[Federal Register Volume 81, Number 222 (Thursday, November 17, 2016)]
[Rules and Regulations]
[Pages 81462-81513]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2016-25405]



[[Page 81461]]

Vol. 81

Thursday,

No. 222

November 17, 2016

Part VI





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; Final Rule

  Federal Register / Vol. 81 , No. 222 / Thursday, November 17, 2016 / 
Rules and Regulations  

[[Page 81462]]


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DEPARTMENT OF THE INTERIOR

Bureau of Land Management

43 CFR Parts 3160 and 3170

[17X.LLWO310000.L13100000.PP0000]
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: Final rule.

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SUMMARY: This final rule updates and replaces Onshore Oil and Gas Order 
Number 4, Measurement of Oil (Order 4) with new regulations codified in 
the Code of Federal Regulations (CFR). It 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.

DATES: The final rule is effective on January 17, 2017. The 
incorporation by reference (IBR) of certain publications listed in the 
rule is approved by the Director of the Federal Register as of January 
17, 2017.

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.

FOR FURTHER INFORMATION CONTACT: Mike McLaren, Petroleum Engineer, BLM 
Wyoming, Pinedale Field Office, 1625 West Pine St., P.O. Box 768, 
Pinedale, WY 82941, or by telephone at 307-367-5389, for information 
about the requirements of this final rule; or Steven Wells, Division 
Chief, Fluid Minerals Division, 202-912-7143, for information regarding 
the Bureau of Land Management's (BLM's) Fluid Minerals Program. For 
questions related 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 Relay Service at 800-877-8339 
to contact the above individuals during normal business hours. The 
Service is available 24 hours a day, 7 days a week to leave a message 
or question with the above individuals. You will receive a reply during 
normal business hours.

SUPPLEMENTARY INFORMATION:

I. Overview and Background
II. Overview of Final Rule, Section-by-Section Analysis, and 
Response to Comments on the Proposed Rule
III. Overview of Public Involvement and Consistency With GAO 
Recommendations
IV. Procedural Matters

I. Overview and Background

    The BLM developed this rule based on the proposed rule published in 
the Federal Register on September 30, 2015 (80 FR 58952), and the BLM's 
consideration of tribal and public comments received on the proposed 
rule. This final rule strengthens the BLM's 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. It also responds to recommendations the United States 
Government Accountability Office (GAO), the Department of the 
Interior's (Interior's or Department's) Office of the Inspector General 
(OIG), and the Secretary of the Interior's (Secretary's) Royalty Policy 
Committee (RPC), Subcommittee on Royalty Management (Subcommittee) made 
with respect to the BLM's production verification efforts. As explained 
in this preamble, the overall volume uncertainty and performance goals 
established by this rule are designed to ensure that the oil volume 
reported on an Oil and Gas Operations Report (OGOR) submitted to the 
Office of Natural Resources Revenue (ONRR) is sufficiently accurate to 
ensure that the royalties due are paid.
    Like the proposed rule, the final 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 final rule expands the acts 
of noncompliance that would result in an immediate assessment. Finally, 
it sets forth a process for the BLM to consider variances from these 
requirements.
    Key changes incorporated into the final rule include provisions 
that allow operators to use Coriolis measurement systems (CMSs) and 
automatic tank gauging (ATG) systems without having to obtain variances 
from the BLM.
    This final rule, as well as the final rules to update and replace 
Onshore Oil and Gas Orders Numbers 3 (Order 3) and 5 (Order 5) related 
to site security and the measurement of gas, respectively, enhance the 
BLM's overall production verification and accountability program.
    The 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. Governing laws include, but are not 
limited to, the Mineral Leasing Act (MLA), 30 U.S.C. 181 et seq.; the 
Mineral Leasing Act for Acquired Lands, 30 U.S.C. 351 et seq.; the 
Federal Oil and Gas Royalty Management Act (FOGRMA), 30 U.S.C. 1701 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; the Indian Mineral Development Act, 25 
U.S.C. 2101 et seq.; and the Federal Land Policy and Management Act 
(FLPMA), 43 U.S.C. 1701, et seq.\1\
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    \1\ Each of the statutes cited above expressly authorizes the 
Secretary of the Interior to promulgate necessary and appropriate 
rules and regulations governing those leases. See e.g., 30 U.S.C. 
189; 30 U.S.C. 359; 30 U.S.C. 1751; 25 U.S.C. 396d; 25 U.S.C. 396; 
25 U.S.C. 2107; and 43 U.S.C 1740. The Secretary has delegated this 
authority to the BLM. Specifically, under Secretarial Order Number 
3087, dated December 3, 1982, as amended on February 7, 1983 (48 FR 
8983), and the Departmental Manual (235 DM 1.1), the Secretary has 
delegated regulatory authority over onshore oil and gas development 
on Federal and Indian (except Osage Tribe) lands to the BLM. For 
Indian leases, the delegation of authority to the BLM is reflected 
in 25 CFR parts 211, 212, 213, 225, and 227. In addition, as 
authorized by 43 U.S.C. 1731(a), the Secretary has delegated to the 
BLM regulatory responsibility for oil and gas operations in Indian 
lands. 235 DM 1.1.K.
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    The BLM's onshore oil and gas program is one of the most 
significant mineral-leasing programs in the Federal Government. In the 
fiscal year (FY) 2015 sales year, onshore Federal oil and gas lease 
holders sold 180 million barrels of oil,\2\ 2.5 trillion cubic feet of 
natural gas,\3\ and 2.6 billion gallons of natural gas liquids, with a 
market value of more than $17.7 billion, and generating royalties of 
almost $2 billion. Nearly half of these revenues were distributed to 
the States in which the leases are located. Lease holders on tribal and 
Indian lands sold 59 million barrels of oil, 239 billion cubic feet of 
natural gas, and 182 million gallons of natural gas liquids, with a 
market value of over $3.6 billion, and generating royalties of over 
$0.6 billion that were all distributed to the applicable tribes and 
individual allotment owners. Under applicable laws, royalties are owed 
on all production removed or sold from Federal and Indian oil and gas 
leases.

[[Page 81463]]

The basis for those royalty payments is the measured production from 
those leases.
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    \2\ This figure includes 168 million barrels of regularly 
classified oil, plus additional sales of condensate, sweet and sour 
crude, black wax crude, other liquid hydrocarbons, inlet scrubber 
and drip or scrubber condensate, and oil losses, all of which are 
considered to be part of oil sales for accounting purposes.
    \3\ This figure includes all processed and unprocessed volumes 
recovered on-lease, nitrogen, fuel gas, coal bed methane, and any 
volumes of gas lost due to venting or flaring.
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    As explained in the preamble for the proposed rule, given the 
magnitude of oil production on Federal and Indian lands, and the BLM's 
statutory and management obligations, it is critically important that 
the BLM ensure that operators accurately measure, properly report, and 
account for that production. However, 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 
final rule addresses the outdated nature of existing requirements and 
helps achieve the BLM's objective of ensuring accurate measurement by 
updating and replacing Order 4's requirements with regulations codified 
in the CFR, at a new 43 CFR subpart 3174. These new regulations reflect 
changes in oil measurement practices and technology since Order 4 was 
first promulgated in 1989.\4\
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    \4\ Order 4, which was published in the Federal Register on 
February 24, 1989 (54 FR 8056), has been in effect since August 23, 
1989.
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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 
based on the conclusion of multiple reports and evaluations of the 
BLM's oil and gas program--one by the Subcommittee, issued in 2007; one 
by the OIG, issued in 2009; and two reports prepared by the GAO, issued 
in 2010 and 2015. Each of these is described further below.
    In 2007, the Secretary appointed an independent panel--the 
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.\5\ 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 observed that:
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    \5\ The Subcommittee was commissioned to report to the RPC, 
which was 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 policies and guidance (see page 31);
     Some BLM policy and guidance are 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 determine whether it includes sufficient guidance for 
ensuring that accurate royalties are paid on Federal oil production. As 
explained in the preamble to the proposed rule, the Interior Department 
formed a Fluid Minerals Team, comprising Departmental oil and gas 
experts. The team determined that Order 4 should be updated in light of 
changes in technology, the BLM, and industry practices.
    As noted, 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 (OIG Report)).
    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, the 
Department's 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 p. 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 OIG 
made similar recommendations based on the Subcommittee's report 
observing that the BLM should, ``(e)nsure that oil . . . regulations 
are current by updating and issuing onshore orders . . .'' (OIG Report, 
p. 11).
    The GAO's recommendations related to the adequacy of the BLM's oil 
measurement rules are also significant because they form 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 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).
    Up-to-date measurement requirements are critically important 
because they help 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 more detail below, the final rule makes a number of 
changes that modernize and strengthen the existing requirements in 
Order 4. In general, this final rule will give industry more choices 
and flexibility for measuring oil produced from Federal and Indian 
leases and will also make it easier for operators in the future to 
adopt new technologies and processes as the industry continues to 
advance.

[[Page 81464]]

    In addition to updating requirements with respect to existing 
technologies, the final rule also specifically recognizes advances in 
measurement technology by affirmatively allowing operators to use a CMS 
\6\ or an ATG/hybrid tank measurement system without first receiving a 
variance from the BLM, as is currently required.\7\ In response to GAO 
and RPC concerns that BLM field offices put out various policies and 
guidance, the final rule establishes nationwide requirements and 
standards for this measurement equipment, including a nationwide 
process for reviewing and approving new technology as it is developed. 
This change is significant because CMSs have proven to be reliable and 
accurate in field and laboratory testing and, when the time comes to 
replace their older systems, more and more operators are opting to use 
CMSs.
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    \6\ A CMS is a metering system that uses a Coriolis flow meter 
in conjunction with a tertiary device, pressure transducer, and 
temperature transducer in order to derive and report gross standard 
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 and allow for a determination of various variables, 
including volume.
    \7\ As explained in the proposed rule, since this equipment was 
not included in Order 4, the BLM did not have uniform national 
performance standards for these systems, which has led BLM state and 
field offices, while approving variances, to specify their own. The 
state-by-state approach results in inconsistencies among offices 
with respect to the requirements imposed on operators.
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    Similarly, operators in newer well fields have been using ATG 
systems for internal inventory purposes for over 10 years and only 
recently have they started using them to measure oil for sales and 
royalty-determination purposes. The BLM reviewed proprietary ATG test 
data that operators submitted to the BLM--both as public comment on the 
proposed rule and in support of variance requests to have ATG systems 
replace manual tank gauging. Based on that review, the BLM believes 
that ATG/hybrid systems can meet or exceed this rule's tank-gauging 
standards and as a result they should be expressly allowed. 
Affirmatively allowing ATG and hybrid systems will also increase worker 
safety because eliminating the need for workers to climb on top of 
tanks, open hatches, and manually measure or sample oil reduces their 
exposure to the fumes coming out of the tanks.\8\ The final rule's 
incorporation of ATG/hybrid systems as a permissible measurement method 
gives operators an additional tool to address growing safety 
concerns.\9\
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    \8\ The Durango Herald, New hazard with oilfield work, March 7, 
2016; http://www.durangoherald.com/article/20160307/NEWS01/160309666/New-hazard-with-oilfield-work.
    \9\ In recent months this safety issue has been highlighted by 
news reports of the deaths of oil workers who died after manually 
opening oil tank hatches and being exposed to toxic fumes.
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    In recognition that new measurement technologies and processes, 
like CMSs and ATG systems, will continue to be developed and evolve, 
the final rule puts in place a process and criteria that will allow for 
a new Production Measurement Team (PMT) to review, and for the BLM to 
approve for use nationwide, new measurement technologies that are 
demonstrated to be reliable and accurate.\10\ Under this new system, 
operators would have to prove to the BLM that new technologies meet or 
exceed this rule's new uncertainty performance standards, which for the 
first time give the BLM a set of objective criteria that can be applied 
to evaluate and approve any new meters, electronic components, 
computers, software, and procedures not specifically addressed in these 
regulations. Unlike the current variance system where operators must 
make such a showing each and every time they wish to deploy a new 
technology, under the PMT approach, once a technology has been approved 
by the BLM based on the PMT's review, that technology can be employed 
at additional facilities or by additional operators without a 
subsequent BLM approval, so long as those facilities and operators 
follow all conditions of approval (COAs) established by the PMT.
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    \10\ The PMT is distinct from 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 expects that the members of the BLM PMT would 
participate as part of the DOI GOMT.
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    Recognizing the newness of the PMT process, the final rule includes 
a 2-year phase-in for that system. Over the next 2 years, the BLM will 
develop and post on its Web site an uncertainty calculator that will 
help the BLM and industry determine if a particular measurement system 
or a new device meets the rule's uncertainty requirements. As an 
operator designs a new system, the operator can plug its components 
into the calculator and know before installing the system whether that 
system meets the requirements, and could be approved by the PMT. Once 
the BLM approves a new technology for use, it will post the make, 
model, size, or software version on its Web site as approved for use 
for all operators nationwide.
    With respect to the PMT, it should be noted that while the final 
rule provides that the PMT will review requests and make 
recommendations to the BLM for approval, it is the BLM's intent that 
such approvals will be issued by a BLM AO with authority over the oil 
and gas program nationally (e.g., the Director, a Deputy Director, or 
an Assistant Director), as opposed to that authority being delegated to 
a local level. This is consistent with recommendations from the RPC, 
GAO, and OIG that decisions on variances be granted at the national 
level to ensure they are consistent and have the appropriate 
perspective, as opposed to more local levels, which can result in 
inconsistencies among BLM field offices.
    In another important departure from Order 4, this final rule 
avoids, where possible, cookbook-style lists of requirements for 
operators to follow when determining oil quantity and quality. Instead, 
in many instances, the rule simply requires operators to follow the 
applicable industry standards, which were developed through a consensus 
process by professional industry groups, with input from Federal oil 
and gas experts. In each instance, the BLM carefully reviewed the 
applicable standards and determined they are technically sufficient to 
meet the BLM's production verification needs and are structured in such 
a way that they can be enforced by BLM personnel in the field. The 
incorporation of industry standards into the final rule gives operators 
more flexibility to comply with the requirements of these regulations. 
For example, Order 4 had one specific way for operators to measure oil 
temperature--by inserting a thermometer in the approximate vertical 
center of the fluid column, not less than 12 inches from the tank shell 
for 5 minutes. The final rule still allows operators to measure oil 
temperature using this method, but they can now also follow American 
Petroleum Institute (API) Chapter 7 standards, which provide for 
operators to use built-in tank thermometers or to take measurements 
from the flow lines that lead to the haulers' trucks.
    The rule also adopts a number of smaller changes which, taken 
together, will increase measurement accuracy, increase verifiability, 
and reduce waste. First, it would prohibit the use of automatic 
temperature/gravity compensators on lease automatic custody transfer 
(LACT) systems, which are required equipment under Order 4. These 
compensators automatically

