[Federal Register Volume 88, Number 9 (Friday, January 13, 2023)]
[Proposed Rules]
[Pages 2430-2500]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2022-28098]
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Vol. 88
Friday,
No. 9
January 13, 2023
Part III
Department of the Interior
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Bureau of Indian Affairs
25 CFR Part 226
Mining of the Osage Mineral Estate for Oil and Gas; Proposed Rule
Federal Register / Vol. 88, No. 9 / Friday, January 13, 2023 /
Proposed Rules
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DEPARTMENT OF THE INTERIOR
Bureau of Indian Affairs
25 CFR Part 226
[Docket No. BIA-2022-0006; 2231A2100DD/AAKC001030/A0A501010.999900; OMB
Control Number 1076-0180, 1012-0004, 1012-0006]
RIN 1076-AF59
Mining of the Osage Mineral Estate for Oil and Gas
AGENCY: Bureau of Indian Affairs, Interior.
ACTION: Proposed rule.
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SUMMARY: The Bureau of Indian Affairs (BIA) proposes to revise the
regulations governing leasing of the Osage Nation's mineral estate
(``Osage Mineral Estate'') for oil and gas mining. The proposed rule
would allow the BIA to strengthen management of the Osage Mineral
Estate by updating bonding, royalty payment and reporting, production
valuation and measurement, site security, and operational requirements
to address changes in technology and industry standards that have
occurred in the 47 years since the regulations were issued. The
proposed rule would also allow the BIA to respond to recommendations
made by the Office of Inspector General, U.S. Department of the
Interior (OIG).
DATES: Proposed Regulations: Submit your comments on the proposed rule
to the BIA on or before March 17, 2023. Information Collection
Requirements: Submit your comments on the information collection
requirements in the proposed rule on or before March 17, 2023. Public
Meeting: A public meeting will be held on February 8, 2023, 6:30 p.m.
to 9 p.m. central time.
ADDRESSES:
Proposed Regulations: You may submit your comments on the proposed
rule by any of the methods listed below.
Federal Rulemaking Portal: https://www.regulations.gov.
Enter ``RIN 1076-AF59'' in the search box and click ``Search.'' Follow
the instructions for sending comments.
Mail: U.S. Department of the Interior, Eastern Oklahoma
Region, Bureau of Indian Affairs, Attn: Regional Director, P.O. Box
8002, Muskogee, OK 74402. All submissions must include the words
``Bureau of Indian Affairs'' or ``BIA'' and ``RIN 1076-AF59.''
Hand Delivery/Courier: U.S. Department of the Interior,
Eastern Oklahoma Region, Bureau of Indian Affairs, Attn: Regional
Director, 3100 W Peak Boulevard, Muskogee, OK 74402.
Public Meeting: The BIA is holding a public meeting on the Proposed
Rule on Wednesday, February 8, 2023, from 6:30 p.m. to 9 p.m. central
time at the Osage Casino and Hotel, 5591 W Rogers Boulevard, Skiatook,
OK 74070. Please see SUPPLEMENTARY INFORMATION, Section II, Public
Comment Procedures, for details.
Information Collection Requirements: Comments on the information
collection requirements in the proposed rule must be submitted to
Steven Mullen, Information Collection Clearance Officer, Office of
Regulatory Affairs and Collaborative Action--Indian Affairs, U.S.
Department of the Interior, 1001 Indian School Road NW, Suite 229,
Albuquerque, NM 87104; or by email to [email protected] with a copy to
[email protected]. All submissions must include the
applicable Office of Management and Budget (OMB) Control Number(s) for
the BIA or ONRR information collection(s) you are commenting on:
OMB Control Number 1076-0180, Mining of the Osage Mineral
Estate for Oil and Gas.
OMB Control Number 1012-0004, Royalty and Production
Reporting.
OMB Control Number 1012-0006, Suspensions Pending Appeal
and Bonding.
FOR FURTHER INFORMATION CONTACT: Oliver Whaley, Director, Office of
Regulatory Affairs and Collaborative Action, Office of the Assistant
Secretary--Indian Affairs, (202) 738-6065, [email protected].
SUPPLEMENTARY INFORMATION:
I. Executive Summary
II. Public Comment Procedures
III. Background
IV. Incorporation by Reference of Industry Standards
V. Discussion of Proposed Changes
VI. Procedural Matters
I. Executive Summary
The purpose of this proposed rule is to amend 25 CFR part 226,
Leasing of Osage Reservation Lands for Oil and Gas Mining, to
strengthen the Bureau of Indian Affairs' (BIA) management and
administration of the Osage Mineral Estate. The last major substantive
revisions to the regulations in 25 CFR part 226 occurred in 1974, with
many provisions having remained virtually unchanged since well before
then. As a result, the regulations are outdated, inconsistent with
industry standards, and do not reflect technological advancements or
modern oil and gas operations within the Osage Mineral Estate. The BIA
believes that the proposed rule updating the regulations makes critical
changes that will improve accounting and production measurement
standards; offer consistency in production valuation; address
inadequate bonding; support the implementation of electronic reporting
systems; enhance accountability; clarify lessees' obligations; prevent
waste; promote safe and environmentally sound operations; and protect
resource values. The BIA also believes that the proposed rule will
allow it to take the necessary actions to resolve certain
recommendations made by the Office of Inspector General, U.S.
Department of the Interior (OIG).
In 2013, the OIG performed an assessment of the BIA Osage Agency's
effectiveness in managing the Osage Mineral Estate. On October 20,
2014, the OIG issued its final evaluation report, titled ``BIA Needs
Sweeping Changes to Manage the Osage Nation's Energy Resources.'' While
the OIG acknowledged the complexity of managing the Osage Mineral
Estate due, in part, to the number of competing interests, it
documented multiple deficiencies in the BIA Osage Agency's management
of the oil and gas program and called for broad reform.
The OIG report set forth 33 recommendations for improvement of the
BIA Osage Agency's oil and gas program. The first issue the OIG report
addressed was deficiencies in the regulations in 25 CFR part 226.
Specifically, the OIG found that the existing regulations are vague,
inadequate, and fail to mirror the oil and gas regulations governing
the rest of Indian country. Accordingly, the OIG recommended that the
BIA ``use its authority to correct program deficiencies by modifying 25
CFR part 226 to mirror other Indian Country oil and gas regulations.''
The OIG also identified issues with accounting, reconciliation, bonding
requirements, royalty and production reporting, inspections, lease
compliance, and enforcement measures, among other things. The BIA Osage
Agency resolved 26 of the OIG's recommendations through the
implementation of new and revised policies and procedures but
determined that the remaining seven recommendations could not be fully
resolved without revision of the regulations in 25 CFR part 226.
This proposed rule modernizes the regulations and brings them in
line with the regulations governing oil and gas leasing and development
throughout the rest of Indian country consistent with the OIG's
recommendation. In addition, the proposed rule will allow the BIA Osage
Agency to respond to the open OIG recommendations regarding engagement
of the Office of Natural Resources Revenue (ONRR) to perform accounting
and compliance activities,
[[Page 2431]]
implementation of ONRR's electronic reporting systems, reconciliation
of royalty payments, verification of allowances and arm's-length sales
transactions, and the implementation of sampling thresholds. These
revisions are critical to ensure that oil and gas produced from the
Osage Mineral Estate is properly accounted for and lessees timely pay
the correct and full amount of royalties due to the Osage Nation.
II. Public Comment Procedures
If you wish to comment on this proposed rule, you may submit your
comments to the BIA by mail, hand delivery/courier, or through https://www.regulations.gov (see ADDRESSES). Please make your comments on the
proposed rule as specific as possible, provide a detailed explanation
of any changes you recommend, and include any relevant supporting
documentation. Where possible, your comments should reference the
specific section or paragraph of the proposed rule that you are
addressing. The BIA is not obligated to consider comments received
after the comment period closes (see DATES) or comments delivered to an
address, or using methods other than, those identified (see ADDRESSES).
Comments, including the names and street addresses of respondents,
will be available for public review at the BIA Eastern Oklahoma
Regional Office, 3100 W Peak Boulevard, Muskogee, OK 74402, during
regular business hours (8 a.m. to 4:30 p.m.), Monday through Friday,
except holidays. Before including your address, phone number, email
address, or other personal identifying information in your comment,
please be advised that your entire comment--including your personal
identifying information--may be made publicly available at any time.
While you can ask the BIA to withhold your personal identifying
information from public review in your comment, we cannot guarantee
that we will be able to do so. As discussed in detail below, this
proposed rule would include revisions to information collection
requirements that must be approved by the Office of Management and
Budget (OMB). If you wish to comment on the revised information
collection requirements in this proposed rule, you must send such
comments directly to the OMB (see ADDRESSES).
The BIA is holding a public meeting on the Proposed Rule on
Wednesday, February 8, 2023, from 6:30 p.m. to 9 p.m. central time at
the Osage Casino and Hotel, 5591 West Rogers Boulevard, Skiatook, OK
74070. At the meeting, you may sign up for a two-minute time slot to
provide verbal comments on the Proposed Rule. The BIA requests that
groups or organizations wishing to provide verbal comments elect a
single representative to speak on behalf of the group or organization.
III. Background
A. Osage Allotment Act
In 1872, the U.S. Congress established a reservation for the Osage
Nation in the Oklahoma Territory. On June 16, 1906, Congress passed the
Oklahoma Enabling Act, Public Law 59-234, 34 Stat. 256, joining the
Oklahoma Territory with Indian Territory to form the state of Oklahoma.
Shortly thereafter, Congress passed the Act of June 28, 1906, Public
Law 59-321, 34 Stat. 539 (1906 Act), titled an ``Act for the division
of the lands and funds of the Osage Indians in Oklahoma Territory.''
The 1906 Act provided for the allotment of the Osage Nation's lands to
individual Tribal members. Upon statehood in 1907, the Osage Indian
Reservation, comprising approximately 1,475,000 acres, became Osage
County, Oklahoma.
Section 3 of the 1906 Act, as amended, severed the surface estate
from the subsurface mineral estate, reserving all oil, gas, coal, and
other minerals to the Osage Nation in perpetuity. Accordingly, the
United States holds the subsurface mineral estate in Osage County,
Oklahoma (``Osage Mineral Estate'') in trust for the benefit of the
Osage Nation. The 1906 Act authorizes the Osage Nation to lease the
Osage Mineral Estate for oil, gas, and other mineral development ``with
the approval of the Secretary of the Interior, and under such rules and
regulations as he may prescribe.'' The Secretary of the Interior
delegated this authority to the Superintendent of the BIA Osage Agency.
See 209 Departmental Manual 8.1(A).
Section 4 of the 1906 Act, as amended, required that the United
States hold the revenues derived from the Osage Mineral Estate in trust
and distribute the funds to individual Tribal members on the authorized
roll of membership in a timely (quarterly) and proper (pro rata with
interest) basis. This prospective right to share in the royalties,
rental, and bonuses derived from the Osage Mineral Estate is referred
to as a ``headright.'' See Act of October 30, 1984, Pub. L. 98-605,
section 11, 98 Stat. 3163.
B. Osage Tribal Trust Settlement and Negotiated Rulemaking
On October 14, 2011, the United States and Osage Nation signed the
Osage Tribal Trust Settlement (Settlement) resolving litigation
regarding the United States' alleged mismanagement of the Osage Mineral
Estate along with other unrelated breach of trust claims. As part of
the Settlement, the Department of the Interior (Department) agreed to
engage in negotiated rulemaking with the Osage Nation pursuant to 5
U.S.C. 561-570a and revise the regulations in 25 CFR part 226 to
improve management of the Osage Mineral Estate. The negotiated
rulemaking process began on June 18, 2012, when the Department
published a notice of the intent to establish an Osage Negotiated
Rulemaking Committee (Committee). See 77 FR 36226.
On July 31, 2012, the Department announced the establishment of the
Committee, comprised of four Federal Government representatives and
five members of the Osage Minerals Council who were selected by Council
vote. See 77 FR 45301. The Osage Minerals Council representatives on
the Committee identified five priority areas to be discussed during
negotiations: (1) modernization of royalty value and royalty rate for
oil production; (2) modernization of royalty value, royalty rate, and
royalty calculations for gas production; (3) strengthening drilling
obligations for oil lessees; (4) requiring detailed electronic
reporting by all lessees; and (5) strengthening oil gauging and gas
meter inspection, calibration, and adjustment.
The Committee held the first public meeting in August 2012 and,
except for December 2012, met monthly until April 2013. On April 25,
2013, the Negotiated Rulemaking Committee submitted its Consensus
Report to the Department on a package of proposed revisions to the
regulations, completing the negotiated rulemaking process required by
the Settlement. The Department published the proposed rule based on the
Committee's recommendations on August 28, 2013. See 78 FR 53083. The
Department received, evaluated, and responded to a significant number
of public comments on the proposed rule and amended the regulations to
make necessary changes in accordance therewith. On May 11, 2015, the
Department published the final rule, which had an effective date of
July 10, 2015. See 80 FR 26994.
On July 1, 2015, the Osage Minerals Council and Osage Producers
Association each filed suit in the U.S. District Court for the Northern
District of Oklahoma (Court), seeking to enjoin implementation of the
final rule. The arguments advanced in the lawsuits included, among
other things, claims that the final rule conflicted with the 1906 Act,
would impose administrative costs that would lead to decreased
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production, and the Department failed to complete the analyses required
by the Regulatory Flexibility and Small Business Regulatory Enforcement
Acts. The Court consolidated the two lawsuits and entered an order
enjoining implementation of the final rule pending resolution of the
litigation.
Upon review of the issues raised in the litigation, the Department
determined that a voluntary remand of the final rule was appropriate.
The Osage Minerals Council and Osage Producers Association supported
such action. On November 19, 2015, the Department filed the Joint
Motion for Voluntary Remand and the Court, in turn, entered the
Judgment of Remand. As a result of the remand, the 2015 final rule
never went into effect. Accordingly, the version of 25 CFR part 226
that was in effect prior to publication of the final rule remained
operative. To ensure that the correct version of the regulations
appeared in the CFR, the Department published a final rule formally
confirming that the prior version of 25 CFR part 226 (last updated in
1974) remained in full force and effect. See 81 FR 39572.
C. Current Rulemaking
Following remand of the 2015 final rule, the BIA determined that it
was appropriate to review the regulations in 25 CFR part 226 to
consider whether, and to what extent, the regulations should be revised
to strengthen the BIA's management and administration of the Osage
Mineral Estate. On September 22, 2016, the BIA mailed letters to the
Principal Chief of the Osage Nation and Chairman of the Osage Minerals
Council requesting government-to-government consultation (consultation)
regarding the need for such revisions. On October 25, 2016, the BIA
held a consultation with representatives from the Osage Nation
Executive and Legislative Branches, the Osage Minerals Council, and
their legal counsel, in Pawhuska, Oklahoma. The outcome of the
consultation was agreement by all parties that revision of the
regulations was necessary. See Section VI, Procedural Matters, for
additional information regarding the Tribal consultation process for
the proposed rule.
The current effort to revise the regulations in 25 CFR part 226 is
not a continuation of the negotiated rulemaking process undertaken
pursuant to the Settlement, nor is it a republication of the 2015 final
rule.
IV. Incorporation by Reference of Industry Standards
This proposed rule would incorporate industry standards and
recommended practices, either in whole or in part, without republishing
the standards in their entirety in the CFR. This practice is known as
incorporation by reference (IBR). These standards currently apply to
all federal and Indian lands except those within Osage County,
Oklahoma. The BIA reviewed these standards and determined that they
achieve the intent of 25 CFR 226.106 through 226.116 and 25 CFR 226.120
through 226.141 of the proposed rule. The proposed rule proposes to
incorporate the versions of the standards listed. Some of the standards
referenced would be incorporated in their entirety. For other
standards, the BIA would incorporate only those sections that are
relevant to the rule, meet the intent of 25 CFR 226.0, and do not
require further clarification.
The National Technology Transfer and Advancement Act (NTTAA),
Public Law 104-113, 15 U.S.C. 3701, et seq., states that ``all Federal
agencies and departments shall use technical standards that are
developed by consensus standards bodies, using such technical standards
as a means to carry out policy objectives or activities determined by
the agencies or departments,'' subject to certain exceptions. The BIA
may incorporate these standards into its regulations by reference
without republishing the standards in their entirety in the
regulations. The legal effect of IBR is that the incorporated standards
would become regulatory requirements. The incorporated standards, like
any other regulation, have the force and effect of law. Accordingly,
lessees and other regulated parties would be required to comply with
the standards incorporated by reference in the regulations.
The Office of the Federal Register (OFR) regulations governing IBR
are set forth in 1 CFR part 51. The industry standards for this
proposed rule are eligible for incorporation pursuant to 1 CFR 51.7
because, among other things, they substantially reduce the volume of
material published in the Federal Register; are published, bound,
numbered, and organized; and are readily available to the public free
of charge or through purchase from the standards organization or
through inspection at the BIA Osage Agency. The IBR language in Sec.
226.0 meets the requirements set forth in 1 CFR 51.9. Where
appropriate, the BIA would incorporate by reference an industry
standard governing a particular process and impose requirements that
add to, or modify, the requirements imposed by that standard (e.g., the
BIA sets a specific value for a variable where the industry standard
proposed a range of values or options).
All American Petroleum Institute (API) materials are available for
inspection and purchase at the API, 200 Massachusetts Avenue NW, Suite
1100, Washington, DC 20001, (202) 682-8000. API also offers free, read-
only access to the standards in the API IBR Reading Room at https://publications.api.org. All American Gas Association (AGA) standards are
available for inspection and purchase from AGA, 400 North Capitol
Street NW, Suite 450, Washington, DC 20001, (202) 824-7000, https://www.aga.org/publication-store. All Gas Processors Association (GPA)
standards are available for inspection and purchase from GPA, 6526 E
60th Street, Tulsa, OK 74145, (918) 493-3872, https://my.midstreamassociation.org/publications-store/publications.
The following industry standards and recommendations are proposed
for incorporation by reference, in whole or in part, in subpart J of
the proposed rule:
API Manual of Petroleum Measurement Standards (MPMS),
Chapter 2--Tank Calibration, Section 2A, Measurement and Calibration of
Upright Cylindrical Tanks by the Manual Tank Strapping Method; First
Edition, February 1995; Reaffirmed 2017 (``API 2.2A''). This standard
describes calibration procedures for upright cylindrical tanks used for
storing oil.
API MPMS Chapter 2--Tank Calibration, Section 2B,
Calibration of Upright Cylindrical Tanks Using the Optical Reference
Line Method; First Edition, March 1989; Reaffirmed April 2019; Addendum
1, October 2019 (``API 2.2B''). This standard describes measurement and
calibration procedures for determining the diameters of upright welded
cylindrical tanks or vertical cylindrical tanks with a smooth surface
and either floating or fixed roofs.
API MPMS Chapter 2--Tank Calibration, Section 2C,
Calibration of Upright Cylindrical Tanks Using the Optical-
triangulation Method; First Edition, January 2002; Reaffirmed April
2019 (``API 2.2C''). This standard describes a calibration procedure
for tanks above 26 feet in diameter with cylindrical courses that are
substantially vertical.
API MPMS Chapter 3.1A, Standard Practice for the Manual
Gauging of Petroleum and Petroleum Products; Third Edition, August
2013; Reaffirmed
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December 2018 (``API 3.1A''). This standard describes the: (a)
procedures for manually gauging the liquid level of petroleum and
petroleum products in non-pressure fixed roof tanks; (b) procedures for
manually gauging the level of free water that may be found with the
petroleum or petroleum products; (c) methods used to verify the length
of gauge tapes under field conditions and the influence of bob weights
and temperature on the gauge tape length; and (d) influences that may
affect the position of gauging reference point (either the datum plate
or the reference gauge point).
API MPMS Chapter 3--Tank Gauging, Section 1B--Standard
Practice for Level Measurement of Liquid Hydrocarbons in Stationary
Tanks by Automatic Tank Gauging; Third Edition, April 2018 (``API
3.1B''). This standard describes the level measurement of liquid
hydrocarbons in stationary, above ground, atmospheric storage tanks
using ATGs. This standard also discusses automatic tank gauging in
general, including the accuracy, installation, commissioning,
calibration, and verification of ATGs that measure either innage or
ullage.
API MPMS Chapter 3--Tank Gauging, Section 6, Measurement
of Liquid Hydrocarbons by Hybrid Tank Measurement Systems; First
Edition, February 2001; Errata September 2005; Reaffirmed January 2017
(``API 3.6''). This standard describes the selection, installation,
commissioning, calibration, and verification of Hybrid Tank Measurement
Systems. This standard also provides a method of uncertainty analysis
to enable users to select the correct components and configurations to
address for the intended application.
API MPMS Chapter 4--Proving Systems, Section 1,
Introduction; Third Edition, February 2005; Reaffirmed June 2014 (``API
4.1''). Section 1 is a general introduction to the subject of proving
meters.
API MPMS Chapter 4--Proving Systems, Section 2--
Displacement Provers; Third Edition, September 2003; Reaffirmed March
2011; Addendum February 2015 (``API 4.2''). This standard outlines the
essential elements of meter provers that do, and do not, accumulate a
minimum of 10,000 whole meter pulses between detector switches and
provides design and installation details for the types of displacement
provers that are currently in use. The provers discussed in this
chapter are designed for proving measurement devices under dynamic
operating conditions with single-phase liquid hydrocarbons.
API MPMS Chapter 4.5, Master- Meter Provers; Fourth
Edition, June 2016 (``API 4.5''). This standard covers the use of
displacement and Coriolis meters as master meters. The requirements in
this standard are for single-phase liquid hydrocarbons.
API MPMS Chapter 4--Proving Systems, Section 6, Pulse
Interpolation; Second Edition, May 1999; Errata April 2007; Reaffirmed
October 2013 (``API 4.6''). This standard describes how the double-
chronometry method of pulse interpolation, including system operating
requirements and equipment testing, is applied to meter proving.
API MPMS Chapter 4.8, Operation of Proving Systems; Second
Edition, September 2013 (``API 4.8''). This standard provides
information for operating meter provers on single-phase liquid
hydrocarbons.
API MPMS Chapter 4--Proving Systems, Section 9--Methods of
Calibration for Displacement and Volumetric Tank Provers, Part 2--
Determination of the Volume of Displacement and Tank Provers by the
Waterdraw Method of Calibration; First Edition, December 2005;
Reaffirmed July 2015 (``API 4.9.2''). This standard provides all the
procedures required to determine the field data necessary to calculate
a Base Prover Volume of Displacement Provers by the Waterdraw Method of
Calibration.
API MPMS Chapter 5--Metering, Section 6--Measurement of
Liquid Hydrocarbons by Coriolis Meters; First Edition, October 2002;
Reaffirmed November 2013 (``API 5.6''). This standard applies to
custody-transfer applications for liquid hydrocarbons and covers the
API standards used in the operation of Coriolis meters, proving and
verification using volume-based methods, installation, operation, and
maintenance.
API MPMS Chapter 6, Metering Assemblies, Section 1--Lease
Automatic Custody Transfer (LACT) Systems; Second Edition, May 1991;
Reaffirmed May 2012 (``API 6.1''). This standard describes the design,
installation, calibration, and operation of a LACT system.
API MPMS Chapter 7, Temperature Determination, Section 1--
Liquid-in- Glass Thermometers; Second Edition, August 2017 (``API
7.1''). This standard describes how to use various types of liquid-in-
glass thermometers to accurately determine the temperatures of
hydrocarbon liquids. This standard is proposed for incorporation for
its standards covering the use of liquid-in-glass thermometers for
temperature determination in tank-gauging operations.
API MPMS Chapter 7--Temperature Determination, Section 2--
Portable Electronic Thermometers; Third Edition, May 2018 (``API
7.2''). This standard describes the methods, equipment, and procedures
for manually determining the temperature of liquid petroleum and
petroleum products by use of a portable electronic thermometer. This
standard is proposed for incorporation for its standards covering the
use of portable electronic thermometers for temperature determination
in tank gauging operations.
API MPMS Chapter 7--Temperature Determination, Section 4--
Dynamic Temperature Measurement; Second Edition, January 2018 (``API
7.4''). This standard describes methods, equipment, installation, and
operating procedures for the proper determination of the temperature of
hydrocarbon liquids under dynamic conditions in custody transfer
applications. This standard is proposed for incorporation for its
standards covering the use of dynamic temperature determination in LACT
and CMS operations.
API MPMS Chapter 8.1, Standard Practice for Manual
Sampling of Petroleum and Petroleum Products; Fourth Edition, October
2013, (``API 8.1''). This standard covers procedures and equipment for
manually obtaining samples of liquid petroleum and petroleum products
from the sample point into the primary containers.
API MPMS Chapter 8.2, Standard Practice for Automatic
Sampling of Petroleum and Petroleum Products; Fourth Edition, November
2016 (``API 8.2''). This standard describes general procedures and
equipment for automatically obtaining samples of liquid petroleum,
petroleum products, and crude oils from a sample point into a primary
container.
API MPMS Chapter 8--Sampling, Section 3--Standard Practice
for Mixing and Handling of Liquid Samples of Petroleum and Petroleum
Products; First Edition, October 1995; Reaffirmed, March 2015 (``API
8.3''). This standard covers the handling, mixing, and conditioning
procedures required to ensure that a representative sample of the
liquid petroleum or petroleum product is delivered from the primary
sample container/receiver into the analytical test apparatus or into
intermediate containers.
API MPMS Chapter 9.1, Standard Test Method for Density,
Relative Density, or API Gravity of Crude Petroleum and Liquid
Petroleum Products by Hydrometer Method; Third Edition, December 2012;
Reaffirmed, May 2017 (``API 9.1''). This standard
[[Page 2434]]
covers the determination of the density, relative density, or API
gravity of crude petroleum, petroleum products, or mixtures of
petroleum and non-petroleum products normally handed as liquids have a
Reid vapor pressure of 101.325 Kilopascal (kPa) (14.696 psi) or less,
using a glass hydrometer in conjunction with a series of calculations.
API MPMS Chapter 9.2, Standard Test Method for Density or
Relative Density of Light Hydrocarbons by Pressure Hydrometer; Third
Edition, December 2012; Reaffirmed, May 2017 (``API 9.2''). This
standard covers the determination of the density or relative density of
light hydrocarbons including liquefied petroleum gases having a Reid
vapor pressure exceeding 101.325 kPa (14.696 psi).
API MPMS Chapter 9.3, Standard Test Method for Density,
Relative Density, and API Gravity of Crude Petroleum and Liquid
Petroleum Products by Thermohydrometer Method; Third Edition, December
2012; Reaffirmed, May 2017 (``API 9.3''). This standard covers the
determination of the density, relative density, or API gravity of crude
petroleum, petroleum products, or mixtures of petroleum and non-
petroleum products normally handed as liquids and having a Reid vapor
pressure of 101.325 kPa (14.696 psi) or less, using a glass
thermohydrometer in conjunction with a series of calculations.
API MPMS Chapter 10.4, Determination of Water and/or
Sediment in Crude Oil by the Centrifuge Method (Field Procedure);
Fourth Edition, October 2013; Errata, March 2015 (``API 10.4''). This
standard describes the field centrifuge method for determining both
water and sediment, or sediment only, in crude oil.
API MPMS Chapter 11--Physical Properties Data, Section 1--
Temperature and Pressure Volume Correction Factors for Generalized
Crude Oils, Refined Products and Lubricating Oils; May 2004; Addendum
1, September 2007, Addendum 2, May 2019; Reaffirmed, August 2012 (``API
11.1''). This standard provides the algorithm and implementation
procedure for the correction of temperature and pressure effects on
density and the volume of liquid hydrocarbons that fall within the
categories of crude oil.
API MPMS Chapter 12--Calculation of Petroleum Quantities,
Section 2--Calculation of Petroleum Quantities Using Dynamic
Measurement Methods and Volumetric Correction Factors, Part 2--
Measurement Tickets; Third Edition, June 2003; Reaffirmed February 2016
(``API 12.2.2''). This standard provides standardized calculation
methods for the quantification of liquids and specifies the equations
for computing correction factors, rules for rounding, calculation
sequences, and discrimination levels to be employed in the
calculations.
API MPMS Chapter 12--Calculation of Petroleum Quantities,
Section 2--Calculation of Petroleum Quantities Using Dynamic
Measurement Methods and Volumetric Correction Factors, Part 3--Proving
Report; First Edition, October 1998; Reaffirmed May 2014 (``API
12.2.3''). This standard provides standardized calculation methods for
the determination of meter factors under defined conditions. The
criteria contained in this standard will allow entities using various
computer languages on different computer hardware (or by manual
calculations) to arrive at identical results using the same
standardized input data. This standard also specifies the equations for
computing correction factors, including the calculation sequence,
discrimination levels, and rules for rounding to be employed in the
calculations.
API MPMS Chapter 12--Calculation of Petroleum Quantities,
Section 2--Calculation of Petroleum Quantities Using Dynamic
Measurement Methods and Volumetric Correction Factors, Part 4--
Calculation of Base Prover Volumes by the Waterdraw Method; First
Edition, December 1997; Errata July 2009; Reaffirmed September 2014
(``API 12.2.4''). This standard provides standardized calculation
methods for the quantification of liquids and determination of base
prover volumes under defined conditions. The criteria contained in this
standard allows individuals, using various computer languages on
different computer hardware (or manual calculations), to arrive at
identical results using the same standardized input data. This standard
specifies the equations for computing correction factors, rules for
rounding, the sequence of the calculations, and the discrimination
levels of all numbers to be used in these calculations.
API MPMS Chapter 13.3, Measurement Uncertainty; Second
Edition, December 2017 (``API 13.3''). This standard establishes a
methodology for developing an uncertainty analysis.
API MPMS Chapter 14, Section 3, Orifice Metering of
Natural Gas and Other Related Hydrocarbon Fluids--Concentric, Square-
edged Orifice Meters, Part 1, General Equations and Uncertainty
Guidelines; Fourth Edition, September 2012; Errata July 2013;
Reaffirmed, September 2017 (``API 14.3.1''). This standard provides
reference for engineering equations and uncertainty estimations.
API MPMS Chapter 18--Custody Transfer, Section 1--
Measurement Procedures for Crude Oil Gathered from Lease Tanks by
Truck; Third Edition, May 2018 (``API 18.1''). This standard describes
the procedures, organized into a recommended sequence of steps, for
manually determining the quantity and quality of crude oil being
transferred under field conditions.
API MPMS Chapter 21--Flow Measurement Using Electronic
Metering Systems, Section 2--Electronic Liquid Volume Measurement Using
Positive Displacement and Turbine Meters; First Edition, June 1998;
Reaffirmed October 2016 (``API 21.2''). This standard provides for the
effective utilization of electronic liquid measurement systems for
custody-transfer measurement of liquid hydrocarbons.
API Recommended Practice (RP) 12R1, Setting, Maintenance,
Inspection, Operation and Repair of Tanks in Production Service; Fifth
Edition, August 1997; Reaffirmed April 2008; Addendum 1, December 2017
(``API RP 12R1''). This recommended practice is a guide on new tank
installations and the maintenance of existing tanks. Specific
provisions from this recommended practice are identified as
requirements.
API RP 2556, Correction Gauge Tables for Incrustation;
Second Edition, August 1993; Reaffirmed November 2013 (``API RP
2556''). This recommended practice provides for correcting gauge tables
for incrustation applied to tank capacity tables. The tables in this
recommended practice show the percent of error of measurement caused by
varying thicknesses of uniform incrustation in tanks of various sizes.
The following industry standards and recommendations are proposed
for incorporation by reference, in whole or in part, in subpart K of
the proposed rule:
API MPMS Chapter 14--Natural Gas Fluids Measurement,
Section 1--Collecting and Handling of Natural Gas Samples for Custody
Transfer; Seventh Edition, May 2016; Addendum, August 2017; Errata,
August 2017 (``API 14.1''). This standard provides comprehensive
guidelines for properly collecting, conditioning, and handling
representative samples of natural gas that are at or above their
hydrocarbon dew point.
API MPMS, Chapter 14, Section 3, Orifice Metering of
Natural Gas and Other Related Hydrocarbon Fluids--Concentric, Square-
edged Orifice Meters, Part 1, General Equations and Uncertainty
Guidelines; Fourth Edition,
[[Page 2435]]
September 2012; Errata, July 2013 (``API 14.3.1''). This standard
provides engineering equations and uncertainty estimations for the
calculation of flow rate through concentric, square-edge, flange-tapped
orifice meters.
API MPMS Chapter 14, Section 3, Orifice Metering of
Natural Gas and Other Related Hydrocarbon Fluids--Concentric, Square-
edged Orifice Meters, Part 2, Specification and Installation
Requirements; Fifth Edition, March 2016; Errata 1, March 2017; Errata
2, January 2019) (``API 14.3.2''). This standard provides construction
and installation requirements, and standardized implementation
recommendations, for the calculation of flow rate through concentric,
square-edge, flange-tapped orifice meters.
API MPMS Chapter 14, Section 3, Orifice Metering of
Natural Gas and Other Related Hydrocarbon Fluids--Concentric, Square-
edged Orifice Meters, Part 3, Natural Gas Applications; Fourth Edition,
November 2013 (``API 14.3.3''). This standard is an application guide
for the calculation of natural gas flow through a flange-tapped,
concentric orifice meter.
API MPMS, Chapter 14.5, Calculation of Gross Heating
Value, Relative Density, Compressibility and Theoretical Hydrocarbon
Liquid Content for Natural Gas Mixtures for Custody Transfer; Third
Edition, January 2009; Reaffirmed November 2020 (``API 14.5''). This
standard presents procedures for calculating the following properties
of natural gas mixtures at base conditions from composition: gross
heating value, relative density (real and ideal), compressibility
factor, and theoretical hydrocarbon liquid content.
API MPMS Chapter 21.1, Flow Measurement Using Electronic
Metering Systems--Electronic Gas Measurement; Second Edition, February
2013 (``API 21.1''). This standard describes the minimum specifications
for electronic gas measurement systems (EGMs) used in the measurement
and recording of flow parameters of gaseous phase hydrocarbon and other
related fluids for custody transfer applications utilizing industry
recognized primary measurement devices.
AGA Report No. 3, Orifice Metering of Natural Gas and
Other Related Hydrocarbon Fluids; Second Edition, September 1985 (``AGA
Report No. 3''). This report provides construction and installation
requirements, and standardized implementation recommendations, for the
calculation of flow rate through concentric, square-edged, flange-
tapped orifice meters.
AGA Transmission Measurement Committee Report No. 8,
Compressibility Factors of Natural Gas and Other Related Hydrocarbon
Gases; Second Edition, November 1992 (``AGA Report No. 8''). This
report presents detailed information for precise computations of
compressibility factors and densities of natural gas and other
hydrocarbon gases, calculation uncertainty estimations, and FORTRAN
computer program listings.
GPA Midstream Standard 2166-17, Obtaining Natural Gas
Samples for Analysis by Gas Chromatography, Reaffirmed 2017 (``GPA
2166-17''). This standard recommends procedures for obtaining samples
from flowing natural gas streams that represent the compositions of the
vapor phase portion of the system being analyzed.
GPA Standard Midstream 2261-19, Analysis for Natural Gas
and Similar Gaseous Mixtures by Gas Chromatography; Revised 2019 (``GPA
2261-19''). This standard establishes a method to determine the
chemical composition of natural gas and similar gaseous mixtures within
set ranges using a gas chromatograph (CG).
GPA Midstream Standard 2198-16, Selection, Preparation,
Validation, Care and Storage of Natural Gas and Natural Gas Liquids
Reference Standard Blends; Revised 2016 (``GPA 2198-16''). This
standard establishes procedures for selecting the proper natural gas
and natural gas liquids reference standards, preparing the reference
standards for use, verifying the accuracy of composition as reported by
the manufacturer, and the proper care and storage of those reference
standards to ensure their integrity while they are in use.
V. Discussion of Proposed Changes
This proposed rule adds new sections and redesignates or revises
current sections as set forth in the table below. The proposed rule
removes all references to the ``Osage Tribal Council,'' and replaces
them with ``Osage Nation'' or ``Osage Minerals Council,'' as
applicable, because the Osage Tribal Council ceased to exist upon
ratification of the Constitution of the Osage Nation in 2006.
----------------------------------------------------------------------------------------------------------------
New section Current section Proposed changes
----------------------------------------------------------------------------------------------------------------
226.0................................... N/A........................ The proposed rule identifies the API
standards incorporated by reference in
subpart J, Oil Measurement, and the API,
AGA, and GPA standards incorporated by
reference in subpart K, Gas Measurement.
226.1................................... 226.1...................... The proposed rule defines new key terms,
updates existing definitions, and
removes definitions of terms that are no
longer used in the regulations.
226.2 (new)............................. N/A........................ The proposed rule identifies the legal
authorities that govern oil and gas
leasing and development activities
within the Osage Mineral Estate.
226.3 (new)............................. N/A........................ The proposed rule describes the
Superintendent's authority and
responsibility to administer oil and gas
leasing and development of the Osage
Mineral Estate.
226.4 (new)............................. N/A........................ The proposed rule describes ONRR's
authority and responsibility to
administer the Osage royalty management
program.
226.5................................... 226.45..................... The proposed rule clarifies the
Superintendent's authority to issue
orders and notices and adds a provision
specifying ONRR's authority to issue
orders and notices.
226.6................................... 226.31..................... The proposed rule removes the provision
requiring lessees who reside outside the
state of Oklahoma to designate in-state
process agents for the purpose of
serving notice. The proposed rule also
removes the provision providing for the
Superintendent to serve notice on
employees present on the lease if the
designated process agent is
incapacitated or absent from the state
of Oklahoma. The proposed rule adds
provisions setting forth the procedures
the Superintendent and ONRR will use to
serve official correspondence.
226.7................................... 226.7...................... No substantive change.
226.8................................... 226.4...................... The proposed rule removes the language
allowing cash payments and updates the
accepted forms of payment to include
electronic funds transfer (EFT),
certified check, cashier's check, money
order, or commercial or personal check
drawn on a solvent bank.
[[Page 2436]]
226.9................................... 226.2(c)................... The proposed rule clarifies the
Superintendent's obligations to conduct
environmental reviews and cultural
surveys prior to approving leases and
operations involving new or additional
ground-disturbance.
226.10.................................. 226.46..................... The proposed rule updates this section to
reflect amendments to the Paperwork
Reduction Act promulgated after the
section was last revised requiring the
BIA to obtain OMB approval for the
information collections in 25 CFR part
226. The proposed rule also adds
language identifying the applicable OMB
Control Numbers.
226.11 (new)............................ N/A........................ The proposed rule informs submitters of
information that the BIA and ONRR will
make records available to the public
without prior notification, subject to
exceptions for trade secrets,
confidential commercial or financial
information, and information protected
by the Privacy Act.
226.12.................................. 226.2(f)................... The proposed rule clarifies that the OMC
must submit requests for the
Superintendent to negotiate leases in
writing and provide a resolution
authorizing such negotiation. This
change reflects the BIA's and OMC's
existing practices for the submission of
leasing requests.
226.13.................................. 226.2(f)................... The proposed rule clarifies that the OMC
must submit requests for the
Superintendent to advertise lease sales
in writing and provide a resolution
authorizing such advertising. This
change reflects the BIA's and OMC's
existing practices for the submission of
lease sale requests.
226.14.................................. 226.2(a)................... The proposed rule removes the nomination
fee for lease sales and clarifies the
content and submission requirements for
lease sale nominations. These
clarifications reflect the BIA's
existing requirements for lease sale
nominations.
226.15.................................. 226.2(b)................... The proposed rule specifies that the
Superintendent will publish the Notice
of Lease Sale at least 30 calendar days
prior to the date of the sale. This
change reflects the BIA's and OMC's
existing practices for publishing such
notices.
226.16.................................. 226.2(b), 226.6(a)......... The proposed rule specifies that
successful bidders must submit 25
percent of the bonus by 4:30 p.m.
central standard time on the day of the
sale. The proposed rule also removes the
language allowing cash payments and
updates the accepted forms of payment to
electronic funds transfer (EFT),
cashier's check, or money order.
226.17.................................. 226.2(b)................... No substantive change.
226.18.................................. 226.2(f)................... The proposed rule specifies what
information offerors must include in non-
competitive lease offers submitted to
the OMC.
226.19.................................. 226.6(a)................... The proposed rule requires successful
offerors of non-competitive leases to
submit the bonus and required
documentation to the Superintendent
within 20 calendar days of the OMC's
acceptance of the offer. This change
reflects the BIA's and OMC's existing
requirements for non-competitive leases
and is consistent with the requirements
for competitive leases in the new Sec.
226.16.
226.20.................................. 226.2(d)................... The proposed rule removes oil-only and
gas-only leases and requires all leases
executed after the effective date of the
final rule to be combination oil and gas
leases.
226.21.................................. 226.9(b), 226.10........... The proposed rule combines the
regulations regarding extension of the
primary term and the term of the lease
into one section. The proposed rule
specifies the actions that constitute
``actual drilling operations'' for
purposes of obtaining an extension of
the primary term.
226.22.................................. 226.5...................... No substantive change.
226.23.................................. 226.2(e)................... The proposed rule clarifies the
prohibition on U.S. Government employees
acquiring interests in leases of the
Osage Mineral Estate.
226.24.................................. 226.15(a).................. The proposed rule specifies that lessees
must submit cooperative agreements to
the Superintendent for approval at least
90 calendar days prior to expiration of
the leases covered by the agreements.
226.25.................................. 226.15(a).................. No substantive change.
226.26.................................. 226.15(b).................. No substantive change.
226.27.................................. 226.15(b).................. No substantive change.
226.28 (new)............................ N/A........................ The proposed rule specifies the effective
date of the transfer for lease
assignments.
226.29 (new)............................ N/A........................ The proposed rule specifies that
assignors are liable for lease
obligations and compliance issues that
accrue prior to approval of the
assignment.
226.30 (new)............................ N/A........................ The proposed rule specifies that
assignees are liable for lease
obligations and compliance issues that
accrue after approval of the assignment.
226.31.................................. 226.15(c).................. No substantive change.
226.32.................................. 226.15(d).................. The proposed rule removes the provision
authorizing the Superintendent to
approve drilling contracts because it is
contrary to law and clarifies that
lessees are simply required to file
copies of drilling contracts with the
Superintendent.
226.33.................................. 226.3...................... No substantive change.
226.34.................................. 226.9(a), 226.29(a)........ The proposed rule combines the
regulations regarding lease termination
and lessees' obligations upon
termination into one section. The
proposed rule adds a provision
specifying that leases in the extended
term terminate by operation of law as of
the date production in paying quantities
ceases. The provision regarding
termination in the extended term
reflects the BIA's existing practices.
226.35.................................. 226.9(a)................... The proposed rule increases the rental
rate for leases approved after the
effective date of the final rule. The
proposed rule also requires lessees to
pay advance annual rental for the full
primary term within 15 calendar days of
the Superintendent's approval of the
lease.
[[Page 2437]]
226.36.................................. 226.11(a)(1)............... The proposed rule removes the language
requiring a royalty rate of not less
than 20 percent when the quantity of oil
from all wells in a quarter-section or
fraction thereof during any calendar
month averages 100 bbl or greater per
well, per day. The proposed rule adds
language authorizing the Superintendent
to approve an oil royalty rate that is
below the minimum royalty rate in the
regulations if it is determined to be in
the best interest of the Osage Nation.
226.37.................................. 226.11(a)(2)............... The proposed rule requires the value of
oil to be calculated using the NYMEX
Calendar Month Average Price of oil at
Cushing, Oklahoma instead of the highest
posted price by a major purchaser in
Osage County, Oklahoma.
226.38 (new)............................ N/A........................ The proposed rule specifies how to
calculate the gravity adjustment of the
NYMEX Calendar Month Average Price of
oil.
226.39.................................. 226.11(b).................. The proposed rule adds language
authorizing the Superintendent to
approve a gas royalty rate that is below
the minimum royalty rate in the
regulations if it is determined to be in
the best interest of the Osage Nation.
226.40.................................. 226.11(b).................. The proposed rule requires the value of
gas to be calculated using the ONRR
Monthly Index Zone Price for Oklahoma
Zone 1 instead of the market value of
the gas and products extracted
therefrom.
226.41.................................. 226.11(c).................. The proposed rule requires lessees to
submit minimum royalty payments to ONRR
instead of the Superintendent.
226.42.................................. 226.11(a)(3)............... The proposed rule revises the royalty-in-
kind provision to allow the OMC to take
both oil and gas royalty-in-kind and
adds a provision setting forth notice
requirements for the OMC initiating and
terminating royalty-in-kind status.
226.43.................................. 226.13(a) and (c).......... The proposed rule requires lessees and
purchasers to submit royalty payments to
ONRR instead of the Superintendent and
establishes a new due date for royalty
payments. The proposed rule also adds a
provision specifying the procedure for
payors to recoup overpayments.
226.44.................................. 226.14..................... The proposed rule removes the language
requiring the Superintendent's approval
of royalty payment contracts and
division orders and clarifies that
lessees are simply required to file such
contracts and division orders with the
Superintendent prior to removing
production from the lease.
226.45.................................. 226.13(b).................. The proposed rule requires lessees to
submit royalty reports to ONRR
electronically, subject to certain
exceptions, and establishes a new due
date for reporting.
226.46.................................. 226.30..................... The proposed rule requires lessees to
retain rental, royalty, and payment
records for a minimum of six years
unless the Superintendent or ONRR direct
otherwise. The proposed rule also adds a
provision requiring lessees to make such
records available to ONRR upon request.
226.47.................................. 226.12..................... The proposed rule updates this section by
requiring the U.S. Government to
purchase oil produced from the Osage
Mineral Estate at the price set forth in
Sec. 226.37.
226.48 (new)............................ N/A........................ The proposed rule authorizes ONRR to
conduct audits and reviews of compliance
with rental, royalty, and other payment
and reporting requirements.
226.49 (new)............................ N/A........................ The proposed rule exempts existing lease
(quarter-section) and collective bonds
from certain changes to the bonding
requirements.
226.50.................................. 226.6...................... The proposed rule adds a provision
identifying the accepted types of
performance bonds.
226.51.................................. 226.6(a) and (c)........... The proposed rule replaces the $5,000
lease bond for each quarter-section or
fraction thereof covered by the lease
with an individual well bond of $6 per
foot of measured or projected well
depth.
226.52.................................. 226.6(a) and (b)........... The proposed rule combines the collective
and nationwide bond provisions into one
section. The proposed rule changes the
collective bond (covering all leases up
to 10,240 acres) to a countywide bond
covering only those operations in Osage
County up to 10,240 acres and increases
the bond amount from $50,000 to $75,000.
226.53.................................. 226.6(d)................... The proposed rule clarifies the
conditions that justify the
Superintendent increasing the required
bond amount and adds a provision placing
a limit on the amount of any such
increase.
226.54 (new)............................ N/A........................ The proposed rule specifies that the
Superintendent has authority to call for
the forfeiture of performance bonds and
clarifies lessees' obligations upon
default. This change reflects the
Superintendent's existing authority, as
all bonds are payable to the
Superintendent. The proposed rule adds a
provision specifying that the United
States or OMC may take action to recover
from lessees all costs in excess of the
amount collected under the bond if an
obligation in default exceeds the face
amount of the bond.
226.55 (new)............................ N/A........................ The proposed rule specifies that the
period of liability under a performance
bond will not terminate, and the bond
will not be released, until all lease
obligations have been satisfied. This
reflects the BIA's existing practices
for the release of bonds.
226.56 (new)............................ N/A........................ The proposed rule requires bonding for
geophysical exploration activities,
subject to certain exceptions for
existing lessees.
226.57 (new)............................ N/A........................ The proposed rule specifies that the
Superintendent has authority to call for
the forfeiture of geophysical
exploration bonds. This is consistent
with the Superintendent's authority for
performance bonds for all other oil and
gas operations within the Osage Mineral
Estate.
[[Page 2438]]
226.58 (new)............................ N/A........................ The proposed rule specifies that the
period of liability under a geophysical
exploration bond will not terminate, and
the bond will not be released, until all
permit obligations have been satisfied.
This is consistent with the BIA's
existing practices for the release of
performance bonds for all other oil and
gas operations within the Osage Mineral
Estate.
226.59.................................. 226.19(a).................. The proposed rule adds a provision
requiring lessees and permittees to
properly maintain installations and
equipment and comply with the National
Electrical Code.
226.60.................................. 226.30..................... The proposed rule clarifies the
Superintendent's authority to inspect
and investigate operations.
226.61.................................. 226.16(a).................. The proposed rule clarifies the language
regarding the commencement of
operations, expressly stating that
operations may not commence until the
Superintendent approves a lease or
geophysical exploration permit, as
applicable.
226.62.................................. 226.17..................... No substantive change.
226.63.................................. 226.18..................... The proposed rule adds a provision
requiring lessees and permittees to send
meeting requests to surface owners by
certified mail. The proposed rule also
adds a provision authorizing the
Superintendent to approve the
commencement of operations if a meeting
request cannot be delivered to the
surface owner's last known address or
the surface owner fails to accept the
request within 30 calendar days of
receiving it.
