[Federal Register Volume 80, Number 189 (Wednesday, September 30, 2015)]
[Proposed Rules]
[Pages 58952-58979]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2015-24008]



[[Page 58951]]

Vol. 80

Wednesday,

No. 189

September 30, 2015

Part IV





Department of the Interior





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Bureau of Land Management





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43 CFR Parts 3160 and 3170





Onshore Oil and Gas Operations; Federal and Indian Oil and Gas Leases; 
Measurement of Oil; Proposed Rule

  Federal Register / Vol. 80 , No. 189 / Wednesday, September 30, 2015 
/ Proposed Rules  

[[Page 58952]]


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DEPARTMENT OF THE INTERIOR

Bureau of Land Management

43 CFR Parts 3160 and 3170

[15X.LLWO300000.L13100000.NB0000]
RIN 1004-AE16


Onshore Oil and Gas Operations; Federal and Indian Oil and Gas 
Leases; Measurement of Oil

AGENCY: Bureau of Land Management, Interior.

ACTION: Proposed rule.

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SUMMARY: This proposed rule would replace Onshore Oil and Gas Order 
Number 4, Measurement of Oil (Order 4) with new regulations that would 
be codified in the Code of Federal Regulations (CFR). Order 4 
establishes minimum standards for the measurement of oil produced from 
Federal and Indian (except Osage Tribe) leases to ensure that 
production is accurately measured and properly accounted for. Order 4 
was issued in 1989.
    The changes contemplated as part of this proposed rule would 
strengthen the Bureau of Land Management's (BLM) policies governing 
production accountability by updating its minimum standards for oil 
measurement to reflect the considerable changes in technology and 
industry practices that have occurred in the 25 years since Order 4 was 
issued. This proposed rule addresses the use of new oil meter 
technology, proper measurement documentation, and recordkeeping; 
establishes performance standards for oil measurement systems; and 
includes a mechanism for the BLM to review, and approve for use, new 
oil measurement technology and systems. The proposed rule expands the 
acts of noncompliance that would result in an immediate assessment 
under the existing regulations. Finally, it sets forth a process for 
the BLM to consider variances from these requirements.

DATES: Send your comments on this proposed rule to the BLM on or before 
November 30, 2015. The BLM is not obligated to consider any comments 
received after this date in making its decision on the final rule.
    As explained later, the proposed rule would establish new 
information collection requirements that must be approved by the Office 
of Management and Budget (OMB). If you wish to comment on the 
information collection requirements in this proposed rule, please note 
that the OMB is required to make a decision concerning the collection 
of information contained in this proposed rule between 30 and 60 days 
after publication of this document in the Federal Register. Therefore, 
a comment to the OMB on the proposed information collection 
requirements is best assured of having its full effect if the OMB 
receives it by October 30, 2015.

ADDRESSES: Mail: U.S. Department of the Interior, Director (630), 
Bureau of Land Management, Mail Stop 2134 LM, 1849 C St. NW., 
Washington, DC 20240, Attention: 1004-AE16. Personal or messenger 
delivery: 20 M Street SE., Room 2134LM, Washington, DC 20003. Federal 
eRulemaking Portal: http://www.regulations.gov. Follow the instructions 
at this Web site.
    Comments on the information collection burdens: Fax: Office of 
Management and Budget (OMB), Office of Information and Regulatory 
Affairs, Desk Officer for the Department of the Interior, fax 202-395-
5806. Electronic mail: [email protected]. Please indicate 
``Attention: OMB Control Number 1004-XXXX,'' regardless of the method 
used to submit comments on the information collection burdens. If you 
submit comments on the information collection burdens, you should 
provide the BLM with a copy, at one of the addresses shown earlier in 
this section, so that we can summarize all written comments and address 
them in the final rule preamble.

FOR FURTHER INFORMATION CONTACT: Mike McLaren, 1625 West Pine St., P.O. 
Box 768, Pinedale, WY 82941, or by telephone at 307-367-5389. For 
questions relating to regulatory process issues, please contact Faith 
Bremner at 202-912-7441. Persons who use a telecommunications device 
for the deaf (TDD) may call the Federal Information Relay Service 
(FIRS) at 1-800-877-8339 to contact these individuals during normal 
business hours. FIRS is available 24 hours a day, 7 days a week to 
leave a message or question with these individuals. You will receive a 
reply during normal business hours.

SUPPLEMENTARY INFORMATION: 

Executive Summary

    The Secretary of the Interior (Secretary) has the authority under 
various Federal and Indian mineral leasing laws to manage oil and gas 
operations on Federal and Indian (except Osage Tribe) lands, including, 
but not limited to, the Mineral Leasing Act, 30 U.S.C. 181 et seq., the 
Mineral Leasing Act for Acquired Lands, 30 U.S.C. 351 et seq., the 
Indian Mineral Leasing Act, 25 U.S.C. 396a et seq., the Act of March 3, 
1909, 25 U.S.C. 396, and the Indian Mineral Development Act, 25 U.S.C. 
2101 et seq. Each of these statutes grants to the Secretary authority 
to promulgate necessary and appropriate rules and regulations. See 30 
U.S.C. 189; 30 U.S.C. 359; 25 U.S.C. 396d; 25 U.S.C. 396; and 25 U.S.C. 
2107. The Secretary has delegated this authority to the BLM.
    The BLM's onshore oil and gas program is one of the most important 
mineral-leasing programs in the Federal Government. In fiscal year (FY) 
2014, onshore Federal oil and gas leases produced about 148 million 
barrels of oil, 2.48 trillion cubic feet of natural gas, and 2.9 
billion gallons of natural gas liquids, with a market value of more 
than $27 billion and generating royalties of almost $3.1 billion. 
Nearly half of these revenues are distributed to the States in which 
the leases are located. Leases on tribal and Indian lands produced 56 
million barrels of oil, 240 billion cubic feet of natural gas, 182 
million gallons of natural gas liquids, with a market value of almost 
$6 billion and generating royalties of over $1 billion that were all 
distributed to the applicable tribes and individual allottee owners. 
Despite the magnitude of this production, the BLM's rules governing how 
that oil is measured and accounted for are more than 25 years old and 
need to be updated and strengthened. Federal laws, technology, and 
industry standards have all changed significantly in that time.
    The BLM implements its authority over Federal and Indian (except 
Osage Tribe) oil and gas leases through the regulations at 43 CFR part 
3160. Those regulations authorize the BLM to issue Onshore Oil and Gas 
Orders (Orders) when necessary to implement and supplement the 
regulations. Over the years, the BLM issued seven Orders that deal with 
different aspects of oil and gas production.\1\ Order 4, which was 
issued in 1989, focuses on oil measurement. This proposed rule would 
update Order 4 to reflect advancements in technology, industry 
standards, and changes in applicable legal requirements. This rule 
proposes to issue those updated requirements as regulations that would 
be codified in the CFR.
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    \1\ These Onshore Orders were published in the Federal Register, 
both for public comment and in final form, but they do not appear in 
the CFR.
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    These updated requirements are the result of the BLM's evaluation 
of its existing requirements, based on its experience in the field, and 
the conclusion of multiple separate reports--one by the Secretary's 
Subcommittee on Royalty Management, issued in 2007; one by the 
Department's Office of Inspector General (OIG), issued

[[Page 58953]]

in 2009; and multiple by the Government Accountability Office (GAO). 
The GAO issued issue-specific reports in 2010 and 2015, and its 
recommendations related to the adequacy of the BLM's oil measurement 
rules generally formed one of the bases for the GAO's inclusion and 
continued presence of the BLM's oil and gas program on the GAO's High 
Risk List in 2011, 2013, and 2015. As explained later, each of these 
entities recommended that the BLM evaluate its existing oil measurement 
guidance to ensure it reflects current technologies and standards and, 
where appropriate, update the guidance and regulations accordingly. Up-
to-date measurement requirements are critically important because they 
provide the mechanism to ensure that oil and gas produced from Federal 
and Indian leases are properly accounted for, thus ensuring that 
operators pay the proper royalties due.
    As explained in detail below, the proposed rule makes a number of 
changes that modernize and strengthen the existing requirements of 
Order 4. For example, by recognizing advancements in measurement 
technologies and changes in industry practices, the proposed rule would 
allow operators to use a Coriolis measurement system (CMS) and 
eliminate the need for industry to submit and the BLM to process 
variance requests as it currently does when operators want to use a 
CMS.\2\ Currently, under Order 4, the only meter that an operator can 
use on a lease without prior approval is a lease automatic custody 
transfer (LACT) system.\3\ A LACT system uses a positive displacement 
(PD) meter, which requires more maintenance than a CMS. The BLM is 
proposing this change because field and laboratory testing have proven 
the CMS to be reliable and accurate. This will also make CMS 
requirements and standards uniform across the country, as opposed to 
varying by BLM state or field office as they currently do. Finally, 
this change would increase efficiency by saving operators the time it 
takes to apply for variances and the BLM the time it takes to process 
them.
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    \2\ A CMS is a metering system using a Coriolis flow meter in 
conjunction with a tertiary device, pressure transducer, and 
temperature transducer in order to derive and report net oil volume. 
A Coriolis flow meter is based on the principle that fluid mass flow 
through a tube results in a measurable twisting or distortion and 
consequent oscillation of the tube. Sensors measure that 
oscillation.
    \3\ A LACT system is a piece of equipment that automatically 
measures, analyzes, and transfers oil from a storage tank to a 
pipeline or tanker truck.
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    In recognition that measurement techniques and technologies will 
continue to evolve, the BLM is also proposing to adopt a process and 
criteria that would allow it, through a new Production Measurement Team 
(PMT), to review and approve for use new measurement technologies that 
are demonstrated to be reliable and accurate. The new technologies 
would have to meet or exceed the same performance standards as those 
prescribed in this proposed rule.\4\
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    \4\ The PMT would be distinguished from the Department of the 
Interior's Gas and Oil Measurement Team (DOI GOMT), which consists 
of members with gas or oil measurement expertise from the BLM, the 
ONRR, and the Bureau of Safety and Environmental Enforcement (BSEE). 
BSEE handles production accountability for Federal offshore leases. 
The DOI GOMT is a coordinating body that enables the BLM and BSEE to 
consider measurement issues and track developments of common concern 
to both agencies. The BLM is not proposing a dual-agency approval 
process for use of new measurement technologies for onshore leases. 
The BLM expects that the members of the BLM PMT would participate as 
part of the DOI GOMT.
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    Similarly, the proposed rule strengthens existing requirements by 
prohibiting the use of automatic temperature/gravity compensators on 
LACT systems, which are currently required by Order 4. These 
compensators are designed to automatically adjust LACT totalizer 
readings to account for temperature changes and, in some cases, oil 
gravity changes. However, the use of automatic compensators means an 
uncorrected totalizer reading is not available for such systems, which 
means the BLM and the operator lack access to the raw data necessary to 
verify that the compensators are functioning correctly or that the 
totalizer reading is correct. To ensure such data exists, this proposed 
rule would, instead, require operators to use temperature averaging 
devices, which record and average the temperatures of the fluids 
flowing through the LACT. Under this system, the operator would use the 
data from the averaging devices to manually correct the volumes from 
the totalizer for the effects of temperature and oil gravity and the 
BLM would have the raw data necessary to verify the results and confirm 
system functionality. In the BLM's experience, the majority of LACT 
systems already use averaging devices, which can be used only under 
BLM-approved variances, while only about 20 percent use automatic 
temperature/gravity compensators.
    The proposed rule would also strengthen existing regulations by 
increasing meter-proving requirements for operators who produce large 
volumes of oil. Current regulations require quarterly proving for all 
meters, except those meters that exceed a 100,000 bbl per month volume 
that are required to be proven monthly. Under this proposal, meters 
would be proven anytime the non-resettable totalizer increases by 
50,000 bbl, or quarterly, whichever occurs first. Increased proving 
frequencies ensure that meter-factor changes that effect measurement 
are corrected before large volumes of production are measured 
incorrectly, which could adversely impact royalty determinations. This 
proposed change would affect approximately 5 percent of existing LACT 
systems nationwide.
    Finally, the proposed rule would clarify existing regulations to 
require that oil storage tanks be vapor-tight and that all venting 
occur through a pressure-vacuum relief valve. This would minimize 
hydrocarbon gas lost to the atmosphere by ensuring that venting is done 
under controlled conditions primarily in response to changes in the 
ambient temperature.
    Where appropriate, this proposed rule incorporates by reference new 
American Petroleum Institute (API) standards that address the 
activities covered by this rule as explained later.

I. Public Comment Procedures
II. Background
III. General Overview of the Proposed Rule
IV. Section-by-Section Analysis
V. Onshore Order Public Meetings, April 24-25, 2013
VI. Procedural Matters

I. Public Comment Procedures

    If you wish to comment on the proposed rule, you may submit your 
comments by any one of several methods specified (see ADDRESSES). If 
you wish to comment on the information collection requirements, you 
should send those comments directly to the OMB as outlined (see 
ADDRESSES); however, we ask that you also provide a copy of those 
comments to the BLM.
    Please make your comments as specific as possible by confining them 
to issues for which comments are sought in this notice, and explain the 
basis for your comments. The comments and recommendations that will be 
most useful and likely to influence agency decisions are:
    1. Those that are supported by quantitative information or studies; 
and
    2. Those that include citations to, and analyses of, the applicable 
laws and regulations.
    The BLM is not obligated to consider or include in the 
Administrative Record for the rule comments received after the close of 
the comment period (see DATES) or comments delivered to an address 
other than those listed (see ADDRESSES).
    Comments, including names and street addresses of respondents, will 
be

[[Page 58954]]

available for public review at the address listed under ADDRESSES 
during regular hours (7:45 a.m. to 4:15 p.m.), Monday through Friday, 
except holidays. Before including your address, phone number, email 
address, or other personal identifying information in your comment, you 
should be aware that your entire comment--including your personal 
identifying information--may be made publicly available at any time. 
While you can ask us in your comment to withhold your personal 
identifying information from public review, we cannot guarantee that we 
will be able to do so.

II. Background

    As noted earlier, the regulations at 43 CFR 3164.1 provide for the 
issuance of Onshore Orders to ``implement and supplement'' the 
regulations in part 3160. The table in 43 CFR 3164.1(b) lists the 
existing Orders. This proposed rule would revise and replace Order 4 
and would govern measurement of oil production on Federal and Indian 
(except Osage Tribe) oil and gas leases. Order 4 has been in effect 
since August 23, 1989.\5\ The BLM is proposing to codify the 
requirements of this proposed rule, which would replace Order 4, at a 
new 43 CFR subpart 3174.
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    \5\ It was published on February 24, 1989 (54 FR 8086).
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III. General Overview of the Proposed Rule

    Under the applicable law, royalty is owed to the United States on 
all production removed or sold from Federal and Indian oil and gas 
leases. The royalty payments are based on the measured production from 
those leases. Thus, it is critically important that the BLM ensure 
accurate measurement, proper reporting, and accountability. The BLM is 
pursuing proposed updates to Order 4's requirements because they are 
necessary to reflect changes in oil measurement practices and 
technology.
    Order 4 has been in place since 1989. As a result, its equipment 
mandates and other requirements do not reflect improvements in oil 
measurement technologies and practices. In the BLM's experience, this 
has meant that industry has had to request, and the BLM has had to 
process, an increasing number of variances to authorize operators to 
install and use new technology, such as CMSs, even though the 
reliability of these systems has been long established. The variances 
are required because Order 4 does not contemplate CMSs. Additionally, 
since they are not included, Order 4 also does not provide uniform 
performance standards for these systems, which has led BLM state and 
field offices to specify their own standards. The BLM's experience in 
the field with Order 4's limitations is consistent with the findings of 
multiple separate independent reports.
    In 2007, the Secretary appointed an independent panel--the 
Subcommittee on Royalty Management (Subcommittee)--to review the 
Department's procedures and processes related to the management of 
mineral revenues and to provide advice to the Department based on that 
review.\6\ In a report dated December 17, 2007, the Subcommittee 
determined that the BLM's production accountability methods are 
``unconsolidated, outdated, and sometimes insufficient.'' The report 
says:
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    \6\ The Subcommittee was commissioned to report to the Royalty 
Policy Committee, which is chartered under the Federal Advisory 
Committee Act to provide advice to the Secretary and other 
Departmental officials responsible for managing mineral leasing 
activities and to provide a forum for the public to voice concerns 
about mineral leasing activities.
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     BLM policy and guidance have not been consolidated into a 
single document or publication, resulting in the BLM's 31 oil and gas 
field offices using varying policy and guidance (see page 31);
     Some BLM policy and guidance is outdated and some policy 
memoranda have expired (ibid.); and
     Some BLM State offices have issued their own ``Notices to 
Lessees and Operators'' (NTLs) for oil and gas operations. While such 
NTLs may have a positive effect on local oil and gas field operations, 
they nevertheless lack a national perspective and may introduce 
inconsistencies among the States (ibid.).
    The Subcommittee specifically recommended that the BLM evaluate 
Order 4 to ensure that it includes sufficient guidance for ensuring 
that accurate royalties are paid on Federal oil production. In 
response, the Interior Department formed a Fluid Minerals Team, 
comprised of Departmental oil and gas experts. The team determined that 
Order 4 should be updated in light of changes in technology and BLM and 
industry practices. In addition to the Subcommittee report, findings 
and recommendation addressing similar issues have been issued by the 
GAO (Report to Congressional Requesters, Oil and Gas Management, 
Interior's Oil and Gas Production Verification Efforts Do Not Provide 
Reasonable Assurance of Accurate Measurement of Production Volumes, 
GAO-10-313 (GAO 2010 Report), and Report to Congressional Requesters, 
Oil and Gas Resources, Interior's Production Verification Efforts: Data 
Have Improved but Further Actions Needed, GAO 15-39 (GAO 2015 Report)) 
and the OIG (Bureau of Land Management's Oil and Gas Inspection and 
Enforcement Program, CR-EV-0001-2009).
    In its 2010 report, the GAO found that the Department's measurement 
regulations and policies do not provide reasonable assurances that oil 
and gas are accurately measured because, among other things, its 
policies for tracking where and how oil and gas are measured are not 
consistent and effective (GAO 2010 Report, p. 20). The report also 
found that the BLM's regulations do not reflect current industry-
adopted measurement technologies and standards designed to improve oil 
and gas measurement (ibid.). The GAO recommended that Interior provide 
Department-wide guidance on measurement technologies not addressed in 
current regulations and approve variances for measurement technologies 
in instances when the technologies are not addressed in current 
regulations or Department-wide guidance (see ibid., p. 80). The OIG 
report made a similar recommendation that the BLM, ``Ensure that oil 
and gas regulations are current by updating and issuing onshore orders. 
. . .'' (see page 11). In its 2015 report, the GAO reiterated that 
``Interior's measurement regulations do not reflect current measurement 
technologies and standards,'' and that this ``hampers the agency's 
ability to have reasonable assurance that oil and gas production is 
being measured accurately and verified. . . .'' (GAO 2015 Report, p. 
16.) Among its recommendations were that the Secretary direct the BLM 
to ``meet its established time frame for issuing final regulations for 
oil measurement.'' (Ibid., p. 32.)
    The GAO's recommendations related to the adequacy of the BLM's oil 
measurement rules are also significant because they formed one of the 
bases for the GAO's inclusion of the BLM's oil and gas program on the 
GAO's High Risk List in 2011 (Report to Congressional Committees, High 
Risk Series, An Update, GAO-11-278). Specifically, the GAO concluded in 
2011 ``that Interior's verification of the volume of oil . . . produced 
from federal leases--on which royalties are due the federal government-
-does not provide reasonable assurance that operators are accurately 
measuring and reporting these volumes.'' (GAO-11-278, p.15.) Because 
the GAO's recommendations have not yet been fully implemented, the 
onshore oil and gas program has remained on the High

[[Page 58955]]

Risk List in subsequent updates in 2013 (Report to Congressional 
Committees, High Risk Series, An Update, GAO-13-283) and 2015 (Report 
to Congressional Committees, High Risk Series, An Update, GAO-15-290).
    The provisions of this proposed rule respond to the recommendations 
by the Subcommittee, the GAO, and the OIG. They were also developed by 
the BLM to enhance and clarify some of the requirements in Order 4 in 
response to changes in technology, BLM field experience, and changes to 
applicable statutory requirements.
    The following table provides an overview of the changes 
contemplated as part of this proposed rule and identifies the 
substantive changes relative to Order 4.