[[Page 81465]]

adjust LACT totalizer readings to account for temperature effects and, 
in some cases, oil gravity effects on volume. However, because these 
automatic compensators do not maintain the raw data the BLM needs to 
verify that the compensators are functioning correctly or that the 
totalizer readings are correct, this rule requires operators to use 
temperature averaging devices instead, which record and average the 
temperatures of the fluids flowing through the LACT. This requirement 
ensures that the necessary audit trail is maintained. Such a system 
strikes the right balance because it gives operators the data they need 
to manually correct the volumes from the totalizer for the effects of 
temperature and oil gravity, while ensuring that the BLM has the raw 
data needed to verify the results and confirm system functionality.
    Finally, the rule requires all oil storage tanks, hatches, 
connections, and other access points to be installed and maintained in 
accordance with manufacturers' specifications. This requirement, in 
effect, requires operators to maintain the pressure-vacuum integrity 
that manufacturers designed and built into their equipment. This in 
turn will minimize hydrocarbon gas lost to the atmosphere.

II. Overview of Final Rule, Section-by-Section Analysis and Response to 
Comments on the Proposed Rule

A. General Overview of the Final Rule

    As discussed in the background section of this preamble, the BLM's 
rules concerning oil measurement found in Order 4 have not kept pace 
with industry standards and practices, statutory requirements, or 
applicable measurement technology and practices. The final rule 
enhances the BLM's overall production accountability efforts by 
addressing these concerns and ensuring that the oil produced from 
Federal and Indian (except Osage Tribe) leases is adequately accounted 
for, ultimately ensuring that all royalties due are paid.
    The following table provides an overview of the changes between the 
proposed rule and this final rule. A similar chart explaining the 
differences between the proposed rule and Order 4 appears in the 
proposed rule at 80 FR 58955-58956.

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         Proposed rule              Final rule      Substantive changes
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43 CFR 3174.1--Definitions and  43 CFR 3174.1--    The final rule
 Acronyms.                       Definitions and    removes definitions
                                 Acronyms.          for ``registered
                                                    volume,''
                                                    ``resistance thermal
                                                    device,'' and
                                                    ``turbulent flow.''
                                                    It changes the
                                                    definitions for
                                                    ``base pressure''
                                                    and ``Coriolis
                                                    meter.'' It adds new
                                                    definitions for
                                                    ``indicated volume''
                                                    and ``transducer.''
43 CFR 3174.2--General          43 CFR 3174.2--    The final rule gives
 Requirements.                   General            operators a phase-in
                                 Requirements.      period of 1 to 4
                                                    years after the
                                                    rule's effective
                                                    date to bring
                                                    existing facility
                                                    measurement point
                                                    (FMP) equipment into
                                                    compliance. This
                                                    timeframe is based
                                                    on the operators'
                                                    production volumes
                                                    and it coincides
                                                    with their schedule
                                                    for applying for
                                                    their FMP numbers. A
                                                    new paragraph (g) in
                                                    this section delays
                                                    for 2 years a
                                                    requirement that
                                                    operators begin
                                                    using approved
                                                    equipment listed on
                                                    the BLM website
                                                    (www.blm.gov).
43 CFR 3174.3--Specific         43 CFR 3174.3--    The final rule adopts
 Measurement Performance         Incorporation by   the latest versions
 Requirements.                   Reference.         of certain API
                                                    standards and
                                                    incorporates them by
                                                    reference into the
                                                    BLM's oil and gas
                                                    regulations. It
                                                    incorporates by
                                                    reference many API
                                                    standards that did
                                                    not appear in the
                                                    proposed rule and
                                                    removes two industry
                                                    standards developed
                                                    by the American
                                                    Society for Testing
                                                    and Materials
                                                    (ASTM).
43 CFR 3174.4--Incorporation    43 CFR 3174.4--    The final rule
 by Reference.                   Specific           establishes two
                                 Measurement        thresholds for
                                 Performance        overall oil
                                 Requirements.      measurement
                                                    uncertainty levels.
                                                    For FMPs measuring
                                                    greater than or
                                                    equal to 30,000
                                                    barrels (bbl)/month,
                                                    the maximum
                                                    uncertainty is 0.50 percent.
                                                    For FMPs measuring
                                                    less than 30,000 bbl/
                                                    month, the maximum
                                                    uncertainty level is
                                                    1.50
                                                    percent. Paragraph
                                                    (d) is revised to
                                                    clarify that the
                                                    PMT, following the
                                                    process outlined in
                                                    Sec.   3174.13, will
                                                    make a determination
                                                    whether proposed
                                                    alternative
                                                    equipment or
                                                    measurement
                                                    procedures meet or
                                                    exceed the
                                                    objectives and
                                                    intent of this
                                                    section.
43 CFR 3174.5 and 3174.6--Oil   43 CFR 3174.5 and  The final rule
 Measurement by Manual Tank      3174.6--Oil        requires operators
 Gauging.                        Measurement by     to submit sales tank
                                 Tank Gauging.      calibration charts
                                                    (tank tables) to the
                                                    authorized officer
                                                    (AO) within 45 days
                                                    after calibrating or
                                                    recalibrating. It
                                                    allows operators to
                                                    use ATG systems and,
                                                    by replacing
                                                    prescriptive
                                                    language with
                                                    additional industry
                                                    standards, it gives
                                                    operators more
                                                    options for tank
                                                    gauging, sampling,
                                                    calibrating sales
                                                    tanks, and
                                                    determining
                                                    temperature, oil
                                                    gravity, and
                                                    sediment and water
                                                    (S&W) content. The
                                                    final rule specifies
                                                    manual gauging
                                                    accuracy to the
                                                    nearest \1/4\ inch
                                                    for tanks of 1,000
                                                    bbl or less and
                                                    gauging accuracy to
                                                    the nearest \1/8\
                                                    inch for tanks
                                                    greater than 1,000
                                                    bbl. All oil storage
                                                    tanks must be
                                                    clearly identified
                                                    with an operator-
                                                    generated unique
                                                    number.

[[Page 81466]]

