must
immediately stop work that might further disturb such materials,
contact the BLM and if appropriate, the FS or other surface managing
agency. The BLM or the FS will inform the operator within 7 days after
the operator contacted the BLM as to whether the materials appear
eligible for listing on the National Register of Historic Places.
(i) If the operator decides to relocate operations to avoid further
costs to mitigate the site, the operator remains responsible for
recording the location of any historic or archaeological resource that
are discovered as a result of the operator's actions. The operator also
is responsible for stabilizing the exposed cultural material if the
operator created an unstable condition that must be addressed
immediately. The BLM, the FS, or other appropriate surface managing
agency will assume responsibility for evaluation and determination of
significance related to the historic or archaeological site.
(ii) If the operator does not relocate operations, the operator is
responsible for mitigation and stabilization costs and the BLM, the FS,
or appropriate surface managing agency will provide technical and
procedural guidelines for conducting mitigation. The operator may
resume construction operations when the BLM or the FS verifies that the
operator has completed the required mitigation.
(iii) Relocation of activities may subject the proposal to
additional environmental review. Therefore, if the presence of such
sites is suspected, the operator may want to submit alternate locations
for advance approval before starting construction.
(2) Endangered Species Act. To comply with the Endangered Species
Act, as amended (16 U.S.C. 1531 et seq.), and its implementing
regulations in 50 CFR chapter I, the operator must conduct all
operations such that all operations avoid a ``take'' of listed or
proposed threatened or endangered species and their critical habitats.
(3) Surface protection. Except as otherwise provided in an approved
Surface Use Plan of Operations, the operator must not conduct
operations in areas subject to mass soil movement, riparian areas,
floodplains, lakeshores, and/or wetlands. The operator also must take
measures to minimize or prevent erosion and sediment production. Such
measures may include, but are not limited to:
(i) Avoiding steep slopes and excessive land clearing when siting
structures, facilities, and other improvements; and
(ii) Temporarily suspending operations when frozen ground, thawing,
or other weather-related conditions would cause otherwise avoidable or
excessive impacts.
(4) Safety measures. The operator must maintain structures,
facilities, improvements, and equipment in a safe condition in
accordance with the approved APD. The operator must also take
appropriate measures as specified in Notices to Lessees to protect the
[[Page 39524]]
public from any hazardous conditions resulting from operations.
(i) In the event of an emergency, the operator may take immediate
action without prior surface managing agency approval to safeguard life
or to prevent significant environmental degradation. The BLM or the FS
must receive notification of the emergency situation and the remedial
action taken by the operator as soon as possible, but not later than 24
hours after the emergency occurred. If the emergency only affected
drilling operations and had no surface impacts, only the BLM must be
notified.
(ii) If the emergency involved surface resources on other surface
managing agency lands, the operator should also notify the surface
managing agency and private surface owner within 24 hours.
(iii) Upon conclusion of the emergency, the BLM or the FS, where
appropriate, will review the incident and take appropriate action.
(5) Completion reports. Within 30 days after the well completion,
the lessee or operator must submit to the BLM two copies of a completed
Form 3160-4, Well Completion or Recompletion Report and Log. Well logs
may be submitted to the BLM in an electronic format such as ``.LAS''
format. Surface and bottom-hole locations must be in latitude and
longitude.
Sec. 3171.18 Rights-of-Way and Special Use Authorizations.
(a) The BLM or the FS will notify the operator of any additional
Rights-of-Way, Special Use Authorizations, licenses, or other permits
that are needed for roads and support facilities for drilling or off-
lease access, as appropriate. This notification will normally occur at
the time the operator submits the APD or Notice of Staking package, or
Sundry Notice, or during the onsite inspection.
(b) The BLM or the FS, as appropriate, will approve or accept on-
lease activities that are associated with actions proposed in the APD
or Sundry Notice and that will occur on the lease as part of the APD or
Sundry Notice. These actions do not require a Right-of- Way or Special
Use Authorization. For pipeline Rights-of-Way crossing lands under the
jurisdiction of two or more Federal surface managing agencies, except
lands in the National Park Service or Indian lands, applications should
be submitted to the BLM. Refer to 43 CFR parts 2800 and 2880 for
guidance on BLM Rights-of-Way and 36 CFR part 251 for guidance on FS
Special Use Authorizations.
(1) Rights-of-Way (BLM). (i) For BLM lands, the APD package may
serve as the supporting document for the Right-of-Way application in
lieu of a Right-of-Way plan of development.
(ii) Any additional information specified in 43 CFR parts 2800 and
2880 will be required in order to process the Right- of-Way. The BLM
will notify the operator within 10 days of receipt of a Notice of
Staking, APD, or other notification if any parts of the project require
a Right- of-Way. If a Right-of-Way is needed, the information required
from the operator to approve the Right-of-Way may be submitted by the
operator with the APD package if the Notice of Staking option has been
used.
(2) Special Use Authorizations (FS) (36 CFR part 251, subpart B).
When a Special Use Authorization is required, the Surface Use Plan of
Operations may serve as the application for the Special Use
Authorization if the facility for which a Special Use Authorization is
required is adequately described (see 36 CFR 251.54(d)(ii)). Conditions
regulating the authorized use may be imposed to protect the public
interest, to ensure compatibility with other NFS lands programs and
activities consistent with the Forest Land and Resources Management
Plan. A Special Use Authorization, when related to an APD, will include
terms and conditions (36 CFR 251.56) and may require a specific
reclamation plan or adopt applicable parts of the Surface Use Plan of
Operations by reference.
Sec. 3171.19 Operating on lands with non-Federal surface and Federal
oil and gas.
(a) The operator must submit the name, address, and phone number of
the surface owner, if known, in its APD. The BLM will invite the
surface owner to the onsite inspection to assure that their concerns
are considered. As provided in the oil and gas lease, the BLM may
request that the applicant conduct surveys or otherwise provide
information needed for the BLM's National Historic Preservation Act
consultation with the State Historic Preservation Officer or Indian
tribe or its Endangered Species Act consultation with the relevant
fisheries agency. The Federal mineral lessee has the right to enter the
property for the purpose set out in the preceding sentence, since it is
a necessary prerequisite to development of the dominant mineral estate.
Nevertheless, the lessee or operator should seek to reach agreement
with the surface owner about the time and method by which any survey
would be conducted.
(b) Likewise, in the case of actual oil and gas operations, the
operator must make a good faith effort to notify the private surface
owner before entry and make a good faith effort to obtain a Surface
Access Agreement from the surface owner. This section also applies to
lands with Indian trust surface and Federal minerals. In these cases,
the operator must make a good faith effort to obtain surface access
agreement with the tribe in the case of tribally owned surface,
otherwise with the majority of the Indian surface owners who can be
located with the assistance and concurrence of the BIA. The Surface
Access Agreement may include terms or conditions of use, be a waiver,
or an agreement for compensation. The operator must certify to the BLM
that:
(1) It made a good faith effort to notify the surface owner before
entry; and
(2) That an agreement with the surface owner has been reached or
that a good faith effort to reach an agreement failed. If no agreement
was reached with the surface owner, the operator must submit an
adequate bond (minimum of $1,000) to the BLM for the benefit of the
surface owner sufficient to:
(i) Pay for loss or damages; or
(ii) As otherwise required by the specific statutory authority
under which the surface was patented and the terms of the lease.
(c) Surface owners have the right to appeal the sufficiency of the
bond. Before the approval of the APD, the BLM will make a good faith
effort to contact the surface owner to assure that they understand
their rights to appeal.
(d) The BLM must comply with NEPA, the National Historic
Preservation Act, the Endangered Species Act, and related Federal
statutes when authorizing lease operations on split estate lands where
the surface is not federally owned and the oil and gas is Federal. For
split estate lands within FS administrative boundaries, the BLM has the
lead responsibility, unless there is a local BLM/FS agreement that
gives the FS this responsibility.
(e) The operator must make a good faith effort to provide a copy of
their Surface Use Plan of Operations to the surface owner. After the
APD is approved the operator must make a good faith effort to provide a
copy of the Conditions of Approval to the surface owner. The APD
approval is not contingent upon delivery of a copy of the Conditions of
Approval to the surface owner.
Sec. 3171.20 Leases for Indian oil and gas.
(a) Approval of operations. The BLM will process APDs, Master
Development Plans, and Sundry Notices on Indian tribal and allotted oil
and gas leases, and Indian Mineral Development Act mineral agreements
in a manner similar to Federal leases. For processing such
[[Page 39525]]
applications, the BLM considers the BIA to be the surface managing
agency. Operators are responsible for obtaining any special use or
access permits from appropriate BIA and, where applicable, tribal
offices. The BLM is not required to post for public inspection APDs for
minerals subject to Indian oil and gas leases or agreements.
(b) Surface use. Where the wellsite and/or access road is proposed
on Indian lands with a different beneficial owner than the minerals,
the operator is responsible for entering into a surface use agreement
with the Indian tribe or the individual Indian surface owner, subject
to BIA approval. This agreement must specify the requirements for
protection of surface resources, mitigation, and reclamation of
disturbed areas. The BIA, the Indian surface owner, and the BLM,
pursuant to 25 CFR 211.4, 212.4 and 225.4, will develop the Conditions
of Approval. If the operator is unable to obtain a Surface Access
Agreement, it may provide a bond for the benefit of the surface
owner(s) (see Sec. 3171.19).
Sec. 3171.21 Subsequent operations and Sundry Notices.
Subsequent operations must follow 43 CFR part 3160, applicable
lease stipulations, and APD Conditions of Approval. The operator must
file the Sundry Notice in the BLM Field Office having jurisdiction over
the lands described in the notice or the operator may file it using the
BLM's electronic commerce system.
(a) Surface disturbing operations. (1) Lessees and operators must
submit for BLM or FS approval a request on Form 3160-5 before:
(i) Undertaking any subsequent new construction outside the
approved area of operations; or
(ii) Reconstructing or altering existing facilities including, but
not limited to, roads, emergency pits, firewalls, flowlines, or other
production facilities on any lease that will result in additional
surface disturbance.
(2) If, at the time the original APD was filed, the lessee or
operator elected to defer submitting information under Sec.
3171.8(e)(4)(iii), the lessee or operator must supply this information
before construction and installation of the facilities. The BLM, in
consultation with any other involved surface managing agency, may
require a field inspection before approving the proposal. The lessee or
operator may not begin construction until the BLM approves the proposed
plan in writing.
(3) The operator must certify on Form 3160-5 that they have made a
good faith effort to provide a copy of any proposal involving new
surface disturbance to the private surface owner in the case of split
estate.
(b) Emergency repairs. Lessees or operators may undertake emergency
repairs without prior approval if they promptly notify the BLM. Lessees
or operators must submit sufficient information to the BLM or the FS to
permit a proper evaluation of any:
(1) Resulting surface disturbing activities; or
(2) Planned accommodations necessary to mitigate potential adverse
environmental effects.