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            Order 4               Proposed rule     Substantive changes
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I. Introduction--A. Authority.  No section in      This section of Order
                                 this proposed      4 would appear in
                                 rule.              proposed 43 CFR
                                                    3170.1. New subpart
                                                    3170 was proposed
                                                    separately in
                                                    connection with
                                                    proposed new 43 CFR
                                                    subpart 3173 (site
                                                    security), (80 FR
                                                    40768, July 13,
                                                    2015).
I. Introduction--B. Purpose...  No section in the  The purpose of this
                                 proposed rule.     proposed rule is to
                                                    revise and replace
                                                    Order 4 with a new
                                                    regulation that
                                                    would be codified in
                                                    the CFR.
I. Introduction--C. Scope.....  No section in      See proposed new 43
                                 this proposed      CFR 3170.2 (80 FR
                                 rule.              40802, July 13,
                                                    2015).
II. Definitions...............  43 CFR 3174.1....  See also proposed new
                                                    43 CFR 3170.3 (80 FR
                                                    40802, July 13,
                                                    2015), which would
                                                    add definitions of
                                                    some of the key
                                                    terms and would add
                                                    a list of acronyms
                                                    that are used in
                                                    this proposed rule.
                                                    Terms for which new
                                                    definitions would be
                                                    added include:
                                                    Configuration log,
                                                    CMS, event log,
                                                    opaque oil, quantity
                                                    transaction record
                                                    (QTR), resistance
                                                    thermal device
                                                    (RTD), tertiary
                                                    device, and unity.
III. Requirements--A. Required  No section in      See proposed new 43
 Recordkeeping.                  this proposed      CFR 3170.7 (80 FR
                                 rule.              40804, July 13,
                                                    2015).
III. Requirements--B. General.  43 CFR 3174.2 and  The proposed rule
                                 3174.3.            would remove all
                                                    specific reference
                                                    to: ``Violation''
                                                    (major or minor),
                                                    ``Corrective
                                                    Action'' (what needs
                                                    to be done to
                                                    resolve the
                                                    violation), and
                                                    ``Normal Abatement
                                                    Period'' (how much
                                                    time is allowed to
                                                    correct the
                                                    violation). The BLM
                                                    will address these
                                                    issues in internal
                                                    guidance documents
                                                    (handbooks, manuals
                                                    or instructional
                                                    memoranda (IMs)).
                                                    This proposed rule
                                                    would specify that
                                                    oil may be produced
                                                    into and stored only
                                                    in tanks meeting the
                                                    minimum requirements
                                                    of this rule. This
                                                    proposed rule would
                                                    also establish
                                                    overall performance
                                                    requirements in
                                                    terms of uncertainty
                                                    levels, bias, and
                                                    verifiability of
                                                    measurement.
None..........................  43 CFR 3174.4....  The proposed rule
                                                    would adopt the
                                                    latest versions of
                                                    certain API and ASTM
                                                    International (ASTM)
                                                    standards.
III. Requirements--C. Oil       43 CFR 3174.5 and  This proposed rule
 Measurement by Tank Gauging.    3174.6.            would require all
                                                    oil storage tank
                                                    hatches,
                                                    connections, and
                                                    other access points
                                                    to be vapor-tight
                                                    and would require
                                                    appropriate pressure-
                                                    vacuum relief
                                                    systems. This
                                                    proposed rule would
                                                    require the operator
                                                    to submit tank
                                                    calibration charts
                                                    (tank tables) to the
                                                    authorized officer
                                                    (AO) within 30 days
                                                    of calibrating or
                                                    recalibrating. This
                                                    entire section has
                                                    been reorganized to
                                                    give the step-by-
                                                    step procedure to
                                                    correctly perform
                                                    the tank gauging
                                                    operation. The
                                                    provision
                                                    specifically
                                                    references API 18.1
                                                    for tanks of 1,000
                                                    bbl or less;
                                                    however, the
                                                    procedure applies to
                                                    all tanks, including
                                                    those tanks with
                                                    capacities greater
                                                    than 1,000 bbl.
III. Requirements--D. Oil       43 CFR 3174.7 and  This proposed rule
 measurement by Positive         3174.8.            would require LACT
 Displacement Metering System.                      systems to use
                                                    electronic
                                                    temperature
                                                    averaging devices,
                                                    and would prohibit
                                                    the use of automatic
                                                    temperature/gravity
                                                    compensators. This
                                                    proposed rule would
                                                    require operators,
                                                    within 24 hours, to
                                                    notify the AO of any
                                                    LACT system failures
                                                    or equipment
                                                    malfunctions, or
                                                    other failures that
                                                    could adversely
                                                    affect oil
                                                    measurement.
None..........................  43 CFR 3174.9 and  This proposed rule
                                 3174.10.           would allow the use
                                                    of CMSs for the
                                                    measurement of oil
                                                    and would add
                                                    sections on CMS
                                                    component and
                                                    operating
                                                    requirements.
III. Requirements--D. 3. Sales  43 CFR 3174.11...  This proposal would
 Meter Proving Requirements.                        change the oil
                                                    volume proving
                                                    requirements to
                                                    require proving for
                                                    every 50,000 bbl of
                                                    volume that flows
                                                    through the meter,
                                                    or quarterly,
                                                    whichever occurs
                                                    first. The proposed
                                                    rule would also
                                                    establish
                                                    requirements for the
                                                    sizing of pipe
                                                    provers, define the
                                                    conditions under
                                                    which proving must
                                                    occur, and include
                                                    verification of
                                                    pressure and
                                                    temperature
                                                    measurement devices.
None..........................  43 CFR 3174.12...  This proposed rule
                                                    would require oil
                                                    measurement tickets
                                                    and specify minimum
                                                    information
                                                    requirements
                                                    contained on the
                                                    tickets. These
                                                    requirements appear
                                                    in the current
                                                    Onshore Oil and Gas
                                                    Order No. 3 (Order
                                                    3). Three new
                                                    requirements would
                                                    be added. Operators
                                                    would be required
                                                    to: (1) Include BLM-
                                                    approved Facility
                                                    Measurement Point
                                                    (FMP) numbers on
                                                    each measurement
                                                    ticket; (2) Notify
                                                    the AO within 2 days
                                                    if the operator
                                                    disagrees with the
                                                    tank gauger's
                                                    measurement; and (3)
                                                    Fill out measurement
                                                    tickets for LACT
                                                    systems and CMSs.
                                                    The proposed rule
                                                    would allow the use
                                                    of electronic
                                                    measurement tickets.

[[Page 58956]]

 
III. Requirements--E. Oil       43 CFR 3174.13...  This proposed rule
 Measurement by Other Methods                       would remove
 or at Other Locations                              language concerning
 Acceptable to the Authorized                       measurement on and
 Officer, 1. and 2.                                 off the lease, which
                                                    would be moved to
                                                    the new proposed
                                                    rule to replace
                                                    Order 3. See
                                                    proposed subpart
                                                    3173 (80 FR 40768,
                                                    July 13, 2015). It
                                                    also proposes that
                                                    all alternate
                                                    measurement system
                                                    approval requests be
                                                    reviewed by the PMT.
F. Determination of Oil         43 CFR 3174.14...  The proposed rule
 Volumes by Methods Other Than                      would retain the
 Measurement.                                       requirements of
                                                    Order 4 with respect
                                                    to determining
                                                    volumes of oil that
                                                    cannot be measured
                                                    as a result of
                                                    spillage or leakage.
None..........................  43 CFR 3174.15...  This proposed rule
                                                    would add six new
                                                    violations as
                                                    follows, each of
                                                    which would be
                                                    subject to an
                                                    immediate assessment
                                                    of $1,000: (1) Any
                                                    required FMP LACT
                                                    system components
                                                    missing or
                                                    nonfunctioning; (2)
                                                    Failure to notify
                                                    the AO within 24
                                                    hours of any FMP
                                                    LACT system failure
                                                    or equipment
                                                    malfunction
                                                    resulting in use of
                                                    an unapproved
                                                    alternate method of
                                                    measurement; (3) Any
                                                    required FMP CMS
                                                    components missing
                                                    or nonfunctioning;
                                                    (4) Failure to
                                                    notify the AO within
                                                    7 days of any
                                                    changes to any CMS
                                                    internal calibration
                                                    factors; (5) Failure
                                                    to meet the proving
                                                    frequency
                                                    requirements for an
                                                    FMP; and (6) Failure
                                                    to obtain a written
                                                    variance approval
                                                    before use of any
                                                    oil measurement
                                                    method other than
                                                    manual tank gauging,
                                                    LACT system, or CMS
                                                    at an FMP.
IV. Variances from Minimum      No section in      See proposed new 43
 Standards.                      this proposed      CFR 3170.6 (80 FR
                                 rule.              40778, July 13,
                                                    2015).
------------------------------------------------------------------------

IV. Section-by-Section Analysis

    This proposed rule would be codified primarily in a new 43 CFR 
subpart 3174 within a new part 3170. The BLM is concurrently preparing 
a separate proposed rule to update and replace Onshore Oil and Gas 
Order No. 5 (Order 5) (gas measurement) that the BLM intends to codify 
at a new 43 CFR subpart 3175. The BLM has previously published a 
separate proposed rule to replace Onshore Oil and Gas Order No. 3 
(Order 3) (site security), which the BLM would codify at a new 43 CFR 
subpart 3173. Given this structure, it is the BLM's intent that a new 
43 CFR subpart 3170 would contain definitions of certain terms common 
to more than one of the proposed rules, as well as other provisions 
common to all rules, i.e., provisions prohibiting by-pass of and 
tampering with meters; procedures for obtaining variances from the 
requirements of a particular rule; requirements for recordkeeping, 
records retention, and submission; and administrative appeal 
procedures. Subpart 3170 was proposed previously in conjunction with 
proposed subpart 3173 (80 FR 40768, July 13, 2015). All of the 
definitions and substantive provisions of proposed subpart 3170 would 
apply to the new subpart 3174 proposed here.
    Certain provisions of this proposed rule would result in amendments 
to related provisions in the onshore oil and gas operations rules in 43 
CFR part 3160. The proposed amendments to those provisions are 
discussed below.

Subpart 3174 and Related Provisions

Sec.  3174.1 Definitions and Acronyms

    Section 3174.1 would define the terms and acronyms that are used in 
proposed subpart 3174. With the proposal to integrate new technology 
into the rule, such as the use of CMSs, related definitions would need 
to be added to the proposed regulations. Defining these terms and 
acronyms is necessary to ensure consistent interpretation and 
implementation of this proposed rule. As such, the proposed rule would 
add a definition of ``Coriolis measurement system,'' and define the 
primary components of a CMS. Related definitions would be added to 
establish the minimum required components of an event log, a 
configuration log, and a quantity transactions record. Definitions for 
technical terms, such as ``opaque oil,'' ``RTD,'' and ``turbulent 
flow,'' would be added because they may not be readily understood. 
Definitions of many of the terms already defined in Order 4 are also 
included in this proposed rule.

Sec.  3174.2 General Requirements

    Paragraphs (a) through (d) of proposed Sec.  3174.2 refer the 
reader to other sections in this proposed rule that contain the 
proposed requirements for oil storage tanks, on-lease oil measurement, 
commingling, and FMP numbers, respectively.
    Proposed Sec.  3174.2(e) would specify that all equipment used to 
measure the volume of oil for royalty purposes installed after the 
effective date of this subpart must comply with the requirements of 
this subpart. Operators would have 180 days after the effective date of 
the final rule to bring existing equipment used to measure oil for 
royalty purposes installed before the effective date of the final rule 
into compliance with the proposed requirements of this subpart. With 
respect to the proposed compliance phase-in period of 180-days for 
existing equipment, the BLM would be interested in receiving comments 
and information about the lead-time required to order, install, and 
configure any new equipment that might be required at existing 
facilities as result of the proposed rule's requirements.
    Proposed Sec.  3174.2(f) would exempt meters used for allocation 
measurement as part of a commingling approval granted under a new 43 
CFR 3173.14 from complying with the requirements of this subpart. The 
new 43 CFR 3173.14 has been proposed under a separate rulemaking that 
would update and replace Order 3 (site security). In the restricted 
circumstances under which commingling would be approved under that 
proposed provision, it would no longer be necessary for allocation 
meters to meet the standards of either the current or proposed oil 
measurement and gas measurement rules.

Sec.  3174.3 Specific Measurement Performance Requirements

    Proposed Sec.  3174.3(a)(1) would set overall performance standards 
for measuring oil produced from Federal and Indian leases, regardless 
of the type of meters or measurement method used. Order 4 has no 
explicit statement of performance standards. The BLM would apply the 
performance standards to individual LACT meters or CMSs as part of the 
compliance process. This would

[[Page 58957]]

accommodate the range of meters and related equipment available to 
operators. The performance goals could result in operating limitations 
(such as a minimum flow rate through the meter); however, they could 
also allow flexibility for various operational functions (for example, 
the range of error between the meter in the field and the meter prover 
between successive runs during a proving). To facilitate this, the BLM 
is considering the development of an uncertainty calculator similar to 
the BLM's gas uncertainty calculator currently in use. The performance 
standards would also provide specific objective criteria with which the 
BLM could analyze variance requests for meters, measurement systems, 
and procedures not specifically addressed in the proposed rule.
    Proposed Sec.  3174.3(a)(1) would establish the maximum allowable 
volume measurement uncertainty. Uncertainty indicates the risk of 
measurement error. The BLM believes that the measurement uncertainties 
discussed below are reasonable, based on equipment capabilities, 
industry standard practices and procedures, and BLM field experience. 
Please specifically comment on whether other volume measurement 
uncertainties would be more appropriate for the range of meters and 
related equipment currently in use on Federal lands.
    For FMPs measuring more than 10,000 bbl per month, the maximum 
proposed overall volume measurement uncertainty would be 0.35 percent. The BLM derived the proposed 0.35 
percent uncertainty by calculating the implied uncertainty for a PD 
meter meeting the minimum requirements of Order 4. The implied 
uncertainty calculation includes the effects of the maximum allowable 
meter-factor drift between meter provings; the minimum standard for 
repeatability during a proving; the accuracy of the pressure and 
temperature transducers used to determine the correction for pressure 
on liquids (CPL) and the correction for temperature on liquids (CTL) 
factors; and the uncertainty of the CPL and CTL calculation. Based on 
this analysis, the overall uncertainty of a PD meter complying with 
Order 4 is 0.32 percent. Therefore, the BLM believes a 
0.35 percent uncertainty requirement is reasonable for both 
PD meters and CMS measurement at a 10,000-bbl-per-month threshold to 
ensure accurate royalty measurement for a high monthly volume.
    For FMPs measuring more than 100 bbl per month and less than or 
equal to 10,000 bbl per month, the maximum proposed overall measurement 
uncertainty would be 1.0 percent. The proposed 1.0 percent is based on the uncertainty calculations of manual 
tank gauging meeting the minimum requirements of Order 4, which show 
that uncertainty is dependent on the volume removed. The proposed 
1.0 percent is the average calculated uncertainty for a 
typical 100-200 bbl truck load-out.
    Based on comments from public meetings held on April 24 and 25, 
2013 (discussed below), the BLM is proposing a third tier for FMPs 
measuring less than 100 bbl per month. The proposed overall allowed 
uncertainty for the third tier would be 2.5 percent, which 
would still provide minimal risk of royalty loss, while allowing the 
maximum ultimate recovery from low-volume leases. The proposed 2.5 percent is the highest calculated uncertainty for manual tank 
gauging meeting the minimum requirements of Order 4.
    Under proposed Sec.  3174.3(a)(2), only a BLM State Director could 
grant an exception to the prescribed uncertainty levels. Granting an 
exception would require a showing that meeting the required uncertainly 
level would involve extraordinary cost or unacceptable adverse 
environmental effects, and the written concurrence of the BLM Director.
    Proposed Sec.  3174.3(b) would establish the degree of allowable 
bias in a measurement. Bias, unlike uncertainty, results in measurement 
error, whereas uncertainty only indicates the risk of measurement 
error. For all FMPs, no statistically significant bias would be 
allowed. (The BLM acknowledges that it is virtually impossible to 
completely remove all bias in measurement.) When a measurement device 
is tested against a laboratory device or prover, there is often slight 
disagreement, or apparent bias, between the two. However, both the 
measurement device being tested and the laboratory device or prover 
have some inherent level of uncertainty. If the disagreement between 
the measurement device being tested and the laboratory device or prover 
is less than the uncertainty of the two devices combined, then it is 
not possible to distinguish apparent bias in the measurement device 
being tested from inherent uncertainty in the devices (sometimes 
referred to as ``noise'' in the data). Therefore, the BLM does not 
consider apparent bias that is less than the uncertainty of the two 
devices combined to be statistically significant.
    Proposed Sec.  3174.3(c) would require that all measurement 
equipment allow for independent verification by the BLM. As with the 
bias requirements, Order 4 only allows measurement methods that can be 
independently verified by the BLM and, therefore, this requirement 
would not change existing requirements. The verifiability requirement 
in this section would prohibit the use of measurement equipment that 
does not allow for independent verification. For example, if a new 
meter were to be developed that did not record the raw data used to 
derive a volume, that meter could not be used at an FMP, because 
without the raw data the BLM would be unable to independently verify 
the volume. Similarly, if a meter were to be developed that used 
proprietary methods that precluded the ability to recalculate volumes, 
its use would also be prohibited.

Sec.  3174.4 Incorporation by Reference

    The proposed rule would incorporate a number of industry standards, 
either in whole or in part, without republishing the standards in their 
entirety in the CFR, a practice known as incorporation by reference. 
These standards were developed through a consensus process, facilitated 
by the API and the ASTM, with input from the oil and gas industry. The 
BLM has reviewed these standards and determined that they would achieve 
the intent of 43 CFR 3174.5 through 3174.13 of this proposed rule. The 
legal effect of incorporation by reference is that the incorporated 
standards become regulatory requirements. This proposed rule would 
incorporate the current versions of the standards listed.
    Some of the standards referenced in this section would be 
incorporated in their entirety. For other standards, the BLM would 
incorporate only those sections that are enforceable, meet the intent 
of Sec.  3174.3 of this proposed rule, or do not need further 
clarification.
    The proposed incorporation of industry standards follows the 
requirements found in 1 CFR part 51. Industry standards proposed for 
incorporation are eligible under 1 CFR 51.7 because, among other 
things, they will substantially reduce the volume of material published 
in the Federal Register; the standards are published, bound, numbered, 
and organized; and the standards proposed for incorporation are readily 
available to the general public through purchase from the standards 
organization or through inspection at any BLM office with oil and gas 
administrative responsibilities. 1 CFR 51.7(a)(3) and (a)(4). The 
language of incorporation in proposed 43 CFR 3174.4 meets the 
requirements of 1 CFR 51.9. Where appropriate, the BLM proposes to

[[Page 58958]]

incorporate an industry standard governing a particular process by 
reference and then impose requirements that are in addition to and/or 
modify the requirements imposed by that standard (e.g., the BLM sets a 
specific value for a variable where the industry standard proposed a 
range of values or options).
    All of the API and ASTM materials for which the BLM is seeking 
incorporation by reference are available for inspection at the BLM, 
Division of Fluid Minerals; 20 M Street SE., Washington, DC 20003; 202-
912-7162; and at all BLM offices with jurisdiction over oil and gas 
activities. The API materials are available for inspection at the API, 
1220 L Street NW., Washington, DC 20005; telephone 202-682-8000; API 
also offers free, read-only access to some of the material at 
www.publications.api.org. The ASTM materials are available for 
inspection at the ASTM, 100 Bar Harbor Drive, P.O. Box C700, West 
Conshohocken, PA 19428; telephone 1-877-909-2786; www.astm.org/Standard/index.shtml; ASTM also offers free read-only access to the 
material at www.astm.org/READINGLIBRARY/.
    The following describes the API and ASTM standards that the BLM 
proposes to incorporate by reference into this rule:
    API Manual of Petroleum Measurement Standards (MPMS) Chapter 2, 
Section 2A, Measurement and Calibration of Upright Cylindrical Tanks by 
the Manual Tank Strapping Method, 1st Ed., February 1995, Reaffirmed 
February 2012 (``API 2.2A''). This standard describes the procedures 
for calibrating upright cylindrical tanks used for storing oil.
    API MPMS Chapter 3, Section 1A, Standard Practice for the Manual 
Gauging of Petroleum and Petroleum Products, 3rd Ed., August 2013 
(``API 3.1A''). This standard describes the following: (a) The 
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 4, Section 1, Introduction, 3rd Ed., February 
2005, Reaffirmed June 2014 (``API 4.1''). Section 1 is a general 
introduction to the subject of proving meters. API MPMS Chapter 4, 
Section 2, Displacement Provers, 3rd Ed., September 2003, Reaffirmed 
March 2011 (``API 4.2,'' and ``API 4.2, Eq. 12''). This standard 
outlines the essential elements of meter provers that do, and also 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, Section 5, Master-Meter Provers, 3rd Ed., 
November 2011 (``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, Section 6, Pulse Interpolation, 2nd Ed., May 
1999, 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, Section 9, Part 2, Methods of Calibration for 
Displacement and Volumetric Tank Provers, Determination of the Volume 
of Displacement and Tank Provers by the Waterdraw Method of 
Calibration, 1st Ed., December, 2005, Reaffirmed September 2010 (``API 
4.9.2''). This standard covers all of 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, Section 6, Measurement of oil by Coriolis 
Meters, 1st Ed., October 2002, Reaffirmed November 2013 (``API 5.6,'' 
``API 5.6.3.2(e),'' API 5.6.8.3,'' ``API 5.6.9.1.2.1,'' and ``API 5.6, 
Eq. 2''). This standard is applicable to custody-transfer applications 
for liquid hydrocarbons. Topics covered are API standards used in the 
operation of Coriolis meters, proving and verification using volume-
based methods, installation, operation, and maintenance.
    API MPMS Chapter 6, Section 1, Lease Automatic Custody Transfer 
(LACT) Systems, 2nd Ed., 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, 1st Ed., June 2001, 
Reaffirmed February 2012 (``API 7'' and ``API 7.1''). This standard 
describes the methods, equipment, and procedures for determining the 
temperature of petroleum and petroleum products under both static and 
dynamic conditions.
    API MPMS Chapter 8, Section 1, Standard Practice for Manual 
Sampling of Petroleum and Petroleum Products, 4th Ed., 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 9, Section 3, Standard Test Method for Density, 
Relative Density, and API Gravity of Crude Petroleum and Liquid 
Petroleum Products by Thermohydrometer Method, 3rd Ed., December 2012 
(``API 9.3''). This standard covers the determination, using a glass 
thermohydrometer in conjunction with a series of calculations, of the 
density, relative density, or API gravity of crude petroleum, petroleum 
products, or mixtures of petroleum and nonpetroleum products normally 
handled as liquids and having a Reid vapor pressures of 101.325 kPa 
(14.696 psi) or less.
    API MPMS Chapter 10 Section 4, Determination of Water and/or 
Sediment in Crude Oil by the Centrifuge Method (Field Procedure), 4th 
Ed., October 2013 (``API 10.4,'' ``10.4.9,'' and ``10.4.9.2''). This 
standard describes the field centrifuge method for determining both 
water and sediment, or sediment only, in crude oil.
    API MPMS Chapter 11, Section 1, Temperature and Pressure Volume 
Correction Factors for Generalized Crude Oils, Refined Products and 
Lubricating Oils, 2nd Ed., May 2004, including Addendum 1, September 
2007, Reaffirmed August 2013 (``API 11.1''). This standard provides the 
algorithm and implementation procedure for the correction of 
temperature and pressure effects on density and volume of liquid 
hydrocarbons, which fall within the categories of crude oil.
    API MPMS Chapter 12, Section 2, Part 1, Calculation of Petroleum 
Quantities Using Dynamic Measurement Methods and Volumetric Correction 
Factors, 2nd Ed., May 1995, Reaffirmed March 2014 (``API 12.2.1''). 
This standard provides standardized calculation methods for the 
quantification of liquids and the determination of base prover volumes 
under defined conditions. The standard specifies the equations for 
computing correction factors, rules for rounding, calculational 
sequence, and discrimination levels to be employed in the calculations.