226.64.................................. 226.19(b) through (d)...... The proposed rule combines the
regulations regarding commencement money
for operations and tank siting fees into
one section. The proposed rule increases
the amount of commencement money for
drilling and reentering wells and siting
tanks and adds a provision requiring
lessees and permittees to pay
commencement money for the acreage
occupied during seismic surveys using
vibroseis. The proposed rule also adds a
provision stating that commencement
money that cannot be delivered to the
surface owner's last known address or
that the surface owner refuses is deemed
forfeited.
226.65.................................. 226.19(a), 226.24.......... The proposed rule combines the
regulations regarding the use of surface
lands and water into one section. No
substantive changes.
226.66.................................. 226.16(b)(1) and (c); The proposed rule combines the
226.33. regulations regarding drilling
operations and line drilling
requirements into one section. The
proposed rule specifies that lessees
must provide the Superintendent with
five calendar days' notice of drilling
operations. The proposed rule adds a
line drilling requirement imposing a
setback from certain water sources. This
setback is consistent with the BIA's
existing permit conditions under the
Osage County Oil and Gas Final
Environmental Impact Statement (2020).
226.67.................................. 226.36..................... The proposed rule requires lessees to
obtain the Superintendent's prior
approval to drill wells that deviate
significantly from the vertical and
conduct directional surveys if deviation
occurs without prior approval.
226.68.................................. 226.40..................... No substantive change.
226.69.................................. 226.16(b)(1) and (2), (c);. The proposed rule specifies that lessees
must provide the Superintendent with at
least five calendar days' notice of
workover operations. The proposed rule
adds a provision clarifying that prior
approval and a subsequent report of
operations are not required for certain
well maintenance activities. This change
reflects the BIA's existing practices
with respect to well maintenance
activities.
226.70 (new)............................ N/A........................ The proposed rule establishes testing,
training, operational, and safety
requirements for drilling and workover
operations in Hydrogen Sulfide (H2S)
areas.
226.71.................................. 226.32(b), (d)............. The proposed rule adds a provision
requiring lessees to conduct reasonable
tests of the mechanical integrity of
downhole equipment.
226.72.................................. 226.28(a).................. The proposed rule clarifies the language
regarding temporary abandonment, more
clearly stating that lessees must obtain
the Superintendent's approval to
temporarily abandon a well for more than
30 calendar days.
226.73.................................. 226.28(a) and (b); The proposed rule combines the
226.29(c) and (d). regulations regarding permanent
abandonment and plugging obligations
into one section. The proposed rule
removes the plugging application fee and
requirement that oil-only and gas-only
lessees offer wells to one another prior
to abandonment. The proposed rule
specifies that lessees must provide the
Superintendent with five calendar days'
notice of plugging operations.
226.74.................................. 226.32(a), (c), and (e).... The proposed rule requires lessees to
submit certain information together with
the subsequent report of hydraulic
fracturing operations and adds a
provision specifying the procedure for
lessees to withhold confidential
information regarding such operations.
The proposed rule also clarifies that
lessees must retain well records and
reports for a minimum of six years
unless the Superintendent directs
otherwise.
226.75.................................. 226.34..................... The proposed rule adds a provision
requiring lessees to mark wells that are
permanently plugged and abandoned.
226.76.................................. 226.22(a), 226.35.......... The proposed rule combines the
regulations regarding the prevention of
pollution and protection of formations
into one section. The proposed rule
specifies that lessees and permittees
must conduct surveys and tests of the
measures taken to protect fresh water
and mineral bearing formations and
provide the results to the
Superintendent upon request.
[[Page 2439]]
226.77.................................. 226.22(b) through (e)...... The proposed rule adds provisions
prohibiting lessees from constructing
pits in certain sensitive locations
consistent with the BIA's existing
permit conditions under the Osage County
Oil and Gas Final Environmental Impact
Statement (2020). The proposed rule also
adds a provision requiring the
Superintendent's prior approval for the
land application of drilling fluids.
226.78 (new)............................ N/A........................ The proposed rule requires lessees to
remove fire hazards from well sites and
facilities and safely dispose of waste
oil. These requirements are consistent
with the BIA's existing permit
conditions under the Osage County Oil
and Gas Final Environmental Impact
Statement (2020).
226.79 (new)............................ N/A........................ The proposed rule requires a geophysical
exploration permit to conduct
geophysical exploration operations on
both leased and unleased lands.
226.80 (new)............................ N/A........................ The proposed rule specifies that lessees
and permittees must provide the
Superintendent with five calendar days'
notice of geophysical exploration
operations.
226.81 (new)............................ N/A........................ The proposed rule requires lessees and
permittees to submit subsequent reports
of geophysical exploration operations to
the Superintendent.
226.82.................................. 226.20..................... No substantive change.
226.83.................................. 226.21..................... No substantive change.
226.84.................................. 226.9(a)................... The proposed rule specifies that lessees
must place oil and gas into marketable
condition at no cost to the lessor. This
change is consistent with current
industry practices within the Osage
Mineral Estate.
226.85.................................. 226.13(b).................. The proposed rule requires lessees to
submit production reports to ONRR
electronically, subject to certain
exceptions, and establishes a new due
date for production reports.
226.86 (new)............................ N/A........................ The proposed rule requires lessees to
submit site facility diagrams to the
Superintendent and specifies the format
and content of such diagrams.
226.87 (new)............................ N/A........................ The proposed rule requires lessees to use
FMP numbers when reporting production to
ONRR.
226.88 (new)............................ N/A........................ The proposed rule specifies what
information production records must
contain and requires lessees to maintain
such records for a minimum of six years
unless the Superintendent or ONRR direct
otherwise. The proposed rule also
requires lessees, purchasers, and
transporters to provide production
records to ONRR upon request.
226.89.................................. 226.23..................... No substantive change.
226.90.................................. 226.37..................... No substantive change.
226.91 (new)............................ N/A........................ The proposed rule requires lessees to pay
compensatory royalty for avoidably lost
or wasted production. This change
reflects the BIA's existing requirement
to pay royalty for lost and wasted
production. The proposed rule specifies
when production is considered avoidably
and unavoidably lost or wasted.
226.92 (new)............................ N/A........................ The proposed rule sets forth lessees'
responsibilities for protecting oil and
gas resources from drainage.
226.93 (new)............................ N/A........................ The proposed rule requires lessees to pay
compensatory royalty for drainage if
protective action is not taken within a
reasonable time and specifies how
compensatory royalty will be calculated.
226.94 (new)............................ N/A........................ The proposed rule requires the use of
seals on appropriate valves at oil
storage and sales facilities and
prohibits tampering with such valves.
226.95 (new)............................ N/A........................ The proposed rule requires the use of
seals on oil measurement system
components.
226.96 (new)............................ N/A........................ The proposed rule requires transporters
removing oil from storage tanks to
possess run tickets, trip logs, and
manifests.
226.97 (new)............................ N/A........................ The proposed rule requires any person
transporting oil or gas to possess
documentation indicating the first
purchaser and authorizes the
Superintendent and law enforcement to
conduct vehicle inspections.
226.98 (new)............................ N/A........................ The proposed rule requires lessees,
purchasers, and transporters to record
certain information when water is
drained from tanks holding oil.
226.99 (new)............................ N/A........................ The proposed rule requires lessees to
record certain information when oil is
removed from storage and used on the
lease or unit for hot oiling, clean up,
and completion operations. The proposed
rule also requires lessees to report all
production removed from storage and used
on a different lease to ONRR.
226.100 (new)........................... N/A........................ The proposed rule specifies the records
that lessees must maintain for each
seal.
226.101 (new)........................... N/A........................ The proposed rule requires lessees to
obtain the Superintendent's approval for
off-lease measurement of production.
226.102................................. 226.41..................... The proposed rule specifies that lessees
must report spills, thefts, mishandling
of production, accidents, and fires to
both the Superintendent and surface
owners immediately upon discovery and
requires lessees to submit incident
reports with proposed contingency or
remediation plans to the Superintendent.
This change reflects the BIA's current
requirements for reporting of such
incidents. The proposed rule adds a
provision requiring lessees to provide
surface owners with both emergency and
written notification of such incidents.
226.103 (new)........................... N/A........................ The proposed rule prohibits bypasses of
meters and tampering with oil
measurement devices, the components of
such devices, and the measurement
process and imposes the maximum penalty
for such violations.
226.104 (new)........................... N/A........................ The proposed rule establishes the
timeframe for complying with the new
requirements for oil measurement
equipment and procedures.
226.105................................. N/A........................ [Reserved]
[[Page 2440]]
226.106 (new)........................... N/A........................ The proposed rule establishes
requirements for oil volume uncertainty
levels, measurement bias, and equipment
verification.
226.107................................. 226.38..................... The proposed rule specifies that tank
gauging may be used to measure oil and
updates requirements for the use and
calibration of oil storage tanks.
226.108................................. 226.38..................... The proposed rule specifies the required
tank gauging procedures.
226.109................................. 226.38..................... The proposed rule specifies that Lease
Automatic Custody Transfer (LACT)
systems may be used to measure oil and
sets forth general requirements for LACT
systems.
226.110................................. 226.38..................... The proposed rule identifies required
LACT system equipment and sets forth
standards for operating LACT system
components.
226.111................................. 226.38..................... The proposed rule specifies that Coriolis
Measurement Systems (CMS) may be used to
measure oil and sets forth general
requirements for CMS and CMS components.
226.112................................. 226.38..................... The proposed rule establishes Coriolis
meter operating requirements.
226.113 (new)........................... N/A........................ The proposed rule sets forth requirements
for volumetric meter proving.
226.114 (new)........................... N/A........................ The proposed rule requires the completion
and submission of run tickets for tank
gauging, LACT systems, and CMS. This
change codifies the BIA's existing
requirements with respect to run
tickets.
226.115................................. 226.38..................... The proposed rule specifies that the
Superintendent's approval is required to
use methods of oil measurement other
than tank gauging, LACT system, or CMS.
226.116 (new)........................... N/A........................ The proposed rule prohibits the sale and
disposal of waste oil without the
Superintendent's approval. This change
codifies the BIA's existing requirement.
226.117 (new)........................... N/A........................ The proposed rule prohibits bypasses of
meters. The proposed rule also prohibits
tampering with any measurement device,
component of a measurement device, or
the measurement process. The proposed
rule imposes the maximum penalty for
such violations.
226.118 (new)........................... N/A........................ The proposed rule establishes the
timeframe for complying with the new
requirements for gas measurement
equipment and procedures.
226.119................................. N/A........................ [Reserved]
226.120 (new)........................... N/A........................ The proposed rule establishes
requirements for gas flow rate and
heating value uncertainty, measurement
bias, and equipment verification.
226.121................................. 226.39..................... The proposed rule specifies the standards
for orifice plates and meter tubes and
sets forth inspection requirements.
226.122................................. 226.39..................... The proposed rule establishes standards
for the use of mechanical recorders.
226.123 (new)........................... N/A........................ The proposed rule establishes
requirements for the verification and
calibration of mechanical recorders,
correction of reported gas volumes, and
certification of test equipment.
226.124 (new)........................... N/A........................ The proposed rule specifies what
information integration statements must
contain and requires lessees to retain
integration statements.
226.125................................. 226.39..................... The proposed rule establishes standards
for the use of electronic gas
measurement (EGM) systems.
226.126 (new)........................... N/A........................ The proposed rule establishes
requirements for the verification and
calibration of transducers, correction
of reported gas volumes, and
certification of test equipment.
226.127 (new)........................... N/A........................ The proposed rule provides the gas flow
rate, volume, and average value
calculations.
226.128 (new)........................... N/A........................ The proposed rule requires lessees to
retain certain logs and records and make
them available to the Superintendent
upon request.
226.129 (new)........................... N/A........................ The proposed rule specifies the methods
of gas sampling and analysis that may be
used.
226.130 (new)........................... N/A........................ The proposed rule establishes standards
for the location, design, and type of
sampling probes and sample tubing size.
226.131 (new)........................... N/A........................ The proposed rule establishes the general
requirements for taking spot samples.
226.132 (new)........................... N/A........................ The proposed rule specifies the methods
of spot sampling that may be used.
226.133 (new)........................... N/A........................ The proposed rule specifies the frequency
with which lessees must take and analyze
spot samples.
226.134 (new)........................... N/A........................ The proposed rule establishes
specifications for composite sampling
methods.
226.135 (new)........................... N/A........................ The proposed rule establishes
requirements for the installation,
operation, verification, and calibration
of on-line gas chromatographs.
226.136 (new)........................... N/A........................ The proposed rule establishes
requirements for the installation,
operation, verification, and calibration
of gas chromatographs.
226.137 (new)........................... N/A........................ The proposed rule identifies the
components of gas that must be analyzed
and the frequency with which component
analysis must occur.
226.138 (new)........................... N/A........................ The proposed rule specifies what
information gas analysis reports must
contain.
226.139 (new)........................... N/A........................ The proposed rule specifies the effective
date of a spot or composite gas sample.
226.140 (new)........................... N/A........................ The proposed rule establishes
requirements for calculating the heating
value, average heating value, and volume
of a gas sample.
226.141 (new)........................... N/A........................ The proposed rule establishes
requirements for reporting gross and
real heating values and volumes.
226.142................................. 226.27(b).................. The proposed rule updates the provision
by requiring the Osage Nation and Tribal
members to pay for gas at the price set
forth in Sec. 226.40.
226.143................................. 226.27(b).................. The proposed rule updates the provision
by requiring the lessee to pay royalty
on all gas furnished to the Osage Nation
and Tribal members at the rate set forth
in Sec. 226.39.
[[Page 2441]]
226.144................................. 226.11(a)(1) and (b)(2).... No substantive change.
226.145 (new)........................... N/A........................ The proposed rule identifies the uses of
production on a lease or unit that do
not require the Superintendent's prior
approval for royalty-free treatment.
226.146 (new)........................... N/A........................ The proposed rule identifies the uses of
production on a lease or unit that
require the Superintendent's prior
approval for royalty-free treatment.
226.147 (new)........................... N/A........................ The proposed rule identifies the uses of
production off the lease or unit that do
not require the Superintendent's prior
approval of royalty-free treatment.
226.148 (new)........................... N/A........................ The proposed rule identifies the uses of
production off the lease or unit that
require the Superintendent's prior
approval of royalty-free treatment.
226.149 (new)........................... N/A........................ The proposed rule sets forth requirements
for the measurement and reporting of
royalty-free volumes of oil and gas
used.
226.150 (new)........................... N/A........................ The proposed rule specifies that lessees
do not need to own or lease the
equipment or facility that uses royalty-
free oil and gas.
226.151 (new)........................... N/A........................ The proposed rule sets forth procedures
for requesting royalty-free use of oil
and gas.
226.152................................. 226.37..................... The proposed rule adds a provision
prohibiting the venting and flaring of
gas without the Superintendent's prior
approval. The proposed rule also
requires all flares and combustible
devices to be equipped with an automatic
ignition system. This reflects the BIA's
existing requirements for venting and
flaring and is consistent with the BIA's
existing permit conditions under the
Osage County Oil and Gas Final
Environmental Impact Statement (2020).
226.153 (new)........................... N/A........................ The proposed rule adds a provision
prohibiting the venting and flaring of
gas-well gas unless it is unavoidably
lost.
226.154 (new)........................... N/A........................ The proposed rule authorizes the venting
and flaring of oil-well gas in
accordance with Sec. Sec. 226.155,
226.156, and 226.157.
226.155 (new)........................... N/A........................ The proposed rule requires gas to be
flared, rather than vented, subject to
certain exceptions.
226.156 (new)........................... N/A........................ The proposed rule authorizes the venting
and flaring of gas during certain tests,
well maintenance activities, and
emergencies.
226.157 (new)........................... N/A........................ The proposed rule sets forth the
requirements for measuring and reporting
the volumes of gas vented and flared.
226.158................................. 226.42..................... The proposed rule identifies the remedies
the Superintendent may utilize to
address violations of lease or permit
terms and conditions, the regulations,
and orders or notices.
226.159................................. 226.43..................... The proposed rule updates the list of
lease operation violations that will
result in immediate assessments.
226.160 (new)........................... N/A........................ The proposed rule authorizes the
Superintendent to issue assessments if a
lessee fails to commence or perform an
operation within five calendar days of
an order to do so if the Superintendent
performs the operation or must retain a
third-party to perform the operation.
226.161 (new)........................... N/A........................ The proposed rule sets forth the
procedure the Superintendent will use to
notify lessees of lease violations that
have a period to correct prior to the
assessment of penalties and the penalty
amounts imposed if violations are not
timely corrected.
226.162 (new)........................... N/A........................ The proposed rule sets forth the
procedure the Superintendent will use to
notify lessees of lease violations that
do not have a period to correct prior to
the assessment of penalties and the
penalty amounts imposed for such
violations.
226.163 (new)........................... N/A........................ The proposed rule specifies the factors
the Superintendent will consider in
determining that amount of the penalty
to assess.
226.164................................. 226.28(c).................. The proposed rule clarifies the
circumstances under which the
Superintendent may take shut-in action.
226.165................................. 226.29(b); 226.42.......... The proposed rule specifies the
circumstances under which the
Superintendent may cancel a lease or
permit and the procedure for cancelling
a lease or permit.
226.166................................. 226.42..................... The proposed rule specifies that interest
on unpaid and underpaid civil penalties
and assessments will be charged at the
IRS underpayment rate or such other rate
as the Superintendent may prescribe.
226.167 (new)........................... N/A........................ The proposed rule identifies the remedies
ONRR may utilize to address violations
of lease or permit terms and conditions,
the regulations, and orders or notices.
226.168 (new)........................... N/A........................ The proposed rule authorizes ONRR to
issue assessments for incorrect or late
royalty and production reporting and
specifies the amount of such
assessments.
226.169 (new)........................... N/A........................ The proposed rule authorizes ONRR to
issue assessments for failing to submit
the correct payment amount or providing
inadequate or erroneous information and
specifies the amounts of such
assessments.
226.170 (new)........................... N/A........................ The proposed rule sets forth the
procedure ONRR will use to notify
reporters and payors of violations that
have a period to correct prior to the
assessment of penalties and the penalty
amounts imposed if violations are not
timely corrected.
226.171 (new)........................... N/A........................ The proposed rule sets forth the
procedure ONRR will use to notify
reporters and payors of violations that
do not have a period to correct prior to
the assessment of penalties and the
penalty amounts imposed.
226.172 (new)........................... N/A........................ The proposed rule specifies the factors
ONRR will consider in determining the
amount of the penalty to assess.
226.173 (new)........................... N/A........................ The proposed rule specifies the due date
for remitting payment of penalties and
assessments to ONRR and that interest on
unpaid and underpaid penalty and
assessment amounts will be charged at
the rate set forth in Sec. 226.166(b).
[[Page 2442]]
226.174 (new)........................... N/A........................ The proposed rule specifies the actions
ONRR may take to collect unpaid civil
penalties.
226.175 (new)........................... N/A........................ The proposed rule specifies that ONRR
will refer past due debts to the U.S.
Treasury for collection or tax refund
offset and may assess administrative
costs.
226.176................................. 226.43(j).................. No substantive change.
226.177................................. 226.44..................... The proposed rule clarifies the
procedures for filing administrative
appeals of decisions the Superintendent
and Regional Director issue.
226.178 (new)........................... N/A........................ The proposed rule sets forth the
procedures for filing administrative
appeals of orders that ONRR issues.
226.179 (new)........................... N/A........................ The proposed rule specifies the
conditions for suspension of compliance
with an ONRR order during an
administrative appeal.
226.180 (new)........................... N/A........................ The proposed rule sets forth the
requirements for posting an appeal bond
or other surety on an appellant's behalf
for administrative appeals of ONRR
orders.
226.181 (new)........................... N/A........................ The proposed rule specifies when an
obligation to comply with an ONRR order
is suspended due to judicial review.
226.182 (new)........................... N/A........................ The proposed rule specifies when ONRR
will collect bonds and other surety
instruments posted for administrative
appeals.
226.183 (new)........................... N/A........................ The proposed rule specifies that the ONRR
bond-approving officer's determination
of the required surety amount is not
subject to appeal.
226.184 (new)........................... N/A........................ The proposed rule sets forth the
standards for ONRR-specified surety
instruments.
226.185 (new)........................... N/A........................ The proposed rule explains how ONRR will
determine the bond or surety instrument
amount.
Appendix A.............................. N/A........................ Table of Atmospheric Pressures to be used
with Sec. Sec. 226.123(a)(7) and
(c)(10), 226.124(c), 226.126(a)(3), and
226.127(b).
----------------------------------------------------------------------------------------------------------------
VI. Procedural Matters
A. Regulatory Planning and Review (Executive Orders 12866 and 13563)
Executive Order 12866 provides that the Office of Information and
Regulatory Affairs (OIRA) at the Office of Management and Budget (OMB)
will review all significant rules. OIRA determined that this proposed
rule is not significant.
Executive Order 13563 reaffirms the principles of Executive Order
12866, while calling for improvements in the Nation's regulatory system
to promote predictability, to reduce uncertainty, and to use the best,
most innovative, and least burdensome tools for achieving regulatory
ends. The Executive Order directs agencies to consider regulatory
approaches that reduce burdens and maintain flexibility and freedom of
choice for the public where these approaches are relevant, feasible,
and consistent with regulatory objectives. Executive Order 13563
further emphasizes that regulations must be based on the best available
science and that the rulemaking process must allow for public
participation and an open exchange of ideas. We developed this proposed
rule in a manner consistent with these requirements.
B. Regulatory Flexibility Act
The Regulatory Flexibility Act (5 U.S.C. 601, et seq.) (RFA)
requires Federal agencies to prepare a regulatory flexibility analysis
for rules subject to notice-and-comment rulemaking requirements under
the Administrative Procedure Act (5 U.S.C. 500, et seq.) to determine
whether a regulation would have a significant economic impact on a
substantial number of small entities. The BIA does not believe the
proposed rule would have a significant economic impact on a substantial
number of small entities. Accordingly, a regulatory flexibility
analysis is not required by the RFA. Although such analysis is not
required, BIA performed an initial regulatory flexibility analysis
pursuant to section 603 of the RFA as part of its Regulatory Impact
Analysis (RIA). The IFRA, included as Appendix B to the RIA, analyzes
impacts on small entities that may be affected by the proposed rule and
is available upon request (see ADDRESSES). The IFRA for the proposed
rule uses the best available information to identify potential impacts
on small entities.
Small entities include small businesses, small governmental
jurisdictions, and small organizations, as defined by section 601 of
the RFA. A small entity is one that is independently owned and operated
and is not dominant in its field of operation. The small entities most
likely to be impacted by the proposed rule are small businesses in the
mining sector; impacts to small governmental jurisdictions and small
organizations are not anticipated. The Small Business Administration
(SBA) defines small businesses in the crude petroleum and natural gas
extraction industry as those with 1,250 employees or less. For
subsector mining support activities, the SBA defines small businesses
as drilling contractors with 1,000 employees or less and service
companies with less than $41.5 million per year in revenues. Under
these size standards, most oil and gas lessees and supporting entities
within the Osage Mineral Estate would be classified as small
businesses. Accordingly, the proposed rule would likely impact a
substantial number of small entities within the Osage Mineral Estate.
Using the best available data for the past three years of
production (2018-2020), there were an average of 223 lessees actively
and exclusively producing oil from the Osage Mineral Estate, 5 lessees
actively and exclusively producing gas from the Osage Mineral Estate,
and 59 lessees actively producing both oil and gas from the Osage
Mineral Estate, for a combined average of 286 lessees actively
producing oil and gas. The volume of production varies substantially
across lessees, with a substantial number of smaller lessees producing
marginal volumes of oil and gas and several larger lessees producing
the majority of annual production from the Osage Mineral Estate. For
example, two lessees produced over 250,000 barrels of oil annually
between 2018 and 2020, comprising 41 percent of all oil production from
the Osage Mineral Estate during that period. In contrast, approximately
100 lessees during the same period produced less than 1,000 barrels of
oil annually. The allocation of production for gas is similarly skewed.
To estimate the economic impacts on small entities, the IFRA
estimates costs of the proposed rule for ``average'' lessees (286
active lessees) by assuming that lessees produce an average volume
[[Page 2443]]
of oil and gas, that costs are shared equally across lessees, and that
small entities would bear all costs of the proposed rule. The estimated
costs of the proposed rule (including compliance costs, reporting and
recordkeeping costs, and other payments) are $18,000 to $26,000 per
year for ``average'' lessees, which could represent between 15 to 65
percent of annual profits depending on the lessee. As the IFRA assumes
that costs are shared equally across lessees, however, the estimated
per entity costs are higher than would be expected for lessees with
small production volumes and lower than would be expected for lessees
with large production volumes. For example, a lessee producing marginal
oil volumes will have lower impacts from a change in the valuation of
oil for royalty purposes than a lessee producing the ``average'' volume
of oil.
The BIA does not believe the proposed rule would conflict with,
duplicate, or overlap any relevant Federal rules in a way that would
unnecessarily add cumulative regulatory burdens on small entities
without any gain in regulatory benefits. BIA invites public comments
identifying any Federal rules that may conflict with, duplicate, or
overlap the proposed rule.
C. Small Business Regulatory Enforcement Fairness Act
This proposed rule is not a major rule under the Small Business
Regulatory Enforcement Fairness Act, 5 U.S.C. 804(2). This proposed
rule would not have an annual effect on the economy of $100 million or
more; would not cause a major increase in the costs or prices for
consumers, individual industries, Federal, State, local government
agencies, or geographic regions; and would not have significant adverse
effects on competition, employment, investment, productivity,
innovation, or the ability of U.S.-based enterprises to compete with
foreign-based enterprises.
D. Unfunded Mandates Reform Act
This proposed rule would not impose an unfunded mandate on State,
local, or Tribal governments or the private sector of $100 million or
more per year. The proposed rule would not have a significant or unique
effect on State, local, or Tribal governments or the private sector. A
statement containing the information required by the Unfunded Mandates
Reform Act, 2 U.S.C. 1531, et seq., is not required for this proposed
rule.
E. Takings (Executive Order 12630)
This proposed rule would not constitute a taking of private
property or otherwise have takings implications under Executive Order
12630. The proposed rule would revise certain operational and
administrative requirements for existing lessees. All such operations
are subject to lease terms and conditions and a current regulation
expressly requiring compliance with amendments to the regulations
except that the term of the lease, acreage, rental rate, and royalty
rate may not be changed absent agreement by both parties to the lease.
The proposed rule conforms to those requirements. A takings implication
assessment is not required.
F. Federalism (Executive Order 13132)
Under the criteria in Executive Order 13132, this proposed rule
would not have a substantial direct effect on the States, the
relationship between the Federal Government and the States, or the
distribution of power and responsibilities among the various levels of
government. A federalism impact statement is not required.
G. Civil Justice Reform (Executive Order 12988)
This proposed rule complies with the requirements of Executive
Order 12988. Specifically, this proposed rule was reviewed to eliminate
errors and ambiguity and written to minimize litigation. In addition,
this proposed rule was written in clear language and contains clear
legal standards.
H. Consultation With Indian Tribal Governments (Executive Order 13175)
The BIA evaluated this proposed rule under the criteria set forth
in Executive Order 13175 and in accordance with Departmental policy to
identify possible effects on federally recognized Indian Tribes and
Indian trust assets. This proposed rule applies to oil and gas leasing
and development activities within the Osage Mineral Estate in Osage
County, Oklahoma. As the Osage Mineral Estate is held in trust by the
United States for the benefit of the Osage Nation, this proposed rule
has the potential to affect the Osage Nation.
On September 22, 2016, the BIA sent letters to the Osage Nation and
Osage Minerals Council inviting their participation in government-to-
government consultation to discuss potential revision of the
regulations in this part. Both the Osage Nation and Osage Minerals
Council expressed an interest in such consultation. On October 25,
2016, the BIA held a consultation with the Osage Nation, Osage Minerals
Council, and their legal counsel in Pawhuska, Oklahoma and the parties
agreed that revision of the regulations was appropriate. As part of the
rulemaking effort, the BIA proposed that the process include an
opportunity for the Osage Nation and Osage Minerals Council to provide
input on proposed revisions to the regulations prior to the BIA
preparing the proposed rule for publication in the Federal Register.
The parties agreed that the BIA would prepare a discussion draft
revising the regulations, provide it to the Osage Nation and Osage
Minerals Council for review and comment, and hold a second government-
to-government consultation to discuss Tribal representatives' feedback.
Thereafter, the BIA would begin preparation of the proposed rule.
On August 18, 2020, the BIA provided the Osage Nation and Osage
Minerals Council with the discussion draft revising the regulations in
25 CFR part 226. The BIA proposed that the parties conduct the second
government-to-government consultation to receive the Tribe's feedback
on the discussion draft in November 2020. On October 7, 2020, the Osage
Minerals Council requested that the review period for the discussion
draft be extended to February 1, 2021. The BIA agreed to the extension.
On December 16, 2020, the Osage Minerals Council requested an
additional government-to-government consultation prior to providing
feedback on the discussion draft. The BIA agreed to conduct an
additional consultation, but the Osage Nation and Osage Minerals
Council did not respond to communications attempting to schedule the
consultation.
On February 11, 2021, the Director of the Bureau of Indian Affairs,
exercising the delegated authority of the Assistant Secretary--Indian
Affairs, sent a letter to the Osage Nation and Osage Minerals Council
advising of the deadline for scheduling the additional consultation
requested and providing feedback on the discussion draft. On February
25, 2021, the Osage Minerals Council responded and declined the BIA's
invitation to provide written feedback on the discussion draft and
participate in government-to-government consultations relating thereto.
The BIA advised the Osage Nation and Osage Minerals Council that they
would still have the opportunity to provide feedback following
publication of the proposed rule in the Federal Register.
On February 22, 2022, the Osage Minerals Council sent a letter to
the Assistant Secretary--Indian Affairs requesting that the BIA not
publish a proposed rule based on the discussion
[[Page 2444]]
draft the Council received in 2020 and, instead, work with the Council
to prepare a new set of regulations. The Assistant Secretary--Indian
Affairs spoke with the Chairman of the Osage Minerals Council by phone
and explained that the proposed rule had already been prepared and the
BIA was in the process of completing the procedural requirements for
publication. The Assistant Secretary--Indian Affairs advised that the
BIA remained open to consulting with the Osage Nation and Osage
Minerals Council following publication of the proposed rule in the
Federal Register and noted that written feedback can also be provided
as part of the public comment process.
I. Paperwork Reduction Act
All information collections require approval under the Paperwork
Reduction Act of 1995 (PRA), 44 U.S.C. 3501, et seq. We may not conduct
or sponsor, and you are not required to respond to, a collection of
information unless it displays a currently valid Office of Management
and Budget (OMB) Control Number. There are BIA and ONRR information
collection requirements in this proposed rule. The BIA is proposing to
renew its information collection with revisions (OMB Control No. 1076-
0180) and ONRR is proposing to renew two information collections with
revisions (OMB Control Nos. 1012-0004 and 1012-0006).
1. OMB Control Number 1076-0180 (BIA)
The OMB has reviewed and approved information collections for the
existing regulations in 25 CFR part 226, which are assigned OMB Control
No. 1076-0180. The BIA is proposing to renew information collection
1076-0180 with revisions. The following BIA revisions to reporting and
recordkeeping requirements in the proposed rule require OMB's approval:
----------------------------------------------------------------------------------------------------------------
Section(s) Proposed revision(s) to OMB 1076-0180 OMB 1076-0180 form(s)
----------------------------------------------------------------------------------------------------------------
226.6(b)................................ Lessees must provide the name and address Osage Form A--Lease
for a designated point of contact upon Contact of Record.
whom the Superintendent can serve
official correspondence regarding the
lease and operations thereon.
226.9(a)................................ Lessees may submit a draft environmental None.
assessment (EA) for proposed drilling
operations and any other proposed ground-
disturbing activities occurring outside
the existing well pad. This requirement
is the same as the requirement in
existing Sec. 226.2(c).
226.9(b)................................ Lessees must submit a Cultural Resources None.
Survey for proposed drilling operations
and any other proposed ground-disturbing
activities occurring outside the existing
well pad if the location of the
operations or activities is not covered
by a prior survey. This requirement is
the same as the requirement in existing
Sec. 226.2(c).
226.12(b)............................... The Osage Minerals Council (OMC) may None.
request that the Superintendent negotiate
a non-competitive lease with a
prospective lessee on its behalf by
submitting a Resolution authorizing the
Superintendent to undertake such action.
This requirement is the same as the
requirement in existing Sec. 226.2(f).
226.13(a)............................... The OMC may request that the None.
Superintendent advertise a competitive
lease sale by submitting a Resolution
that specifies the proposed location,
date, and time of the lease sale as well
as the minimum acceptable bid. This
requirement is the same as the
requirement in existing Sec. 226.2(f).
226.14(a)............................... An individual who wants to nominate a None.
tract for a competitive lease sale must
submit a nomination letter that includes
their name and address as well as the
legal description of the tract they are
nominating. This requirement is the same
as the requirement in existing Sec.
226.2(a).
226.17(a)(2) through (4)................ The successful bidder at a competitive Osage Form B--Evidence of
lease sale must submit an executed lease Authority to Execute
form, evidence of authority to execute Papers.
papers form, and certificate of good Osage Form C--Oil and/or
standing from the Oklahoma Secretary of Gas Mining Lease.
State. This requirement is the same as
the requirement in existing Sec.
226.2(b).
226.19(a)(2) through (4)................ A prospective lessee who negotiates a non- Osage Form B--Evidence of
competitive lease with the OMC must Authority to Execute
submit an executed lease form, evidence Papers.
of authority to execute papers form, and Osage Form C--Oil and/or
certificate of good standing from the Gas Mining Lease.
Oklahoma Secretary of State. This
requirement is the same as the
requirement in existing Sec. 226.2(f).
226.21(b)............................... Lessees may submit a lease amendment form Osage Form D--Lease
evidencing an agreement between the Amendment.
lessee and OMC to extend the primary term
of the lease. This requirement is the
same as the requirement in existing Sec.
226.9(b).
226.24(b)............................... The lessee or OMC may submit a proposed None.
cooperative agreement whereby the parties
agree to unitize or merge one or more
leases of the Osage Mineral Estate to
promote development. This requirement is
the same as the requirement in existing
Sec. 226.15(a).
226.24(c)............................... The lessee or OMC may submit an agreement None.
whereby the parties agree to modify,
amend, or terminate an approved
cooperative agreement. This requirement
is the same as the requirement in
existing Sec. 226.15(a).
226.26(c)............................... A lessee (assignor) may submit a lease Osage Form E--Assignment
assignment form transferring record title of Record Title Interest.
in an approved lease to another existing
or prospective lessee (assignee). This
requirement is the same as the
requirement in existing Sec. 226.15(b).
226.33(a)............................... Lessees must submit a request to surrender None.
all or part of an approved lease. This
requirement is the same as the
requirement in existing Sec. 226.3.
226.34(d)............................... Lessees must submit a copy of any None.
agreement with a surface owner where the
parties agree that the lessee can remove
permanent improvements from the lease
following termination. This requirement
is the same as the requirement in
existing Sec. 226.29(a).
[[Page 2445]]
226.36.................................. The OMC must submit a Resolution approving None.
a royalty rate for oil that is below the
regulatory minimum of 12\1/2\ percent.
This requirement is the same as the
requirement in existing Sec. 226.11(a).
226.39.................................. The OMC must submit a Resolution approving None.
a royalty rate for gas that is below the
regulatory minimum of 12\1/2\ percent.
This requirement is the same as the
requirement in existing Sec. 226.11(b).
226.42(b)............................... The OMC must submit a Resolution providing None.
notice of its intention to take oil and/
or gas royalty in kind. This requirement
is the same as the requirement in
existing Sec. 226.11(a), except that
the new provision allows the OMC to take
both oil and gas royalty in kind, instead
of allowing the OMC to only take oil
royalty in kind.
226.44(a)............................... Lessees must submit contracts or division None.
orders with purchasers of oil and gas.
This requirement is the same as the
requirement in existing Sec. 226.14,
except that the Superintendent's approval
of contracts and division orders is no
longer required.
226.46(b)............................... Lessees must make, retain, and preserve None.
royalty, rental, and payment records for
six years from the date upon which the
relevant transaction was recorded or such
longer period as the Superintendent or
ONRR may require. This requirement is the
same as the requirement in existing Sec.
226.30, except that it reduces the
burden by providing a specific timeframe
for record retention and clarifies that
both the Superintendent ONRR may request
the subject records.
226.51(c), 226.52(a) and (b)............ Lessees must file an individual well bond Osage Form F--Oil and Gas
for each well the lessee proposes to Lease Bond.
drill, reenter, recomplete, or accept
responsibility for through assignment; a
countywide bond covering all leases of
the Osage Mineral Estate (10,240 acres
maximum); or a nationwide bond covering
all leases within the United States to
which the lessee is a party. This
requirement is the same as the
requirement in existing Sec. 226.6(a).
226.56(a) and (c)....................... Lessees and permittees must file an Oil Osage Form G--Oil and Gas
and Gas Exploration Bond Form for Geophysical Exploration
geophysical exploration operations. An Bond.
existing lessee with a countywide or
nationwide Oil and Gas Lease Bond may
file a bond rider covering geophysical
exploration operations in lieu of filing
an Oil and Gas Exploration Bond. There is
no form for bond riders because they are
prepared by the surety.
226.65(b)............................... Lessees must submit a request to expand an None.
approved drilling site beyond the acreage
set forth in the approved EA. This
requirement is the same as the
requirement in existing Sec. 226.19(b).
226.66(a)............................... Lessees must submit an application for a Osage Form 139--
permit to drill or reenter a well. This Application for Permit to
requirement is the same as the Drill or Workover Wells.
requirement in existing Sec. 226.16(b),
but the burden on respondents is reduced
because Osage Form 139 is now a fillable
form that can be completed and submitted
electronically.
226.66(c)............................... Lessees must notify the Superintendent of None.
planned drilling and reentry operations
five days prior to the commencement
thereof. Notice may be provided by phone
or email. This requirement is the same as
the requirement in existing Sec.
226.16(c), except that the new provision
specifies that the timeframe for
providing notice is five days as opposed
to ``a reasonable time in advance.''.
226.66(d)............................... Lessees must submit a request to drill a None.
well within 300 feet of the lease
boundary or locate a well or tank within
200 feet of roads or highways maintained
for public use, water sources, and
residences, granaries, and barns. This
requirement is the same as the
requirement in existing Sec. 226.33.
226.67(b)............................... Lessees must submit a request to drill a None.
well that deviates significantly from the
vertical and report the drilling of any
well that deviates significantly from the
vertical without prior approval.
226.69(a)............................... Lessees must submit an application for a Osage Form 139--
permit to workover a well. This Application for a Permit
requirement is the same the requirement to Drill or Workover
in existing Sec. 226.16(b), but the Wells.
burden hours are reduced because Osage
Form 139 is now a fillable form that can
be completed and submitted electronically.
226.69(c)............................... Lessees must notify the Superintendent of None.
planned workover operations five days
prior to the commencement thereof. Notice
may be provided by phone or email. This
requirement is the same as the
requirement in existing Sec. 226.16(c),
except that the new provision specifies
that the timeframe for providing notice
is five days as opposed to ``a reasonable
time in advance.''.
226.70(a)............................... Lessees must submit the results of H2S None.
concentration tests upon request and
submit radius of exposure calculations
for any well or production facility with
an H2S concentration of 100 ppm or more.
226.70(b)(1) and (2).................... Lessees must report any release of a None.
potentially hazardous volume of H2S as
soon as practicable, but not later than
24 hours following identification of the
release. Notice must be provided by
phone. A lessee must submit a Public
Protection Plan for the potential release
of a hazardous volume of H2S if:
1. The 100 ppm radius of exposure is
greater than 50 feet and includes any
part of a residence, school, church,
park, place of business, or other area
the general public can 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 that is owned
and maintained for public use; or
[[Page 2446]]
3. The 100 ppm radius of exposure if
greater than or equal to 3,000 feet.
The regulations specify the information
that Public Protection Plans must
include.
226.70(d)............................... Lessees must maintain a record of all None.
tests of H2S monitoring systems and make
the records available to the
Superintendent upon request.
226.72.................................. Lessees must submit a request to None.
temporarily abandon a well for more than
30 calendar days. This requirement is the
same as the requirement in existing Sec.
226.28.
226.73(d)............................... Lessees must submit an application for a Osage Form 139--
permit to plug a well. This requirement Application for a Permit
is the same the requirement in existing to Drill, Workover, or
Sec. 226.28(a), (c), but the burden Plug Wells.
hours are reduced because Osage Form 139
is now a fillable form that can be
completed and submitted electronically.
226.73(f)............................... Lessees must notify the Superintendent of None.
planned plugging operations five days
prior to the commencement thereof. Notice
may be provided by phone or email. This
requirement is the same as the
requirement in existing Sec. 226.16(c),
except that the new provision specifies
that the timeframe for providing notice
is five days as opposed to ``a reasonable
time in advance.''.
226.73(h)............................... Lessees must submit any agreement with a None.
surface owner whereby the parties agree
that lessee will condition a well that is
being plugged for the surface owner's use
as a water supply well. This requirement
is the same as the requirement in
existing Sec. 226.29(d).
226.74(a)............................... Lessees must make all books and records None.
relating to lease operations available to
the Superintendent upon request. This
requirement is the same as the
requirement in existing Sec. 226.30.
226.74(c) through (f)................... Lessees must submit a report upon Osage Form 208--Well
completion of all approved drilling, Completion or
workover, and plugging operations, Recompletion Report.
together with copies of the results for Osage Form 209--Report of
all samples, tests, and surveys conducted Workover or Plugging
on the well; copies of the electrical, Operations.
mechanical, and radioactive logs or other Osage Form 210--
surveys of the wellbore; core analysis; Withholding of
and for plugging operations, cementing Proprietary Hydraulic
tickets. This requirement is the same as Fracturing Information.
the requirement in existing Sec.
226.32(a), (b) and (c).
Lessees must submit a report upon
completion of hydraulic fracturing
operations together with a report of the
fracking fluids used. The regulations
specify the information that such reports
of fracking fluids must include. Lessees
or owners of the fracking fluid
information may withhold proprietary
information that is exempt from public
disclosure by submitting a signed
withholding statement..
226.74(h)............................... Lessees must maintain well records and None.
reports for six years from the date they
were generated unless the Superintendent
requires a longer retention period due to
an audit or investigation. This
requirement is the same as the
requirement in existing Sec. 226.32(c),
except that the new provision specifies
the timeframe for retention.
226.76.................................. Lessees must submit the results of tests None.
and surveys performed to establish the
effectiveness of measures taken to
protect fresh water and mineral bearing
formations upon request. This requirement
is the same as the requirement in
existing Sec. 226.35.
226.77(c)............................... Lessees must submit a request to None.
construct, utilize, enlarge, or relocate
a pit. This requirement is the same as
the requirement in existing Sec.
226.22(d).
226.77(d)............................... Lessees must file a copy of any agreement None.
whereby the lessee and surface owner
reach an alternative agreement regarding
the emptying and leveling of pits. This
requirement is the same as the
requirement in existing Sec. 226.22(b).
226.77(f)............................... Lessees must submit a request for the land- None.
application of waste.
226.79(a)............................... A lessee or individual wishing to conduct Osage Form 339--
oil and gas geophysical exploration Application for Oil and
activities within the Osage Mineral Gas Geophysical
Estate must submit an Application for an Exploration Permit.
Oil and Gas Geophysical Exploration
Permit. This requirement is the same as
the requirement in existing Sec.
226.16(a), except that the Proposed Rule
provides a form for such applications.
226.80.................................. A lessee or permittee must notify the None.
Superintendent of planned oil and gas
geophysical operations five days prior to
the commencement thereof. Notice may be
provided by phone or email.
226.81.................................. A lessee or permittee must submit a Osage Form 408--Completion
Completion Report for Oil and Gas Report for Oil and Gas
Geophysical Exploration Operations Geophysical Exploration
providing a subsequent report of the Operations.
exploration operations performed.
226.82(d)............................... A person claiming an interest in leased None.
lands for the purpose of the settlement
of surface damages must notify the
Superintendent of that interest. This
requirement is the same as the
requirement in existing Sec. 226.20(d).
226.83(f)............................... A lessee or permittee must file a report None.
of each settlement agreement whereby the
lessee or permittee and an Indian
landowner agree to the amount of surface
damages to be paid. This requirement is
the same as the requirement in existing
Sec. 226.21(g).
226.84(e)............................... Lessees must report the emergency pumping None.
of oil into a pit. Emergency reports must
be submitted by phone.
[[Page 2447]]
226.86(a) through (e)................... Lessees must submit a site facility None.
diagram for all permanent facilities. The
regulations specify the information that
site facility diagrams must include and
the timeframe for submitting site
facility diagrams, which varies depending
on the date the relevant facilities
became operational. Lessees have an
ongoing obligation to update and amend
site facility diagrams if facilities are
modified to ensure that the diagrams
accurately represent facilities. Sample
site facility diagrams are available at
https://www.bia.gov/regional-offices/eastern-oklahoma/osage-agency.
226.88(a) through (c)................... Lessees, purchasers, transporters, and None.
other persons involved in producing,
transporting, purchasing, selling, or
measuring oil and gas must retain all
records for a minimum of six years from
the date upon which the relevant
transaction was recorded unless the
Superintendent or ONRR requires retention
for a longer period. Such records must be
made available to the Superintendent or
ONRR upon request. The regulations
specify the information that production
records must include.
226.92(b)............................... A lessee may request the use of None.
alternative protective measures to
prevent drainage.
226.97(a) and (b)....................... Persons engaged in transporting oil by None.
motor vehicle or pipeline must maintain
documentation showing the amount, origin,
and intended first purchaser of the oil.
226.98.................................. Lessees, purchasers, or transporters who None.
drain water from a production storage
tank must document such draining
operations. The regulations specify the
information that documentation of water
draining operations must include.
226.99(a)............................... Lessees must document the removal of oil None.
from storage, temporary use of the oil
for operations, and return of the oil to
storage during hot-oil, clean-up, or
completion operations. The regulations
specify the information that
documentation for temporary removal of
oil from storage must include.
226.100................................. Lessees must maintain a record of the None.
seals used on valves and meter
components. The regulations specify the
information that seal records must
include.
226.101(a).............................. Lessees must submit a request for off- None.
lease measurement of production. The
regulations specify the information that
requests for off-lease measurement of
production must include.
226.102(a) and (c)...................... Lessees must report spills, theft, Osage Form H--Spill and
mishandling of production, blowouts, Remediation Report.
fires, and accidents that occur on the
lease by phone or email immediately upon
discovery, but not later than one
calendar day following discovery. Lessees
must also submit a written report of the
incident together with a proposed
contingency or remediation plan. The
initial report of spills, theft,
mishandling of production, blowouts,
fires, and accidents is provided by
phone. This requirement is the same as
the requirement in existing Sec. 226.41.
226.107(f).............................. Lessees measuring oil by tank gauging must None.
submit tank tables within 45 days after
calibrating a tank or recalculation of
the tables. This requirement is the same
as the requirement in existing Sec.
226.38, except that the new provision
specifies the timeframe for submitting
tank tables.
226.108(a).............................. Lessee must submit a request to use None.
automatic tank gauging for oil
measurement. The regulations specify the
information that requests to use
automatic tank gauging must include. This
requirement is the same as the
requirement in existing Sec. 226.38.
226.108(b)(5)(ii)(B).................... Lessees must submit a detailed log of None.
field verifications of automatic tank
gauges upon request. This requirement is
the same as the requirement in existing
Sec. 226.38.
226.109(e).............................. Lessees must provide notice of any LACT None.
system failures or equipment malfunctions
that may have resulted in measurement
error within 15 calendar days of
discovering such failure or malfunction.
226.112(c), (e), (f), and (g)........... Lessees must submit Coriolis meter None.
specifications upon request. Lessees must
maintain the following information on-
site at the FMP:
Make, model, and size of each
sensor;
Make, model, range, and
calibrated span of the pressure and
temperature transducers used to determine
gross standard volume; and
A log of all meter factors, zero
verifications, and zero adjustments.
Lessees must retain QTRs, configuration
logs, event logs, and alarm logs for six
years from the date they were generated
or such longer period as the
Superintendent may require.
226.113(b).............................. Lessees must have a certificate of None.
calibration for the meter prover (e.g., a
device that verifies the accuracy of the
meter) on-site and available for review.
226.113(j).............................. Lessees must submit a report of meter None.
proving and volume adjustments within 14
days after any LACT system or CMS
malfunction, including excessive meter-
factor deviation.
226.114(d).............................. Lessees must submit run tickets on or None.
before the last calendar day of the month
following the production month. The
regulations specify the information that
run tickets for tank gauging, LACT, and
CMS must include. This requirement is the
same as the requirement in existing Sec.
226.16(b), except that the new provision
specifies the information run tickets
must contain. The information required is
consistent with what is currently
submitted and prevailing industry
standards.
226.115................................. Lessees must submit a request to use any None.
method of oil measurement other than tank
gauging, LACT system, or CMS.
[[Page 2448]]
226.116(c).............................. Lessees must submit a request to sell or None.
dispose of slop oil and, following the
approved sale or disposal of slop oil,
must submit a report identifying the
volume of slop oil sold or disposed of,
the method used to computer that volume,
and the gross revenue from the sale. This
provision codifies lessees' existing
practices for the sale or disposal of
slop oil. Accordingly, it does not impose
a new burden on lessees with respect to
such sales.