 
43 CFR 3174.7 and 3174.8--LACT  43 CFR 3174.7 and  The final rule
 Systems.                        3174.8--LACT       requires operators
                                 Systems.           to notify the AO of
                                                    any LACT system
                                                    failures or
                                                    equipment
                                                    malfunctions, or
                                                    other failures that
                                                    could adversely
                                                    affect oil
                                                    measurement within
                                                    72 hours upon
                                                    discovery. The
                                                    requirement in
                                                    proposed Sec.
                                                    3174.7(b) that
                                                    operators generate
                                                    an additional run
                                                    ticket before
                                                    proving a LACT
                                                    system has been
                                                    modified. A related
                                                    change in Sec.
                                                    3174.12(b)(1) makes
                                                    it clear that LACT
                                                    systems that use
                                                    flow computers are
                                                    exempt from the
                                                    requirement that
                                                    operators close a
                                                    run ticket before
                                                    proving a LACT
                                                    system. The table in
                                                    proposed Sec.
                                                    3174.7(c) entitled,
                                                    ``Standards to
                                                    Measure Oil by a
                                                    LACT System,'' has
                                                    been removed and in
                                                    its place the final
                                                    rule requires
                                                    operators to
                                                    complete measurement
                                                    tickets as required
                                                    under Sec.
                                                    3174.12(b). Industry
                                                    standards have been
                                                    added to replace
                                                    prescriptive
                                                    language in the
                                                    proposed rule. This
                                                    gives operators more
                                                    choices for
                                                    collecting, mixing,
                                                    and analyzing
                                                    samples. The final
                                                    rule clarifies that
                                                    LACT systems may
                                                    have either a
                                                    Coriolis meter or a
                                                    positive
                                                    displacement (PD)
                                                    meter.
43 CFR 3174.9--Coriolis         43 CFR 3174.9--    The final rule is
 Measurement System--General     Coriolis           revised to clarify
 Requirements and Components.    Measurement        that operators can
                                 System--General    use CMSs as a
                                 Requirements and   standalone unit,
                                 Components.        independent of a
                                                    LACT system. The
                                                    table in paragraph
                                                    (d) entitled,
                                                    ``Standards
                                                    Applicable to CMS
                                                    Use,'' has been
                                                    removed and in its
                                                    place the final rule
                                                    requires operators
                                                    to complete
                                                    measurement tickets,
                                                    as required under
                                                    Sec.   3174.12(b).
                                                    Prescriptive
                                                    language in proposed
                                                    paragraph (e) that
                                                    dictated which CMS
                                                    components should be
                                                    used during set up
                                                    and installation of
                                                    a CMS, for the most
                                                    part, has been
                                                    removed and replaced
                                                    with industry
                                                    standards, which
                                                    give operators more
                                                    flexibility. The
                                                    requirement for a
                                                    back pressure valve
                                                    has been removed and
                                                    operators may use
                                                    any means to apply
                                                    sufficient back
                                                    pressure to ensure
                                                    single-phase flow so
                                                    long as it meets
                                                    industry standard
                                                    API 5.6. Industry
                                                    standards have been
                                                    added to give
                                                    operators more
                                                    options for
                                                    automatic sampling
                                                    and for mixing and
                                                    handling samples. A
                                                    new paragraph (g)
                                                    has been added that
                                                    requires operators
                                                    to follow API 12.2.1
                                                    and API 12.2.2 for
                                                    calculating net
                                                    standard volume. A
                                                    similar, more
                                                    prescriptive
                                                    requirement for
                                                    calculating net
                                                    standard volume
                                                    appeared in proposed
                                                    Sec.   3174.10(g),
                                                    which has been
                                                    removed from the
                                                    final rule.
43 CFR 3174.10--Coriolis        43 CFR 3174.10--   Requirement for
 Measurement System--Operating   Coriolis meter     straight piping
 Requirements.                   for LACT and CMS   upstream and
                                 Measurement        downstream of a
                                 Applications.      meter has been
                                                    removed from the
                                                    final rule. The
                                                    requirement for
                                                    verifying the meter
                                                    zero value is
                                                    revised to be less
                                                    prescriptive and
                                                    instead requires
                                                    operators to follow
                                                    manufacturers'
                                                    specifications and
                                                    procedures. The
                                                    requirement that
                                                    operators keep the
                                                    log containing the
                                                    meter factor, zero
                                                    verification, and
                                                    zero adjustments on
                                                    site has been
                                                    changed to require
                                                    them to make it
                                                    available to the AO
                                                    upon request.
43 CFR 3174.11--Meter-Proving   43 CFR 3174.11--   The final rule
 Requirements.                   Meter-Proving      requires proving
                                 Requirements.      every 3 months
                                                    (quarterly) after
                                                    last proving, or
                                                    after every 75,000
                                                    bbl of volume flows
                                                    through the meter,
                                                    whichever comes
                                                    first, but no more
                                                    frequently than
                                                    monthly. The rule
                                                    includes
                                                    verification
                                                    requirements for
                                                    pressure,
                                                    temperature, and
                                                    density measurement
                                                    devices with each
                                                    proving. The table
                                                    in proposed
                                                    paragraph (b)
                                                    entitled, ``Minimum
                                                    Standards for
                                                    Proving FMP
                                                    Meters,'' has been
                                                    removed because it
                                                    is not needed. The
                                                    proposed requirement
                                                    for master meter
                                                    repeatability of
                                                    0.0002 (0.02
                                                    percent) has been
                                                    changed to 0.0005
                                                    (0.05 percent). The
                                                    frequency for
                                                    proving master
                                                    meters is no less
                                                    than once every 12
                                                    months. The final
                                                    rule replaces
                                                    prescriptive
                                                    language that
                                                    dictated the sizes
                                                    and proving
                                                    frequencies of
                                                    displacement provers
                                                    with requirements
                                                    that operators
                                                    follow industry
                                                    standards. Paragraph
                                                    (c)(4) adds the
                                                    requirement that
                                                    operators follow
                                                    industry standards
                                                    when calculating the
                                                    average meter
                                                    factor. Paragraph
                                                    (c)(6) contains new
                                                    language on how to
                                                    utilize multiple
                                                    meter factors. Meter-
                                                    proving reports may
                                                    be submitted to the
                                                    AO in either hard-
                                                    copy or electronic
                                                    format.
43 CFR 3174.12--Measurement     43 CFR 3174.12--   The final rule
 Tickets.                        Measurement        requires that oil
                                 Tickets.           measurement tickets
                                                    for LACT systems and
                                                    CMS be closed at the
                                                    end of each month
                                                    and before proving
                                                    unless utilizing
                                                    flow computers. The
                                                    rule allows the use
                                                    of electronic
                                                    measurement tickets.
                                                    The final rule no
                                                    longer requires the
                                                    operator's
                                                    representative to
                                                    certify that the
                                                    measurement on a
                                                    completed run ticket
                                                    is correct. The
                                                    final rule has also
                                                    removed the
                                                    requirement that
                                                    operators must
                                                    notify the AO within
                                                    7 days if they
                                                    disagree with a tank
                                                    gauger's
                                                    measurement.
43 CFR 3174.13--Oil             43 CFR 3174.13--   None.
 Measurement by Other Methods.   Oil Measurement
                                 by Other Methods.

[[Page 81467]]

 
43 CFR 3174.14--Determination   43 CFR 3174.14--   None.
 of Oil Volumes by Methods       Determination of
 Other Than Measurement.         Oil Volumes by
                                 Methods Other
                                 Than Measurement.
43 CFR 3174.15--Immediate       43 CFR 3174.15--   The final rule
 Assessments.                    Immediate          removes one of the
                                 Assessments.       six violations
                                                    listed in the
                                                    proposed rule:
                                                    Failure to notify
                                                    the AO within 7 days
                                                    of any changes to
                                                    any CMS internal
                                                    calibration factors
                                                    (proposed violation
                                                    #4). Of the five
                                                    remaining violations
                                                    listed, the final
                                                    rule changes the
                                                    timeframe from
                                                    ``within 24 hours''
                                                    to ``within 72
                                                    hours'' that
                                                    operators must
                                                    notify the AO of any
                                                    LACT system failure
                                                    or equipment
                                                    malfunction
                                                    resulting in use of
                                                    an unapproved
                                                    alternative method
                                                    of measurement
                                                    (violation #2 in the
                                                    final rule). The
                                                    final rule also
                                                    removes the word
                                                    ``variance'' from
                                                    the violation of
                                                    failure to obtain a
                                                    written approval
                                                    before using any oil
                                                    measurement method
                                                    other than tank
                                                    gauging, LACT
                                                    system, or CMS at an
                                                    FMP (violation #5 in
                                                    the final rule).
------------------------------------------------------------------------

B. Section-by-Section Analysis of the Final Rule and Response to 
Comments on Specific Provisions of the Proposed Rule

    This final rule is codified primarily in a new 43 CFR subpart 3174 
within a new part 3170. In addition to this rule, the BLM has also 
prepared separate rules to update and replace Onshore Oil and Gas Order 
Number 3 (Order 3) (site security), which will be codified at a new 43 
CFR subpart 3173; and Onshore Oil and Gas Order Number 5 (Order 5) (gas 
measurement), which will be codified at a new 43 CFR subpart 3175. The 
rules to replace Orders 3 and 5 are being published concurrently with 
this rule. In addition to establishing a new 43 CFR subpart 3173, the 
rule to replace Order 3 establishes 43 CFR part 3170 and subpart 3170. 
Subpart 3170 contains definitions of certain terms common to more than 
one of these rules, as well as other provisions common to all of the 
rules, such as provisions prohibiting bypass 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. All of the 
definitions and substantive provisions of subpart 3170 also apply to 
this new subpart 3174.
    Certain provisions of this final rule will result in amendments to 
related provisions in the onshore oil and gas operations rules in 43 
CFR part 3160. The amendments to those provisions are also discussed 
below.
Subpart 3174 and Related Provisions
Section 3174.1 Definitions and Acronyms
    Section 3174.1 defines terms and acronyms used in subpart 3174. 
Defining these terms and acronyms is necessary to ensure consistent 
interpretation and implementation of this rule. The BLM received a 
number of comments on this section. Except as noted in this section, 
the terms and acronyms in Sec.  3174.1 did not change between the draft 
and final rule. A summary of the definitions and acronyms that were not 
changed in the final rule may be found in the proposed rule.
    Several commenters recommended that base pressure should be defined 
as 14.696 pounds per square inch, absolute (psia), as opposed to 
defining it, as in the proposed rule, as the atmospheric pressure or 
the vapor pressure of the liquid at 60[emsp14][deg]F, whichever is 
higher. Subsequent research has shown that base pressure should be 
defined as a fixed amount and therefore the BLM agrees with these 
comments. As a result, the definition of base pressure has been changed 
to 14.696 psia in the final rule.
    Several commenters had concerns about the definition of Coriolis 
meter and Coriolis metering system (CMS). They suggested we replace the 
word ``measures'' in the definition of Coriolis meter with the word 
``infers.'' The BLM agrees with this comment because the Coriolis meter 
does not actually measure volume directly as a positive displacement 
(PD) meter does, by isolating the flowing liquid into segments of known 
volume, but instead analyzes the interaction between the flowing fluid 
and the oscillation of the tubes. As a result, the definition of 
Coriolis has been changed to say that a Coriolis meter infers a mass 
flow rate. Another commenter said the definition of CMS should be 
changed to say the CMS reports ``net standard oil volume'' instead of 
``net oil volume,'' while another commenter noted that the Coriolis 
meter displays ``gross,'' not ``net'' standard volumes. The BLM agrees 
with these suggestions because the Coriolis meter is capable of 
correcting to gross standard volume, but not capable of deducting the 
S&W content to derive net standard volumes. The definition has been 
changed in the final rule to ``gross standard volume'' as a result of 
this comment.
    Another commenter requested that we include a definition in the 
rule for ``vapor tight.'' The proposed rule at Sec.  3174.5(b)(3) 
required all oil storage tanks, hatches, connections, and other access 
points to be vapor tight. The BLM agrees that the term ``vapor tight'' 
should be defined and has defined the term to mean capable of holding 
pressure differential only slightly higher than that of installed 
pressure-relieving or vapor recovery devices.
    A few commenters suggested that all of the definitions in the rule 
should come from the API standards, rather than be the BLM's own 
customized definitions. After comparing the API definitions against the 
BLM's definitions in the rule, the BLM does not agree with this 
suggestion. Not all API definitions fit the terms used in the rule. For 
example, one commenter said the BLM should use the API definition for 
LACT systems, which defines turbine meters as an example of a meter 
that can be part of a LACT system. The BLM disagrees with this comment 
because the rule does not allow turbine meters to be used at a FMP. The 
BLM has used many API definitions in the rule, but not all of them are 
suitable for this rule, therefore, this rule was not changed as a 
result of these comments.
    Three commenters suggested that we include definitions for the 
acronyms ``AO,'' authorized officer; ``PA,'' participating area; and 
``CA,'' communitization agreement. The definitions for the acronyms AO, 
PA, and CA are included in the definitions section of 43 CFR subpart 
3170, which is in a related rulemaking previously discussed. As a 
result, no change was made to this rule as a result of these comments.
    One commenter suggested that we not use the term ``registered 
volume,'' but rather the term ``indicated volume.'' The

[[Page 81468]]