[[Page 58959]]

    API MPMS Chapter 12, Section 2, Part 3, Calculation of Petroleum 
Quantities Using Dynamic Measurement Methods and Volumetric Correction 
Factors, Proving Report, 1st Ed., October 1998, Reaffirmed March 2009 
(``API 12.2.3''). This standard provides standardized calculation 
methods for the determination of meter factors under defined 
conditions. The criteria contained here will allow different 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 document 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, Section 2, Part 4, Calculation of Petroleum 
Quantities Using Dynamic Measurement Methods and Volumetric Correction 
Factors, Calculation of Base Prover Volumes by the Waterdraw Method, 
1st Ed., December, 1997, Reaffirmed March 2009 (``API 12.2.4''). This 
standard provides standardized calculation methods for the 
quantification of liquids and the determination of base prover volumes 
under defined conditions. The criteria contained in this document 
allows different 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 18, Section 1, Measurement Procedures for Crude 
Oil Gathered From Small Tanks by Truck, 2nd Ed., April 1997, Reaffirmed 
February 2012 (``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, Section 2, Electronic Liquid Volume 
Measurement Using Positive Displacement and Turbine Meters, 1st Ed., 
June 1998, Reaffirmed August 2011 (``API 21.2,'' ``API 21.2.10,'' 
``21.2.10.2,'' ``21.2.10.6,'' and ``API 21.2.9.2.13.2a''). This 
standard provides for the effective utilization of electronic liquid 
measurement systems for custody-transfer measurement of liquid 
hydrocarbons.
    API Recommended Practice (RP) 12 R1, Setting, Maintenance, 
Inspection, Operation and Repair of Tanks in Production Service, 5th 
Ed., August 1997, Reaffirmed April 2008 (``API RP 12 R1''). This 
recommended practice is a guide on new tank installations and 
maintenance of existing tanks. Specific provisions of this recommended 
practice are identified as requirements in this proposed rule.
    API RP 2556, Correction Gauge Tables For Incrustation, 2nd Ed., 
August 1993, Reaffirmed August 2013 (``API RP 2556''). This recommended 
practice provides for correcting gauge tables for incrustation applied 
to tank capacity tables. The tables given in this recommended practice 
show the percent of error of measurement caused by varying thicknesses 
of uniform incrustation in tanks of various sizes.
    ASTM D-1250, Table 5A, Generalized Crude Oils Correction of 
Observed Gravity to API Gravity at 60o F, September 1980 (``ASTM Table 
5A''). Table 5A gives the values of API gravity at 60o F corresponding 
to an API hydrometer reading at observed temperatures other than 60o F.

Sec. Sec.  3174.5 and 3174.6 Oil Measurement by Manual Tank Gauging--
Procedures

    Proposed Sec.  3174.5(a) would provide that measurement by manual 
tank gauging must accurately compute the total net standard volume of 
oil withdrawn from a properly calibrated sales tank by following a 
proper sequence of activities outlined in Sec.  3174.6.
    Proposed Sec.  3174.5(b) would include requirements that all oil 
storage tanks, hatches, connections, and other access points be vapor 
tight and that all venting occur through a pressure-vacuum relief valve 
placed in the vent line or in the connection with another tank. This 
requirement would minimize hydrocarbon gas lost to the atmosphere by 
ensuring that venting is done under controlled conditions through the 
pressure-vacuum relief valve primarily in response to changes in 
ambient temperature. This requirement would be added to eliminate 
confusion over the intent of the language in Order 4 in this area. This 
change would expressly state the required condition--vapor-tight with a 
pressure-vacuum integrity device. This section would further clarify 
that each storage tank be clearly identified by a unique number. Other 
existing requirements in Order 4 are included in this proposed section, 
namely, that each oil storage tank must be set and maintained level and 
must be equipped with a distinct gauging reference point.
    Proposed Sec.  3174.5(c) would retain the current Order 4 
requirement that oil storage tanks associated with an FMP that are 
measured by tank gauging be accurately calibrated, and would include 
additional specifics regarding calibration requirements. Proposed Sec.  
3174.5(c)(1) would specify that the tank capacity tables must be 
calculated by actual tank measurements, which would eliminate using 
general formulas, such as the formula created for calculating the 
volume of a typical 400 bbl tank using 1.67 bbl/inch. This proposed 
paragraph would specify that the volume be measured in barrels and 
change the incremental height measurement from the current \1/4\ inch 
to \1/8\ inch when calculating the capacity tables. This change would 
match the gauging accuracy changes from the current Order 4 gauging of 
\1/4\ inch to the proposed \1/8\ inch gauging accuracy, which would 
match the current industry standard.
    Proposed Sec.  3174.5 paragraph (c)(2) and (3) would retain the 
current Order 4 requirement that storage tanks associated with an FMP 
and measured by tank gauging be recalibrated if they are relocated, 
repaired, or the capacity is changed as a result of denting, damage, 
installation, removal of interior components, or other alterations. 
However, instead of the existing requirement that operators submit 
sales tank calibration charts upon request from the AO, they would be 
required to submit the charts to the AO within 30 days after 
calibration. This proposed change would ensure that BLM personnel use 
the latest charts when conducting inspections or audits.
    Proposed Sec.  3174.6(a) would list the proper sequence of 
activities for measuring oil by manual tank gauging along with the 
corresponding section reference. The BLM is proposing the sequence 
listed in the API Manual of Petroleum Measurement Standards (MPMS) 
Chapter 18.1 for all size tanks that would be used as FMPs. API MPMS 
18.1 specifically covers tank sizes of 1,000 bbl or less, but the most 
recent edition of the API standards referenced in MPMS 18.1 has removed 
many of the procedural differences between the tank sizes, making this 
sequence acceptable for tanks of all sizes.
    Proposed Sec.  3174.6(b)(1) would retain the current Order 4 
requirement that tanks must be isolated for 30 minutes to allow for 
tank contents to settle before proceeding with tank gauging operations.
    Proposed Sec.  3174.6(b)(2) would change the requirements for 
determining the temperature of oil in a sales tank that is used as an 
FMP. The minimum thermometer immersion times listed in API MPMS Chapter 
18.1 and in API

[[Page 58960]]

MPMS Chapter 7 would be used, which would vary depending on the oil API 
oil gravity, whether the thermometer is stationary or in motion, and 
whether the thermometer was electronic or mechanical (wood-back).
    Proposed Sec.  3174.6 paragraphs (b)(3) through (9) would follow 
API MPMS chapter 18.1, the industry standard, in prescribing the 
procedure for conducting the step-by-step process of manual tank 
gauging and the proper equipment usage. This is a change from Order 4, 
which lists the equipment required, but not the proper sequence of 
processes. The gauging measurement accuracy would be changed from the 
current Order 4 requirement of \1/4\ inch gauging accuracy to \1/8\ 
inch gauging accuracy. This change is proposed to match industry 
standards that now indicate gauging should be accurate to within \1/8\-
inch.
    Proposed Sec.  3174.6(b)(10) would list the proper documentation of 
a measurement ticket, to provide for consistent documentation and 
ensure that the operator uses the correct reference material.

Sec.  3174.7 LACT System--General Requirements

    Proposed Sec.  3174.7 paragraphs (a) through (c) would refer to 
other sections of this proposed rule for construction and operation 
requirements for LACT systems, proving requirements, and measurement 
tickets, and would provide a table of the LACT system requirements and 
corresponding section references.
    Proposed Sec.  3174.7 paragraphs (d) through (f) would retain 
current requirements that all components of a LACT system be accessible 
for inspection by the AO and that the AO must be notified of all LACT 
system failures that may have resulted in measurement error. The 
proposed rule would modify this notification requirement to put a 24-
hour time limit on the notification. This would be added to ensure that 
the BLM is able to verify that all oil volumes are properly derived and 
accounted for, and verify any alternative measurement method, meter 
repairs, or meter provings. This proposed rule would retain the current 
Order 4 requirement that all oil samples taken from the LACT system 
samplers for determination of temperature, oil gravity, and sediment 
and water (S&W) content must meet the same minimum standards set in the 
manual tank gauging sections.
    Proposed Sec.  3174.7(g) would prohibit the use of Automatic 
Temperature Compensators (ATCs) and Automatic Temperature and Gravity 
Compensators (ATGs) on LACT systems. Order 4 requires these devices. 
Instead, the proposed rule would require the use of an electronic 
temperature averaging device. ATCs and ATGs are designed to 
automatically adjust the LACT totalizer reading to compensate for 
changes in temperature and, in some cases, for changes in oil gravity 
as well. Unfortunately, the accuracy or operation of these devices 
cannot be verified in the field and there is no record of the original, 
uncorrected, totalizer readings. Therefore, the BLM believes that the 
use of these devices inhibits its ability to verify the reported 
volumes because there is no source record generated and they degrade 
the accuracy of measurement. Because there are relatively few LACT 
systems that still employ ATCs or ATGs, the BLM does not believe this 
requirement would result in significant costs to the industry.

Sec.  3174.8 LACT System--Components and Operating Requirements

    Proposed Sec.  3174.8, with the exception of proposed Sec.  
3174.8(b)(11), would contain the same LACT system components and 
operating requirements as Order 4.
    Proposed Sec.  3174.8(b)(11) would establish requirements for 
electronic temperature averaging devices, using API standards where 
available. Order 4 does not address electronic temperature averaging 
devices.

Sec. Sec.  3174.9 and 3174.10 Coriolis Measurement Systems

    Proposed Sec. Sec.  3174.9 and 3174.10 would create new sections 
for CMSs, which are not addressed in Order 4. Order 4 allows only for 
the use of PD meters with LACT systems. The proposal to allow the use 
of Coriolis meters in this rule is based on technological advancements 
that provide for measurement accuracy that meets or exceeds the overall 
performance standards in proposed Sec.  3174.3. Field and laboratory 
testing of the Coriolis meter has proven it to be a reliable, accurate 
meter when installed, configured, and operated correctly.
    Proposed Sec.  3174.9 paragraphs (a) through (c) would specify that 
CMSs must consist of components that have been reviewed by the PMT, 
approved by the BLM, and identified and described on the nationwide 
approval list at www.blm.gov. Installations meeting the proposed 
standards described in this section, Sec.  3174.10, and API 5.6 
(incorporated by reference) would not require additional BLM approval. 
CMS proving must meet the proving requirements described in proposed 
Sec.  3174.11 and measurement tickets would be required, as described 
in proposed Sec.  3174.12(b).
    Proposed Sec.  3174.9(d) would provide a table of the requirements, 
section reference, and applicable API standards under which oil 
measurement under a CMS must follow.
    Proposed Sec.  3174.9(e) would list the components in order from 
upstream to downstream of a CMS used at an FMP. The requirements for a 
CMS would generally parallel the requirements for LACT systems.
    Proposed Sec.  3174.9(e)(1) through (4) would parallel the LACT 
system equipment requirements and are needed to ensure accurate and 
proper functioning of a CMS. A charge pump may be necessary to maintain 
required pressure and flow rate to achieve uncertainty levels proposed 
under Sec.  3174.3(a). A block valve upstream of the meter would be 
required for zero value verification. An air/vapor eliminator would be 
required upstream of the meter.
    Proposed Sec.  3174.9(e)(5) through (6) would set accuracy 
thresholds for temperature and pressure measurement devices that are 
part of a CMS installed downstream of the meter, but upstream of the 
proving connections. These devices are needed to calculate the CPL and 
CTL factors. The uncertainties of these devices would be used to ensure 
the CMS meets or exceeds the uncertainty levels that would be required 
by proposed Sec.  3174.3(a). Under proposed Sec.  3174.9(e)(7), a 
density measurement verification point would follow the temperature and 
pressure measurement devices.
    Proposed Sec.  3174.9(e)(8) would not require a composite sampling 
system if the S&W content is not used to determine net oil volume. 
Measurement using a PD meter requires a composite sampling system and 
determines net oil volume by deducting S&W content. In contrast, 
Coriolis meters do not necessarily use S&W content in determining net 
oil volume. In practice, Coriolis meters may be used at the outlet of a 
separator. It may not be feasible to use a composite sampling system at 
the outlet of a separator due to high separator pressure, thus 
effectively precluding the use of a PD meter at that location. This is 
because the lack of a composite sampling system would eliminate the 
ability to determine S&W content through the traditional centrifuge 
procedures proposed in Sec.  3174.6(b)(6). Without the ability to 
accurately determine S&W content, proposed Sec.  3174.9(e)(9) would 
require operators to report the S&W content as zero, should they choose 
to use a CMS

[[Page 58961]]

at the outlet of a separator. The BLM may consider a variance to use 
other methods to determine S&W content should acceptable technology or 
processes be proposed in the future. However, the BLM would only 
approve an alternate method of S&W determination if resulting overall 
measurement uncertainty was within the limits proposed in Sec.  
3174.3(a).
    Proposed Sec.  3174.9 paragraphs (e)(9), (10), and (11) would 
parallel the meter proving connections, back-pressure valve, and check 
valve requirements for LACT systems.
    Proposed Sec.  3174.10(a) would establish a minimum pulse 
resolution (i.e., the increment of total volume that can be 
individually recognized, measured in pulse per unit volume) of 8,400 
pulses per barrel for CMSs. Because this resolution is standard for PD 
meters, and is accepted by the BLM, the same standard would apply to 
CMSs. The BLM originally considered a minimum pulse resolution of 
10,000 pulses per barrel; however, this was reduced to 8,400 pulses per 
barrel based on comments received in response to the public meeting 
held on April 24 and 25, 2013 (see comments at the end of the 
discussion on major proposed changes).
    Proposed Sec.  3174.10 paragraphs (b), (c), (d), and (e) would 
establish minimum standards for the specifications for a specific make, 
model, and size of a Coriolis meter. The specifications would allow the 
BLM to determine the overall measurement uncertainty of the CMS to 
ensure that it meets the requirements of proposed Sec.  3174.3(a). The 
specifications would also help ensure that the meters are properly 
installed, require that the BLM be notified of any changes to any of 
the internal calibration factors, and require a non-resettable 
totalizer for registered volume.
    Proposed Sec.  3174.10(f) would require verification of the meter 
zero reading before proving the meter or any time the AO requests it. 
This would be accomplished by shutting off the flow and observing the 
flow rate indicated by the CMS. If the indicated flow rate is within 
the manufacturer's specifications for zero stability, then the zero 
error would be accounted for in the uncertainty calculation and no 
adjustments would be required. However, if the indicated flow rate was 
outside the manufacturer's specification for zero stability, the 
meter's zero reading would be required to be adjusted.
    Proposed Sec.  3174.10(g) would establish the method by which a CMS 
determines net oil volume on which royalty is due. Most CMSs include 
advanced software features that can automatically calculate net oil 
volume. However, in order to allow the BLM to independently re-
calculate net oil volume, the proposed provision would establish a 
calculation method similar to that used for PD meters. This would allow 
for manual re-calculation and verification by the BLM, without relying 
on algorithms internal to the CMS.
    Proposed Sec.  3174.10(h) would allow the API oil gravity to be 
determined by using one of two methods: (a) Directly from the average 
density measured by the Coriolis meter; or (b) A sample taken from a 
composite sample container. This would accommodate situations in which 
it is not feasible to install a composite sampling system due to 
economic or operating constraints. The BLM recognizes that high amounts 
of water in the oil would affect the average density determined by the 
Coriolis meter, which could in turn affect the value of the oil used to 
determine royalty due. However, because the BLM would not allow an S&W 
adjustment in situations where a composite sampling system was not 
used, we believe the increase in the measured and reported volume on 
which royalty is due would offset any value reductions due to the water 
content. The operator would determine whether to install a composite 
sampling system. The BLM specifically seeks comments on this proposed 
approach.
    Proposed Sec.  3174.10 paragraphs (i), (j), and (k) would establish 
minimum requirements for the information that the operator would need 
to maintain on-site, information that must be retained for an audit 
trail, and requirements for protecting the retained data in the CMS 
unit's memory. This information is necessary for the BLM to ensure 
compliance with these regulations and conduct production audits.