226.121(e).............................. Lessees must document orifice plate None.
inspections and include that
documentation as part of the verification
report submitted in accordance with Sec.
Sec. 226.123 (for mechanical recorders)
or 226.126 (for EGM systems). The
regulations specify the information that
documentation of orifice plate
inspections must include.
226.121(i).............................. Lessees must document meter tube None.
inspections and must make such
documentation available upon request. The
regulations specify the information that
documentation of meter tube inspections
must include.
226.121(j).............................. Lessees must notify the Superintendent at None.
least 72 hours in advance of performing
basic or detailed meter tube inspections
under Sec. 226.121(d), (g), and (h) or
submit a monthly or quarterly schedule or
inspections. Notice may be provided by
phone or email. This provision codifies
lessees' existing practice of providing
notice of meter tube inspections but
specifies that 72 hours' advance notice
be provided. The provision introduces the
option for lessees to submit inspection
schedules to provide additional
flexibility for notice requirements.
226.122(g).............................. Lessees must maintain certain data at FMPs None.
for mechanical recorders. The regulations
specify the information that mechanical
recorder data maintained at FMPs must
include.
226.123(d).............................. Lessees must retain documentation of None.
mechanical recorder verifications and
make such documentation available to the
Superintendent upon request. The
regulations specify the information that
documentation of mechanical recorder
verifications must include.
226.123(e).............................. Lessees must notify the Superintendent at None.
least 72 hours in advance of performing
mechanical recorder verifications
following installation or repair or
performing routine verifications. Notice
may be provided by phone or email, or
lessees may submit a monthly or quarterly
schedule of verifications.
226.123(g).............................. Purchasers or purchasers' representatives None.
must retain documentation of test
equipment certifications on-site. The
regulations specify the information that
documentation of certification of test
equipment include. This collection does
not impose a burden on respondents
pursuant to 5 CFR 1320.3(h)).
226.124(a).............................. Lessees must retain an unedited None.
integration statement and make such
statement available to the Superintendent
upon request. The regulations specify the
information that unedited integration
statements must include. Lessees already
obtain integration statements containing
the above information consistent with
industry standards. This provision
codifies lessees' existing practices. The
requirement to retain such statements is
the same as the requirement in existing
Sec. 226.30.
226.125(e).............................. Lessees must maintain certain data at FMPs None.
for EGM systems. The regulations specify
the information that data for EGM systems
must include.
226.126(e).............................. Lessees must retain documentation of each None.
verification of EGM systems and make such
documentation available to the
Superintendent upon request. The
regulations specify the information that
documentation of EGM system verifications
must include.
226.126(f).............................. Lessees must notify the Superintendent at None.
least 72 hours before conducting routine
EGM system verifications and
verifications following installation or
repairs. Notice may be provided by phone
or email, or lessees may submit a monthly
or quarterly verification schedule. This
provision codifies lessees' existing
practice of providing notice EGM
verifications but specifies that 72
hours' advance notice be provided.
226.126(h).............................. Purchasers or purchasers' representatives None.
must maintain documentation of test
equipment certifications on-site. The
regulations specify the information that
documentation of test equipment
certifications must include. This
collection does not impose a burden on
respondents pursuant to 5 CFR 1320.3(h)).
226.128(a).............................. Lessees must retain QTRs for EGM systems None.
and make them available to the
Superintendent upon request. The
regulations specify the information that
QTRs for EGM systems must include.
226.128(b).............................. Lessees must retain the original, None.
unaltered, unprocessed, and unedited
configuration log for the EGM system and
make it available upon request. The
regulations specify the information that
configuration logs must include.
226.128(c).............................. Lessees must retain the original, None.
unaltered, unprocessed, and unedited
event log for the EGM system and make it
available upon request. The regulations
require the configuration log to contain
the information identified in API 21.1,
subsection 5.5 and have sufficient
capacity to be retrieved and stored at
intervals that will maintain a continuous
record of events for either the required
six-year retention period or the life of
the FMP, whichever is shorter.
226.128(d).............................. Lessees must retain an alarm log and make None.
it available upon request. The
regulations require alarm logs to comply
with the requirements set forth in API
21.1, Subsection 5.6.
[[Page 2449]]
226.131(b).............................. Lessees must notify the Superintendent at None.
least 72 hours before obtaining a spot
sample. Notice may be provided by phone
or email, or lessees may submit a monthly
or quarterly sampling schedule. This
provision codifies lessees' existing
practice of providing notice of spot
sampling but specifies that 72 hours'
advance notice be provided. The provision
introduces the option for lessees to
submit spot sample schedules to provide
additional flexibility for notice
requirements.
226.131(c).............................. Lessees must maintain documentation of the None.
cleaning of sample cylinders and make
such documentation available upon request.
226.132(a)(2)........................... Lessees must maintain documentation None.
demonstrating that the cylinder was
evacuated and pre-charged before sampling
for spot sampling using the Helium
``pop'' method and make such
documentation available upon request.
226.132(a)(3)........................... Lessees must maintain documentation of the None.
seal material and type of lubricant used
for the floating piston cylinder method
of spot sampling and make such
documentation upon request.
226.136(e).............................. Lessees must retain documentation of the None.
gas chromatograph verifications and make
the documentation available upon request.
The regulations specify the information
that documentation of gas chromatograph
verifications must include.
226.138(a), (e)......................... Lessees must submit all gas analysis None.
reports within 14 calendar days after the
due date for the sample as specified in
Sec. 226.133. The regulations specify
the information that gas analysis reports
must include.
226.141(c)(2)........................... Lessees must document all edits made to None.
reported heating value or volume data
before the report is submitted to ONRR,
including verifiable justifications for
the edits made, and such documentation
must be made available upon request.
226.142(d).............................. Lessees must submit a request to stop None.
furnishing gas to Tribally owned
buildings or enterprises or members of
the Osage Nation residing in Osage
County. This requirement is the same as
the requirement in existing Sec.
226.27(b)(3).
226.146(b).............................. Lessees must submit a request for certain
royalty-free uses of production on the
lease or unit. The regulations require
the Superintendent's approval of:
Use of oil or gas the lessee None.
removes from the pipeline at a location
downstream of the FMP;
Use of gas that has been removed
from the lease or unit for treatment or
processing because the particular
physical characteristics of the gas
require it to be treated or processed
prior to use, where the gas is returned
to, and used on, the same lease or unit
from which it is produced; and
Any other uses of produced oil
and gas for operations and production
purposes that are not set forth in Sec.
226.145.
The regulations specify the information
that requests for royalty-free use of
production on the lease or unit must
include.
226.148(c).............................. Lessees must submit a request for certain None.
royalty-free uses of production off the
lease or unit. The regulations require
the Superintendent's approval of royalty-
free treatment of oil or gas used in
operations conducted off the lease or
unit if the:
Use is among those listed in Sec.
Sec. 226.145(a) or 226.146(a);
Equipment or facility in which
the operation is conducted is located off
the lease or unit for engineering,
economic, resource protection, or
physical accessibility reasons; and
Operations are conducted upstream
of the FMP.
The regulations specify the information
that requests for royalty use of
production off the lease or unit must
include.
226.149(d).............................. Lessees must notify the Superintendent in None.
writing if oil or gas is removed
downstream of the FMP for royalty-free
use pursuant to Sec. Sec. 226.145
through 226.148 and obtain an approved
FMP to measure the production removed for
use.
226.152(a).............................. Lessees must submit a request to vent or None.
flare gas. The regulations require the
Superintendent's approval to vent or
flare gas to ensure that the natural gas
disposed of through venting or flaring is
properly measured and, where applicable,
proper royalties paid. This provision
codifies the Superintendent's existing
notice to lessees requiring prior
approval for all venting and flaring.
Accordingly, this provision does not
impose a new burden on lessees.
226.158................................. Lessees must submit a self-certification Osage Form I--Self-
following the correction of any lease Certification for
violations for which a notice of non- Correction of Lease
compliance is received. This provision Violations.
codifies the Superintendent's existing
requirement that self-certification forms
be submitted upon completion of the
correction of lease violations.
Accordingly, this provision does not
impose a new burden on lessees.
----------------------------------------------------------------------------------------------------------------
Title of Collection: Mining of the Osage Mineral Estate for Oil and
Gas.
OMB Control Number: 1076-0180.
Abstract: Under the 1906 Act, the BIA is required to administer oil
and gas leasing and development of the Osage Mineral Estate. The BIA
needs to perform the IC activities set forth in the regulations at 25
CFR part 226 to perform its responsibilities under the statute.
Form Number: Osage Form A (Lease Contact of Record); Osage Form B
(Evidence of Authority to Execute Papers); Osage Form C (Oil and Gas
Mining Lease); Osage Form D (Lease Amendment); Osage Form E (Assignment
of Record Title Interest); Osage Form F (Oil and Gas Lease Bond); Osage
Form G (Oil and Gas Geophysical Exploration Bond); Osage Form H (Spill
[[Page 2450]]
and Remediation Report); Osage Form I (Self-Certification for
Correction of Lease Violations); Osage Form 139 (Application for Permit
to Drill or Workover Wells); Osage Form 208 (Well Completion or Reentry
Report); Osage Form 209 (Report of Workover or Plugging Operations);
Osage Form 210 (Withholding of Proprietary Hydraulic Fracturing
Information); Osage Form 339 (Application for Permit to Conduct Oil and
Gas Geophysical Exploration Operations); Osage Form 408 (Oil and Gas
Geophysical Exploration Completion Report).
Type of Review: Revision of a currently approved collection.
Respondents/Affected Public: Individual Indians, businesses, and
Tribal authorities.
Total Estimated Number of Annual Respondents: 4,974.
Total Estimated Number of Annual Responses: 59,196.
Estimated Completion Time per Response: Varies from six minutes to
40 hours.
Total Estimated Number of Annual Burden Hours: 22,564.
Respondent's Obligation: Required to obtain a benefit.
Frequency of Collection: Varies from monthly to yearly.
Total Estimated Annual Non-Hour Burden Cost: $0.
2. OMB Control Number 1012-0004 (ONRR)
The OMB has reviewed and approved information collections for
ONRR's royalty and production reporting operations throughout the rest
of Indian country, which are assigned OMB Control No. 1012-0004. ONRR
is proposing to renew information collection 1012-0004 with revisions
to provide for such collections within the Osage Mineral Estate. The
following ONRR royalty and production reporting and recordkeeping
requirements in the proposed rule require OMB's approval:
----------------------------------------------------------------------------------------------------------------
Section(s) Proposed revision(s) to OMB 1012-0004 OMB 1012-0004 Form(s)
----------------------------------------------------------------------------------------------------------------
226.43(c) and (d)....................... Lessees must make royalty payments to ONRR None.
by EFT (preferred) or the other forms of
payment identified in Sec. 226.8. Non-
EFT royalty payments submitted via U.S.
Postal Service must be addressed to:
Office of Natural Resources Revenue, P.O.
Box 25627, Denver, CO 80225-0627. Royalty
reports submitted manually via courier or
overnight delivery service must be
addressed to: Office of Natural Resources
Revenue, Denver Federal Center, Building
85, Entrance N-1, Room 332, 6th Avenue
and Kipling Street, Denver, CO 80225.
226.45.................................. Lessees must submit certified monthly ONRR 2014--Report of Sales
royalty reports to ONRR by 4 p.m. and Royalty Remittance.
mountain time on or before the last
calendar day of the month that follows
the month during which the oil and gas is
produced and sold. Royalty reports must
be submitted electronically via ONRR's
eCommerce Reporting website, https://onrrreporting.onrr.gov, unless the lessee
meets the qualifications for manual
reporting. Royalty reports submitted
manually via U.S. Postal Service must be
addressed to: Office of Natural Resources
Revenue, P.O. Box 25627, Denver, CO 80225-
0627. Royalty reports submitted manually
via courier or overnight delivery service
must be addressed to: Office of Natural
Resources Revenue, Denver Federal Center,
Building 85, Entrance N-1, Room 332, 6th
Avenue and Kipling Street, Denver, CO
80225.
226.46.................................. Lessees must make, retain, and preserve None.
records demonstrating that rental,
royalty, and other payments relating to
oil and gas leases comply with the terms
and conditions of the lease, the
regulations in 25 CFR part 226, and
applicable orders and notices. Lessees
must preserve records for a minimum of
six years from the date upon which the
relevant transaction was recorded unless
the Superintendent or ONRR provides
notice that records must be maintained
for a longer period due to investigation
or audit. Lessees must make records
available to the Superintendent ONRR for
inspection upon request. Covered under
burden for Sec. Sec. 226.32(c) and (d)
and 226.45.
226.85.................................. Lessees must submit certified monthly ONRR 4054--Oil and Gas
productions reports to ONRR by 4 p.m. Operations Report (OGOR).
mountain time on or before the 15th day
of the second month following the
production month. Production reports must
be submitted electronically via ONRR's
eCommerce Reporting website, https://onrrreporting.onrr.gov, unless the lessee
meets the qualifications for manual
reporting. Production reports submitted
manually via U.S. Postal Service must be
addressed to: Office of Natural Resources
Revenue, P.O. Box 25627, Denver, CO,
80225-0627. Production reports submitted
manually via courier or overnight
delivery service must be addressed to:
Office of Natural Resources Revenue,
Denver Federal Center, Building 85,
Entrance N-1, Room 332, 6th Avenue and
Kipling Street, Denver, CO 80225.
226.88.................................. Lessees, purchasers, transporters, and None.
other persons involved in producing,
transporting, purchasing, selling, or
measuring oil and gas through the point
of royalty measurement or point of first
sale, whichever is later, must retain all
records, including source records,
relevant to determining the quality,
quantity, disposition, and verification
of production attributable to the subject
lease. The regulations specify the
information that production records must
include. Production records must be
preserved for a minimum of six years from
the date upon which the relevant
transaction was recorded unless the
Superintendent or ONRR provides notice
that records must be maintained for a
longer period due to investigation or
audit. Lessees must make records
available to the Superintendent ONRR for
inspection upon request. Covered under
burden for Sec. 226.85.
----------------------------------------------------------------------------------------------------------------
Title of Collection: Royalty and Production Reporting.
OMB Control Number: 1012-0004.
Revisions: Under the 1906 Act, the BIA is required to administer
oil and gas
[[Page 2451]]
leasing and development of the Osage Mineral Estate. The proposed rule
would allow BIA to transfer the royalty and production reporting and
compliance functions for the Osage Mineral Estate to ONRR. ONRR would
perform the specified IC activities in 25 CFR part 226 to carry out the
BIA's responsibilities and ensure that lessees pay proper royalties and
revenues on oil and gas produced from the Osage Mineral Estate. The
requirement to timely and accurately report royalties and production is
mandatory.
Form Number: ONRR-2014, ONRR-4054.
Type of Review: Revision of a currently approved collection.
Respondents/Affected Public: Businesses.
Total Estimated Number of Annual Respondents: 3,490 oil, gas, and
geothermal reporters.
Total Estimated Number of Annual Responses: 12,827,063 lines of
data.
Estimated Completion Time per Response: Varies between 1 and 7
minutes per line, depending on the activity. The average completion
time is 1.72 minutes per line. The average completion time is
calculated by first multiplying the estimated annual burden hours
(369,379) by 60 to obtain the total annual burden minutes. Then the
total annual burden minutes (22,162,740) is divided by the estimated
annual number of lines submitted (12,827,063).
Total Estimated Number of Annual Burden Hours: 369,379.
Respondent's Obligation: Mandatory.
Frequency of Collection: Monthly.
Total Estimated Annual Non-Hour Burden Cost: ONRR identified no
``non-hour cost'' burden associated with this information collection.
3. OMB Control Number 1012-0006 (ONRR)
The OMB has reviewed and approved information collections for
ONRR's suspensions pending appeal and bonding throughout the rest of
Indian country, which are assigned OMB Control No. 1012-0006. ONRR is
proposing to renew information collection 1012-0006 with revisions to
provide for such collections within the Osage Mineral Estate. The
following ONRR suspensions pending appeal and bonding requirements in
the proposed rule require OMB's approval:
----------------------------------------------------------------------------------------------------------------
Section(s) Proposed revision(s) to OMB 1012-0006 OMB 1012-0006 Form(s)
----------------------------------------------------------------------------------------------------------------
226.179(b)(2)........................... A party who appeals an order regarding the ONRR 4435--Administrative
payment and reporting of royalties, or Appeal Bond.
other payments due, may suspend ONRR 4436--Letter of
compliance with such order by submitting Credit.
an ONRR-specified surety instrument ONRR 4437--Assignment of
within 60 days after receiving the Order Certificate of Deposit.
or Notice of Order.
226.180(a).............................. Any other person, including a designee, None.
payor, or affiliate, may post a bond or
other surety instrument on behalf of an
appellant. If such person is assuming an
appellant's responsibility, they must
notify ONRR in writing of such
assumption. Covered under burden for Sec.
226.179(b)(2).
226.182(b)(2)........................... ONRR will suspend an obligation to comply None.
with an order if the amount under appeal
is $1,000 or more if the appellant
submits an ONRR-specified surety
instrument within the required timeframe.
Covered under burden for Sec.
226.179(b)(2).
226.185(c).............................. An appellant whose appeal is not decided None.
within one year from the filing date must
increase the surety amount to cover
additional estimated interest for another
one-year period and continue such
increases annually. Covered under burden
for Sec. 226.179(b)(2).
----------------------------------------------------------------------------------------------------------------
Title of Collection: Suspensions Pending Appeal and Bonding.
OMB Control Number: 1012-0006.
Revision: Under the 1906 Act, the BIA is required to administer oil
and gas leasing and development of the Osage Mineral Estate. The
proposed rule would allow BIA to transfer the royalty and production
reporting and compliance functions for the Osage Mineral Estate to
ONRR. ONRR would perform the specified IC activities in 25 CFR part 226
to carry out enforcement and compliance actions for the Osage Mineral
Estate.
Form Number: ONRR-4435, ONRR-4436, and ONRR-4437.
Type of Review: Revision of a currently approved collection.
Respondents/Affected Public: Businesses.
Total Estimated Number of Annual Respondents: 107.
Total Estimated Number of Annual Responses: 107.
Estimated Completion Time per Response: The time per response is
120 mins. The average completion time is calculated by first
multiplying the estimated annual burden hours (214 burden hours) by 60
to obtain the total annual burden minutes. Then the total annual burden
minutes (12,840) is divided by the estimated annual responses (107).
Total Estimated Number of Annual Burden Hours: 214.
Respondent's Obligation: Mandatory.
Frequency of Collection: Annually and on occasion.
Total Estimated Annual Non-Hour Burden Cost: There are no
additional recordkeeping costs associated with this information
collection. However, ONRR estimates 5 appellants per year will pay a
$50 fee to obtain credit data from a business information or credit
reporting service, which is a total non-hour cost burden of $250 per
year (5 appellants per year x $50 = $250).
J. National Environmental Policy Act
This proposed rule does not constitute a major Federal action
significantly affecting the quality of the human environment under the
National Environmental Policy Act of 1969 (NEPA), 42 U.S.C. 4321, et
seq. Therefore, this proposed rule is categorically excluded from
further review under 43 CFR 46.210(i) because these are regulations
``whose environmental effects are too broad, speculative, or
conjectural to lend themselves to meaningful analysis and will later be
subject to the NEPA review process either collectively or case by
case.'' No extraordinary circumstances exist that require greater NEPA
review.
K. Effects on the Energy Supply (Executive Order 13211)
This proposed rule is not a significant energy action under the
definition in Executive Order 13211. A statement of Energy Effects is
not required.
L. Clarity of This Regulation (Executive Orders 12866, 12988, and
13563)
We are required by Executive Orders 12866, 12988, and 13563 and by
the
[[Page 2452]]
Presidential Memorandum of June 1, 1988, to write all rules in plain
language. This means that each rule must:
(a) Be logically organized;
(b) Use the active voice to address readers directly;
(c) Use clear language rather than jargon;
(d) Be divided into short sections and sentences; and
(e) Use lists and tables wherever possible.
If you feel that we have not met these requirements, send us
comments using one of the methods listed in the ADDRESSES section. To
better help the BIA revise the rule, your comments should identify the
numbers of the sections or paragraphs that you find unclear and specify
which sections or sentences are too long, the sections where you
believe lists or tables would be useful.
List of Subjects in 25 CFR Part 226
Administrative practice and procedure, Environmental protection,
Incorporation by reference, Indians-lands, Mineral royalties, Oil and
gas exploration, Oil and gas measurement, Penalties, Reporting and
recordkeeping requirements.
For the reasons stated in the preamble, the Bureau of Indian
Affairs proposes to revise 25 CFR part 226 as follows:
PART 226--MINING OF THE OSAGE MINERAL ESTATE FOR OIL AND GAS
Subpart A--General
Sec.
226.0 Incorporation by reference (IBR).
226.1 Definitions.
226.2 Authorities that govern oil and gas activities within the
Osage Mineral Estate.
226.3 Authority and responsibility of the Superintendent of the
Osage Agency.
226.4 Authority and responsibility of the Office of Natural
Resources Revenue (ONRR).
226.5 Orders and notices.
226.6 Service of official correspondence.
226.7 Forms.
226.8 Acceptable forms of payment.
226.9 Environmental reviews and cultural surveys.
226.10 Information collection.
226.11 Public availability of information.
Subpart B--Acquiring a Lease
Authorized Procedures
226.12 Procedures the Osage Minerals Council may use to enter into a
lease.
Competitive Leases
226.13 Advertisement of a lease sale.
226.14 Nominating lands for a lease sale.
226.15 Publication of a Notice of Lease Sale.
226.16 Bidding system.
226.17 Award of leases.
Non-Competitive Leases
226.18 Submitting an offer to lease.
226.19 Acceptance of an offer to lease.
Lease Terms
226.20 Types of leases.
226.21 Primary term of leases.
226.22 Effect of changes in current regulations on existing leases.
226.23 U.S. Government employees may not acquire leases.
Subpart C--Cooperative Agreements and Unitization
226.24 Cooperative agreements.
226.25 Unit development plans.
Subpart D--Transferring a Lease by Assignment
226.26 Assignment of record title interest in a lease.
226.27 Qualifications of the assignee.
226.28 Effective date of transfer.
226.29 Effect of assignment on the assignor's liability under the
lease.
226.30 Effect of assignment on the assignee's liability under the
lease.
226.31 Overriding royalty agreements.
226.32 Drilling contracts.
Subpart E--Ending a Lease
226.33 Surrender of all or any portion of a lease.
226.34 Termination of a lease by operation of law.
Subpart F--Rental and Royalty
Rental Obligations
226.35 Annual rental requirements.
Royalty Obligations
226.36 Royalty rate for oil.
226.37 Calculating the value of oil for royalty purposes.
226.38 Gravity adjustment for oil.
226.39 Royalty rate for gas.
226.40 Calculating the value of gas for royalty purposes.
226.41 Minimum royalty.
226.42 Royalty-in-kind.
226.43 Royalty payments.
226.44 Royalty payment contracts and division orders.
226.45 Royalty reports.
226.46 Requirements for royalty, rental, and payment records.
226.47 Right of the U.S. Government to purchase oil.
Audits
226.48 Audits and reviews.
Subpart G--Bonds
Lease Bonds
226.49 Grandfathering of existing bonds.
226.50 Bond obligations.
226.51 Individual well bond requirements.
226.52 Countywide and nationwide bond requirements.
226.53 Authorization to increase the required bond amount.
226.54 Bond forfeiture.
226.55 Termination of the period of liability and release of bonds.
Geophysical Exploration Bonds
226.56 Geophysical exploration bond requirements.
226.57 Bond forfeiture.
226.58 Termination of the period of liability and release of bonds.
Subpart H--Operations
General Requirements
226.59 Conduct of operations.
226.60 Inspection of operations.
Commencement of Operations
226.61 No operations may commence prior to approval of a lease or
geophysical exploration permit.
226.62 Prior authorization required to commence operations on trust
or restricted lands.
226.63 Notice and information to be given to surface owners prior to
commencement of operations.
226.64 Payment of commencement money and tank siting fees to the
surface owner.
Drilling, Workover, and Well Abandonment Operations
226.65 Use of surface lands and water for operations.
226.66 Drilling operations.
226.67 Well control.
226.68 Use of gas for artificial lifting of oil.
226.69 Workover operations.
226.70 Requirements for operations in Hydrogen Sulfide
(H2S) areas.
226.71 Surveys, samples, and tests.
226.72 Temporary abandonment.
226.73 Permanent plugging and abandonment operations.
226.74 Well records and reports.
226.75 Well and facility identification.
226.76 Pollution prevention.
226.77 Storage and disposal of fluids.
226.78 Removal of fire hazards.
Geophysical Exploration Operations
226.79 Applying for a geophysical exploration permit.
226.80 Commencement of operations.
226.81 Records and reports.
Settlement of Surface Damages
226.82 Lessee or permittee required to settle surface damages.
226.83 Procedure for settlement of surface damages.
Subpart I--Production and Site Security
General Requirements
226.84 Production obligations.
226.85 Production reporting.
226.86 Site facility diagrams.
226.87 Assignment of facility measurement point (FMP) numbers.
226.88 Requirements for production records.
226.89 Easements for access to wells located off-lease.
Waste Prevention
226.90 Prevention of waste.
226.91 Royalty on lost or wasted production.
Drainage Requirements
226.92 Prevention of drainage.
226.93 Compensatory royalty for drainage.
[[Page 2453]]
Site Security
226.94 Storage and sales facilities--seals.
226.95 Oil measurement system components--seals.
226.96 Removing production from tanks for sale and transportation by
truck.
226.97 Documentation required for transportation of oil and gas.
226.98 Water draining operations.
226.99 Hot oiling, clean-up, and completion operations.
226.100 Seal records.
226.101 Requirements for off-lease measurement of production.
226.102 Report of spills, theft, mishandling of production,
accidents, or fires.
Subpart J--Oil Measurement
226.103 General requirements.
226.104 Timeframes for compliance.
226.105 [Reserved]
226.106 Specific measurement performance requirements.
226.107 Tank gauging--general requirements.
226.108 Tank gauging--procedures.
226.109 LACT system--general requirements.
226.110 LACT system--components and operating requirements.
226.111 Coriolis measurement systems (CMS)--general requirements and
components.
226.112 Coriolis meter--operating requirements.
226.113 Meter proving requirements.
226.114 Run tickets.
226.115 Oil measurement by alternate methods.
226.116 Determination of oil volumes by methods other than
measurement.
Subpart K--Gas Measurement
226.117 General requirements.
226.118 Timeframes for compliance.
226.119 [Reserved]
226.120 Specific performance requirements.
226.121 Flange-tapped orifice plates (primary devices).
226.122 Mechanical recorder (secondary device).
226.123 Verification and calibration of mechanical recorder.
226.124 Integration statements.
226.125 Electronic gas measurement (secondary and tertiary device).
226.126 Verification and calibration of electronic gas measurement
systems.
226.127 Flow rate, volume, and average value calculation.
226.128 Logs and records.
226.129 Gas sampling and analysis.
226.130 Sampling probe and tubing.
226.131 Spot samples--general requirements.
226.132 Spot samples--allowable methods.
226.133 Spot samples--frequency.
226.134 Composite sampling methods.
226.135 On-line gas chromatographs.
226.136 Gas chromatographs.
226.137 Components to analyze.
226.138 Gas analysis report requirements.
226.139 Effective date of a spot or composite gas sample.
226.140 Calculation of heating value and volume.
226.141 Reporting of heating value and volume.
Subpart L--Tribal and Royalty-Free Use of Production
Tribal Use of Gas Production
226.142 Use of gas by the Osage Nation and Tribe members.
226.143 Royalty on gas furnished for Tribal use.
Royalty-Free Use of Lease Production
226.144 Production on which no royalty is due.
226.145 Uses of production on a lease or unit that do not require
the Superintendent's prior approval of royalty-free treatment.
226.146 Uses of production on a lease or unit that require the
Superintendent's prior approval of royalty-free treatment.
226.147 Uses of production moved off the lease or unit that do not
require the Superintendent's prior approval of royalty-free
treatment.
226.148 Uses of production moved off the lease or unit that require
the Superintendent's prior approval of royalty-free treatment.
226.149 Measurement or estimation of royalty-free volumes of oil or
gas.
226.150 Ownership of equipment or facilities.
226.151 Requesting approval of royalty-free treatment for volumes
used.
Subpart M--Venting and Flaring
226.152 General requirements.
226.153 Gas-well gas.
226.154 Oil-well gas.
226.155 Limitations on venting gas.
226.156 Authorized venting and flaring of gas.
226.157 Measurement and reporting of volumes of gas vented or
flared.
Subpart N--Assessments and Penalties
Lease Management Assessments and Civil Penalties
226.158 Remedies for violations of lease or permit terms and
conditions, regulations, orders, and notices.
226.159 Immediate assessments for violations of certain operating
regulations.
226.160 Other assessments.
226.161 Civil penalties with a period to correct.
226.162 Civil penalties without a period to correct.
226.163 Penalty amount.
226.164 Shut-in actions.
226.165 Lease or permit cancellation.
226.166 Payment of assessments and civil penalties.
Royalty Management Assessments and Civil Penalties
226.167 Remedies for violations of lease or permit terms and
conditions, regulations, orders, and notices.
226.168 Assessments for incorrect or late reports and failure to
report.
226.169 Assessments for failure to submit payment amount indicated
on a form or bill document or to provide adequate information.
226.170 Civil penalties with a period to correct.
226.171 Civil penalties without a period to correct.
226.172 Penalty amount.
226.173 Payment of civil assessments and civil penalties.
226.174 Collection of unpaid civil penalties.
226.175 Debt collection and administrative offset.
Criminal Penalties
226.176 Penalties for filing fraudulent reports.
Subpart O--Appeals
Appeals of BIA Decisions
226.177 Procedure for filing an administrative appeal of a decision,
order, or notice of the Superintendent.
Appeals of ONRR Decisions
226.178 Procedures for filing an administrative appeal of an order
from ONRR.
226.179 Suspension of compliance with an ONRR order.
226.180 Requirements for posting a bond or other surety on behalf of
appellant.
226.181 Suspension of obligation to comply with an ONRR order due to
judicial review in federal court.
226.182 ONRR's collection of bonds and other surety instruments.
226.183 ONRR bond-approving officer's determination of surety amount
not subject to appeal.
226.184 Standards for ONRR-specified surety instruments.
226.185 ONRR's determination of bond or surety instrument amount.
Appendix A Appendix A to Part 226--Table of Atmospheric Pressures
Authority: Sec. 3, Pub. L. 59-321, 34 Stat. 543; Secs. 1-2,
Pub. L. 66-360, 41 Stat. 1249; Secs. 1-2, Pub. L. 70-919, 45 Stat.
1478; Sec. 3, Pub. L. 75-711, 52 Stat. 1034; Pub. L. 81-548, 65
Stat. 215; Pub. L. 88-632, 78 Stat. 1008; Secs. 2, 4, Pub. L. 95-
496, 92 Stat. 1660.
Subpart A--General
Sec. 226.0 Incorporation by reference (IBR).
Certain material is incorporated by reference into this part with
the approval of the Director of the Federal Register under 5 U.S.C.
552(a) and 1 CFR part 51. To enforce any edition other than those
specified in this section, the Bureau of Indian Affairs (BIA) must
publish a document in the Federal Register, and the material must be
available to the public. All approved incorporation by reference (IBR)
material is available for inspection at the BIA and at the National
Archives and Records Administration (NARA). To inspect the material at
BIA, contact: the BIA Osage Agency, 513 Grandview Avenue, Pawhuska, OK
74056; phone 918-287-5700. For information on the availability of this
material at NARA,
[[Page 2454]]
visit www.archives.gov/federal-register/cfr/ibr-locations.html or email
[email protected]. The material may be obtained from the following
sources:
(a) American Petroleum Institute (API), 200 Massachusetts Avenue
NW, Suite 1100, Washington, DC 20005; phone: 202-682-8000; website:
https://www.api.org.
(1) API Manual of Petroleum Measurement Standards (MPMS), Chapter
2--Tank Calibration, Section 2A--Measurement and Calibration of Upright
Cylindrical Tanks by the Manual Tank Strapping Method; First Edition,
February 1995; Reaffirmed August 2017 (``API 2.2A''); IBR approved for
Sec. 226.107(f).
(2) API MPMS Chapter 2--Tank Calibration, Section 2B--Calibration
of Upright Cylindrical Tanks Using the Optical Reference Line Method;
First Edition, March 1989; Reaffirmed, April 2019; Addendum 1, October
2019 (``API 2.2B''); IBR approved for Sec. 226.107(f).
(3) API MPMS Chapter 2--Tank Calibration, Section 2C--Calibration
of Upright Cylindrical Tanks Using the Optical-Triangulation Method;
First Edition, January 2002; Reaffirmed April 2019 (``API 2.2C''); IBR
approved for Sec. 226.107(f).
(4) API MPMS Chapter 3--Tank Gauging, Section 1A--Standard Practice
for the Manual Gauging of Petroleum and Petroleum Products; Third
Edition, August 2013; Reaffirmed December 2018 (``API 3.1A''); IBR
approved for Sec. 226.108(b).
(5) API MPMS Chapter 3--Tank Gauging, Section 1B--Standard Practice
for Level Measurement of Liquid Hydrocarbons in Stationary Tanks by
Automatic Tank Gauging; Third Edition, April 2018 (``API 3.1B''); IBR
approved for Sec. 226.108(b).
(6) API MPMS Chapter 3--Tank Gauging, Section 6--Measurement of
Liquid Hydrocarbons by Hybrid Tank Measurement Systems; First Edition,
February 2001; Errata September 2005; Reaffirmed January 2017 (``API
3.6''); IBR approved for Sec. 226.108(b).
(7) API MPMS Chapter 4--Proving Systems, Section 1--Introduction;
Third Edition, February 2005; Reaffirmed June 2014 (``API 4.1''); IBR
approved for Sec. 226.113(c).
(8) API MPMS Chapter 4--Proving Systems, Section 2--Displacement
Provers; Third Edition, September 2003; Reaffirmed March 2011, Addendum
February 2015 (``API 4.2''); IBR approved for Sec. 226.113(b) and (c).
(9) API MPMS Chapter 4--Proving Systems, Section 5--Master-Meter
Provers; Fourth Edition, June 2016, (``API 4.5''); IBR approved for
Sec. 226.113(b).
(10) API MPMS Chapter 4--Proving Systems, Section 6--Pulse
Interpolation; Second Edition, May 1999; Errata April 2007; Reaffirmed
October 2013 (``API 4.6''); IBR approved for Sec. 226.113(c).
(11) API MPMS Chapter 4--Proving Systems, Section 8--Operation of
Proving Systems; Second Edition, September 2013 (``API 4.8''); IBR
approved for Sec. 226.113(b).
(12) API MPMS Chapter 4--Proving Systems, Section 9--Methods of
Calibration for Displacement and Volumetric Tank Provers, Part 2--
Determination of the Volume of Displacement and Tank Provers by the
Waterdraw Method of Calibration; First Edition, December 2005;
Reaffirmed July 2015 (``API 4.9.2''); IBR approved for Sec.
226.113(b).
(13) API MPMS Chapter 5--Metering, Section 6--Measurement of Liquid
Hydrocarbons by Coriolis Meters; First Edition, October 2002;
Reaffirmed November 2013 (``API 5.6''); IBR approved for Sec. Sec.
226.111(d); 226.113(i) and (j).
(14) API MPMS Chapter 6--Metering Assemblies, Section 1--Lease
Automatic Custody Transfer (LACT) Systems; Second Edition, May 1991;
Reaffirmed May 2012 (``API 6.1''); IBR approved for Sec. 226.110(a)
and (b).
(15) API MPMS Chapter 7--Temperature Determination, Section 1--
Liquid-in-glass Thermometers, Second Edition, August 2017 (``API
7.1''); IBR approved for Sec. 226.108(b).
(16) API MPMS Chapter 7--Temperature Determination, Section 2--
Portable Electronic Thermometers; Third Edition, May 2018 (``API
7.2''); IBR approved for Sec. 226.108(b).
(17) API MPMS Chapter 7--Temperature Determination, Section 4--
Dynamic Temperature Measurement, Second Edition, January 2018 (``API
7.4''); IBR approved for Sec. 226.110(b).
(18) API MPMS Chapter 8--Sampling, Section 1--Standard Practice for
Manual Sampling of Petroleum and Petroleum Products; Fourth Edition,
October 2013 (``API 8.1''); IBR approved for Sec. Sec. 226.108(b);
226.113(i).
(19) API MPMS Chapter 8--Sampling, Section 2--Standard Practice for
Automatic Sampling of Petroleum and Petroleum Products; Fourth Edition,
November 2016 (``API 8.2''); IBR approved for Sec. Sec. 226.110(b);
226.113(i).
(20) API MPMS Chapter 8--Sampling, Section 3--Standard Practice for
Mixing and Handling of Liquid Samples of Petroleum and Petroleum
Products; First Edition, October 1995; Reaffirmed, March 2015 (``API
8.3''); IBR approved for Sec. Sec. 226.110(b); 226.113(i).
(21) API MPMS Chapter 9--Density Determination, Section 1--Standard
Test Method for Density, Relative Density, or API Gravity of Crude
Petroleum and Liquid Petroleum Products by Hydrometer Method; Third
Edition, December 2012; Reaffirmed May 2017 (``API 9.1''); IBR approved
for Sec. Sec. 226.108(b); 226.110(b).
(22) API MPMS Chapter 9--Density Determination, Section 2--Standard
Test Method for Density or Relative Density of Light Hydrocarbons by
Pressure Hydrometer; Third Edition, December 2012; Reaffirmed May 2017
(``API 9.2''); IBR approved for Sec. Sec. 226.108(b); 226.110(b).
(23) API MPMS Chapter 9--Density Determination, Section 3--Standard
Test Method for Density, Relative Density, and API Gravity of Crude
Petroleum and Liquid Petroleum Products by Thermohydrometer Method;
Third Edition, December 2012; Reaffirmed May 2017 (``API 9.3''); IBR
approved for Sec. Sec. 226.108(b); 226.110(b).
(24) API MPMS Chapter 10--Sediment and Water, Section 4--
Determination of Water and/or Sediment in Crude Oil by the Centrifuge
Method (Field Procedure); Fourth Edition, October 2013; Errata March
2015 (``API 10.4''); IBR approved for Sec. Sec. 226.108(b);
226.110(b).
(25) API MPMS Chapter 11--Physical Properties Data, Section 1--
Temperature and Pressure Volume Correction Factors for Generalized
Crude Oils, Refined Products and Lubricating Oils; May 2004, Addendum 1
September 2007, Addendum 2 May 2019; Reaffirmed August 2012 (``API
11.1''); IBR approved for Sec. Sec. 226.109(g); 226.110(b);
226.111(e); 226.114(a).
(26) API MPMS Chapter 12--Calculation of Petroleum Quantities,
Section 2--Calculation of Petroleum Quantities Using Dynamic
Measurement Methods and Volumetric Correction Factors, Part 2--
Measurement Tickets; Third Edition, June 2003; Reaffirmed February 2016
(``API 12.2.2''); IBR approved for Sec. 226.110(b).
(27) API MPMS Chapter 12--Calculation of Petroleum Quantities,
Section 2--Calculation of Petroleum Quantities Using Dynamic
Measurement Methods and Volumetric Correction Factors, Part 3--Proving
Report; First Edition, October 1998; Reaffirmed May 2014 (``API
12.2.3''); IBR approved for Sec. 226.113(c) and (j).
(28) API MPMS Chapter 12--Calculation of Petroleum Quantities,
Section 2--Calculation of Petroleum Quantities Using Dynamic
Measurement Methods and Volumetric Correction Factors, Part 4--
Calculation of Base Prover Volumes by the Waterdraw
[[Page 2455]]
Method; First Edition, December 1997; Reaffirmed September 2014 (``API
12.2.4''); IBR approved for Sec. 226.113(b).
(29) API MPMS Chapter 13--Statistical Aspects of Measuring and
Sampling, Section 3--Measurement Uncertainty; Second Edition, December
2017 (``API 13.3''); IBR approved for Sec. 226.106(a).
(30) API Manual of Petroleum Measurement Standards (MPMS) Chapter
14--Natural Gas Fluids Measurement, Section 1--Collecting and Handling
of Natural Gas Samples for Custody Transfer; Seventh Edition, May 2016;
Addendum August 2017; Errata August 2017 (``API 14.1''); IBR approved
for Sec. Sec. 226.130(b) and (c); 226.131(c); 226.132(b).
(31) API MPMS Chapter 14--Natural Gas Fluids Measurement, Section
3--Orifice Metering of Natural Gas and Other Related Hydrocarbon
Fluids--Concentric, Square-edged Orifice Meters, Part 1--General
Equations and Uncertainty Guidelines; Fourth Edition, September 2012;
Errata July 2013; Reaffirmed September 2017 (``API 14.3.1''); IBR
approved for Sec. Sec. 226.106(a); 226.120(a).
(32) API MPMS Chapter 14--Natural Gas Fluids Measurement, Section
3--Orifice Metering of Natural Gas and Other Related Hydrocarbon
Fluids--Concentric, Square-edged Orifice Meters, Part 2--Specification
and Installation Requirements; Fifth Edition, March 2016; Errata 1,
March 2017; Errata 2, January 2019 (``API 14.3.2''); IBR approved for
Sec. 226.121(b) through (f), (h), (i), and (l).
(33) API MPMS Chapter 14--Natural Gas Fluids Measurement, Section
3--Orifice Metering of Natural Gas and Other Related Hydrocarbon
Fluids--Concentric, Square-edged Orifice Meters, Part 3--Natural Gas
Applications; Fourth Edition, November 2013 (``API 14.3.3''); IBR
approved for Sec. Sec. 226.124(b); 226.127(a).
(34) API MPMS, Chapter 14--Natural Gas Fluids Measurement, Section
5--Calculation of Gross Heating Value, Relative Density,
Compressibility and Theoretical Hydrocarbon Liquid Content for Natural
Gas Mixtures for Custody Transfer; Third Edition, January 2009;
Reaffirmed November 2020 (``API 14.5''); IBR approved for Sec. Sec.
226.138(c); 226.140(a).
(35) API MPMS Chapter 18--Custody Transfer, Section 1--Measurement
Procedures for Crude Oil Gathered from Small Tanks by Truck; Third
Edition, May 2018 (``API 18.1''); IBR approved for Sec. 226.108(b).
(36) API MPMS Chapter 21--Flow Measurement Using Electronic
Metering Systems, Section 1--Electronic Gas Measurement; Second
Edition, February 2013 (``API 21.1''); IBR approved for Sec. Sec.
226.125(a) and (g); 226.126(a), (c), and (d); 226.127(c); 226.128(a)
through (d).
(37) API MPMS Chapter 21--Flow Measurement Using Electronic
Metering Systems, Section 2--Electronic Liquid Volume Measurement Using
Positive Displacement and Turbine Meters; First Edition, June 1998;
Reaffirmed October 2016 (``API 21.2''); IBR approved for Sec. Sec.
226.110(b); 226.111(e); 226.112(g).
(38) API Recommended Practice (RP) 12R1, Setting, Maintenance,
Inspection, Operation and Repair of Tanks in Production Service; Fifth
Edition, August 1997; Reaffirmed April 2008; Addendum 1, December 2017
(``API RP 12R1''); IBR approved for Sec. 226.107(b).
(39) API RP 2556, Correction Gauge Tables for Incrustation; Second
Edition, August 1993; Reaffirmed November 2013 (``API RP 2556''); IBR
approved for Sec. 226.107(f).
(b) American Gas Association (AGA), 400 North Capitol Street NW,
Suite 450, Washington, DC 20001; phone: 202-824-7000; website: https://www.aga.org.
(1) AGA Report No. 3, Orifice Metering of Natural Gas and Other
Related Hydrocarbon Fluids, Second Edition, September 1985 (``AGA
Report No. 3''); IBR approved for Sec. 226.124(b).
(2) AGA Transmission Measurement Committee Report No. 8,
Compressibility Factors of Natural Gas and Other Related Hydrocarbon
Gases; Second Edition, November 1992 (``AGA Report No. 8''); IBR
approved for Sec. Sec. 226.127(a); 226.138(d).
(c) Gas Processors Association (GPA), 6526 E. 60th Street, Tulsa,
OK 74145; phone 918-493-3872; website: https://www.gpamidstream.org.
(1) GPA Midstream Standard 2166-17, Obtaining Natural Gas Samples
for Analysis by Gas Chromatography; Reaffirmed 2017 (``GPA 2166-17'');
IBR approved for Sec. Sec. 226.131(c) and (d); 226.132(a); 226.135(a).
(2) GPA Midstream Standard 2261-20, Analysis for Natural Gas and
Similar Gaseous Mixtures by Gas Chromatography; Revised 2020 (``GPA
2261-20''); IBR approved for Sec. 226.136(a) and (c).
(3) GPA Midstream Standard 2198-16, Selection, Preparation,
Validation, Care and Storage of Natural Gas and Natural Gas Liquids
Reference Standard Blends; Revised 2016 (``GPA 2198-16''); IBR approved
for Sec. 226.136(c).
Sec. 226.1 Definitions.
(a) As used in this part, the term:
Alarm log means a log for recording any system alarm, user-defined
alarm, or error conditions (such as out-of-range temperature or
pressure) that occur. This includes a description of each alarm
condition and the times the condition occurred and cleared.
Appropriate valve means those valves that provide access to
production before it is measured for sales and that are subject to the
sealing requirements set forth in this part.
Area ratio means the smallest unrestricted area at the primary
device divided by the cross-sectional area of the meter tube. For
example, the area ratio (Ar) of an orifice plate is the area
of the orifice bore (Ad) divided by the area of the meter
tube (AD). For an orifice plate with a bore diameter (d) of
1.000 inches in a meter tube with an inside diameter (D) of 2.000
inches, the area ratio is 0.25 and is calculated as follows:
[GRAPHIC] [TIFF OMITTED] TP13JA23.006
As-found means the reading of a mechanical or electronic transducer
when compared to a certified test device, prior to making any
adjustments to the transducer.
[[Page 2456]]
As-left means the reading of a mechanical or electronic transducer
when compared to a certified test device after adjusting the
transducer, but prior to returning the transducer to service.
Audit means a review of production reporting, royalty reporting, or
payment activities of lessees, designees, or other persons or entities
who report production or pay royalties, rents, bonuses, or other
revenues on leases or properties where a lease, or portion of a lease,
is committed to a cooperative agreement.
Automatic ignition system means an automatic ignitor and, where
needed to ensure continuous combustion, a continuous pilot flame.
Averaging period means the previous 12 months or life of the meter,
whichever is shorter. For an FMP that measures production from a newly
drilled well, the averaging period excludes production from the well
that occurred during or prior to the first full month of production.
Barrel (bbl) means 42 standard United States gallons.
Beta (or diameter) ratio means the reference inside diameter
(measured inside diameter corrected to a reference temperature of 68
[deg]F) of the orifice bore divided by the reference inside diameter of
the meter tube. This is also referred to as a diameter ratio.
Bias means a shift in the mean value of a set of measurements away
from the true value of what is being measured.
Business day means any day Monday through Friday, excluding
weekends and Federal holidays.
Bypass means any piping or equipment used at an FMP to go around or
otherwise avoid a meter or other measurement device, or any component
thereof, to allow oil or gas to flow without accountability. Equipment
that allows the changing of the orifice plate of a gas meter without
bleeding the pressure off the gas meter run (e.g., senior fitting) is
not a bypass.
Capture means the physical containment of natural gas for
transportation to market or productive use of natural gas and includes
injection and royalty-free on-site uses pursuant to the regulations in
this part.
Calendar day means all days in a month, including weekends and
Federal holidays.
Composite meter factor means a meter factor corrected from normal
operating pressure to base pressure. The composite meter factor is
determined by proving operations where the pressure is considered
constant during the measurement period between provings. This
definition applies to liquid meter provings only.
Configuration log means a record that contains all selected flow
parameters used in the generation of a quantity transaction record.
Cooperative agreement means a binding legal agreement between two
or more parties for the development or operation of a designated area
as a single unit without regard to separate ownership of the leased
lands included in the agreement. Such cooperative agreements include,
but are not limited to, unit agreements and communitization agreements.
Coriolis measurement system (CMS) means a metering system using a
Coriolis meter in conjunction with a tertiary device, pressure
transducer, and temperature transducer to derive and report gross
standard oil volume. A CMS system provides real-time, on-line
measurement of oil.
Deleterious substance means any chemical, saltwater, oil field
brine, waste oil, waste emulsified oil, basic sediment, mud, or other
injurious substance produced or used in the drilling, development,
production, transportation, refining, and processing of oil and gas.
Director means the Director of ONRR, the Director's authorized
representative acting under delegated authority, or such other person
as the Director may delegate to fulfill responsibilities and exercise
authorities under this part.
Discharge coefficient means an empirically derived correction
factor that is applied to the theoretical differential flow equation to
calculate a flow rate that is within stated uncertainty limits.
Drainage means the migration of hydrocarbons, inert gases, or
associated resources caused by production from other wells.
Effectively sealed means sealed in such a manner that the sealed
component cannot be accessed, moved, or altered without breaking the
seal.