BLM agrees that the term ``indicated volume'' is a more appropriate 
term for the definition and aligns with common industry language, and 
as a result has changed the definition in the rule to reflect the 
definition for indicated volume.
    One commenter said the term ``resistance thermal device'' is not a 
common industry term and suggested we change it to ``resistance thermal 
detector.'' As a result of this comment and a review of comments and 
changes to other sections, the term and definition for ``resistance 
thermal device'' has been removed and replaced by the term 
``transducer.'' Transducer has been defined to be an electronic device 
that converts a physical property--such as pressure, temperature, or 
electrical resistance--into an electrical output signal that varies 
proportionally with the magnitude of the physical property. This 
defines a broader spectrum of devices and can include a resistance 
thermal detector. This use of the term ``transducer'' aligns with 
common industry practice and better suits the BLM's objective of 
ensuring that there is sufficient flexibility built into the rule.
    One commenter suggested that we change our definition of 
``turbulent flow'' to include a reference to the common measure for 
determining the flow, which is by Reynolds number. Since the final rule 
does not contain the turbulent-flow requirements that appeared in the 
proposed rule at Sec.  3174.8(b)(1), the BLM has removed this term from 
the definitions section.
    Based on changes to other sections resulting in new terms being 
introduced, a definition for ``dynamic meter factor'' has been included 
as meaning a kinetic meter factor derived by linear interpolation or 
polynomial fit, used for conditions where a series of meter factors 
have been determined over a range of normal operating conditions. In 
the revised non-prescriptive structure of the final rule, the term 
``opaque oil'' is no longer used, as such the definition has been 
removed.
Section 3174.2 General Requirements
    Paragraphs (a) through (d) of Sec.  3174.2 refer the reader to 
other sections in this rule and to 43 CFR subpart 3173, which is 
addressed in the rulemaking to replace Order 3. That rulemaking 
contains the requirements for oil storage tanks, on-lease oil 
measurement, commingling, and FMP numbers, respectively. All comments 
received on these paragraphs are addressed in the corresponding section 
discussions later in this preamble and in the preamble for 43 CFR 
subpart 3173.
    Section 3174.2(e) specifies that all equipment used to measure the 
volume of oil for royalty purposes at an FMP installed after the 
effective date of this subpart must comply with the requirements of 
this subpart. The BLM received no comments on this requirement.
    Section 3174.2(f) requires that measuring procedures and equipment 
used to measure oil for royalty purposes that are in use on the 
effective date of this rule, must comply with the requirements of this 
subpart on or before the date the operator is required to apply for an 
FMP number under 3173.12(e) of this part. Prior to that date, measuring 
procedures and equipment used to measure oil for royalty purposes, that 
is in use on the effective date of this rule, must continue to comply 
with the requirements of Onshore Oil and Gas Order No. 4, Measurement 
of oil, 54 FR 8086 (Feb 24, 1989), and any COAs and written orders 
applicable to that equipment.
    The proposed rule would have required operators to bring existing 
equipment used at FMPs into compliance within 180 days after the 
effective date of the final rule. Many commenters said 180 days is not 
enough time to plan for and bring existing equipment into compliance. 
The BLM agrees, and in response, this final rule provides a phase-in 
period of 1 to 4 years after the rule's effective date to bring 
existing equipment into compliance.
    The 1- to 4-year phase-in period is based on the time-frames 
established for operators to apply for their FMP numbers, which is 
provided for in 43 CFR 3173.12 and is addressed in a related rulemaking 
that is updating and replacing Order 3. This modified implementation 
timeframe in the final rule links compliance with the oil measurement 
requirement to an operator's production volumes, with lower-volume 
producers having more time to comply. Under this new approach, the 
highest 25 percent of the producing leases, CAs, or unit PAs are 
required to be in compliance the earliest--within 12 months of the 
effective date of this rule. All remaining leases, CAs, or unit PAs, 
based on volume thresholds, are staged out over the following 3 years.
    Commenters' greatest concern with the 180-day deadline was that it 
was not enough time to generate new oil-storage-tank calibration tables 
that would have allowed them to measure volumes in \1/8\-inch 
increments, as required in Sec.  3174.6 of the proposed rule.\11\ That 
is no longer a concern, however, because the final rule does not 
require that volumes be measured in \1/8\-inch increments.
---------------------------------------------------------------------------

    \11\ Order 4 requires \1/4\-inch gauging accuracy for tanks with 
a capacity of 1,000 bbl or less and requires strapping tables at \1/
4\-inch increments. For tanks with a capacity greater than 1,000 
bbl, Order 4 requires a \1/8\-inch gauging accuracy and strapping 
tables at \1/8\-inch increments.
---------------------------------------------------------------------------

    In the proposed rule, the BLM proposed switching to the \1/8\-inch 
gauging accuracy for all tanks in order to meet one objective of the 
rule--to bring the oil measurement regulations up to current industry 
standards. However, API has two contradictory standards for manual 
gauging measurement accuracy on oil storage tanks--API 3.1A calls for 
\1/8\-inch gauging accuracy for all tanks, while API 18.1 calls for a 
\1/4\-inch gauging accuracy for tanks of 1,000 bbl or less. Based on 
this change in industry standards and its own experience, the BLM 
assumed that new calibration tables could be generated from existing 
tank strapping measurements. Commenters disagreed, saying operators 
would have to hire engineering companies to reanalyze some 40,000 sales 
tanks across the nation. They said numerous tanks would have to be 
physically re-measured, or re-strapped. Some commenters said that, due 
to budgeting, equipment, and weather constraints, it could take them a 
year to re-strap their tanks. Others said it could take months to do 
the job.
    As discussed later in Sec.  3174.6, the BLM has decided to retain 
the \1/4\-inch gauging accuracy requirement for oil tanks with a 
capacity of 1,000 bbl or less, which is the current requirement, 
eliminating the need for operators to re-strap their tanks. To 
implement these standards, the BLM plans to develop a liquids 
uncertainty calculator that will allow its inspectors to enforce oil 
tank measurement uncertainty requirements for operators who elect to 
use automatic and hybrid tank gauging systems. It will take the BLM 
about 2 years to develop the uncertainty calculator and verify that 
automated equipment meets the uncertainty standards. During this time, 
operators who use automatic and hybrid tank gauging systems will still 
have to meet the measurement performance requirements.
    Some commenters argued that existing equipment used at FMPs should 
not have to meet any deadline for coming into compliance with this 
rule's requirement and should instead be exempted from complying 
entirely (that is, grandfathered).
    For example, one commenter said the BLM should grandfather all 
existing

[[Page 81469]]

equipment, but require all new installations or installations that 
undergo repairs costing more than 50 percent of the cost of new 
equipment to meet the new standards. The BLM does not agree with this 
proposed change for several reasons. The rule's only equipment retrofit 
requirement is that all automatic temperature/gravity compensators be 
replaced with temperature averagers. Temperature averagers are 
relatively inexpensive, costing around $6,500 per device, and automatic 
temperature/gravity compensators are not used on very many LACT 
systems. The BLM estimates that over 80 percent of all LACTs on Federal 
and Indian leases already have temperature averagers installed. A 
second issue the BLM has with this proposed change is that it would 
require the BLM to monitor all maintenance activity and estimate costs 
of repairs on ``grandfathered'' equipment. Finally, the commenter did 
not explain or provide justification for how this proposed change would 
be preferable to the proposed rule.
    Another commenter said, as an alternative to grandfathering, 
equipment serving low-volume and marginal FMPs should be exempted from 
the requirements. The BLM does not see a need for this exemption 
because low-volume or marginal wells will, in most cases, be measured 
by manual tank gauging. Since the tank-gauging requirements in this 
final rule have not changed relative to the requirements in Order 4, 
this change was unnecessary.
    Another commenter disagreed with the proposed rule's prohibition of 
automatic temperature/gravity compensators. These compensators should 
be grandfathered, the commenter said, as long as an audit trail exists 
whereby the raw data is available and the final results from the 
compensators can be recreated from this data. The commenter further 
stated that systems that cannot provide such data should be 
grandfathered in the final rule. The BLM disagrees. The fact remains 
that automatic compensator systems alter the raw data before any audit 
trail is created. They automatically change a meter's totalizer 
readings, erasing the raw data that the BLM and the operator need to 
verify that the compensators are functioning correctly and that the 
totalizer reading is correct.
    Another commenter said that if existing equipment is not 
grandfathered, operators may need to install new LACT units in order to 
comply, which in turn would require operators to re-pipe their wells. 
According to this commenter, this would result in undue surface 
disturbance, excessive expenses, strain on the labor force, and wells 
that are currently in secondary recovery or that do not produce large 
amounts of oil being plugged prematurely, leaving behind undeveloped 
and valuable resources. The BLM disagrees with this interpretation of 
the rule's requirements. The only equipment that would have to be 
replaced at an FMP under both the proposed and final rules is the 
automatic temperature/gravity compensator, which is only one component 
of a PD meter of a LACT unit. Operators must replace these devices with 
temperature averagers, which allow operators to collect and retain the 
raw data the BLM needs to verify results and confirm and preserve 
system functionality. Based on the BLM's experience, this replacement 
can occur without replacing the entire LACT system. Additionally, as 
explained elsewhere in this preamble, most existing LACT systems do not 
use automatic temperature/gravity compensators.
    One commenter said the midstream sector (the pipeline companies and 
processing plants at or downstream of the meters) would suffer if the 
rule does not grandfather existing equipment. The commenter did not 
explain or specify any negative impacts on the midstream sector from 
the requirement that operators replace automatic temperature/gravity 
compensators on LACTs. The BLM is not aware of any negative impacts 
this would have on the midstream sector and the commenter did not 
provide any information on how the midstream sector will suffer from 
accurate, verifiable measurement on a lease, PA, or CA. As a result, 
the BLM does not agree with the commenter and no change has been made 
to the rule based on this comment.
    Several commenters said properly operating equipment should be 
grandfathered, and, if it must be replaced, operators should be allowed 
to negotiate installation timeframes with local BLM field offices. The 
BLM believes that this recommendation would perpetuate the problem of 
program requirements being inconsistently applied from state to state 
or field office to field office and therefore did not change the rule 
as a result of these comments. One of the primary goals of this final 
rule is to provide some nationwide consistency as to the application of 
these requirements.
    Another commenter said that existing facilities and equipment 
should be grandfathered because operators could not afford an 
``investment of this magnitude'' to retrofit equipment to meet the new 
standards. The commenter did not provide any details regarding what is 
meant by an ``investment of this magnitude.'' The BLM disagrees with 
the implication that replacing automatic temperature/gravity 
compensators on a LACT is a significant investment. The cost to replace 
automatic temperature/gravity compensators on LACT systems with 
temperature averagers is relatively minor--approximately $6,500 per 
system. No change resulted from this comment.
    The BLM does not believe that existing equipment should be 
grandfathered. For years, the GAO and industry have voiced concerns 
that the BLM's measurement regulations are outdated and make it harder 
for the BLM to have reasonable assurance that production is being 
accurately measured and verified. This rule aims to address these 
concerns at both new and existing facilities.
    Section 3174.2(g) exempts meters that are used for allocation 
measurement as part of commingling approvals from complying with the 
requirements of this subpart. Commingling approvals will be governed 
under new requirements in 43 CFR 3173.14, which are addressed in the 
rulemaking that is updating and replacing Order 3. One commenter said 
that meters used for allocating production from wells in approved 
commingling arrangements or that are in the same unit, PA, or CA should 
be required to meet API standards for allocation measurement. The 
commenter did not state a reason for this suggestion. Since the BLM 
does not want to impose blanket allocation measurement requirements 
that may not be relevant to every situation, it did not adopt this 
suggestion. Instead, the final rule retains the AO's discretion to 
include those requirements as a condition of approval on a case-by-case 
basis.
Section 3174.3 Incorporation by Reference (IBR)
    This section previously appeared as Sec.  3174.4 in the proposed 
rule, but based on edits made to the final rule, this section and 
proposed Sec.  3174.3 have been switched. All comments discussed below 
were submitted for the previously proposed Sec.  3174.4.
    This rule incorporates a number of industry standards and 
recommended practices, either in whole or in part, without republishing 
the standards in their entirety in the CFR, a practice known as IBR. 
These standards have been developed through a consensus process, 
facilitated by the API, with input from the oil and gas industry and 
Federal agencies with oil and gas operational oversight 
responsibilities. The BLM has reviewed these standards