Sec.  3174.11 Meter Proving Requirements

    Proposed Sec.  3174.11 paragraphs (a) and (b) would establish that 
a meter would not be eligible to be used for royalty determination 
unless it is proven by the standards detailed in this proposed rule. A 
summary table is provided of the minimum standards for proving FMP 
meters and their applicable section reference.
    Proposed Sec.  3174.11(c) would establish the acceptable types of 
provers that could be used to prove a LACT or CMS.
    Proposed Sec.  3174.11 paragraphs (c)(1), (2), and (3) would 
describe and detail the requirements for acceptable meter provers, 
which include the master meters and displacement provers that are 
currently allowed under Order 4. (A meter prover is a device that 
verifies a meter's accuracy.) Coriolis master meters have been added, 
which were not addressed in Order 4. The BLM believes that Coriolis 
technology has advanced to the point where Coriolis meters can meet the 
accuracy requirements required for master meters. The proposed rule 
would not allow tank-provers to be used as an acceptable device for 
proving a meter. According to API standards, tank-provers are not 
recommended for viscous liquids, which include most crude oil. Because 
there are few tank-provers currently in use on Federal and Indian 
leases, this requirement is not expected to result in a significant 
cost to industry.
    Proposed Sec.  3174.11(c)(4) would establish displacement prover 
sizing standards. These standards would ensure that fluid velocity 
within the prover is within the limits recommended by API MPMS Chapter 
4.2.4.3.4. Displacement velocities that are too low (prover is 
oversized) can result in unacceptable pressure and flow-rate changes 
and higher uncertainty due to possible displacement device ``chatter.'' 
Displacement velocities that are too high (prover is undersized) can 
cause damage to the components of the prover.
    Proposed Sec.  3174.11(d)(1) would expand on the current Order 4 
requirement to prove the meter under ``normal'' operating conditions. 
This section would define limits of flow rate, pressure, and API oil 
gravity that must exist during the proving to be considered the 
``normal'' operating condition. The BLM proposes to add this 
requirement because the BLM realizes that the meter factor can change 
with changes in these parameters. For example, a meter factor 
determined at an abnormally low flow rate may not represent the meter 
factor at a higher flow rate where the meter normally operates. This 
proposed section would also require a multi-point meter proving if the 
LACT or CMS were subject to highly variable conditions. The multi-point 
meter proving would establish three meter factors; one at the low end 
of the normal operating range, one at the midpoint, and one at the high 
end. An appropriate meter factor would then be applied according to 
proposed Sec.  3174.11(d)(6).
    Proposed Sec.  3174.11 paragraphs (d)(2) through (5) would provide 
the details for minimum proving requirements, such as requiring a 
minimum proving pulse resolution of 10,000 pulses per proving run or 
requiring the use of pulse interpolation, if this cannot be met, and 
setting a requirement to continue

[[Page 58962]]

repeating proving runs until the calculated meter factor from five 
consecutive runs is within a 0.05 percent tolerance between the highest 
and lowest value. The new meter factor would be the arithmetic average 
of the five meter factors from the five consecutive proving runs. This 
section also would require the meter factors to be calculated following 
the sequence described in API MPMS Chapter 12.2.3.
    Proposed Sec.  3174.11(d)(6) would allow two methods of 
incorporating multiple meter factors that would be required under 
proposed Sec.  3174.11(d)(1)(iv). The first method would be to combine 
the meter factors into a single arithmetic average. The second method 
would be to curve-fit the meter factors and incorporate a real-time 
dynamic meter factor into the flow computer (this would apply primarily 
to CMS). Neither multi-point provings nor multi-point meter factors are 
discussed in Order 4. Please specifically comment on proposed Sec.  
3174.11 paragraphs (d)(1)(iv) and (d)(6) regarding how to handle meter 
factor determinations when the LACT or CMS experiences highly variable 
flow rates, pressures, or API oil gravities.
    Proposed Sec.  3174.11 paragraphs (d)(7) and (8) would set the 
minimum and maximum values that would be allowed for a meter factor, 
both between meter provings and for initial meter factors for newly 
installed or repaired meters. These meter factor ranges are not changed 
from Order 4.
    Proposed Sec.  3174.11(d)(9) would allow back-pressure valve 
adjustment after proving only within the normal operating fluid flow 
rate and fluid pressure as prescribed in proposed Sec.  3174.11(d)(1). 
If the back-pressure valve is adjusted after proving, the ``as left'' 
fluid flow rate and fluid pressure would have to be documented on the 
proving report. The BLM is proposing this requirement because the BLM 
has observed this practice frequently in certain areas of the country 
and has observed that a change in back-pressure outside the proving 
conditions does, in some cases, affect the meter factor and results in 
operators reporting incorrect volumes. Allowing back-pressure valve 
adjustment after proving would not be intended as a means to circumvent 
the displacement prover minimum and maximum velocity requirements of 
proposed Sec.  3174.11(c)(4). Order 4 has no specific requirements 
relating to the adjustment of the back-pressure valve after proving.
    Proposed Sec.  3174.11(d)(10) would set standards for the pressure 
used to calculate a CPL for a composite meter factor for LACTs. It 
would also prohibit the use of a composite meter factor for Coriolis 
meters because they have the capability to use a true average pressure 
over the measurement ticket period in the calculation of an average 
CPL. The use of a composite meter factor is intended to make 
measurement tickets easier to complete because the CPL is already 
included in the meter factor. This is typically not an issue with a 
Coriolis meter because of the advanced capability of the flow computer 
to which it is connected.
    Proposed Sec.  3174.11(e) contains a new provision for meter-
proving requirements that were previously located in the LACT section 
of Order 4. This change would consolidate in one place all meter-
proving requirements for both LACTs and CMSs. The proposal would change 
FMP meter-proving requirements for operators who run large volumes of 
oil through their meters. Currently, an FMP meter must be proven at 
least quarterly, unless total throughput exceeds 100,000 bbl per month, 
in which case the meter must be proven monthly. This proposal would 
require operators to prove an FMP meter each time the volume flowing 
through the meter, as measured on the non-resettable totalizer, 
increases by 50,000 bbl, or quarterly, whichever occurs first. This 
change to meter provings would affect approximately 5 percent of 
existing LACT systems nationwide, yet would ensure that meter-factor 
changes are corrected before large volumes of production are measured 
incorrectly, which could have an adverse impact on Federal or Indian 
royalty determinations.
    The proposed 50,000 bbl threshold was determined by performing a 
statistical analysis to determine the volume at which the cost of 
proving the meter could be equal to the amount of potential royalty 
underpayment or overpayment that could occur, due to the difference in 
meter factors. This section also proposes to expand the current Order 4 
requirement from proving after repair to proving any time after the 
mechanical or electrical components of the meter have been opened, 
changed, repaired, removed, exchanged, or reprogrammed.
    Proposed Sec.  3174.11(f) would not change Order 4 requirements for 
excess meter factor deviation and the required actions if proving 
reflects a deviation in meter factor that exceeds 0.0025.
    Proposed Sec.  3174.11 paragraphs (g) and (h) would require that 
the temperature and pressure devices used as part of a LACT or CMS be 
verified as part of every proving. These sections would establish 
standards for the verification procedure and the test equipment used in 
the verification.
    Proposed Sec.  3174.11(i) would require verification of the density 
measurement function of the Coriolis meter under API MPMS Chapter 
5.6.9.1.2.1 if measured density is used to determine API oil gravity 
(instead of a thermohydrometer, which is generally required under 
proposed Sec.  3174.6(b)(4)). This would provide an independent 
verification that the Coriolis meter's density determination function 
is within the accuracy specifications for that meter.
    Proposed Sec.  3174.11(j) would prescribe meter-proving reporting 
requirements. This section would provide additional requirements for 
data that would need to be included on the meter-proving report beyond 
what is required under Order 4. One change would require operators to 
list the BLM-assigned FMP numbers on each proving report. Proposed 
Sec.  3174.11 includes requirements for verification of the temperature 
average or RTD, verification of the pressure transducer, and density 
verification, as applicable, as well as any ``as left'' conditions 
after adjustment of the back-pressure valve that operators also would 
have to document on the proving report.

Sec.  3174.12 Measurement Tickets

    Proposed Sec.  3174.12 would specify the measurement ticket (run 
ticket) requirements that are currently in Order 3. The BLM believes 
that measurement ticket requirements are better suited to this proposed 
rule than to the rule that the BLM has proposed separately to replace 
Order 3, because this proposed rule specifies the requirements for the 
data that is recorded on oil measurement tickets. This section details 
the specific data requirements for measurement tickets based on which 
method of oil measurement is used, i.e., manual tank gauging, LACT 
system, or CMS.
    This rule proposes five changes to Order 3's current measurement-
ticket requirements. One of those changes would require operators to 
list the BLM-assigned FMP numbers on each measurement ticket. This is 
to incorporate the new approval requirement for assigned FMPs included 
in the separately published proposed rule to replace Order 3. The 
second change would require operators to notify the BLM whenever they 
disagree with data documented on a measurement ticket. This is to allow 
the BLM to investigate the alleged discrepancy and potential impacts on 
Federal or Indian royalty determinations. The third change would 
require the operator, purchaser, or

[[Page 58963]]

transporter, as appropriate, to fill out measurement tickets whenever a 
LACT system or CMS is proven and at least monthly. This would provide 
an audit trail for oil measured through a LACT system. The fourth 
change would allow the submission of electronic run tickets in lieu of 
paper run tickets. The fifth and final change would require the 
resetting of totalizers (accumulators) used to determine average 
pressure and average temperature whenever a measurement ticket is 
closed. This would ensure that the averages used for the calculation of 
CPL, CTL, and density only reflect the data measured and recorded since 
the opening of the measurement ticket.

Sec.  3174.13 Oil Measurement by Other Methods

    Proposed Sec.  3174.13(a) would provide that using any method of 
oil measurement other than manual tank gauging, LACT system, or CMS at 
an FMP would require BLM approval. Under proposed Sec.  3174.13(b), the 
BLM would use the PMT as a central advisory body within the BLM to 
review and recommend approval of industry measurement technology not 
addressed in the proposed regulations. The PMT is made up of a panel of 
BLM employees who are oil and gas measurement experts.
    The process outlined in proposed Sec.  3174.13(b) for reviewing new 
equipment would allow the BLM to keep up with technology as it advances 
and approve its use without having to update its regulations. Under the 
proposed rule, if the PMT recommends, and the BLM approves, new 
equipment, the BLM would post the make, model, and range or software 
version on the BLM Web site www.blm.gov as being appropriate for use at 
an FMP for oil measurement going forward, i.e., subsequent users of the 
technology would not have to go through the PMT process. The web 
posting identifying the equipment or technology would include, as 
appropriate, conditions of use.
    The PMT would consider new measurement technologies on a case-by-
case basis. Proposed Sec.  3174.13(b) would identify the requirements 
for requesting approval of oil measurement by equipment other than 
equipment listed in this proposed rule. The BLM believes this process 
would be used as other technologies appear and their reliability is 
established. For example, the BLM considered other meters for inclusion 
in this proposed rule, such as turbine meters and ultrasonic meters; 
however, it ultimately decided not to include them in this rule because 
there is insufficient testing to validate their accuracy and 
reliability under all operating conditions at this time.
    Proposed Sec.  3174.13(c) would expressly provide that the 
procedures for requesting and granting a variance under Sec.  3170.6 
could not be used as an avenue for approving new technology or 
equipment. An operator could obtain approval of alternative oil 
measurement equipment or methods only through review, recommendation, 
and approval by the PMT under proposed Sec.  3174.13.

Sec.  3174.14 Determination of Oil Volumes by Methods Other Than 
Measurement

    Proposed Sec.  3174.14 would not be a change from Order 4 
requirements for determining volumes of oil that cannot be measured as 
a result of spillage or leakage. This section includes, but is not 
limited to, oil that is classified as slop or waste oil.

Sec.  3174.15 Immediate Assessments

    Proposed Sec.  3174.15 would identify certain acts of noncompliance 
that would be subject to immediate assessments. These actions subject 
to immediate assessment would be in addition to those identified in the 
current regulations at 43 CFR 3163.1(b). These assessments are not 
civil penalties and are separate from the civil penalties authorized in 
Section 109 of FOGRMA, 30 U.S.C. 1719.
    Order 4 does not provide for immediate assessments in addition to 
those specified in 43 CFR 3163.1(b). However, the BLM continues to 
incur costs associated with correcting violations of lease terms and 
regulations. Accordingly, this proposed rule would add six new 
violations that would be subject to immediate assessments.
    The authority for the BLM to impose these assessments was explained 
in the preamble to the final rule in which 43 CFR 3163.1 was originally 
promulgated in 1987:

    The provisions providing assessments have been promulgated under 
the Secretary of the Interior's general authority, which is set out 
in Section 32 of the Mineral Leasing Act of 1920, as amended and 
supplemented (30 U.S.C. 189), and under the various other mineral 
leasing laws. Specific authority for the assessments is found in 
Section 31(a) of the Mineral Leasing Act (30 U.S.C. 188(a), which 
states, in part ``. . . the lease may provide for resort to [sic] 
appropriate methods for the settlement of disputes or for remedies 
for breach of specified conditions thereof.'' All Federal onshore 
and Indian oil and gas lessees must, by the specific terms of their 
leases which incorporate the regulations by reference, comply with 
all applicable laws and regulations.
    Failure of the lessee to comply with the law and applicable 
regulations is a breach of the lease, and such failure may also be a 
breach of other specific lease terms and conditions. Under Section 
31(a) of the Act and the terms of its leases, the BLM may go to 
court to seek cancellation of the lease in these circumstances. 
However, since at least 1942, the BLM (and formerly the Conservation 
Division, U.S. Geological Survey), has recognized that lease 
cancellation is too drastic a remedy, except in extreme cases. 
Therefore, a system of liquidated damages was established to set 
lesser remedies in lieu of lease cancellation. . . .
    The BLM recognizes that liquidated damages cannot be punitive, 
but are a reasonable effort to compensate as fully as possible the 
offended party, in this case the lessor, for the damage resulting 
from a breach where a precise financial loss would be difficult to 
establish. This situation occurs when a lessee fails to comply with 
the operating and reporting requirements. The rules, therefore, 
establish uniform estimates for the damages sustained, depending on 
the nature of the breach.

53 FR 5384, 5387 (Feb. 20, 1987).
    All of the immediate assessments under this proposed rule would be 
set at $1,000 per violation. The BLM chose the $1,000 figure because it 
generally approximates what it would cost the agency to identify and 
document each of the violations in question and verify remedial action 
and compliance.

Change in Violation, Corrective Action, and Abatement Compliance

    This proposal would remove the enforcement, corrective action, and 
abatement period provisions of Order 4. In their place the BLM will 
develop an internal handbook for inspection and enforcement. The 
handbook would provide direction to BLM inspectors on how to classify a 
violation--as major or minor--what corrective action should be applied, 
and what timeframes for correction should be applied. The handbook will 
be in place by the effective date of the final rule. The proposed rule 
would take the approach that a violation's severity and corrective 
action timeframes should be decided on a case-by-case basis, using the 
definitions in the regulations. In deciding how severe a violation is, 
BLM inspectors would take into account whether a violation could result 
in ``immediate, substantial, and adverse impacts on production 
accountability, or royalty income.'' (Definition of ``major violation'' 
43 CFR 3160.0-5.) The AO would use the inspection and enforcement 
handbook in conjunction with 43 CFR subpart 3163, which provides for 
assessments and civil penalties when lessees and operators fail to 
remedy their violations in a

[[Page 58964]]

timely fashion, and for immediate assessments for certain other 
violations. The BLM is asking the public to comment specifically on 
this proposal for dealing with violations and corrective actions, 
particularly the approach that a violation's severity and corrective 
action timeframes should be decided on a case-by-case basis as opposed 
to establishing a fixed schedule for penalties or corrective actions.
    None of the changes proposed in this rule would in any way diminish 
existing enforcement authority.

Miscellaneous Changes to Other BLM Regulations in 43 CFR Part 3160

    Because this proposed rule would replace Order 4, the BLM is 
proposing two related changes to provisions in 43 CFR part 3160.
    1. Section 3162.7-2, Measurement of oil, would be rewritten to 
reflect this proposed rule.
    2. Section 3164.1, Onshore Oil and Gas Orders, the table would be 
revised to remove the reference to Order 4.

V. Onshore Order Public Meetings, April 24-25, 2013

    On April 24 and 25, 2013, the BLM held a series of public meetings 
to discuss draft proposed revisions to Orders 3, 4, and 5. The meetings 
were webcast so tribal members, industry, and the public across the 
country could participate and ask questions either in person or over 
the Internet. Following the forum, the BLM opened a 36-day informal 
comment period, during which 13 comment letters were submitted. The 
following summarizes comments relating to Order 4:
    1. Electronic run tickets. The BLM received numerous comments 
suggesting that electronic run tickets should be allowed in lieu of 
paper run tickets in order to accommodate paperless transactions. The 
BLM agrees with this comment and has added language to the proposed 
rule that would allow either paper or electronic records to be 
submitted, as long as certain requirements are met.
    2. Automatic tank gauging. Several comments suggested that the BLM 
include automatic tank gauging as an accepted method of measuring oil 
sold from tanks because manual tank gauging requires opening the thief 
hatch, thereby releasing vapors into the atmosphere and exposing 
personnel to potentially dangerous vapor inhalation and fire hazards. 
The BLM considered adding provisions for automatic tank gauging in the 
proposed rule, including the incorporation by reference of API MPMS 
Chapter 3, Section 1B, ``Standard Practice for Level Measurement of 
Liquid Hydrocarbons in Stationary Tanks by Automatic Tank Gauging,'' 
Second Edition, June 2001. However, because the BLM has not seen any 
test data to confirm that their certainty, bias, and verifiability 
would meet the specific measurement performance objectives in proposed 
Sec.  3174.3, or the accuracy standards for manual tank gauging in 
proposed Sec.  3174.6(b)(5)(iii), the BLM did not include an automatic 
tank gauging provision in the proposed rule. In order to more fully 
understand the issues surrounding automatic tank gauging, the BLM is 
specifically asking the public to comment on this issue and provide 
test and field data demonstrating that automatic tank gauging would 
meet or exceed the proposed standards for manual tank gauging. If the 
BLM decides to include automatic tank gauging in the final rule, we may 
also consider approvals of specific types of equipment, including the 
makes, models, and sizes for which test data demonstrate their ability 
to meet the BLM's minimum standards.
    3. Modifications to existing LACTs. One comment suggested that 
existing LACTs using automatic temperature/gravity compensators should 
be exempt from the proposed requirement that prohibits their use 
(proposed Sec.  3174.7(g)). The BLM did not accept this suggestion 
because the estimated number of existing LACTs at FMPs that are 
equipped with automatic temperature/gravity compensators is small, but 
the potential for lost royalty could be significant. Absent further 
information to the contrary, the BLM believes that retrofitting these 
LACTs to conform to the proposed rule would not be a significant cost 
burden to operators.
    4. Coriolis Meters. The BLM received one comment suggesting that 
the minimum pulse output for a Coriolis meter should be 8,400 pulses 
per barrel, not 10,000 pulses per barrel as presented at the meeting. 
The reason given is that, especially for high-volume meters, a pulse 
output of 10,000 pulses per barrel could exceed the maximum frequency 
output of the Coriolis meter or the frequency input for the tertiary 
device. The BLM agrees and has incorporated this suggestion into the 
proposed rule.
    5. CMS non-resettable totalizer. The BLM received one comment 
objecting to the requirement for a non-resettable totalizer on a CMS 
for volume at metered conditions because the flow computer on a CMS 
will automatically calculate corrected volume using the meter factor, 
CPL, and CTL. While the BLM agrees that the calculation of corrected 
oil volume at standard conditions is possible with a flow computer, the 
BLM requires access to the raw values going into the calculation for 
the purpose of independent verification. No changes to the proposed 
rule were made as a result of this comment.
    6. Uncertainty limits--high volume. One commenter suggested that 
the proposed uncertainty limit for high-volume oil measurement of 
0.35 percent (proposed Sec.  3174.3(a)(1)) is too 
restrictive and, instead, should be based on published API documents. 
As explained above, the BLM believes that the 0.35 percent 
uncertainty in the proposed rule is reasonable, based on the BLM's 
experience with current equipment capabilities and industry standard 
practices and procedures. The BLM would consider changing this limit if 
specific data and uncertainty analyses were presented in the comments 
to this proposed rule that support the use of a different value.
    7. Uncertainty limits--low volume. Another commenter suggested that 
the BLM should establish a third uncertainty tier of 3 
percent for very low volumes of less than 500 barrels per month. The 
BLM agrees with the premise of this suggestion; however, upon review of 
uncertainty data, the BLM is proposing a third uncertainty tier of 
2.5 percent for low volumes of less than 100 barrels per 
month. Data indicates that for a typical 400 bbl tank measuring by 
manual tank gauging, the uncertainty level increases as lower volumes 
of oil are removed, achieving the highest uncertainty level of 2.5 percent. Based on current information, the BLM believes that 
an uncertainty level of 2.5 percent and a less than 100 bbl 
per month threshold to be achievable without additional investment, and 
that attempts to achieve a lower uncertainty standard could become 
uneconomic for a typical low-volume operation. The BLM is interested in 
comments and data related to this proposed uncertainty level and volume 
threshold.
    8. Meter proving frequency. The BLM received one comment objecting 
to the proposed requirement of a LACT/CMS proving frequency every 
50,000 barrels or quarterly, whichever is more frequent. However, the 
objection was based on coordination with the pipeline company that may 
own the meter, not on the lack of need to perform the proving. Because 
no data was submitted to justify a different frequency, we did not 
change the proposed requirement. While the BLM would consider a 
different proving frequency, it would have to be justified by specific 
data submitted during the public comment period for this rule. The 
proposed rule

[[Page 58965]]

was not revised as a result of this comment.
    9. Allocation meters. The BLM received one comment suggesting that 
the BLM should establish less rigid standards for allocation meters. 
The BLM did not change the proposed rule based on this comment. 
Inaccurate or unverifiable measurement will affect royalty payment 
regardless of whether the measurement is used to determine a percentage 
of a commingled measurement (allocation) or is used directly to 
determine royalty-bearing volume and quality. The proposed rule was not 
revised based on this comment.
    10. Vapor-tight tanks. The BLM received one comment objecting to 
the cost of maintaining vapor-tight tanks. Although the existing Order 
4 does not explicitly require vapor-tight tanks, the requirement of a 
pressure-vacuum thief hatch or vent line valve implies that other 
components of the tank must be vapor tight. The proposed rule would 
clear up this ambiguity. The BLM does not believe that this is a change 
from the existing requirement in Order 4 that tanks must be vapor-
tight. The BLM did not make any changes to the proposed rule based on 
this comment.
    11. LACT/CMS run tickets. The BLM received one comment suggesting 
that run tickets generated for oil volume measured by LACT or CMS be 
prepared monthly, not every time the LACT or CMS was activated. The BLM 
agrees with this comment. A run ticket would be opened at the beginning 
of every calendar month and whenever a meter proving was conducted.