Element range means the difference between the minimum and maximum
value that the element of a mechanical recorder (e.g., differential-
pressure bellows, static pressure element, temperature element) is
designed to measure.
Ephemeral stream or water source means a stream or water source
that only flows in direct response to precipitation and whose channel
is always above the water table.
Escape rate means the maximum volume of gas determined to be
available for escape (Q), calculated as follows:
(1) For production facilities, the maximum daily rate of gas
produced through that facility or the best estimate thereof;
(2) For oil wells, the producing gas/oil ratio multiplied by the
maximum daily production rate or the best estimate thereof; and
(3) For gas wells, the current daily absolute open flow rate
against atmospheric pressure.
Event log means an electronic record of all exceptions and changes
to the flow parameters contained within the configuration log that have
an impact on a quantity transaction record.
Facility measurement point (FMP) means a point where oil or gas
produced from a lease is measured and such measurement affects
calculation of the volume or quality of production on which royalty is
owed. Each individual meter installation (including its primary,
secondary, and tertiary devices) and tank battery is a separate FMP.
Free water means the measured volume of water that is present in a
container and that is not in suspension in the contained liquid at
observed temperature.
Gas means any fluid, either combustible or non-combustible,
hydrocarbon or non-hydrocarbon, which is extracted from a reservoir and
has neither independent shape nor volume, but tends to expand
indefinitely, and which exists in a gaseous or rarefied state under
standard temperature and pressure conditions.
Gas-to-oil ratio (GOR) means the ratio of gas to oil in the
production stream expressed in standard cubic feet of gas per barrel of
oil.
Gas plant products means separate marketable elements, compounds,
or mixtures, whether in liquid, gaseous, or solid form, resulting from
processing gas. This does not include residue gas.
Gas well means a well that produces natural gas that is not
associated with oil at the time of well completion or for which the
energy equivalent of the gas produced, including its entrained
liquefiable hydrocarbons, exceeds the energy equivalent of the oil
produced by at least 15,000 standard cubic feet for each barrel of oil
produced at the time of well completion.
Geophysical exploration means activity relating to the search for
evidence of oil and gas which requires physical presence upon surface
lands and may result in damage to the lands or resources located
thereon. This includes, but is not limited to, geophysical operations,
construction of roads and trails, cross-country transit of vehicles,
and drilling operations to place explosive charges, where
[[Page 2457]]
approved. This does not include drilling for oil and gas.
Gross proceeds means the total monies and other consideration
accruing to a lessee for the disposition of the oil, gas, or other
marketable products produced.
Gross standard volume means a volume of oil corrected to base
pressure and temperature and includes meter factor, as applicable.
Heating value means the gross heat energy released by the complete
combustion of one standard cubic foot of gas at 14.73 psia and 60
[deg]F.
High-volume FMP means any gas FMP that measures more than 200 Mcf/
day, but less than 1,000 Mcf/day, over the averaging period. This
definition only applies to gas FMPs; it does not apply to oil FMPs on
an equivalent-gas basis.
Indicated volume means the uncorrected volume indicated by the
meter in a LACT system or the Coriolis meter in a CMS. For a positive
displacement meter, the indicated volume is represented by the non-
resettable totalizer on the meter head. For Coriolis meters, the
indicated volume is the uncorrected (without the meter factor) mass of
liquid divided by the density.
Innage gauge means the level of a liquid in a tank, measured from
the datum plate or tank bottom to the surface of the liquid.
Intermittent stream or water source means a stream or water source
flowing only at certain times of the year when it receives water from
springs or other surface sources.
Knowingly or willfully means an act, or failure to act, that is
committed with actual knowledge, deliberate ignorance, or reckless
disregard of the facts surrounding the event or violation; it requires
no proof of specific intent to defraud. The knowing or willful nature
of conduct may be established by plain indifference or reckless
disregard of the terms and conditions of the lease or permit or
applicable laws, regulations, orders, or notices. A consistent pattern
of performance, or failure to perform, may be sufficient to establish
the knowing or willful nature of the conduct. Conduct that is regarded
as knowing or willful is not accidental, nor is it mitigated by the
belief that the conduct is reasonable or legal.
Lease means any contract approved by the United States under the
Act of June 28, 1906, Public Law 59-321, 34 Stat. 539, as amended, that
authorizes exploration for, or the extraction and removal of, oil and
gas from the Osage Mineral Estate.
Lease automatic custody transfer (LACT) system means a system of
components designed for the unattended custody transfer of oil produced
from a lease or unit to the transporting carrier. The system must
determine the net standard volume and quality and provide for safe and
tamper-proof operations.
Legal description means the geographical description of a location
utilizing the quarter-section, section, township, and range.
Lessee means any person holding record title to, or owning
operating rights in, an oil and/or gas lease issued under the
regulations in this part and any authorized representative thereof,
including any designee who reports production or submits royalty
payments on behalf of the lessee.
Liquids unloading means the removal of an accumulation of liquid
hydrocarbons or water from the wellbore of a completed gas well.
Lost oil or gas means produced oil or gas that escapes containment,
whether such loss is intentional or unintentional, or that is flared
before being removed from the lease or unit and cannot be recovered.
Low-volume FMP means any gas FMP that measures more than 35 Mcf/
day, but less than or equal to 200 Mcf/day, over the averaging period.
This definition only applies to gas FMPs; it does not apply to oil FMPs
on a gas-equivalent basis.
Marketable condition means a condition in which lease products are
sufficiently free from impurities or otherwise so conditioned that a
purchaser will accept them under a sales contract typical for the field
or area.
Maximum ultimate economic recovery means the recovery of oil and
gas that a prudent lessee could be expected to make from the field or
reservoir given existing knowledge and other pertinent facts and
utilizing common industry practices for primary, secondary, or tertiary
recovery operations.
Meter factor means a ratio obtained by dividing the measured volume
of liquid that passed through a prover or master meter during the
proving by the measured volume of liquid that passed through the line
meter during the proving, corrected to base pressure and temperature.
Mole percent means the number of molecules of a particular type
that are present in a gas mixture divided by the total number of
molecules in the gas mixture, expressed as a percentage.
Monthly Index Zone Price means the index-based value per MMBtu for
gas production from a lease in an index zone. The Monthly Index Zone
Price is calculated by averaging the highest reported prices for all
index-pricing points in the relevant index zone for each ONRR-approved
publication, summing those averages, dividing by the number of ONRR-
approved publications, and reducing the number calculated by 10
percent, but not by less than 10 cents per MMBtu or more than 30 cents
per MMBtu.
Natural gas liquids (NGLs) means gas plant products consisting of
ethane, propane, butane, or heavier liquid hydrocarbons.
Net standard volume means the gross standard volume corrected for
quantities of non-merchantable substances such as sediment and water.
NYMEX Calendar Month Average Price means the average of the New
York Mercantile Exchange (NYMEX) daily settlement prices for light
sweet crude oil delivered at Cushing, Oklahoma, calculated as follows:
(1) Sum the prices published for each day during the calendar month of
production, excluding weekends and Federal holidays, for oil to be
delivered in the nearest month of delivery for which NYMEX futures
prices are published corresponding to each such day; and (2) Divide the
sum by the number of days on which those prices are published,
excluding weekends and Federal holidays.
Oil well means a well for which the energy equivalent of the oil
produced exceeds the energy equivalent of the gas produced at the time
of completion.
Operating right (working interest) means a percentage of ownership
in a lease granting the owner the right to enter upon the leased lands
to conduct exploratory, drilling, or related operations, including the
production of oil and gas, in accordance with the terms and conditions
of the lease.
Orphan well means an oil, gas, disposal, injection, or service well
that is no longer in use whether dry, inoperable, or incapable of
production; that the current lessee did not assume through assignment;
that has not been drilled, re-entered, operated, or affected by the
current lessee; and for which there is no legally or financially
responsible party with sufficient resources to conduct proper plugging,
abandonment, and surface restoration operations.
Osage Minerals Council means the independent agency within the
Osage Nation created by Article XV, section 4, of the Constitution of
the Osage Nation (2006) with administrative authority to consider and
approve leases of the Osage Mineral Estate and propose other forms of
development thereof, and its successors in interest.
[[Page 2458]]
Osage Mineral Estate means the subsurface mineral estate underlying
Osage County, Oklahoma that is held in trust by the United States for
the benefit of the Osage Nation in accordance with the Act of June 28,
1906, Public Law 59-321, section 3, 34 Stat. 539, as amended.
Osage Nation means the federally recognized Indian Tribe referred
to by Article I of the Constitution of the Osage Nation (2006) and its
predecessors and successors in interest.
Perennial stream or water source means a stream or water source
that flows continuously.
Permittee means any person, other than a lessee, who applies for
and receives a geophysical exploration permit.
Person means any individual, corporation, partnership, association,
firm, consortium, joint venture, or other entity.
Primary term means the initial term of the lease during which the
lease contract may be kept in force by either commencement of
production in paying quantities or the payment of annual rental.
Production in paying quantities means production of oil or gas from
a lease that is of sufficient value to exceed direct operating costs
and the cost of annual rental or minimum royalty.
Production phase means that event during which oil is delivered
directly to or through production equipment to the storage facilities
and includes all operations at the facility other than those defined as
being within the sales phase.
Prompt month means the nearest month of delivery for which NYMEX
futures prices are published during the trading month.
Quantity transaction record (QTR) means a report generated by a
flow computer on a LACT, CMS, or other approved system that summarizes
the daily and/or hourly volume calculated by the flow computer and the
average or totals of the dynamic data that is used in the calculation
of gross standard volume.
Record title means a lessee's interest in a lease which includes
the obligation to pay rental and the right to assign or surrender the
lease. Overriding royalty and operating rights are severable from
record title interests.
Regional Director means the Regional Director for the Eastern
Oklahoma Region, Bureau of Indian Affairs, or the Regional Director's
authorized representative acting under delegated authority.
Residue gas means hydrocarbon gas consisting principally of methane
and resulting from processing gas.
Sales phase means that event during which oil is removed from
storage facilities at an FMP for sale.
Seal means a uniquely numbered device that completely secures
either a valve or those components of a measuring system that affect
the quality or quantity of the oil being measured.
Senior fitting means a type of orifice plate holder that allows the
orifice plate to be removed, inspected, and replaced without isolating
and depressurizing the meter tube.
Slop oil means oil that is of such quality that it is not
acceptable to normal purchasers and is usually sold to oil reclaimers.
Oil that can be made acceptable to normal purchasers through special
treatment economically provided at existing or modified facilities or
using portable equipment at, or upstream of, the FMP, is not slop oil.
Source record means any unedited, original record, document, or
data that is used to determine the volume and quality of production,
regardless of how it was created or stored or the format it is in
(i.e., paper or electronic). This includes, but is not limited to, raw
and unprocessed data (e.g., instantaneous and continuous information
used by flow computers to calculate volumes); gas charts; run tickets;
calibration, verification, prover and configuration reports; lessee
field logs; volume statements; event logs; seal records; and gas
analyses.
Statistically significant means a difference between two data sets
that exceeds the threshold of significance. The threshold of
significance is the maximum difference between two data sets (a and b)
that can be attributed to uncertainty effects, and is calculated as
follows:
[GRAPHIC] [TIFF OMITTED] TP13JA23.007
Where:
Ts = Threshold of significance, in percent
Ua = Uncertainty (95 percent confidence) of data set
a, in percent
Ub = Uncertainty (95 percent confidence) of data set
b, in percent
Superintendent means the Superintendent of the Osage Agency, Bureau
of Indian Affairs, the Superintendent's authorized representative
acting under delegated authority, or such other person or official that
may be delegated to fulfill responsibilities and exercise authorities
under this part.
Surface owner means any person who owns a surface estate within
Osage County, Oklahoma, regardless of whether the surface estate is
held in fee, restricted fee, or trust status.
Total observed volume (TOV) means the total measured volume of all
oil, sludge, S&W, and free water at the measured or observed
temperature and pressure.
Trading month means the period extending from the second business
day before the 25th day of the second calendar month preceding the
delivery month (or, if the 25th day of that month is a non-business
day, the second business day before the last business day preceding the
25th day of that month) through the third business day before the 25th
day of the calendar month preceding the delivery month (or if the 25th
day of that month is a non-business day, the third business day before
the last business day preceding the 25th day of that month), unless the
NYMEX publishes a different definition or different dates on its
official website, http://www.cmegroup.com, in which case the NYMEX
definition will apply.
Upper calibrated limit means the maximum engineering value for
which a transducer was calibrated by certified equipment, either in the
factory or in the field.
US well number means a unique, permanent numeric identifier
assigned to each oil and gas well drilled in the United States that
includes the completion code.
Very-high-volume FMP means any gas FMP that measures more than
1,000 Mcf/day over the averaging period. This definition only applies
to gas FMPs; it does not apply to oil FMPs on an equivalent-gas basis.
Very-low-volume FMP means any gas FMP that measures 35 Mcf/day or
less over the averaging period. This definition only applies to gas
FMPs; it does not apply to oil FMPs on an equivalent-gas basis.
Waste of oil or gas means any action or inaction by the lessee that
is not sanctioned by the Superintendent as necessary for proper
development and production, where compliance costs are not greater than
the monetary value of the resources they are expected to conserve, and
that results in:
(1) A reduction in the quality or quantity of oil or gas ultimately
producible from a reservoir under prudent and proper operations; or
(2) Avoidable surface loss of oil or gas.
Waste oil means oil that the Superintendent determined is of such
quality that it cannot be treated economically and put in a marketable
condition with existing or modified lease facilities or portable
equipment, cannot be sold to reclaimers, and has no economic value.
[[Page 2459]]
(b) As used in this part, the following acronyms apply:
API means American Petroleum Institute.
BIA means Bureau of Indian Affairs.
Btu means British thermal unit.
CPL means correction for the effect of pressure on a liquid.
CTL means correction for the effect of temperature on a liquid.
FCCP means a Failure to Correct Civil Penalty Notice.
ft msl means feet above mean sea level.
GPA means Gas Processors Association.
GPS means Global Positioning System.
IBIA means the Interior Board of Indian Appeals, Office of Hearings
and Appeals.
IBLA means the Interior Board of Land Appeals, Office of Hearings
and Appeals.
ILCP means an Immediate Liability Civil Penalty Notice.
IRS means Internal Revenue Service.
Mcf means 1,000 standard cubic feet.
MMBtu means million metric British thermal units.
MMcf means million cubic feet.
NIST means National Institute of Standards and Technology.
NONC means a Notice of Noncompliance.
NTL means Notice to Lessee(s).
ONRR means Office of Natural Resources Revenue.
psia means pounds per square inch--absolute.
psig means pounds per square inch--gauge.
S&W means sediment and water.
SWD means saltwater disposal.
Sec. 226.2 Authorities that govern oil and gas activities within the
Osage Mineral Estate.
All oil and gas exploration and development activities conducted
within the Osage Mineral Estate are subject to:
(a) The regulations in this part;
(b) Lease and permit terms and conditions;
(c) Orders, notices, and instructions the Superintendent issues;
(d) Orders, notices, and instructions ONRR issues; and
(e) All other applicable laws, regulations, and authorities.
Sec. 226.3 Authority and responsibility of the Superintendent of the
Osage Agency.
The Superintendent of the Osage Agency has the authority and
responsibility to administer leasing and development of the Osage
Mineral Estate.
Sec. 226.4 Authority and responsibility of the Office of Natural
Resources Revenue (ONRR).
The Office of Natural Resources Revenue (ONRR) has the authority
and responsibility for administering the Osage Agency's royalty
management program including, but not limited to, royalty and
production accounting, reporting, verification, collection,
enforcement, and appeals.
Sec. 226.5 Orders and notices.
(a) The Superintendent is authorized to issue orders and notices
when necessary to implement, supplement, clarify, and enforce the
regulations in this part. Orders and notices the Superintendent issues
under this section are binding on the lessee and any other persons they
apply to. The Superintendent may, in their discretion, grant an
extension of the time to comply with an order or notice.
(b) ONRR is authorized to issue orders and notices when necessary
to implement, supplement, clarify, and enforce the regulations in this
part. Orders that ONRR issues under this section are binding on the
lessee and any other persons they apply to.
Sec. 226.6 Service of official correspondence.
(a) The Superintendent and ONRR will serve all official
correspondence by regular U.S. mail, certified mail--return receipt
requested, private delivery service (i.e., UPS or FedEx), or hand
delivery.
(b) The Superintendent will serve official correspondence to the
party identified on the most recently received Lease Contact of Record
form. The lessee is responsible for notifying the Superintendent of any
change in the designated point of contact's name, address, or phone
number by submitting an updated form within two weeks of any such
change.
(c) ONRR will serve official correspondence to the party identified
on the most recently received Form ONRR-4444, Address/Addressee of
Record, for the type of correspondence at issue. The reporter is
responsible for notifying ONRR of any name or address changes within
two weeks of any such change.
(d) If the lessee, reporting party, or payor fails to submit or
update contact information in accordance with the requirements in this
section:
(1) The Superintendent may use the name and address listed on the
lease; and
(2) ONRR may use the individual or departmental name, address, or
position title, contained in ONRR's database based on previous formal
or informal communications or correspondence.
(e) The Superintendent and ONRR may also obtain contact information
from public records and send official correspondence to:
(1) The registered agent;
(2) A corporate officer; or
(3) The addressee of record reflected in the files of any state
Secretary, any Federal or state agency that keeps official records of
business entities or corporations, or other appropriate public records
for individuals, business entities, and corporations.
(f) The Superintendent and ONRR consider the date of service for
official correspondence to be:
(1) Seven calendar days for regular U.S. mail;
(2) The date of receipt for certified mail--return receipt
requested and private delivery service; and
(3) The date of delivery for hand delivery.
(g) If, the Superintendent or ONRR serves official correspondence
using multiple methods and the dates of receipt differ, the date of the
earliest receipt is the date of service.
(h) If, after a reasonable effort, the Superintendent or ONRR are
unable to deliver official correspondence to the contact of record, the
correspondence will be considered constructively served seven calendar
days after the original mailing date. This includes, but is not limited
to, situations where delivery does not occur because:
(1) The contact of record moved without filing a forwarding
address, Lease Contact of Record form, or ONRR Form-4444;
(2) The forwarding order expired;
(3) Delivery was expressly refused; or
(4) The correspondence was unclaimed and the U.S. Postal Service, a
private mailing service, or an individual who attempted to make
delivery using a different method of service substantiates the delivery
attempt.
Sec. 226.7 Forms.
Leases, assignments, applications, bonds, affidavits, reports, and
other instruments must be on forms approved by the Superintendent or
ONRR. Only the official version and current edition of such forms will
be accepted.
Sec. 226.8 Acceptable forms of payment.
All sums due under a lease or the regulations in this part must be
paid by electronic funds transfer (EFT), certified check, cashier's
check, money order, or commercial or personal check drawn on a solvent
bank, otherwise specified herein or notified by the Superintendent or
ONRR in writing. Such sums constitute a prior lien on all equipment
[[Page 2460]]
and unsold oil located on the lease or unit.
Sec. 226.9 Environmental reviews and cultural surveys.
Prior to approving leases and permit applications for operations
requiring new or additional ground-disturbance, the Superintendent
must:
(a) Ensure that environmental review has been conducted in
accordance with the National Environmental Policy Act of 1969 (NEPA),
42 U.S.C. 4321, et seq., the regulations promulgated by the Council on
Environmental Quality (CEQ), 40 CFR parts 1500 through 1508, and the
Department's regulations implementing NEPA, 43 CFR part 46, and that an
environmental record of review (e.g., categorical exclusion checklist,
determination of NEPA adequacy), environmental assessment, or
environmental impact statement has been prepared, as appropriate.
(b) Ensure that all necessary archeological or cultural surveys are
performed, and clearances obtained, in accordance with the National
Historic Preservation Act (NHPA), 54 U.S.C. 300101, et seq., the
regulations promulgated by the Advisory Council on Historic
Preservation, 36 CFR part 800 et seq., and the Archaeological Resources
Protection Act of 1979 (ARPA), 16 U.S.C. 470aa-470mm, as applicable.
Sec. 226.10 Information collection.
The collections of information in this part have been approved by
the Office of Management and Budget under 44 U.S.C. 3501 et seq. and
assigned OMB Control Number 1076-0180 (BIA collections) and OMB Control
Numbers 1012-0004 and 1012-0006 (ONRR collections). Response is
required to obtain a benefit. A Federal agency may not conduct or
sponsor, and you are not required to respond to, a collection of
information unless it displays a valid OMB Control Number.
Sec. 226.11 Public availability of information.
The BIA and ONRR will make all records and information submitted in
accordance with the regulations in this part available to the public
for inspection, without notification of the submitter, subject to the
following exceptions:
(a) Trade secrets;
(b) Privileged or confidential commercial or financial information;
and
(c) Information protected from disclosure by the Privacy Act (5
U.S.C. 552a).
Subpart B--Acquiring a Lease
Authorized Procedures
Sec. 226.12 Procedures the Osage Minerals Council may use to enter
into a lease.
The Osage Minerals Council may utilize the following procedures to
enter into a lease of the Osage Mineral Estate:
(a) Competitive bidding at an advertised lease sale; or
(b) Negotiation with prospective lessees. The Osage Minerals
Council may negotiate directly or request that the Superintendent
undertake negotiation on its behalf. Requests that the Superintendent
negotiate leases must be submitted in writing together with a
resolution authorizing such negotiation.
Competitive Leases
Sec. 226.13 Advertisement of a lease sale.
(a) The Osage Minerals Council may request that the Superintendent
advertise a competitive lease sale. Such requests must be submitted to
the Superintendent in writing at least 60 calendar days in advance of
the date the Osage Minerals Council would like the Notice of Lease Sale
published, together with a resolution authorizing the lease sale. The
resolution must identify the:
(1) Location, date, and time of the lease sale; and
(2) Minimum acceptable bid.
(b) Upon receipt of the Osage Minerals Council's written request
under paragraph (a) of this section, the Superintendent will publish a
Lease Sale Bulletin advertising the lease sale and calling for
nominations.
Sec. 226.14 Nominating lands for a lease sale.
(a) You must submit a nomination letter to the Superintendent to
nominate lands for a lease sale. The nomination letter must:
(1) Include the name and address of the person making the
nomination;
(2) Identify the legal description of the lands nominated; and
(3) Be legible and signed in ink.
(b) Nomination letters must be submitted to the Superintendent by
mail or hand delivery prior to expiration of the nomination period
identified in the Lease Sale Bulletin. Nomination letters that do not
meet the requirements in paragraph (a) of this section will be
rejected.
Sec. 226.15 Publication of a Notice of Lease Sale.
The Superintendent will publish a Notice of Lease Sale at least 30
calendar days prior to the date of the sale. The Notice of Lease Sale
will offer leases for sale to the highest responsible bidder and
identify the nominated lands; primary term of each lease offered;
location, date, and time of the sale; and method for submitting bids.
Sec. 226.16 Bidding system.
(a) Leases will be offered for sale by competitive bonus bidding
under the terms and conditions specified in the Notice of Lease Sale
and in accordance with applicable laws and regulations.
(b) All bids are subject to the Osage Minerals Council's acceptance
and the Superintendent's approval. The Superintendent reserves the
right to reject any bid and may require any bidder to submit evidence
of good faith and ability to comply with the requirements in the Notice
of Lease Sale.
(c) A winning bid is the highest bid by a qualified bidder that is
equal to, or exceeds, the minimum acceptable bid.
(d) Each successful bidder must deposit 25 percent of the bonus bid
with the Superintendent by 4:30 p.m. central standard time on the day
of the lease sale. Deposits must be paid by EFT, cashier's check, or
money order.
Sec. 226.17 Award of leases.
(a) A successful bidder must deposit the following with the
Superintendent within 20 calendar days of the lease sale:
(1) The balance of the bonus;
(2) An executed Oil and Gas Mining Lease form;
(3) An Evidence of Authority to Execute Papers form; and
(4) A certificate of good standing issued by the Oklahoma Secretary
of State.
(b) The Superintendent may extend the time for submitting the
executed lease, evidence of authority to execute papers, and
certificate of good standing. No extension of time may be granted for
depositing the balance of the bonus.
(c) The bonus, or any portion thereof, deposited with the
Superintendent will be forfeited for the use and benefit of the Osage
Nation if:
(1) A successful bidder fails to pay the bonus in full by the
required deadline;
(2) A successful bidder fails to file the items in paragraphs
(a)(2) through (4) of this section by the required deadline; or
(3) The Superintendent denies approval of the lease pursuant to
paragraph (d) of this section, through no fault of the Osage Minerals
Council or BIA.
(d) Competitive leases are subject to the Superintendent's
approval. The Superintendent may deny the approval of a lease executed
by a successful bidder upon satisfactory evidence of collusion, fraud,
or other irregularity.
[[Page 2461]]
Non-Competitive Leases
Sec. 226.18 Submitting an offer to lease.
(a) You may submit non-competitive offers to lease the Osage
Mineral Estate to the Osage Minerals Council. Such offers must include
the:
(1) Name and address of the offeror;
(2) Legal description of the lands covered by the proposed lease;
(3) Bonus amount; and
(4) Such other information as may be required by the Osage Minerals
Council.
(b) Upon receipt of a non-competitive offer to lease, the Osage
Minerals Council may accept the offer, reject the offer, or enter
negotiations with the offeror directly or through the Superintendent.
Sec. 226.19 Acceptance of an offer to lease.
(a) A successful offeror must deposit the following with the
Superintendent within 20 calendar days of the Osage Minerals Council's
acceptance of a non-competitive offer to lease:
(1) The full bonus;
(2) An executed Oil and Gas Mining Lease form;
(3) An Evidence of Authority to Execute Papers form; and
(4) A certificate of good standing issued by the Oklahoma Secretary
of State.
(b) Non-competitive leases are subject to the Superintendent's
approval.
Lease Terms
Sec. 226.20 Types of leases.
All leases of the Osage Mineral Estate issued after [effective date
of final rule] will be combination oil and gas leases. Oil-only and
gas-only leases issued prior to [effective date of final rule] will
remain in full force and effect until such time as they terminate or
are cancelled but cannot be assigned unless the assignee executes a new
combination oil and gas lease covering the subject lands.
Sec. 226.21 Primary term of leases.
(a) Leases will be for a primary term established by the Osage
Minerals Council, subject to the Superintendent's approval, and will
continue so long thereafter as oil and/or gas is produced in paying
quantities.
(b) The Superintendent may approve an amendment extending the
primary term of a lease for up to two years if actual drilling
operations commenced prior to expiration of the primary term,
operations are being diligently pursued at the end of the primary term,
and the parties jointly submit a Lease Amendment form evidencing their
agreement. This includes any lease that is part of an approved
cooperative agreement where actual drilling operations took place
within the unit or area covered by the agreement. The following
requirements must be met to qualify for an extension of the primary
term:
(1) Actual drilling operations must have been conducted in a manner
consistent with serious oil and gas exploration in that area based on
existing knowledge of the geology or other pertinent facts and
information.
(2) In drilling a new well on a lease, or for the benefit of a
lease pursuant to the terms of an approved cooperative agreement, the
lessee must take the well to a depth sufficient to penetrate at least
one formation recognized as having potential to produce oil or gas.
(3) In the reentry of an existing well, the lessee must take the
well to a depth sufficient to penetrate at least one new and deeper
formation recognized as having the potential to produce oil or gas.
Sec. 226.22 Effect of changes in current regulations on existing
leases.
Leases issued pursuant to this part are subject to the current
regulations, all of which are made a part of such leases. No amendment
or change in the regulations after the approval of any lease will
operate to affect the primary term, acreage, royalty rate, or rental
set forth therein unless the parties jointly submit a Lease Amendment
form evidencing their agreement to the amended terms and the
Superintendent approves the amendment.
Sec. 226.23 U.S. Government employees may not acquire leases.
U.S. Government employees are prohibited from acquiring leases of
the Osage Mineral Estate or any interests therein.
Subpart C--Cooperative Agreements and Unitization
Sec. 226.24 Cooperative agreements.
(a) The Osage Minerals Council and lessees may unitize or merge two
or more leases into a cooperative agreement to promote the development
of any pool, field, or similar area, or any part thereof, subject to
the Superintendent's approval.
(b) The Osage Minerals Council and lessees must submit requests for
approval of cooperative agreements to the Superintendent at least 90
calendar days prior to the earliest expiration date of any of the
leases proposed to be covered by the agreement.
(c) Any agreement by the parties in interest to supplement, modify,
amend, or terminate a cooperative agreement as to all the lands
covered, or any portion thereof, is subject to the Superintendent's
approval. Upon approval of termination, the leases covered by the
cooperative agreement will be restored to their original terms.
Sec. 226.25 Unit development plans.
The Superintendent may, with the consent of the Osage Minerals
Council, require all leases issued under this part to join a unit
development plan for the purpose of preventing waste and promoting
development of the Osage Mineral Estate. Any such plan must adequately
protect the rights of all parties in interest.
Subpart D--Transferring a Lease by Assignment
Sec. 226.26 Assignment of record title interest in a lease.
(a) A lease, or any divided or undivided interest in a lease, may
be transferred by assignment subject to the Superintendent's approval.
If an assignment will only cover a portion of a lease, the transfer
requires both the Osage Minerals Council's consent and the
Superintendent's approval. The assignment of a separate zone or
deposit, or part of a legal subdivision, is prohibited.
(b) If a lease is divided by the assignment of an entire interest
in any part, the assigned and retained portions of the lease are
segregated and become separate and distinct leases.
(c) The assignor must submit the Assignment of Record Title
Interest form to the Superintendent for approval within 30 calendar
days of the date the last party executes the instrument.
Sec. 226.27 Qualifications of the assignee.
The assignee must be qualified to hold the lease, or interest
therein, under the regulations in this part and must furnish a
satisfactory bond.
Sec. 226.28 Effective date of transfer.
The effective date of the transfer is 12:01 a.m. central standard
time on the first calendar day following the day the Superintendent
approves the assignment.
Sec. 226.29 Effect of assignment on the assignor's liability under
the lease.
(a) The assignor remains liable for the performance of all lease
obligations, monetary and non-monetary, that accrue in connection with
the lease prior to the effective date of the assignment specified in
Sec. 226.28.
(b) After the assignment is approved, the Superintendent and ONRR
may require the assignor to bring the lease into compliance if the
assignee fails to satisfy an obligation that accrued prior to the
effective date of the assignment.
[[Page 2462]]
This does not include the obligation to plug and abandon wells the
assignee assumed liability for pursuant to the assignment.
Sec. 226.30 Effect of assignment on the assignee's liability under
the lease.
(a) The assignee must comply with the terms and conditions of the
lease, any approved permits for wells located thereon, and the
regulations in this part as they apply to the rights and obligations
acquired.
(b) The assignee is liable for all obligations that accrue after
the effective date of the assignment specified in Sec. 226.28
including, but not limited to, properly plugging and abandoning all
wells that the assignee drills, operates, or controls following the
effective date of the transfer and remediating environmental problems
or other lease violations, regardless of whether such problems were
identified at the time of the assignment. For purposes of this section,
an assignee is considered to ``control'' all unplugged wells located on
the lease that are recorded in the Osage Agency's plat book or that a
purchaser exercising reasonable diligence could or should have known of
at the time of the assignment, except for orphan wells that neither the
assignor nor assignee occasioned.
Sec. 226.31 Overriding royalty agreements.
(a) Agreements creating overriding royalties or payments out of
production are not considered an interest in a lease as that term is
used in Sec. 226.26.
(b) Agreements creating overriding royalties or payments out of
production are hereby authorized and do not require the
Superintendent's approval, subject to the condition that nothing in any
such agreement will be construed as modifying the lessee's obligations
under the terms and conditions of the lease or the regulations in this
part. All such obligations remain in full force and effect, the same as
if free of any overriding royalties or payments out of production.
(c) The Superintendent will not consider the existence of
agreements creating overriding royalties or payments out of production
as justification for approving the abandonment of any well, regardless
of whether they are actually paid.
(d) The Superintendent will suspend an agreement creating
overriding royalties or payments out of production if it is determined
that the working interest income of an active producing well is less
than or equal to the operational cost of the well.
Sec. 226.32 Drilling contracts.
The lessee is authorized to enter into drilling contracts with a
stipulation that nothing in such contracts may bind the Department or
otherwise require the Superintendent's approval of subsequent
assignments that may be contemplated by the contract.
Subpart E--Ending a Lease
Sec. 226.33 Surrender of all or any portion of a lease.
(a) A lessee may surrender all or any portion of a lease at any
time by submitting a written request for surrender to the
Superintendent. All parties holding record title interests in the lease
must sign the request for surrender.
(b) The Superintendent may approve the surrender, or partial
surrender, of a lease subject to the following conditions:
(1) All royalties, including minimum and compensatory royalties,
rental, interest, late charges, assessments, civil penalties, and other
amounts that may be due under the regulations in this part have been
paid in full; and
(2) All wells located on the leased lands being surrendered that
are no longer capable of producing in paying quantities have been
properly plugged and abandoned and the well sites restored.
(c) The Superintendent must obtain the Osage Minerals Council's
consent to approve the partial surrender of a lease if the acreage to
be retained is less than 160 acres.
(d) The lessee and surety are not relieved of any obligations or
liabilities under the lease or the regulations in this part until the
Superintendent approves the request for surrender.
(e) If a lease has been recorded, the lessee must execute a release
and record it in the proper office upon the Superintendent's approval
of the request for surrender.
(f) Surrender or partial surrender of a lease does not entitle the
lessee to a refund of advance rental or other sums paid under the lease
or the regulations in this part.
Sec. 226.34 Termination of a lease by operation of law.
(a) If a lessee fails to timely pay advance annual rental in
accordance with Sec. 226.35, the lease terminates by operation of law
as of the date rental was due.
(b) If a lessee fails to drill a well capable of producing oil or
gas in paying quantities during the primary term in accordance with
Sec. 226.21, the lease terminates by operation of law as of the date
the primary term expires.
(c) Any lease in the extended term upon which there are no wells
capable of producing oil or gas in paying quantities terminates by
operation of law as of the date production ceases unless the
Superintendent approved a request to temporarily abandon the wells on
the lease under Sec. 226.72.
(d) When a lease terminates, permanent improvements remain part of
the land and become the property of the surface owner unless the lessee
and surface owner agree otherwise. The lessee must file a copy of any
such agreement with the Superintendent within 15 calendar days of its
execution.
(e) The lessee must remove all trash, debris, and personal property
from the lease within 90 calendar days of termination. For purposes of
this section, personal property includes, but is not limited to, tools,
tanks, pumping and drilling equipment, derricks, engines, machinery,
tubing, and casings. Upon expiration of the 90-day removal period, the
ownership of all casings reverts to the Osage Nation and the ownership
of all other personal property transfers to the surface owner.
(f) Nothing in this section relieves the lessee of the
responsibility for removing permanent improvements and personal
property from the leased lands if the Superintendent orders such
removal.
Subpart F--Rental and Royalty
Rental Obligations
Sec. 226.35 Annual rental requirements.
(a) The annual rental for leases approved after [effective date of
final rule] is $8 per acre or fraction thereof.
(b) The lessee must pay advance annual rental for each year of the
primary term within 15 calendar days of the Superintendent's approval
of the lease. If the lease is amended to extend the primary term, the
lessee must pay advance annual rental for each additional year of the
primary term within 15 calendar days of the Superintendent's approval
of the extension.
(c) Rental must be paid for a full year and may not be prorated,
refunded, or credited against production royalty.
(d) Rental payments must be mailed to the Superintendent addressed
to: Osage Agency--BIA, Dept. C155, P.O. Box 105533, Atlanta, GA 30348-
5533.
Royalty Obligations
Sec. 226.36 Royalty rate for oil.
The lessee must pay to the Superintendent as royalty no less than
16\2/3\ percent of the value of all oil produced and removed or sold
from the lease. The Osage Minerals Council may,
[[Page 2463]]
upon presentation of justifiable economic evidence by a lessee, agree
to a lower royalty rate, of no less than 12\1/2\ percent of the value
of all oil produced and removed or sold from the lease, subject to the
Superintendent's approval. The Superintendent may only approve a lower
royalty rate if it is determined to be in the best interest of the
Osage Nation.
Sec. 226.37 Calculating the value of oil for royalty purposes.
(a) Unless the Osage Minerals Council elects to take royalty in
kind under Sec. 226.42, the value of oil for royalty purposes is the
greater of the:
(1) NYMEX Calendar Month Average Price of oil at Cushing, Oklahoma,
for the month in which the produced oil was removed or sold from the
lease, adjusted for gravity using the scale set forth in Sec. 226.38;
or
(2) Actual selling price for the transaction, adjusted for gravity
using the scale set forth in Sec. 226.38.
(b) The applicable NYMEX Calendar Month Average Price will be
published on ONRR's website at https://www.onrr.gov.
Sec. 226.38 Gravity adjustment for oil.
(a) The gravity adjustment of the NYMEX Calendar Month Average
Price of oil at Cushing, Oklahoma under Sec. 226.37(a) is a deduction
from the price per barrel, as follows:
------------------------------------------------------------------------
If the gravity of the oil is . .
. the rate is . . . for each . . .
------------------------------------------------------------------------
(1) At or between 40.0 and 44.9 zero ..................
degrees.
(2) At or between 35.0 and 39.9 $0.02............. degree or fraction
degrees. thereof below
40.0.
(3) Below 35.0 degrees.......... $0.10 plus an one-tenth of one
additional $0.015. degree below
35.0.
(4) Above 44.9 degrees.......... $0.015............ for each one-tenth
of one degree
above 44.9.
------------------------------------------------------------------------
(b) The Superintendent may, on or before the fifth calendar day of
the month following production, publish a gravity adjustment scale for
oil of gravity below 40.0 degrees or above 44.9 degrees that supersedes
this section if they determine that such adjustments are warranted
based on market conditions.
Sec. 226.39 Royalty rate for gas.
The lessee must pay to the Superintendent as royalty no less than
16\2/3\ percent of the value of all gas, including residue gas and gas
plant products, produced and removed or sold from the lease. The Osage
Minerals Council may, upon presentation of justifiable economic
evidence by a lessee, agree to a lower royalty rate, of no less than
12\1/2\ percent of the value of all gas, including residue gas and gas
plant products, produced and removed or sold from the lease, subject to
the Superintendent's approval. The Superintendent will only approve a
lower royalty rate if it is determined to be in the best interest of
the Osage Nation.
Sec. 226.40 Calculating the value of gas for royalty purposes.
Unless the Osage Minerals Council elects to take royalty-in-kind
under Sec. 226.42, the value of production for royalty purposes is
calculated by multiplying the measured volume of gas at the well (Mcf),
times the heating value of the gas (MMBtu/Mcf), times the Monthly Index
Zone Price of the gas ($/MMBtu) for Oklahoma Zone 1 published by ONRR
on its website, https://www.onrr.gov. The heating value of the gas must
be calculated and reported in accordance with Sec. Sec. 226.140(a) and
(b) and 226.141, respectively. If the Monthly Index Zone Price ceases
to be published or is otherwise unavailable, the Superintendent must
establish a comparable method for calculating the value of production.
No deductions or allowances, whether monetary, volumetric, or
otherwise, are allowed.
Sec. 226.41 Minimum royalty.
(a) If the royalty paid for a producing lease during any year is
less than the amount of the annual rental for the lease, the lessee
must pay minimum royalty.
(b) Minimum royalty in an amount equal to the annual rental
specified for the lease less the amount of the royalty paid on
production is due on or before the lease anniversary date.
(c) Failure to timely pay minimum royalty will result in the
assessment of interest on all unpaid or underpaid minimum royalty
amounts. Interest will be charged at the IRS underpayment rate pursuant
to 26 U.S.C. 6621(a)(2), or such other rate as the Superintendent or
ONRR may prescribe. The IRS underpayment rate is posted quarterly and
is available online at https://www.irs.gov. Interest will be charged
only for the number of days the payment is late.
(d) Minimum royalty payments must be paid to ONRR in accordance
with the requirements set forth in Sec. 226.43.
Sec. 226.42 Royalty-in-kind.
(a) The Osage Minerals Council may take oil and gas royalty-in-kind
on a lease-by-lease basis or for all leases in Osage County.
(b) The Osage Minerals Council must provide the Superintendent and
affected lessees with at least 30 calendar days' written notice of its
decision to take royalty-in-kind and at least 60 calendar days' written
notice of its decision to terminate royalty-in-kind. The Osage Minerals
Council must submit resolutions to the Superintendent for its decisions
to take and terminate royalty-in-kind.
(c) The Osage Minerals Council must take 100 percent of the daily
royalty oil and royalty gas produced from all leases placed in royalty-
in-kind status. Royalty oil and royalty gas must be taken in-kind at
the wellhead. For purposes of this section, royalty oil and royalty gas
mean the daily lease production multiplied by the royalty rate.
(d) Lessees must furnish free storage for royalty oil and royalty
gas for 30 calendar days from the date of production. The Osage
Minerals Council must negotiate agreements for the storage of royalty
oil and royalty gas directly with lessees. The Superintendent will not
negotiate, review, or approve royalty-in-kind storage agreements.
(e) All rights, duties, and obligations that exist under the terms
and conditions of the lease and the regulations in this part remain in
effect when royalty is taken in kind, including the lessee's obligation
to pay advance annual rental and minimum royalty.
Sec. 226.43 Royalty payments.
(a) Royalty payments must be remitted to ONRR. The lessee or
purchaser may remit royalty payments in accordance with Sec. 226.44.
(b) Royalty payments are due on or before the last calendar day of
the month following the month during which the oil or gas is produced
and removed or sold and shall cover all volumes removed or sold for the
preceding month. If the last calendar day of the month falls on a
weekend or
[[Page 2464]]
Federal holiday, payments are due on the first business day of the next
month.
(c) All royalty payments must be remitted using one of the forms of
payment identified in Sec. 226.8 unless ONRR specifies otherwise.
Payment by EFT is preferred.
(d) Non-EFT royalty payments must be made payable to ``DOI-ONRR for
BIA Osage Nation.'' Payments mailed via U.S. Postal Service must be
addressed to: Office of Natural Resources Revenue, P.O. Box 25627,
Denver, CO 80225-0627. Payments sent via courier or overnight delivery
service must be addressed to: Office of Natural Resources Revenue,
Denver Federal Center, Building 85, Entrance N-1, Room 332, 6th Avenue
and Kipling Street, Denver, CO 80225.
(e) ONRR must receive royalty payments submitted by EFT in its
account on or before the due date. ONRR must receive royalty payments
submitted via U.S. Postal Service, courier, or overnight delivery
service at the applicable address set forth in paragraph (d) of this
section before 4 p.m. mountain time on the due date.
(f) Failure to timely and properly make royalty payments will
result in the assessment of interest on all unpaid or underpaid royalty
amounts. Interest will be charged at the IRS underpayment rate pursuant
to 26 U.S.C. 6621(a)(2), or such other rate as the Superintendent or
ONRR may prescribe. The IRS underpayment rate is posted quarterly and
is available online at https://www.irs.gov. Interest will be charged
only for the number of days the payment is late.
(g) A payor may recoup an overpayment through a recoupment on Form
ONRR-2014 against the current month's royalties or other revenues owed
on the same lease. For any month, a payor may not recoup more than 100
percent of the royalties or other revenues owed in that month.
Overpayments subject to recoupment include all payments made in excess
of the required payment for royalty, rental, bonus, or other amounts
owed as specified by the terms and conditions of the lease, the
regulations in this part, orders and notices the Superintendent or ONRR
issue, and other applicable law. ONRR may order any payor not to recoup
any amount for such reasonable period as may be necessary for ONRR to
review the claimed overpayment.
Sec. 226.44 Royalty payment contracts and division orders.
(a) The lessee may enter into contracts or division orders with
purchasers of oil and gas, or derivatives therefrom, that designate the
purchaser as the party responsible for remitting royalty payments. The
lessee must provide the Superintendent with a copy of the contract or
division order evidencing such designation.
(b) A contract or division order does not relieve the lessee from
responsibility for the payment of royalty or from responsibility for
ensuring the accurate measurement and reporting of all oil and gas
removed or sold from the lease. If the purchaser fails to pay or
underpays royalty, the lessee is responsible for payment in full of all
amounts due and owing, including any interest that may be assessed.
Sec. 226.45 Royalty reports.
(a) The lessee must submit a certified monthly royalty report to
ONRR using Form ONRR-2014, Report of Sales and Royalty Remittance.
(b) ONRR must receive reports by 4 p.m. mountain time on or before
the last calendar day of the month that follows the month during which
the oil and gas is produced and removed or sold. If the last calendar
day of the month falls on a weekend or Federal holiday, the report is
due on the first business day of the next month.
(c) The lessee must submit Form ONRR-2014 electronically via ONRR's
eCommerce Reporting website, https://onrrreporting.onrr.gov, unless
they qualify for an exception under paragraph (d) of this section. The
lessee must enter royalty data into the system manually or upload data
files using the American Standard Code for Information Interchange
(ASCII) or Comma Separated Values (CSV) file layout formats specified
by ONRR. Detailed information regarding how to complete and submit Form
ONRR-2014 is available at https://www.onrr.gov/ReportPay/royalty-reporting.htm.
(d) The lessee may submit Form ONRR-2014 manually if they:
(1) Have never reported to ONRR before, in which case they have
three months from the date the first royalty report is due to begin
reporting electronically;
(2) Are only reporting minimum royalty; or
(3) Are a small business, as defined by the Small Business
Administration, and do not own a computer.
(e) Royalty reports submitted manually via U.S. Postal Service must
be addressed to: Office of Natural Resources Revenue, P.O. Box 25627,
Denver, CO, 80225-0627. Royalty reports submitted manually via courier
or overnight delivery service must be addressed to: Office of Natural
Resources Revenue, Denver Federal Center, Building 85, Entrance N-1,
Room 332, 6th Avenue and Kipling Street, Denver, CO 80225. If a lessee
who is submitting royalty reports manually has three or more late
submissions, ONRR may issue an order requiring the lessee to submit all
future royalty reports electronically.
Sec. 226.46 Requirements for royalty, rental, and payment records.
(a) The lessee must make, retain, and preserve accurate and
complete records demonstrating that rental, royalty, and other payments
relating to oil and gas leases comply with the terms and conditions of
the lease, the regulations in this part, and applicable orders or
notices. Such records include, but are not limited to, royalty and
production reports; computer programs, automated files, and supporting
systems documentation used to produce reports submitted to the
Superintendent and ONRR; and relevant statements, receipts, run
tickets, QTRs, contracts and agreements.
(b) The lessee must maintain and preserve records under this
section for a minimum of six years from the date upon which the
relevant transaction was recorded unless the Superintendent or ONRR
provides written notice to the lessee that an audit or investigation is
being conducted and the records must be maintained for a longer period.
If an audit or investigation of the records is being conducted, the
lessee must maintain the records until the Superintendent or ONRR
issues a written release of such obligation.
(c) The lessee must make records available to the Superintendent
and ONRR for inspection upon request. The lessee will be given a
reasonable period of time to produce historical records.
Sec. 226.47 Right of the U.S. Government to purchase oil.
Any of the executive departments of the U.S. Government have the
option to purchase all or any part of the oil produced from any lease
under this part at no less than the price set forth in Sec. 226.37.
Audits
Sec. 226.48 Audits and reviews.
ONRR may initiate and conduct audits and reviews relating to the
scope, nature, and extent of lessees' and purchasers' compliance with
rental, royalty, and other payment and reporting requirements under the
terms and conditions of the lease, the regulations in this part, and
applicable orders or notices.
[[Page 2465]]
Subpart G--Bonds
Lease Bonds
Sec. 226.49 Grandfathering of existing bonds.
(a) Existing $5,000 lease bonds filed with leases and assignments
approved prior to [effective date of final rule] are exempt from
Sec. Sec. 226.51(b) and 226.53(a)(3).
(b) Existing $50,000 collective bonds filed with leases and
assignments approved prior to [effective date of final rule] are exempt
from Sec. Sec. 226.52(a) and 226.53(a)(3).
(c) Existing lease and collective bonds will cover all unplugged
wells located on the subject lease(s) that the lessee of record drilled
and completed, operated, or controlled prior to [effective date of
final rule] according to the Osage Agency's records. For purposes of
this section, a lessee is considered to ``control'' all unplugged wells
located on the lease that are recorded in the Osage Agency's plat book
or that a purchaser exercising reasonable diligence could or should
have known of at the time the lease or assignment was executed, except
for orphan wells.
(d) Lessees with existing lease and collective bonds must file
performance bonds that comply with the requirements set forth in this
subpart for all wells they propose to drill, reenter, recomplete, and
accept via assignment after [effective date of final rule].
(e) Existing lease and collective bonds will be considered an
acceptable form of financial security for the lessee of record on
[effective date of final rule] only. The right to maintain existing
lease and collective bonds cannot be conveyed to any other person
through assignment, a transfer of operating rights or working
interests, or otherwise. All future lessees, including assignees, of
leases with grandfathered lease or collective bonds must file
performance bonds that comply with the requirements set forth in this
subpart.
Sec. 226.50 Bond obligations.
(a) The lessee must file a performance bond conditioned upon
compliance with the terms and conditions of the lease and the
regulations in this part prior to drilling, reentering, and
recompleting wells or accepting responsibility for wells through
assignment. The lessee must also file a performance bond for all
saltwater disposal (SWD) easements.