[[Page 81470]]

and determined that they will achieve the intent of 43 CFR 3174.4 
through 3174.13 of this rule. The legal effect of IBR is that the 
incorporated standards become regulatory requirements. With the 
approval of the Director of the Federal Register, this rule 
incorporates the current versions of the standards listed.
    Some of the standards referenced in this section have been 
incorporated in their entirety. For other standards, the BLM 
incorporates only those sections that are relevant to the rule, meet 
the intent of Sec.  3174.3 of the rule, and do not need further 
clarification.
    The incorporation of industry standards follows the requirements 
found in 1 CFR part 51. The industry standards in this final rule are 
eligible for incorporation 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 incorporated 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 Sec.  3174.3 meets the requirements of 1 CFR 51.9. 
Where appropriate, the BLM has incorporated by reference an industry 
standard governing a particular process and then imposed requirements 
that add to 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 materials that the BLM is incorporating 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 and purchase 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 http://publications.api.org.
    The following describes the API standards that the BLM has 
incorporated by reference into this rule:
    API Manual of Petroleum Measurement Standards (MPMS) Chapter 2--
Tank Calibration, Section 2A, Measurement and Calibration of Upright 
Cylindrical Tanks by the Manual Tank Strapping Method; First Edition, 
February 1995; Reaffirmed February 2012 (``API 2.2A''). This standard 
describes the procedures for calibrating upright cylindrical tanks used 
for storing oil.
    API MPMS Chapter 2--Tank Calibration, Section 2.2B, Calibration of 
Upright Cylindrical Tanks Using the Optical Reference Line Method; 
First Edition, March 1989; Reaffirmed January 2013 (``API 2.2B''). This 
standard describes measurement and calibration procedures for 
determining the diameters of upright welded cylindrical tanks, or 
vertical cylindrical tanks with a smooth surface and either floating or 
fixed roofs.
    API MPMS Chapter 2--Tank Calibration, Section 2C, Calibration of 
Upright Cylindrical Tanks Using the Optical-triangulation Method; First 
Edition, January 2002; Reaffirmed May 2008 (``API 2.2C''). This 
standard describes a calibration procedure for applications to tanks 
above 26 feet in diameter with cylindrical courses that are 
substantially vertical.
    API MPMS Chapter 3, Section 1A, Standard Practice for the Manual 
Gauging of Petroleum and Petroleum Products; Third Edition, 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 3--Tank Gauging, Section 1B, Standard Practice for 
Level Measurement of Liquid Hydrocarbons in Stationary Tanks by 
Automatic Tank Gauging; Second Edition, June 2001; Reaffirmed August 
2011 (``API 3.1B''). This standard describes the level measurement of 
liquid hydrocarbons in stationary, above ground, atmospheric storage 
tanks using automatic tank gauges (ATG). This standard discusses 
automatic tank gauging in general, accuracy, installation, 
commissioning, calibration, and verification of ATG that measure either 
innage or ullage.
    API MPMS Chapter 3--Tank Gauging, Section 6, Measurement of Liquid 
Hydrocarbons by Hybrid Tank Measurement Systems; First Edition, 
February 2001; Errata September 2005; Reaffirmed October 2011 (``API 
3.6''). This standard describes the selection, installation, 
commissioning, calibration, and verification of Hybrid Tank Measurement 
Systems. This standard also provides a method of uncertainty analysis 
to enable users to select the correct components and configurations to 
address for the intended application.
    API MPMS Chapter 4--Proving Systems, Section 1, Introduction; Third 
Edition, February 2005; Reaffirmed June 2014 (``API 4.1''). Section 1 
is a general introduction to the subject of proving meters.
    API MPMS Chapter 4--Proving Systems, Section 2, Displacement 
Provers; Third Edition, September 2003; Reaffirmed March 2011 (``API 
4.2''). 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; Fourth 
Edition, June 2016 (``API 4.5''). This standard covers the use of 
displacement and Coriolis meters as master meters. The requirements in 
this standard are for single-phase liquid hydrocarbons.
    API MPMS Chapter 4--Proving Systems, Section 6, Pulse 
Interpolation; Second Edition, May 1999; Errata April 2007; Reaffirmed 
October 2013 (``API 4.6''). This standard describes how the double-
chronometry method of pulse interpolation, including system operating 
requirements and equipment testing, is applied to meter proving.
    API MPMS Chapter 4, Section 8, Operation of Proving Systems; Second 
Edition September 2013 (``API 4.8''). This standard provides 
information for operating meter provers on single-phase liquid 
hydrocarbons.
    API MPMS Chapter 4--Proving Systems, Section 9, Methods of 
Calibration for Displacement and Volumetric Tank Provers, Part 2, 
Determination of the Volume of Displacement and Tank Provers by the 
Waterdraw Method of Calibration; First Edition, December 2005; 
Reaffirmed July 2015 (``API 4.9.2''). This standard 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--Metering, Section 6, Measurement of Liquid 
Hydrocarbons by Coriolis Meters; First Edition, October 2002; 
Reaffirmed November 2013 (``API 5.6''). This standard is applicable to 
custody-

[[Page 81471]]

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--Metering Assemblies, Section 1, Lease Automatic 
Custody Transfer (LACT) Systems; Second Edition, May 1991; Reaffirmed 
May 2012 (``API 6.1''). This standard describes the design, 
installation, calibration, and operation of a LACT system.
    API MPMS Chapter 7, Temperature Determination; First Edition, June 
2001; Reaffirmed February 2012 (``API 7''). 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 7.3, Temperature Determination--Fixed Automatic 
Tank Temperature Systems, Second Edition, October 2011 (``API 7.3''). 
This standard describes the methods, equipment, and procedures for 
determining the temperature of petroleum and petroleum products under 
static conditions using automatic methods.
    API MPMS Chapter 8, Section 1, Standard Practice for Manual 
Sampling of Petroleum and Petroleum Products; Fourth Edition, October 
2013 (``API 8.1''). This standard covers procedures and equipment for 
manually obtaining samples of liquid petroleum and petroleum products 
from the sample point into the primary containers.
    API MPMS Chapter 8, Section 2, Standard Practice for Automatic 
Sampling of Petroleum and Petroleum Products; Third Edition, October 
2015 (``API 8.2''). This standard describes general procedures and 
equipment for automatically obtaining samples of liquid petroleum, 
petroleum products, and crude oils from a sample point into a primary 
container.
    API MPMS Chapter 8--Sampling, Section 3, Standard Practice for 
Mixing and Handling of Liquid Samples of Petroleum and Petroleum 
Products; First Edition, October 1995; Errata March 1996; Reaffirmed, 
March 2010 (``API 8.3''). This standard covers the handling, mixing, 
and conditioning procedures required to ensure that a particular 
representative sample of the liquid petroleum or petroleum product is 
delivered from the primary sample container/receiver into the 
analytical test apparatus or into intermediate containers.
    API MPMS Chapter 9, Section 1, Standard Test Method for Density, 
Relative Density, or API Gravity of Crude Petroleum and Liquid 
Petroleum Products by Hydrometer Method; Third Edition, December 2012 
(``API 9.1''). This standard covers the determination, using a glass 
hydrometer 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 pressure of 101.325 kPa 
(14.696 psi) or less.
    API MPMS Chapter 9, Section 2, Standard Test Method for Density or 
Relative Density of Light Hydrocarbons by Pressure Hydrometer; Third 
Edition, December 2012 (``API 9.2''), This standard covers the 
determination of the density or relative density of light hydrocarbons 
including liquefied petroleum gases having a Reid vapor pressure 
exceeding 101.325 kPa (14.696 psi).
    API MPMS Chapter 9, Section 3, Standard Test Method for Density, 
Relative Density, and API Gravity of Crude Petroleum and Liquid 
Petroleum Products by Thermohydrometer Method; Third Edition, December 
2012 (``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 pressure 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); 
Fourth Edition, October 2013; Errata March 2015 (``API 10.4''). This 
standard describes the field centrifuge method for determining both 
water and sediment, or sediment only, in crude oil.
    API MPMS Chapter 11--Physical Properties Data, Section 1, 
Temperature and Pressure Volume Correction Factors for Generalized 
Crude Oils, Refined Products and Lubricating Oils; May 2004; Addendum 
1, September 2007; 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 that fall within the categories of crude oil.
    API MPMS Chapter 12--Calculation of Petroleum Quantities, Section 
2, Calculation of Petroleum Quantities Using Dynamic Measurement 
Methods and Volumetric Correction Factors, Part 1, Introduction; Second 
Edition, 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 
sequences, and discrimination levels to be employed in the 
calculations.
    API MPMS Chapter 12--Calculation of Petroleum Quantities, Section 
2, Calculation of Petroleum Quantities Using Dynamic Measurement 
Methods and Volumetric Correction Factors, Part 2, Measurement Tickets; 
Third Edition, June 2003; Reaffirmed September 2010 (``API 12.2.2''). 
This standard provides standardized calculation methods for the 
quantification of liquids and specifies the equations for computing 
correction factors, rules for rounding, calculation sequences, and 
discrimination levels to be employed in the calculations.
    API MPMS Chapter 12--Calculation of Petroleum Quantities, Section 
2, Calculation of Petroleum Quantities Using Dynamic Measurement 
Methods and Volumetric Correction Factors, Part 3, Proving Report; 
First Edition, October 1998; Reaffirmed 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--Calculation of Petroleum Quantities, Section 
2, Calculation of Petroleum Quantities Using Dynamic Measurement 
Methods and Volumetric Correction Factors, Part 4, Calculation of Base 
Prover Volumes by the Waterdraw Method; First Edition, December, 1997; 
Reaffirmed March 2009; Errata July 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 allow different 
individuals, using various computer languages on different computer 
hardware (or manual calculations), to arrive at identical results using 
the same standardized

[[Page 81472]]

input data. This standard specifies the equations for computing 
correction factors, rules for rounding, the sequence of the 
calculations, and the discrimination levels of all numbers to be used 
in these calculations.
    API MPMS Chapter 13--Statistical Aspects of Measuring and Sampling, 
Section 1, Statistical Concepts and Procedures in Measurements; First 
Edition, June 1985; Reaffirmed February 2011, Errata July 2013 (``API 
13.1''). This standard covers the basic concepts involved in estimating 
errors by statistical techniques and ensuring that results are quoted 
in the most meaningful way. This standard also discusses the 
statistical procedures that should be followed in estimating a true 
quantity from one or more measurements and in deriving the range of 
uncertainty of the results.
    API MPMS Chapter 13, Section 3, Measurement Uncertainty; First 
Edition, May 2016 (``API 13.3''). This standard establishes a 
methodology for developing an uncertainty analysis.
    API MPMS Chapter 14, Section 3/American Gas Association Report No. 
3, Orifice Metering of Natural Gas and Other Related Hydrocarbon 
Fluids--Concentric, Square-edged Orifice Meters, Part 1, Section 12, 
General Equations and Uncertainty Guidelines; Fourth Edition, September 
2012; Errata July 2013 (``API 14.3''). This standard provides reference 
for engineering equations and uncertainty estimations.
    API MPMS Chapter 18--Custody Transfer, Section 1, Measurement 
Procedures for Crude Oil Gathered From Small Tanks by Truck; Second 
Edition, 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 18, Section 2, Custody Transfer of Crude Oil from 
Lease tanks Using Alternative Measurement Methods, First Edition, July 
2016 (``API 18.2''). This standard defines the minimum equipment and 
methods used to determine the quantity and quality of oil being loaded 
from a lease tank to a truck trailer without requiring direct access to 
a lease tank gauge hatch.
    API MPMS Chapter 21--Flow Measurement Using Electronic Metering 
Systems, Section 2, Electronic Liquid Volume Measurement Using Positive 
Displacement and Turbine Meters; First Edition, June 1998; Reaffirmed 
August 2011 (``API 21.2''). This standard provides for the effective 
utilization of electronic liquid measurement systems for custody-
transfer measurement of liquid hydrocarbons.
    API Recommended Practice (RP) 12R1, Setting, Maintenance, 
Inspection, Operation and Repair of Tanks in Production Service; Fifth 
Edition, August 1997; Reaffirmed April 2008 (``API RP 12R1''). 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 final rule.
    API RP 2556, Correction Gauge Tables for Incrustation; Second 
Edition, August 1993; Reaffirmed November 2013 (``API RP 2556''). This 
recommended practice provides for correcting gauge tables for 
incrustation applied to tank capacity tables. The tables given in this 
recommended practice show the percent of error of measurement caused by 
varying thicknesses of uniform incrustation in tanks of various sizes.
    The BLM received numerous comments addressing the incorporation by 
reference documents. Several commenters were concerned that the BLM was 
not incorporating the most recent versions of API standards. The API 
standards are dynamic standards that are constantly being reviewed and 
updated. The commenters referred to standards that were updated and 
published either after the proposed rule published or during the BLM's 
final internal review process before publishing the proposed rule. The 
BLM generally agrees with the commenters that the latest editions of 
industry standards should be incorporated and has made the change here 
after reviewing the latest version of the standards to confirm they 
will satisfy the applicable requirements.
    Several commenters said that some of the incorporated materials in 
the proposed rule were in conflict. For example, ASTM D1250-1980 
version tables 5A and 6A for temperature and gravity correction factors 
and API 11.1 for the correction of temperature effects on density and 
volume provide differing correction factors that may result in 
different corrected oil volumes. The BLM agrees with these comments and 
has removed ASTM D1250-1980 tables 5A and 6A from the list of 
incorporated materials. The final rule now refers to API 11.1 for 
calculations of temperature and pressure effects on density and volume.
    Several commenters expressed concern that the BLM will not be 
updating the incorporated industry standards as new versions are 
published. The BLM is aware of the need to continuously monitor the 
industry standards as they are revised and updated, and intends to 
draft guidance to ensure that the BLM's rules and the incorporated 
standards they reference are kept up-to-date as technology and 
practices change. Under the applicable IBR rules, however, the BLM 
cannot automatically incorporate updated versions of standards into BLM 
regulations. The rules require that BLM reference the specific version 
of any particular standard being incorporated. Recognizing that these 
standards are continually being updated, the BLM intends to undertake 
periodic rulemakings to make corresponding updates to the relevant 
regulations. In the interim, an operator could submit a request to the 
PMT for a variance to comply with a newer version of a standard in lieu 
of compliance with the version listed above.
    Many commenters said the BLM should rewrite the rule to be less 
prescriptive, to primarily reference industry standards, and to include 
additional API standards that would expand industry options for 
achieving accurate measurement. They argued that a highly prescriptive 
rule would discourage industry from adopting new technology as it 
becomes available. Upon careful consideration of these comments, the 
BLM has decided to take a less prescriptive approach that will achieve 
the ultimate goal of accurate measurement, while still maintaining our 
requirements for an audit trail and production accountability, and that 
will provide reasonable versatility for operators. The rule has been 
modified to be less prescriptive than the proposed rule and includes 
more industry standards that operators may choose from to comply with 
the requirements of the final rule. For example, the tank gauging 
section at Sec.  3174.6 has been rewritten to refer more to industry 
standards and less to step-by-step instructions and requirements. 
Proposed Sec.  3174.6(b)(3) had a list of requirements for taking oil 
samples prior to the opening gauge and was geared towards manual tank 
gauging. Section 3174.6(b)(3) of the final rule instead requires 
operators to follow one of two industry standards for taking oil 
samples prior to the opening gauge--API 8.1 for manual sampling or API 
8.2 for sampling by automatic sampling systems. This paves the way for 
operators to use hybrid tank measurement systems and any other new 
technology that may come along in the coming years. Where necessary, 
the rule enhances or modifies an industry standard to ensure that the 
BLM's audit trail and production accountability