Sec. 3171.22 Well conversions.
(a) Conversion to an injection well. When subsequent operations
will result in a well being converted to a Class II injection well
(i.e., for disposal of produced water, oil and gas production
enhancement, or underground storage of hydrocarbons), the operator must
file with the appropriate BLM office a Sundry Notice, Notice of Intent
to Convert to Injection on Form 3160-5. The BLM and the surface
managing agency, if applicable, will review the information to ensure
its technical and administrative adequacy. Following the review, the
BLM, in consultation with the surface managing agency, where
applicable, will decide upon the approval or disapproval of the
application based upon relevant laws and regulations and the
circumstances (e.g., the well used for lease or non-lease operations,
surface ownership, and protection of subsurface mineral ownership). The
BLM will determine if a Right-of-Way or Special Use Authorization and
additional bonding are necessary and notify the operator.
(b) Conversion to a water supply well. In cases where the surface
managing agency or private surface owner desires to acquire an oil and
gas well and convert it to a water supply well or acquire a water
supply well that was drilled by the operator to support lease
operations, the surface managing agency or private surface owner must
inform the appropriate BLM office of its intent before the approval of
the APD in the case of a dry hole and no later than the time a Notice
of Intent to Abandon is submitted for a depleted production well. The
operator must abandon the well according to BLM instructions, and must
complete the surface cleanup and reclamation, in conjunction with the
approved APD, Surface Use Plan of Operations, or Notice of Intent to
Abandon, if the BLM or the FS require it. The surface managing agency
or private surface owner must reach agreement with the operator as to
the satisfactory completion of reclamation operations before the BLM
will approve any abandonment or reclamation. The BLM approval of the
partial abandonment under this section, completion of any required
reclamation operations, and the signed release agreement will relieve
the operator of further obligation for the well. If the surface
managing agency or private surface owner acquires the well for water
use purposes, the party acquiring the well assumes liability for the
well.
Sec. 3171.23 Variances.
The operator may make a written request to the agency with
jurisdiction to request a variance from this subpart. A request for a
variance must explain the reason the variance is needed and demonstrate
how the operator will satisfy the intent of this subpart. The operator
may include the request in the APD package. A variance from the
requirements of this subpart does not constitute a variance to
provisions of other regulations, laws, or orders. When the BLM is the
decision maker on a request for a variance, the decision whether to
grant or deny the variance request is entirely within the BLM's
discretion. The decision on a variance request is not subject to
administrative appeals either to the State Director or pursuant to 43
CFR part 4.
Sec. 3171.24 Waivers, exceptions, or modifications.
(a) An operator may also request that the BLM waive (permanently
remove), except (case-by-case exemption), or modify (permanently
change) a lease stipulation for a Federal lease. In the case of Federal
leases, a request to waive, except, or modify a stipulation should also
include information demonstrating that the factors leading to its
inclusion in the lease have changed sufficiently to make the protection
provided by the stipulation no longer justified or that the proposed
operation would not cause unacceptable impacts.
(b) When the waiver, exception, or modification is substantial, the
proposed waiver, exception, or modification is subject to public review
for 30 days. Prior to such public review, the BLM, and when applicable
the FS, will post it in their local Field Office and, when possible,
electronically on the internet. When the request is included in the
Notice of Staking or APD, the request will be included as part of the
application posting under Sec. 3171.5(c). Prior to granting a waiver,
exception, or modification, the BLM will obtain the concurrence or
approval of the FS or Federal surface managing agency. Decisions on
such waivers,
[[Page 39526]]
exceptions, or modifications are subject to appeal pursuant to 43 CFR
part 4.
(c) After drilling has commenced, the BLM and the FS may consider
verbal requests for waivers, exceptions, or modifications. However, the
operator must submit a written notice within 7 days after the verbal
request. The BLM and the FS will confirm in writing any verbal
approval. Decisions on waivers, exceptions, or modifications submitted
after drilling has commenced are final for the Department of the
Interior and not subject to administrative review by the State Director
or appeal pursuant to 43 CFR part 4.
Sec. 3171.25 Abandonment.
In accordance with the requirements of 43 CFR 3162.3-4, before
starting abandonment operations the operator must submit a Notice of
Intent to Abandon on Sundry Notices and Reports on Wells, Form 3160-5.
If the operator proposes to modify the plans for surface reclamation
approved at the APD stage, the operator must attach these modifications
to the Notice of Intent to Abandon.
(a) Plugging. The operator must obtain BLM approval for the
plugging of the well by submitting a Notice of Intent to Abandon. In
the case of dry holes, drilling failures, and in emergency situations,
verbal approval for plugging may be obtained from the BLM, with the
Notice of Intent to Abandon promptly submitted as written
documentation. Within 30 days following completion of well plugging,
the operator must file with the BLM a Subsequent Report of Plug and
Abandon, using Sundry Notices and Reports on Wells, Form 3160-5. For
depleted production wells, the operator must submit a Notice of Intent
to Abandon and obtain the BLM's approval before plugging.
(b) Reclamation. Plans for surface reclamation are a part of the
Surface Use Plan of Operations, as specified in Sec. 3171.8(e)(10),
and must be designed to return the disturbed area to productive use and
to meet the objectives of the land and resource management plan. If the
operator proposes to modify the plans for surface reclamation approved
at the APD stage, the operator must attach these modifications to the
Subsequent Report of Plug and Abandon using Sundry Notices and Reports
on Wells, Form 3160-5.
(1) For wells not having an approved plan for surface reclamation,
operators must submit to the BLM a proposal describing the procedures
to be followed for complete abandonment, including a map showing the
disturbed area and roads to be reclaimed. The BLM will forward the
request to the FS or other surface managing agency. If applicable, the
private surface owner will be notified and their views will be
carefully considered.
(2) Earthwork for interim and final reclamation must be completed
within 6 months of well completion or well plugging (weather
permitting). All pads, pits, and roads must be reclaimed to a
satisfactorily revegetated, safe, and stable condition, unless an
agreement is made with the landowner or surface managing agency to keep
the road or pad in place. Pits containing fluid must not be breached
(cut) and pit fluids must be removed or solidified before backfilling.
Pits may be allowed to air dry subject to BLM or FS approval, but the
use of chemicals to aid in fluid evaporation, stabilization, or
solidification must have prior BLM or FS approval. Seeding or other
activities to reestablish vegetation must be completed within the time
period approved by the BLM or the FS.
(3) Upon completion of reclamation operations, the lessee or
operator must notify the BLM or the FS using Form 3160-5, Final
Abandonment Notice, when the location is ready for inspection. Final
abandonment will not be approved until the surface reclamation work
required in the Surface Use Plan of Operations or Subsequent Report of
Plug and Abandon has been completed to the satisfaction of the BLM or
the FS and surface managing agency, if appropriate.
Sec. 3171.26 Appeal procedures.
(a) Complete information concerning the review and appeal processes
for BLM actions is contained in 43 CFR parts 4 and 3160, subpart 3165.
Incorporation of a FS approved Surface Use Plan of Operations into the
approval of an APD or a Master Development Plan is not subject to
protest to the BLM or appeal to the Interior Board of Land Appeals.
(b) The FS's decisions approving use of NFS lands may be subject to
agency appeal procedures, in accordance with 36 CFR part 215 or 251.
(c) Decisions governing Surface Use Plan of Operations and Special
Use Authorization approvals on NFS lands that involve analysis,
documentation, and other requirements of the NEPA may be subject to
agency appeal procedures, under 36 CFR part 215.
(d) The FS's regulations at 36 CFR part 251 govern appeals by an
operator of written FS decisions related to Conditions of Approval or
administration of Surface Use Plans of Operations or Special Use
Authorizations to occupy and use NFS lands.
(e) The operator may appeal decisions of the BIA under 25 CFR part
2.
Appendix A to Subpart 3171--Sample Format for Notice of Staking
(Not to be used in place of Application for Permit to Drill or
Reenter Form 3160-3)
1. Oil Well
Gas Well
Other (Specify)
2. Name, Address, and Telephone of Operator
3. Name and Telephone of Specific Contact Person
4. Surface Location of Well
Attach:
(a) Sketch showing road entry onto pad, pad dimensions, and
reserve pit
(b) Topographical or other acceptable map (e.g., a USGS 7-\1/
2\'' Quadrangle) showing location, access road, and lease boundaries
5. Lease Number
6. If Indian, Allottee or Tribe Name
7. Unit Agreement Name
8. Well Name and Number
9. American Petroleum Institute (API) Well Number (if available)
10. Field Name or Wildcat
11. Section, Township, Range, Meridian; or Block and Survey; or Area
12. County, Parish, or Borough
13. State
14. Name and Depth of Formation Objective(s)
15. Estimated Well Depth
16. For directional or horizontal wells, anticipated bottom-hole
location.
17. Additional Information (as appropriate; include surface owner's
name, address and, if known, telephone).
18. Signed-------------------------------------------------------------
Title------------------------------------------------------------------
Date-------------------------------------------------------------------
Note: When the Bureau of Land Management or the Forest Service,
as appropriate, receives this Notice, the agency will schedule the
date of the onsite inspection. You must stake the location and flag
the access road before the onsite inspection. Operators should
consider the following before the onsite inspection and incorporate
these considerations into the Notice of Staking Option, as
appropriate:
(a) H<INF>2</INF>S Potential;
(b) Cultural Resources (Archeology); and
(c) Federal Right-of-Way or Special Use Permit.
Subpart 3172--Drilling Operations on Federal and Indian Oil and Gas
Leases
Sec.
3172.1 Authority.
3172.2 Purpose.
3172.3 Scope.
3172.4 General.
3172.5 Definitions.
3172.6 Well control.
3172.7 Casing and cementing.
3172.8 Mud program.
3172.9 Drill stem testing.
3172.10 Special drilling operations.
3172.11 Surface use.
3172.12 Drilling abandonment.
[[Page 39527]]
3172.13 Variances from minimum standards.
Appendix A to Subpart 3172--Diagrams of Choke Manifold Requirements
Sec. 3172.1 Authority.
(a) This subpart is established pursuant to the authority granted
to the Secretary of the Interior pursuant to various Federal and Indian
mineral leasing statutes and the Federal Oil and Gas Royalty Management
Act of 1982. This authority has been delegated to the Bureau of Land
Management and is implemented by the onshore oil and gas operating
regulations contained in 43 CFR part 3160.
(b) Specific authority for the provisions contained in this subpart
is found at: 43 CFR 3162.3-1, 3162.3-4, 3162.4-1, 3162.4-3, 3162.5-1,
3162.5-2 (see paragraph (a)), and 3162.5-3; and 43 CFR part 3160,
subpart 3163.
Sec. 3172.2 Purpose.
This subpart details the Bureau's uniform national standards for
the minimum levels of performance expected from lessees and operators
when conducting drilling operations on Federal and Indian lands (except
Osage Tribe) and for abandonment immediately following drilling. The
purpose also is to identify the enforcement actions that will result
when violations of the minimum standards are found, and when those
violations are not abated in a timely manner.