(b) Performance bonds must be in one of the following forms:
(1) Surety bond issued by a qualified surety company approved by
the Department of the Treasury (see Department of the Treasury Circular
No. 570);
(2) Certificate of deposit issued by a financial institution, the
deposits of which are federally insured, explicitly granting the
Superintendent the full authority to demand immediate payment in the
event of default;
(3) Cashier's check;
(4) Certified check;
(5) Negotiable Treasury securities of the United States of a value
equal to the amount specified in the bond and including a proper
conveyance to the Superintendent of the full authority to sell such
securities in the event of default; or
(6) Irrevocable letter of credit issued by a financial institution,
the deposits of which are federally insured, for a specific term,
identifying the Superintendent as the sole payee with full authority to
demand immediate payment in the event of default and subject to the
following requirements:
(i) The letter of credit must be issued by a financial institution
organized or authorized to do business in the United States;
(ii) The letter of credit must be irrevocable during its term. A
letter of credit used as security for any well(s) that have been
drilled, but for which final approval of abandonment has not been
given, shall be forfeited and collected by the Superintendent if not
replaced by a suitable bond or letter of credit at least 30 calendar
days before its expiration date;
(iii) The letter of credit must be payable to the Superintendent
upon demand, in full or in part, upon receipt of a notice of attachment
from the Superintendent stating the basis therefore (e.g., default or
failure to file a replacement in accordance with paragraph (c)(5)(ii)
of this section);
(iv) The initial expiration date of the letter of credit must be at
least one year following the date it is filed with the Superintendent;
and
(v) The letter of credit must contain a provision for automatic
renewal for periods of not less than one year in the absence of notice
to the Superintendent at least 90 calendar days prior to the original
or extended expiration date.
Sec. 226.51 Individual well bond requirements.
(a) After [effective date of final rule], individual performance
bonds must be filed for:
(1) Each well the lessee proposes to drill, reenter, recomplete, or
accept responsibility for through assignment; and
(2) Each SWD well under an approved SWD easement.
(b) Individual well bonds must be in the amount of not less than $6
per foot of the measured well depth for each existing well or the
projected well depth for each proposed well.
(c) Individual well bonds must be filed with the permit
application, executed assignment, or executed SWD easement.
Sec. 226.52 Countywide and nationwide bond requirements.
(a) In lieu of an individual well bond, the lessee may file a
countywide bond in the amount of not less than $75,000 covering all
leases of, and SWD easements within, the Osage Mineral Estate to which
the lessee is, or may become, a party. The total lease acreage covered
by a single countywide bond cannot exceed 10,240 acres.
(b) In lieu of individual well or countywide bonds, the lessee may
file a $150,000 nationwide bond covering all leases to which the lessee
is, or may become, a party in the United States and all SWD easements
to which the lessee is, or may become, as party within the Osage
Mineral Estate.
(c) Countywide and nationwide bonds must be filed with the executed
lease, assignment, or SWD easement.
Sec. 226.53 Authorization to increase the required bond amount.
(a) The Superintendent may require an increase in the amount of any
bond, including grandfathered bonds, if the:
(1) The lessee defaults on an obligation incurred under the lease,
approved permits, the regulations in this part, or applicable orders
and notices;
(2) The lessee is deemed high risk due to a history of lease
violations in Osage County; enforcement action by other Federal or
state agencies; unpaid royalties, civil penalties, or other amounts due
and owing; or other factors; or
(3) The total estimated cost of plugging existing wells exceeds the
present bond amount.
(b) The Superintendent may increase the bond amount to any level,
but in no circumstances will the bond amount exceed the sum of the
amounts owed for prior violations that remain outstanding, the amount
of uncollected royalties or other amounts due, and the total estimated
costs of plugging.
Sec. 226.54 Bond forfeiture.
(a) The Superintendent may call for forfeiture of all or part of a
performance bond if the lessee defaults on, refuses to comply with, or
otherwise fails to satisfy an obligation incurred under a lease,
approved permit, the regulations in this part, or applicable notices
and orders.
[[Page 2466]]
(b) Where the surety makes payment to the Superintendent due to
default, the face amount of the bond and the surety's liability
thereunder will be reduced by the amount of such payment.
(c) If the value of the bond is reduced due to default, and the
obligation in default is less than or equal to the face amount of the
bond, the lessee must either restore the existing bond or post a new
bond. If the obligation in default exceeds the face amount of the bond,
the lessee must make full payment to the BIA for all costs incurred
that are in excess of the face amount of the bond and must post a new
bond. If the lessee fails to make full payment for all such
obligations, the United States or Osage Minerals Council may take
action to recover from the lessee all costs in excess of the amount
collected under the bond. The United States has sole discretion
regarding whether to take action to recover costs and nothing in this
section will be construed as imposing an obligation on the United
States to take such action.
(d) The lessee must restore the existing bond or post a new bond
under paragraph (c) of this section within six months of receiving the
notice of default, or such shorter period as the Superintendent may
specify.
(e) Failure to restore or replace a deficient bond may subject the
lease(s) of, and SWD easements within, the Osage Mineral Estate covered
by the bond to cancellation under Sec. 226.165.
Sec. 226.55 Termination of the period of liability and release of
bonds.
(a) The Superintendent will not terminate the period of liability
or release a bond unless an acceptable replacement bond has been filed
or all obligations incurred under the lease, approved permits,
regulations in this part, and applicable notices and orders have been
satisfied.
(b) Termination of the period of liability ends the period during
which obligations accrue but does not relieve the surety of
responsibility for obligations that accrued during the period of
liability. Release of the bond relieves the surety of all liability.
Geophysical Exploration Bonds
Sec. 226.56 Geophysical exploration bond requirements.
(a) Lessees and permittees must file a bond conditioned on
compliance with the terms and conditions of the geophysical exploration
permit and the regulations in this part prior to commencing exploration
operations. The bond must be in one of the forms identified in Sec.
226.50(b).
(b) A lessee holding a valid lease of the Osage Mineral Estate
under this part for which the required performance bond has been
posted, may conduct geophysical exploration operations on the covered
lease without further bonding.
(c) A lessee holding a valid lease of the Osage Mineral Estate for
which an individual well bond has been posted who wishes to explore
unleased lands, must post a geophysical exploration bond in accordance
with paragraph (d) of this section. A lessee holding a valid lease of
the Osage Mineral Estate for which a countywide or nationwide bond has
been posted who wishes to explore unleased lands, may obtain a bond
rider to include geophysical exploration operations.
(d) Individual exploration bonds in the amount of $5,000 must be
filed with each geophysical exploration permit. In lieu of individual
exploration bonds, lessees and permittees may file a countywide bond in
the amount of $25,000 covering all exploration operations within Osage
County or a nationwide bond in the amount of $50,000 covering all
exploration operations within the United States.
Sec. 226.57 Bond forfeiture.
The Superintendent may call for forfeiture of all or part of the
bond posted for geophysical exploration operations if the lessee or
permittee defaults on, refuses to comply with, or otherwise fails to
satisfy an obligation incurred under the geophysical exploration
permit, the regulations in this part, or applicable notices and orders.
Sec. 226.58 Termination of the period of liability and release of
bonds.
(a) The Superintendent will not terminate the period of liability
or release a geophysical exploration bond unless all obligations
incurred under the geophysical exploration permit and the regulations
in this part have been satisfied.
(b) Terminating the period of liability ends the period during
which obligations accrue but does not relieve the surety of
responsibility for obligations that accrued during the period of
liability. Release of the bond relieves the surety of all liability.
Subpart H--Operations
General Requirements
Sec. 226.59 Conduct of operations.
(a) Lessees and permittees must comply with the terms and
conditions of the lease and approved permits, the regulations in this
part, orders and notices the Superintendent issues, and all other
applicable laws and regulations in the conduct of all operations.
(b) Lessees and permittees must conduct all exploration, testing,
development, production, and other operations in a safe and workmanlike
manner that:
(1) Protects the leased or permitted lands and improvements
thereon;
(2) Protects natural resources, cultural resources, and
environmental quality;
(3) Protects health and safety;
(4) Ensures proper management, measurement, disposition, and
security of production; and
(5) Results in the maximum ultimate recovery of oil and gas with
minimum waste and minimal adverse effect on the recovery of other
mineral resources.
(c) Lessees and permittees must not commit waste on leased or
permitted lands, nor allow avoidable nuisance to be maintained thereon.
(d) Lessees and permittees must use and maintain all installations
and equipment in a manner that ensures structural and mechanical
integrity, proper function, and the safe conduct of operations at the
location of the installation or equipment.
(e) Lessees and permittees must comply with the National Electrical
Code in the installation, operation, maintenance, and use of all
electrical lines.
Sec. 226.60 Inspection of operations.
(a) The Superintendent has the right to enter or travel across any
lands covered by a lease or permit for the purpose of conducting an
inspection or investigation.
(b) The Superintendent may conduct inspections and investigations
with or without advance notice to the lessee or permittee. Inspections
and investigations may take place at any time but will normally be
conducted during those hours when responsible persons are expected to
be present at the site being inspected or investigated.
(c) Lessees and permittees must allow the Superintendent to inspect
and investigate:
(1) Lands covered by the lease or permit;
(2) Operations; and
(3) Improvements, facilities, structures, fixtures, and equipment
located on leased or permitted lands and any records of design,
construction, maintenance, or repairs relating thereto.
Commencement of Operations
Sec. 226.61 No operations may commence prior to approval of a lease
or geophysical exploration permit.
No operations may commence on any tract of land until the
Superintendent
[[Page 2467]]
approves a lease or geophysical exploration permit covering such land.
Sec. 226.62 Prior authorization required to commence operations on
trust or restricted lands.
(a) No operations are permitted on trust or restricted lands
without the Superintendent's approval.
(b) If an Indian landowner is unwilling to allow the commencement
of operations on their lands, the Superintendent will conduct an
examination of the lands with the Indian landowner and lessee or
permittee. If the Superintendent determines that the interests of the
Osage Nation require that the lands be developed or explored, they will
instruct the parties to reach an agreement under which operations may
be conducted.
(c) If the Indian landowner and lessee or permittee cannot reach an
agreement under paragraph (b) of this section, the parties must present
the matter to the Osage Minerals Council, which will issue a written
recommendation. The Osage Minerals Council's recommendation will be
considered final and binding upon the Indian landowner and lessee or
permittee. A guardian or authorized representative may represent the
Indian landowner before the Osage Minerals Council. If no such guardian
or authorized representative exists, or where the Superintendent
determines that there is no proper party to speak for an Indian
landowner of unsound mind, the Principal Chief of the Osage Nation will
represent the Indian landowner.
(d) If the Indian landowner or their guardian or authorized
representative fails to appear before the Osage Minerals Council as
required, or the Osage Minerals Council fails to act within 10 calendar
days after the matter is referred for recommendation, the
Superintendent may authorize the lessee or permittee to proceed with
operations.
Sec. 226.63 Notice and information to be given to surface owners
prior to commencement of operations.
(a) The lessee or permittee must meet with the surface owner prior
to the commencement of any operations on leased or permitted lands,
except for archeological or biological surveying and the staking of
wells.
(b) For operations other than those identified in paragraph (a) of
this section, the lessee or permittee must send the surface owner a
written request for a meeting by certified mail. The meeting must be
held at least 10 calendar days prior to the commencement of operations
unless the Superintendent waives such requirement, or the parties agree
otherwise. At the meeting, the lessee or permittee must:
(1) Indicate the location of the well(s), shot holes to be drilled,
or seismic survey site;
(2) Arrange for a route of ingress and egress. If the lessee or
permittee and surface owner fail to agree on a route of ingress and
egress, the Superintendent will set the route; and
(3) Provide the name and address of the representative upon whom
the surface owner must serve any claim for damages that may be
sustained from operations and the procedure for the settlement of such
claims as set forth in Sec. 226.83.
(c) Where operations will occur on trust or restricted land, the
lessee or permittee must conduct the meeting required under paragraph
(b) of this section with the Superintendent and, if possible, the
Indian landowner.
(d) If the surface owner cannot be contacted at their last known
address or has not accepted the meeting request within 30 calendar days
of receipt thereof, the Superintendent will authorize the lessee or
permittee to commence operations.
Sec. 226.64 Payment of commencement money and tank siting fees to the
surface owner.
(a) Prior to commencing drilling, reentry, or geophysical
exploration operations, the lessee or permittee must pay the surface
owner commencement money in the amount of:
(1) $1,500 per well to be drilled or reentered;
(2) $25 per seismic shot hole; and
(3) $12 per acre, or fraction thereof, occupied by the lessee or
permittee while conducting a seismic survey.
(b) The lessee must pay the surface owner $200 per tank for each
tank to be sited on the leased lands, except for tanks temporarily set
on well sites for drilling, completion, or testing purposes only.
(c) Commencement money and tank siting fees must be paid in full
prior to the commencement of operations or siting of tanks on the
lease, subject to the exception set forth in paragraph (e) of this
section.
(d) Where the surface estate is trust or restricted land,
commencement money and tank siting fees must be paid to the
Superintendent for the Indian landowner.
(e) Where the surface estate is not trust or restricted land,
commencement money and tank siting fees must be paid to the surface
owner directly. If the surface owner is not a resident of Osage County,
such payment must be sent by certified mail to the surface owner's last
known address. If the payment is returned as undeliverable or the
surface owner refuses to accept the payment, the commencement money or
tank siting fees will be deemed forfeited. Nothing herein affects the
surface owner's right to the settlement of surface damages under
Sec. Sec. 226.82 and 226.83.
(f) Commencement money and tank siting fees are a credit toward the
settlement of surface damages. The surface owner's acceptance of
commencement money and tank siting fees does not affect their right to
compensation for damages occasioned by operations. A settlement
covering the actual surface damages resulting from drilling, reentry,
or geophysical exploration operations does not need to be paid until
such operations are complete.
Drilling, Workover, and Well Abandonment Operations
Sec. 226.65 Use of surface lands and water for operations.
(a) The lessee has the right to use so much of the surface of the
leased lands as may be reasonable for the development, extraction,
marketing, and sale of oil and gas. The right to use the surface lands
includes the right-of-way for ingress and egress to any point of
operations. The right to surface lands also includes, but is not
limited to, the right to install and maintain pipelines, electric
lines, and other necessary equipment and facilities. The Superintendent
will determine the routing of pipelines and electric lines, as well as
the siting of equipment and facilities of the lessee and surface owner
are unable to agree.
(b) Drilling sites must be held to the minimum area essential for
operations and must not exceed the acreage set forth in the approved EA
unless the Superintendent authorizes such expansion in writing.
(c) The lessee may use water from natural water courses for
approved lease operations, provided that such use does not diminish the
supply below the requirements of the surface owner from whose land the
water is taken.
(d) The lessee may use water from reservoirs formed by the
impoundment of water from natural water courses for approved lease
operations, provided that such use does not exceed the quantity to
which the lessee would originally have been entitled had the reservoirs
not been constructed.
(e) The lessee may install necessary lines and other equipment
within the
[[Page 2468]]
Osage Mineral Estate to obtain water in accordance with paragraphs (c)
and (d) of this section. If any such installation will be over or
across surface lands that are held in trust or restricted status, the
lessee must obtain a right-of-way pursuant to part 169 of this title
prior to commencing the necessary installation operations. Any damages
resulting from installations to obtain water must be settled as
provided in Sec. 226.83.
Sec. 226.66 Drilling operations.
(a) The lessee must submit an Application for Permit to Drill,
together with any required information or documentation, for each well
to be drilled or reentered. No drilling or reentry operations, or
surface disturbance preliminary thereto, may commence prior to the
Superintendent's approval of the permit.
(b) The Superintendent will not accept an application for a permit
to drill unless it is administratively complete.
(c) The lessee must notify the Superintendent of planned drilling
or reentry operations at least five business days prior to the
commencement thereof. The Superintendent may witness such operations
without advance notice.
(d) The lessee may not drill, or conduct surface disturbance
preliminary to drilling, within 300 feet of the boundary line of leased
lands without the Superintendent's approval. The lessee may not locate
a well or tank within 200 feet of any Federal, state, county, or
municipal road or highway that is owned and maintained for public use;
any intermittent, ephemeral, or perennial streams or water sources; or
any building used as a residence, granary, or barn without the
Superintendent's approval. Failure to obtain such approval will result
in the assessment of civil penalties under Sec. 226.161 and the
issuance of an order to immediately plug the well or remove the tank(s)
and may subject the lease to cancellation under Sec. 226.165.
(e) The lessee must submit a subsequent Well Completion or Reentry
Report following drilling and reentry operations in accordance with
Sec. 226.74(c) through (g).
Sec. 226.67 Well control.
(a) Drilling wells. The lessee must take the necessary precautions
to keep wells under control and must use and maintain materials and
equipment necessary to ensure the safety of operating conditions and
procedures.
(b) Vertical drilling. The lessee must conduct drilling operations
in a manner that prevents the completed well from deviating
significantly from the vertical unless the Superintendent's prior
approval of such deviation is obtained. The lessee must promptly report
any well that deviates significantly from the vertical without prior
approval to the Superintendent and conduct a directional survey. For
purposes of this section, significant deviation means a projected
deviation of the well bore from the vertical of 10 degrees or more or a
projected bottom hole location that may be less than 300 feet from the
lease boundary.
(c) High pressure or loss of circulation. The lessee must take
immediate steps to maintain or restore control of any well in which the
pressure equilibrium becomes unbalanced.
Sec. 226.68 Use of gas for artificial lifting of oil.
A lessee with an oil-only lease executed prior to [effective date
of final rule] is prohibited from using gas from a distinct or separate
stratum for the purpose of flowing or lifting oil. A lessee with a
combined oil and gas lease may use gas from a distinct or separate
stratum for the purpose of flowing or lifting oil subject to the
requirements set forth in Sec. Sec. 226.144 through 226.151.
Sec. 226.69 Workover operations.
(a) The lessee must submit an Application for Permit to Workover
Wells, together with any required information or documentation, for
each well to be worked over. The following workover operations, and
surface disturbance preliminary thereto, may not commence prior to the
Superintendent's approval of the permit:
(1) Recompletion;
(2) Deepening, plugging back, or converting a well;
(3) Formation treatments and acidizing jobs, including acid
fracturing;
(4) Hydraulic fracturing; and
(5) Pulling or altering the casing.
(b) The Superintendent will not accept an application for a
workover permit unless it is administratively and technically complete.
(c) The lessee must notify the Superintendent of planned
recompletion, deepening, and hydraulic fracturing operations at least
five business days prior to the commencement thereof. The lessee does
not need to provide notice prior to commencement of the other workover
operations identified in paragraph (a) of this section. The
Superintendent may witness any workover operations without advance
notice.
(d) The lessee must submit a subsequent Report of Workover
Operations following all workover operations identified in paragraph
(a) of this section in accordance with Sec. 226.74(c) through (g).
(e) Prior approval and a subsequent report of operations are not
required for well cleanout work, well maintenance, or bottom hole
pressure surveys. The operations listed in paragraph (a) of this
section do not qualify as well cleanout work or well maintenance.
Sec. 226.70 Requirements for operations in Hydrogen Sulfide (H2S)
areas.
(a) Testing requirements. (1) The lessee must conduct an initial
test of the H2S concentration of the gas stream for each
well and production facility completed and make the results of such
test(s) available to the Superintendent upon request.
(2) The lessee must determine the radius of exposure for each well
and production facility having an H2S concentration of 100
ppm or more in the gas stream and submit a report of such calculations
to the Superintendent. The radius of exposure must be calculated as
follows:
(i) For determining the 100-ppm radius of exposure where the
H2S concentration in the gas stream is less than 10 percent:
X = [(1.589)(H2S Concentration)(Q)](0.6258)
(ii) For determining the 500-ppm radius of exposure where the
H2S concentration in the gas stream is less than 10 percent:
X = [(0.4546)(H2S Concentration)(Q)](0.6258)
Where:
X = radius of exposure in feet
H2S Concentration = decimal equivalent of the mole or
volume fractions of the H2S in the gaseous mixture
Q = maximum volume of gas determined to be available for escape, or
escape rate, in cubic feet per day (at standard condition of 14.73
psia and 60 [deg]F)
(iii) For determining the 100-ppm or 500-ppm radius of exposure
where the H2S concentration in the gas stream is 10 percent
or greater, the lessee must use an air dispersion model approved by the
EPA, or such another method the Superintendent approves.
(3) The lessee must calculate the radius of exposure pursuant to
paragraph (a)(2) of this section for each well and production facility
completed prior to [effective date of final rule] that has a
H2S concentration of 100 ppm or greater in the gas stream
and submit a report of such calculations to the Superintendent on or
before [six months from effective date of final rule].
[[Page 2469]]
(4) If a change in operations or production results in an increase
in the H2S concentration or radius of exposure of five
percent or more as calculated pursuant to paragraph (a)(2) of this
section, the lessee must notify the Superintendent in writing of such
increase within 60 calendar days of identification of the change.
(b) Public protection. (1) The lessee must report any release of a
potentially hazardous volume of H2S to the Superintendent as
soon as practicable, but not later than 24 hours following
identification of the release.
(2) The lessee must submit a Public Protection Plan providing a
detailed plan of action for alerting and protecting the public in the
event of a release of a potentially hazardous volume of H2S
when any of the following conditions apply:
(i) The 100-ppm radius of exposure is greater than 50 feet and
includes any part of a residence, school, church, place of business, or
other area the public can reasonably be expected to frequent;
(ii) 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 that is owned and maintained for public use; or
(iii) The 100-ppm radius of exposure is greater than or equal to
3,000 feet.
(3) The details of the Public Protection Plan may vary according to
site-specific characteristics expected to be encountered and the
proximity and density of the population at risk. All plans must include
the following:
(i) The lessee's name and phone number;
(ii) The names, phone numbers, and responsibilities of key
personnel;
(iii) The names and phone numbers of residents within the radius of
exposure;
(iv) The names and phone numbers of the responsible parties for
each of the schools, churches, businesses, roads, highways, or other
public areas or facilities within the radius of exposure;
(v) A call list including the Osage Agency, Osage Minerals Council,
Federal and state regulatory agencies, local law enforcement, local
fire departments, and other public safety personnel;
(vi) Instructions and procedures for notifying the Osage Agency,
Osage Minerals Council, and public of an emergency;
(vii) Instructions and procedures for notifying Federal and state
regulatory agencies, local law enforcement, local fire departments, and
public safety personnel of an emergency and requesting their response;
(viii) A plat showing the location of residences, schools,
churches, places of business, roads, highways, or other areas the
public may reasonably be expected to frequent within the radius of
exposure;
(ix) Advance briefing of residences, schools, and churches within
the 100-ppm radius of exposure. Advance briefing may be conducted in-
person or by certified letter and must provide:
(A) Information regarding the characteristics and hazards of
H2S and SO2;
(B) A list of possible sources of H2S and SO2
within the radius of exposure;
(C) Detailed instructions for reporting a gas leak to the lessee;
(D) Information regarding the necessity of having an emergency
action plan;
(E) The way the public will be notified of an emergency; and
(F) The steps that should be taken in the event of an emergency;
(x) The title(s) or position(s) of the individuals authorized by
the lessee to ignite escaping gas, circumstances under which those
individuals may ignite escaping gas, and way in which escaping gas will
be ignited;
(xi) Procedures for monitoring H2S and SO2
levels and wind direction, maintaining site security, controlling
access to the affected site, and implementing any other measures
necessary to monitor the situation and protect the public until the
release is contained; and
(xii) A description of the detection system(s) that will be used to
determine the concentration of H2S released in the event of
a release from a production facility.
(4) The Public Protection Plan must be activated immediately upon
detection of the release of a potentially hazardous volume of
H2S. The lessee must notify the Superintendent of activation
of the Public Protection Plan.
(5) A copy of the Public Protection Plan must be maintained at the
well site, production facility, or such other location on the lease
that the plan is readily accessible if activation is required.
(6) The lessee must review the Public Protection Plan on an annual
basis and submit any revisions to the Superintendent.
(c) Operating requirements for drilling, completion, and workover
operations. (1) If the lessee encounters zones containing
H2S concentrations in excess of 100 ppm while drilling with
air, gas, mist, or other non-mud circulating mediums for aerated mud,
the well must be killed with water-based or oil-based drilling mud, and
thereafter, mud must be used as the circulating medium for continued
drilling.
(2) A flare system meeting the following requirements must be
installed to safely gather and burn H2S-bearing gas:
(i) Flare lines must be located as far from the operating site as
feasible and must compensate for changes in wind direction;
(ii) Flare lines must be straight unless targeted with running
tees; and
(iii) The flare system must be equipped with a safe means of
ignition.
(3) The lessee must check the SO2 level in the flare
impact area using portable detection equipment at any site where
SO2 may be released due to the flaring of H2S
during drilling, completion, or workover operations. The lessee must
implement the Public Protection Plan if the flare impact area reaches a
sustained ambient threshold of 2 ppm or greater of SO2 in
air and includes any part of a residence, school, church, place of
business, or other area the public can reasonably be expected to
frequent.
(4) The lessee must install a remote-controlled choke or valve for
all H2S drilling operations and, where feasible, completion
operations.
(d) H2S training and safety requirements. (1) The lessee must
provide appropriate H2S training for all personnel
including, but not limited to, training regarding:
(i) The hazards and characteristics of H2S;
(ii) The effect of H2S on metal components of the well
system;
(iii) The operation of safety equipment;
(iv) First aid procedures in the event of exposure; and
(v) Emergency response procedures and evacuation routes if there is
a release of a potentially hazardous volume of H2S.
(2) The lessee must ensure that the following safety equipment is
available for use on the lease and maintained in good working
condition:
(i) Protective breathing apparatus for personnel;
(ii) Communication devices that can be used with protective
breathing apparatus; and
(iii) A flare gun and flares to ignite the well.
(3) Each drilling and well completion site must have an
H2S detection and monitoring system that automatically
activates audible and visible alarms when the ambient air concentration
of H2S reaches 10 ppm. The system must have rapid response
sensors capable of sensing a minimum of 10 ppm of H2S
[[Page 2470]]
in ambient air, with at least three sensing points located at the shale
shaker, rig floor, and bell nipple for a drilling site, and the cellar,
rig floor, and circulating tanks or shale shaker for a well completion
site. During workover operations, one sensing point must be located as
close as possible to the wellbore. The lessee must maintain a record of
all tests of the H2S monitoring system and make such records
available to the Superintendent upon request.
(4) The lessee must install at least one wind direction indicator
at a location that is visible at all times during drilling, completion,
and workover operations.
(5) The lessee must display a red flag at the entrance to the well
or production facility site when H2S is detected in excess
of 10 ppm at any detection point.
(6) The lessee must post danger or caution signs on all roads and
controlled access routes to the well or production facility site. The
lessee must post a danger or caution sign a minimum of 200 feet, but no
more than 500 feet, from the well or production facility site at a
location that allows vehicles to turn around at a safe distance. Signs
must meet the following requirements:
(i) Signs must be prominently displayed, legible, and large enough
to be read from the road or entrance to the site;
(ii) Signs must be visible to all personnel and members of the
public approaching the site under normal lighting and weather
conditions;
(iii) Signs must read ``Danger--Poison Gas--Hydrogen Sulfide'' or
``Caution--Poison Gas May Be Present--H2S;'' and
(iv) Signs must be painted high-visibility red, white, and black,
or yellow and black.
(7) Storage tanks that are utilized as part of production
operations and are operated at or near atmospheric pressure, where the
vapor accumulation has an H2S concentration of 500 ppm or
greater in the tank, are subject to the following requirements:
(i) All stairs and ladders leading to the top of the storage tank
must be chained and marked to restrict entry;
(ii) The lessee must install at least one wind direction indicator
at the storage tank site; and
(iii) The lessee must post a danger or caution sign on the storage
tank or within 50 feet thereof. The sign must comply with the
requirements set forth in paragraphs (c)(6)(i) through (iv) of this
section.
(8) Production facilities with a H2S concentration of
100 ppm or greater in the gas stream are subject to the following
requirements:
(i) The lessee must install at least one wind direction indicator
at the production facility site. If the production facility and storage
tank(s) are located at the same site, only one indicator is required;
(ii) The lessee must post a danger or caution sign within 50 feet
of the production facility. The sign must comply with the requirements
set forth in paragraphs (c)(6)(i) through (iv) of this section. If the
facility is fenced, the sign may be posted on the gate; and
(iii) The lessee must post danger or caution signs at each location
where a well flowline or lease gathering line crosses lease or public
roads. The signs must be posted on each side of the road, as close to
the pipeline as possible, and must contain the name of the lessee and a
24-hour phone number.
(9) The lessee must install automatic safety valves or shutdowns at
the wellhead, or other appropriate shut-in controls for wells equipped
with artificial lift, where the H2S 100-ppm radius of
exposure includes any part of a residence, school, church, place of
business, or other area the public may be reasonably expected to
frequent. Such valves must be set to activate upon the release of a
potentially hazardous volume of H2S.
(10) All equipment that has the potential to be exposed to
H2S must be suitable for the H2S working
environment.
Sec. 226.71 Surveys, samples, and tests.
(a) The Superintendent may require the lessee to conduct tests, run
logs, and take any other surveys necessary to determine the following
during the drilling and completion of a well:
(1) The presence, quantity, and quality of oil and gas;
(2) The presence and quality of water;
(3) The amount and direction of deviation of any well from the
vertical; and
(4) The formations drilled and relevant characteristics of the oil
and gas reservoirs penetrated.
(b) After a well is completed, the lessee must conduct periodic
well tests to determine the quality and quantity of the oil, gas, and
water. The Superintendent may determine the method and frequency of
such tests.
(c) The Superintendent may require the lessee to conduct reasonable
tests of the mechanical integrity of downhole equipment.
Sec. 226.72 Temporary abandonment.
A lessee may not temporarily abandon, shut down, or otherwise
discontinue the use or operation of any producing well for more than 30
calendar days without the Superintendent's prior approval. The lessee
must submit a request for temporary abandonment to the Superintendent
in writing, together with any relevant supporting documentation, for
each well to be temporarily abandoned. Wells cannot be temporarily
abandoned prior to the Superintendent's approval of such request.
Sec. 226.73 Permanent plugging and abandonment operations.
(a) A lessee may not permanently abandon a newly completed or
recompleted well unless oil and gas is not encountered in paying
quantities.
(b) A lessee may not permanently abandon a producing well without
the Superintendent's approval.
(c) The lessee must promptly plug dry and permanently abandoned
wells in a manner that protects formations bearing fresh water,
saltwater, oil, gas, and other minerals.
(d) The lessee must submit an Application for Permit to Plug Wells,
together with evidence that the well is no longer capable of producing
in paying quantities, proposed plugging instructions, and any other
required information or documents, for each well to be permanently
plugged and abandoned. No plugging and abandonment operations may
commence prior to the Superintendent's approval of the permit.
(e) The Superintendent will not accept an application for a
plugging permit unless it is administratively and technically complete.
(f) The lessee must notify the Superintendent of planned plugging
operations at least five business days prior to the commencement
thereof. The Superintendent may witness such operations without advance
notice.
(g) The lessee must submit a subsequent Report of Plugging
Operations in accordance with Sec. 226.74(c) through (g).
(h) Upon written agreement with the surface owner, the lessee may
condition a well that is being plugged and abandoned for use as a fresh
water supply source for the surface owner. The lessee must file a copy
of any such agreement with the Superintendent. The surface owner
assumes all risk for the use of a reconditioned well as a fresh water
supply source.
Sec. 226.74 Well records and reports.
(a) The lessee must keep accurate and complete records for all
lease operations and submit reports thereof as required by the
Superintendent and the regulations in this part. The lessee must make
all books and records available to
[[Page 2471]]
the Superintendent for inspection upon request.
(b) Records for operations including, but not limited to, the
drilling, reentry, recompletion, deepening, repair, conversion,
plugging and abandonment of all wells must show:
(1) All formations penetrated, the content and character of the
oil, gas, and water in each formation, and the kind, weight, size,
landed depth, and cement record of casing used;
(2) The record of drill-stem and other bottom hole pressure or
fluid sample surveys, temperature surveys, directional surveys, or
reports;
(3) The materials and procedures used in the treating or plugging
of wells or the preparation of wells for temporary abandonment; and
(4) Any other information obtained during well operations.
(c) The lessee must submit the following to the Superintendent
within 10 calendar days after the completion of operations on any well,
or any required sampling, testing, or surveying thereof:
(1) A subsequent report of operations on the required form;
(2) A copy of the results of all samples, tests, and surveys
required under this subpart;
(3) A copy of the electrical, mechanical, and radioactive logs or
any other surveys of the well bore; and
(4) The core analysis obtained from the well, if available.
(d) For plugging operations, the lessee must submit copies of all
cementing service tickets together with the subsequent report of
operations.
(e) For hydraulic fracturing operations, the lessee must submit the
following information together with the subsequent report of
operations:
(1) The total volume of water used;
(2) The total volume of base fluid used;
(3) The type of base fluid used;
(4) The trade name, supplier, general purpose, ingredients,
Chemical Abstract Service (CAS) Number, and maximum ingredient
concentration in the hydraulic fracturing fluid (percent by mass), for
each chemical additive or other substance added to the base fluid or,
if such chemical identity information is withheld under paragraph (f)
of this section, the generic chemical name or a similar descriptor for
the chemical;
(5) The actual, estimated, or calculated fracture length, height,
and direction;
(6) The actual measured depth of perforations and shots per foot or
the open-hole interval; and
(7) The total volume of fluid recovered between completion of the
last stage of the hydraulic fracturing operation and the point at which
the lessee begins reporting water produced from the well to ONRR.
(f) If the lessee or owner of the information claims that any
information that must be reported under paragraph (e) of this section
is exempt from public disclosure, the information may be withheld. If
information is withheld, the lessee must submit a Withholding of
Proprietary Hydraulic Fracturing Information form with the report.
(g) The Superintendent may require a lessee to submit any
information withheld under paragraph (f) of this section. The
Superintendent will maintain the confidentiality of the information
unless they determine that the information is not exempt from public
disclosure. The Superintendent will provide the lessee with written
notice of any such determination.
(h) The lessee must maintain and preserve records and reports
required under this section for six years from the date they were
generated, unless the Superintendent provides written notice to the
lessee that an audit or investigation is being conducted and the
records must be maintained for a longer period. If an audit or
investigation of the records is being conducted, the lessee must
maintain the records until the Superintendent issues a written release
of such obligation.
Sec. 226.75 Well and facility identification.
(a) The lessee must properly identify each well located on the
lease, excluding those wells that have been permanently abandoned, by a
sign placed in a conspicuous location. The well sign must include the
well number, lessee's name, lease name, lease number, and legal
description.
(b) The lessee must mark each permanently abandoned well located on
the lease with a permanent monument containing the information required
under paragraph (a) of this section. The Superintendent reserves the
right to waive the requirement for a permanent monument.
(c) The lessee must properly identify all facilities at which oil
and gas produced from a lease is stored, measured, or processed by a
sign placed in a conspicuous location. The sign must include the
lessee's name, lease name, lease number, and legal description.
(d) All signs required by this section must be maintained in
legible condition.
Sec. 226.76 Pollution prevention.
The lessee or permittee must take measures to prevent the
unauthorized discharge of pollutants and migration of oil, gas,
saltwater, or other deleterious substances to fresh water or other
mineral bearing formations during the exploration, development,
production, and transportation of oil and gas. The lessee or permittee
must conduct tests and surveys of the effectiveness of the measures
taken to ensure the protection of fresh water and mineral bearing
formations and make the results of such tests available to the
Superintendent upon request.
Sec. 226.77 Storage and disposal of fluids.
(a) Pits for drilling mud and deleterious substances used in the
drilling, completion, recompletion, workover, or plugging of any well
must be constructed and maintained to prevent the pollution of surface
and subsurface fresh water. The lessee must routinely inspect and
maintain pits to ensure that there is no fluid leakage into the
environment.
(b) Pits constructed after [effective date of final rule] may not
be located:
(1) In areas subject to frequent flooding according to the USDA
Natural Resources Conservation Service (NCRS) Soil Survey;
(2) Within 300 feet of intermittent or ephemeral streams or water
sources; or
(3) Within 500 feet of perennial streams, springs, fresh water
sources, or wetlands.
(c) Pits may not be constructed, utilized, enlarged, or relocated
without the Superintendent's prior approval.
(d) Immediately after the completion of operations, pits must be
emptied and leveled as the Superintendent directs or as provided by
written agreement with the surface owner. The lessee must file a copy
of any surface owner agreement with the Superintendent.
(e) All produced water must be disposed of by injection into the
subsurface, collection in approved pits, or other methods the
Superintendent authorizes.
(f) Land application of water-based fluids from pits, tanks, and
containment vessels; waste oil; waste oil residue; crude oil
contaminated soil; freshwater drill cuttings; drilling mud; and other
deleterious substances is not permitted upon any lease without the
Superintendent's prior approval.
Sec. 226.78 Removal of fire hazards.
Any material that may constitute a fire hazard must be moved to a
safe distance from the well site, tanks, and other surface facilities.
Waste oil must be burned or disposed of in a matter that prevents
creation of a fire hazard.
[[Page 2472]]
Geophysical Exploration Operations
Sec. 226.79 Applying for a geophysical exploration permit.
(a) Any party wishing to conduct oil and gas geophysical
exploration activities on leased or unleased tracts of the Osage
Mineral Estate must submit an Application for Oil and Gas Geophysical
Exploration Permit and obtain the Superintendent's approval thereof
prior to commencing exploratory operations or any surface disturbance
preliminary thereto.
(b) Upon approval of an application, the Superintendent will issue
a geophysical exploration permit that includes the terms and conditions
deemed necessary to protect mineral resources and other resource
values. The permit does not grant the permittee any option or
preference rights to a lease of the subject lands or authorize the
production, extraction, removal, or sale of oil, gas, or other mineral
resources therefrom.
Sec. 226.80 Commencement of operations.
Permittees must notify the Superintendent of planned geophysical
exploration operations at least five business days prior to the
commencement thereof. The Superintendent may witness any such
activities without advance notice.
Sec. 226.81 Records and reports.
Within 30 calendar days after the completion of geophysical
exploration operations, the permittee must submit a subsequent Oil and
Gas Geophysical Exploration Report.
Settlement of Surface Damages
Sec. 226.82 Lessee or permittee required to settle surface damages.
(a) The lessee or permittee must pay for damages to growing crops,
improvements on the land, and all other surface damages occasioned by
operations.
(b) In the settlement of surface damages on unrestricted lands, all
sums due and payable must be paid to the surface owner. The surface
owner must apportion damages among the parties having legal interests
in the surface as the parties mutually agree or as their interests
dictate. Parties having legal interests in the surface include, but are
not limited to, owners, tenants, and surface lessees.
(c) In the settlement of damages on restricted lands, all sums due
and payable must be paid to the Superintendent. The Superintendent will
apportion damages among the surface owner, tenants, and surface lessees
of record and credit the surface owner's account with the amount of
damages apportioned.
(d) Any person claiming an interest in leased trust or restricted
lands and damages thereto must notify the Superintendent, in writing,
of the interest claimed and provide any documentation the
Superintendent requests in support thereof. Failure to submit a written
statement or the required supporting documentation to the
Superintendent constitutes a waiver of notice and bars that person from
asserting a claim for any portion of surface damages after such damages
have been disbursed.
Sec. 226.83 Procedure for settlement of surface damages.
If a surface owner, tenant, or surface lessee suffers damages due
to oil and gas exploration or development operations, the procedure for
recovery is as follows:
(a) The aggrieved party or parties must serve written notice upon
the lessee or permittee as soon as possible after the discovery of any
damages. The written notice must describe the nature and location of
the alleged damages, date of occurrence, name of the party or parties
that caused the damages, and amount of the damages. This requirement
does not limit the time within which any action must be brought in a
court of competent jurisdiction to less than the 90-day period allowed
by section 2 of the Act of March 2, 1929 (45 Stat. 1478, 1479).
(b) If the alleged damages are not adjusted at the time that
written notice is served, the lessee or permittee must try to adjust
the claim with the aggrieved party or parties within 20 calendar days
of receipt of such notice.
(c) If the parties fail to adjust the claim within 20 calendar days
as specified in paragraph (b) of this section, each party has 10
calendar days to appoint an arbitrator. Immediately upon their
appointment, the two arbitrators must agree upon a third arbitrator. If
the two arbitrators fail to agree upon a third arbitrator within 10
calendar days of their appointment, they must immediately notify the
parties. If the parties cannot agree upon a third arbitrator within
five calendar days after receipt of such notice, the Superintendent
must appoint the third arbitrator.
(1) All arbitrators must be disinterested persons.
(2) Where both a surface owner and their tenant(s) or surface
lessee(s) are injured, the aggrieved parties must join in the
appointment of an arbitrator. Where an injury is chargeable to more
than one lessee or permittee, all chargeable lessees or permittees must
join in the appointment of an arbitrator.
(3) Each claimant and lessee or permittee must pay the fees and
expenses for the arbitrator they appoint. The fees and expenses of the
third arbitrator must be borne equally by the claimant(s) and lessee(s)
or permittee(s).
(d) Immediately following the appointment of the third arbitrator,
the arbitrators must meet, hear the evidence and arguments of the
parties, and examine the crops, improvements, lands, or other property
allegedly damaged. Within 10 calendar days thereafter, the arbitrators
must issue a written decision regarding the amount of damages due and
serve the decision upon all interested parties. Any two of the
arbitrators may render the decision as to the amount of damages due.
(e) Each party has 90 calendar days from the date the arbitrators'
decision is served to file an action in a court of competent
jurisdiction challenging the decision. If no such action is filed and
the arbitration resulted in a decision finding the lessee or permittee
liable for surface damages, the lessee or permittee must pay all
damages together with interest assessed from the date of the award at
the IRS underpayment rate pursuant to 26 U.S.C. 6621(a)(2) within 10
calendar days after expiration of the period for filing an action in
court. The IRS underpayment rate is posted quarterly and is available
online at https://www.irs.gov.
(f) If the claimant is an Indian landowner, the lessee or permittee
must submit any surface damages settlement agreement to the
Superintendent for approval. The settlement agreement must describe the
nature and location of the damages, date(s) of occurrence, settlement
amount, and any other pertinent information.
Subpart I--Production and Site Security
General Requirements
Sec. 226.84 Production obligations.
(a) The Superintendent may order a lessee to promptly drill and
produce wells on any lease acreage regardless of whether the lessee has
drilled and paid rental if, in their opinion:
(1) A prudent lessee would conduct further development; or
(2) Such drilling is necessary to ensure that the lease is properly
and timely developed in accordance with sound economic operating
practices.
(b) Failure to develop a lease in compliance with the
Superintendent's order is a violation of the terms and conditions of
the lease and results in
[[Page 2473]]
termination of the lease by operation of law as to the acreage the
lessee was ordered to develop.
(c) The lessee must put all oil and gas produced from the lease
into marketable condition at no cost to the Osage Nation.
(d) Where oil accumulates in a pit, such oil must either be
recirculated through the regular treating system and returned to the
stock tanks for sale or pumped into a stock tank without treatment and
measured for sale in the same manner as from any sales tank under the
regulations in this part.
(e) Except in an emergency, no oil may be pumped into a pit without
the Superintendent's prior approval. Each such pumping occurrence must
be reported to the Superintendent immediately, but not later than the
next business day, and the oil promptly recovered in accordance with
applicable orders and notices.
Sec. 226.85 Production reporting.
(a) The lessee must submit certified monthly production reports to
ONRR using Form ONRR-4054, Oil and Gas Operations Report, regardless of
whether there was production during the reporting period, if the lessee
operates a lease or cooperative agreement upon which one or more wells
are not permanently plugged and abandoned.
(b) The lessee must submit Form ONRR-4054 for each well every month
beginning with the month in which drilling is completed or, if
production testing is conducted during drilling operations, beginning
with the month in which testing occurs. Such reporting must continue
until the lease or cooperative agreement terminates or is cancelled and
the Superintendent determines that all wells have been permanently
plugged and abandoned.
(c) Reports must be received by 4 p.m. mountain time on or before
the 15th day of the second month following the production month.
(d) The lessee must submit Form ONRR-4054 electronically via ONRR's
eCommerce Reporting website, https://onrrreporting.onrr.gov, unless
they qualify for an exception under paragraph (e) of this section. The
lessee must enter production data into the system manually or upload
data files in American Standard Code for Information Exchange (ASCII)
or Comma Separated Values (.csv) file formats that ONRR specifies.
Information regarding how to complete and submit Form ONRR-4054 is
available at https://www.onrr.gov/ReportPay/royalty-reporting.htm.
(e) The lessee may submit Form ONRR-4054 manually if they:
(1) Have never reported to ONRR before. In such instance, they have
three months from the date the first production report is due to begin
reporting electronically; or
(2) Have a small business, as defined by the Small Business
Administration, and do not own a computer.
(f) Production reports submitted manually via U.S. Postal Service
must be addressed to: Office of Natural Resources Revenue, P.O. Box
25627, Denver, CO 80225-0627. Production reports submitted manually via
courier or overnight delivery service must be addressed to: Office of
Natural Resources Revenue, Denver Federal Center, Building 85, Room A-
614, 6th Avenue and Kipling Street, Denver, CO 80225.
Sec. 226.86 Site facility diagrams.
(a) A site facility diagram is required for all permanent
facilities. A site facility diagram is not required for temporary
measurement facilities used during well testing operations. No format
is prescribed for site facility diagrams. The diagram should be
formatted to fit on an 8\1/2\ x 11-inch sheet of paper, if possible,
and must be legible and comprehensible to an individual with an
ordinary working knowledge of oil and gas field operations. If more
than one page is required, each page must be numbered using the format
``N of X pages.'' The diagram does not need to be to scale. Sample site
facility diagrams are available at https://www.bia.gov/regional-offices/eastern-oklahoma/osage-agency.
(b) The site facility diagram must:
(1) Clearly identify the name of the lessee, lease(s) the diagram
applies to, and facility location. Facility location must include both
GPS coordinates and the legal description;
(2) Reflect the position of the production and water recovery
equipment, piping for oil, gas, and water, and metering or other
measuring systems in relation to each other;
(3) Commencing with the header, identify all equipment including,
but not limited to, the header, wellhead, piping, tanks, metering
systems located on the site, appropriate valves, and any other
equipment used in the handling, conditioning, or disposal of production
and water, and must indicate the direction or flow;
(4) Identify the wells flowing into headers by US Well Number;
(5) Indicate which valve(s) must be sealed and in what position
during the production phase, sales phase, and during other production
activities (e.g., circulating tanks or drawing off water), which may be
shown by an attachment, if necessary;
(6) Clearly identify all meters and measurement equipment on the
diagram or in an attachment to the diagram; and
(7) Clearly identify the FMP(s) for each measurement facility where
the measurement affects calculation of the volume or quality of oil and
gas production upon which royalty is owed. Where production from more
than one well will flow into the FMP(s), the lessee must list all US
Well Numbers associated with each FMP.
(c) For new, permanent facilities that become operational after
[effective date of final rule], a site facility diagram must be filed
within 60 calendar days after the facilities become operational.
(d) For facilities that are in service on or before [effective date
of final rule], a site facility diagram identifying FMPs, as required
by paragraph (b)(7) of this section, must be filed by [120 days after
effective date of final rule] or such longer period as the
Superintendent may authorize.
(e) After a site facility diagram is submitted pursuant to this
section, the lessee has an ongoing obligation to amend the diagram
within 60 calendar days after any facilities are modified.
Sec. 226.87 Assignment of facility measurement point (FMP) numbers.
The BIA will assign a unique FMP number to each oil and gas FMP
identified on the site facility diagram submitted under Sec. 226.85.
(a) For a new facility in service after [effective date of final
rule], the lessee must start using FMP numbers for reporting to ONRR
the first production month after the BIA assigns the FMP numbers and
every month thereafter.
(b) For an existing facility in service on or before [effective
date of final rule], the lessee must start using FMP numbers for
reporting to ONRR the third production month after the BIA assigns the
FMP numbers and every month thereafter.
Sec. 226.88 Requirements for production records.
(a) Lessees, purchasers, transporters, and other persons involved
in producing, transporting, purchasing, selling, or measuring oil and
gas through the point of royalty measurement or point of first sale,
whichever is later, must retain all records, including source records,
relevant to determining the quality, quantity, disposition, and
verification of production attributable to the subject lease. This
applies to all records generated during, or for, the period the lessee
has an interest in, or conducts
[[Page 2474]]
operations on, the lease or the period in which a purchaser,
transporter, or other persons are involved in transporting, purchasing,
or selling production therefrom.
(b) Records that are created after [effective date of final rule]
must be legible and include the following:
(1) The FMP, lease, or unit number;
(2) A unique equipment identifier (e.g., a unique tank or meter
station number);
(3) The name of the person who created the record; and
(4) The signor's printed name, for any records requiring a
signature.
(c) Records under this section must be maintained and preserved for
a minimum of six years from the date upon which the relevant
transaction was recorded unless the Superintendent or ONRR provides
written notice to the lessee that an audit or investigation is being
conducted and the records must be maintained for a longer period. If an
audit or investigation of the records is being conducted, the lessee
must maintain the records until the Superintendent or ONRR issues a
written release of such obligation.
(d) Records under this section must be made available to the
Superintendent or ONRR for inspection upon request. A reasonable period
of time will be provided to produce historical records.