VI. Procedural Matters

Executive Orders 12866 and 13563, Regulatory Planning and Review

    Executive Order 12866 provides that the Office of Information and 
Regulatory Affairs (OIRA) will review all significant rules. The OIRA 
has determined that this rule is significant because it would raise 
novel legal or policy issues.
    Executive Order 13563 reaffirms the principles of E.O. 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. E.O. 13563 emphasizes further 
that regulations must be based on the best available science and that 
the rulemaking process must allow for public participation and an open 
exchange of ideas. The BLM has developed this rule in a manner 
consistent with these requirements.

Regulatory Flexibility Act

    The BLM certifies that this proposed rule would not have a 
significant economic effect on a substantial number of small entities 
as defined under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.). 
The Small Business Administration (SBA) has developed size standards to 
carry out the purposes of the Small Business Act and those size 
standards can be found at 13 CFR 121.201. Small entities for mining, 
including the extraction of crude oil and natural gas, are defined by 
the SBA as an individual, limited partnership, or small company 
considered being at ``arm's length'' from the control of any parent 
companies, with fewer than 500 employees.
    Of the 6,628 domestic firms involved in onshore oil and gas 
extraction, 99 percent (or 6,530) had fewer than 500 employees. There 
are another 10,160 firms involved in drilling and other support 
functions. Of the firms providing support functions, 99 percent of 
those firms had fewer than 500 employees. Based on this national data, 
the preponderance of firms involved in developing oil and gas resources 
are small entities as defined by the SBA. As such, it appears a number 
of small entities potentially could be affected by this proposed rule. 
Using the best available data, the BLM estimates there are 
approximately 3,700 lessees/operators conducting oil operations on 
Federal and Indian lands that could be affected by this rule.
    In addition to determining whether a number of small entities are 
likely to be affected by this rule, the BLM must also determine whether 
the rule is anticipated to have a significant economic impact on those 
small entities. On an ongoing basis, we estimate the proposed changes 
to the LACT meter proving frequency requirements based on volume 
throughput would increase the regulated community's annual costs by 
less than $258,000, and would affect approximately 74 of the highest-
volume LACT systems. In addition, there would be a one-time cost to 
retrofit 20 percent of existing LACT systems of about $1.4 million, or 
a one-time average cost of about $4,000 to approximately 346 existing 
LACT systems. New paperwork requirements would also increase operators' 
one-time costs by about $700,000 for submitting revised tank 
calibration tables to the BLM. New annual paperwork costs would amount 
to about $300,000. All of the proposed provisions would apply to 
entities regardless of size. However, entities with the greatest 
activity would likely experience the greatest increase in compliance 
costs.
    Based on the available information, we conclude that the proposed 
rule would not have a significant impact on a substantial number of 
small entities. Therefore, a final Regulatory Flexibility Analysis is 
not required, and a Small Entity Compliance Guide is not required.

Small Business Regulatory Enforcement Fairness Act

    This proposed rule is not a major rule under 5 U.S.C. 804(2), the 
Small Business Regulatory Enforcement Fairness Act. This rule would not 
have an annual effect on the economy of $100 million or more. As 
explained under the preamble discussion concerning Executive Order 
12866, Regulatory Planning and Review, proposed changes to Order 4, 
Measurement of Oil, would increase, by about $558,000 annually, the 
cost associated with the development and production of crude oil 
resources under Federal and Indian oil and gas leases. There would also 
be a one-time cost estimated to be $2.1 million.
    This rule proposes to replace Order 4 to ensure that crude oil 
produced from Federal and Indian oil and gas leases is accurately 
measured and accounted for. Based on the cost figures above, the 
estimated annual increased cost to each entity that produces oil from 
all Federal and Indian leases for implementing these changes would be 
about $150 per year, and a one-time average cost of about $570 per 
entity for the estimated 3,700 lessees/operators conducting operations 
on Federal or Indian leases.
    This proposed rule:
     Would not cause a major increase in costs or prices for 
consumers, individual industries, Federal, State, tribal, or 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.

Unfunded Mandates Reform Act

    In accordance with the Unfunded Mandates Reform Act (2 U.S.C. 1501 
et seq.), the BLM finds that:
     This proposed rule would not ``significantly or uniquely'' 
affect small governments. A Small Government Agency Plan is 
unnecessary.

[[Page 58966]]

     This proposed rule would not produce a Federal mandate of 
$100 million or greater in any single year.
    The proposed rule is not a ``significant regulatory action'' as it 
would not require anything of any non-Federal governmental entity.

Executive Order 12630, Governmental Actions and Interference With 
Constitutionally Protected Property Rights (Takings)

    Under Executive Order 12630, the proposed rule would not have 
significant takings implications. A takings implication assessment is 
not required. This proposed rule would establish the minimum standards 
for accurate measurement and proper reporting of oil produced from 
Federal and Indian leases, unit PAs, and CAs, by providing a system for 
production accountability by operators and lessees. All such actions 
are subject to lease terms which expressly require that subsequent 
lease activities be conducted in compliance with applicable Federal 
laws and regulations. The proposed rule conforms to the terms of those 
Federal leases and applicable statutes, and as such the proposed rule 
is not a governmental action capable of interfering with 
constitutionally protected property rights. Therefore, the proposed 
rule would not cause a taking of private property or require further 
discussion of takings implications under this Executive Order.

Executive Order 13132, Federalism

    In accordance with Executive Order 13132, the BLM finds that the 
proposed rule would not have significant Federalism effects. A 
Federalism assessment is not required. This proposed rule would not 
change the role of or responsibilities among Federal, State, and local 
governmental entities. It does not relate to the structure and role of 
the States and would not have direct, substantive, or significant 
effects on States.

Executive Order 13175, Consultation and Coordination With Indian Tribal 
Governments

    Under Executive order 13175, the President's memorandum of April 
29, 1994, ``Government-to-Government Relations with Native American 
Tribal Governments'' (59 FR 22951), and 512 Departmental Manual 2, the 
BLM evaluated possible effects of the proposed rule on federally 
recognized Indian tribes. The BLM approves proposed operations on all 
Indian onshore oil and gas leases (except Osage Tribe). Therefore, the 
proposed rule has the potential to affect Indian tribes. In conformance 
with the Secretary's policy on tribal consultation, the BLM held three 
tribal consultation meetings to which more than 175 tribal entities 
were invited. The consultations were held in:
     Tulsa, Oklahoma on July 11, 2011;
     Farmington, New Mexico on July 13, 2011; and
     Billings, Montana on August 24, 2011.
    In addition, the BLM hosted a tribal workshop and webcast in 
Washington, DC on April 24, 2013.
    The purpose of these meetings was to solicit initial feedback and 
preliminary comments from the tribes. Comments from the tribes will 
continue to be accepted and consultation will continue as this 
rulemaking proceeds. To date, the tribes have expressed concerns about 
the subordination of tribal laws, rules, and regulations to the 
proposed rule; representation on the DOI GOMT; and the BLM's Inspection 
and Enforcement program's ability to enforce the terms of this proposed 
rule. While the BLM will continue to address these concerns, none of 
the concerns expressed relate to or affect the substance of this 
proposed rule.

Executive Order 12988, Civil Justice Reform

    Under Executive Order 12988, the Office of the Solicitor has 
determined that the proposed rule would not unduly burden the judicial 
system and meets the requirements of Sections 3(a) and 3(b)(2) of the 
Executive Order. The Office of the Solicitor has reviewed the proposed 
rule to eliminate drafting errors and ambiguity. It has been written to 
minimize litigation, provide clear legal standards for affected conduct 
rather than general standards, and promote simplification and burden 
reduction.

Executive Order 13352, Facilitation of Cooperative Conservation

    Under Executive Order 13352, the BLM has determined that this 
proposed rule would not impede facilitating cooperative conservation 
and would take appropriate account of and consider the interests of 
persons with ownership or other legally recognized interests in land or 
other natural resources. This rulemaking process will involve Federal, 
tribal, State, and local governments, private for-profit and nonprofit 
institutions, other nongovernmental entities and individuals in the 
decision-making via the public comment process. That process would 
provide that the programs, projects, and activities are consistent with 
protecting public health and safety.

Paperwork Reduction Act

I. Overview
    The Paperwork Reduction Act (PRA) (44 U.S.C. 3501-3521) provides 
that an agency may not conduct or sponsor, and a person is not required 
to respond to, a ``collection of information,'' unless it displays a 
currently valid OMB control number. Collections of information include 
any request or requirement that persons obtain, maintain, retain, or 
report information to an agency, or disclose information to a third 
party or to the public (44 U.S.C. 3502(3) and 5 CFR 1320.3(c)). This 
proposed rule contains information collection requirements that are 
subject to review by OMB under the PRA. In accordance with the PRA, the 
BLM is inviting public comments on proposed new information collection 
requirements for which the BLM is requesting a new OMB control number.
    After promulgating a final rule and receiving approval from the OMB 
(in the form of a new control number), the BLM intends to ask OMB to 
combine the activities authorized by the new control number with 
existing control number 1004-0137, Onshore Oil and Gas Operations 
(expiration date January 31, 2018).
    The information collection activities in this proposed rule are 
described below along with estimates of the annual burdens. These 
activities, along with annual burden estimates, do not include 
activities that are considered usual and customary industry practices. 
Included in the burden estimates are the time for reviewing 
instructions, searching existing data sources, gathering and 
maintaining the data needed, and completing and reviewing each 
component of the proposed information collection requirements.
    The information collection request for this proposed rule has been 
submitted to OMB for review under 44 U.S.C. 3507(d). A copy of the 
request can be obtained from the BLM by electronic mail request to 
Jennifer Spencer at [email protected] or by telephone request to 202-
912-7146. You may also review the information collection request online 
at http://www.reginfo.gov/public/do/PRAMain.
    The BLM requests comments on the following subjects:
    1. Whether the collection of information is necessary for the 
proper functioning of the BLM, including whether the information will 
have practical utility;
    2. The accuracy of the BLM's estimate of the burden of collecting 
the information, including the validity of the methodology and 
assumptions used;

[[Page 58967]]

    3. The quality, utility, and clarity of the information to be 
collected; and
    4. How to minimize the information collection burden on those who 
are to respond, including the use of appropriate automated, electronic, 
mechanical, or other forms of information technology.
    If you want to comment on the information collection requirements 
of this proposed rule, please send your comments directly to OMB, with 
a copy to the BLM, as directed in the ADDRESSES section of this 
preamble. Please identify your comments with ``OMB Control Number 1004-
XXXX.'' OMB is required to make a decision concerning the collection of 
information contained in this proposed rule between 30 to 60 days after 
publication of this document in the Federal Register. Therefore, a 
comment to OMB is best assured of having its full effect if OMB 
receives it by October 30, 2015.
II. Summary of Proposed Information Collection Requirements
    Title: Measurement of Oil.
    OMB Control Number: Not assigned. This is a new collection of 
information.
    Description of Respondents: Holders of Federal and Indian (except 
Osage Tribe) oil and gas leases, operators, purchasers, transporters, 
and any other person directly involved in producing, transporting, 
purchasing, or selling, including measuring, oil or gas through the 
point of royalty measurement or the point of first sale.
    Respondents' Obligation: Required to obtain or retain a benefit.
    Frequency of Collection: On occasion.
    Abstract: The proposed rule includes new information collection 
requirements that are necessary in order to update the BLM's 
regulations on measurement of oil produced from Federal and Indian 
(except Osage Tribe) onshore oil and gas leases, and from units or 
communitized areas that include Federal or Indian leases.
    Estimated Total Annual Burden Hours: The proposed rule would result 
in an estimated 26,290 responses and 14,696 burden hours annually.
III. Proposed Information Collection Requirements
    Proposed Sec.  3174.5(c) would require submission of tank 
calibration tables to the BLM within 30 days after calibration. This 
provision would ensure that BLM personnel would have the latest tables 
when conducting inspections or audits.
    Proposed Sec.  3174.7(e)(1) would require the operator to notify 
the BLM within 24 hours of any LACT system failures or equipment 
malfunctions which may have resulted in measurement error.
    Proposed Sec.  3174.10(d) would require the operator to notify the 
BLM within 24 hours of any changes to any Coriolis meter internal 
calibration factors.
    Proposed Sec.  3174.10(i), (j), and (k) would establish minimum 
requirements for the information about Coriolis Measurement Systems 
(CMSs) that the operator would need to maintain on-site, information 
that must be retained for an audit trail, and requirements for 
protecting the retained data in the CMS unit's memory. This information 
is necessary for the BLM to ensure compliance with these regulations 
and conduct production audits.
    Proposed Sec.  3174.11(c) would require the operator to have 
available on-site, for review by the BLM, a valid certificate of 
calibration for the meter prover that is used to determine the meter 
factor.
    Proposed 3174.11(j) would require the operator to provide a meter 
proving report no later than 14 days after a meter proving. The 
following information would be required:
     All meter-proving and volume adjustments after any LACT 
system or CMS malfunction;
     FMP number;
     Lease number, CA number, or unit PA number;
     The temperature from the test thermometer and the 
temperature from the temperature averager or tertiary device;
     For CMS, the pressure applied by the pressure test device 
and the pressure reading from the tertiary device at the three points 
required under paragraph (h)(3) of this section; and
     The ``as left'' fluid flow rate and fluid pressure, if the 
back-pressure valve is adjusted after proving.
    Proposed 3174.13 would require prior BLM approval for any method of 
oil measurement other than manual tank gauging, LACT system, or CMS at 
a Facility Measurement Point. Any operator requesting approval to use 
alternative oil measurement equipment would be required to submit to 
the BLM:
     Performance data;
     Actual field test results;
     Laboratory test data; or
     Any other supporting data or evidence that demonstrates 
that the proposed alternative oil measurement equipment would meet or 
exceed the objectives of the applicable minimum requirements at 
proposed subpart 3174 and would not affect royalty income or production 
accountability.
IV. Burden Estimates
    The following table details the information elements and respective 
annual hour burdens of the request for a new control number:

----------------------------------------------------------------------------------------------------------------
                                                                   B. Number of    C. Hours per
                       A. Type of response                           responses       response     D. Total hours
----------------------------------------------------------------------------------------------------------------
Tank Calibration Tables (43 CFR 3174.5(c))......................          22,000             0.5          11,000
Notification of LACT System Failure (43 CFR 3174.7(e)(1)).......             100               1             100
Notification of Changes to Internal Meter Calibration Factors                 10               1              10
 (43 CFR 3174.10(d))............................................
Requirements for Coriolis Measurement Systems (43 CFR                      2,200               1           2,200
 3174.10(i), (j), and (k))......................................
Meter Prover Calibration Certification Documentation (43 CFR                 985             0.5             493
 3174.11(c))....................................................
Meter Proving Reports (43 CFR 3174.11(j)).......................             985             0.5             493
Oil Measurement by Other Methods (43 CFR 3174.13)...............              10              40             400
                                                                 -----------------------------------------------
    Totals......................................................          26,290  ..............          14,696
----------------------------------------------------------------------------------------------------------------

National Environmental Policy Act (NEPA)

    The BLM has prepared a draft environmental assessment (EA) that 
concludes that this proposed rule would not have a significant impact 
on the quality of the environment under NEPA, 42 U.S.C. 4332(2)(C), 
therefore a detailed statement under NEPA is not required. A copy of 
the draft EA can be viewed at www.regulations.gov (use the search term 
1004-AE16, open the Docket Folder, and look under Supporting Documents) 
and at the address specified in the ADDRESSES section.
    The proposed rule would not impact the environment significantly. 
For the

[[Page 58968]]

most part, the proposed rule would in substance update the provisions 
of Order 4 and would involve changes that are of an administrative, 
technical, or procedural nature that would apply to the BLM's and the 
lessee's or operator's administrative processes. For example, the 
proposed rule would update the step-by-step procedure required by the 
BLM for performing tank gauging operations. The rule would also 
establish new requirements for the specific types of information that 
should be included in a measurement ticket that must be submitted to 
the BLM after performing oil measurement operations. Additionally, the 
rule would establish new standards for meters, including an increased 
proving frequency established by the BLM. These changes will enhance 
the agency's ability to account for the oil and gas produced from 
Federal and Indian lands, but should have minimal to no impact on the 
environment. Some of these proposed standards, such as those associated 
with proposed new standards for storage tanks, LACT systems, and meter-
proving, may result in increased human presence and traffic on existing 
disturbed surfaces, but these activities are expected to have a 
negligible impact on the quality of the human environment, as discussed 
in the draft EA. We will consider any new information we receive during 
the public comment period for the proposed rule that may inform our 
analysis of the potential environmental impacts of the rule.

Executive Order 13211, Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use

    Although this proposed rule would amend the BLM's oil production 
regulations, it would not have a substantial direct effect on the 
nation's energy supply, distribution, or use, including a shortfall in 
supply or price increases. Changes in this proposed rule would 
strengthen the BLM's accountability requirements for operators holding 
Federal and Indian oil leases. As discussed previously, these changes 
would increase recordkeeping requirements and establish national 
requirements for operators who wish to use CMSs. All of the changes 
would increase the regulated community's annual costs by about 
$558,000, or about $150 per entity per year.
    We expect that the proposed rule would not result in a net change 
in the quantity of oil that is produced from Federal and Indian leases.

Information Quality Act

    In developing this proposed rule, we did not conduct or use a 
study, experiment, or survey requiring peer review under the 
Information Quality Act (Pub. L. 106-554, Appendix C Title IV, 515, 114 
Stat. 2763A-153).

Clarity of the Regulations

    Executive Order 12866 requires each agency to write regulations 
that are simple and easy to understand. We invite your comments on how 
to make these proposed regulations easier to understand, including 
answers to questions such as the following:
    1. Are the requirements in the proposed regulations clearly stated?
    2. Do the proposed regulations contain technical language or jargon 
that interferes with their clarity?
    3. Does the format of the proposed regulations (grouping and order 
of sections, use of headings, paragraphing, etc.) aid or reduce their 
clarity?
    4. Would the regulations be easier to understand if they were 
divided into more (but shorter) sections?
    5. Is the description of the proposed regulations in the 
SUPPLEMENTARY INFORMATION section of this preamble helpful in 
understanding the proposed regulations? How could this description be 
more helpful in making the proposed regulations easier to understand?
    Please send any comments you have on the clarity of the regulations 
to the address specified in the ADDRESSES section.

Authors

    The principal authors of this proposed rule are Mike McLaren of the 
BLM Pinedale, Wyoming Field Office; Steve Klimetz of the U.S. Forest 
Service Region 8 Office, Atlanta, Georgia (formerly of the BLM); Tom 
Zelenka of the BLM New Mexico State Office; Chris DeVault from the BLM 
Montana State Office; Val Jamison of the BLM Farmington, New Mexico 
Field Office; assisted by Faith Bremner, BLM, Division of Regulatory 
Affairs, Washington Office; Mike Wade, BLM, Washington Office; Rich 
Estabrook, BLM, Washington Office; and Geoffrey Heath, Office of the 
Solicitor, Department of the Interior.

List of Subjects

43 CFR Part 3160

    Administrative practice and procedure, Government contracts, 
Indians-lands, Mineral royalties, Oil and gas exploration, Penalties, 
Public lands--mineral resources, Reporting and recordkeeping 
requirements.

43 CFR Part 3170

    Administrative practice and procedure, Immediate assessments, 
Incorporation by reference, Indians-lands, Mineral royalties, Oil and 
gas measurement, Public lands--mineral resources.

    Dated: September 16, 2015.
Janice M. Schneider,
Assistant Secretary, Land and Minerals Management.

43 CFR Chapter II

    For the reasons set out in the preamble, the Bureau of Land 
Management proposes to amend 43 CFR part 3160 and, as proposed to be 
added on July 13, 2015 (80 FR 40768), 43 CFR part 3170, as follows:

PART 3160--ONSHORE OIL AND GAS OPERATIONS

0
1. The authority citation for part 3160 continues to read as follows:

    Authority: 25 U.S.C. 396d and 2107; 30 U.S.C. 189, 306, 359, and 
1751; and 43 U.S.C. 1732(b), 1733, and 1740.

0
2. Revise Sec.  3162.7-2 to read as follows:


Sec.  3162.7-2  Measurement of oil.