Sec. 3172.3 Scope.
This subpart is applicable to all onshore Federal and Indian
(except Osage Tribe) oil and gas leases.
Sec. 3172.4 General.
(a) If an operator chooses to use higher rated equipment than that
authorized in the Application for Permit to Drill (APD), testing
procedures shall apply to the approved working pressures, not the
upgraded higher working pressures.
(b) Some situations may exist either on a well-by-well or field-
wide basis whereby it is commonly accepted practice to vary a
particular minimum standard(s) established in this subpart. This
situation may be resolved by requesting a variance (see Sec. 3172.13),
by the inclusion of a stipulation to the APD, or by the issuance of a
Notice to Lessees and Operators (NTL) by the appropriate BLM office.
(c) When a violation is discovered, and if it does not cause or
threaten immediate substantial and adverse impact on public health and
safety, the environment, production accountability or royalty income,
it will be classified as minor. The violation may be reissued as a
major violation if not corrected during the abatement period and
continued drilling has changed the adverse impact of the violation so
that it meets the specific definition of a major violation.
(d) This subpart is not intended to circumvent the reporting
requirements or compliance aspects that may be stated elsewhere in
existing NTLs, regulations, etc. A lessee's compliance with the
requirements of the regulations in this subpart shall not relieve the
lessee of the obligation to comply with other applicable laws and
regulations in accordance with 43 CFR 3162.5-1(c). Lessees should give
special attention to the automatic assessment provisions in 43 CFR
3163.1(b).
(e) This subpart is based upon the assumption that operations have
been approved in accordance with 43 CFR part 3160 and subpart 3171 of
this part. Failure to obtain approval prior to commencement of drilling
or related operations shall subject the operator to immediate
assessment under 43 CFR 3163.1(b)(2).
Sec. 3172.5 Definitions.
As used in this subpart, the term:
2M, 3M, 5M, 10M, and 15M mean the pressure ratings used for
equipment with a working pressure rating of the equivalent thousand
pounds per square inch (psi) (2M=2,000 psi, 3M=3,000 psi, etc.).
Abnormal pressure zone means a zone that has either pressure above
or below the normal gradient for an area and/or depth.
Bleed line means the vent line that bypasses the chokes in the
choke manifold system; also referred to as panic line.
Blooie line means a discharge line used in conjunction with a
rotating head.
Drilling spool means a connection component with both ends either
flanged or hubbed, with an internal diameter at least equal to the bore
of the casing, and with smaller side outlets for connecting auxiliary
lines.
Exploratory well means any well drilled beyond the known producing
limits of a pool.
Fill-up line means the line used to fill the hole when the drill
pipe is being removed from the well. It is usually connected to a 2-
inch collar that is welded into a drilling nipple.
Flare line means a line used to carry gas away from the rig to be
burned at a safer location. The gas comes from the degasser, gas
buster, separator, or when drill stem testing, directly from the drill
pipe.
Functionally operated means activating equipment without subjecting
it to well-bore pressure.
Isolating means using cement to protect, separate, or segregate
usable water and mineral resources.
Lease means any contract, profit-share agreement, joint venture, or
other agreement issued or approved by the United States under a mineral
leasing law that authorizes exploration for, extraction of, or removal
of oil or gas (see 43 CFR 3160.0-5).
Lessee means a person holding record title in a lease issued by the
United States (see 43 CFR 3160.0-5).
Make-up water means water that is used in mixing slurry for cement
jobs and plugging operations and is compatible with the cement
constituents being used.
Manual locking device means any manually activated device, such as
a hand wheel, etc., that is used for the purpose of locking the
preventer in the closed position.
Mud for plugging purposes means a slurry of bentonite or similar
flocculent/viscosifier, water, and additives needed to achieve the
desired weight and consistency to stabilize the hole.
Mudding up means adding materials and chemicals to water to control
the viscosity, weight, and filtrate loss of the circulating system.
Operating rights owner (or owner) means a person or entity holding
operating rights in a lease issued by the United States. A lessee also
may be an operating rights owner if the operating rights in a lease or
portion thereof have not been severed from record title.
Operational means capable of functioning as designed and installed
without undue force or further modification.
Operator means any person or entity, including but not limited to
the lessee or operating rights owner, who has stated in writing to the
authorized officer his/her responsibility for the operations conducted
in the leased lands or a portion thereof.
Precharge pressure means the nitrogen pressure remaining in the
accumulator after all the hydraulic fluid has been expelled from
beneath the movable barrier.
Prompt correction means immediate correction of violations, with
drilling suspended if required in the discretion of the authorized
officer.
Prospectively valuable deposit of minerals means any deposit of
minerals that the authorized officer determines to have characteristics
of quantity and quality that warrant its protection.
Tagging the plug means running in the hole with a string of tubing
or drill
[[Page 39528]]
pipe and placing sufficient weight on the plug to ensure its integrity.
Other methods of tagging the plug may be approved by the authorized
officer.
Targeted tee or turn means a fitting used in pressure piping in
which a bull plug or blind flange of the same pressure rating as the
rest of the approved system is installed at the end of a tee or cross,
opposite the fluid entry arm, to change the direction of flow and to
reduce erosion.
Usable water means generally those waters containing up to 10,000
parts per million (ppm) of total dissolved solids.
Weep hole means a small hole that allows pressure to bleed off
through the metal plate used in covering well bores after abandonment
operations.
Sec. 3172.6 Well control.
(a) Requirements. Blowout preventer (BOP) and related equipment
(BOPE) shall be installed, used, maintained, and tested in a manner
necessary to assure well control and shall be in place and operational
prior to drilling the surface casing shoe unless otherwise approved by
the APD. Commencement of drilling without the approved BOPE installed,
unless otherwise approved, shall subject the operator to immediate
assessment under 43 CFR 3163.1(b)(1). The BOP and related control
equipment shall be suitable for operations in those areas which are
subject to sub-freezing conditions. The BOPE shall be based on known or
anticipated sub-surface pressures, geologic conditions, accepted
engineering practice, and surface environment. Item number 7 of the 8
point plan in the APD specifically addresses expected pressures. The
working pressure of all BOPE shall exceed the anticipated surface
pressure to which it may be subjected, assuming a partially evacuated
hole with a pressure gradient of 0.22 psi/ft.
(b) Violation classifications. The gravity of the violation for
many of the well control minimum standards listed in paragraphs (b)(1)
through (9) of this section are shown as minor. However, very short
abatement periods in this subpart are often specified in recognition
that by continuing to drill, the violation which was originally
determined to be of a minor nature may cause or threaten immediate,
substantial, and adverse impact on public health and safety, the
environment, production accountability, or royalty income, which would
require it reclassification as a major violation.
(1) Minimum standards and enforcement provisions for well control
equipment. (i) A well control device shall be installed at the surface
that is capable of complete closure of the well bore. This device shall
be closed whenever the well is unattended.
Table 1 to Sec. 3172.6(b)(1)(i)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Major....................... Install the Prompt correction
equipment as required.
specified.
------------------------------------------------------------------------
(ii) For 2M system:
(A) Annular preventer, double ram, or two rams with one being blind
and one being a pipe ram (major);
(B) Kill line (2 inch minimum);
(C) 1 kill line valve (2 inch minimum);
(D) 1 choke line valve;
(E) 2 chokes (refer to diagram in appendix A to this subpart);
(F) Upper kelly cock valve with handle available;
(G) Safety valve and subs to fit all drill strings in use;
(H) Pressure gauge on choke manifold;
(I) 2 inch minimum choke line; and
(J) Fill-up line above the uppermost preventer.
Table 2 to Sec. 3172.6(b)(1)(ii)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Install the 24 hours.
equipment as
specified.
Major (as indicated)........ Install the Prompt correction
equipment as required.
specified.
------------------------------------------------------------------------
(iii) For 3M system:
(A) Annular preventers (major);
(B) Double ram with blind rams and pipe rams (major);
(C) Drilling spool, or blowout preventer with 2 side outlets (choke
side shall be a 3-inch minimum diameter, kill side shall be at least 2-
inch diameter) (major);
(D) Kill line (2 inch minimum);
(E) A minimum of 2 choke line valves (3 inch minimum) (major);
(F) 3 inch diameter choke line;
(G) 2 kill line valves, one of which shall be a check valve (2 inch
minimum) (major);
(H) 2 chokes (refer to diagram in appendix A to this subpart);
(I) Pressure gauge on choke manifold;
(J) Upper kelly cock valve with handle available;
(K) Safety valve and subs to fit all drill string connections in
use;
(L) All BOPE connections subjected to well pressure shall be
flanged, welded, or clamped (major); and
(M) Fill-up line above the uppermost preventer.
Table 3 to Sec. 3172.6(b)(1)(iii)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Install the 24 hours.
equipment as
specified.
Major (as indicated)........ Install the Prompt correction
equipment as required.
specified.
------------------------------------------------------------------------
(iv) For 5M system:
(A) Annular preventer (major);
(B) Pipe ram, blind ram, and, if conditions warrant, as specified
by the authorized officer, another pipe ram shall also be required
(major);
[[Page 39529]]
(C) A second pipe ram preventer or variable bore pipe ram preventer
shall be used with a tapered drill string;
(D) Drilling spool, or blowout preventer with 2 side outlets (choke
side shall be a 3-inch minimum diameter, kill side shall be at least 2-
inch diameter) (major);
(E) 3 inch diameter choke line;
(F) 2 choke line valves (3 inch minimum) (major);
(G) Kill line (2 inch minimum);
(H) 2 chokes with 1 remotely controlled from rig floor (refer to
diagram in appendix A to this subpart);
(I) 2 kill line valves and a check valve (2 inch minimum) (major);
(J) Upper kelly cock valve with a handle available;
(K) When the expected pressures approach working pressure of the
system, 1 remote kill line tested to stack pressure (which shall run to
the outer edge of the substructure and be unobstructed);
(L) Lower kelly cock valve with handle available;
(M) Safety valve(s) and subs to fit all drill string connections in
use;
(N) Inside BOP or float sub available;
(O) Pressure gauge on choke manifold;
(P) All BOPE connections subjected to well pressure shall be
flanged, welded, or clamped (major); and
(Q) Fill-up line above the uppermost preventer.
Table 4 to Sec. 3172.6(b)(1)(iv)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Install the 24 hours.
equipment as
specified.
Major (as indicated)........ Install the Prompt correction
equipment as required.
specified.