Sec. 226.89 Easements for access to wells located off-lease.
(a) The Superintendent may grant commercial and non-commercial SWD
easements for access to existing wells located off-lease on trust or
restricted Indian lands in accordance with the regulations in part 169
of this title.
(b) The grantee must post a performance bond for all SWD easements
in accordance with the requirements in subpart G.
(c) The lessee is responsible for all surface damages resulting
from use of the easement and must settle such damages as provided in
Sec. 226.83.
Waste Prevention
Sec. 226.90 Prevention of waste.
(a) A lessee must conduct all operations in a manner that prevents
the waste of oil and gas and must not use oil and gas in a wasteful
manner.
(b) The Superintendent has authority to impose requirements deemed
necessary to prevent the waste of oil and gas and promote the maximum
ultimate economic recovery thereof, consistent with conservation of the
resources.
(c) For purposes of this section, waste includes, but is not
limited to, inefficient, excessive, or improper use or dissipation of
reservoir energy resulting in a reasonable reduction in the quality of
oil and gas that may be produced or the unnecessary or excessive
surface loss or destruction of oil and gas without beneficial use.
Sec. 226.91 Royalty on lost or wasted production.
(a) Royalty is due on all oil and gas avoidably lost or wasted. The
Superintendent and ONRR will determine the volume and quality of lost
or wasted production. Royalty is not due on oil and gas that is
unavoidably lost.
(b) The following qualify as avoidably lost production:
(1) Gas that is vented or flared without the Superintendent's prior
approval; and
(2) Produced oil or gas that the Superintendent determines was lost
because of the lessee's:
(i) Negligence;
(ii) Failure to take all reasonable measures to prevent or control
the loss; or
(iii) Failure to comply with applicable lease and permit terms and
conditions, the regulations in this part, or applicable orders and
notices.
(c) The following qualify as unavoidably lost production:
(1) Oil or gas that is lost because of line failures, equipment
malfunctions, blowouts, fires, or other similar circumstances, except
where the Superintendent determines that the loss was avoidable
pursuant to paragraph (b)(2) of this section;
(2) Oil or gas that is lost during the following operations, and
from the following sources, except where the Superintendent determines
that the loss was avoidable pursuant to paragraph (b)(2) of this
section:
(i) Well drilling;
(ii) Well completion and related operations;
(iii)Initial production tests, subject to the limitations in Sec.
226.156(a);
(iv) Subsequent well tests, subject to the limitations in Sec.
226.156(b);
(v) Exploratory coalbed methane well dewatering;
(vi) Normal gas vapor losses from a storage tank or other low-
pressure vessel, unless the Superintendent determines that recovery of
the gas vapors is warranted;
(vii) Well venting during downhole well maintenance or liquids
unloading, performed in compliance with Sec. 226.156(c);
(viii) Facility and pipeline maintenance, such as when the lessee
must blow-down and depressurize equipment to perform maintenance or
repairs; and
(ix) Emergencies, subject to the limitations in Sec. 226.156(d).
(3) Produced gas that is vented or flared with the Superintendent's
approval.
Drainage Obligations
Sec. 226.92 Prevention of drainage.
(a) Where any lease is being drained of oil and gas by wells on an
adjacent lease issued at a lower royalty rate, the Superintendent may
require the lessee being drained to:
(1) Drill or modify and produce all wells necessary to protect the
lease from drainage;
(2) Enter into a cooperative agreement with the lease upon which
the draining well is located; or
(3) Pay compensatory royalties for drainage that has occurred and
continues to occur.
(b) The Superintendent may, in their discretion, approve
alternative, equivalent protective measures outside of those set forth
in paragraph (a) of this section.
(c) The lessee must take protective action within a reasonable time
after they first knew, or had constructive notice, that drainage may be
occurring. For purposes of this section, a lessee is considered to have
constructive notice of drainage if they operate or own any interest in
the draining lease or well.
(d) If the Superintendent has reason to believe that drainage is
occurring, they will notify the lessee in writing. Such notification
does not alleviate the lessee's responsibility to take protective
action when they first knew, or had constructive notice, that drainage
may be occurring, which date may precede the receipt of notice from the
Superintendent.
(e) The Superintendent will determine whether a lessee took
protective action within a reasonable time on a case-by-case basis
taking into consideration the time required to evaluate the
characteristics and performance of the draining well; rig availability;
well depth; the need for environmental analysis; weather conditions;
and other relevant factors.
(f) The lessee is not required to take any of the protective
actions listed in paragraph (a) of this section if they can prove, to
the Superintendent's satisfaction, that when they first knew, or had
constructive notice, of drainage, a sufficient quantity of oil or gas
could not be produced from a protective well for a reasonable profit
above the cost of drilling, completing, and operating the protective
well.
[[Page 2475]]
Sec. 226.93 Compensatory royalty for drainage.
(a) If the Superintendent determines that a lessee was required to
take protective action to prevent drainage under Sec. 226.92 and
failed to take such action within a reasonable time, the lessee must
pay compensatory royalty for the period of the delay.
(b) The Superintendent will assess compensatory royalty beginning
on the first calendar day of the month following the earliest
reasonable time the lessee should have taken protective action and
continuing until:
(1) The lessee drills adequate economic protective wells, and such
wells remain in continuous production;
(2) The Superintendent approves a cooperative agreement that covers
the mineral resources being drained or alternative protective measures;
(3) The draining well stops producing; or
(4) The lessee relinquishes their interest in the lease through an
assignment.
(c) If a lessee assigns their interest in a lease, they are not
liable for drainage that occurs after the effective date of the
assignment.
(d) An assignee is liable for all drainage obligations that accrue
after the effective date of the assignment.
Site Security
Sec. 226.94 Storage and sales facilities--seals.
(a) All lines entering or leaving any oil storage tank must have
valves capable of being effectively sealed during the production and
sales phases unless otherwise provided by the regulations in this part.
Existing valves may be modified so that they are capable of being
effectively sealed. Appropriate valves must be in an operable condition
and accurately reflect whether the valve is open or closed.
(1) During the production phase, all appropriate valves that allow
unmeasured production to be removed from storage must be effectively
sealed in the closed position. During any other phase (e.g., sales,
water draining, hot oiling), and prior to taking the top tank gauge
measurement, all appropriate vales that allow unmeasured production to
enter or leave the sales tank must be effectively sealed in the closed
position.
(2) Each unsealed or ineffectively sealed valve is a separate
violation.
(b) Valves, or combinations of valves and tanks, that provide
access to production before it is measured for sale are considered
appropriate valves and are subject to the seal requirements in this
part. If there is more than one valve on a line from a tank, the valve
closest to the tank must be sealed.
(c) All appropriate valves must be in operable condition and
accurately reflect whether the valve is open or closed.
(d) The following are not considered appropriate valves and,
therefore, are not subject to the seal requirements in this part:
(1) Valves on production equipment (e.g., dehydrator, gun barrel,
or wash tank);
(2) Valves on water tanks, provided that the possibility of access
to production in the sales and storage tanks does not exist through a
common circulating drain, overflow, or equalizer system;
(3) Valves on tanks that contain what the Superintendent determines
to be slop or waste oil;
(4) Sample cock valves used on piping or tanks with a Nominal Pipe
Size of one inch or less in diameter;
(5) Fill-line valves during shipment when a single tank with a
nominal capacity of 500 bbl or less is used for collecting marginal
production of oil produced from a single well (i.e., production that is
less than three bbl per day). All other seal requirements apply;
(6) Gas line valves used on piping with a Nominal Pipe Size of one
inch or less used as tank bottom ``roll'' lines, provided that there is
no access to the contents of the storage tank and the roll lines cannot
be used as equalizer lines;
(7) Valves on tank heating systems that use a fluid other than the
contents of the storage tank (i.e., steam, water, glycol);
(8) Valves used on piping with a Nominal Pipe Size of one inch or
less, connected directly to the pump body or used on pump bleed off
lines;
(9) Tank vent-line valves; and
(10) Sales, equalizer, or fill-line valves on systems where
production may be removed only through approved oil metering systems
(e.g., LACT or CMS). Any valve that allows access for removal of oil
before it is measured through the metering system must be effectively
sealed.
(e) Tampering with any appropriate valve is prohibited.
Sec. 226.95 Oil measurement system components--seals.
(a) Components used for determining the quality or quantity of oil
must be effectively sealed to indicate tampering. Such components
include, but are not limited to, the following components of LACT
meters and CMSs:
(1) The sampler volume control;
(2) All valves on lines entering or leaving the sample container,
excluding the safety pop-off valve, if so equipped. Each valve must be
sealed in the open or closed position, as appropriate;
(3) The mechanical counter head (totalizer) and meter head;
(4) The stand-alone temperature averager monitor;
(5) The non-automatic adjusting, fixed back-pressure valve pressure
adjustment downstream of the meter;
(6) Any drain valves larger than one inch in nominal diameter; and
(7) The right-angle drive.
(b) Each missing or ineffectively sealed component is a separate
violation.
Sec. 226.96 Removing production from tanks for sale and
transportation by truck.
(a) When a single truckload constitutes a completed sale, the
driver must possess the documentation required in Sec. 226.114.
(b) When multiple trucks are involved in a sale and the oil
measurement method is based on the difference between the opening and
closing gauges, the driver of the last truck must possess the
documentation required in Sec. 226.114. All other drivers involved in
the sale must possess a trip log or manifest.
(c) After the seals have been broken, the purchaser or transporter
is responsible for the entire contents of the tank until it is
resealed. When a single truck is involved in a sale with multiple
truckloads, the purchaser or transporter must seal the tank in between
each individual truckload.
Sec. 226.97 Documentation required for transportation of oil and gas.
(a) Any person engaged in transporting by motor vehicle any oil
produced from or allocated to any lease, must carry on their person, in
their vehicle, or have in their immediate control, documentation
showing the amount, origin, and intended first purchaser of the oil.
(b) Any person engaged in transporting any oil or gas produced from
or allocated to any lease by pipeline, must maintain documentation
showing the amount, origin, and intended first purchaser of the oil or
gas.
(c) Any properly identified authorized representative of the
Superintendent may stop and inspect any motor vehicle on a lease if
they have probable cause to believe the vehicle is carrying oil
produced from or allocated to the lease, to determine whether the
driver possesses proper documentation for the load of oil.
(d) Any appropriate law enforcement officer or properly identified
authorized representative of the Superintendent
[[Page 2476]]
accompanied by an appropriate law enforcement officer, may stop and
inspect any motor vehicle that is off lease, if there is probable cause
to believe the vehicle is carrying oil produced from or allocated to a
lease, to determine whether the driver possesses proper documentation
for the load of oil.
Sec. 226.98 Water draining operations.
When water is drained from a production storage tank, the lessee,
purchaser, or transporter must document the following information:
(a) The lease number;
(b) The tank location using both GPS coordinates and legal
description;
(c) The unique tank number and nominal capacity;
(d) The date of the opening gauge;
(e) The opening gauge (gauged manually or automatically), TOV, and
free water measurements, all to the nearest \1/2\ inch;
(f) The unique identifying number of each seal removed;
(g) The closing gauge (gauged manually or automatically) and TOV
measurement to the nearest \1/2\ inch; and
(h) The unique identifying number of each seal installed.
Sec. 226.99 Hot oiling, clean-up, and completion operations.
(a) During hot oil, clean-up, completion operations, or any other
situation where the lessee removes oil from storage, temporarily uses
it for operational purposes, and then returns it to storage, they must
document the following information:
(1) The lease number;
(2) The tank location using both GPS coordinates and legal
description;
(3) The unique tank number and nominal capacity;
(4) The date of the opening gauge;
(5) The opening gauge measurement (gauged manually or
automatically) to the nearest \1/2\ inch;
(6) The unique identifying number of each seal removed;
(7) The closing gauge measurement (gauged manually or
automatically) to the nearest \1/2\ inch;
(8) The unique identifying number of each seal installed;
(9) How the oil was used; and
(10) Where the oil was used (e.g., well or facility name and
number).
(b) During hot oiling, line flushing, or completion operations of
any other kind where the lessee removes production from storage for use
on a different lease, the production is considered sold and must be
measured in accordance with the requirements in the regulations in this
part and reported to ONRR for the period covering the production in
question.
Sec. 226.100 Seal records.
For each seal, the lessee must maintain a record that includes the:
(a) Unique identifying number of each seal and the valve or meter
component on which the seal is, or was, used;
(b) Date of installation or removal of each seal;
(c) Position in which the valve was sealed (e.g., open or closed);
and
(d) Reason the seal was removed.
Sec. 226.101 Requirements for off-lease measurement of production.
(a) The lessee must submit a request, in writing, for off-lease
measurement of production and obtain the Superintendent's approval
thereof. The request must include the following information:
(1) The lessee's name;
(2) The lease number for which the lessee is requesting off-lease
measurement;
(3) The US Well Number(s) and GPS coordinates for each well
included in the off-lease measurement proposal; and
(4) The lease number and legal description for the existing or
proposed off-lease FMP.
(b) Off-lease measurement of production must occur at an identified
FMP unless the Superintendent authorizes otherwise.
Sec. 226.102 Report of spills, theft, mishandling of production,
accidents, or fires.
(a) Lessees must report the following to the Superintendent and
surface owner(s) immediately upon discovery, but not later than the
calendar day following discovery:
(1) All spills or releases of oil, gas, produced water, toxic
liquids, deleterious substances, or waste materials;
(2) Theft of equipment or production;
(3) Blowouts;
(4) Fires;
(5) Mishandling of production; and
(6) Accidents on the lease that resulted in the loss of production
or damage to measurement equipment.
(b) In addition to providing emergency notification by phone or in
person, the lessee must also send written notice of the incidents
identified in paragraphs (a)(1) through (4) of this section to surface
owner(s) by certified mail--return receipt requested.
(c) The lessee must submit a Spill and Remediation Report for all
spills and releases, and a written report of all other incidents, to
the Superintendent within five business days of any incident identified
in paragraph (a) of this section, together with a proposed contingency
or remediation plan that describes the procedures being implemented to
restore resource values and protect life, property, and the
environment.
(d) The lessee must exercise due diligence in taking necessary
measures to control and remove pollutants and extinguish fires.
(e) Compliance with the requirements set forth in the regulations
in this part does not relieve the lessee of the obligation to comply
with all other applicable laws and regulations.
Subpart J--Oil Measurement
Sec. 226.103 General requirements.
(a) Oil must be measured on the lease or unit area from which it is
produced unless approval for off-lease measurement of production is
obtained in accordance with Sec. 226.101.
(b) All bypasses of meters are prohibited.
(c) Tampering with any measurement device, component of a
measurement device, or measurement process is prohibited.
(d) Violation of the prohibitions set forth in paragraphs (b) and
(c) of this section will result in assessment of the maximum penalty
available under Sec. 226.162(c).
Sec. 226.104 Timeframes for compliance.
(a) All equipment and procedures used to measure the volume of oil
for royalty purposes after [effective date of final rule] must comply
with the requirements in this subpart.
(b) All equipment and procedures used to measure the volume of oil
for royalty purposes installed or in-use on leases approved prior to
[effective date of final rule] must comply with the requirements in
this subpart by [one year from effective date of final rule]. Prior to
that date, the equipment and procedures used to measure oil for royalty
purposes must continue to comply with Sec. 226.38, as it appears in 25
CFR part 226 (April 1, 2017, edition) and any applicable orders or
notices.
Sec. 226.105 [Reserved]
Sec. 226.106 Specific measurement performance requirements.
(a) Volume measurement uncertainty levels. (1) The FMP must achieve
the following volume measurement uncertainty levels, calculated in
accordance with the statistical methodologies set forth in API 13.3 and
the quadrature sum method set forth in Subsection 12.3 of API 14.3.1
(both incorporated by reference, see Sec. 226.0):
[[Page 2477]]
Table 1 to Paragraph (a)(1)--Volume Measurement Uncertainty Levels
------------------------------------------------------------------------
The overall volume measurement
If the averaging period volume is: uncertainty level must be
within:
------------------------------------------------------------------------
1. Greater than or equal to 30,000 bbl/ +/-0.50 percent.
month.
2. Less than 30,000 bbl/month......... +/-1.50 percent.
------------------------------------------------------------------------
(2) The Superintendent may grant an exception to the uncertainty
levels in paragraph (a) of this section only upon the lessee's showing
that meeting the required uncertainty level would involve extraordinary
cost or unacceptable adverse environmental effects.
(b) Bias. The measurement equipment used for volume determinations
must achieve measurement without statistically significant bias.
(c) Verifiability. All FMP equipment must be susceptible to the
BIA's independent verification of the accuracy and validity of all
inputs, factors, and equations used to determine quality or quantity.
Verifiability includes the ability to independently recalculate the
volume and quality of oil based on source records.
Sec. 226.107 Tank gauging--general requirements.
(a) Oil measurement by tank gauging must be performed using the
procedures set forth in Sec. 226.108 and accurately compute the total
net standard volume of oil withdrawn from a properly calibrated sales
tank.
(b) Each tank used for oil storage must comply with the recommended
practices in Subsection 4 of API RP 12R1 (incorporated by reference,
see Sec. 226.0) and must be connected, maintained, and operated in
compliance with Sec. Sec. 226.94, 226.98, and 226.99.
(c) All oil storage tanks must be clearly identified and have a
unique number the lessee generated stenciled on the tank and maintained
in a legible condition.
(d) Each oil storage tank that has a tank gauging system and is
associated with an FMP must be set and maintained on a level plane.
(e) Each oil storage tank that has a tank gauging system and is
associated with an FMP must be gauged using a gauging reference point
located at 180 degrees (6:00 o'clock) when the individual performing
the gauging is facing the tank hatch unless the Superintendent approves
an alternative method.
(f) The lessee must accurately calibrate each oil storage tank that
has a tank gauging system and is associated with an FMP using either
API 2.2A, API 2.2B, or API 2.2C and API RP 2556 (all incorporated by
reference, see Sec. 226.0) and:
(1) Determine sales tank capacities by tank calibration using
actual tank measurements, with unit volume in bbl and incremental
height measurements that match the gauging increment specified in Sec.
226.108(b)(5)(i)(d);
(2) Recalibrate the sales tank if there is a change in purchaser,
the tank is relocated or repaired, or the capacity of the tank changes
due to denting, damage, installation, removal of interior components,
or other alterations; and
(3) Submit sales tank tables to the Superintendent within 45
calendar days after calibration or recalculation of the tables.
Sec. 226.108 Tank gauging--procedures.
(a) The lessee may use manual or automatic tank gauging to
determine the quality and quantity of oil measured under field
conditions at an FMP. The Superintendent's prior approval is required
for all automatic tank gauging. Requests for authorization to use
automatic tank gauging must be submitted to the Superintendent in
writing and include the make and model of the automatic tank gauge
(ATG) the lessee proposes to use.
(b) The lessee must comply with the following procedures to
determine the quality and quantity of oil measured:
(1) Isolate tank. Isolate the tank for at least 30 minutes to allow
the contents to settle before conducting tank gauging operations. Tank
isolating valves must be closed and sealed in accordance with Sec.
226.94.
(2) Determine opening oil temperature. Determine the temperature of
oil contained in the sales tank in accordance with API 7.1 or API 7.2
(both incorporated by reference, see Sec. 226.0) and the following
requirements:
(i) A single temperature measurement at the middle of the liquid
may be used for tanks with less than 5,000 bbls nominal capacity;
(ii) Glass thermometers must be clean, free of fluid separation,
and have a minimum graduation of 1.0 [deg]F and an accuracy of +/-0.5
[deg]F; and
(iii) Electronic thermometers must have a minimum graduation of 1.0
[deg]F and an accuracy of +/-0.5 [deg]F.
(3) Take oil samples. The lessee must conduct sampling operations
prior to taking the opening gauge unless automatic sampling methods are
used. Sampling of oil removed from an FMP tank must yield a
representative sample of the oil and its physical properties and comply
with the requirements in API 8.1 (incorporated by reference, see Sec.
226.0).
(4) Determine observed oil gravity. The lessee must conduct tests
for oil gravity in accordance with API 9.1, API 9.2, or API 9.3 (all
incorporated by reference, see Sec. 226.0) and the following
requirements:
(i) The hydrometer or thermohydrometer must be clean with a clear,
legible oil gravity scale and no loose shot weights and must be
calibrated for an oil gravity range that includes the observed gravity
of the oil sample being tested;
(ii) The lessee must allow the temperature to stabilize for a
minimum of five minutes prior to reading the hydrometer or
thermohydrometer; and
(iii) The lessee must read and record the observed API oil gravity
to the nearest 0.1 degree and the temperature to the nearest 1.0
[deg]F.
(5) Measure opening tank fluid level. The lessee must take and
record the opening gauge only after samples have been taken.
(i) The lessee must conduct manual gauging in accordance with API
3.1A and API 18.1 (both incorporated by reference, see Sec. 226.0)
subject to the following exceptions, additions, and clarifications:
(A) The proper innage-gauging bob for the measurement method must
be used;
(B) A gauging tape must be used. The tape must be made of steel or
corrosion-resistant material with graduation clearly legible and must
not be kinked or spliced;
(C) A suitable product-indicating paste must be used on the gauging
tape to facilitate the reading. The use of chalk or talcum powder is
prohibited; and
(D) The lessee must obtain two consecutive gauging measurements
that are within \1/4\ inch of each other for any tank regardless of
size.
(ii) The lessee must conduct automatic tank gauging in accordance
with API 3.1B, and API 3.6 (both incorporated by reference, see Sec.
226.0) and the following requirements:
(A) The ATG must be inspected, and its accuracy verified to within
+/-\1/4\ inch, in accordance with the procedures in Subsection 9 of API
3.1B (incorporated by reference, see Sec. 226.0) prior to sales and
upon the Superintendent's request. If the ATG is found to be out of the
manufacturer's tolerance, the lessee will be required to calibrate the
ATG prior to sales; and
(B) The lessee must make a detailed log of ATG field verifications
available to the Superintendent upon request.
[[Page 2478]]
(6) Determine S&W content. Determine the S&W content of the oil in
the sales tanks in accordance with API 10.4 (incorporated by reference,
see Sec. 226.0) using the oil samples obtained pursuant to paragraph
(d) of this section.
(7) Transfer oil. Break the tank load valve seal and transfer the
oil to the tanker truck. After the transfer is complete, close and seal
the tank valve in accordance with Sec. Sec. 226.94 and 226.96.
(8) Determine closing oil temperature. Determine the closing oil
temperature using the procedures set forth in paragraph (b)(2) of this
section.
(9) Take closing tank gauge. Take the closing tank gauge using the
procedures set forth in paragraph (b)(5) of this section.
(10) Complete run ticket. Complete the run ticket in accordance
with Sec. 226.114.
Sec. 226.109 LACT system--general requirements.
(a) LACT systems must meet the construction and operation
requirements and minimum standards set forth in this section and
Sec. Sec. 226.103 and 226.110.
(b) LACT systems must be proven as set forth in Sec. 226.113.
(c) Run tickets must be completed as set forth in Sec. 226.114.
(d) All components of LACT systems must be accessible for
inspection.
(e) The lessee must notify the Superintendent, in writing, of any
LACT system failure or equipment malfunction that may have resulted in
measurement error within 15 calendar days of discovering the failure.
(f) Any tests conducted on oil samples extracted from LACT system
samplers for determination of S&W content and observed oil gravity must
meet the requirements and minimum standards set forth in Sec.
226.108(b)(2), (4), and (6).
(g) The average temperature for the run ticket must be calculated
for the measurement period covered by the run ticket and must be the
temperature used to calculate the CTL correction factor using API 11.1
(incorporated by reference, see Sec. 226.0).
Sec. 226.110 LACT system--components and operating requirements.
(a) Each LACT system must include all equipment listed in API 6.1
(incorporated by reference, see Sec. 226.0), subject to the following
exceptions:
(1) The LACT meter must be a positive displacement or Coriolis
meter;
(2) An electronic temperature averaging device must be installed;
and
(3) Meter back-pressure must be applied by a back-pressure valve or
other controllable means of applying back-pressure. Back-pressure may
be maintained by an automatic-adjusting back-pressure control to adjust
for changing flow conditions. Back-pressure control must maintain a
pressure that is above the bubble point of the liquid to prevent the
formation of vapor, ensuring single-phase flow.
(b) All LACT system components must be operated in accordance with
API 6.1 (incorporated by reference, see Sec. 226.0) and the following
requirements:
(1) Sampling and mixing must be conducted in accordance with API
8.2 and API 8.3 (both incorporated by reference, see Sec. 226.0), and
the sample exactor probe must be inserted in the center half of the
flowing stream, horizontally oriented, and have external markings that
show the orientation of the probe in relation to the direction of flow.
(2) All tests conducted on oil samples extracted from LACT system
samplers for determination of oil gravity must be conducted in
accordance with API 9.1, API 9.2, or API 9.3 (all incorporated by
reference, see Sec. 226.0). All tests for the determination of S&W
content must be conducted in accordance with API 10.4 (incorporated by
reference, see Sec. 226.0).
(3) The composite sample container must be emptied and cleaned upon
completion of the sample withdrawal.
(4) The positive displacement or Coriolis meter must be equipped
with a non-resettable totalizer. The non-resettable totalizer display
may reside in an electronic flow computer. The meter must include or
allow for the attachment of a device that generates at least 8,400
pulses per bbl of registered volume.
(5) The pressure-indicating device must be located downstream of
the meter, but upstream of the first valve of the prover connections.
The pressure-indicating device must be capable of providing pressure
data to calculate the CPL correction factor.
(6) The electronic temperature averaging device may be a stand-
alone device or a function of a flow computer and must be installed,
operated, and maintained as follows:
(i) The temperature thermowell and transducer must be installed as
set forth in Subsections 6.3 and 7.2 of API 7.4 (incorporated by
reference, see Sec. 226.0);
(ii) The electronic temperature averaging device must be volume-
weighted and take a temperature reading as set forth in Subsection
9.2.8 of API 21.2 (incorporated by reference, see Sec. 226.0);
(iii) The average temperature for the run ticket must be calculated
using the volumetric averaging method set forth in Subsection 9.2.13.2a
of API 21.2 (incorporated by reference, see Sec. 226.0);
(iv) The temperature averaging device must have a reference
accuracy of +/-0.5 [deg]F or better and a minimum graduation of 0.1
[deg]F.
(v) The temperature averaging device must include a display of the
instantaneous temperature and average temperature calculated since the
run ticket was opened. The display may be a function of an electronic
flow computer; and
(vi) The average temperature calculated since the run ticket was
opened must be used to calculate the CTL correction factor.
(7) The net standard volume must be calculated at the close of each
run ticket in accordance with the guidelines set forth in API 11.1 and
API 12.2.2 (both incorporated by reference, see Sec. 226.0).
Sec. 226.111 Coriolis measurement systems (CMS)--general requirements
and components.
This section applies to Coriolis measurement applications that are
independent of LACT systems.
(a) A CMS must meet the requirements and minimum standards set
forth in this section and Sec. Sec. 226.106 and 226.112.
(b) A CMS must be proven as set forth in Sec. 226.113.
(c) Run tickets must be completed as set forth in Sec. 226.114.
(d) A CMS at an FMP must be installed with the components listed in
API 5.6 (incorporated by reference, see Sec. 226.0) and in accordance
with the following requirements:
(1) The pressure transducer must meet the requirements set forth in
Sec. 226.110(b)(5);
(2) The temperature determination must meet the requirements set
forth in Sec. 226.110(b)(6);
(3) The sampling system must meet the requirements set forth in
Sec. 226.110(b)(1) through (3) if nonzero S&W content is to be used in
determining net oil volume. If no sampling system is used, or the
sampling system does not meet the requirements in Sec. 226.110(b)(1)
through (3), the S&W content must be reported as zero.
(4) Sufficient back-pressure must be applied to ensure single-phase
flow through the meter.
(e) The API oil gravity reported for the run ticket period must be:
(1) Determined from a composite sample taken in accordance with
Sec. 226.110(b)(1) through (3); or
(2) Calculated from the average density as measured by the CMS over
the run ticket period in accordance with
[[Page 2479]]
Subsection 9.2.13.2a of API 21.2 (incorporated by reference, see Sec.
226.0). Density must be corrected to base temperature and pressure in
accordance with API 11.1 (incorporated by reference, see Sec. 226.0).
Sec. 226.112 Coriolis meter--operating requirements.
(a) Minimum electronic pulse level. The Coriolis meter must
register the volume of oil passing through the meter as determined by a
system that constantly emits electronic pulse signals representing the
indicated volume measured. The pulse per unit volume must be set at a
minimum of 8,400 pulses per bbl.
(b) Meter specifications. The Coriolis meter specifications must
identify the make and model of the meter they apply to and include the
following:
(1) The reference accuracy for both mass flow rate and density,
stated in percent of reading, percent of full scale, or units of
measure;
(2) The effect of changes in temperature and pressure on both mass
flow and fluid density readings, and the effect of flow rate on density
readings, stated in percent of reading, percent of full scale, or units
of measure over a stated amount of change in temperature, pressure, or
flow rate (e.g., +/-0.1 percent of reading per 20 psi);
(3) The stability of the zero reading for volumetric flow rate,
stated in percent of reading, percent of full scale, or units of
measure;
(4) The design limits for flow rate and pressure; and
(5) The pressure drop through the meter as a function of flow rate
and fluid viscosity.
(c) Submission of meter specifications. The lessee must submit
Coriolis meter specifications to the Superintendent upon request.
(d) Non-resettable totalizer. The Coriolis meter must have a non-
resettable internal totalizer for indicated volume.
(e) Verification of meter zero-value using the manufacturer's
specifications. If the indicated flow rate is within the manufacturer's
specifications for zero stability, no adjustments are required. If the
indicated flow rate is outside such specifications, the meter's zero
reading must be adjusted. After the meter's zero has been adjusted, the
meter must be proven as set forth in Sec. 226.113. A copy of the zero-
value verification procedure must be provided to the Superintendent
upon request.
(f) Required on-site information.
(1) The Coriolis meter display must be readable without using data
collection units, laptop computers, or any special equipment and must
be on-site and accessible to the Superintendent.
(2) The following values and corresponding units of measurement
must be displayed for each Coriolis meter:
(i) The instantaneous display of liquid density (pounds/bbl,
pounds/gal, or degrees API);
(ii) The instantaneous indicated volumetric flow rate through the
meter (bbl/day);
(iii) The meter factor;
(iv) The instantaneous pressure (psi);
(v) The instantaneous temperature ([deg]F);
(vi) The cumulative gross standard volume through the meter (non-
resettable totalizer) (bbl); and
(vii) The previous day's gross standard volume through the meter
(bbl).
(3) The following information must be correct, maintained in
legible condition, and accessible to the Superintendent at the FMP
without the use of data collection equipment, laptop computers, or any
other special equipment:
(i) The make, model, and size of each sensor; and
(ii) The make, model, range, and calibrated span of the pressure
and temperature transducer used to determine gross standard volume.
(4) The lessee must maintain a log of all meter factors, zero
verifications, and zero adjustments. For zero adjustments, the log must
include the zero value after adjustment. The log must be made available
to the Superintendent upon request.
(g) Audit trail requirements. The information identified in
paragraphs (g)(1) through (4) of this section must be recorded and
maintained by the lessee for six years from the date it was generated
unless the Superintendent provides written notice to the lessee that an
audit or investigation is being conducted and the records must be
maintained for a longer period. If an audit or investigation of the
records is being conducted, the lessee must maintain the records until
the Superintendent issues a written release of such obligation. Audit
trail requirements must follow Subsection 10 of API 21.2 (incorporated
by reference, see Sec. 226.0). All data and records must be provided
to the Superintendent upon request.
(1) Quantity transaction record (QTR). The QTR must comply with the
requirements for run tickets set forth in Sec. 226.114.
(2) Configuration log. The configuration log must comply with the
requirements set forth in Subsection 10.2 of API 21.2 (incorporated by
reference, see Sec. 226.0), and identify all constant flow parameters
used in generating the QTR.
(3) Event log. The event log must comply with the requirements set
forth in Subsection 10.6 of API 21.2 (incorporated by reference, see
Sec. 226.0).
(4) Alarm log. The alarm log must record the type and duration of
density deviations from acceptable parameters and instances in which
the flow rate exceeded the manufacturer's maximum recommended flow rate
or was below the manufacturer's minimum recommended flow rate.
(h) Data protection. To ensure that audit trail requirements under
paragraph (g) of this section are met, each Coriolis meter must have a
backup power supply installed and maintained in operable condition or a
non-volatile memory capable of retaining all data in the unit's memory.
Sec. 226.113 Meter proving requirements.
(a) This section specifies the minimum requirements for conducting
volumetric meter proving for all FMP meters.
(b) Meter prover. The only acceptable provers are positive
displacement master meters, Coriolis master meters, and displacement
provers. The lessee must ensure that the meter prover used to determine
the meter factor has a valid certificate of calibration, identifying
the prover by serial number, on site and available for the
Superintendent's review. The certificate must show that the prover was
calibrated as follows:
(1) Master meters must have a meter factor within 0.9900 to 1.0100
determined by a minimum of five consecutive prover runs within 0.0005
(0.05 percent repeatability) as set forth in Subsection 6.5, Table 2 of
API 4.5 (incorporated by reference, see Sec. 226.0). The master meter
must not be mechanically compensated for oil gravity or temperature;
its readout must indicate units of volume without corrections.
(2) The meter factor must be documented on the calibration
certificate and must be calibrated at least once every 12 months. New
master meters must be calibrated immediately and recalibrated three
months thereafter. Master meters that have undergone mechanical
repairs, alterations, or changes that affect the calibration must be
calibrated immediately upon the completion of this work and
recalibrated three months thereafter in accordance with Annex B of API
4.8 (incorporated by reference, see Sec. 226.0).
(3) Displacement provers must meet the requirements set forth in
API 4.2
[[Page 2480]]
and be calibrated using the water-draw method set forth in API 4.9.2 at
the calibration frequencies specified in Subsection 10.1(b) of API 4.8
(all incorporated by reference, see Sec. 226.0).
(4) The base prover volume of a displacement prover must be
calculated in accordance with API 12.2.4 (incorporated by reference,
see Sec. 226.0).
(5) Displacement provers must be sized to obtain a displacer
velocity through the prover that is within the appropriate range during
proving in accordance with Subsections 4.3.4.1 and 4.3.4.2 of API 4.2
(incorporated by reference, see Sec. 226.0).
(6) Fluid velocity is calculated using Subsection 4.3.4.3, Equation
12 of API 4.2 (incorporated by reference, see Sec. 226.0).
(c) Meter proving runs. Meter proving must comply with the
applicable section(s) of API 4.1 (incorporated by reference, see Sec.
226.0) and the following requirements:
(1) Meter proving must be performed under normal operating
conditions. The normal operating conditions will be established by the
flow rate, fluid pressure, fluid temperature, and fluid gravity at the
time of proving. These established conditions will be in effect until
the next proving.
(i) The oil flow rate through the LACT or CMS during proving must
be within 10 percent of the normal flow rate;
(ii) The pressure as measured by the LACT or CMS during proving
must be within 10 percent of the normal flow rate;
(iii) The temperature as measured by the LACT or CMS during the
proving must be within 10 [deg]F of the normal operating temperature;
(iv) The gravity of the oil during proving must be within 5[deg]
API of the normal oil gravity; and
(v) If the normal flow rate, pressure, temperature, or oil gravity
vary by more than the limits defined in paragraphs (c)(1) through (4)
of this section, meter provings must be conducted at the upper, lower,
and midpoint limits of normal operating conditions.
(2) If each proving run is not of sufficient volume to generate at
least 10,000 pulses from the positive displacement meter or the
Coriolis meter as specified in Subsection 4.3.2.1 of API 4.2, then
pulse interpolation must be used in accordance with API 4.6 (both
incorporated by reference, see Sec. 226.0).
(3) Proving runs must be made until the calculated meter factor or
meter-generated pulses from five consecutive runs match within a
tolerance of 0.0005 (0.05 percent) between the highest and lowest value
in accordance with Subsection 9 of API 12.2.3 (incorporated by
reference, see Sec. 226.0).
(4) The new meter factor is the arithmetic average of the meter-
generated pulses or intermediate meter factors calculated from the five
consecutive runs in accordance with Subsection 9 of API 12.2.3
(incorporated by reference, see Sec. 226.0).
(5) Meter factor computations must follow the sequence set forth in
Subsection 12 of API 12.2.3 (incorporated by reference, see Sec.
226.0).
(6) If multiple meter factors are determined over a range of normal
operating conditions, then:
(i) If all the meter factors determined over a range of conditions
fall within 0.0020 of each other, a single meter factor may be
calculated for that range as the arithmetic average of all the meter
factors within that range. The full range of normal operating
conditions may be divided into segments such that all the meter factors
within each segment fall within a range of 0.0020. In such case, a
single meter factor for each segment may be calculated as the
arithmetic average of the meter factors within that segment; or
(ii) The metering system may apply a dynamic meter factor derived
(using linear interpolation, polynomial fit, etc.) from the series of
meter factors determined over the range of normal operating conditions,
so long as no two neighboring meter factors differ by more than 0.0020.
(7) The meter factor must be at least 0.9900 and no more than
1.0100.
(8) The initial meter factor for a new or repaired meter must be at
least 0.9950 and no more than 1.0050.
(9) For positive displacement meters, the back-pressure valve may
be adjusted after proving only within the normal operating fluid flow
rate and fluid pressure as described in paragraph (c)(1) of this
section. If the back-pressure valve is adjusted after proving, the
lessee must document the as-left fluid flow rate and fluid pressure on
the proving report.
(10) If a composite meter factor is calculated, the CPL value must
be calculated from the pressure setting of the back-pressure valve or
the normal operating pressure at the meter. Composite meter factors
must not be used with a Coriolis meter.
(d) Minimum proving frequency. The lessee must prove all FMP meters
every three months (quarterly) or each time the registered volume
flowing through the meter, as measured on the non-resettable totalizer
from the last proving, increases by 75,000 bbls, whichever occurs
first, but not more frequently than monthly.
(e) Events triggering proving. The lessee must prove all FMP meters
before the removal or sale of production after any of the following
events occur:
(1) Initial meter installation;
(2) Meter zeroing (Coriolis meter);
(3) Modification of mounting conditions;
(4) A change in fluid temperature that exceeds the transducer's
calibrated span;
(5) A change in the flow rate, pressure, temperature, or gravity
that exceeds the normal operating conditions as set forth in paragraph
(c)(1) of this section;
(6) The mechanical or electrical components of the meter are
changed, repaired, or removed;
(7) Internal calibration factors are changed or reprogrammed; or
(8) The Superintendent requests proving.
(f) Excessive meter factor deviation. If the difference between
meter factors established in two successive provings exceeds +/-0.0025,
the meter must be immediately removed from service, checked for damage
or wear, adjusted or repaired, and reproved before being returned to
service.
(1) The arithmetic average of the two successive meter factors must
be applied to the production measured through the meter between the
date of the previous meter proving and the date of the most recent
meter proving.
(2) The proving report must clearly show the most recent meter
factor and describe all subsequent adjustments or repairs.
(g) Verification of the temperature transducer. As part of each
required meter proving and upon replacement, the temperature averager
for a LACT system and temperature transducer used in conjunction with a
CMS must be verified against a known standard in accordance with the
following requirements:
(1) The temperature averager or temperature transducer must be
compared with a test thermometer traceable to NIST and having a stated
accuracy of +/-0.25[deg] or better; and
(2) The temperature reading displayed on the temperature averager
or temperature transducer must be compared with the reading of the test
thermometer using one of the following methods:
(i) The test thermometer must be placed in a test thermometer well
located not more than 12 inches from the probe of the temperature
averager or temperature transducer; or
(ii) Both the test thermometer and probe of the temperature
averager or temperature transducer must be placed
[[Page 2481]]
in an insulated water bath. The water bath temperature must be within
20 [deg]F of the normal flowing temperature of the oil.
(3) The displayed reading of instantaneous temperature from the
temperature averager or temperature transducer must be compared with
the reading from the test thermometer. If the readings differ by more
than 0.5 [deg]F, the difference must be noted on the meter proving
report and the temperature average or temperature transducer must be:
(i) Adjusted to match the reading of the test thermometer; or
(ii) Recalibrated, repaired, or replaced.
(h) Verification of the pressure transducer (if applicable). As
part of each required meter proving and upon replacement, the pressure
transducer must be compared with a test pressure device (dead weight or
pressure gauge) traceable to NIST and having a stated maximum
uncertainty of no more than one-half of the accuracy required from the
transducer being verified.
(1) The pressure reading displayed on the pressure transducer must
be compared with the reading of the test pressure device.
(2) The pressure transducer must be tested at the following three
points:
(i) Zero (atmospheric pressure);
(ii) 100 percent of the calibrated span of the pressure transducer;
and
(iii) A point that represents the normal flowing pressure through
the Coriolis meter.
(3) If the pressure applied by the test pressure device and the
pressure displayed on the pressure transducer vary by more than the
required accuracy of the pressure transducer, the pressure transducer
must be adjusted to read within the stated accuracy of the test
pressure device.
(i) Density verification (if applicable). If the API gravity of oil
is determined from the average density measured by the Coriolis meter
(rather than from a composite sample), then during each proving of the
Coriolis meter, the instantaneous flowing density determined by the
Coriolis meter must be verified by comparing it with an independent
density measurement as set forth in Subsection 9.1.2.1 of API 5.6
(incorporated by reference, see Sec. 226.0). The difference between
the indicated density determined from the Coriolis meter and the
independently determined density must be within the density reference
accuracy specification of the Coriolis meter. Sampling must be
performed in accordance with API 8.1, API 8.2, or API 8.3, as
appropriate, (all incorporated by reference, see Sec. 226.0).
(j) Reporting requirements for meter proving. The lessee must
report all meter proving and volume adjustments following any LACT
system or CMS malfunction, including excessive meter-factor deviation,
to the Superintendent within 14 calendar days after proving. Meter
proving reports may use the forms in Subsection 13 of API 12.2.3 or
Appendix C of API 5.6 (see Sec. 226.0 for availability information) or
any other format containing the same information as the API forms,
provided that the calculation of meter factors maintains the proper
calculation sequence and rounding.
(k) Edits and adjustments to reported volume. (1) If there are
measurement errors stemming from an equipment malfunction that results
in discrepancies to the calculated volume, the lessee must estimate the
volume reported during the period in which the error occurred.
(2) All edits made to the data before submission of the report to
ONRR must be documented and include verifiable justifications of the
edits made. Such documentation must be made available to the
Superintendent and ONRR upon request.
(3) All values on QTRs that have been changed or edited must be
clearly identified and cross-referenced to the justification required
in paragraph (k)(2) of this section.
(4) The volumes reported to ONRR must be corrected beginning with
the date that the inaccuracy occurred. If the date is unknown, the
volumes must be corrected beginning with the production month that
includes the date that is halfway between the date of the previous and
most recent verifications.
Sec. 226.114 Run tickets.
(a) Tank gauging. After oil is measured by tank gauging, the
lessee, purchaser, or transporter, as appropriate, must complete a
uniquely numbered run ticket containing the following information:
(1) The lessee's name;
(2) The lease number;
(3) The name of the individual that performed the tank gauging;
(4) The unique tank number and nominal tank capacity;
(5) The opening and closing dates and times;
(6) The open and closing gauges and observed temperatures in
[deg]F;
(7) The observed volume for opening and closing gauge using tank-
specific calibration charts (see Sec. 226.107(f));
(8) The total net standard volume removed from the tank following
API 11.1 (incorporated by reference, see Sec. 226.0);
(9) The observed API oil gravity and temperature in [deg]F;
(10) The API oil gravity at 60 [deg]F, following API 11.1
(incorporated by reference, see Sec. 226.0);
(11) The S&W content percentage; and
(12) The unique numbering of each seal removed and installed.
(b) LACT system and CMS. Unless the lessee is using a flow
computer, at the beginning of every month, before conducting proving
operations on a LACT system, the lessee, purchaser, or transporter, as
appropriate, must complete a uniquely numbered run ticket containing
the following information:
(1) The lessee's name;
(2) The name of the purchaser's representative;
(3) The lease number;
(4) The unique meter ID number;
(5) The opening and closing dates and times;
(6) The opening and closing totalizer readings of the indicated
volume;
(7) The meter factor, indicating whether it is a composite meter
factor;
(8) The total gross standard volume removed through the LACT system
or CMS;
(9) The API oil gravity;
(i) For API oil gravity determined from a composite sample, the
observed API oil gravity and temperature must be indicated in [deg]F
and the API oil gravity must be indicated at 60 [deg]F;
(ii) For API oil gravity determined from average density (CMS
only), the CMS must determine the average uncorrected density;
(10) The average temperature for the measurement period in [deg]F;
(11) The average flowing pressure for the measurement period in
psia;
(12) The S&W content percent; and
(13) The unique number of each seal removed and installed.
(c) Any accumulators used in the determination of average pressure,
average temperature, and average density for the measurement period
must be reset to zero whenever a new run ticket is opened.
(d) Run tickets must be submitted to the Superintendent on or
before the last calendar day of the month following the production
month.
Sec. 226.115 Oil measurement by alternate methods.
Any method of oil measurement at an FMP, other than tank gauging,
LACT system, or CMS, requires the Superintendent's prior approval.
Sec. 226.116 Determination of oil volumes by methods other than
measurement.
(a) When production cannot be measured due to a spill or leak, the
[[Page 2482]]
amount of production will be determined using the method the
Superintendent requires. This category of production includes, but is
not limited to, oil classified as slop or waste oil.
(b) No oil may be classified or disposed of as waste oil unless the
lessee demonstrates to the Superintendent's satisfaction that it is not
economically feasible to put such oil into marketable condition.
(c) The lessee must not sell or otherwise dispose of slop oil
without prior approval from the Superintendent. The sale or disposal of
slop oil must be reported to ONRR in accordance with the requirements
set forth in Sec. Sec. 226.45 and 226.87.
Subpart K--Gas Measurement
Sec. 226.117 General requirements.
(a) Gas must be measured on the lease or cooperative agreement unit
area from which it is produced unless approval for off-lease
measurement is obtained pursuant to Sec. 226.101.
(b) All bypasses of meters are prohibited.
(c) Tampering with any measurement device, component of a
measurement device, or measurement process is prohibited. Violation of
this prohibition will result in the assessment of the maximum penalty
available under Sec. 226.162(c).
Sec. 226.118 Timeframes for compliance.
(a) All equipment and procedures used to measure the volume of gas
for royalty purposes after [effective date of final rule] must comply
with the requirements in this subpart.
(b) All equipment and procedures used to measure the volume of gas
for royalty purposes in use on [effective date of final rule] must
comply with the requirements in this subpart by [one year from
effective date of final rule]. Prior to that date, the equipment and
procedures used to measure gas for royalty purposes must continue to
comply with Sec. 226.39, as it appears in 25 CFR part 226 (April 1,
2017, edition) and any applicable orders or notices.
Sec. 226.119 [Reserved]
Sec. 226.120 Specific performance requirements.
(a) Flow rate measurement uncertainty levels. (1) For high-volume
FMPs, the measuring equipment must achieve an overall flow rate
measurement uncertainty within +/- 3 percent.
(2) For very-high-volume FMPs, the measuring equipment must achieve
an overall flow rate measurement uncertainty within +/- 2 percent.
(3) There are no measurement uncertainty requirements for low- and
very-low-volume FMPs.
(4) The measurement uncertainty is based on the values of flowing
parameters (e.g., differential pressure, static pressure, and flowing
temperature for differential meters or velocity, mass flow rate, and
volumetric flow rate for linear meters) determined as follows, listed
in order of priority:
(i) The average flowing parameters listed on the most recent daily
QTR, if available to the Superintendent at the time of the uncertainty
determination; or
(ii) The average flowing parameters from the previous day, as
required under Sec. 226.125(d)(4)(i) through (iii) (for differential
meters).
(5) The uncertainty must be calculated in accordance with Section
12 of API 14.3.1 (incorporated by reference, see Sec. 226.0) or other
methods the Superintendent approves.
(b) Heating value uncertainty levels. (1) For high-volume FMPs, the
measuring equipment must achieve an annual average heating value
uncertainty within +/- 3 percent.
(2) For very-high-volume FMPs, the measuring equipment must achieve
an annual average heating value uncertainty within +/- 2 percent.
(3) There are no heating value uncertainty requirements for low-
and very-low-volume FMPs.
(4) Unless otherwise approved by the Superintendent, the average
annual heating value uncertainty must be determined as follows:
[GRAPHIC] [TIFF OMITTED] TP13JA23.008
(c) Bias. For low-, high-, and very-high-volume FMPs, the measuring
equipment used for either the flow rate or heating value determination
must achieve measurement without statistically significant bias.
(d) Verifiability. The lessee must not use measurement equipment
for which the Superintendent cannot independently verify the accuracy
and validity of any input, factor, or equation used by the measuring
equipment to determine quantity, rate, or heating value. Verifiability
includes the ability to independently recalculate the volume, rate, and
heating value based on source records and field observations.
Sec. 226.121 Flange-tapped orifice plate (primary devices).
(a) Exemptions from requirements. The standards and requirements in
this section apply to all flange-tapped orifice plates subject to the
following exceptions:
(1) Low-volume FMPs are exempt from the standards in paragraph (b)
of this section; and
(2) Very-low-volume FMPs are exempt from the standards and
requirements in paragraphs (b), (c), (f) and (l) of this section.