    All oil removed or sold from a lease, communitized area, or unit 
participating area must be measured under subpart 3174 of this title. 
All measurement must be on the lease, communitized area, or unit from 
which the oil originated and must not be commingled with oil 
originating from other sources unless approved by the authorized 
officer under the provisions of subpart 3173 of this title.


Sec.  3164.1  [Amended]

0
3. Amend Sec.  3164.1(b) by removing the fourth entry in the table, 
Order No. 4, Measurement of Oil.

PART 3170--ONSHORE OIL AND GAS PRODUCTION

0
4. The authority citation is added to part 3170, proposed to be added 
on July 13, 2015 (80 FR 40768), to read as follows:

    Authority: 25 U.S.C. 396d and 2107; 30 U.S.C. 189, 306, 359, and 
1751; and 43 U.S.C. 1732(b), 1733, and 1740.

0
5. Add subpart 3174 to part 3170, proposed to be added on July 13, 2015 
(80 FR 40768), to read as follows:

Subpart 3174--Measurement of Oil

Sec.
3174.1 Definitions and acronyms.
3174.2 General requirements.
3174.3 Specific measurement performance requirements.

[[Page 58969]]

3174.4 Incorporation by reference.
3174.5 Oil measurement by manual tank gauging--general requirements.
3174.6 Oil measurement by manual tank gauging--procedures.
3174.7 LACT systems--general requirements.
3174.8 LACT systems--components and operating requirements.
3174.9 Coriolis measurement systems (CMS)--general requirements and 
components.
3174.10 Coriolis measurement systems--operating requirements.
3174.11 Meter proving requirements.
3174.12 Measurement tickets.
3174.13 Oil measurement by other methods.
3174.14 Determination of oil volumes by methods other than 
measurement.
3174.15 Immediate assessments.


Sec.  3174.1  Definitions and acronyms.

    (a) As used in this subpart, the term:
    Barrel (bbl) means 42 standard United States gallons.
    Base pressure means atmospheric pressure or the vapor pressure of 
the liquid at 60[emsp14][deg]F, whichever is higher.
    Base temperature means 60[emsp14][deg]F.
    Certificate of calibration means a document stating the base prover 
volume and other physical data required for the calibration of flow 
meters.
    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.
    Configuration log means the list of constant flow parameters, 
calculation methods, alarm set points, and other values that are 
programmed into the flow computer in a Coriolis measurement system.
    Coriolis meter means a device which by means of the interaction 
between a flowing fluid and oscillation of tube(s), measures mass flow 
rate and density. The Coriolis meter consists of sensors and a 
transmitter, which converts the output from the sensors to signals 
representing volume and density.
    Coriolis measurement system (CMS) means a metering system using a 
Coriolis meter in conjunction with a tertiary device, pressure 
transducer, and temperature transducer in order to derive and report 
net oil volume. A CMS system provides real-time, on-line measurement of 
oil.
    Displacement prover means a prover consisting of a pipe or pipes 
with known capacities, a displacement device, and detector switches, 
which sense when the displacement device has reached the beginning and 
ending points of the calibrated section of pipe. Displacement provers 
can be portable or fixed.
    Event log means an electronic record of all exceptions and changes 
to the flow parameters contained within the configuration log that 
occur and have an impact on a quantity transaction record.
    Gross standard volume means a volume of oil corrected to base 
pressure and temperature.
    Innage gauging means the level of a liquid in a tank measured from 
the datum plate or tank bottom to the surface of the liquid.
    Lease automatic custody transfer (LACT) system means a system of 
components designed to provide for the unattended custody transfer of 
oil produced from a lease, unit PA, or CA to the transporting carrier 
while providing a proper and accurate means for determining the net 
standard volume and quality, and fail-safe and tamper-proof operations.
    Master meter prover means a positive displacement meter or Coriolis 
meter that is selected, maintained, and operated to serve as the 
reference device for the proving of another meter. A comparison of the 
master meter to the Facility Measurement Point (FMP) meter output is 
the basis of the master-meter method.
    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 meter 
during the proving, corrected to base pressure and temperature.
    Net standard volume means the gross standard volume corrected for 
quantities of non-merchantable substances such as sediment and water.
    Opaque oil means oil exhibiting the ability to block the passage of 
light.
    Outage gauging means the distance from the surface of the liquid in 
a tank to the reference gauge point of the tank.
    Positive displacement meter means a meter that registers the volume 
passing through the meter using a system which constantly and 
mechanically isolates the flowing liquid into segments of known volume.
    Quantity transaction record (QTR) means a report generated by CMS 
equipment that summarizes the daily and hourly gross standard 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.
    Registered volume means the uncorrected volume registered by the 
positive displacement meter in a LACT system or the Coriolis meter in a 
CMS. For a positive displacement meter, the registered volume is 
represented by the non-resettable totalizer on the meter head. For 
Coriolis meters, the registered volume is the uncorrected (without the 
meter factor) mass of liquid divided by the density.
    Resistance thermal device (RTD) means a type of transducer that 
converts a physical temperature into an electrical resistance (ohms).
    Tertiary device means, for a CMS, the flow computer and associated 
memory, calculation, and display functions.
    Turbulent flow means a type of flow in which random eddying flow 
patterns are superimposed upon the general flow progressing in a given 
direction.
    Unity means an amount taken as 1.0000.
    (b) As used in this subpart part the following additional acronyms 
carry the meaning prescribed:
    API RP means an American Petroleum Institute Recommended Practice.
    API MPMS means American Petroleum Institute Manual of Petroleum 
Measurement Standards.
    CPL means correction for the effect of pressure on a liquid.
    CPS means correction for the effect of pressure on steel.
    CTL means correction for the effect of temperature on a liquid.
    CTS means correction for the effect of temperature on steel.
    NIST means National Institute of Standards and Technology.
    S&W means sediment and water.


Sec.  3174.2  General requirements.

    (a) Oil may be stored only in tanks that meet the requirements of 
Sec.  3174.5(b) of this subpart.
    (b) Oil must be measured on the lease, unit, or CA, unless approval 
for off-lease measurement is obtained under Sec. Sec.  3173.21 and 
3173.22 of this part.
    (c) Oil produced from a lease, unit PA, or CA may not be commingled 
with production from other leases, unit PAs, or CAs or non-Federal 
properties before the point of royalty measurement, unless prior 
approval is obtained under Sec. Sec.  3173.14 and 3173.15 of this part.
    (d) An operator must obtain a BLM-approved FMP number under 
Sec. Sec.  3173.12 and 3173.13 of this part for each oil measurement 
facility where the measurement affects the calculation of the volume or 
quality of production on which royalty is owed (i.e., oil tank used for 
manual tank gauging, LACT system, CMS, or other approved metering 
device).
    (e) Except as provided in paragraph (f) of this section, all 
equipment used to measure the volume of oil for royalty purposes 
installed after [THE EFFECTIVE DATE OF THE FINAL RULE] must comply with 
the requirements of this subpart. Equipment

[[Page 58970]]

used to measure oil for royalty purposes in use on [THE EFFECTIVE DATE 
OF THE FINAL RULE] must comply with the requirements of this subpart by 
[DATE 180 DAYS AFTER THE EFFECTIVE DATE OF THE FINAL RULE].
    (f) Meters used for allocation under a commingling and allocation 
approval under 43 CFR 3173.14 are not required to meet the requirements 
of this subpart.


Sec.  3174.3  Specific measurement performance requirements.

    (a) Volume measurement uncertainty levels. (1) The FMP must achieve 
the following uncertainty levels:

------------------------------------------------------------------------
  If the monthly volume averaged over the        The overall volume
previous 12 months or the life of the FMP,  measurement uncertainty must
         whichever is shorter, is:                   be within:
------------------------------------------------------------------------
1. Greater than 10,000 bbl/month..........  0.35 percent.
2. Greater than 100 bbl/month and less      1.0 percent.
 than 10,000 bbl/month.
3. Less than 100 bbl/month................  2.5 percent.
------------------------------------------------------------------------

    (2) Only a BLM State Director may grant an exception to the 
uncertainty levels prescribed in paragraph (a)(1) of this section, and 
only upon:
    (i) A showing that meeting the required uncertainly level would 
involve extraordinary cost or unacceptable adverse environmental 
effects; and
    (ii) Written concurrence of the BLM Director.
    (b) Bias. The measuring equipment used for volume determination 
must achieve measurement without statistically significant bias.
    (c) Verifiability. All FMP equipment must be susceptible to 
independent verification by the BLM of the accuracy and validity of all 
inputs, factors, and equations that are used to determine quantity or 
quality. Verifiability includes the ability to independently 
recalculate volume and quality based on source records.
    (d) Variances. The Production Measurement Team (PMT) will make any 
determination under Sec.  3170.6(a)(4) of this part regarding whether a 
proposed variance in measurement procedures meets or exceeds the 
objectives of this section.


Sec.  3174.4  Incorporation by reference.

    (a) Certain material specified in paragraphs (b) and (c) of this 
section 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. Operators must comply with all incorporated standards and 
material, as they are in effect as of the effective date of this 
section. All approved material is available for inspection at the 
Bureau of Land Management, Division of Fluid Minerals, 20 M Street SE., 
Washington, DC 20003, 202-912-7162, and at all BLM offices with 
jurisdiction over oil and gas activities. It is also available for 
inspection at the National Archives and Records Administration (NARA). 
For information on the availability of this material at NARA, call 202-
741-6030 or go to http://www.archives.gov/federal_register/code_of_federal_regulations/ibr_locations.html. In addition, the 
material incorporated by reference is available from the sources of 
that material, identified in paragraphs (b) and (c) of this section, as 
follows:
    (b) American Petroleum Institute (API), 1220 L Street NW., 
Washington, DC 20005; telephone 202-682-8000; API also offers free, 
read-only access to some of the material at www.publications.api.org.
    (1) API Manual of Petroleum Measurement Standards (MPMS) Chapter 2, 
Section 2A, Measurement and Calibration of Upright Cylindrical Tanks by 
the Manual Tank Strapping Method, 1st Ed., February 1995, Reaffirmed 
February 2012 (``API 2.2A''), IBR approved for Sec.  3174.5(c).
    (2) API MPMS Chapter 3, Section 1A, Standard Practice for the 
Manual Gauging of Petroleum and Petroleum Products, 3rd Ed., August 
2013 (``API 3.1A''), IBR approved for Sec. Sec.  3174.5(b)(7) and 
3174.6(b)(5).
    (3) API MPMS Chapter 4, Section 1, Introduction, 3rd Ed., February 
2005, Reaffirmed June 2014 (``API 4.1''), IBR approved for Sec.  
3174.11(d).
    (4) API MPMS Chapter 4, Section 2, Displacement Provers, 3rd Ed., 
September 2003, Reaffirmed March 2011 (``API 4.2,'' and ``API 4.2, Eq. 
12''), IBR approved for Sec. Sec.  3174.11(c)(2) and 3174.11(c)(4).
    (5) API MPMS Chapter 4, Section 5, Master-Meter Provers, 3rd Ed., 
November 2011 (``API 4.5''), IBR approved for Sec.  3174.11(c)(1).
    (6) API MPMS Chapter 4, Section 6, Pulse Interpolation, 2nd Ed., 
May 1999, Reaffirmed October 2013 (``API 4.6''), IBR approved for Sec.  
3174.11(d)(2).
    (7) API MPMS Chapter 4, Section 9, Part 2, Methods of Calibration 
for Displacement and Volumetric Tank Provers, Determination of the 
Volume of Displacement and Tank Provers by the Waterdraw Method of 
Calibration, 1st Ed., December, 2005, Reaffirmed September 2010 (``API 
4.9.2''), IBR approved for Sec.  3174.11(c)(2).
    (8) API MPMS Chapter 5, Section 6, Measurement of oil by Coriolis 
Meters, 1st Ed., October 2002, Reaffirmed November 2013 (``API 5.6,'' 
``API 5.6.3.2(e),'' API 5.6.8.3,'' ``API 5.6.9.1.2.1,'' and ``API 5.6, 
Eq. 2''), IBR approved for Sec. Sec.  3174.9(b), 3174.9(d), 
3174.9(e)(1), 3174.10(c), 3174.10(f), 3174.11(i), and 3174.11(j).
    (9) API MPMS Chapter 6, Section 1, Lease Automatic Custody Transfer 
(LACT) Systems, 2nd Ed., May 1991, Reaffirmed May 2012 (``API 6.1''), 
IBR approved for Sec.  3174.7(a).
    (10) API MPMS Chapter 7, Temperature Determination, 1st Ed., June 
2001, Reaffirmed February 2012 (``API 7'' and ``API 7.1''), IBR 
approved for Sec. Sec.  3174.6(b)(2), 3174.6(c)(1), and 
3174.8(b)(11)(i).
    (11) API MPMS Chapter 8, Section 1, Standard Practice for Manual 
Sampling of Petroleum and Petroleum Products, 4th Ed., October 2013, 
(``API 8.1''), IBR approved for Sec.  3174.6(b)(3).
    (12) API MPMS Chapter 9, Section 3, Standard Test Method for 
Density, Relative Density, and API Gravity of Crude Petroleum and 
Liquid Petroleum Products by Thermohydrometer Method, 3rd Ed., December 
2012 (``API 9.3''), IBR approved for Sec.  3174.6(b)(4).
    (13) API MPMS Chapter 10 Section 4, Determination of Water and/or 
Sediment in Crude Oil by the Centrifuge Method (Field Procedure), 4th 
Ed., October 2013 (``API 10.4,'' ``10.4.9,'' and ``10.4.9.2''), IBR 
approved for Sec. Sec.  3174.6(b)(6), 3174.6(b)(6)(i), 
3174.6(b)(iii)(A), and 3174.6(b)(iii)(B).
    (14) API MPMS Chapter 11, Section 1, Temperature and Pressure 
Volume Correction Factors for Generalized Crude Oils, Refined Products 
and Lubricating Oils, 2nd Ed., May 2004, including Addendum 1, 
September 2007, Reaffirmed August 2013 (``API 11.1''), IBR approved for 
Sec. Sec.  3174.6(b)(10)(i), 3174.6(b)(10)(iii), 3174.6(b)(10)(v), and 
3174.10(h)(2).
    (15) API MPMS Chapter 12, Section 2, Part 1, Calculation of 
Petroleum Quantities Using Dynamic Measurement Methods and Volumetric 
Correction Factors, 2nd Ed., May 1995, Reaffirmed March 2014 (``API 
12.2.1''), IBR approved for Sec.  3174.10(h)(2).
    (16) API MPMS Chapter 12, Section 2, Part 3, Calculation of 
Petroleum Quantities Using Dynamic Measurement Methods and Volumetric 
Correction Factors, Proving Report, 1st Ed., October 1998, Reaffirmed 
March 2009 (``API 12.2.3''), IBR approved for Sec. Sec.  3174.11(d)(5) 
and 3174.11(j)(1).
    (17) API MPMS Chapter 12, Section 2, Part 4, Calculation of 
Petroleum Quantities Using Dynamic Measurement Methods and Volumetric 
Correction

[[Page 58971]]

Factors, Calculation of Base Prover Volumes by the Waterdraw Method, 
1st Ed., December, 1997, Reaffirmed March 2009 (``API 12.2.4''), IBR 
approved for Sec.  3174.11(c)(3).
    (18) API MPMS Chapter 18, Section 1, Measurement Procedures for 
Crude Oil Gathered From Small Tanks by Truck, 2nd Ed., April 1997, 
Reaffirmed February 2012 (``API 18.1''), IBR approved for Sec.  
3174.6(a).
    (19) API MPMS Chapter 21, Section 2, Electronic Liquid Volume 
Measurement Using Positive Displacement and Turbine Meters, 1st Ed., 
June 1998, Reaffirmed August 2011 (``API 21.2,'' ``API 21.2.10,'' 
``21.2.10.2,'' ``21.2.10.6,'' and ``API 21.2.9.2.13.2a''), IBR approved 
for Sec. Sec.  3174.8(b)(11)(iii), 3174.10(g)(2), 3174.10(h)(2), 
3174.10(j), 3174.10(j)(2), and 3174.10(j)(3).
    (20) API Recommended Practice (RP) 12 R1, Setting, Maintenance, 
Inspection, Operation and Repair of Tanks in Production Service, 5th 
Ed., August 1997, Reaffirmed April 2008 (``API RP 12 R1''), IBR 
approved for Sec.  3174.5(b)(1).
    (21) API RP 2556, Correction Gauge Tables For Incrustation, 2nd 
Ed., August 1993, Reaffirmed August 2013 (``API RP 2556''), IBR 
approved for Sec.  3174.5(c).
    (c) American Society for Testing and Materials (ASTM), 100 Bar 
Harbor Drive, P.O. Box C700, West Conshohocken, PA 19428; telephone 1-
877-909-2786; www.astm.org/Standard/index.shtml; ASTM also offers free 
read-only access to the material at www.astm.org/READINGLIBRARY/.
    (1) ASTM D-1250, Table 5A, Generalized Crude Oils Correction of 
Observed Gravity to API Gravity at 60[deg] F, September 1980 (``ASTM 
Table 5A''), IBR approved for Sec.  3174.6(b)(10)(i).
    (2) ASTM D-1250, Table 6A, Generalized Crude Oils Correction of 
Volume to 60[deg] F Against API Gravity at 60[deg] F, September 1980 
(``ASTM Table 6A''), IBR approved for Sec. Sec.  3174.6(b)(10)(iii), 
3174.6(b)(10)(v), and 3174.10(h)(2).

    Note 1 to Sec.  3174.4(b):  You may also be able to purchase 
these standards from the following resellers: Techstreet, 3916 
Ranchero Drive, Ann Arbor, MI 48108; telephone 734-780-8000; 
www.techstreet.com/api/apigate.html; IHS Inc., 321 Inverness Drive 
South, Englewood, CO 80112; 303-790-0600; www.ihs.com; SAI Global, 
610 Winters Avenue, Paramus, NJ 07652; telephone 201-986-1131; 
http://infostore.saiglobal.com/store/.

Sec.  3174.5  Oil measurement by manual tank gauging--general 
requirements.

    (a) Measurement objective. Oil measurement by manual tank gauging 
must accurately compute the total net standard volume of oil withdrawn 
from a properly calibrated sales tank by following the proper sequence 
of activities prescribed in Sec.  3174.6 of this subpart to determine 
the quantity and quality of oil being removed.
    (b) Oil tank equipment. (1) Each tank used for oil storage must 
meet the requirements of API RP 12 R1 (incorporated by reference, see 
Sec.  3174.4).
    (2) Each oil storage tank must be connected, maintained, and 
operated in compliance with Sec. Sec.  3173.2, 3173.6, and 3173.7 of 
this part.
    (3) All oil storage tanks, hatches, connections, and other access 
points must be vapor tight.
    (4) Each oil storage tank, unless connected to a vapor recovery 
system, must have a pressure-vacuum relief valve installed at the 
highest point in the vent line or connection with another tank. 
Pressure-vacuum relief valves must provide for normal inflow and 
outflow venting at an outlet pressure that is less than the thief hatch 
exhaust pressure and at an inlet pressure that is greater than the 
thief hatch vacuum setting.
    (5) All oil storage tanks must be clearly identified and have a 
unique number stenciled on the tank and maintained in a legible 
condition.
    (6) Each oil storage tank associated with an approved FMP must be 
set and maintained level.
    (7) Each oil storage tank associated with an approved FMP by tank 
gauging must be equipped with a distinct gauging reference point, with 
the height of the reference point stamped on a fixed bench-mark plate 
or stenciled on the tank near the gauging hatch and must be maintained 
in a legible condition, consistent with API 3.1A (incorporated by 
reference, see Sec.  3174.4).
    (c) Sales tank calibrations. The operator must accurately calibrate 
each oil storage tank associated with an approved FMP by tank gauging 
using API 2.2A and API RP 2556 (both incorporated by reference, see 
Sec.  3174.4). The operator must:
    (1) Determine sales tank capacities by tank calibration using 
actual tank measurements;
    (i) The unit volume must be in barrels (bbl); and
    (ii) The incremental height measurement must be in \1/8\-inch 
increments;
    (2) Recalibrate a sales tank if it is relocated, repaired, or the 
capacity is changed as a result of denting, damage, installation, 
removal of interior components, or other alterations; and
    (3) Submit sales tank calibration charts (tank tables) to the AO 
within 30 days after calibration. Tank tables may be in paper or 
electronic format.


Sec.  3174.6  Oil measurement by manual tank gauging--procedures.

    (a) The procedures for oil measurement by manual tank gauging from 
tanks with capacities of 1,000 bbl or less must comply with API 18.1 
(incorporated by reference, see Sec.  3174.4) as outlined in the 
following table and further described in paragraph (b) of this section. 
Tanks with capacities greater than 1,000 bbl must also comply as 
outlined in the following table and further described in paragraph (b) 
of this section.