------------------------------------------------------------------------
(v) For 10M & 15M system:
(A) Annular preventer (major);
(B) 2 pipe rams (major);
(C) Blind rams (major);
(D) Drilling spool, or blowout preventer with 2 side outlets (choke
side shall be a 3-inch minimum diameter, kill side shall be at least 2-
inch diameter) (major):
(E) 3 inch choke line (major);
(F) 2 kill line valves (2 inch minimum) and check valve (major):
(G) Remote kill line (2 inch minimum) shall run to the outer edge
of the substructure and be unobstructed;
(H) Manual and hydraulic choke line valves (3 inch minimum)
(major);
(I) 3 chokes, 1 being remotely controlled (refer to diagram in
appendix A to this subpart);
(J) Pressure gauge on choke manifold;
(K) Upper kelly cock valve with handle available;
(L) Lower kelly cock valve with handle available;
(M) Safety valves and subs to fit all drill string connections in
use;
(N) Inside BOP or float sub available;
(O) Wear ring in casing head;
(P) All BOPE connections subjected to well pressure shall be
flanged, welded, or clamped (major); and
(Q) Fill-up line installed above the uppermost preventer.
Table 5 to Sec. 3172.6(b)(1)(v)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Install the 24 hours.
equipment as
specified.
Major (as indicated)........ Install the Prompt correction
equipment as required.
specified.
------------------------------------------------------------------------
(vi) If repair or replacement of the BOPE is required after
testing, this work shall be performed prior to drilling out the casing
shoe.
Table 6 to Sec. 3172.6(b)(1)(vi)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Major....................... Install the Prompt correction
equipment as required.
specified.
------------------------------------------------------------------------
(vii) When the BOPE cannot function to secure the hole, the hole
shall be secured using cement, retrievable packer or a bridge plug
packer, bridge plug, or other acceptable approved method to assure safe
well conditions.
Table 7 to Sec. 3172.6(b)(1)(vii)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Major....................... Install the Prompt correction
equipment as required.
specified.
------------------------------------------------------------------------
(2) Minimum standards and enforcement provisions for choke manifold
equipment. (i) All choke lines shall be straight lines unless turns use
tee blocks or are targeted with running tees, and shall be anchored to
prevent whip and reduce vibration.
[[Page 39530]]
Table 8 to Sec. 3172.6(b)(2)(i)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Install the 24 hours.
equipment as
specified.
------------------------------------------------------------------------
(ii) Choke manifold equipment configuration shall be functionally
equivalent to the appropriate example diagram shown in appendix A of
this subpart. The configuration of the chokes may vary.
Table 9 to Sec. 3172.6(b)(2)(ii)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Install the Prompt correction
equipment as required.
specified.
------------------------------------------------------------------------
(iii) All valves (except chokes) in the kill line, choke manifold,
and choke line shall be a type that does not restrict the flow (full
opening) and that allows a straight through flow (same enforcement as
paragraph (b)(2)(ii) of this section).
(iv) Pressure gauges in the well control system shall be a type
designed for drilling fluid service (same enforcement as paragraph
(b)(2)(ii) of this section).
(3) Minimum standards and enforcement provisions for pressure
accumulator system. (i) 2M system--accumulator shall have sufficient
capacity to close all BOP's and retain 200 psi above precharge.
Nitrogen bottles that meet manufacturer's specifications may be used as
the backup to the required independent power source.
Table 10 to Sec. 3172.6(b)(3)(i)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Install the 24 hours.
equipment as
specified.
------------------------------------------------------------------------
(ii) 3M system--accumulator shall have sufficient capacity to open
the hydraulically controlled choke line valve (if so equipped), close
all rams plus the annual preventer, and retain a minimum of 200 psi
above precharge on the closing manifold without the use of the closing
unit pumps. This is a minimum requirement. The fluid reservoir capacity
shall be double the usable fluid volume of the accumulator system
capacity and the fluid level of the reservoir shall be maintained at
the manufacturer's recommendations. The 3M system shall have 2
independent power sources to close the preventers. Nitrogen bottles (3
minimum) may be 1 of the independent power sources and, if so, shall
maintain a charge equal to the manufacturer's specifications.
Table 11 to Sec. 3172.6(b)(3)(ii)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Install the 24 hours.
equipment as
specified.
------------------------------------------------------------------------
(iii) 5M and higher system--accumulator shall have sufficient
capacity to open the hydraulically controlled gate valve (if so
equipped) and close all rams plus the annular preventer (for 3 ram
systems add a 50 percent safety factor to compensate for any fluid loss
in the control system or preventers) and retain a minimum pressure of
200 psi above precharge on the closing manifold without use of the
closing unit pumps. The fluid reservoir capacity shall be double the
usable fluid volume of the accumulator system capacity and the fluid
level of the reservoir shall be maintained at the manufacturer's
recommendations. Two independent sources of power shall be available
for powering the closing unit pumps. Sufficient nitrogen bottles are
suitable as a backup power source only, and shall be recharged when the
pressure falls below manufacturer's specifications.
Table 12 to Sec. 3172.6(b)(3)(iii)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Install the 24 hours.
equipment as
specified.
------------------------------------------------------------------------
(4) Minimum standards and enforcement provisions for accumulator
precharge pressure test. This test shall be conducted prior to
connecting the closing unit to the BOP stack and at least once every 6
months. The accumulator pressure shall be corrected if the measured
precharge pressure is found to be above or below the maximum or minimum
limit specified in table 13 to this paragraph (b)(4) (only nitrogen gas
may be used to precharge):
[[Page 39531]]
Table 13 to Sec. 3172.6(b)(4)
----------------------------------------------------------------------------------------------------------------
Accumulator working Minimum acceptable Maximum acceptable Minimum acceptable
pressure rating operating pressure Desired precharge precharge pressure precharge pressure
(psi) (psi) pressure (psi) (psi) (psi)
----------------------------------------------------------------------------------------------------------------
1,500 1,500 750 800 700
2,000 2,000 1,000 1,100 900
3,000 3,000 1,000 1,100 900
----------------------------------------------------------------------------------------------------------------
Table 14 to Sec. 3172.6(b)(4)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Perform test........ 24 hours.
------------------------------------------------------------------------
(5) Minimum standards and enforcement provisions for power
availability. Power for the closing unit pumps shall be available to
the unit at all times so that the pumps shall automatically start when
the closing unit manifold pressure has decreased to a pre-set level.
Table 15 to Sec. 3172.6(b)(5)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Major....................... Install the Prompt correction
equipment as required.
specified.
------------------------------------------------------------------------
(6) Minimum standards and enforcement provisions for accumulator
pump capacity. Each BOP closing unit shall be equipped with sufficient
number and sizes of pumps so that, with the accumulator system isolated
from service, the pumps shall be capable of opening the hydraulically
operated gate valve (if so equipped), plus closing the annular
preventer on the smallest size drill pipe to be used within 2 minutes,
and obtain a minimum of 200 psi above specified accumulator precharge
pressure.
Table 16 to Sec. 3172.6(b)(6)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Install the 24 hours.
equipment as
specified.
------------------------------------------------------------------------
(7) Minimum standards and enforcement provisions for locking
devices. A manual locking device (i.e., hand wheels) or automatic
locking devices shall be installed on all systems of 2M or greater. A
valve shall be installed in the closing line as close as possible to
the annular preventer to act as a locking device. This valve shall be
maintained in the open position and shall be closed only when the power
source for the accumulator system is inoperative.
Table 17 to Sec. 3172.6(b)(7)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Install the 24 hours.
equipment as
specified.
------------------------------------------------------------------------
(8) Minimum standards and enforcement provisions for remote
controls. Remote controls shall be readily accessible to the driller.
Remote controls for all 3M or greater systems shall be capable of
closing all preventers. Remote controls for 5M or greater systems shall
be capable of both opening and closing all preventers. Master controls
shall be at the accumulator and shall be capable of opening and closing
all preventers and the choke line valve (if so equipped). No remote
control for a 2M system is required.
Table 18 to Sec. 3172.6(b)(8)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Install the 24 hours.
equipment as
specified.
------------------------------------------------------------------------
(9) Minimum standards and enforcement provisions for well control
equipment testing. (i) Perform all tests described in paragraphs
(b)(9)(ii) through (x) of this section using clear water or an
appropriate clear liquid for
[[Page 39532]]
subfreezing temperatures with a viscosity similar to water.
(ii) Ram type preventers and associated equipment shall be tested
to approved (see Sec. 3172.4(a)) stack working pressure if isolated by
test plug or to 70 percent of internal yield pressure of casing if BOP
stack is not isolated from casing. Pressure shall be maintained for at
least 10 minutes or until requirements of test are met, whichever is
longer. If a test plug is utilized, no bleed-off of pressure is
acceptable. For a test not utilizing a test plug, if a decline in
pressure of more than 10 percent in 30 minutes occurs, the test shall
be considered to have failed. Valve on casing head below test plug
shall be open during test of BOP stack.
(iii) Annular type preventers shall be tested to 50 percent of
rated working pressure. Pressure shall be maintained at least 10
minutes or until provisions of test are met, whichever is longer.
(iv) As a minimum, the test in paragraph (b)(9)(iii) of this
section shall be performed:
(A) When initially installed;
(B) Whenever any seal subject to test pressure is broken;
(C) Following related repairs; and
(D) At 30-day intervals.
(v) Valves shall be tested from working pressure side during BOPE
tests with all down stream valves open.
(vi) When testing the kill line valve(s), the check valve shall be
held open or the ball removed.
(vii) Annular preventers shall be functionally operated at least
weekly.
(viii) Pipe and blind rams shall be activated each trip, however,
this function need not be performed more than once a day.
(ix) A BOPE pit level drill shall be conducted weekly for each
drilling crew.
(x) Pressure tests shall apply to all related well control
equipment.
(xi) All of the tests described in paragraphs (b)(1)(ii) through
(x) of this section and/or drills shall be recorded in the drilling
log.
Table 19 to Sec. 3172.6(b)(9)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Perform the 24 hours or next
necessary test or trip, as most
provide appropriate.
documentation.
------------------------------------------------------------------------
Sec. 3172.7 Casing and cementing.
(a) Requirements. The proposed casing and cementing programs shall
be conducted as approved to protect and/or isolate all usable water
zones, potentially productive zones, lost circulation zones, abnormally
pressured zones, and any prospectively valuable deposits of minerals.
Any isolating medium other than cement shall receive approval prior to
use. The casing setting depth shall be calculated to position the
casing seat opposite a competent formation which will contain the
maximum pressure to which it will be exposed during normal drilling
operations. Determination of casing setting depth shall be based on all
relevant factors, including: presence/absence of hydrocarbons; fracture
gradients; usable water zones; formation pressures; lost circulation
zones; other minerals; or other unusual characteristics. All
indications of usable water shall be reported.
(1) Minimum design factors for tensions, collapse, and burst that
are incorporated into the casing design by an operator/lessee shall be
submitted to the authorized operator for his review and approval along
with the APD for all exploratory wells or as otherwise specified by the
authorized officer.
(2) Casing design shall assume formation pressure gradients of 0.44
to 0.50 psi per foot for exploratory wells (lacking better data).
(3) Casing design shall assume fracture gradients from 0.70 to 1.00
psi per foot for exploratory wells (lacking better data).