[[Page 81473]]

requirements relate to lease activity and are met. For example, the 
rule modifies the industry standard for the tolerance on the 
verification for ATG systems, from \3/16\ inch to \1/4\ inch, in response to field test data that showed properly 
calibrated equipment has difficulty meeting the \3/16\ inch 
tolerance specified in industry standards. Also industry standards call 
for monthly ATG systems verification. This rule instead requires that 
ATG systems be verified monthly or before sales, whichever is later. 
This change will help smaller producers that may have sales only once 
every 2 or 3 months.
    Several commenters had the opposite view and said the BLM should 
not incorporate industry standards, but rather make its regulations 
predominantly prescriptive, explicitly stating what is allowed and 
required. Their reasoning for this approach was that API RPs are 
optional for industry to consider following, while industry must follow 
BLM regulations. The BLM disagrees with the commenter's description of 
how these rules will be applied. Under the final rule, operators are 
required to comply with industry standards or practices that are 
incorporated by reference. As discussed earlier, the BLM has decided to 
take a less prescriptive approach and, where possible, incorporate 
multiple industry standards to give operators a choice for achieving a 
particular measurement standard.
    Several commenters said the BLM should incorporate forthcoming 
industry standards that have not yet been finalized into the rule. The 
BLM cannot incorporate a standard that an industry trade association 
has not yet published. An unpublished standard is subject to change. It 
is possible the trade association creating the standard could 
completely rewrite the draft standard after the BLM incorporated it 
into this rule, in ways that would compromise the BLM's ability to 
enforce audit-trail or production-accountability requirements. The BLM 
disagrees with these comments and has not incorporated any unpublished 
standards into the rule.
    One commenter suggested the BLM not incorporate industry standards 
but rather copy industry standard language directly into the rule. 
Copyright restrictions prevent the BLM from taking this course of 
action. Also this approach makes it harder for the BLM to update these 
requirements in the future. The final rule was not revised as a result 
of this comment.
    Another commenter said the BLM is statutorily prohibited from 
cherry-picking industry standards for inclusion in the rule--picking 
and choosing which standards to apply and which to ignore. The BLM 
disagrees with this comment. Some industry standards do not meet the 
rule's goals and objectives and have not been incorporated. For 
example, there are industry standards for turbine meters, but the BLM 
does not allow these meters to be used at an FMP because, in some 
situations, they do not meet the BLM's accuracy requirements.
    Several commenters said that incorporating industry standards puts 
an unreasonable financial burden on industry because it forces industry 
to purchase the published standards from the trade groups that create 
them. The BLM agrees that the cost of purchasing a complete set of 
industry standards is not insignificant. However, the API provides the 
public free, read-only access to most of the standards incorporated in 
this final rule. In addition, all incorporated material is available 
for inspection at the BLM's Division of Fluid Minerals, 20 M Street 
SE., Washington, DC 20003, 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). Several commenters 
stated that the BLM has not made a good effort to provide these newly 
required standards for public review. The BLM disagrees with this 
comment. As stated earlier, all industry standards incorporated by 
reference are available for inspection at the BLM, Division of Fluid 
Minerals, and at all BLM offices with jurisdiction over oil and gas 
activities.
    The commenter also said the documents are not available in the 
BLM's Washington Office or in any particular field office. The BLM 
disagrees. The documents are available for review in the BLM's 
Washington Office and in all local offices that have jurisdiction over 
oil and gas activities. It has come to the BLM's attention that some 
local office personnel may not be aware of how to access the 
incorporated standards and, as part of the implementation process for 
the final rule, the BLM plans to carry out a training program to ensure 
that field office staff can readily access the standards as needed.
    Several commenters expressed concern about who is responsible for 
complying with the incorporated standards--operators or their 
contractors. The incorporated standards are regulatory requirements, 
and operators are responsible for ensuring that third parties that do 
not have a contractual relationship with the BLM comply with the 
incorporated industry standards. Existing BLM regulations at 43 CFR 
3162.3 state that a contractor on a leasehold will be considered the 
agent of the operator for such operations with full responsibility for 
acting on behalf of the operator for purposes of complying with 
applicable laws, regulations, the lease terms, NTLs, Onshore Oil and 
Gas Orders, and other orders and instructions of the AO.
    Several commenters said the industry standards as written are not 
enforceable by the BLM. The BLM disagrees. Many of the industry 
standards employ the terms ``shall'' and ``should,'' with ``shall'' 
denoting a minimum requirement necessary to conform to the 
specification, and ``should'' denoting a recommendation or that which 
is advised, though is not required, in order to conform to the 
specification. However, once the standards are incorporated into BLM 
regulations, operators must comply with them whether the standard uses 
the word ``shall'' or ``should.'' One commenter inquired whether 
operators will be required to follow a standard, and if any deviation 
from a standard is a violation. As stated previously, operators must 
comply with all incorporated standards and material, and any deviation 
without an approved variance is a violation.
Section 3174.4 Specific Measurement Performance Requirements
    This section was previously published as Sec.  3174.3. Based on 
edits made to the final rule, this section and previously published 
Sec.  3174.4 have been switched. All discussion of comments here were 
submitted under the previous proposed Sec.  3174.3.
    Section 3174.4(a)(1) sets volume-based overall performance 
standards for measuring oil produced from Federal and Indian leases, 
regardless of the type of meters or measurement method used. The 
overall volume uncertainty performance goals apply to volumes reported 
on the OGOR Part B (Production Disposition), commonly referred to as an 
OGOR B. FMPs measuring greater than or equal to 30,000 bbl per month 
must achieve an overall measurement uncertainty within 0.50 
percent. FMPs measuring less than 30,000 bbl per month must achieve an 
overall measurement uncertainty within 1.50 percent. 
Existing Order 4 has no explicit statement of performance standards. 
The BLM will apply the performance standards in this final rule to FMPs 
as part of the compliance process. 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

[[Page 81474]]

range of error between the meter in the field and the meter prover 
between successive runs during a proving). To facilitate this process, 
the BLM is developing an oil uncertainty calculator similar to the 
BLM's gas uncertainty calculator currently in use. The uncertainty 
calculator will be an internal tool for BLM employees to use to verify 
uncertainty. Once it is developed, the uncertainty calculator will be 
available for the public to review and use. The methods for calculating 
uncertainty have been clarified in the final rule to be in accordance 
with statistical concepts described in API 13.1, the methodologies in 
API 13.3, the quadrature sum (square root of the sum of the squares) 
method described in API 14.3.1; Subsection 12.3, and other methods 
approved by the AO. Uncertainty indicates the risk of measurement 
error. The performance standards provide specific objective criteria 
against which the BLM could analyze operator requests to use new 
metering technology, measurement systems, and procedures not 
specifically addressed in the rule. The two-tiered uncertainty 
thresholds established in Sec.  3174.4(a)(1) set the maximum allowable 
volume measurement uncertainty. The BLM believes that the measurement 
uncertainties established are reasonable, based on equipment 
capabilities, industry standard practices and procedures, and BLM field 
experience.
    As noted, for FMPs measuring greater than or equal to 30,000 bbl 
per month, the maximum overall volume measurement uncertainty allowed 
is 0.50 percent. The BLM has established the 0.50 percent uncertainty limit based on uncertainty calculations 
and public comments received on the proposed rule, discussed below. The 
overall uncertainty calculation includes the effects of the meter 
accuracy; 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) factors, and the correction 
for temperature on liquids (CTL) factors; and the uncertainty of the 
CPL and CTL calculations. The BLM chose the volume threshold of 30,000 
bbl per month for this uncertainty level after determining that at this 
monthly volume, a one-percentage-point decrease in the expected over- 
or underpayment of royalties--from 1.5 percent to 0.5 percent--evaluated over a 5-year time frame, equals $150,000. 
This $150,000 amount reflects the cost to purchase a LACT system, based 
on price quotes from several distributors. In other words, requiring a 
LACT system, in terms of increased accuracy, will generate benefits 
that equal or exceed the cost of the new system. In making this 
calculation, the BLM assumed a 5-year crude oil price average of $67.58 
per bbl,\12\ and a royalty rate of 12.5 percent. FMPs with production 
volumes less than 30,000-bbl-per-month production volume do not 
generate sufficient volumes that the potential royalty risk justifies 
installing a LACT system with an expected 5-year lifespan. As a result, 
the maximum proposed overall measurement uncertainty for these FMPs is 
1.5 percent. The BLM believes based on available data and 
its experience that a 1.5 percent threshold is reasonable 
and readily achievable by manual tank gauging. Based on the BLM's 
analysis and review of comments received, the BLM determined that the 
overall uncertainty of manual tank gauging ranges from 0.6 
percent to 2.50 percent depending on the volume of oil 
removed from the tank at the time of sale. A 0.6 percent 
uncertainty results from potential measurement error applied to large 
volumes, while a 2.50 percent uncertainty results from the 
same potential measurement error applied to smaller volumes removed 
during one load-out. The 1.5 percent uncertainty in the 
final rule reflects the high average calculated uncertainty for a 
typical truck load-out by tank gauging, which BLM believe is 
representative of onshore operations more generally, and therefore is 
an appropriate threshold to use in this rule.
---------------------------------------------------------------------------

    \12\ Based on the projected nominal West Texas Intermediate 
crude oil spot price published in the U.S. Energy Information 
Administration's 2016 Annual Energy Outlook Reference case scenario.
---------------------------------------------------------------------------