------------------------------------------------------------------------
               Activity                         Section reference
------------------------------------------------------------------------
Isolate tank for at least 30 minutes..  3174.6(b)(1).
Determine opening oil temperature.....  3174.6(b)(2).
Take upper, middle, and outlet          3174.6(b)(3).
 samples..
Determine observed API gravity........  3174.6(b)(4).
Take opening gauge....................  3174.6(b)(5).
Determine S&W content.................  3174.6(b)(6).
Break the seal and transfer the oil;    3174.6(b)(7).
 then close the valve and reseal the
 tank..
Determine closing oil temperature.....  3174.6(b)(8).
Take closing gauge....................  3174.6(b)(9).
Complete measurement ticket...........  3174.6(b)(10).
------------------------------------------------------------------------

    (b) The operator must take the steps in the order prescribed in the 
following paragraphs to manually determine the quality and quantity of 
oil measured under field conditions at an FMP.

[[Page 58972]]

    (1) Isolate tank. Isolate the tank for at least 30 minutes to allow 
contents to settle before proceeding with tank gauging operations. The 
tank isolating valves must be closed and sealed under Sec.  3173.2 of 
this part.
    (2) Determine opening oil temperature. Determination of the 
temperature of oil contained in a sales tank must comply with 
paragraphs (b)(2)(i) through (iv) of this section and API 7 
(incorporated by reference, see Sec.  3174.4).
    (i) Glass thermometers must be clean, be free of mercury 
separation, and have a minimum graduation of 1.0[deg] F.
    (ii) Portable electronic thermometers must have a minimum 
graduation of 0.1[deg] F and have an accuracy of 0.5[deg] 
F.
    (iii) Suspend the cup-case thermometer assembly or portable 
electronic thermometer in the tank by immersing it at the approximate 
vertical center of the fluid column, not less than 12 inches from the 
shell of the tank, for the minimum immersion time prescribed in the 
following table (API 7, Table 6 (incorporated by reference, see Sec.  
3174.4)):

                            Minimum Immersion Times for Oil Temperature Determination
----------------------------------------------------------------------------------------------------------------
 
----------------------------------------------------------------------------------------------------------------
                                                                 Minimum Immersion Time
----------------------------------------------------------------------------------------------------------------
                                       Portable Electronic                 Woodback Cup-Case Assembly
                                        Thermometer.
----------------------------------------------------------------------------------------------------------------
       API Gravity at 60[deg] F        In-Motion*               In-Motion*               Stationary
----------------------------------------------------------------------------------------------------------------
>50..................................  30 Seconds.............  5 Minutes..............  10 Minutes.
40-49................................  30 Seconds.............  5 Minutes..............  15 Minutes.
30-39................................  45 Seconds.............  12 Minutes.............  20 Minutes.
20-29................................  45 Seconds.............  20 Minutes.............  35 Minutes.
<20..................................  75 Seconds.............  35 Minutes.............  60 Minutes.
----------------------------------------------------------------------------------------------------------------
* In-Motion means repeatedly raising and lowering the assembly 1 foot above and below the desired depth.

    (iv) Record the temperature to the nearest 1.0[deg] F for glass 
thermometers or 0.1[deg] F for portable electronic thermometers.
    (3) Take oil samples. Sampling of oil removed from an FMP tank must 
yield a representative sample of the oil and its physical properties 
and must comply with paragraphs (b)(3)(i) through (iii) of this section 
and API 8.1 (incorporated by reference, see Sec.  3174.4).
    (i) First, using a clean sampling thief, take an upper sample from 
the vertical center of the upper one-third of the fluid column. 
Transfer to a clean centrifuge tube a 100-part sample for 200-part 
(percent) centrifuge tubes or a 50-milliliter sample for 100-milliliter 
centrifuge tubes and cork the tube. Use the contents of the tube to 
determine sediment and water content under paragraph (b)(6) of this 
section.
    (ii) Second, take a middle sample from the vertical center of the 
middle one-third of the fluid column to determine the observed API oil 
gravity and temperature. Immediately use this sample to determine oil 
gravity under paragraph (b)(4) of this section.
    (iii) After determining observed API oil gravity, take an outlet 
sample with the inlet opening of the sample thief at the level of the 
bottom of the tank outlet. Transfer to a second clean centrifuge tube a 
100-part sample for 200-part (percent) centrifuge tubes or a 50-
milliliter sample for 100-milliliter centrifuge tubes and cork the 
tube. Use the contents of the tube to determine sediment and water 
content under paragraph (b)(6) of this section.
    (4) Determine observed oil gravity. Tests for oil gravity must 
comply with paragraphs (b)(4)(i) through (iv) of this section and API 
9.3 (incorporated by reference, see Sec.  3174.4).
    (i) The thermohydrometer must be calibrated for an oil gravity 
range that includes the observed gravity of the oil sample being tested 
and must be clean, with a clearly legible oil gravity scale and with no 
loose shot weights.
    (ii) Slowly insert the thermohydrometer into the filled sample 
thief about 2 API gravity divisions below the expected settled 
position. Release with a slight spin.
    (iii) Remove any air bubbles and allow the temperature to stabilize 
for at least 5 minutes.
    (iv) Read and record the observed API oil gravity to the nearest 
0.1 degree. For transparent liquids, read to the nearest scale division 
at the point on the scale at which the surface of the liquid cuts the 
scale. For opaque oil, read the scale at the top of the meniscus and 
deduct 0.1 degree gravity from the reading. Read and record the 
thermohydrometer temperature reading to the nearest 1.0[deg] F.
    (5) Take opening gauge. Take and record the tank opening gauge only 
after upper, middle, and outlet samples have been taken. Gauging must 
comply with paragraphs (b)(5)(i) through (b)(5)(v) of this section and 
API 3.1A (incorporated by reference, see Sec.  3174.4).
    (i) Gauging must use the proper bob for the particular measurement 
method, i.e., either innage gauging or outage gauging.
    (ii) Gauging must use gauging tapes made of steel or corrosion-
resistant material with graduation clearly legible. The gauging tape 
must not be kinked or spliced.
    (iii) Acceptable gauging requires either obtaining two consecutive 
identical gauging measurements or three consecutive measurements within 
\1/8\-inch of each other, averaging these three measurements to the 
nearest \1/8\ inch.
    (iv) A suitable product-indicating paste may be used on the tape to 
facilitate the reading. The use of chalk or talcum powder is 
prohibited.
    (v) The same tape and bob must be used for both opening and closing 
gauges.
    (6) Determine S&W content. Using the oil samples in the centrifuge 
tubes collected from the upper and outlet fluid column (see paragraph 
(b)(3) of this section), determine the S&W content of the oil in the 
sales tanks, according to paragraphs (b)(6)(i) through (iii) of this 
section and API 10.4 (incorporated by reference, see Sec.  3174.4).
    (i) A thoroughly mixed oil sample-solvent combination, prepared in 
accordance with the procedure described in API 10.4.9.2 (incorporated 
by reference, see Sec.  3174.4), must be heated to 140[deg] F before 
centrifuging.
    (ii) The heated sample must be whirled in the centrifuge for not 
less than 5 minutes. At the conclusion of centrifuging, the temperature 
must be a minimum of 115[deg] F without water-saturated diluents or 
125[deg] F with water-saturated diluents.
    (iii)(A) For 100-milliliter tubes, refer to API 10.4.9 Figure 1 
(incorporated by reference, see Sec.  3174.4). Read and record the 
volume of both water and sediment in each tube and add the readings

[[Page 58973]]

together reporting the sum as the percent of S&W. Record the S&W to 
three decimal places.
    (B) For 200-part (percent) tubes, refer to API 10.4.9 Figure 2 
(incorporated by reference, see Sec.  3174.4). The percent of S&W is 
the average of the values directly read from the tubes. Record the S&W 
to three decimal places.
    (7) Transfer oil. Break the tank load line valve seal and transfer 
oil to the tanker truck. After transfer is complete, close the tank 
valve and seal the valve under Sec. Sec.  3173.2 and 3173.5 of this 
part.
    (8) Determine closing oil temperature. Determine the closing oil 
temperature using the procedures in paragraph (b)(2) of this section.
    (9) Take closing gauge. Take the closing tank gauge using the 
procedures in paragraph (b)(5) of this section.
    (10) Complete measurement ticket. The operator, purchaser, or 
transporter, as appropriate, must complete the measurement ticket (run 
ticket) as required by paragraphs (b)(10)(i) through (vii) of this 
section and by Sec.  3174.12(a) of this subpart.
    (i) The observed oil gravity must be corrected to 60[deg] F using 
ASTM Table 5A or API 11.1 (both incorporated by reference, see Sec.  
3174.4).
    (ii) Use the opening gauge with the tank-specific calibration 
charts (tank tables) (see paragraph (e) of this section) to compute the 
total observed volume of oil prior to sales.
    (iii) Correct the total observed volume of oil prior to sales to 
60[emsp14][deg]F using the calculated API oil gravity at 60[deg] F (see 
paragraph (b)(1) of this section) and the opening oil temperature using 
ASTM Table 6A or API 11.1 (both incorporated by reference, see Sec.  
3174.4) to determine the gross standard volume prior to sales.
    (iv) Use the closing gauge with the tank-specific calibration 
charts (tank tables) to compute the total observed volume of oil after 
sales.
    (v) Correct the total observed volume of oil after sales to 60[deg] 
F using the API oil gravity corrected to 60[deg] F (see paragraph 
(b)(1) of this section) and the closing oil temperature using ASTM 
Table 6A or API 11.1 (both incorporated by reference, see Sec.  3174.4) 
to determine the gross standard volume after sales.
    (vi) The gross standard volume sold is the difference between the 
gross standard volume prior to sales and the gross standard volume 
after sales.
    (vii) The gross standard volume sold must be corrected for 
quantities of non-merchantable substances such as S&W to determine net 
standard volume (may be corrected at a later time prior to Oil and Gas 
Operations Report submission).


Sec.  3174.7  LACT system--general requirements.

    (a) A LACT system must meet the construction and operation 
requirements and minimum standards of this section and Sec.  3174.8 and 
API 6.1 (incorporated by reference, see Sec.  3174.4).
    (b) A LACT system must be proven as prescribed in Sec.  3174.11 of 
this subpart. Measurement tickets must be completed under Sec.  
3174.12(b) of this subpart before conducting proving operations.
    (c) The following table lists the requirements under which the 
operator must measure oil using a LACT system:

                Standards to Measure Oil by a LACT System
------------------------------------------------------------------------
                 Subject                         Section reference
------------------------------------------------------------------------
Required LACT system components..........  3174.8(a)
Accessibility of LACT system components    3174.7(d)
 to AO.
Notification of LACT system failures or    3174.7(e)
 malfunctions adversely affecting
 accurate measurement.
Oil gravity, temperature, and S&W content  3174.7(f)
 testing requirements.
Required LACT system component--charging   3174.8(b)(1)
 pump and motor.
Required LACT system component--sampler..  3174.8(b)(2)
Required LACT system component--composite  3174.8(b)(3)
 sample container.
Required LACT system component--mixing     3174.8(b)(4)
 system.
Required LACT system component--strainer.  3174.8(b)(5)
Required LACT system component--air        3174.8(b)(6)
 eliminator.
Required LACT system component--S&W        3174.8(b)(7)
 monitor.
Required LACT system component--diverter   3174.8(b)(8)
 valve or shut-off valve.
Required LACT system component--positive   3174.8(b)(9)
 displacement meter.
Required LACT system component--pressure   3174.8(b)(10)
 indicating device.
Required LACT system component--           3174.8(b)(11)
 electronic temperature averaging device.
Required LACT system component--meter      3174.8(b)(12)
 proving connections.
Required LACT system component--back-      3174.8(b)(13)
 pressure and check valves.
------------------------------------------------------------------------

    (d) All components of a LACT system must be accessible for 
inspection by the AO.
    (e)(1) The operator must notify the AO within 24 hours of any LACT 
system failures or equipment malfunctions which may have resulted in 
measurement error.
    (2) Such system failures or equipment malfunctions include, but are 
not limited to, electrical, meter, and other failures that affect oil 
measurement.
    (f) Any tests conducted on oil samples extracted from LACT system 
samplers for determination of temperature, oil gravity, and S&W content 
must meet the requirements and minimum standards in Sec. Sec.  
3174.6(b)(2), (4), and (6) of this subpart.
    (g) Automatic temperature compensators and automatic temperature 
and gravity compensators are prohibited.


Sec.  3174.8  LACT system--components and operating requirements.

    (a) LACT system components. Each LACT system must include all of 
the following components:
    (1) Charging pump and motor;
    (2) Sampler, composite sample container, and mixing system;
    (3) Strainer;
    (4) Air eliminator;
    (5) S&W monitor;
    (6) Diverter valve or shut-off valve;
    (7) Positive displacement meter;
    (8) Electronic temperature averaging device;
    (9) Meter proving connections; and
    (10) Meter back-pressure valve and check valve.
    (b) Operation of all LACT system components must meet the following 
minimum standards:
    (1) Charging pump and motor. The LACT system must include an 
electrically driven pump that has a discharge pressure compatible with 
the meter used and sized to assure that the turbulent flow in the LACT 
main stream

[[Page 58974]]

piping and that the measurement uncertainty levels in Sec.  3174.3(a) 
of this subpart are met.
    (2) Sampler. The sampler probe must extend into the center one-
third of the flow piping in a vertical run, at least 3 pipe diameters 
downstream of any pipe fitting. The probe must always be in a 
horizontal position.
    (3) Composite sample container. The composite sample container must 
be capable of holding the sample under pressure, be equipped with a 
vapor-proof top closure, and operated to prevent the unnecessary escape 
of vapor. The container must be emptied and cleaned upon completion of 
sample withdrawal.
    (4) Mixing system. The mixing system must completely blend the 
sample (inside the sample composite container) into a homogeneous 
mixture before and during the withdrawal of a portion of a sample for 
testing.
    (5) Strainer. The strainer must be constructed so that it may be 
depressurized, opened, and cleaned. The strainer must be located 
upstream of the meter and be made of corrosion resistant material of a 
mesh size no larger than \1/4\-inch.
    (6) Air eliminator. An air eliminator must be installed to prevent 
air or gas from entering the meter.
    (7) S&W monitor. The S&W monitor must be an internally plastic-
coated capacitance probe mounted in a vertical pipe located upstream 
from both the meter and the diverter valve or shut-off valve.
    (8) Diverter valve or shut-off valve. The diverter valve or shut-
off valve must be configured to prevent the flow of oil through the 
positive displacement meter whenever the S&W monitor detects S&W above 
a pre-determined limit, usually a contractual value agreed upon by the 
purchaser and the seller.
    (9) Positive displacement meter. The meter must register volumes 
determined by a system which constantly and mechanically isolates the 
flowing oil into segments of known volume, and must be equipped with a 
non-resettable totalizer. The meter must include or allow for the 
attachment of a device which generates at least 8,400 pulses per barrel 
of registered volume.
    (10) Pressure indicating device. The system must have a pressure 
indicating device downstream of the meter, but upstream of meter 
proving connections.
    (11) Electronic temperature averaging device. An electronic 
temperature averaging device must be installed, operated, and 
maintained as follows:
    (i) The temperature sensor must be placed as required under API 7.1 
(incorporated by reference, see Sec.  3174.4);
    (ii) The electronic temperature averaging device must be flow 
proportional and take a temperature reading at least once per barrel;
    (iii) The average temperature for the measurement ticket must be 
calculated by the volumetric averaging method using API 21.2.9.2.13.2a 
(incorporated by reference, see Sec.  3174.4);
    (iv) The temperature averaging device must have a reference 
accuracy of 0.5 [deg]F, or better; and
    (v) The temperature averaging device must include a display of 
instantaneous temperature and the average temperature calculated since 
the measurement ticket was opened. The temperatures must be displayed 
to the nearest 0.1 [deg]F.
    (12) Meter-proving connections. All meter-proving connections must 
be installed downstream from the LACT meter with the line valve(s) 
between the inlet and outlet of the prover loop having a double block 
and bleed design feature to provide for leak testing during proving 
operations.
    (13) Back-pressure and check valves. The back-pressure valve and 
check valve must be installed downstream from the meter and meter-
proving connections.


Sec.  3174.9  Coriolis measurement systems (CMS)--general requirements 
and components.

    (a) The specific makes, models, and sizes of Coriolis meter and 
associated software that are identified and described at www.blm.gov 
are approved for use.
    (b) A CMS must meet the operational requirements and minimum 
standards of this section, Sec.  3174.10 and API 5.6 (incorporated by 
reference, see Sec.  3174.4).
    (c) A CMS system must be proven at the frequency and under the 
requirements of Sec.  3174.11 of this subpart. Measurement tickets must 
be completed under Sec.  3174.12(b) of this subpart before conducting 
proving operations.
    (d) The following table lists the requirements and applicable API 
standards under which an operator must measure oil using a CMS:

                     Standards Applicable to CMS Use
------------------------------------------------------------------------
                                                       API Reference
                                    Section          (incorporated by
           Subject                 reference        reference, see Sec.
                                                          3174.4)
------------------------------------------------------------------------
Coriolis meter components....  3174.9(e)........  API 5.6.
Minimum pulse output.........  3174.10(a).......  (None).
Specifications...............  3174.10(b).......  (None).
Orientation..................  3174.10(c).......  API 5.6.3.2.(e).
Notification of changes......  3174.10(d).......  (None).
Non-resettable totalizer.....  3174.10(e).......  (None).
Verification of meter zero     3174.10(f).......  API 5.6.8.3.
 value.
Determination of net standard  3174.10(g).......  (None).
 volume.
Determination of API oil       3174.10(h).......  (None).
 gravity.
Display requirements.........  3174.10(i)(1)....  (None).
Displayed information          3174.10(i)(2)....  (None).
 requirements.
Onsite information             3174.10(i)(3)....  (None).
 requirements.
Onsite log information         3174.10(i)(4)....  (None).
 requirements.
Quantity transaction record..  3174.10(j)(1)....  API 21.2.10.3.
Configuration log............  3174.10(j)(2)....  API 21.2.10.2.
Event log....................  3174.10(j)(3)....  API 21.2.10.6.
Alarm log....................  3174.10(j)(4)....  (None).
Data protection..............  3174.10(k).......  (None).
------------------------------------------------------------------------


[[Page 58975]]

    (e) A CMS at an FMP must be installed with the following minimum 
components listed in order from upstream to downstream:
    (1) Charge pump, if necessary to maintain the minimum required 
pressure under API 5.6.3.2 (incorporated by reference, see Sec.  
3174.4) and flow rate to achieve the uncertainty levels required under 
Sec.  3174.3(a) of this subpart;
    (2) Block valve upstream of the meter (for zero value 
verification);
    (3) Air/vapor eliminator upstream of the meter;
    (4) Coriolis meter (see Sec.  3174.10(a) through (f) of this 
subpart);
    (5) RTD downstream of the meter, but upstream of the meter-proving 
connection, with a reference accuracy of 0.5 [deg]F, or 
better, and on the list of type-tested equipment maintained at 
www.blm.gov;
    (6) Pressure transducer downstream of the meter, but upstream of 
the meter-proving connection, with a reference accuracy of 0.25 psi, or 0.25 percent of reading, or better, 
whichever is less restrictive, and on the list of type-tested equipment 
maintained at www.blm.gov;
    (7) Density measurement verification point;
    (8) Sampling system as required in Sec.  3174.8 paragraphs (b)(2) 
through (4) of this subpart, if S&W is to be used in determining net 
oil volume. If no sampling system is included, the S&W must be reported 
as zero (see Sec.  3174.10(g)(3) of this subpart);
    (9) Meter-proving connection (block and bleed valves) downstream of 
the meter;
    (10) Back-pressure valve downstream of the meter; and
    (11) Check valve downstream of the meter.