(4) Casing collars shall have a minimum clearance of 0.422 inches
on all sides in the hole/casing annulus, with recognition that
variances can be granted for justified exceptions.
(5) All waiting on cement times shall be adequate to achieve a
minimum of 500 psi compressive strength at the casing shoe prior to
drilling out.
(b) Minimum standards and enforcement provisions for casing and
cementing. (1) All casing, except the conductor casing, shall be new or
reconditioned and tested casing. All casing shall meet or exceed
American Petroleum Institute (API) standards for new casing. The use of
reconditioned and tested used casing shall be subject to approval by
the authorized officer: approval will be contingent upon the wall
thickness of any such casing being verified to be at least 87\1/2\
percent of the nominal wall thickness of new casing.
Table 1 to Sec. 3172.7(b)(1)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Major....................... Perform remedial Prompt correction
action as specified required.
by the authorized
officer.
------------------------------------------------------------------------
(2) For liners, a minimum of 100 feet of overlap between a string
of casing and the next larger casing is required. The interval of
overlap shall be sealed and tested. The liner shall be tested by a
fluid entry or pressure test to determine whether a seal between the
liner top and next larger string has been achieved. The test pressure
shall be the maximum anticipated pressure to which the seal will be
exposed. No test shall be required for liners that do not incorporate
or need a seal mechanism.
Table 2 to Sec. 3172.7(b)(2)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Perform remedial Upon determination
action as specified of corrective
by the authorized action.
officer.
------------------------------------------------------------------------
[[Page 39533]]
(3) The surface casing shall be cemented back to surface either
during the primary cement job or by remedial cementing.
Table 3 to Sec. 3172.7(b)(3)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Major....................... Perform remedial Prompt correction
cementing. required.
------------------------------------------------------------------------
(4) All of the tests described in paragraphs (b)(1) through (3) of
this section shall be recorded in the drilling log.
Table 4 to Sec. 3172.7(b)(4)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Perform the 24 hours.
necessary test or
provide
documentation.
------------------------------------------------------------------------
(5) All indications of usable water shall be reported to the
authorized officer prior to running the next string of casing or before
plugging orders are requested, whichever occurs first.
Table 5 to Sec. 3172.7(b)(5)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Major....................... Report information Prompt correction
as required. required.
------------------------------------------------------------------------
(6) Surface casing shall have centralizers on the bottom 3 joints
of the casing (a minimum of 1 centralizer per joint, starting with the
shoe joint).
Table 6 to Sec. 3172.7(b)(6)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Major....................... Logging/testing may Prompt correction
be required to upon determination
determine the of corrective
quality of the job. action.
Recementing may
then be specified.
------------------------------------------------------------------------
(7) Top plugs shall be used to reduce contamination of cement by
displacement fluid. A bottom plug or other acceptable technique, such
as a suitable preflush fluid, inner string cement method, etc., shall
be utilized to help isolate the cement from contamination by the mud
fluid being displaced ahead of the cement slurry.
Table 7 to Sec. 3172.7(b)(7)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Major....................... Logging may be Based upon
required to determination of
determine the corrective action.
quality of the
cement job.
Recementing or
further recementing
may then be
specified.
------------------------------------------------------------------------
(8) All casing strings below the conductor shall be pressure tested
to 0.22 psi per foot of casing string length or 1,500 psi, whichever is
greater, but not to exceed 70 percent of the minimum internal yield. If
pressure declines more than 10 percent in 30 minutes, corrective action
shall be taken.
Table 8 to Sec. 3172.7(b)(8)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Perform the test and/ 24 hours.
or remedial action
as specified by the
authorized officer.
------------------------------------------------------------------------
(9) On all exploratory wells, and on that portion of any well
approved for a 5M BOPE system or greater, a pressure integrity test of
each casing shoe shall be performed. Formation at the shoe shall be
tested to a minimum of the mud weight equivalent anticipated to control
the formation pressure to the next casing depth or at total depth of
the
[[Page 39534]]
well. This test shall be performed before drilling more than 20 feet of
new hole.
Table 9 to Sec. 3172.7(b)(9)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Perform the 24 hours.
specified test.
------------------------------------------------------------------------
Sec. 3172.8 Mud program.
(a) Requirements. The characteristics, use, and testing of drilling
mud and the implementation of related drilling procedures shall be
designed to prevent the loss of well control. Sufficient quantities of
mud materials shall be maintained or readily accessible for the purpose
of assuring well control.
(b) Minimum standards and enforcement provisions for mud program
and equipment. (1) Record slow pump speed on daily drilling report
after mudding up.
Table 1 to Sec. 3172.8(b)(1)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Record required 24 hours.
information.
------------------------------------------------------------------------
(2) Visual mud monitoring equipment shall be in place to detect
volume changes indicating loss or gain of circulating fluid volume.
Table 2 to Sec. 3172.8(b)(2)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Install necessary 24 hours.
equipment.
------------------------------------------------------------------------
(3) When abnormal pressures are anticipated, electronic/mechanical
mud monitoring equipment shall be required, which shall include as a
minimum: pit volume totalizer (PVT); stroke counter; and flow sensor.
Table 3 to Sec. 3172.8(b)(3)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Install necessary 24 hours.
instrumentation.
------------------------------------------------------------------------
(4) A mud test shall be performed every 24 hours after mudding up
to determine, as applicable: density, viscosity, gel strength,
filtration, and pH.
Table 4 to Sec. 3172.8(b)(4)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Perform necessary 24 hours.
tests.
------------------------------------------------------------------------
(5) A trip tank shall be used on 10M and 15M systems and on
upgraded 5M systems as determined by the authorized officer.
Table 5 to Sec. 3172.8(b)(5)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Install necessary 24 hours.
equipment.
------------------------------------------------------------------------
(6)(i) Gas detecting equipment shall be installed in the mud return
system for exploratory wells or wells where abnormal pressure is
anticipated, and hydrocarbon gas shall be monitored for pore pressure
changes.
(ii) Hydrogen sulfide safety and monitoring equipment requirements
may be found in subpart 3176 of this part.
[[Page 39535]]
Table 6 to Sec. 3172.8(b)(6)(ii)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Install necessary 24 hours.
equipment.
------------------------------------------------------------------------
(7) All flare systems shall be designed to gather and burn all gas.
The flare line(s) discharge shall be located not less than 100 feet
from the well head, having straight lines unless turns are targeted
with running tees, and shall be positioned downwind of the prevailing
wind direction and shall be anchored. The flare system shall have an
effective method for ignition. Where noncombustible gas is likely or
expected to be vented, the system shall be provided supplemental fuel
for ignition and to maintain a continuous flare.
Table 6 to Sec. 3172.8(b)(7)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Major....................... Install equipment as 24 hours.
specified.
------------------------------------------------------------------------
(8) A mud-gas separator (gas buster) shall be installed and
operable for all systems of 10M or greater and for any system where
abnormal pressure is anticipated beginning at a point at least 500 feet
above any anticipated hydrocarbon zone of interest.
Table 8 to Sec. 3172.8(b)(8)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Install required Prompt correction
equipment. required.
------------------------------------------------------------------------
Sec. 3172.9 Drill stem testing.
(a) Requirements. Initial opening of drill stem test tools shall be
restricted to daylight hours unless specific approval to start during
other hours is obtained from the authorized officer. However, drill
stem tests (DSTs) may be allowed to continue at night if the test was
initiated during daylight hours and the rate of flow is stabilized and
if adequate lighting is available (i.e., lighting which is adequate for
visibility and vapor-proof for safe operations). Packers can be
released, but tripping shall not begin before daylight, unless prior
approval is obtained from the authorized officer. Closed chamber DSTs
may be accomplished day or night.
(b) Minimum standards for drill stem testing. (1) A DST that flows
to the surface with evidence of hydrocarbons shall be either reversed
out of the testing string under controlled surface conditions, or
displaced into the formation prior to pulling the test tool. This would
involve providing some means for reserve circulation.
Table 1 to Sec. 3172.9(b)(1)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Major....................... Contingent on Prompt correction
circumstances and required.
as specified by the
authorized officer.
------------------------------------------------------------------------
(2) Separation equipment required for the anticipated recovery
shall be properly installed before a test starts.
Table 2 to Sec. 3172.9(b)(2)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Major....................... Install required Prompt correction
equipment. required.
------------------------------------------------------------------------
(3) All engines within 100 feet of the wellbore that are required
to ``run'' during the test shall have spark arresters or water-cooled
exhausts.
Table 3 to Sec. 3172.9(b)(3)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Major....................... Install required Prompt correction
equipment. required.
------------------------------------------------------------------------
[[Page 39536]]
Sec. 3172.10 Special drilling operations.
(a) In addition to the equipment already specified elsewhere in
this subpart, the following equipment shall be in place and operational
during air/gas drilling:
(1) Properly lubricated and maintained rotating head (major);
(2) Spark arresters on engines or water-cooled exhaust (major);
(3) Blooie line discharge 100 feet from well bore and securely
anchored;
(4) Straight run on blooie line unless otherwise approved;
(5) Deduster equipment (major);
(6) All cuttings and circulating medium shall be directed into a
reserve or blooie pit (major);
(7) Float valve above bit (major);
(8) Automatic igniter or continuous pilot light on the blooie line
(major);
(9) Compressors located in the opposite direction from the blooie
line a minimum of 100 feet from the well bore; and
(10) Mud circulating equipment, water, and mud materials (does not
have to be premixed) sufficient to maintain the capacity of the hole
and circulating tanks or pits.
Table 1 to Sec. 3172.10(a)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Install the 24 hours.
equipment as
specified.
Major (as indicated)........ Install the Prompt correction
equipment as required.
specified.
------------------------------------------------------------------------
(b) Hydrogen sulfide operation is specifically addressed under
subpart 3176 of this part.
Sec. 3172.11 Surface use.
(a) Responsibilities. Subpart 3171 of this part specifically
addresses surface use. Subpart 3171 provides for safe operations,
adequate protection of surface resources and uses, and other
environmental components. The operator/lessee is responsible for, and
liable for, all building, construction, and operating activities and
subcontracting activities conducted in association with the APD.
Requirements and special stipulations for surface use are contained in
or attached to the approved APD.
(b) Minimum standards and enforcement provisions for surface use.
The requirements and stipulations of approval shall be strictly adhered
to by the operator/lessee and any contractors.
(c) Violation. If a violation is identified by the authorized
officer he shall determine whether it is major or minor, considering
the definitions in 43 CFR 3160.0-5, and shall specify the appropriate
corrective action and abatement period.
Sec. 3172.12 Drilling abandonment.
(a) Requirements. The standards in paragraphs (a)(1) through (11)
of this section apply to the abandonment of newly drilled dry or non-
productive wells in accordance with Sec. 3171.18 and 43 CFR 3162.3-4.
Approval shall be obtained prior to the commencement of abandonment.