    The two-tiered uncertainty performance requirements in the final 
rule reflect modifications from the proposed rule, based on comments 
received. First, one commenter noted that the proposed rule did not 
give guidance on how the uncertainty was to be calculated. The BLM 
agrees with this comment and the final rule makes it clear that the 
uncertainty is to be calculated using API 13.1, Statistical Concepts 
and Procedures; API 13.3, the uncertainty methodologies; the quadrature 
sum method as described in API 14.3.1, Subsection 12.3, General 
Equations and Uncertainty Guidelines; or other methods approved by the 
AO.
    Another commenter agreed that it is appropriate to permit a certain 
amount of measurement uncertainty and to utilize a tiered approach for 
uncertainty based on volume. However, the commenter disagreed with the 
proposed rule's three-tiered uncertainty requirement:  0.35 
percent for FMPs measuring more than 10,000 bbl per month;  
1 percent for FMPs measuring more than 100 bbl per month and less than 
or equal to 10,000 bbl per month; and  2.5 percent for FMPs 
measuring less than 100 bbl per month. The commenter said the proposed 
 2.5 percent uncertainty level for FMPs measuring volumes 
less than 100 bbl/month is both unnecessary and counterproductive. This 
commenter noted that there are a large number of older, low-volume 
wells operating on BLM and tribal leases, and argued that the  2.5 percent uncertainty for those operations could cause some 
low-volume operators to shut in their wells, resulting in a significant 
cumulative loss of Federal revenue from royalties. Commenters instead 
recommended that the BLM eliminate the lowest-volume category of the 
three uncertainty levels under proposed Sec.  3174.3(a)(1). They 
further recommended that all FMPs with monthly volumes averaged over 
the previous 12 months that are less than 10,000 bbl/month should be 
subject to an uncertainty level of  1.0 percent. The 
commenters also said that this gives the BLM more discretion over when 
a less stringent uncertainty level for low-volume operators is 
appropriate based on site-specific factors.
    The BLM partially agrees with these comments. After reanalyzing the 
uncertainty data and volume thresholds, the BLM has eliminated the 
lowest tier of uncertainty. However, this rule uses a 30,000 bbl per 
month volume as the dividing volume between the two tiers, and sets the 
uncertainty level for the highest-producing tier at 0.50 
percent and the uncertainty level for the lowest-producing tier at 
1.5 percent, which will be high enough for most tank-
gauging operations while still ensuring the rules achieve accurate 
measurement.
    The BLM chose the 30,000 bbl per month volume as the dividing line 
between the two tiers, and their respective uncertainty performance 
standards, based on what it would cost an operator to install and 
operate a LACT system, relative to the risk that the operator would 
under- or overpay royalties if measuring by tank gauging. The 
calculation for this assumes: A LACT system costs $150,000 and has a 5-
year expected equipment lifespan, tank gauging results in a 1.5 percent uncertainty, the 5-year oil price averages $67.58 per 
bbl, and the royalty rate is 12.5 percent. The following equation shows 
the calculation used to arrive at the 30,000 bbl per month volume

[[Page 81475]]

dividing line between the two tiers of uncertainty performance 
requirements:

Monthly volume = $150,000/((Uncertainty x Oil price x Royalty rate) x 
60 months)

    One commenter suggested that the performance standards for 
uncertainty should not be less than 1.0 percent. A 
performance standard of less than 1.0 percent is 
excessively onerous, the commenter said, and does not provide a 
substantial benefit compared to a 1.0 percent standard. 
This commenter did not justify why a 1.0 percent 
uncertainty standard is reasonable or how anything less is onerous. The 
BLM disagrees with this comment. The root square sum method of 
calculating the uncertainty of a LACT system with a PD meter configured 
and operated under the requirements of Order 4 calculates an overall 
uncertainty of 0.32 percent. The final rule makes only 
minor changes to the Order 4 LACT requirements, so a calculated overall 
uncertainty rate under this rule will be similar to the existing 
requirements of Order 4. A LACT system with either a PD meter or a 
Coriolis meter is very capable of achieving the 0.50 
percent uncertainty when constructed and operated according to the 
requirements of this rule and corresponding API standards; no change 
was made as a result of this comment.
    One commenter said BLM regulations do not need to specify equipment 
models that are acceptable for use in custody transfer measurement when 
uniform uncertainty metrics are utilized. The commenter stated that if 
any equipment meets the established uncertainty-performance standards 
for a measurement system, and that uncertainty can be validated and 
maintained, such equipment should then be allowed to be used for oil 
measurement. The BLM partly agrees with this comment, which is why this 
final rule establishes a procedure whereby the PMT can review and 
approve the use of new equipment and measurement methods, so long as 
the new equipment and methods meet the performance uncertainty and 
verifiability standards of the rule. The BLM believes that once this 
equipment has been proven to be capable of meeting the uncertainty 
performance and verifiability standards of this rule, then that 
equipment can be approved for use.
    The second part of this comment suggests that the volume 
uncertainty limit of 0.35 percent in the proposed rule for 
high-volume producers is excessively small (strict) for measurement 
installations that measure in excess of 10,000 bbl/month. The commenter 
further stated that the BLM failed to provide any basis for the 
proposed allowable volume uncertainty calculations. The proposed rule 
did not offer any detail as to how the uncertainty limit of 0.35 percent includes any effects of maximum allowable meter-
factor drift between meter proving, the minimum standard for 
repeatability during proving the accuracy of pressure and temperature 
transducers for volumetric correction, and the uncertainty in the 
volume-correction factor correction. The commenter also said the BLM 
did not disclose the data that it utilized to determine the 1.0 percent uncertainty limit for FMPs in the 100 to 10,000 bbl/
month range.
    The BLM conducted an overall uncertainty calculation for a LACT 
utilizing a PD meter operated and proven under the requirements of 
Order 4. The results of this calculation provided an overall 
uncertainty of 0.32 percent, which was what the BLM used to 
establish the higher standard in the proposed rule. The commenter did 
not provide a more appropriate uncertainty calculation to justify their 
claim that 0.35 percent is excessively small for 
installations that measure in excess of 10,000 bbl per month. As a 
result no specific changes were made in response to this comment; 
however, as noted elsewhere in this section, the BLM has modified the 
uncertainty thresholds for larger-volume FMPs.
    In order to identify appropriate thresholds, the BLM reviewed a 
proprietary third-party uncertainty calculation for tank gauging using 
Order 4 requirements for a 400 bbl tank. The results indicate that the 
overall uncertainty varies depending upon the volume removed from the 
tank. The overall uncertainty in the calculation varied from 0.6 percent for large volumes removed to uncertainties of 2.50 percent for very small volumes removed. The BLM reviewed 
overall uncertainty calculations in order to determine reasonable 
uncertainty requirement in the rule.
    Several commenters said the BLM should re-evaluate its proposed 
measurement uncertainty (0.35 percent), claiming the 
methodology appears to be flawed. They further stated the proposed oil 
measurement rule demands a level of accuracy that would not apply to 
heavy oil regimes and that would increase operating costs beyond what 
is necessary or of value. They suggest that operators with heavy oil 
operations may receive unwarranted and costly penalties at a greater 
rate than the rest of the petroleum industry, and that heavy oil 
producers would be disproportionately impacted by the proposed 
standard. These commenters did not submit justification for their 
claims, and when the BLM contacted them to clarify this comment, they 
still failed to justify or explain how heavy oil regimes would be 
disproportionately impacted by the rule. No change to the rule resulted 
from these comments.
    One commenter requested that the 0.35 percent 
performance uncertainty be adjusted to 1.0 percent for 
meters measuring 10,000 barrels per day. The commenter agreed with 
comments that the API submitted to the BLM on the proposed rule and 
requests that the BLM use the Order 4 proving and uncertainty 
performance requirements for LACT systems. The BLM has re-analyzed the 
uncertainty performance requirements and volume thresholds, and, based 
on the re-evaluation and other comments received showing a different 
uncertainty calculation resulting in a slightly higher uncertainty than 
proposed, has changed the rule's uncertainty performance standards to 
encompass reasonable flexibility in evaluating alternative measurement 
equipment and methods and adjusted the volume thresholds to match 
volumes where the risk to royalty would equal the expense of installing 
a LACT or CMS to require a more accurate measurement.
    Another commenter said the overall volume uncertainty limit of 
0.35 percent for measurement installations with throughputs 
greater than 10,000 bbl/month is unreasonably and excessively strict, 
given the potential number of sources of measurement error. The error 
should be calculated to include the uncertainty from all sources of 
error in the oil volumetric calculation chain. The BLM agrees in part 
with the comment that a 0.35 percent uncertainty may be 
somewhat strict in some applications. The 0.35 percent has 
been calculated to include all sources of error in the LACT measurement 
calculation chain, based on other comments providing similar 
calculations. The BLM has chosen to use a slightly higher uncertainty 
level in the final rule to give some leeway when considering approvals 
for future measurement technology and procedures for use on Federal and 
Indian leases. This commenter also suggested that systems installed at 
FMPs that measure less than 100 bbl/month should have the option to pay 
royalties as if they were producing at the rate of 100 bbl/month and 
avoid the cost of installing measurement equipment that could make 
their operations economically infeasible. The BLM

[[Page 81476]]

disagrees with the concept of paying royalties based on a fixed volume 
rather than royalties based on actual measurements. In addition, if the 
uncertainty standards would render a lease uneconomic, the operator can 
seek an exemption from the requirements under Sec.  3174.4(a)(2). No 
change to the rule resulted from this comment.
    One commenter said they were unable to verify the uncertainty 
levels proposed without the ``calculator'' that the BLM is developing. 
This commenter created its own uncertainty calculation using the 
following assumptions: A maximum allowable deviation for temperature of 
0.25[emsp14][deg]F and pressure of 0.25 psi. The uncertainty was 
calculated to be 0.46 percent in this one instance.
    The BLM appreciates receiving this comment as it provides useful 
input and actual calculation results to support the commenter's 
position. As a result of this comment and further analysis, the BLM 
agrees that this uncertainty calculation could reflect one possible 
application and has adjusted the rule's lower overall uncertainty 
performance requirements for the highest-producing tier to 0.50 percent.
    One commenter expressed concern that the cost of complying with 
this provision will increase as uncertainty standards are updated. 
However, there is nothing in this provision that provides for the 
updating of the uncertainty threshold standards.
    Under Sec.  3174.4(a)(2), only a BLM State Director, with the 
written concurrence of the PMT, prepared in coordination with the 
Deputy Director, can grant an exception to the prescribed uncertainty 
levels. Granting an exception requires a showing that meeting the 
required uncertainly levels would involve extraordinary cost or 
unacceptable adverse environmental effects. By having the State 
Directors make these decisions, with concurrence of the PMT (prepared 
in coordination with the Deputy Director), the BLM hopes to ensure that 
there is consistent application of the performance standards across the 
Bureau and that approvals for exceptions from the performance standards 
are granted in limited circumstances. In the proposed rule, the BLM had 
proposed to require concurrence from the Director; however, upon 
further review, the BLM modified the written concurrence requirement to 
require written concurrence from the PMT that has been prepared in 
coordination with the Deputy Director. The BLM feels this approach 
would be more appropriate given that the PMT will have the necessary 
technical expertise, while requiring coordination with the Deputy 
Director ensures such changes have the necessary national policy 
perspective.
    The BLM received several comments on its approach to exceptions to 
the proposed rule's uncertainty limits. A few commenters requested that 
the BLM clarify and limit the criteria a BLM State Director can use to 
grant exceptions. The BLM does not believe additional clarification is 
necessary and the rule's description of potential extraordinary 
circumstance(s) that could result in an exception to the uncertainty 
levels is sufficient. The BLM cannot identify every situation or event 
that could warrant an exception. The intent of the rule is that an 
exception is not a normal occurrence, and to allow exceptions only in 
limited, special circumstances. No change to the rule resulted from 
this comment.
    Similarly, another commenter urged the BLM to clarify the manner in 
which exceptions may be granted and to clearly define the term 
``extraordinary cost.'' According to this commenter, a lack of clear 
guidance on these exceptions will result in unrealistic expectations 
from operators and inconsistent application by the BLM. Again, there 
could be numerous circumstances under which an exception could be 
warranted, and the BLM cannot accurately anticipate and address all of 
these in the rule. It will be up to the individual or entity applying 
for the exception to make the case to justify an exception. The process 
for granting exceptions is more likely to be consistent if decisions 
are left to State Directors, with written concurrence from the PMT 
(prepared in coordination with the Deputy Director). No change to the 
rule resulted from this comment.
    One commenter questioned why, on the one hand, the proposed rule 
would have authorized BLM State Directors to grant exceptions to 
uncertainty standards for equipment at FMPs (with BLM Director 
concurrence) and on the other hand, the rule at Sec.  3174.4(d) gives 
the PMT the authority to recommend and the BLM to decide whether 
proposed alternative equipment or measurement procedures meets or 
exceeds the uncertainty standards. The commenter questioned a process 
that will rely on the availability of the PMT and State Directors to 
review and evaluate requests for exceptions. The commenter said BLM 
technical experts are often overworked, and therefore the PMT approval 
process is likely to take a considerable amount of time and hinder 
operators' ability to effectively develop Federal oil and gas 
resources. The BLM agrees that its technical experts have a significant 
workload and face a number of competing demands. However, one reason 
for creating a BLM-wide PMT is to relieve field offices of having to 
review new technology, and to provide a consistent BLM-wide decision-
making process. The BLM believes that this structure should minimize 
the amount of time it will take for the BLM to process requests for 
evaluation of new equipment, and to evaluate requests for exemptions 
from the uncertainty requirements. No change to the rule resulted from 
this comment.
    Section 3174.4(b) establishes the degree of allowable bias in a 
measurement. Bias differs from uncertainty in that bias results in 
systematic measurement error, whereas uncertainty only indicates a risk 
of measurement error. While the BLM acknowledges that it is virtually 
impossible to remove all bias in measurement, the final rule requires 
that there be no statistically significant bias at any FMPs. 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 
for purposes of compliance with the final rule. However, if the shift 
in the mean value of a set of measurements away from the true value of 
what is being measured exceeds the ``statistically combined 
uncertainty'' of the devices, then the BLM requires that known shift to 
be corrected to as close to the actual value as possible.
    The BLM received several comments concerning bias. The first 
commenter stated the rule does not give any guidance on how bias will 
be determined, or what the BLM considers to be statistically 
significant. In order for the bias restriction to be applied uniformly 
throughout the nation, the commenter asserted that the term needs to be 
defined in the regulation. The BLM agrees with this comment and has 
added a new definition for ``bias'' to 43 CFR subpart 3170, as part of 
the