[[Page 2483]]
(b) Orifice plate specifications. Orifice plates must meet the
requirements set forth in Section 4 of API 14.3.2 (incorporated by
reference, see Sec. 226.0) and the:
(1) Beta ratio must be no less than 0.10 and no greater than 0.75;
and
(2) Orifice bore diameter must be no less than 0.45 inches.
(c) Initial orifice plate inspection. If an FMP measures oil from
wells first coming into production or existing wells that have been re-
fractured, the lessee must inspect the orifice plate upon installation
and every two weeks thereafter until the production of particulate
matter from the wells subsides. If the orifice plate does not comply
with the requirements set forth in Subsection 4 of API 14.3.2
(incorporated by reference, see Sec. 226.0), the lessee must replace
it. Once the orifice plate complies with API 14.3.2, Subsection 4, the
lessee must conduct inspections as set forth in paragraph (d) of this
section.
(d) Routine orifice plate inspection. (1) Lessees must pull and
inspect the orifice plate as follows:
(i) Once every 12 months for very-low-volume FMPs;
(ii) Once every 6 months for low-volume FMPs;
(iii) Once every 3 months for high-volume FMPs; and
(iv) Once a month for very-high-volume FMPs.
(2) If a routine inspection reveals that an orifice plate does not
comply with Section 4 of API 14.3.2 (incorporated by reference, see
Sec. 226.0), the lessee must replace it.
(e) Documentation of orifice plate inspections. The lessee must
document each orifice plate inspection and include that documentation
as part of the verification report submitted in accordance with
Sec. Sec. 226.123 or 226.126. The documentation must include:
(1) The lessee's name;
(2) The lease number;
(3) The well or facility name and number;
(4) The plate orientation (bevel upstream or downstream);
(5) The measured orifice bore diameter;
(6) The plate condition (documenting compliance with Section 4 of
API 14.3.2 (incorporated by reference, see Sec. 226.0);
(7) The presence of oil, grease, paraffin, scale, or other
contaminants on the plate;
(8) The date and time of inspection; and
(9) Whether the plate was replaced.
(f) Meter tube specifications.
(1) Meter tubes must meet the requirements set forth in Subsections
5.1 through 5.4 of API 14.3.2 (incorporated by reference, see Sec.
226.0). If flow conditioners are used, they must be isolating flow
conditioners or 19-tube bundle flow straighteners constructed in
compliance with Subsections 5.5.2 through 5.5.4 of API 14.3.2 and
located in compliance with Subsection 6.3 of API 14.3.2 (all
incorporated by reference, see Sec. 226.0).
(2) Meter tube lengths and the location of 19-tube bundle flow
straighteners, if applicable, must comply with the requirements set
forth in Subsection 6.3 of API 14.3.2 (incorporated by reference, see
Sec. 226.0). If the diameter ratio falls between the values set forth
in Subsection 6.3, Tables 7, 8a, or 8b of API 14.3.2 (incorporated by
reference, see Sec. 226.0), the length identified for the larger
diameter ratio in the appropriate table is the minimum requirement for
meter tube length and determines the location of the end of the 19-tube
bundle flow straightener that is closest to the orifice plate.
(g) Basic meter tube inspection. The lessee must perform a basic
inspection of meter tubes that can identify obstructions, pitting, and
buildup of foreign substances within the following timeframe:
(1) Frequency. (i) Once every 10 years for low-volume and very-low-
volume FMPs; and
(ii) Once every 5 years for high-volume and very-high-volume FMPs.
(2) Corrective action. If the basic meter tube inspection
identifies obstructions, pitting, or buildup of foreign substances, the
lessee must take one of the following corrective actions within 30
calendar days:
(i) For all FMPs, if the inspection only identifies the presence of
an obstruction (such as debris in front of the flow conditioner), the
lessee must remove the obstruction. If the inspection only identifies
pitting, no corrective action is required;
(ii) For low- and very-low volume FMPs, if the inspection
identifies the buildup of foreign substances, the lessee must clean the
meter tube of such buildup; and
(iii) For high- and very-high-volume FMPs, if the inspection
indicates pitting or the buildup of foreign substances, the lessee must
clear or repair the meter tube and conduct a detailed meter tube
inspection under paragraph (h) of this section; or
(iv) Submit a written request to the Superintendent for an
extension of the 30-day corrective action timeframe, justifying the
need for the extension and specifying the length of the extension
requested.
(h) Detailed meter tube inspection. If a detailed meter tube
inspection is required under paragraph (g)(2)(iii) of this section, the
lessee must measure and inspect the meter tube to determine whether it
complies with Subsections 5.1 through 5.4 of API 14.3.2 (incorporated
by reference, see Sec. 226.0). If the meter tube does not comply with
the required standards, the lessee must repair or replace the meter
tube and bring into compliance.
(i) Documentation of meter tube inspections. The lessee must
document all inspections and make such documentation available to the
Superintendent upon request. The documentation must include:
(1) The lessee's name;
(2) The lease number;
(3) The well or facility name and number;
(4) The date and time of the inspection;
(5) The type of equipment used to perform the inspection;
(6) For a basic meter tube inspection, a description of findings,
including the location and severity of pitting, obstructions, and
buildup of foreign substances; and
(7) For detailed meter tube inspections, information demonstrating
that the meter tube complies with Subsection 5.1 through 5.4 of API
14.3.2 (incorporated by reference, see Sec. 226.0) and showing all
required measurements.
(j) Advance notice of inspections. The lessee must notify the
Superintendent at least 72 hours in advance of performing an inspection
under paragraphs (d), (g), and (h) of this section or submit a monthly
or quarterly schedule of inspections at least 15 calendar days prior to
the date of the first inspection scheduled.
(k) Other inspections. The lessee must conduct additional
inspections at the Superintendent's request.
(l) Thermometer well. Thermometer wells used for determining the
flowing temperature of the gas and verification (test well), must be
located in compliance with Subsection 6.5 of API 14.3.2 (incorporated
by reference, see Sec. 226.0). Where multiple thermometer wells have
been installed in a meter tube, the flowing temperature must be
measured from the thermometer well closest to the primary device.
Thermometer wells used to measure or verify flowing temperature must
contain a thermally conductive liquid.
(m) Sampling probe. The sampling probe must be located as specified
in Sec. 226.130.
[[Page 2484]]
Sec. 226.122 Mechanical recorder (secondary device).
(a) Mechanical recorders may be used as a secondary device on low-
and very-low-volume FMPs only.
(b) Chart recorders used in conjunction with differential-type
meters are approved for low- and very-low-volume FMPs only.
(c) Very-low-volume FMPs are exempt from the standards and
requirements set forth paragraphs (e), (f), and (g) of this section.
(d) The connection between the pressure taps and the mechanical
recorder must meet the following requirements:
(1) Gauge lines must:
(i) Have a nominal diameter of not less than \3/8\ inch;
(ii) Be sloped upwards from the pressure taps at a minimum pitch of
one inch per foot of length with no visible sag;
(iii) Have the same internal diameter along their entire length;
and
(iv) Be no longer than 6 feet.
(2) Valves, including the valves in manifolds, must have a full-
opening internal diameter of not less than \3\/8 inch;
(3) There must not be any tees except for the static-pressure line;
and
(4) There must be no connections to any other devices or more than
one differential-pressure bellows and static pressure element.
(e) The differential-pressure pen must record at a minimum reading
of 10 percent of the differential-pressure bellows range for the
majority of the flowing period. This requirement does not apply to
inverted charts.
(f) The flowing temperature of the gas must be continuously
recorded and used in the volume calculations.
(g) The following information must always be maintained at the FMP
in a legible condition and accessible to the Superintendent:
(1) The differential-pressure-bellows range;
(2) The static-pressure-element range;
(3) The temperature-element range;
(4) The relative density (specific gravity) of the gas;
(5) The static-pressure units of measure (psia or psig);
(6) The elevation of, or atmospheric pressure at, the FMP;
(7) The reference inside diameter of the meter tube;
(8) The primary device type;
(9) The orifice-bore or other primary device dimensions necessary
for device verification, Beta or area ratio determination, and gas
volume calculation;
(10) The location of isolating flow conditioners, if used;
(11) The location of the downstream end of the 19-tube-bundle flow
straighteners, if used;
(12) The date of last primary device inspection; and
(13) The date of last meter verification.
(h) The differential pressure, static pressure, and flowing
temperature elements must be operated between the lower- and upper-
calibrated limits of the respective elements.
Sec. 226.123 Verification and calibration of mechanical recorder.
(a) Verification following installation or repair.
(1) Prior to performing any verification of a mechanical recorder,
the lessee must perform a leak test. The test must be conducted in a
manner that will detect leaks in all connections and fittings of the
secondary device, including meter manifolds and verification equipment,
isolation valves, and equalizer valves. If leaks are detected, the
lessee must repair the leaks before proceeding with verification.
(2) The lessee must adjust the time lag between the differential-
and static-pressure pens, if necessary, to be \1/96\ of the chart
rotation period measured at the chart hub.
(3) The meter's differential pen arc must be able to duplicate the
test chart's time arc over the full range of the test chart and must be
adjusted if necessary.
(4) The as-left values must be verified, in the following sequence,
against a certified pressure device for the differential- and static-
pressure elements (if the static-pressure pen has been offset for
atmospheric pressure, the static-pressure element range is in psia):
(i) Zero (vented to atmosphere);
(ii) 50 percent of element range;
(iii) 100 percent of element range;
(iv) 80 percent of element range;
(v) 20 percent of element range; and
(vi) Zero (vented to atmosphere).
(5) The following as-left temperatures must be verified by placing
the temperature probe in a water bath with a certified test
thermometer:
(i) Approximately 10 [deg]F below the lowest expected flowing
temperature;
(ii) Approximately 10 [deg]F above the highest expected flowing
temperature; and
(iii) At the expected average flowing temperature.
(6) If any of the readings required in paragraph (a)(4) or (5) of
this section vary from the test device reading by more than the
following tolerance levels, the lessee must replace and verify the
element for which readings were outside the applicable tolerances
before returning the meter to service:
(i) Differential pressure element, +/-0.5 percent;
(ii) Static pressure element, +/-1.0 percent; and
(iii) Temperature element, +/-2 [deg]F.
(7) If the static-pressure pen is offset for atmospheric pressure,
the atmospheric pressure must be calculated in accordance with Appendix
A to this part and the pen must be offset prior to obtaining the as-
left verification values required in paragraph (a)(4) of this section.
(b) Routine verification frequency. The differential pressure
bellows, static pressure element, and temperature element must be
verified according to the requirements in this section at the following
frequencies:
(1) Once every 6 months for very-low-volume FMPs; and
(2) Once every 3 months for low-volume FMPs.
(c) Routine verification procedures. (1) Prior to performing any
verification required in this subpart, the lessee must perform a leak
test in the manner specified in paragraph (a)(1) of this section.
(2) No adjustments to the pens or linkages may be made until an as-
found verification is obtained. If the static pen has been offset for
atmospheric pressure, the static pen must not be reset to zero until
the as-found verification is obtained.
(3) The lessee must obtain and verify the as-found values of
differential and static pressure against a certified pressure device at
the readings listed in paragraph (a)(4) of this section, subject to the
following additional requirements:
(i) If there is sufficient data on-site to determine the point at
which the differential and static pens normally operate, the lessee
must also obtain an as-found value at those points;
(ii) If sufficient data is not available on-site, the lessee must
also obtain as-found values at 5 percent and 10 percent of the element
range; and
(iii) If the static pressure pen has been offset for atmospheric
pressure, the static-pressure element range is in units of psia.
(4) The as-found value for temperature must be taken using a
certified test thermometer placed in a test thermometer well if there
is flow through the meter and the meter tube is equipped with such a
well. If there is no flow through the meter, or if the meter is not
equipped with a test thermometer well, the temperature probe must be
verified by placing it in an insulated water bath along with a test
thermometer.
[[Page 2485]]
(5) The element undergoing verification must be calibrated
according to manufacturer specifications if any of the as-found values
determined under paragraph (c)(3) or (4) of this section are not within
the tolerances specified in paragraph (a)(6) of this section, when
compared to the values applied by the test equipment.
(6) The lessee must adjust the time lag between the differential-
and static-pressure pens, if necessary, to be \1/96\ of the chart
rotation period, measured at the chart hub.
(7) The meter's differential pen arc must be able to duplicate the
test chart's time arc over the full range of the test chart and must be
adjusted if necessary.
(8) If any adjustment to the meter was made, the lessee must
perform an as-left verification on each element adjusted using the
procedures in paragraphs (c)(3) and (4) of this section.
(9) If, after an as-left verification, any of the readings required
by paragraphs (c)(3) and (4) of this section vary by more than the
tolerances set forth in paragraph (a)(6) of this section when compared
with the test device reading, the lessee must replace and verify any
element which has readings outside of the applicable tolerances under
this section before returning the meter to service.
(10) If the static-pressure pen is offset for atmospheric pressure:
(i) The atmospheric pressure must be calculated in accordance with
Appendix A to this part; and
(ii) The pen must be offset prior to obtaining the as-left
verification values required in paragraph (c)(3) of this section.
(d) The lessee must retain documentation of each verification and
make such documentation available to the Superintendent upon request.
The documentation must include:
(1) The date and time of the verification;
(2) The date of the prior verification;
(3) Primary device data (reference inside diameter of the meter
tube and differential-device size and Beta or area ratio) if the
orifice plate is pulled and inspected;
(4) The type and location of taps (flange or pipe, upstream or
downstream static tap);
(5) The atmospheric pressure used to offset the static-pressure
pen, if applicable;
(6) Mechanical recorder data (differential pressure, static
pressure, and temperature element ranges);
(7) The normal operating points for differential pressure, static
pressure, and flowing temperature;
(8) The verification points (as-found and applied) for each
element;
(9) The verification points (as-left and applied) for each element
if a calibration is performed; and
(10) The name and contact information for each individual who
performed or witnessed the verification, if applicable.
(e) Notification of verification. (1) For verifications performed
after installation or following repair, the lessee must notify the
Superintendent at least 72 hours before conducting the verification.
(2) For routine verifications, the lessee must notify the
Superintendent at least 72 hours before conducting the verification or
must submit a monthly or quarterly verification schedule to the
Superintendent in advance.
(f) Correction of reported volumes. If during the verification, the
combined errors in as-found differential pressure, static pressure, and
flowing temperature taken at the normal operating points tested
resulted in a flow-rate error greater than 2 percent and 2 Mcf/day, the
volumes reported to ONRR must be corrected beginning with the date that
the inaccuracy occurred. If such date is unknown, the volumes must be
corrected beginning with the production month that includes the date
that is halfway between the date of the last verification and the date
of the current verification. Corrected reports must be submitted to
ONRR within 30 calendar days of discovery of the error in the reported
volumes.
(g) Test equipment certification. Test equipment used to verify or
calibrate elements at an FMP must be certified at least once every two
years. Documentation of the recertification must be available on site
during all verifications and must show the:
(1) Test equipment serial number, make, and model;
(2) Date that recertification took place;
(3) Test equipment measurement range; and
(4) Uncertainty determined or verified as part of the
recertification.
Sec. 226.124 Integration statements.
(a) The lessee must retain an unedited integration statement and
make such statement available to the Superintendent upon request. The
integration statement must contain the following:
(1) The lessee's name;
(2) The lease number;
(3) The well or facility name and number;
(4) The name of the company performing the integration;
(5) The month and year to which the integration statement applies;
(6) The reference inside diameter of the meter tube (inches);
(7) The orifice bore diameter (inches) or Beta or area ratio and
discharge coefficient, as applicable, and any other information
necessary to calculate flow rate;
(8) The relative density (specific gravity);
(9) The CO2 content (mole percent);
(10) The Dinitrogen (N2) content (mole percent);
(11) The heating value calculated under Sec. 226.140 (Btu/standard
cubic feet);
(12) The atmospheric pressure or elevation at the FMP;
(13) The pressure base;
(14) The temperature base;
(15) The static-pressure tap location (upstream or downstream);
(16) The chart rotation (hours or days);
(17) The differential-pressure bellows range (inches of water);
(18) The static-pressure element range (psi); and
(19) For each chart integrated:
(i) The date and time on, and date and time off;
(ii) The average differential pressure (inches of water)
(iii) The average static pressure;
(iv) The static-pressure units of measure (psia or psig);
(v) The average temperature ([deg]F);
(vi) The integrator counts or extension;
(vii) The hours of flow; and
(viii) The volume (Mcf).
(b) The volume for each chart integrated must be determined as
follows:
V = IMV x IV
Where:
V = reported volume, Mcf
IMV = integral multiplier value, as calculated under this section
IV = the integral value determined by the integration process (also
known as the ``extension,'' ``integrated extension,'' and
``integrator count'')
(1) If the primary device is a flange-tapped orifice plate, a
single IMV must be calculated for each chart or chart interval using
the following equation:
[[Page 2486]]
[GRAPHIC] [TIFF OMITTED] TP13JA23.009
Where:
Cd = discharge coefficient or flow coefficient,
calculated under API 14.3.3 or Section 5 of AGA Report No. 3 (both
incorporated by reference, see Sec. 226.0)
[beta] = beta ratio
Y = gas expansion factor, calculated under Subsection 5.6 of API
14.3.3, or Section 5 of AGA Report No. 3 (both incorporated by
reference, see Sec. 226.0)
d = orifice diameter, in inches
Zb = supercompressibility at base pressure and
temperature
Gr = relative density (specific gravity)
Zf = supercompressibility at flowing temperature and
pressure
Tf = average flowing temperature, in degrees Rankine
(2) Variables that are functions of differential pressure, static
pressure, or flowing temperature (e.g., Cd, Y,
Zf) must use the average values of differential pressure,
static pressure, and flowing temperature as determined from, and
reported on, the integration statement for the chart or chart interval
integrated. The flowing temperature must be the average flowing
temperature reported on the integration statement for the chart or
chart interval being integrated.
(c) Atmospheric pressure used to convert static pressure in psig to
static pressure in psia, must be determined in accordance with Appendix
A to this part.
Sec. 226.125 Electronic gas measurement (secondary and tertiary
device).
(a) All electronic gas measurement systems (EGMs) must meet the
requirements set forth in Section 9 and Subsection 4.4.5 of API 21.1
(incorporated by reference, see Sec. 226.0).
(b) Very-low-volume FMPs are exempt from the standards and
requirements set forth in paragraphs (c), (f), and (g) of this section.
(c) The connection between pressure taps and the secondary device
must meet the following requirements:
(1) If gauge lines are used, they must:
(i) Have a nominal diameter of not less than \3/8\ inch;
(ii) Be sloped upwards from the pressure taps at a minimum pitch of
one inch per foot of length, with no visible sag;
(iii) Have the same internal diameter along their entire length;
and
(iv) Be no longer than 6 feet.
(2) Valves, including the valves in manifolds, must have a full-
opening internal diameter of not less than \3/8\ inch;
(3) There must not be any tees, except for the static pressure
line; and
(4) There must be no connections to any other devices or more than
one differential pressure and static pressure transducer, except that
where the lessee is employing redundancy verification, two differential
pressure and two static pressure transducers may be connected.
(d) Each FMP must include a display that:
(1) Is readable without the need for data collection units, laptop
computers, a password, or any special equipment;
(2) Is on-site and in a location that is accessible to the
Superintendent;
(3) Includes the units of measure for each required variable;
(4) Displays the previous day's volume and the following variables
consecutively:
(i) Current flowing static pressure with units (psia or psig);
(ii) Current differential pressure (inches of water);
(iii) Current flowing temperature ([deg]F);
(iv) Current flow rate (Mcf/day or scf/day); and
(5) Displays an hourly or daily QTR no more than 31 calendar days
old and shows the following information:
(i) The previous period (for this section, previous period means at
least 1 day prior, but no longer than 1 month prior) average
differential pressure (inches of water);
(ii) The average static pressure with units (psia or psig); and
(iii) The average flowing temperature ([deg]F).
(e) The lessee must always maintain the following at the FMP in
legible condition and accessible to the Superintendent:
(1) The unique meter identification number;
(2) The relative density (specific gravity);
(3) The elevation of, or the atmospheric pressure at, the FMP;
(4) Primary device information, such as orifice bore diameter
(inches) or Beta or area ratio and discharge coefficient, as
applicable;
(5) The reference inside diameter of meter tube;
(6) The make, model, and location of isolating flow conditioners,
if used;
(7) The location of the downstream end of 19-tube-bundle flow
straighteners, if used;
(8) The upper calibrated limit for each transducer;
(9) The location of the static-pressure tap (upstream or
downstream);
(10) The date of last orifice plate inspection;
(11) The date of last meter tube inspection; and
(12) The date of last secondary device inspection.
(f) The differential pressure, static pressure, and flowing
temperature transducers must be operated between the upper and lower
calibrated limits of the transducer.
(g) The flowing temperature of the gas must be continuously
measured and used in the flow-rate calculations in accordance with
Section 4 of API 21.1 (incorporated by reference, see Sec. 226.0).
Sec. 226.126 Verification and calibration of electronic gas
measurement systems.
(a) Transducer verification and calibration after installation or
repair. (1) Prior to performing any verification required in this
section, the lessee must perform a leak test in the manner set forth in
Sec. 226.123(a)(1).
(2) The lessee must verify the points listed in Subsection 7.3.3 of
API 21.1 (incorporated by reference, see Sec. 226.0), by comparing the
values from the certified test device with the values used by the flow
computer to calculate flow rate. If any of these as-left readings vary
from the test equipment reading by more than the tolerance calculated
using Subsection 8.2.2.2, Equation 24 of API 21.1 (incorporated by
reference, see Sec. 226.0), the transducer must be replaced and tested
under this paragraph.
(3) For absolute static pressure transducers, the value of
atmospheric pressure used when the transducer is vented to atmosphere
must be calculated in accordance with Appendix A to this part, measured
by a NIST-certified barometer with a stated accuracy of +/-0.06 psi
(4 millibars) or better, or obtained from an absolute
pressure calibration device.
(4) Prior to putting the meter into service, the differential
pressure transducer must be tested at zero with full working pressure
applied to both sides of the transducer. If the absolute value of the
transducer reading is greater than the reference accuracy of the
transducer, expressed in inches of water column, the transducer must be
re-zeroed.
(b) Routine verification frequency. (1) If redundancy verification
under
[[Page 2487]]
paragraph (d) of this section is not used, the differential pressure,
static pressure, and temperature transducers must be verified in
accordance with the procedures set forth in paragraph (c) of this
section at the following frequencies:
(i) Once every 24 months for low-volume and very-low-volume FMPs;
(ii) Once every 6 months for high-volume and very-high-volume FMPs.
(2) If redundancy verification under paragraph (d) of this section
is used, the differential pressure, static pressure, and temperature
transducers must be verified in accordance with the procedures set
forth therein. In addition, the temperature transducers must be
verified in accordance with the procedures set forth in paragraph (c)
of this section at least once a year.
(c) Routine verification procedures. Verifications must be
performed in accordance with Subsection 8.2 of API 21.1 (incorporated
by reference, see Sec. 226.0), subject to the following exceptions,
additions, and clarifications:
(1) Prior to performing any verification required under this
section, the lessee must perform a leak test in the manner set forth in
Sec. 226.123(a)(1).
(2) An as-found verification for differential pressure, static
pressure, and temperature must be conducted at the normal operating
point of each transducer.
(i) The normal operating point is the mean value taken over a
previous time period that is not less than one day, or greater than one
month, prior. Acceptable mean values include means that are weighted
based on flow time and flow rate.
(ii) For differential and static pressure transducers, the pressure
applied to the transducer must be within five percentage points of the
normal operating point.
(iii) For the temperature transducer, the water bath or test
thermometer well must be within 20 [deg]F of the normal operating point
for temperature.
(3) If a transducer is calibrated, the as-left verification must
include the normal operating point of that transducer, as defined in
paragraph (c)(2) of this section.
(4) The as-found values for differential pressure obtained with the
low side vented to atmospheric pressure must be corrected to working
pressure values using Annex H, Equation H.1 of API 21.1 (incorporated
by reference, see Sec. 226.0).
(5) The verification tolerance for differential and static pressure
is calculated using Subsection 8.2.2.2, Equation 24 of API 21.1
(incorporated by reference, see Sec. 226.0). The verification
tolerance for temperature is equivalent to the uncertainty of the
temperature transmitter or 0.5 [deg]F, whichever is greater.
(6) All required verification points must be within the applicable
verification tolerance before returning the meter to service.
(7) Prior to putting a meter into service, the differential
pressure transducer must be tested at zero with full working pressure
applied to both sides of the transducer. If the absolute value of the
transducer reading is greater than the reference accuracy of the
transducer, as expressed in inches of water column, the transducer must
be re-zeroed.
(d) Redundancy verification procedures. Redundancy verification
must be performed as required under Subsection 8.2 of API 21.1
(incorporated by reference, see Sec. 226.0), subject to the following
exceptions, additions, and clarifications:
(1) The lessee must identify which set of transducers is used for
reporting on the Form ONRR-4054 (the primary transducers) and which set
of transducers is used as a check (the check set of transducers);
(2) For every calendar month, the lessee must compare the flow-time
linear averages of differential pressure, static pressure, and
temperature readings from the primary transducers with those from the
check transducers; and
(3) If for any transducer the difference between the averages
exceeds the tolerance defined by the equation below, the lessee must
verify both the primary and check transducer under paragraph (c) of
this section within the first five days of the month following the
month in which the redundancy verification was performed. For example,
if the redundancy verification for March reveals that the difference in
flow-time linear averages of differential pressure exceeded the
verification tolerance, both the primary and check differential-
pressure transducers must be verified under paragraph (c) of this
section by April 5th.
[GRAPHIC] [TIFF OMITTED] TP13JA23.010
Where:
AP is the reference accuracy of the primary transducer
and
AC is the reference accuracy of the check transducer
(e) Documentation of verifications. The lessee must retain
documentation of each verification and make such documentation
available to the Superintendent upon request. The documentation must
include the following:
(1) The lessee's name;
(2) The lease number;
(3) The well or facility name and number;
(4) The date and time of verification, and date of the last
verification;
(5) Primary device information (reference inside diameter of the
meter tube and orifice plate or differential device size, and Beta or
area ratio);
(6) The type and location of taps (flange or pipe, upstream or
downstream, static tap);
(7) The upper calibrated limit for each transducer;
(8) The normal operating points for differential pressure, static
pressure, and flowing temperature;
(9) The atmospheric pressure;
(10) The verification points (as-found and applied) for each
transducer;
(11) The verification points (as-left and applied) for each
transducer if calibration was performed;
(12) The differential device date of inspection and condition
(e.g., clean, sharp edge, or surface condition);
(13) The verification equipment make, model, range, accuracy, and
date of last certification; and
(14) The name(s) and contact information for individuals that
performed or witnessed the verification, if applicable.
(f) Notification of verification. (1) The lessee must notify the
Superintendent at least 72 hours before conducting verifications after
installation or following repair.
(2) The lessee must notify the Superintendent at least 72 hours
before conducting routine verifications or provide the Superintendent
with a monthly or quarterly verification schedule in advance.
(g) Correction of reported volumes. If during the verification, the
combined errors in as-found differential pressure, static pressure, and
flowing temperature taken at the normal operating points tested result
in a flow-rate error greater than 2 percent and 2 Mcf/day, the volumes
reported to ONRR must be corrected beginning with the date that the
inaccuracy occurred. If that date is unknown, the volumes must be
corrected beginning with the production month that includes the date
that is halfway between the date of the last verification and the date
of the present verification. Corrected reports must be submitted to
ONRR within 30 calendar days of discovery of the error in the reported
volumes.
(h) Certification of test equipment. Test equipment used to verify
or calibrate transducers at an FMP must be
[[Page 2488]]
certified at least once every two years. Documentation of the
certification must be on-site and available to the Superintendent
during all verifications. Such documentation must show the:
(1) Test equipment serial number, make and model;
(2) Date that recertification took place;
(3) Test equipment measurement range; and
(4) Uncertainty determined or verified as part of the
recertification.
(i) Accuracy standards for test equipment. Test equipment used to
verify or calibrate transducers at an FMP must meet the following
accuracy standards:
(1) The accuracy of the test equipment, stated in actual units of
measure, must be no greater than 0.5 times the reference accuracy of
the transducer being verified, also stated in actual units of measure;
or
(2) The equipment must have a stated accuracy of 0.10 percent of
the upper calibrated limit of the transducer being verified.
Sec. 226.127 Flow rate, volume, and average value calculation.
(a) For flange-tapped orifice plates, the flow rate must be
calculated under:
(1) Sections 4 and 5 of API 14.3.3 (incorporated by reference, see
Sec. 226.0); and
(2) AGA Report No. 8 (incorporated by reference, see Sec. 226.0),
for supercompressibility.
(b) Atmospheric pressure used to convert static pressure in psig to
static pressure in psia must be determined using Appendix A of this
part.
(c) Hourly and daily gas volumes, average values of the live input
variables, flow time, and integral value or average extension required
under Sec. 226.128 must be determined using Section 4 and Annex B of
API 21.1 (incorporated by reference, see Sec. 226.0).
Sec. 226.128 Logs and records.
(a) The lessee must retain, and make available to the
Superintendent upon request, the original, unaltered, unprocessed, and
unedited daily and hourly QTRs, which must contain the information
identified in Subsection 5.2 of API 21.1 (incorporated by reference,
see Sec. 226.0), subject to the following additions and
clarifications:
(1) The QTRs must contain the lessee's name, lease number, and well
or facility name and number;
(2) The volume, flow time, and integral value or average extension
must be reported to at least five significant digits;
(3) The average differential pressure, static pressure, and
temperature, as calculated in Sec. 226.127(c), must be reported to at
least three significant digits; and
(4) The QTRs must include a statement indicating whether the lessee
submitted the integral value or average extension.
(b) The lessee must retain, and make available to the
Superintendent upon request, the original unaltered, unprocessed, and
unedited configuration log, which must contain the information
specified in Subsection 5.4 (including the flow-computer snapshot
report in Subsection 5.4.2) of API 21.1 and Annex G of API 21.1 (both
incorporated by reference, see Sec. 226.0), as well as the following:
(1) The lessee's name;
(2) The lease number;
(3) The well or facility name and number;
(4) For very-low-volume FMPs only, the fixed temperature, if not
continuously measured ([deg]F); and
(5) The static-pressure tap location (upstream or downstream).
(c) The lessee must retain, and make available to the
Superintendent upon request, the original, unaltered, unprocessed, and
unedited event log. The event log must comply with the requirements set
forth in Subsection 5.5 of API 21.1 (incorporated by reference, see
Sec. 226.0), and must have sufficient capacity to be retrieved and
stored at intervals that will maintain a continuous record of events
for the required six-year retention period or the life of the FMP,
whichever is shorter.
(d) The lessee must retain, and make available to the
Superintendent upon request, an alarm log. The alarm log must comply
with the requirements set forth in Subsection 5.6 of API 21.1
(incorporated by reference, see Sec. 226.0).
Sec. 226.129 Gas sampling and analysis.
(a) Samples must be taken using one of the following methods:
(1) Spot sampling under Sec. Sec. 226.131, 226.132, and 226.133;
(2) Flow-proportional composite sampling under Sec. 226.134; or
(3) On-line gas chromatograph under Sec. 226.135.
(b) At all times during the sampling process, the minimum
temperature of all gas sampling components must be the lesser of:
(1) The flowing temperature of the gas measured at the time of
sampling; or
(2) 30 [deg]F above the calculated hydrocarbon dew point of the
gas.
Sec. 226.130 Sampling probe and tubing.
(a) Exemptions. Very-low-volume FMPs are exempt from the standards
and requirements set forth in this section.
(b) Location of sample probe. (1) The sampling probe must be
located as specified in Subsection 6.4.2 of API 14.1 (incorporated by
reference, see Sec. 226.0) and must be the first obstruction
downstream of the primary device.
(2) The sample probe must be exposed to the same ambient
temperature as the primary device. The lessee may accomplish this by
physically locating the sample probe in the same ambient temperature
conditions as the primary device (such as in a heated meter house) or
by installing insulation and/or heat tracing along the entire meter
run.
(c) Sample probe design and type. (1) Sample probes must be made
from stainless steel.
(2) If a regulating type of sample probe is used, the pressure-
regulating mechanism must be inside the pipe or maintained at a
temperature of at least 30 [deg]F above the hydrocarbon dew point of
the gas.
(3) The sample probe length must be the shorter of the:
(i) Length necessary to place the collection end of the probe in
the center one-third of the pipe cross-section; or (ii) Recommended
probe length in Subsection 6.4, Table 1 of API 14.1 (incorporated by
reference, see Sec. 226.0).
(4) The use of membranes, screens, or filters at any point in the
sample probe is prohibited.
(d) Sample tubing type. Sample tubing connecting the sample probe
to the sample container or analyzer must be made of stainless steel or
nylon 11.
Sec. 226.131 Spot samples--general requirements.
(a) Sampling while flowing. The FMP must be flowing when a gas
sample is taken. If an FMP is in non-flowing status on the date that a
sample is due under Sec. 226.133, no sample is required. The lessee
must take a sample within 15 calendar days of the date that flow to the
FMP is reinitiated. For purposes of this section, non-flowing status
means there has been no flow through the FMP for at least 30
consecutive days. Non-flowing status does not apply to meters at FMPs
that flow intermittently on a daily or weekly basis.
(b) Notice of spot samples. The lessee must provide the
Superintendent with at least 72 hours' advance notice before obtaining
a spot sample or submit a monthly or quarterly sampling schedule to the
Superintendent in advance of taking samples.
(c) Sample cylinder requirements. Sample cylinders must:
(1) Comply with the requirements set forth in Subsection 9.1 of API
14.1 (incorporated by reference, see Sec. 226.0);
(2) Have a minimum capacity of 300 cubic centimeters; and
[[Page 2489]]
(3) Be cleaned prior to sampling in accordance with Appendix A of
GPA 2166-17 (incorporated by reference, see Sec. 226.0) or an
equivalent method. The lessee must maintain documentation of cleaning,
have the documentation on-site during sampling, and provide the
documentation to the Superintendent upon request.
(d) Spot sampling using portable gas chromatographs. (1) If used,
sampling separators must be:
(i) Constructed of stainless steel;
(ii) Cleaned prior to sampling in accordance with Appendix A of GPA
2166-17 (incorporated by reference, see Sec. 226.0) or an equivalent
method. The lessee must maintain documentation of cleaning, have the
documentation on-site during sampling, and provide the documentation to
the Superintendent upon request; and
(iii) Operated under Appendix B.3 of GPA 2166-17 (incorporated by
reference, see Sec. 226.0).
(2) The sample port and inlet to the sample line must be purged
using the gas being sampled before completing the connection between
them.
(3) The portable gas chromatograph must be operated, verified, and
calibrated as set forth in Sec. 226.136 and documentation of such
verification and calibration must be available for inspection by the
Superintendent at the time of sampling.
(4) The documentation of verification or calibration required in
Sec. 226.136(e) must be available for the Superintendent's inspection
at the time of sampling.
(5) The minimum number of samples and analyses is as follows:
(i) For low-volume and very-low-volume FMPs, at least three samples
must be taken and analyzed;
(ii) For high-volume FMPs, samples must be taken and analyzed until
the difference between the maximum and minimum heating values
calculated based on three consecutive analyses is less than or equal to
16 Btu/scf; and
(iii) For very-high-volume FMPs, samples must be taken and analyzed
until the difference between the maximum and minimum heating values
calculated based on three consecutive analyses is less than or equal to
8 Btu/scf.
(6) Unless the Superintendent approves an alternative method of
calculation, the heating value and relative density used for reporting
to ONRR must be either the mean or median heating value and relative
density calculated from the three analyses required in paragraph (d)(5)
of this section.
Sec. 226.132 Spot samples--allowable methods.
(a) Spot samples must be obtained using one of the following
methods:
(1) Purging--fill and empty method. Samples taken using this method
must comply with the requirements set forth in Section 9.1 of GPA 2166-
17 (incorporated by reference, see Sec. 226.0);
(2) Helium ``pop'' method. Samples taken using this method must
comply with the requirements set forth in Section 9.5 of GPA 2166-17
(incorporated by reference, see Sec. 226.0). The lessee must maintain
documentation demonstrating that the cylinder was evacuated and pre-
charged before sampling and make such documentation available to the
Superintendent upon request;
(3) Floating piston cylinder method. Samples taken using this
method must comply with the requirements set forth in Sections 9.7.1
and 9.7.3 of GPA 2166-17 (incorporated by reference, see Sec. 226.0).
The lessee must maintain documentation of the seal material and type of
lubricant used and make such documentation available to the
Superintendent upon request;
(4) Portable gas chromatograph. Samples taken using this method
must comply with Sec. 226.136; or
(5) Alternative methods. Other methods the Superintendent approves.
(b) If the lessee uses the sampling methods in paragraph (a)(1) or
(2) of this section and the flowing pressure at the sample port is less
than or equal to 15 psig, the lessee may also employ a vacuum gathering
system. Samples taken using a vacuum-gathering system must comply with
the requirements set forth in Subsection 11.10 of API 14.1
(incorporated by reference, see Sec. 226.0) and the samples must be
obtained from the discharge of the vacuum pump.
Sec. 226.133 Spot samples--frequency.
(a) Spot samples must be taken and analyzed at the following
frequencies:
(1) Once every 12 months for very-low-volume FMPs;
(2) Once every 6 months for low-volume FMPs;
(3) One every 3 months for high-volume FMPs; and
(4) Once a month for very-high-volume FMPs.
(b) The Superintendent may change the required sampling frequency
for high- and very-high-volume FMPs if a determination is made that the
frequency under paragraph (a) of this section does not achieve the
heating value uncertainty levels required in Sec. 226.120(b).
(1) The Superintendent may change the sampling frequency no sooner
than [two years from effective date of final rule].
(2) The new sampling frequency will remain in effect until the
heating value variability justifies a different frequency.
(3) The Superintendent may not change the sampling frequency to
more than once every two weeks or less than once every six months.
(c) The time between any two spot samples must not exceed:
(1) 18 calendar days, if the required sampling frequency is every
two weeks;
(2) 45 calendar days, if the required sampling frequency is once a
month;
(3) 105 calendar days, if the required sampling frequency is once
every 3 months;
(4) 195 calendar days, if the required sampling frequency is once
every 6 months; and
(5) 380 calendar days, if the required sampling frequency is once
every 12 months.
Sec. 226.134 Composite sampling methods.
(a) Composite samplers must be flow-proportional.
(b) Samples must be collected using a positive-displacement pump.
(c) Sample cylinders must be sized to ensure the cylinder capacity
is not exceeded within the normal collection frequency.
Sec. 226.135 On-line gas chromatographs.
(a) On-line gas chromatographs must be installed, operated, and
maintained in accordance with, Appendix D of GPA 2166-17 (incorporated
by reference, see Sec. 226.0), and the manufacturer's specifications,
instructions, and recommendations.
(b) On-line gas chromatographs must comply with the verification
and calibration requirements set forth in Sec. 226.136. The lessee
must maintain documentation of verifications and calibrations and make
such documentation available to the Superintendent upon request.
Sec. 226.136 Gas chromatographs.
(a) All gas chromatographs must be installed, operated, and
calibrated in accordance with GPA 2261-20 (incorporated by reference,
see Sec. 226.0).
(b) Gas chromatographs must be verified under the requirements in
paragraph (c) of this section not less than once every seven calendar
days.
(c) Verifications must be performed in accordance with 2261-20
(incorporated by reference, see Sec. 226.0), with the following
additions and clarifications:
(1) All gases used for verification and calibration must meet the
standards of Sections 3 and 4 of GPA 2198-16 (incorporated by
reference, see Sec. 226.0);
[[Page 2490]]
(2) All new gases used for verification and calibration must be
authenticated prior to verification or calibration in accordance with
Section 6 of GPA 2198-16 (incorporated by reference, see Sec. 226.0);
(3) The gas used to calibrate a gas chromatograph must be
maintained in accordance with Section 5 of GPA 2198-16 (incorporated by
reference, see Sec. 226.0);
(4) If the composition of the gas used for verification as
determined by the gas chromatograph varies from the certified
composition of the gas used for verification by more than the
reproducibility values in Section 10 of GPA 2261-20, the gas
chromatograph must be calibrated in accordance with Section 6 of GPA
2261-20 (both incorporated by reference, see Sec. 226.0); and
(5) If the gas chromatograph is calibrated, it must be re-verified
under paragraph (c)(4) of this section.
(d) Samples must be analyzed until the un-normalized sum of the
mole percent of all gases analyzed is between 97 and 103 percent.
(e) The lessee must retain documentation of the verifications and
make such documentation available to the Superintendent upon request.
The documentation must include:
(1) The components analyzed;
(2) The response factor for each component;
(3) The peak area for each component;
(4) The mole percent of each component as determined by the gas
chromatograph;
(5) The mole percent of each component in the gas used for
verification;
(6) The difference between the mole percentages determined in
paragraphs (e)(4) and (5) of this section, expressed in relative
percent;
(7) Evidence that the gas used for verification and calibration:
(i) Meets the requirements of paragraph (c)(2) of this section,
including a unique identification number of the calibration gas used,
the name of the supplier of the calibration gas, and the certified list
of the mole percent of each component in the calibration gas;
(ii) Was authenticated under paragraph (c)(3) of this section prior
to verification or calibration, including the fidelity plots; and
(iii) Was maintained under paragraph (c)(4) of this section,
including the fidelity plot made as part of the calibration run;
(8) The chromatograms generated during the verification process;
(9) The time and date the verification was performed; and
(10) The name and affiliation of the person performing the
verification.
Sec. 226.137 Components to analyze.
(a) Low- and very-low-volume FMPs are exempt from the standards and
requirements set forth in paragraphs (c), (d), and (e) of this section.
(b) Gas must be analyzed for the following components:
(1) Methane;
(2) Ethane;
(3) Propane;
(4) Isobutane;
(5) Normal Butane;
(6) Pentanes;
(7) Hexanes + (C6+);
(8) Carbon dioxide; and
(9) Nitrogen.
(c) When the concentration of C6+ exceeds 0.5 mole
percent, hexanes, heptanes, octanes, and Nonanes-plus (C9+)
must also be analyzed.
(d) In lieu of testing each sample for the components required
under paragraph (c) of this section, the lessee may periodically test
for these components and adjust the assumed C6+ composition
to remove bias in the heating value. The adjusted C6+
composition must be applied to the mole percent of C6+
analyses until the next analysis is done under paragraph (c) of this
section.
(e) The minimum analysis frequency for components listed in
paragraph (c) of this section is:
(1) Once every 12 months, for high-volume FMPs; and
(2) Once every 6 months, for very-high-volume FMPs.
Sec. 226.138 Gas analysis report requirements.
(a) The gas analysis report must contain the following information:
(1) The lessee's name;
(2) The lease number;
(3) The well or facility name and number;
(4) The date and time the sample or spot samples were taken or, for
composite samples, the date the cylinder was installed and date it was
removed;
(5) The date and time of the analysis;
(6) For spot samples, the effective date, if other than the date of
sampling;
(7) For composite samples, the effective start and end dates;
(8) The name of the laboratory where the analysis was performed, if
applicable;
(9) The device used for analysis (i.e., gas chromatograph,
calorimeter, or mass spectrometer);
(10) The make and model of the analyzer;
(11) The date of the last verification or calibration of the
analyzer;
(12) The flowing temperature at the time of sampling;
(13) The flowing pressure at the time of sampling, including units
of measure (psia or psig);
(14) The flow rate at the time of sampling;
(15) The ambient air temperature at the time of sampling;
(16) Whether or not heat trace or any other method of heating was
used;
(17) The type of sample (i.e., spot-cylinder, spot-portable gas
chromatograph, composite);
(18) The sampling method if spot-cylinder (e.g., fill and empty,
helium pop);
(19) A list of the components tested;
(20) The total un-normalized mole percent of the components tested;
(21) The normalized mole percent of each component tested,
including a summation of those mole percentages;
(22) The ideal heating value (Btu/scf);
(23) The real heating value (Btu/scf), dry basis;
(24) The hexanes-plus heating value (Btu/scf), if applicable;
(25) The pressure base and temperature base;
(26) The relative density; and
(27) The name of company obtaining the gas sample.
(b) Components that are listed on the analysis report but are not
tested must be annotated as such.
(c) The heating value and relative density must be calculated using
API 14.5 (incorporated by reference, see Sec. 226.0).
(d) The base supercompressibility must be calculated using AGA
Report No. 8 (incorporated by reference, see Sec. 226.0).
(e) The lessee must submit all gas analysis reports to the
Superintendent within 14 calendar days after the due date for the
sample as specified in Sec. 226.133.
Sec. 226.139 Effective date of a spot or composite gas sample.
(a) Unless otherwise specified in the gas analysis report, the
effective date of a spot sample is the date on which the sample was
taken. The effective date of a spot sample may be no later than the
first day of the production month following the lessee's receipt of the
laboratory analysis of the sample.
(b) Unless otherwise specified in the gas analysis report, the
effective date of a composite sample is the first day of the month in
which the sample was removed.
Sec. 226.140 Calculation of heating value and volume.
(a) Heating value of sample. The heating value of gas sampled must
be calculated as follows:
[[Page 2491]]
(1) Gross heating value is defined in Subsection 3.7 of API 14.5,
and must be calculated using Subsection 7.1 of API 14.5 (incorporated
by reference, see Sec. 226.0); and
(2) Real heating value must be calculated by dividing the gross
heating value of the gas calculated under paragraph (a)(1) of this
section by the compressibility factor of the gas at 14.73 psia and 60
[deg]F.
(b) Average heating value. (1) If a lease has more than one FMP,
the average heating value for the lease for a reporting month must be
the volume-weighted average of heating values, calculated as follows:
[GRAPHIC] [TIFF OMITTED] TP13JA23.011
Where:
HV = the average heating value for the lease for the reporting
month, in Btu/scf
HVi = the heating value for FMPi during the reporting
month (see Sec. 226.140(a)(2), if an FMP has multiple heating
values during the reporting month), in Btu/scf
Vi = the volume measured by FMPi during the reporting month, in Btu/
scf
i = each FMP for the lease
n = the number of FMPs for the lease
(2) If the effective date of a heating value for an FMP is other
than the first day of the reporting month, the average heating value of
the FMP must be the volume-weighted average of heating values,
determined as follows:
[GRAPHIC] [TIFF OMITTED] TP13JA23.012
Where:
HVi = the heating value for FMPi, in Btu/scf
HVi,j = the heating value for FMPi, for partial month j,
in Btu/scf
Vi,j = the volume measured by FMPi, for partial month j,
in Btu/scf
i = represents each FMP for the lease
j = represents a partial month for which heating value HVi,j is
effective
m = the number of different heating values in a reporting month for
an FMP
(c) Calculation of volume. The volume must be determined under
Sec. 226.124(b) and (c) (mechanical recorders) or Sec. 226.125(c)
(electronic gas measurement systems).
Sec. 226.141 Reporting of heating value and volume.
(a) Reported gross and real heating values. The gross heating value
and real heating value, or average gross heating value and average real
heating value, as applicable, derived from all samples and analyses
must be reported to ONRR in units of Btu/scf under the following
conditions:
(1) Containing no water vapor (``dry''), unless the water vapor
content has been determined through actual on-site measurement,
included in heating value calculations, and reported on the gas
analysis report. The heating value may not be reported based on assumed
water vapor content. Acceptable methods of measuring water vapor are
chilled mirror and other methods the Superintendent approves;
(2) Adjusted to a pressure of 14.73 psia and a temperature of 60
[deg]F; and
(3) For samples analyzed under Sec. 226.137(a), notwithstanding
any provision of a contract between the lessee and purchaser or
transporter, the composition of hexanes + must have a heating value of
not less than:
(i) 5,129 Btu/scf (equivalent heating value of 60 percent hexanes,
30 percent heptanes, and 10 percent octanes); or
(ii) The heating value of the C9+ composition determined
under Sec. 226.137(c).
(b) Reported volume. The volume for royalty purposes must be
reported to ONRR in units Mcf, as follows:
(1) The volume must not be adjusted for water-vapor content or any
other factors that are not included in calculations required in Sec.
226.124(b) and (c) or Sec. 226.127; and
(2) The volume must match the monthly volume(s) shown in the
unedited QTR(s) or integration statement(s) unless edits to the data
are documented under paragraph (c) of this section.
(c) Edits and adjustments to reported heating value or volume. (1)
If there are measurement errors stemming from an equipment malfunction
that results in discrepancies in the calculated heating value or volume
of the gas, the heating value or volume reported during the period in
which the error persisted must be estimated.
(2) All edits made to the data before the report is submitted to
ONRR must be documented and include verifiable justifications for the
edits made. Such documentation must be available to the Superintendent
and ONRR upon request.
(3) All values on daily and hourly QTRs that have been changed or
edited must be clearly identified and cross referenced to the
justification required in paragraph (c)(2) of this section.
(4) The volumes reported to ONRR must be corrected beginning with
the date that the inaccuracy occurred. If the date is unknown, the
volumes must be corrected beginning with the production month that
includes the date that is halfway between the date of the previous
verification and the date of the most recent verification. Corrected
reports must be submitted to ONRR within 30 calendar days of discovery
of the error in the reported volumes.