All formations bearing usable-quality water, oil, gas, or geothermal
resources, and/or a prospectively valuable deposit of minerals shall be
protected. Approval may be given orally by the authorized officer
before abandonment operations are initiated. This oral request and
approval shall be followed by a written Notice of Intent to Abandon
filed not later than the fifth business day following oral approval.
Failure to obtain approval prior to commencement of abandonment
operations shall result in immediate assessment of under 43 CFR
3163.1(b)(3). The hole shall be in static condition at the time any
plugs are placed (this does not pertain to plugging lost circulation
zones). Within 30 days of completion of abandonment, a subsequent
report of abandonment shall be filed. Plugging design for an
abandonment hole shall include the following:
(1) Open hole. (i) A cement plug shall be placed to extend at least
50 feet below the bottom (except as limited by total depth (TD) or
plugged back total depth (PBTD)), to 50 feet above the top of:
(A) Any zone encountered during drilling which contains fluid or
gas with a potential to migrate; and (B) Any prospectively valuable
deposit of minerals.
(ii) All cement plugs, except the surface plug, shall have
sufficient slurry volume to fill 100 feet of hole, plus an additional
10 percent of slurry for each 1,000 feet of depth.
(iii) No plug, except the surface plug, shall be less than 25 sacks
without receiving specific approval from the authorized officer.
(iv) Extremely thick sections of a single formation may be secured
by placing 100-foot plugs across the top and bottom of the formation,
and in accordance with paragraph (a)(1)(ii) of this section.
(v) In the absence of productive zones or prospectively valuable
deposits of minerals which otherwise require placement of cement plugs,
long sections of open hole shall be plugged at least every 3,000 feet.
Such plugs shall be placed across in-gauge sections of the hole, unless
otherwise approved by the authorized officer.
(2) Cased hole. A cement plug shall be placed opposite all open
perforations and extend to a minimum of 50 feet below (except as
limited by TD or PBTD) to 50 feet above the perforated interval. All
cement plugs, except the surface plug, shall have sufficient slurry
volume to fill 100 feet of hole, plus an additional 10 percent of
slurry for each 1,000 feet of depth. In lieu of the cement plug, a
bridge plug is acceptable, provided:
(i) The bridge plug is set within 50 feet to 100 feet above the
open perforations; (ii) The perforations are isolated from any open
hole below; and (iii) The bridge plug is capped with 50 feet of cement.
If a bailer is used to cap this plug, 35 feet of cement shall be
sufficient.
(3) Casing removed from hole. If any casing is cut and recovered, a
cement plug shall be placed to extend at least 50 feet above and below
the stub. The exposed hole resulting from the casing removal shall be
secured as required in paragraphs (a)(1)(i) and (ii) of this section.
(4) Cement plug. An additional cement plug placed to extend a
minimum of 50 feet above and below the shoe of the surface casing (or
intermediate string, as appropriate).
(5) Annular space. No annular space that extends to the surface
shall be left open to the drilled hole below. If this condition exists,
a minimum of the top 50 feet of annulus shall be plugged with cement.
(6) Isolating medium. Any cement plug which is the only isolating
medium for a fresh water interval or a zone containing a prospectively
valuable deposit of minerals shall be tested by tagging with the drill
string. Any plugs placed where the fluid level will not remain static
also shall be tested by either tagging the plug with the working pipe
string, or pressuring to a minimum
[[Page 39537]]
pump (surface) pressure of 1,000 psi, with no more than a 10 percent
drop during a 15-minute period (cased hole only). If the integrity of
any other plug is questionable, or if the authorized officer has
specific concerns for which he/she orders a plug to be tested, it shall
be tested in the same manner.
(7) Silica sand or silica flour. Silica sand or silica flour shall
be added to cement exposed to bottom hole static temperatures above
230[ordm] F to prevent heat degradation of the cement.
(8) Surface plug. A cement plug of at least 50 feet shall be placed
across all annuluses. The top of this plug shall be placed as near the
eventual casing cutoff point as possible.
(9) Mud. Each of the intervals between plugs shall be filled with
mud of sufficient density to exert hydrostatic pressure exceeding the
greatest formation pressure encountered while drilling such interval.
In the absence of other information at the time plugging is approved, a
minimum mud weight of 9 pounds per gallon shall be specified.
(10) Surface cap. All casing shall be cut-off at the base of the
cellar or 3 feet below final restored ground level (whichever is
deeper). The well bore shall then be covered with a metal plate at
least \1/4\ inch thick and welded in place, or a 4-inch pipe, 10-feet
in length, 4 feet above ground and embedded in cement as specified by
the authorized officer. The well location and identity shall be
permanently inscribed. A weep hole shall be left if a metal plate is
welded in place.
(11) Cellar. The cellar shall be filled with suitable material as
specified by the authorized officer and the surface restored in
accordance with the instructions of the authorized officer.
(b) Minimum standard. All plugging orders shall be strictly adhered
to.
Table 1 to Sec. 3172.12(b)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Major....................... Contingent upon Prompt correction
circumstances. required.
------------------------------------------------------------------------
Sec. 3172.13 Variances from minimum standards.
(a) An operator may request the authorized officer to approve a
variance from any of the minimum standards prescribed in Sec. Sec.
3172.6 through 3172.12. All such requests shall be submitted in writing
to the appropriate authorized officer and provide information as to the
circumstances which warrant approval of the variance(s) requested and
the proposed alternative methods by which the related minimum
standard(s) are to be satisfied. The authorized officer, after
considering all relevant factors, if appropriate, may approve the
requested variance(s) if it is determined that the proposed
alternative(s) meet or exceed the objectives of the applicable minimum
standard(s).
(b) Emergency or other situations of an immediate nature that could
not be reasonably foreseen at the time of APD approval may receive oral
approval. However, such requests shall be followed up by a written
notice filed not later than the fifth business day following oral
approval.
Appendix A to Subpart 3172--Diagrams of Choke Manifold Equipment
BILLING CODE 4331-29-P
Figure 1 to Appendix A to Subpart 3172--2M Choke Manifold Equipment
[[Page 39538]]
[GRAPHIC] [TIFF OMITTED] TR16JN23.000
Figure 2 to Appendix A to Subpart 3172--3M Choke Manifold Equipment
[GRAPHIC] [TIFF OMITTED] TR16JN23.001
[[Page 39539]]
Figure 3 to Appendix A to Subpart 3172--5M Choke Manifold Equipment
[GRAPHIC] [TIFF OMITTED] TR16JN23.002
[[Page 39540]]
Figure 4 to Appendix A to Subpart 3172--10M and 15M Choke Manifold
Equipment
[GRAPHIC] [TIFF OMITTED] TR16JN23.003
BILLING CODE 4331-29-C
0
3. Add subparts 3176 and 3177 to read as follows
Subpart 3176--Onshore Oil and Gas Production: Hydrogen Sulfide
Operations
Sec.
3176.1 Authority.
3176.2 Purpose.
3176.3 Scope.
3176.4 Definitions.
3176.5 Requirements.
3176.6 Applications, approvals, and reports.
3176.7 Public protection.
3176.8 Drilling/completion/workover requirements.
3176.9 Production requirements.
3176.10 Variances from requirements.
3176.11 Incorporation by reference.
Authority: 25 U.S.C. 396d and 2107; 30 U.S.C. 189, 306, 359,
and 1751; and 43 U.S.C. 1732(b), 1733, and 1740.
Sec. 3176.1 Authority.
This subpart is established pursuant to the authority granted to
the Secretary of the Interior through various Federal and Indian
mineral leasing statutes and the Federal Oil and Gas Royalty Management
Act of 1982. This authority has been delegated to the Bureau of Land
Management and is implemented by the onshore oil and gas operating
regulations contained in 43 CFR part 3160. More specifically, this
subpart implements and supplements the provisions of 43 CFR 3162.1,
3162.5-1(a), (c), and (d), 3162.5-2(a), and 3162.5-3.
Sec. 3176.2 Purpose.
The purpose of this subpart is to protect public health and safety
and those personnel essential to maintaining control of the well. This
subpart identifies the Bureau of Land Management's uniform national
requirements and minimum standards of performance expected from
operators when conducting operations involving oil or gas that is known
or could reasonably be expected to contain hydrogen sulfide
(H<INF>2</INF>S) or which results in the emission of sulfur dioxide
(SO<INF>2</INF>) as a result of flaring H<INF>2</INF>S. This subpart
also identifies the gravity of violations, probable corrective
action(s), and normal abatement periods.
[[Page 39541]]
Sec. 3176.3 Scope.
(a) This subpart is applicable to all onshore Federal and Indian
(except Osage Tribe) oil and gas leases when drilling, completing,
testing, reworking, producing, injecting, gathering, storing, or
treating operations are being conducted in zones which are known or
could reasonably be expected to contain H<INF>2</INF>S or which, when
flared, could produce SO<INF>2</INF>, in such concentrations that upon
release could constitute a hazard to human life. The requirements and
minimum standards of this subpart do not apply when operating in zones
where H<INF>2</INF>S is presently known not to be present or cannot
reasonably be expected to be present in concentrations of 100 parts per
million (ppm) or more in the gas stream.
(b) The requirements and minimum standards in this subpart do not
relieve an operator from compliance with any applicable Federal, State,
or local requirement(s) regarding H<INF>2</INF>S or SO<INF>2</INF>
which are more stringent.
Sec. 3176.4 Definitions.
As used in this subpart, the term:
Authorized officer means any employee of the Bureau of Land
Management authorized to perform the duties described in 43 CFR parts
3000 and 3100 (43 CFR 3000.0-5).
Christmas tree means an assembly of valves and fittings used to
control production and provide access to the producing tubing string.
The assembly includes all equipment above the tubinghead top flange.
Dispersion technique means a mathematical representation of the
physical and chemical transportation, dilution, and transformation of
H<INF>2</INF>S gas emitted into the atmosphere.
Escape rate means that the maximum volume (Q) used as the escape
rate in determining the radius of exposure shall be that specified in
paragraphs (1) through (4) of this definition, as applicable:
(1) For a production facility, the escape rate shall be calculated
using the maximum daily rate of gas produced through that facility or
the best estimate thereof;
(2) For gas wells, the escape rate shall be calculated by using the
current daily absolute open-flow rate against atmospheric pressure;
(3) For oil wells, the escape rate shall be calculated by
multiplying the producing gas/oil ratio by the maximum daily production
rate or best estimate thereof; or
(4) For a well being drilled in a developed area, the escape rate
may be determined by using the offset wells completed in the
interval(s) in question.
Essential personnel means those on-site personnel directly
associated with the operation being conducted and necessary to maintain
control of the well.
Exploratory well means any well drilled beyond the known producing
limits of a pool.
Gas well means a well for which the energy equivalent of the gas
produced, including the entrained liquid hydrocarbons, exceeds the
energy equivalent of the oil produced.
H2S Drilling Operations Plan means a written plan which provides
for safety of essential personnel and for maintaining control of the
well with regard to H<INF>2</INF>S and SO<INF>2.</INF>
Lessee means a person or entity holding record title in a lease
issued by the United States (43 CFR 3160.0-5).