Sec.  3174.10  Coriolis measurement systems--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 which constantly emits electronic pulse signals representing the 
registered volume measured. The pulse per unit volume must be set at a 
minimum of 8,400 pulses per barrel.
    (b) Meter specifications. (1) The Coriolis meter specifications 
must clearly identify the make and model of the Coriolis meter to which 
they apply and must include the following:
    (i) The reference accuracy for both mass flow rate and density, 
stated in either percent of reading, percent of full scale, or units of 
measure;
    (ii) 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. These specifications must be 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'');
    (iii) The stability of the zero reading for both mass and 
volumetric flow rate. The specifications must be stated in percent of 
reading, percent of full scale, or units of measure;
    (iv) Minimum lengths of straight piping upstream and downstream of 
the meter necessary to achieve the stated reference accuracy;
    (v) Design limits for flow rate and pressure; and
    (vi) Pressure drop through the meter as a function of flow rate and 
fluid viscosity.
    (2) Submission of meter specifications. The operator must submit 
Coriolis meter specifications to the BLM upon request.
    (c) Meter orientation. The Coriolis meter must be oriented using 
API 5.6.3.2.(e) (incorporated by reference, see Sec.  3174.4).
    (d) Changes to calibration factors. The operator must notify the AO 
within 24 hours of any changes to any Coriolis meter internal 
calibration factors including, but not limited to, meter factor, pulse-
scaling factor, flow-calibration factor, density-calibration factor, or 
density-meter factor.
    (e) Non-resettable totalizer. The Coriolis meter must have a non-
resettable internal totalizer for registered volume.
    (f) Verification of meter zero value. Before proving the meter, or 
any time the AO requests it, the zero value stored in the meter using 
API 5.6.8.3 (incorporated by reference, see Sec.  3174.4) must be 
verified by stopping the flow through the meter and then monitoring the 
indicated mass flow rate under this condition. If the zero error equals 
or exceeds the stated zero stability specification of the meter, as 
calculated by the following equation (API 5.6, Eq. (2) (incorporated by 
reference, see Sec.  3174.4)), the meter must be zeroed:
[GRAPHIC] [TIFF OMITTED] TP30SE15.003


Where:
Err0 = zero error (percent)
q0 = observed zero value (flow rate)
qf = flow rate during normal operation

    (g) Determination of net standard volume. The net standard volume 
on which royalty is due must be calculated as follows:
    (1) Calculate the corrected registered volume at the close of each 
measurement ticket by multiplying the registered volume over the 
measurement ticket period by the meter factor determined from the most 
recent proving.
    (2) Calculate the gross standard volume at the close of each 
measurement ticket by multiplying the corrected registered volume by 
the CPL and CTL determined from the average pressure and average 
temperature, respectively, taken over the measurement ticket period. 
The average pressure and temperature must be determined using API 
21.2.9.2.13.2a (incorporated by reference, see Sec.  3174.4).
    (3) Calculate the net standard volume at the close of each 
measurement ticket by multiplying the gross standard volume by the 
quantity of one minus the S&W content (expressed as a fraction) from 
the composite sample taken over the measurement ticket period. If the 
CMS does not include a composite sampling system, the S&W content is 
zero and the net standard volume will equal the gross standard volume.
    (h) Determination of API oil gravity. The API oil gravity reported 
for the measurement ticket period must be determined by one of the 
following methods:
    (1) From a composite sample taken under the requirements of Sec.  
3174.6(b)(4) of this subpart; or
    (2) Calculated from the average density, average temperature, and 
average pressure as measured by the CMS over the measurement ticket 
period under API 21.2.9.2.13.2a (incorporated by reference, see Sec.  
3174.4). The average density must be corrected to base temperature and 
pressure using ASTM Table 6A or API 11.1, (both incorporated by 
reference, see Sec.  3174.4).
    (i) Required on-site information. (1) The CMS display must be 
readable without using data collection units, laptop computers, or any 
special equipment, and must be on-site and accessible to the AO.
    (2) For each CMS, the following values and corresponding units of 
measurement must be displayed:
    (i) The instantaneous mass flow rate through the meter (pounds/
day);
    (ii) The instantaneous density of liquid (pounds/bbl);
    (iii) The instantaneous registered volumetric flow rate through the 
meter (bbl/day);
    (iv) The meter factor;
    (v) The instantaneous pressure (psi);
    (vi) The instantaneous temperature ([deg]F);

[[Page 58976]]

    (vii) The cumulative gross standard volume through the meter (non-
resettable totalizer) (bbl);
    (viii) The previous day's gross standard volume through the meter 
(bbl); and
    (ix) The meter alarm conditions.
    (3) The following information must be correct, be maintained in a 
legible condition, and be accessible to the AO at the FMP without the 
use of data collection equipment, laptop computers, or any special 
equipment:
    (i) The make, model, and size of each sensor; and
    (ii) The make, range, calibrated span, and model of the pressure 
and temperature transducer used to determine gross standard volume.
    (4) A log must be maintained of all meter factors, zero 
verifications, and zero adjustments. For zero adjustments, the log must 
include the zero value before adjustment and the zero value after 
adjustment. This log must be located on-site and accessible to the AO.
    (j) Audit trail requirements. The information specified in 
paragraphs (j)(1) through (4) of this section must be recorded and 
retained under the recordkeeping requirements of Sec.  3170.7 of this 
part. Audit trail requirements must follow API 21.2.10 (incorporated by 
reference, see Sec.  3174.4). All data must be available and submitted 
to the BLM upon request.
    (1) Quantity transaction record (QTR). Follow the requirements for 
a CMS measurement ticket in Sec.  3174.12(b) of this subpart.
    (2) Configuration log. The configuration log must comply with the 
requirements of API 21.2.10.2 (incorporated by reference, see Sec.  
3174.4). The configuration log must contain and identify all constant 
flow parameters used in generating the QTR.
    (3) Event log. The event log must comply with the requirements of 
API 21.2.10.6 (incorporated by reference, see Sec.  3174.4). In 
addition, the event log must be of sufficient capacity to record all 
events such that the operator can retain the information under the 
recordkeeping requirements of Sec.  3170.7 of this part.
    (4) Alarm log. The type and duration of any of the following alarm 
conditions must be recorded:
    (i) Density deviations from acceptable parameters; and
    (ii) Instances in which the flow rate exceeded the manufacturer's 
maximum recommended flow rate or were below the manufacturer's minimum 
recommended flow rate.
    (k) Data protection. Each CMS must have installed and maintained in 
an operable condition a backup power supply or a nonvolatile memory 
capable of retaining all data in the unit's memory to ensure that the 
audit trail information required under paragraph (j) of this section is 
protected.


Sec.  3174.11  Meter proving requirements.

    (a) Applicability. This section specifies the minimum requirements 
for conducting volumetric meter proving for all FMP meters. The FMP 
meter must not be used for royalty volume determination unless all of 
the requirements in this section are met.
    (b) Summary. The following table lists the requirements and minimum 
standards for proving FMP meters:

                Minimum Standards for Proving FMP Meters
------------------------------------------------------------------------
                  Subject                         Section reference
------------------------------------------------------------------------
Meter Prover..............................  3174.11(c).
Meter Proving Runs........................  3174.11(d).
Minimum Proving Frequency.................  3174.11(e).
Excessive Meter Factor Deviation..........  3174.11(f).
Temperature Verification..................  3174.11(g).
Pressure Verification.....................  3174.11(h).
Density Verification......................  3174.11(i).
Meter Proving Reporting Requirements......  3174.11(j).
------------------------------------------------------------------------

    (c) Meter prover. Acceptable provers are positive displacement 
master meters, Coriolis master meters, and displacement provers. The 
operator must ensure that the meter prover used to determine the meter 
factor has a valid certificate of calibration available for review by 
the AO on site that shows that the prover, identified by serial number 
assigned to and inscribed on 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 0.0002 
(0.02 percent repeatability). The master meter must not be mechanically 
compensated for oil gravity or temperature; its readout must indicate 
units of volume without corrections. The certified meter factor must be 
documented on the calibration certificate and must be calibrated no 
less frequently than every 90 days under API 4.5 (incorporated by 
reference, see Sec.  3174.4).
    (2) Displacement provers must meet the requirements under API 4.2 
(incorporated by reference, see Sec.  3174.4) and be calibrated using 
the water-draw method under API 4.9.2 (incorporated by reference, see 
Sec.  3174.4), at the following frequencies:
    (i) Portable provers must be calibrated at least once every 36 
months; and
    (ii) Permanently installed provers must be calibrated at least once 
every 60 months.
    (3) The base prover volume of a displacement prover must be 
calculated under API 12.2.4 (incorporated by reference, see Sec.  
3174.4).
    (4) Displacement provers must be sized to obtain a displacer 
velocity through the prover that is within the appropriate range during 
proving as follows:

------------------------------------------------------------------------
                                              Minimum         Maximum
               Prover type                 velocity (ft/   velocity (ft/
                                               sec)            sec)
------------------------------------------------------------------------
Displacement--unidirectional............             0.5              10
Displacement--bidirectional.............             0.5               5
Piston (Small volume prover)............            0.25               5
------------------------------------------------------------------------


[[Page 58977]]

    Fluid velocity is calculated by the following equation (API 4.2., 
Eq. 12 (incorporated by reference, see Sec.  3174.4)):
[GRAPHIC] [TIFF OMITTED] TP30SE15.004


Where:
Vd = displacer velocity, ft/sec.
Dp = inside diameter of prover, in.
Q = flow rate, barrels per hour (bbl/hr)

    (d) Meter proving runs. Meter proving must follow the applicable 
section(s) of API 4.1--Proving Systems (incorporated by reference, see 
Sec.  3174.4).
    (1) Meter proving must be performed under normal operating fluid 
pressure, fluid temperature, and fluid type and composition, as 
follows:
    (i) The oil flow rate through the LACT or CMS during proving must 
be within 10 percent of the normal flow rate;
    (ii) The absolute pressure as measured by the LACT or CMS during 
proving must be within 10 percent of the normal operating absolute 
pressure; and
    (iii) The gravity of the oil during proving must be within 5 
degrees API of the normal oil gravity.
    (iv) If the normal flow rate, pressure, temperature, or oil gravity 
vary by more than the limits defined in paragraphs (d)(i) through (iii) 
of this section, meter provings must be conducted under three 
conditions, namely, at the lower limit of normal operating conditions, 
at the upper limit of normal operation conditions, and at the midpoint 
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 in a LACT 
system or the Coriolis meter in a CMS, pulse interpolation must be used 
in accordance with API 4.6 (incorporated by reference, see Sec.  
3174.4).
    (3) Proving runs must be made until the calculated meter factor 
from five consecutive runs match within a tolerance of 0.0005 (0.05 
percent) between the highest and the lowest value.
    (4) The new meter factor is the arithmetic average of the meter 
factors calculated from the five consecutive runs.
    (5) Meter factor computations must follow the sequence described in 
API 12.2.3 (incorporated by reference, see Sec.  3174.4).
    (6) If multiple meters factors are determined over a range of 
normal operating conditions, then:
    (i) A single meter factor may be calculated as the arithmetic 
average of the three meter factors determined over the range of normal 
operating conditions; or
    (ii) The metering system may apply a dynamic meter factor derived 
from the three meter factors determined over the range of normal 
operating conditions.
    (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) The back-pressure valve may be adjusted after proving only 
within the normal operating fluid flow rate and fluid pressure as 
described in paragraph (d)(1) of this section. If the back-pressure 
valve is adjusted after proving, the operator 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 in a CMS.
    (e) Minimum proving frequency. The operator must prove any FMP 
meter before removal or sales of production after any of the following 
events:
    (1) Initial meter installation;
    (2) Each time the registered volume flowing through the meter, as 
measured on the non-resettable totalizer from the last proving, 
increases by 50,000 bbl or quarterly, whichever occurs first;
    (3) Meter zeroing (CMS);
    (4) Modification of mounting conditions;
    (5) A change in fluid temperature outside of the RTD's calibrated 
span;
    (6) A change in pressure, density, or flow rate that is outside of 
the operating proving limits;
    (7) The mechanical or electrical components of the meter have been 
opened, changed, repaired, removed, exchanged, or reprogrammed; or
    (8) At the request of the AO.
    (f) Excessive meter factor deviation. (1) 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 re-proved before 
returning the meter to service.
    (2) 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.
    (3) The proving report submitted under paragraph (j) of this 
section must clearly show the most recent meter factor and describe all 
subsequent repairs and adjustments.
    (g) Verification of the temperature averager or RTD. As part of 
each required meter proving, the temperature averager for a LACT system 
and the RTD used in conjunction with a CMS must be verified against a 
known standard according to the following:
    (1) The temperature averager or RTD must be compared with a test 
thermometer traceable to NIST and with a stated accuracy of 0.25 [deg]F or better.
    (2) The temperature reading displayed on the temperature averager 
or tertiary device 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'' from the probe of the temperature averager 
or RTD; or
    (ii) Both the test thermometer and probe of the temperature 
averager or RTD must be placed in an insulated water bath. The water 
bath temperature must be within 10 [deg]F of the normal flowing 
temperature of the oil.
    (3) The displayed reading of instantaneous temperature from the 
temperature averager or the tertiary device must be compared with the 
reading from the test thermometer. If they differ by more than 0.5 
[deg]F, then:
    (i) The temperature averager or tertiary device must be adjusted to 
match the reading of the test thermometer; or
    (ii) The difference in temperatures must be noted on the meter 
proving report and all temperatures used until the next proving must be 
adjusted by the difference.
    (h) Verification of the pressure transducer (CMS only). (1) The 
pressure transducer must be compared with a test pressure device (dead 
weight or pressure gauge) traceable to NIST and with a stated accuracy 
at least two times better than the reference accuracy of the pressure 
device being tested.
    (2) The pressure reading displayed on the tertiary device must be 
compared with the reading of the test pressure device.
    (3) 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) At a point that represents the normal flowing pressure 
through the Coriolis meter.
    (4) If the pressure applied by the test pressure device and the 
pressure displayed on the tertiary device vary by more than the 
required accuracy of the pressure transducer, the pressure transducer 
must be adjusted to read

[[Page 58978]]

within the pressure device's stated accuracy of the test pressure 
device.
    (i) Density verification (CMS only). 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 specified under API 5.6.9.1.2.1. (incorporated 
by reference, see Sec.  3174.4). The difference between the indicated 
density determined from the CMS and the independently determined 
density must be within the specified density reference accuracy 
specification of the Coriolis meter.
    (j) Meter proving reporting requirements. (1) The operator must 
report to the AO all meter-proving and volume adjustments after any 
LACT system or CMS malfunction, including excessive meter-factor 
deviation, using the appropriate form in either API 12.2.3, or API 5.6 
(both incorporated by reference, see Sec.  3174.4), or any similar 
format showing the same information as the API form, provided that the 
calculation of meter factors maintains the proper calculation sequence 
and rounding.
    (2) In addition to the information required under paragraph (j)(1) 
of this section, each meter-proving report must also show the:
    (i) FMP number;
    (ii) Lease number, CA number, or unit PA number;
    (iii) The temperature from the test thermometer and the temperature 
from the temperature averager or tertiary device;
    (iv) For CMS, the pressure applied by the pressure test device and 
the pressure reading from the tertiary device at the three points 
required under paragraph (h)(3) of this section; and
    (v) The ``as left'' fluid flow rate and fluid pressure, if the 
back-pressure valve is adjusted after proving as described in Sec.  
3174.11(d)(9).
    (3) The operator must submit the meter-proving report to the AO no 
later than 14 days after the meter proving.


Sec.  3174.12  Measurement tickets.

    (a) Manual tank gauging. Immediately after oil is measured by 
manual tank gauging under Sec. Sec.  3174.5 and 3174.6 of this subpart, 
the operator, purchaser, or transporter, as appropriate, must complete 
a uniquely numbered measurement ticket, in either paper or electronic 
format, with the following information:
    (1) Lease, unit, or communitization agreement number;
    (2) FMP number;
    (3) Unique tank number and nominal tank capacity;
    (4) Opening and closing dates and times;
    (5) Opening and closing gauges and observed temperatures in [deg]F;
    (6) Total observed volume prior to sales and after sales;
    (7) Total gross standard volume removed from the tank;
    (8) Observed API oil gravity and temperature;
    (9) API oil gravity at 60 [deg]F;
    (10) S&W percent;
    (11) Unique number of each seal removed and installed;
    (12) Name of the individual performing the manual tank gauging;
    (13) Name of the operator; and
    (14) Name of the operator's representative certifying that the 
measurement is correct.
    (15) If the operator does not agree with the tank gauger's 
measurement, the operator must notify the AO within 7 days of the 
reasons for the operator's disagreement with the tank gauger's 
measurement.
    (b) LACT system and CMS. (1) Before conducting proving operations 
on a LACT system or CMS and, at a minimum, at the beginning of every 
month, the operator, purchaser, or transporter, as appropriate, must 
complete a uniquely numbered measurement ticket, in either paper or 
electronic format, with the following information:
    (i) Lease, unit, or communitization agreement number;
    (ii) FMP number;
    (iii) Opening and closing dates;
    (iv) Opening and closing totalizer readings of the registered 
volume;
    (v) Meter factor from the most recent proving;
    (vi) Total gross standard volume removed through the LACT system or 
CMS;
    (vii) API oil gravity. For API oil gravity determined from a 
composite sample, the API oil gravity at 60[deg] F and the observed API 
oil gravity and temperature in [deg]F. For API oil gravity determined 
from average density (CMS only), the average uncorrected density 
determined by the CMS;
    (viii) The average temperature in [deg]F;
    (ix) The average flowing pressure in psig;
    (x) S&W percent;
    (xi) Unique number of each seal removed and installed;
    (xii) Name of the purchaser's representative;
    (xiii) Name of the operator; and
    (xiv) Name of the operator's representative certifying that the 
measurement is correct.
    (2) If the purchaser or transporter takes the LACT system or CMS 
measurement, and if the operator does not agree with the measurement, 
the operator must notify the AO within 7 days of the reasons for the 
operator's disagreement with the LACT system or CMS measurement.
    (3) The accumulators used in the determination of average pressure, 
average temperature, and average density must be reset to zero whenever 
a new measurement ticket is opened.


Sec.  3174.13  Oil measurement by other methods.

    (a) Any method of oil measurement other than manual tank gauging, 
LACT system, or CMS at an FMP requires BLM approval.
    (b)(1) Any operator requesting approval to use alternate oil 
measurement equipment must submit to the BLM performance data, actual 
field test results, laboratory test data, or any other supporting data 
or evidence that demonstrates that the proposed alternate oil equipment 
would meet or exceed the objectives of the applicable minimum 
requirements of this subpart and would not affect royalty income or 
production accountability.
    (2) The PMT will review the submitted data to ensure that the 
alternate oil measurement equipment meets the requirements of this 
subpart and will make a recommendation to the BLM to approve use of the 
equipment, disapprove use of the equipment or approve use of the 
equipment with conditions for its use. If the PMT recommends, and the 
BLM approves new equipment, the BLM will post the make, model, and 
range or software version on the BLM Web site www.blm.gov as being 
appropriate for use at an FMP for oil measurement.
    (c) The procedures for requesting and granting a variance under 
Sec.  3170.6 of this part may not be used as an avenue for approving 
new technology, methods, or equipment. Approval of alternative oil 
measurement equipment or methods may be obtained only under this 
section.


Sec.  3174.14  Determination of oil volumes by methods other than 
measurement.

    (a) Under 43 CFR 3162.7-2, when production cannot be measured due 
to spillage or leakage, the amount of production must be determined by 
using any method the AO approves or prescribes. This category of 
production includes, but is not limited to, oil that is classified as 
slop oil or waste oil.

[[Page 58979]]

    (b) No oil may be classified or disposed of as waste oil unless the 
operator can demonstrate to the satisfaction of the AO that it is not 
economically feasible to put the oil into marketable condition.
    (c) The operator may not sell or otherwise dispose of slop oil 
without prior written approval from the AO. Following the sale or 
disposal of slop oil, the operator must notify the AO in writing of the 
volume sold or disposed of and the method used to compute the volume.


Sec.  3174.15  Immediate assessments.

    Certain instances of noncompliance warrant the imposition of 
immediate assessments upon the BLM's discovery of the violation, as 
prescribed in the following table. Imposition of any of these 
assessments does not preclude other appropriate enforcement actions.

              Violations Subject to an Immediate Assessment
------------------------------------------------------------------------
                                                            Assessment
                        Violation                           amount per
                                                             violation
------------------------------------------------------------------------
1. Missing or nonfunctioning FMP LACT system components           $1,000
 as required by Sec.   3174.8(a) of this subpart........
2. Failure to notify the AO within 24 hours of any FMP             1,000
 LACT system failure or equipment malfunction resulting
 in use of an unapproved alternate method of measurement
 as required by Sec.   3174.7(e) of this subpart........
3. Missing or nonfunctioning FMP CMS components as                 1,000
 required by Sec.   3174.9(e) of this subpart...........
4. Failure to notify the AO within 7 days of any changes           1,000
 to any CMS internal calibration factors as required by
 Sec.   3174.10(d) of this subpart......................
5. Failure to meet the proving frequency requirements              1,000
 for an FMP as required by Sec.   3174.11(e) of this
 subpart................................................
6. Failure to obtain a written variance approval before            1,000
 using any oil measurement method other than manual tank
 gauging, LACT system, or CMS at a FMP as required by
 Sec.   3174.13 of this subpart.........................
------------------------------------------------------------------------

[FR Doc. 2015-24008 Filed 9-29-15; 8:45 am]
 BILLING CODE 4310-84-P