Subpart L--Tribal and Royalty-Free Use of Production
Tribal Use of Gas Production
Sec. 226.142 Use of gas by the Osage Nation and Tribe members.
(a) Gas from any well must be furnished to any Tribally-owned
building or enterprise at a rate not to exceed the rate set forth in
Sec. 226.40, subject to the Superintendent's determination that the
lease is producing gas in excess of the lessee's requirements for
operations and that no waste will result. The Osage Nation must furnish
all labor and materials necessary for connection with the lessee's gas
system. The Osage Nation uses gas under this section at its own risk.
(b) Any member of the Osage Nation who resides in Osage County
outside of an incorporated city is entitled to use a maximum of 400,000
cubic feet of gas per calendar year for their primary residence at a
rate not to exceed the rate set forth in Sec. 226.40, subject to the
Superintendent's determination that the lease is producing gas in
excess of the lessee's requirements and that no waste will result. The
Tribe member must furnish all labor and materials necessary for
connection with the lessee's gas system and must maintain their own
lines. Tribal members use gas under this section at their own risk.
(c) The lessee may not stop furnishing gas pursuant to paragraphs
(a) and (b) of this section without Superintendent's approval. To
obtain such approval, the lessee must submit a request to the
Superintendent, in writing, providing justification for terminating the
Tribe member's use of gas from the lessee's well.
Sec. 226.143 Royalty on gas furnished for Tribal use.
The lessee must pay royalty on all gas furnished to Tribally owned
buildings and enterprises and Tribe members in accordance with
Sec. Sec. 226.39 and 226.40.
[[Page 2492]]
Royalty-Free Use of Lease Production
Sec. 226.144 Production on which no royalty is due.
To the extent specified in Sec. Sec. 226.145 and 226.146, royalty
is not due on:
(a) Oil and gas produced from a lease and used for operations or
production purposes (including placing the oil and gas in marketable
condition) on the same lease without being removed therefrom; or
(b) Oil and gas produced from a unit and used for operations or
production purposes (including placing the oil and gas in marketable
condition) on the same unit, under the same cooperative agreement,
without being removed therefrom.
Sec. 226.145 Uses of production on a lease or unit that do not
require the Superintendent's prior approval of royalty-free treatment.
(a) The following uses of oil and gas for operations or production
purposes do not require the Superintendent's prior approval to be
royalty-free:
(1) Use of fuel to generate power or operate combined heat and
power;
(2) Use of fuel to power equipment, including artificial lift
equipment, equipment used for enhanced recovery, drilling rigs, and
completion and workover equipment;
(3) Use of gas to actuate pneumatic controllers or operate
pneumatic pumps at production facilities;
(4) Use of fuel to heat, separate, or dehydrate production;
(5) Use of gas as a pilot fuel or as assist gas for a flare,
combustor, thermal oxidizer, or other control device;
(6) Use of fuel to compress or treat gas to place it in marketable
condition;
(7) Use of oil to clean the well and improve production (e.g., hot
oil treatments). The lessee must document removal of the oil from the
tank or pipeline in accordance with Sec. 226.99;
(8) Use of oil as a circulating medium in drilling operations if
such use is part of an approved drilling plan;
(9) Injection of gas for the purpose of conserving gas or
increasing the recovery of oil or gas if the Superintendent ordered or
approved such injection; and
(10) Injection of gas that is cycled in a contained gas-lift
system.
(b) The volumes of oil and gas treated as royalty-free under this
section must not exceed the amount of fuel necessary to perform the
operation using equipment of appropriate capacity.
Sec. 226.146 Uses of production on a lease or unit that require the
Superintendent's prior approval of royalty-free treatment.
(a) The following uses of oil and gas for operations or production
purposes require the Superintendent's prior approval of royalty-free
treatment to ensure that accountability is maintained:
(1) Use of oil or gas the lessee removes from the pipeline at a
location downstream of the FMP;
(2) Use of gas that has been removed from the lease or unit for
treatment or processing because the physical characteristics of the gas
require it to be treated or processed prior to use, where the gas is
returned to, and used on, the same lease or unit from which it was
produced; and
(3) Any other uses of produced oil and gas for operations and
production purposes that are not set forth in Sec. 226.145.
(b) The lessee must submit a request to conduct activities under
paragraph (a) of this section to the Superintendent, in writing, to
obtain approval of royalty-free treatment for the volumes of oil and
gas used. Such request must include the information required by Sec.
226.151. If the Superintendent approves a request for royalty-free
treatment under this section, the effective date of such approval will
be the date the Superintendent received the lessee's request. If the
Superintendent denies a request for royalty-free treatment under this
section, the lessee must pay royalties on all volumes utilized to
conduct activities under paragraph (a) of this section.
(c) The lessee must measure the volumes of oil and gas used to
conduct activities under paragraph (a)(1) of this section in accordance
with subparts J and K, as applicable. The lessee must measure the
volume of gas returned to the lease or unit following removal under
paragraph (a)(2) of this section in accordance with subpart K.
Sec. 226.147 Uses of production moved off the lease or unit that do
not require the Superintendent's prior approval of royalty-free
treatment.
Oil and gas moved off the lease or unit may be treated as royalty-
free without the Superintendent's prior approval if the use meets the
criteria in Sec. 226.145 and:
(a) The oil or gas is transported from one area of the lease or
unit to be used at another area of the same lease or unit and no oil or
gas is added to, or removed from, the pipeline while crossing lands
that are not part of the lease or unit from which the oil or gas was
produced; or
(b) A well is directionally drilled, the wellhead is not located on
the producing lease or unit, and the oil or gas is being used on the
same well pad for operations or production purposes for that well.
Sec. 226.148 Uses of production moved off the lease or unit that
require the Superintendent's prior approval of royalty-free treatment.
(a) Except as provided in Sec. 226.147(b) and paragraph (b) of
this section, royalty is owed on all oil and gas used in operations
conducted off the lease or unit from which it is produced.
(b) The Superintendent may grant prior approval of royalty-free
treatment of oil or gas used in operations conducted off the lease or
unit if the:
(1) Use is among those listed in Sec. Sec. 226.145(a) or
226.146(a);
(2) Equipment or facility in which the operation is conducted is
located off the lease or unit for engineering, economic, resource
protection, or physical accessibility reasons; and
(3) Operations are conducted upstream of the FMP.
(c) The lessee must submit a request to the Superintendent, in
writing, to obtain approval of royalty-free treatment of the volumes of
oil and gas used. Such request must comply with the requirements set
forth in Sec. 226.151. If the Superintendent approves a request for
royalty-free treatment under this section, the effective date of such
approval will be the date the Superintendent received the lessee's
request. If the Superintendent denies a request for royalty-free
treatment under this section, the lessee must pay royalties on all
volumes used.
(d) If equipment or a facility located on a particular lease treats
oil or gas produced from the lease as well as oil or gas produced from
properties that are not unitized with the lease, the lessee may only
report as royalty-free that portion of the oil or gas used as fuel that
is properly allocated to the share of production contributed by the
lease or unit upon which the equipment or facility is located.
Sec. 226.149 Measurement or estimation of royalty-free volumes of oil
or gas.
(a) The lessee must measure or estimate the volumes of royalty-free
gas used upstream of the FMP.
(b) The lessee must measure the volume of gas that is removed from
the product stream downstream of the FMP and used royalty-free pursuant
to Sec. Sec. 226.145 through 226.148.
(c) The lessee must measure the volume of oil that is used royalty-
free pursuant to Sec. Sec. 226.145 through 226.148. The lessee must
also document the removal of such oil from the tank or pipeline.
(d) If the lessee removes oil or gas downstream of the FMP and it
is used
[[Page 2493]]
royalty-free pursuant to Sec. Sec. 226.145 through 226.148, the lessee
must notify the Superintendent, in writing, and obtain an approved FMP
under Sec. 226.86 to measure the production removed for use.
(e) The lessee must use the best available information when
estimating gas volumes.
(f) The lessee must report each of the volumes required to be
measured or estimated under this subpart to ONRR in accordance with
Sec. Sec. 226.45 and 226.87.
Sec. 226.150 Ownership of equipment and facilities.
The lessee is not required to own or lease the equipment or
facility that uses oil or gas royalty-free under this subpart. The
lessee is responsible for obtaining required authorizations, measuring
and reporting production, and all other applicable requirements.
Sec. 226.151 Requesting approval of royalty-free treatment for
volumes used.
The lessee must submit a request to the Superintendent, in writing,
for approval of royalty-free use of production under this subpart. Such
requests must include the following information:
(a) A complete description of the operation to be conducted,
including the location of all equipment and facilities involved in the
operation and the location of the FMP;
(b) The volumes of oil and gas the lessee expects will be used to
conduct the operation and the method used to measure or estimate such
volumes;
(c) If the volume of gas expected to be used is estimated, the
basis for the estimate (e.g., equipment manufacturer's published
consumption or usage rates); and
(d) The proposed disposition of the oil and gas used (e.g., whether
gas used would be consumed as fuel, vented through use of a gas-
activated pneumatic controller, returned to the reservoir, or used in
some other way).
Subpart M--Venting and Flaring
Sec. 226.152 General requirements.
(a) No venting or flaring of gas is permitted without the
Superintendent's prior approval, except as defined in Sec. 226.156.
(b) The lessee must notify the Superintendent by email or facsimile
at least three business days prior to conducting approved venting or
flaring operations.
(c) For purposes of this subpart, all flares or combustible devices
must be equipped with an automatic ignition system.
Sec. 226.153 Gas-well gas.
Gas-well gas may not be vented or flared except where it is
unavoidably lost under Sec. 226.91(c).
Sec. 226.154 Oil-well gas.
Oil-well gas may be vented or flared in accordance with Sec. Sec.
226.155, 226.156, and 226.157.
Sec. 226.155 Limitations on venting gas.
(a) The lessee must flare, rather than vent, any gas that is not
captured, except when:
(1) Flaring the gas is technically infeasible, such as when the gas
is not readily combustible, or the volumes are too small to flare;
(2) There are emergency conditions, as defined in Sec. 226.156(d),
and the loss of gas is uncontrollable, or venting is necessary for
safety reasons;
(3) Gas is vented through normal operations of a natural gas-
activated pneumatic controller or pump;
(4) Gas vapor is vented from a storage tank or other low-pressure
production vessel, unless the Superintendent determined that recovery
of the gas vapors is warranted;
(5) Gas is vented during downhole well maintenance or liquids
unloading activities;
(6) Venting is necessary to allow the performance of non-routine
facility and pipeline maintenance, such as when the lessee must
occasionally blow-down and depressurize equipment to perform
maintenance or repairs; or
(7) A release of gas is unavoidable under Sec. 226.91(c) and
flaring is prohibited by Federal law.
(b) Venting of gas that has an H2S content of 100 ppm or
greater is prohibited.
Sec. 225.156 Authorized venting and flaring of gas.
(a) Initial production testing. Gas flared during the initial
production test of each completed interval in a well is royalty-free
until one of the following occurs:
(1) The lessee obtains adequate reservoir information;
(2) It has been 30 calendar days since the beginning of the
production test, unless the Superintendent approves a longer test
period; or
(3) The lessee has flared 50 MMcf of gas.
(b) Subsequent well tests. Gas flared during well tests after the
initial production test is royalty-free for a period not to exceed 24
hours unless the Superintendent approves or requires a longer test
period.
(c) Downhole well maintenance and liquids unloading. Gas vented
during downhole well maintenance and well purging is royalty-free for a
period not to exceed 24 hours per event, provided that the requirements
in paragraphs (c)(1) through (3) of this section are met. Gas vented
from a plunger lift system or automated well control system is royalty-
free, provided that the requirements in paragraphs (c)(1) and (2) of
this section are met. For purposes of this section, ``well purging''
means blowing accumulated liquids out of a wellbore using reservoir gas
pressure, whether manually or by an automatic control system that
relies on real-time pressure or flow, times, or other well data, where
gas is vented to the atmosphere. The term ``well purging'' does not
apply to wells equipped with plunger lift systems.
(1) The lessee must minimize the loss of gas associated with
downhole well maintenance and liquids unloading consistent with safe
operations.
(2) For wells equipped with a plunger lift system or automated well
control system, minimizing the loss of gas under paragraph (c)(1) of
this section includes optimizing operation of the system to minimize
gas losses to the maximum extent possible, consistent with removing
liquids that would inhibit proper function of the well.
(3) For any liquids unloading by manual well purging, the lessee
must ensure that the person conducting the well purging remains on-site
throughout the operation so he can end the operation as soon as
practical, thereby minimizing venting to the atmosphere to the maximum
extent possible.
(d) Emergencies. (1) Gas vented or flared during an emergency is
royalty-free for a period not to exceed 24 hours, unless the
Superintendent determines that emergency conditions exist that
necessitate venting or flaring for a longer period.
(2) For purposes of this subpart, an ``emergency'' is a temporary,
infrequent, and unavoidable situation in which the loss of oil or gas
is uncontrollable or necessary to avoid the risk of immediate and
substantial adverse impacts on public health, safety, or the
environment and that is not the result of lessee negligence or non-
compliance.
(3) The following do not constitute emergencies for the purpose of
royalty assessment:
(i) Failure to install appropriate equipment with sufficient
capacity to accommodate the production conditions;
(ii) Failure to limit production when the production rate exceeds
the capacity of the necessary equipment, pipeline, or gas plant or
exceeds sales contract volumes of oil or gas;
[[Page 2494]]
(iii) Scheduled maintenance;
(iv) Situations caused by lessee negligence or non-compliance,
including equipment failures; and
(v) Situations on a lease or unit that has experienced three or
more emergencies within the past 30 days unless the Superintendent
determines that the occurrence of such emergencies within the 30-day
period could not have been anticipated and was beyond the lessee's
control.
(4) The lessee must notify the Superintendent of all emergencies in
writing, by email or facsimile, immediately upon discovery, but not
later than the next calendar day.
(5) The lessee must estimate and report the volumes vented or
flared beyond the timeframe specified in paragraph (c)(1) of this
section within 45 calendar days of the date the emergency started.
Sec. 226.157 Measurement and reporting of volumes of gas vented or
flared.
(a) The lessee must estimate or measure all volumes of oil and gas
avoidably and unavoidably lost from wells, facilities, and equipment on
a lease or unit and report such volumes to ONRR in accordance with
Sec. Sec. 226.45 and 226.87.
(b) The lessee may:
(1) Estimate the volume of gas vented or flared based on the
results of a regularly performed GOR test and measured values for the
volumes of oil production and gas sales to allow the Superintendent to
independently verify the volume, rate, and heating value of the flared
gas; or
(2) Measure the volume of the flared gas.
(c) The Superintendent may require the installation of additional
measurement equipment whenever it is determined that the existing
methods are inadequate to meet the purposes of this subpart.
(d) The lessee may combine gas from multiple leases or units for
the purpose of venting or flaring at a common point but must allocate
the quantities of the vented or flared gas to each lease or unit using
a method the Superintendent approves.
Subpart N--Assessments and Penalties
Lease Management Assessments and Civil Penalties
Sec. 226.158 Remedies for violations of lease or permit terms and
conditions, regulations, orders, and notices.
Violation of, or non-compliance with, the terms and conditions of
any lease or permit, the regulations in this part, or orders and
notices the Superintendent issues, may result in:
(a) Assessments;
(b) Civil penalties for each day such violation continues;
(c) Shut-in action; and
(d) Cancellation of the lease or permit and bond forfeiture.
Sec. 226.159 Immediate assessments for violations of certain
operating regulations.
The Superintendent will issue immediate assessments upon discovery
of the violations identified in Table 1. Assessments will be issued in
the specified amounts per violation, per inspection. Imposition of
these assessments does not preclude other appropriate enforcement
action and civil penalties.
Table 1 to Sec. 226.159--Violations Subject to an Immediate Assessment
------------------------------------------------------------------------
Assessment
Violation amount per
violation ($)
------------------------------------------------------------------------
1. Failure to post signs and install flags and wind $250
indicators as required by Sec. 226.70(d)(4) through
(8)....................................................
2. Failure to properly identify wells, tanks, and 250
facilities as required by Sec. 226.75................
3. Failure to seal an appropriate valve on an oil 1,000
storage tank as required by Sec. 226.94..............
4. Failure to seal an appropriate valve or component on 1,000
an oil metering system as required by Sec. 226.95....
5. Failure to properly measure oil before removal from 1,000
storage for use on a different lease or unit as
required by Sec. 226.99(b)...........................
6. Failure to retain records necessary to determine the 1,000
quality and quantity of production as required by Sec.
226.88................................................
7. Missing or non-functioning FMP LACT system components 1,000
as required by Sec. 226.110..........................
8. Missing or non-functioning FMP CMS components as 1,000
required by Sec. 226.111.............................
9. Failure to meet the proving frequency requirements 1,000
for an FMP as set forth in Sec. 226.113..............
10. Failure to obtain the Superintendent's approval 1,000
prior to using any oil measurement method other than
tank gauging, LACT system, or CMS at an FMP as required
by Sec. 226.115......................................
11. Failure to conduct new FMP orifice plate inspections 1,000
as required by Sec. 226.121(c).......................
12. Failure to conduct routine FMP orifice plate 1,000
inspections as required by Sec. 226.121(d)...........
13. Failure to conduct basic meter-tube inspections as 1,000
required by Sec. 226.121(g)..........................
14. Failure to conduct detailed meter-tube inspections 1,000
as required by Sec. 226.121(h).......................
15. Failure to conduct an initial mechanical recorder 1,000
verification as required by Sec. 226.123(a)..........
16. Failure to conduct routine mechanical recorder 1,000
verifications as required by Sec. 226.123(b).........
17. Failure to conduct an initial EGM system 1,000
verification as a required by Sec. 226.126(a)........
18. Failure to conduct routine EGM system verifications 1,000
as required by Sec. 226.126(b).......................
19. Failure to take spot samples for FMPs as required by 1,000
Sec. 226.133.........................................
20. Failure to construct and maintain pits as required 2,500
by Sec. 226.77.......................................
21. Failure to install and maintain H2S detection 2,500
equipment as required by Sec. 226.70(d)(2)...........
------------------------------------------------------------------------
Sec. 226.160 Other assessments.
If a lessee fails to commence or perform an operation within five
calendar days after the Superintendent orders such operation in
writing, or such other time as may be specified in the order, the
Superintendent may enter upon the lease and perform the operation, or
have a third-party perform the operation, at the sole risk and expense
of the lessee. The Superintendent will issue an assessment for the
actual cost of performance plus an additional 25 percent of such amount
for all operations performed by or through the Superintendent due to
the lessee's non-compliance.
Sec. 226.161 Civil penalties with a period to correct.
(a) If a lessee or permittee violates the terms and conditions of
the lease or permit, the regulations in this part, or
[[Page 2495]]
orders and notices the Superintendent issues, the Superintendent may
issue a NONC informing the lessee or permittee of the violation and
specifying what actions, if any, must be taken to correct the non-
compliance and avoid the assessment of civil penalties and cancellation
of the lease or permit. Upon completion of the required corrective
actions, the lessee must submit a Self-Certification for Correction of
Lease Violations form to the Superintendent.
(b) If the violation is corrected within 20 calendar days of the
NONC, or such longer period for correction specified in the NONC, the
Superintendent will not assess a civil penalty or cancel the lease or
permit but will consider the violations part of the lessee's or
permittee's history of non-compliance for future penalty assessments.
(c) If the violation is not corrected within 20 calendar days of
the NONC, or such longer period for correction specified in the NONC,
the lessee or permittee will be liable for a civil penalty of up to
$1,198 per violation for each day such violation continues, commencing
with the date of the NONC.
(d) If the violation is not corrected within 40 calendar days of
the notice, or such longer period for correction specified in the NONC,
the lessee or permittee will be liable for a civil penalty of up to
$11,995 per violation for each day such violation continues, commencing
with the date of the NONC.
(e) If the Superintendent agrees to an extension of the time to
take corrective action exceeding 20 calendar days, the date of the NONC
will be deemed to be 20 calendar days prior to the end of the extended
period for the purpose of civil penalty calculation.
(f) Any amount imposed and paid as assessments under Sec. 226.159
will be deducted from penalties under this section.
Sec. 226.162 Civil penalties without a period to correct.
(a) The Superintendent may assess civil penalties for the
violations identified in paragraphs (b) and (c) of this section without
prior notice or an opportunity to correct the violation. The
Superintendent will inform lessees, permittees, and other persons of
violations resulting in civil penalties without a period to correct by
issuing an ILCP identifying the violation and the amount of the civil
penalty. For purposes of this section, civil penalties begin to accrue
on the day the violation is committed.
(b) Any person is liable for a civil penalty of up to $23,989 per
violation for each day such violation continues, if such person:
(1) Fails or refuses to permit the Superintendent's lawful entry or
inspection pursuant to Sec. 226.60; or
(2) Knowingly or willfully commences drilling, recompletion, or
reentry operations, or causes surface disturbance preliminary thereto,
without the Superintendent's prior approval in accordance with Sec.
226.61.
(c) Any person is liable for a civil penalty of up to $59,973 per
violation for each day such violation continues, if such person:
(1) Knowingly or willfully prepares, maintains, or submits false,
inaccurate, or misleading reports, notices, affidavits, records, data,
or other documents and information required by this part;
(2) Knowingly or willfully removes, transports, uses, or diverts
any oil or gas from any lease or unit without valid legal authority to
do so;
(3) Tampers with or bypasses any measurement device, component of a
measurement device, or the measurement process;
(4) Purchases, accepts, sells, transports, or conveys oil or gas to
any other person knowing or having reason to know that such oil or gas
was stolen or unlawfully removed or diverted from a lease or unit of
the Osage Mineral Estate.
Sec. 226.163 Penalty amount.
(a) The Superintendent will determine the amount of the penalty to
assess by considering:
(1) The severity of the violation; and
(2) The lessee's or permittee's history of non-compliance.
(b) The Superintendent may compromise or reduce a civil penalty
assessed under this subpart.
Sec. 226.164 Shut-in actions.
(a) The Superintendent may take immediate shut-in action, without
notice, when necessary for compliance; when operations are commenced or
conducted without the required approval; or where continued operations
could result in immediate adverse impacts on public health and safety,
natural resources, the environment, production accountability, or
royalty income.
(b) The Superintendent may take shut-in action in situations other
than those identified in paragraph (a) of this section only after
providing written notice to the lessee or permittee.
Sec. 226.165 Lease or permit cancellation.
(a) The Superintendent may issue a Notice of Cancellation for a
lease or permit if a lessee or permittee:
(1) Is determined to have obtained the lease or permit by
collusion, fraud, or misrepresentation;
(2) Fails to comply with the terms and conditions of the lease or
permit, the regulations in this part, or other applicable laws;
(3) Fails to timely comply with, or respond to, an order or notice
the Superintendent or ONRR issues;
(4) Fails to timely correct a violation under Sec. 226.161;
(5) Fails to pay civil penalties in full on or before the date the
Superintendent or ONRR specifies;
(6) Knowingly and willfully commits a violation that results in
immediate adverse impacts on public health and safety, natural
resources, or the environment, production accountability, or royalty
income; or
(7) Has a history of non-compliance.
(b) The Notice of Cancellation will inform the lessee or permittee
of the violation, set forth the reasons why cancellation is warranted,
and specify what actions, if any, may be taken to avoid cancellation of
the lease or permit and bond forfeiture.
(c) Cancellation of a lease or permit does not relieve the lessee
or permittee of any continuing obligations under the lease, permit, or
regulations in this part.
(d) Upon cancellation of a lease, the Osage Minerals Council may
take immediate possession of the leased lands and all permanent
improvements and surface equipment necessary for operation of the
lease.
Sec. 226.166 Payment of assessments and civil penalties.
(a) The lessee or permittee must remit payment for civil penalties
and immediate assessments set forth in this subpart within 10 business
days of receipt of the notice of collection from the Superintendent by
certified mail unless a different date is specified therein.
(b) Failure to timely pay civil penalties will result in the
assessment of an interest charge on all unpaid or underpaid penalty and
assessment amounts. Interest will be charged at the IRS underpayment
rate pursuant to 26 U.S.C. 6621(a)(2), or such other rate as the
Superintendent may prescribe. The IRS underpayment rate is posted
quarterly and is available online at https://www.irs.gov. Interest will
only be charged on the amount of the payment not received and for the
number of days the payment is late.
(c) Payments made pursuant to subpart N of this part do not relieve
the lessee or permittee of compliance with the terms and conditions of
the lease or permit or the regulations in this part,
[[Page 2496]]
nor do they relieve the lessee or permittee of liability for waste,
surface damages, or any other damages that may be occasioned. A waiver,
compromise, or reduction of any penalty must not be construed as
precluding or limiting the imposition of penalties for any other
violations or acts of non-compliance at that time or any other time.
Royalty Management Assessments and Civil Penalties
Sec. 226.167 Remedies for violations of lease or permit terms and
conditions, regulations, orders, and notices.
Violation of the terms or conditions of a lease, permit, or the
regulations in this part relating to royalty payment and reporting,
production reporting, or non-compliance with any orders ONRR issues,
may result in:
(a) Assessments;
(b) Civil penalties for each day such violation or non-compliance
continues;
(c) Shut-in or cancellation of the lease and bond forfeiture under
Sec. Sec. 226.164 and 226.165; and
(d) The transfer of delinquent debts to the U.S. Department of
Treasury for collection.
Sec. 226.168 Assessments for incorrect or late reports and failure to
report.
(a) ONRR may issue assessments of up to $10 per day for each report
it does not receive by the designated due date and for each report
submitted that is incorrectly completed.
(b) ONRR will periodically establish the amount of the assessments
imposed under paragraph (a) of this section based on its experience
with costs and improper reporting. ONRR will publish notice of the
assessment amount in the Federal Register.
Sec. 226.169 Assessments for failure to submit payment amount
indicated on a form or bill document or to provide adequate
information.
(a) ONRR may issue an assessment of up to $250 when the amount of a
payment a reporter or payor submits is not equivalent in amount to the
total of individual line items on the associated form or bill document,
unless ONRR authorized the difference in amount.
(b) ONRR may issue an assessment of up to $250 for each payment a
reporter or payor submits that cannot be automatically applied to the
associated form or bill document because the reporter or payor
submitted inadequate or erroneous information.
(c) For purposes of this section, the term ``applicable forms''
include Form ONRR-2014, Form ONRR-4054, and any other forms ONRR
requires under this part.
(d) For purposes of this section, the term ``bill document'' means
any invoice that ONRR issues for assessments, late-payment interest
charges, or other amounts owed. A payment document is defined as a
check or wire transfer message.
(e) For purposes of this section, ``inadequate or erroneous
information'' is defined as an:
(1) Absent or incorrect payor-assigned document number the reporter
or payor is required to identify in Block 4 on Form ONRR-2014 (document
4 number), or the reuse of the same incorrect payor-assigned document 4
number in a subsequent reporting period;
(2) Absent or incorrect bill document invoice number (to include
the three-character alpha prefix and the nine-digit number) or the
payor-assigned document 4 number the reporter or payor is required to
be identify on the associated payment document, or reuse of the same
incorrect payor-assigned document 4 number in a subsequent reporting
period;
(3) Absent or incorrect name of the administering BIA agency or
office or the Tribe name on payment documents remitted. If the payment
is made by EFT, the reporter or payor must identify the Tribe on the
EFT message by a pre-established five-digit code;
(4) Absent or incorrect ONRR-assigned payor code on a payment
document; or
(5) Absent or incorrect identification on a payment document.
(f) ONRR will periodically establish the amount of the assessment
to be imposed under paragraphs (a) and (b) of this section. The amount
of the assessment for each violation will be based on ONRR's experience
with costs and improper reporting. ONRR will publish notice of the
assessment amount in the Federal Register.
Sec. 226.170 Civil penalties with a period to correct.
(a) If a reporter or payor violates the terms and conditions of the
lease, the regulations in this part or any order relating to royalty
and production reporting and payment requirements, ONRR may issue a
NONC informing the reporter or payor of the violation and specifying
what actions, if any, must be taken to correct the violation and avoid
the assessment of civil penalties.
(b) If the violation is corrected within 20 calendar days of the
NONC, or such longer period for correction specified in the NONC, ONRR
will not assess a civil penalty or request that the Superintendent
shut-in or cancel the lease or permit but will consider the violations
part of the reporter's or payor's history of non-compliance for future
penalty assessments.
(c) If the violation is not corrected within 20 calendar days after
the date on which the NONC is served, or within 20 days following the
expiration of any longer period for correction specified in the NONC,
ONRR may issue an FCCP.
(1) The FCCP will state the amount of the penalty. The penalty
will:
(i) Begin to run on the day the NONC is served; and
(ii) Continue to accrue for each violation identified in the NONC
until it is corrected.
(2) The penalty may be up to $1,368 per day for each violation
identified in the NONC that has not been corrected.
(d) If the violation is not corrected within 40 calendar days from
the date the NONC is served, or within 20 calendar days following the
expiration of any longer correction period specified in the NONC, the
reporter or payor will be liable for a penalty of up to $13,693 per day
for each day the violation identified in the NONC that has not been
corrected. The increased penalty will:
(1) Begin to run on the 40th day after the day the NONC was served
or on the 20th day after the expiration of any longer correction period
in the NONC; and
(2) Continue to accrue for each violation identified in the NONC
until it is corrected.
Sec. 226.171 Civil penalties without a period to correct.
(a) ONRR may assess a penalty for a violation identified in
paragraphs (b) and (c) of this section without prior notice or an
opportunity to correct the violation. ONRR will inform reporters and
payors of violations without a period to correct by issuing an ILCP
explaining the violation and the amount of the civil penalty. The
penalty will begin to run on the day the violation is committed.
(b) A reporter or payor is liable for a civil penalty of up to
$27,384 per violation for each day the violation continues if they:
(1) Fail or refuse to permit lawful entry, inspection, or audit,
including refusal to keep, maintain, or produce documents; or
(2) Knowingly or willfully fail to make any royalty payment by the
date specified in the lease, regulations in this part, or any
applicable order.
(c) A reporter or payor is liable for a civil penalty up to $68,462
per violation for each day the violation continues if they knowingly or
willfully prepare, maintain, or submit false, inaccurate, or
[[Page 2497]]
misleading reports, notices, affidavits, records, data, or other
information to ONRR.
(d) ONRR may use any information as evidence that a reporter or
payor knowingly or willfully committed a violation including, but not
limited to:
(1) Any acts, or failures to act, by a reporter's or payor's
employee or agent;
(2) An email indicating the reporter's or payor's concurrence with
an issue;
(3) An order that the reporter or payor failed to appeal an order,
NONC, or ILCP for which no further appeal is available; and
(4) Any oral or written communication that identifies a violation
that the reporter or payor:
(i) Acknowledges as true and fails to correct;
(ii) Fails to appeal, or cannot further appeal, and fails to
correct; or
(iii) Corrects, but the reporter or payor subsequently commits the
same violation.
Sec. 226.172 Penalty amount.
(a) ONRR will determine the amount of the penalty to assess by
considering the:
(1) Severity of the violation;
(2) History of non-compliance; and
(3) Size of the reporter's or payor's business. To determine
business size, ONRR may consider the number of employees in the
reporter's or payor's company, parent company or companies, and any
subsidiaries or contractors.
(b) ONRR will not consider the royalty consequence of the
underlying violation when determining the amount of the civil penalty
for a violation under Sec. Sec. 226.170, 226.171(b)(1), and
226.171(c).
(c) FCCP and ILCP assessment matrices and adjustments thereto are
posted on ONRR's website.
(d) Penalties ONRR assesses under this subpart are in addition to
interest owed on any underlying payments or unpaid debts and are
supplemental to, not in derogation of, any other penalties or
assessments for non-compliance set forth in this part or other
applicable laws and regulations.
(e) ONRR may compromise or reduce a civil penalty assessed under
this subpart.
Sec. 226.173 Payment of assessments and civil penalties.
(a) The reporter or payor must remit payment for the civil
penalties and assessments set forth in Sec. Sec. 226.168 through
226.171 on or before the due date identified in the bill accompanying
the FCCP or ILCP.
(b) Failure to timely pay civil penalties and assessments will
result in the reporter or payor owing late-payment interest on all
unpaid or underpaid penalty and assessment amounts. Interest will be
charged in accordance with Sec. 226.166(b) beginning on the day the
payment was due and continuing until all debts are paid in full.
Sec. 226.174 Collection of unpaid civil penalties.
If a reporter or payor fails to pay a civil penalty amount on or
before the date it is due, ONRR may use all available means to collect
the penalty including, but not limited to:
(a) For an amount owed by a lessee, requiring the lease surety to
pay the penalty;
(b) Deducting the amount of the penalty from any sum the United
States may owe the reporter or payor; or
(c) Referring the debt to the U.S. Department of the Treasury
(Treasury) for collection in accordance with Sec. 226.175.
Sec. 226.175 Debt collection and administrative offset.
(a) ONRR will transfer any past due, legally enforceable non-tax
debt to Treasury within 180 days from the date the debt becomes past
due so that Treasury may take appropriate action to collect the debt or
terminate the collection action 26 U.S.C. 6402(d)(1)-(2); 31 U.S.C.
3711, 3716, and 3720A; Federal Claims Collection Standards (31 CFR
parts 900 through 904); and 31 CFR 285.2 and 285.5.
(b) If ONRR determines that a person owes, or may owe, a legally
enforceable debt to ONRR, it will send a written notice to the debtor
advising that ONRR intends to refer the debt to Treasury. The notice
will inform the debtor of the:
(1) Amount, nature, and basis of the debt;
(2) Methods of offset that ONRR or Treasury may use;
(3) Opportunity to inspect and copy Agency records related to the
debt;
(4) Opportunity to enter into a written agreement with ONRR to
repay the debt;
(5) ONRR's policy regarding interest and administrative costs,
including a statement that ONRR will make such assessments unless it
determines otherwise under the criteria of the Federal Claims
Collection Standards and this part;
(6) Date by which payment must be remitted to avoid additional late
charges and enforced collection; and
(7) Name, address, and phone number of an ONRR representative who
is available to discuss the debt.
(c) Debtors that receive a notice issued pursuant to paragraph (b)
of this section may not appeal unless the notice specifically provides
for such opportunity because the debtor did not previously receive a
notice of the order, decision on appeal, or any other notice or
decision that is the basis of the debt that ONRR intends to refer to
Treasury and for which the debtor may be liable in whole or in part
under applicable law. Debtors may not dispute matters related to
delinquent debts that were the subject of a final order or appeal
decision of which they were the recipient or a party thereto and that
are the basis of the delinquent debt. The requirements under this
paragraph apply whether the debtor appealed the order, demand, NONC, or
assessment.
(d) ONRR will issue an initial assessment of $436 for
administrative costs incurred because of a debtor's failure to pay a
delinquent debt. ONRR will publish notice of any increases in
administrative costs in the Federal Register. ONRR may also assess an
additional $436 for administrative costs that continue to accrue during
any appeal process if:
(1) The notice issued under paragraph (b) of this section grants
the right to appeal and the debtor exercises that right; and
(2) The appeal is denied and ONRR refers the delinquent debt to
Treasury.
(e) ONRR will apply a partial or installment payment made on a
delinquent debt sent to Treasury in the following order: outstanding
penalty assessments, administrative costs, accrued interest, and
outstanding debt principal.
(f) The Director of ONRR may waive collection of all or part of the
administrative costs under paragraph (d) of this section if they
determine that collection of this charge would be against equity and
good conscience or the Federal Government's best interest. The
Director's decision to collect or waive administrative costs is the
final decision for the Department and is not subject to administrative
review.
(g) The Director of ONRR may recommend that the Superintendent
revoke a debtor's ability to engage in the leasing of any trust or
restricted lands or the granting of easements, permits, or rights-of-
way if the debtor inexcusably or willfully fails to pay a debt. Any
such recommendation will remain in effect until such time as the debt
is paid in full or otherwise resolved to ONRR's satisfaction.
(h) ONRR may refer any past due, legally enforceable debt to
Treasury to collect through administrative offset or tax refund offset
at least 60 calendar days after it issues notice under paragraph (b) of
this section if the debt
[[Page 2498]]
is at least $250 or such other base amount as may be established by
Treasury.
(i) ONRR may refer debts reduced to judgment to Treasury for tax
refund offset at any time.
Criminal Penalties
Sec. 226.176 Penalties for filing fraudulent reports.
Any person who knowingly and willfully files fraudulent reports or
information under the regulations in this part is subject to criminal
penalties under 18 U.S.C. 1001.
Subpart O--Appeals
Appeals of BIA Decisions
Sec. 226.177 Procedure for filing an administrative appeal of a
decision, order, or notice of the Superintendent.
(a) Any party adversely affected by a decision, order, or notice
the Superintendent issues by virtue of the regulations in this part may
appeal pursuant to 25 CFR part 2.
(b) If an appeal is not timely filed with the Regional Director
under 25 CFR part 2 and subsequently with the IBIA under 43 CFR part 4,
subpart D (where required):
(1) The subject decision, order, or notice will be final for the
Department; and
(2) The affected party will be barred from contesting the validity
or merits of the decision, order, or notice in subsequent
administrative or judicial proceedings due to failure to exhaust
administrative remedies.
Appeals of ONRR Decisions
Sec. 226.178 Procedures for filing and administrative appeal of an
order from ONRR.
(a) Any party adversely affected by an order ONRR issues by virtue
of the regulations in this part may appeal to the Director of ONRR as
set forth in this section.
(b) For purposes of this section, the term ``order'' means any
document ONRR issues that contains language mandating or directing the
recipient to report, compute, or pay royalties or other obligations;
report production; or provide any other information.
(1) An order includes, but is not limited to:
(i) An Order to Pay or Order to Perform a Restructured Accounting;
(ii) A decision from ONRR denying a lessee's, reporter's, or
payor's written request and that imposes an obligation on the lessee,
reporter, or payor (a denial); and
(iii) A NONC, FCCP, or ILCP.
(2) An order does not include:
(i) A non-binding request, information, or guidance, such as a
policy determination or guidance on how to report or pay, including a
valuation determination, unless it contains language indicating that an
action is mandatory or expressly orders the recipient(s) to take a
certain action;
(ii) A subpoena;
(iii) An order that ONRR issues to a refiner or other person
involved in disposition of royalty taken in-kind;
(iv) A ``Dear Lessee,'' ``Dear Payor,'' or ``Dear Reporter''
letter, unless it explicitly includes the right to appeal; or
(v) Any other correspondence from ONRR that does not include the
right to appeal.
(c) A lessee or designee may appeal an order to the Director of
ONRR by filing a Notice of Appeal in the office of the official that
issued the order within 30 calendar days from the date the order was
received. If a designee is filing an appeal, they must concurrently
serve the Notice of Appeal on all lessees for the lease(s) identified
in the order by certified mail--return receipt requested. Within the
same 30-day period, the lessee or designee must file a Statement of
Reasons setting forth any factual and legal arguments justifying
reversal or modification of the order. No extension of time will be
granted for filing the Notice of Appeal.
(d) A lessee may join an appeal filed by a designee within 30
calendar days from the date the lessee receives the Notice of Appeal by
filing a Notice of Joinder with the office of the official that issued
the order. If a lessee joins an appeal, they are deemed to appeal the
order jointly with the designee, but the designee must fulfill all
requirements imposed on appellants under this section and 43 CFR part
4, subpart E. Lessees may not file pleadings separately from the
designee.
(1) If a lessee does not appeal, or join the designee's appeal, the
designee's actions with respect to the appeal and any decisions therein
are binding on the lessee.
(2) If a designee decides to discontinue participation in an
appeal, they must serve written notice at least 30 calendar days before
the next pleading is due. The notice must be served on:
(i) All lessees who joined the appeal under this section;
(ii) The office or officer with whom subsequent pleadings must be
filed; and
(iii) All other parties to the appeal.
(e) Any party adversely affected by a decision the Director of ONRR
issues under this section may appeal the decision to the IBLA pursuant
to 43 CFR part 4, subpart E.
(f) If an order is neither paid, nor appealed to the Director of
ONRR under this section and, subsequently, to the IBLA under 43 CFR
part 4, subpart E:
(i) The order is the final decision of the Department; and
(ii) The affected party will be barred from contesting the validity
or merits of the order in subsequent administrative or judicial
proceedings, including enforcement proceedings.
Sec. 226.179 Suspension of compliance with an ONRR order.
(a) For purposes of this subpart, ``ONRR-specified surety
instrument'' means an ONRR-specified administrative appeal bond, an
ONRR-specified irrevocable letter of credit, or a financial institution
book-entry certificate of deposit.
(b) Subject to paragraph (d) of this section, if an affected party
appeals an order regarding the payment or reporting of royalties and
other payments due from leases of the Osage Mineral Estate:
(1) If the amount under appeal is less than $1,000, or does not
require payment, the appellant's obligation to comply with the order is
suspended while the appeal is pending. ONRR will use the performance
bond posted with the BIA as collateral for the obligation.
(2) If the amount under appeal is $1,000 of more, ONRR will suspend
the appellant's obligation to comply with the order if they submit an
ONRR-specified surety instrument under this subpart within 60 calendar
days of the date they receive the order or Notice of Order.
(c) Nothing in this subpart prohibits an appellant from paying any
demanded amount or otherwise complying with any other requirement
pending resolution of their appeal. Voluntarily paying any demanded
amount or otherwise complying with any other requirement when
suspension of an order is available under the regulations does not
create a final agency action subject to judicial review under 5 U.S.C.
704.
(d) Regardless of the amount under appeal, ONRR may inform an
appellant that it will not suspend their obligation to comply with the
order under paragraph (a) of this section because suspension would harm
the interests of the United States or Osage Nation.
Sec. 226.180 Requirements for posting a bond or other surety on
behalf of an appellant.
Any person, including a designee, payor, or affiliate, may post a
bond or
[[Page 2499]]
surety instrument under this subpart on behalf of an appellant. If you
assume an appellant's responsibility to post a bond or other surety
instrument, you:
(a) Must notify ONRR in writing that you are assuming the
appellant's responsibility under this subpart;
(b) May not assert that you are not otherwise liable for royalties
or other payments under the lease, or any other theory, as a defense if
ONRR collects your bond or other surety instrument; and
(c) May end your voluntarily assumed responsibility for posting a
bond or other surety instrument only after the appellant pays or posts
a bond or other surety instrument.
Sec. 226.181 Suspension of the obligation to comply with an ONRR
order due to judicial review in federal court.
(a) If an appellant seeks judicial review of an IBLA decision or
another final action of the Department of the Interior regarding an
ONRR order, ONRR will suspend the appellant's obligation to comply with
that order pending judicial review if they continue to meet the
requirements of this subpart.
(b) Notwithstanding paragraph (a) of this section, ONRR may decide
that it will not suspend an appellant's obligation to comply with an
order. ONRR will notify the appellant in writing of such decision and
the reasons for it.
Sec. 226.182 ONRR's collection of bonds and other surety instruments.
(a) This section applies to you if you maintain a bond or an ONRR-
specified surety instrument on your own behalf or on another person's
behalf for an appeal of an order under this subpart.
(b) ONRR may initiate collection of your bond or other surety
instrument if:
(1) The Director of ONRR decides the appeal adversely to you and
you do not pay the amount due or appeal the decision further to the
IBLA under 43 CFR part 4, subpart E;
(2) The IBLA, Director of the Office of Hearings and Appeals, an
Assistant Secretary, or the Secretary decides the appeal adversely to
you and you do not pay the amount due or pursue judicial review within
90 calendar days of the decision;
(3) A court of competent jurisdiction issues a final non-appealable
decision adverse to you and you do not pay the amount due within 30
calendar days of the decision;
(4) You do not increase the amount of your bond or other surety
instrument as required under Sec. 226.185(c), or otherwise fail to
maintain an adequate surety instrument in effect, and you do not pay
the amount due under the ONRR order within 30 calendar days of receipt
of the notice from ONRR under Sec. 226.185(c); or
(5) The obligation to comply with an order or decision is not
suspended and you do not pay the amount required under the order or
decision.
Sec. 226.183 ONRR bond-approving officer's determination of surety
amount not subject to appeal.
Any decision regarding the amount of the surety due under this
subpart is final and not subject to appeal.
Sec. 226.184 Standards for ONRR-specified surety instruments.
(a) An ONRR-specified surety instrument must be in a form
identified in ONRR's instructions. ONRR will provide written
information and standards forms for ONRR-specified surety instrument
requirements.
(b) ONRR will use a bank-rating service to determine whether a
financial institution has an acceptable rating to provide a surety
instrument adequate to indemnify the lessor from loss or damage.
(1) Administrative appeal bonds must be issued by a qualified
surety company that Treasury approved.
(2) Irrevocable letters of credit or certificates of deposit must
be from a financial institution acceptable to ONRR with a minimum one-
year period of coverage subject to automatic renewal up to five years.
Sec. 226.185 ONRR's determination of bond or surety instrument
amount.
(a) The ONRR bond-approving officer may approve an appellant's
surety if they determine that the amount is adequate to guarantee
payment. The amount of the appellant's surety may vary depending on the
form of the surety and how long the surety is effective.
(b) The amount of the ONRR-specified surety instrument must include
the principal amount owed under the order plus any accrued interest
ONRR determines is owed plus projected interest for a one-year period.
(c) If an appeal is not decided within one year from the date of
filing, the appellant must increase the surety amount to cover
additional estimated interest for another one-year period. The
appellant must continue to increase the surety amount annually on the
date of filing for the duration of the appeal. ONRR will determine the
additional estimated interest and notify the appellant of the amount so
it can amend your surety instrument.
(d) The appellant may submit a single surety instrument that covers
multiple appeals. The appellant may change the instrument to add new
amounts under appeal or remove amounts that have been adjudicated in
their favor or that they have paid if they:
(1) Amend the single surety instrument annually on the date they
filed their first appeal; and
(2) Submit a separate surety instrument for new amounts under
appeal until they amend the instrument to cover the new appeals.
Appendix A to Part 226--Table of Atmospheric Pressures
----------------------------------------------------------------------------------------------------------------
Atmos. Elevation (ft Atmos. Elevation (ft Atmos.
Elevation (ft msl) pressure (psi) msl) pressure (psi) msl) pressure (psi)
----------------------------------------------------------------------------------------------------------------
0............................... 14.70 4,000 12.70 8,000 10.92
100............................. 14.64 4,100 12.65 8,100 10.88
200............................. 14.59 4,200 12.60 8,200 10.84
300............................. 14.54 4,300 12.56 8,300 10.80
400............................. 14.49 4,400 12.51 8,400 10.76
500............................. 14.43 4,500 12.46 8,500 10.72
600............................. 14.38 4,600 12.42 8,600 10.68
700............................. 14.33 4,700 12.37 8,700 10.63
800............................. 14.28 4,800 12.32 8,800 10.59
900............................. 14.23 4,900 12.28 8,900 10.55
1,000........................... 14.17 5,000 12.23 9,000 10.51
1,100........................... 14.12 5,100 12.19 9,100 10.47
1,200........................... 14.07 5,200 12.14 9,200 10.43
1,300........................... 14.02 5,300 12.10 9,300 10.39
1,400........................... 13.97 5,400 12.05 9,400 10.35
[[Page 2500]]
1,500........................... 13.92 5,500 12.01 9,500 10.31
1,600........................... 13.87 5,600 11.96 9,600 10.27
1,700........................... 13.82 5,700 11.92 9,700 10.23
1,800........................... 13.77 5,800 11.87 9,800 10.19
1,900........................... 13.72 5,900 11.83 9,900 10.15
2,000........................... 13.67 6,000 11.78 10,000 10.12
2,100........................... 13.62 6,100 11.74 10,100 10.08
2,200........................... 13.57 6,200 11.69 10,200 10.04
2,300........................... 13.52 6,300 11.65 10,300 10.00
2,400........................... 13.47 6,400 11.61 10,400 9.96
2,500........................... 13.42 6,500 11.56 10,500 9.92
2,600........................... 13.37 6,600 11.52 10,600 9.88
2,700........................... 13.32 6,700 11.48 10,700 9.84
2,800........................... 13.27 6,800 11.43 10,800 9.81
2,900........................... 13.22 6,900 11.39 10,900 9.77
3,000........................... 13.17 7,000 11.35 11,000 9.73
3,100........................... 13.13 7,100 11.30 11,100 9.69
3,200........................... 13.08 7,200 11.26 11,200 9.65
3,300........................... 13.03 7,300 11.22 11,300 9.62
3,400........................... 12.98 7,400 11.18 11,400 9.58
3,500........................... 12.93 7,500 11.13 11,500 9.54
3,600........................... 12.89 7,600 11.09 11,600 9.50
3,700........................... 12.84 7,700 11.05 11,700 9.47
3,800........................... 12.79 7,800 11.01 11,800 9.43
3,900........................... 12.74 7,900 10.97 11,900 9.39
----------------------------------------------------------------------------------------------------------------
Calculated as:
Palm = 14.696 x (1x0.00000686E)525577
From: U.S. Standard Atmosphere, 1976, U.S. Government Printing
Office, Washington, DC 1976.
Bryan Newland,
Assistant Secretary--Indian Affairs.
[FR Doc. 2022-28098 Filed 1-12-23; 8:45 am]
BILLING CODE 4337-15-P