Major violation means noncompliance which causes or threatens
immediate. substantial, and adverse impacts on public health and
safety, the environment, production accountability, or royalty income
(43 CFR 3160.0-5).
Minor violation means noncompliance which does not rise to the
level of a major violation (43 CFR 3160.0-5).
Oil well means a well for which the energy equivalent of the oil
produced exceeds the energy equivalent of the gas produced, including
the entrained liquid hydrocarbons.
Operating rights owner means a person or entity holding operating
rights in a lease issued by the United States. A lessee may also be an
operating rights owner if the operating rights in a lease or portion
thereof have not been severed from record title (43 CFR 3160.0-5).
Operator means any person or entity including but not limited to
the lessee or operating rights owner who has stated in writing to the
authorized officer that he/she is responsible under the terms of the
lease for the operations conducted on the leased lands or a portion
thereof (43 CFR 3160.0-5).
Potentially hazardous volume means a volume of gas of such
H<INF>2</INF>S concentration and flow rate that it may result in radius
of exposure-calculated ambient concentrations of 100 ppm H<INF>2</INF>S
at any occupied residence, school, church, park, school bus stop, place
of business, or other area where the public could reasonably be
expected to frequent, or 500 ppm H<INF>2</INF>S at any Federal, State,
County, or municipal road or highway.
Production facilities means any wellhead, flowline, piping,
treating, or separating equipment, water disposal pits, processing
plant, or combination thereof prior to the approved measurement point
for any lease, communitization agreement, or unit participating area.
Prompt correction means immediate correction of violations, with
operation suspended if required at the discretion of the authorized
officer.
Public Protection Plan means a written plan which provides for the
safety of the potentially affected public with regard to H<INF>2</INF>S
and SO<INF>2.</INF>
Radius of exposure means the calculation resulting from using the
following Pasquill-Gifford derived equation, or by such other method(s)
as may be approved by the authorized officer:
(1) For determining the 100 ppm radius of exposure where the
H<INF>2</INF>S concentration in the gas stream is less than 10:
X = [1.589)(H<INF>2</INF>S concentration)(Q)]\(0.6258)\; or
(2) For determining the 500 ppm radius of exposure where the
H<INF>2</INF>S concentration in the gas stream is less than 10:
X = [(0.4546)(H<INF>2</INF>S concentration)(Q)]\(0.6258)\
Where:
X = radius of exposure in feet;
H<INF>2</INF>S Concentration = decimal equivalent of the mole or
volume fractions of H<INF>2</INF>S in the gaseous mixture; and
Q = maximum volume of gas determined to be available for escape in
cubic feet per day (at standard conditions of 14.73 psia and
60[deg]F).
(3) For determining the 100 ppm or the 500 ppm radius of exposure
in gas streams containing H<INF>2</INF>S concentrations of 10 percent
or greater, a dispersion technique that takes into account
representative wind speed, direction, atmospheric stability, complex
terrain, and other dispersion features shall be utilized. Such
techniques may include, but shall not be limited to, one of a series of
computer models outlined in the Environmental Protection Agency's
``Guidelines on Air Quality Models'' (EPA-450/2-78-027R).
(4) Where multiple H<INF>2</INF>S sources (i.e., wells, treatment
equipment, flowlines, etc.) are present, the operator may elect to
utilize a radius of exposure which covers a larger area than would be
calculated using radius of exposure formula for each component part of
the drilling/completion/workover/production system.
(5) For a well being drilled in an area where insufficient data
exits to calculate a radius of exposure, but where H<INF>2</INF>S could
reasonably be expected to be present in concentrations in excess of 100
ppm in the gas stream, a 100 ppm radius of exposure equal to 3,000 feet
shall be assumed.
[[Page 39542]]
Zones known not to contain H2S means geological formations in a
field where prior drilling, logging, coring, testing, or producing
operations have confirmed the absence of H<INF>2</INF>S-bearing zones
that contain 100 ppm or more of H<INF>2</INF>S in the gas stream.
Zones known to contain H2S means geological formations in a field
where prior drilling, logging, coring, testing, or producing operations
have confirmed that H<INF>2</INF>S-bearing zones will be encountered
that contain 100 ppm or more of H<INF>2</INF>S in the gas stream.
Zones which can reasonably be expected to contain H2S means
geological formations in the area which have not had prior drilling,
but prior drilling to the same formations in similar field(s) within
the same geologic basin indicates there is a potential for 100 ppm or
more of H<INF>2</INF>S in the gas stream.
Zones which cannot reasonably be expected to contain H2S means
geological formations in the area which have not had prior drilling,
but prior drilling to the same formations in similar field(s) within
the same geologic basin indicates there is not a potential for 100 ppm
or more of H<INF>2</INF>S in the gas stream.
Sec. 3176.5 Requirements.
The requirements of this subpart are the minimum acceptable
standards with regard to H<INF>2</INF>S operations. This subpart also
classifies violations as typically major or minor for purposes of the
assessment and penalty provisions of 43 CFR part 3160, subpart 3163,
specifies the corrective action which will probably be required, and
establishes the normal abatement period following detection of a major
or minor violation in which the violator may take such corrective
action without incurring an assessment. However, the authorized officer
may, after consideration of all appropriate factors, require reasonable
and necessary standards, corrective actions, and abatement periods that
may, in some cases, vary from those specified in this subpart that he/
she determines to be necessary to protect public health and safety, the
environment, or to maintain control of a well to prevent waste of
Federal mineral resources. To the extent such standards, actions, or
abatement periods differ from those set forth in this subpart, they may
be subject to review pursuant to 43 CFR 3165.3.
Sec. 3176.6 Applications, approvals, and reports.
(a) Drilling. For proposed drilling operations where formations
will be penetrated which have zones known to contain or which could
reasonably be expected to contain concentrations of H<INF>2</INF>S of
100 ppm or more in the gas stream, the H<INF>2</INF>S Drilling
Operation Plan and, if the applicability criteria in Sec. 3176.7(a)
are met, a Public Protection Plan as outlined in Sec. 3176.7(b), shall
be submitted as part of the Application for Permit to Drill (APD)
(refer to subpart 3171 of this part). In cases where multiple filings
are being made with a single drilling plan, a single H<INF>2</INF>S
Drilling Operations Plan and, if applicable, a single Public Protection
Plan may be submitted for the lease, communitization agreement, unit,
or field in accordance with subpart 3171. Failure to submit either the
H<INF>2</INF>S Drilling Operations Plan or the Public Protection Plan
when required by this subpart shall result in an incomplete APD
pursuant to 43 CFR 3162.3-1.
(b) Drilling plan. The H<INF>2</INF>S Drilling Operations Plan
shall fully describe the manner in which the requirements and minimum
standards in Sec. 3176.8, shall be met and implemented. As required by
this subpart (Sec. 3176.8), the following must be submitted in the
H<INF>2</INF>S Drilling Operations Plan:
(1) Statement that all personnel shall receive proper
H<INF>2</INF>S training in accordance, with Sec. 3176.8(c)(1).
(2) A legible well site diagram of accurate scale (may be included
as part of the well site layout as required by subpart 3171 of this
part) showing the following:
(i) Drill rig orientation;
(ii) Prevailing wind direction;
(iii) Terrain of surrounding area;
(iv) Location of all briefing areas (designate primary briefing
area);
(v) Location of access road(s) (including secondary egress);
(vi) Location of flare line(s) and pit(s);
(vii) Location of caution and/or danger signs; and
(viii) Location of wind direction indicators.
(3) As required by this subpart, a complete description of the
following H<INF>2</INF>S safety equipment/systems:
(i) Well control equipment. (A) Flare line(s) and means of
ignition;
(B) Remote controlled choke;
(C) Flare gun/flares; and
(D) Mud-gas separator and rotating head (if exploratory well);
(ii) Protective equipment for essential personnel. (A) Location,
type, storage, and maintenance of all working and escape breathing
apparatus; and
(B) Means of communication when using protective breathing
apparatus;
(iii) H2S detection and monitoring equipment. (A) H<INF>2</INF>S
sensors and associated audible/visual alarm(s); and
(B) Portable H<INF>2</INF>S and SO<INF>2</INF> monitor(s);
(iv) Visual warning systems. (A) Wind direction indicators; and (B)
Caution/danger sign(s) and flag(s);
(v) Mud program. (A) Mud system and additives; and (B) Mud
degassing system;
(vi) Metallurgy. Metallurgical properties of all tubular goods and
well control equipment which could be exposed to H<INF>2</INF>S (Sec.
3176.8(d)(3)); and
(vii) Communication. Means of communication from wellsite.
(4) Plans for well testing.
(c) Production. (1) For each existing production facility having an
H<INF>2</INF>S concentration of 100 ppm or more in the gas stream, the
operator shall calculate and submit the calculations to the authorized
officer within 180 days of January 22, 1991, the 100 and, if
applicable, the 500 ppm radii of exposure for all facilities to
determine if the applicability criteria in Sec. 3176.7(a) are met.
Radii of exposure calculations shall not be required for oil or water
flowlines. Further, if any of the applicability criteria (Sec.
3176.7(a)) are met, the operator shall submit a complete Public
Protection Plan which meets the requirements of Sec. 3176.7(b)(2) to
the authorized officer within 1 year of January 22, 1991. For
production facilities constructed after January 22, 1991, and meeting
the minimum concentration (100 ppm in gas stream), the operator shall
report the radii of exposure calculations, and if the applicability
criteria in Sec. 3176.7(a) are met, submit a complete Public
Protection Plan (Sec. 3176.7(b)(2)) to the authorized officer within
60 days after completion of production facilities.
Table 1 to Sec. 3176.6(c)(1)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor for failure to submit Submit required 20 to 40 days.
required information. information (radii
of exposure and/or
complete Public
Protection Plan).
------------------------------------------------------------------------
[[Page 39543]]
(2) The operator shall initially test the H<INF>2</INF>S
concentration of the gas stream for each well or production facility
and shall make the results available to the authorized officer, upon
request.
Table 2 to Sec. 3176.6(c)(2)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Test gas from well 20 to 40 days.
or production
facility.
------------------------------------------------------------------------
(3) If operational or production alterations result in a 5 percent
or more increase in the H<INF>2</INF>S concentration (i.e., well
recompletion, increased gas-to-oil ratios) or the radius of exposure as
calculated under paragraph (c)(1) of this section, notification of such
changes shall be submitted to the authorized officer within 60 days
after identification of the change.
Table 3 to Sec. 3176.6(c)(3)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Submit information 20 to 40 days.
to authorized
officer.
------------------------------------------------------------------------
(d) Plans and reports. (1) H<INF>2</INF>S Drilling Operations
Plan(s) or Public Protection Plan(s) shall be reviewed by the operator
on an annual basis and a copy of any necessary revisions shall be
submitted to the authorized officer upon request.
Table 4 to Sec. 3176.6(d)(1)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Submit information 20 to 40 days.
to authorized
officer.
------------------------------------------------------------------------
(2) Any release of a potentially hazardous volume of H<INF>2</INF>S
shall be reported to the authorized officer as soon as practicable, but
no later than 24 hours following identification of the release.
Table 5 to Sec. 3176.6(d)(2)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Report undesirable 24 hours.
event to the
authorized officer.
------------------------------------------------------------------------
Sec. 3176.7 Public protection.
(a) Applicability criteria. For both drilling/completion/workover
and production operations, the H<INF>2</INF>S radius of exposure shall
be determined on all wells and production facilities subject to this
subpart. A Public Protection Plan (paragraph (b) of this section) shall
be required when any of the following conditions apply:
(1) The 100 ppm radius of exposure is greater than 50 feet and
includes any occupied residence, school, church, park, school bus stop,
place of business, or other areas where the public could reasonably be
expected to frequent;
(2) The 500 ppm radius of exposure is greater than 50 feet and
includes any part of a Federal, State, County, or municipal road or
highway owned and principally maintained for public use; or
(3) The 100 ppm radius of exposure is equal to or greater than
3,000 feet where facilities or roads are principally maintained for
public use. Additional specific requirements for drilling/completion/
workover or producing operations are described in Sec. Sec. 3176.8 and
3176.9, respectively.
(b) Public Protection Plan--(1) Plan submission/implementation/
availability. (i) A Public Protection Plan providing details of actions
to alert and protect the public in the event of a release of a
potentially hazardous volume of H<INF>2</INF>S shall be submitted to
the authorized officer as required by Sec. 3176.6(a) for drilling or
by Sec. 3176.6(c) for producing operations when the applicability
criteria established in paragraph (a) of this section are met. One plan
may be submitted for each well, lease, communitization agreement, unit,
or field, at the operator's discretion. The Public Protection Plan
shall be maintained and updated, in accordance with Sec. 3176.6(d).
(ii) The Public Protection Plan shall be activated immediately upon
detection of release of a potentially hazardous volume of
H<INF>2</INF>S.
Table 1 to Sec. 3176.7(b)(1)(ii)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Major....................... Immediate Prompt correction
implementation of required.
the Public
Protection Plan.
------------------------------------------------------------------------
[[Page 39544]]
(iii) A copy of the Public Protection Plan shall be available at
the drilling/completion site for such wells and at the facility, field
office, or with the pumper, as appropriate, for producing wells,
facilities, and during workover operations.
Table 2 to Sec. 3176.7(b)(1)(iii)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Make copy of Plan 24 hours (drilling/
available. completion/
workover), 5 to 7
days (production).
------------------------------------------------------------------------
(2) Plan content. (i) The details of the Public Protection Plan may
vary according to the site-specific characteristics (concentration,
volume, terrain, etc.) expected to be encountered and the number and
proximity of the population potentially at risk. In the areas of high
population density or in other special cases, the authorized officer
may require more stringent plans to be developed. These may include
public education seminars, mass alert systems, and use of sirens,
telephone, radio, and television depending on the number of people at
risk and their location with respect to the well site.
(ii) The Public Protection Plan shall include:
(A) The responsibilities and duties of key personnel, and
instructions for alerting the public and requesting assistance;
(B) A list of names and telephone numbers of residents, those
responsible for safety of public roadways, and individuals responsible
for the safety of occupants of buildings within the 100 ppm radius of
exposure (e.g., school principals, building managers, etc.) as defined
by the applicability criteria in paragraph (a) of this section. The
operator shall ensure that those who are at the greatest risk are
notified first. The Plan shall define when and how people are to be
notified in case of an H<INF>2</INF>S emergency;
(C) A telephone call list (including telephone numbers) for
requesting assistance from law enforcement, fire department, and
medical personnel and Federal and State regulatory agencies, as
required. Necessary information to be communicated and the emergency
responses that may be required shall be listed. This information shall
be based on previous contacts with these organizations;
(D) A legible 100 ppm (or 3,000 feet, if conditions unknown) radius
plat of all private and public dwellings, schools, roads, recreational
areas, and other areas where the public might reasonably be expected to
frequent;
(E) Advance briefings, by visit, meeting, or letter to the people
identified in paragraph (b)(2)(ii)(B) of this section, including:
(1) Hazards of H<INF>2</INF>S and SO<INF>2</INF>;
(2) Necessity for an emergency action plan;
(3) Possible sources of H<INF>2</INF>S and S0<INF>2</INF>;
(4) Instructions for reporting a leak to the operator;
(5) The manner in which the public shall be notified of an
emergency; and
(6) Steps to be taken in case of an emergency, including evacuation
of any people;
(F) Guidelines for the ignition of the H<INF>2</INF>S bearing gas.
The Plan shall designate the title or position of the person(s) who has
the authority to ignite the escaping gas and define when, how, and by
whom the gas is to be ignited;
(G) Additional measures necessary following the release of
H<INF>2</INF>S and SO<INF>2</INF> until the release is contained are as
follows:
(1) Monitoring of H<INF>2</INF>S and SO<INF>2</INF> levels and wind
direction in the affected area;
(2) Maintenance of site security and access control;
(3) Communication of status of well control; and
(4) Other necessary measures as required by the authorized officer;
and
(H) For production facilities, a description of the detection
system(s) utilized to determine the concentration of H<INF>2</INF>S
released.
Sec. 3176.8 Drilling/completion/workover requirements.
(a) General. (1) A copy of the H<INF>2</INF>S Drilling Operations
Plan shall be available during operations at the well site, beginning
when the operation is subject to the terms of this subpart (i.e., 3
days or 500 feet of known or probable H<INF>2</INF>S zone).
Table 1 to Sec. 3176.8(a)(1)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Make copy of Plan 24 hours.
available.
------------------------------------------------------------------------
(2) Initial H<INF>2</INF>S training shall be completed and all
H<INF>2</INF>S related safety equipment shall be installed, tested, and
operational when drilling reaches a depth of 500 feet above, or 3 days
prior to penetrating (whichever comes first) the first zone containing
or reasonably expected to contain H<INF>2</INF>S. A specific
H<INF>2</INF>S operations plan for completion and workover operations
will not be required for approval. For completion and workover
operations, all required equipment and warning systems shall be
operational and training completed prior to commencing operations.
Table 2 to Sec. 3176.8(a)(2)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Major....................... Implement H2S Prompt correction
operational required.
requirements, such
as completion of
training and/or
installation,
repair, or
replacement of
equipment, as
necessary.
------------------------------------------------------------------------
[[Page 39545]]
(3) If H<INF>2</INF>S was not anticipated at the time the APD was
approved, but is encountered in excess of 100 ppm in the gas stream,
the following measures shall be taken:
(i) The operator shall immediately ensure control of the well,
suspend drilling ahead operations (unless detrimental to well control),
and obtain materials and safety equipment to bring the operations into
compliance with the applicable provisions of this subpart.
Table 3 to Sec. 3176.8(a)(3)(i)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Major....................... Implement H2S Prompt correction
operational required.
requirements, as
applicable.
------------------------------------------------------------------------
(ii) The operator shall notify the authorized officer of the event
and the mitigating steps that have or are being taken as soon as
possible, but no later than the next business day. If said notification
is subsequent to actual resumption of drilling operations, the operator
shall notify the authorized officer of the date that drilling was
resumed no later than the next business day.
Table 4 to Sec. 3176.8(a)(3)(ii)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Notify authorized 24 hours.
officer.
------------------------------------------------------------------------
(iii) It is the operator's responsibility to ensure that the
applicable requirements of this subpart have been met prior to the
resumption of drilling ahead operations. Drilling ahead operations will
not be suspended pending receipt of a written H<INF>2</INF>S Drilling
Operations Plan(s) and, if necessary, Public Protection Plan(s)
provided that complete copies of the applicable Plan(s) are filed with
the authorized officer for approval within 5 business days following
resumption of drilling ahead operations.
Table 5 to Sec. 3176.8(a)(3)(iii)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Submit plans to 5 days.
authorized officer.
------------------------------------------------------------------------
(b) Locations. (1) Where practical, 2 roads shall be established, 1
at each end of the location, or as dictated by prevailing winds and
terrain. If an alternate road is not practical, a clearly marked
footpath shall be provided to a safe area. The purpose of such an
alternate escape route is only to provide a means of egress to a safe
area.
Table 6 to Sec. 3176.8(b)(1)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Designate or 24 hours.
establish an
alternate escape
route.
------------------------------------------------------------------------
(2) The alternate escape route shall be kept passable at all times.
Table 7 to Sec. 3176.8(b)(2)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Make alternate 24 hours.
escape route
passable.
------------------------------------------------------------------------
(3) For workovers, a secondary means of egress shall be designated.
Table 8 to Sec. 3176.8(b)(3)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Designate secondary 24 hours.
means of egress.
------------------------------------------------------------------------
[[Page 39546]]
(c) Personnel protection--(1) Training program. The operator shall
ensure that all personnel who will be working at the wellsite will be
properly trained in H<INF>2</INF>S drilling and contingency procedures
in accordance with the general training requirements outlined in API
RP-49, Section 2 (incorporated by reference, see Sec. 3176.11). (The
use of later editions of API RP-49 is deemed to comply with the
requirements of this paragraph (c)(1).) The operator also shall ensure
that the training will be accomplished prior to a well coming under the
terms of this subpart (i.e., 3 days or 500 feet of known or probable
H<INF>2</INF>S zone). In addition to the requirements of API RP-49, a
minimum of an initial training session and weekly H<INF>2</INF>S and
well control drills for all personnel in each working crew shall be
conducted. The initial training session for each well shall include a
review of the site-specific Drilling Operations Plan and, if
applicable, the Public Protection Plan.
Table 9 to Sec. 3176.8(c)(1)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Major....................... Train all personnel Prompt correction
and conduct drills. required.
------------------------------------------------------------------------
(i) All training sessions and drills shall be recorded on the
driller's log or its equivalent.
Table 10 to Sec. 3176.8(c)(1)(i)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Minor....................... Record on driller's 24 hours.
log or equivalent.
------------------------------------------------------------------------
(ii) For drilling/completion/workover wells, at least 2 briefing
areas shall be designated for assembly of personnel during emergency
conditions, located a minimum of 150 feet from the well bore, and 1 of
the briefing areas shall be upwind of the well at all times. The
briefing area located most normally upwind shall be designated as the
``primary briefing area.''
Table 11 to Sec. 3176.8(c)(1)(ii)
------------------------------------------------------------------------
Normal abatement
Violation Corrective action period
------------------------------------------------------------------------
Major....................... Designate briefing 24 hours.
[…truncated; see source link]Indexed from Federal Register on June 16, 2023.
This is legal information, not legal advice. Laws vary by jurisdiction and change frequently. Always verify current law with official sources and consult a licensed attorney in your jurisdiction for advice on your specific situation.