[[Page 81477]]

rulemaking that is updating and replacing Order 3.
    Another commenter noted that the BLM presented no data or 
calculations in the proposed rule to verify that bias issues will not 
exist under field conditions where many additional variables impact the 
statistical calculations. The commenter claimed that the rule 
essentially assumes that uncertainties that can be demonstrated in 
laboratory conditions can also be demonstrated in field conditions, 
which are not practical in a production scenario. The commenter asked 
that the BLM delete paragraph (b) from the final rule. The BLM does not 
agree with this comment. If a shift in the mean value of a set of 
measurements away from the true value of what is being measured, 
exceeds the statistically combined uncertainty of the devices, occurs, 
then the BLM requires that known shift to be corrected to as close to 
actual value as possible. An example of where this shift could be 
discovered is during a transducer verification that results in a 
reading that is outside of the device's stated uncertainty. This is 
different from uncertainty, where a potential for measurement error 
exists. No change to the rule resulted from this comment.
    A third commenter recommended that the BLM clarify language in the 
preamble that discusses statistically significant bias. As noted above, 
the preamble quantifies statistically significant bias as being a 
number that is greater than the combined uncertainties of the 
laboratory device, or prover, and the measured device, or the 
``statistically combined uncertainty.'' The BLM recognizes that there 
will always be some apparent bias resulting from the uncertainty of all 
devices. Bias is only considered significant when it exceeds the 
combined uncertainties of the devices involved. The BLM believes that 
the final rule accurately explains bias in terms of it being outside of 
the ``statistically combined uncertainty'' of the devices being used. 
No change to the rule resulted from this comment.
    Section 3174.4(c) requires that all measurement equipment be 
subject to independent verification by the BLM that it is performing 
accurately and that all inputs, factors, and equations that are used to 
determine quantity or quality are valid. Order 4 already requires that 
the BLM be able to independently verify measurement methods, as well as 
bias, so these are not new requirements. The verifiability requirement 
in this section prohibits 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.
    The BLM received several comments about the verifiability 
requirements of this rule. One commenter seemed to suggest that the BLM 
did not take into account the use of automation and other measurement 
systems advances, such as the use of flow computers handling 
calculations. The comment further stated that in order to retain the 
raw data that the BLM needs to manually verify equipment accuracy, 
operators will be required to use computers that are less efficient and 
that require more data storage. The BLM agrees that the rule may 
require operators to acquire more data storage, but does not agree with 
the commenter that saving raw data for future verification will result 
in less efficient flow computers, or that it is unnecessary. The BLM 
manages Federal oil resources on behalf of the American taxpayer and 
has an affirmative obligation to ensure that the oil produced is 
accurately measured and accounted for. In order to satisfy those 
obligations it is critically important that an audit trail exists so 
that the BLM can verify the production data. As a result, the BLM will 
continue to manually verify calculations at FMPs. No change to the rule 
resulted from this comment.
    Another commenter suggested any verifiability does not take into 
account the difference between live calculations at high frequencies 
versus averaged and accumulated data over time. The commenter also said 
that independent calculations should only have to fall within a 
statistically insignificant window. In order for independent 
calculations to be applied uniformly throughout the nation, they should 
to be defined in the regulations, the commenter said. The BLM partly 
agrees with this comment that calculations should be live calculations 
at high frequencies or calculations averaged and accumulated over time. 
The Inspection and Enforcement Handbook will address possible methods 
for the BLM to verify calculations at an FMP. No changes to the rule 
were made as a result of this comment, but the BLM will include 
guidance in the Inspection and Enforcement Handbook regarding whether 
calculations should be based on live calculations or averaged over 
time. Under the final rule, all volume calculations at an FMP must be 
verifiable.
    One commenter asked whether the requirement that new equipment 
undergo independent verification will preclude new technology. The BLM 
does not intend to prevent or exclude new technology. In fact, this 
rule, by establishing performance standards, adopting industry 
standards, and standing up the PMT process, has been designed 
explicitly to provide flexibility for the BLM to adopt new technology 
and practices as they are developed. No changes were made in response 
to this comment.
    Another commenter said that paragraph (c) would require the BLM to 
contract with an independent laboratory to verify equipment, which 
could take 6 months per device and cost upwards of ``$500M'' for each 
device. The BLM disagrees with this comment because Sec.  3174.4(c) 
merely requires operators to have FMP equipment that can produce the 
source records that provide the data and equations the BLM needs to 
independently recalculate oil production volume and quality during 
production audits. No changes were made in response to this comment.
    Section 3174.4(d) clarifies that the operator can propose the use 
of alternative equipment, provided that it meets or exceeds the 
uncertainty requirements of this section. The PMT will make a 
determination under Sec.  3174.13 of this subpart regarding whether 
proposed alternative equipment or measurement procedures meets or 
exceeds the objectives and intent of this section. See Sec.  3174.13 
for discussion of comments concerning the PMT and the PMT review 
process.
Section 3174.5 Oil Measurement by Tank Gauging--General Requirements
    Section 3174.5(a) specifies the general requirements for oil 
measurement by tank gauging as a means to accurately determine the 
quantity and quality of oil removed from an FMP. The BLM received many 
comments on this section of the proposed rule. Almost all of these 
comments requested that the BLM consider permitting the use of ATG 
systems for custody transfer applications. Order 4 allows only manual 
tank gauging. In the proposed rule, the BLM indicated that it was 
considering including provisions in the final rule allowing for the use 
of ATG systems, and requested data regarding whether these systems can 
meet the BLM's performance standards for manual tank gauging with 
respect to uncertainty and verifiability. The BLM requested additional 
data regarding ATG measurement systems because it recognizes the 
significant safety advantages they provide.

[[Page 81478]]

    The majority of the commenters indicated that ATG systems are much 
safer for workers when compared to manual tank gauging systems, 
especially when workers are measuring hydrocarbon fluids such as those 
found in the Bakken, which have higher gravity and higher vapor 
pressure, and thus emit higher volumes of toxic fumes. The BLM agrees 
that safety concerns associated with manual tank gauging can be reduced 
if operators have the option of using ATG systems as well as the other 
measurement methods addressed in this final rule. Based on data 
provided in response to the proposed rule--both as public comment on 
the proposed rule and in support of project-specific variance requests 
to use ATG systems on tanks--the BLM has determined that ATG systems 
can meet or exceed the uncertainty thresholds for tank gauging. As a 
result, the rule has been changed to allow for the use of ATG systems.
    The BLM received one comment that recommended the BLM prohibit the 
practice of oil measurement by manual tank gauging because, according 
to the commenter, the practice is an antiquated and considerably less 
reliable method of measurement. The BLM disagrees that properly 
conducted manual tank gauging operations are antiquated or less 
reliable than other methods of measurement and will continue to give 
operators the option of using this widely accepted practice for oil 
measurement, which is generally used at lower-volume facilities. 
However, the BLM hopes for a shift towards ATG in areas where the 
nature of the produced oil presents a safety concern.
    In the proposed rule, Sec.  3174.5(b) required that all oil storage 
tanks, hatches, connections, and other access points be vapor tight and 
that 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 would 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. The intent is to 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. The 
requirement that all access points be vapor tight has been expressly 
included in this rule in order to eliminate confusion over the intent 
of Order 4, which specified all the same equipment, but did not specify 
the manner in which it was supposed to be operated. The implied intent 
of Order 4 was always that the tanks be operated such that they are 
vapor tight.
    The BLM received numerous comments on this section, the majority of 
which said the proposed requirements could conflict with U.S. 
Environmental Protection Agency (EPA) air quality regulations and the 
BLM's separately proposed Methane and Waste Prevention Rule (81 FR 
6616). Some of the same commenters also complained about the potential 
costs associated with retrofitting some of the tank batteries. The BLM 
disagrees with these comments. The intent of the requirement is to 
conserve the quantity and quality of the liquid hydrocarbons in storage 
by controlling the storage conditions, not to create a potential 
conflict with the EPA's regulations for release of harmful pollutants. 
The BLM also disagrees with claims made by some commenters that the 
potential costs associated with retrofitting existing tank batteries to 
make them vapor-tight would be too high. Pressure vacuum vent line 
valves and thief hatches are already required equipment for the 
existing tank battery installations under Order 4. Paragraphs (b)(3) 
and (4) of the proposed rule have been changed and merged into a new 
paragraph (b)(3) in the final rule, which now requires that all oil 
storage tanks be vapor tight, and, unless connected to a vapor recovery 
or flare system, must have a pressure-vacuum relief valve installed at 
the highest point in the vent line or connection with another tank. All 
hatches, connections, and other access points must be installed and 
maintained in accordance with manufacturers' specifications.
    Several commenters recommended that the BLM add the requirement 
that oil storage tank hatches (``thief hatches'' or other access 
points) have pressure indicators that provide a clear and immediate 
visual indicator of tank pressures and potential gas/vapor release 
hazard should the tank need to be accessed. One of the commenters said 
pressure indicators on tank access hatches visually display the 
presence of gas/vapor pressure in a tank, allowing a trained worker to 
make risk-based decisions before accessing a tank, including actuating 
a remote venting valve, venting gas to a flare, or using appropriate 
respiratory protection, such as a self-contained breathing apparatus or 
an air-line respirator. The BLM recognizes that having such information 
could potentially be useful to personnel in the field; however, the BLM 
did not make any changes in response to this comment because the 
pressure indicators proposed by the commenter would have no bearing on 
determining measured volume, and therefore are outside the scope of 
this rule. It should also be noted that in general the Occupational 
Safety and Health Administration takes the lead on adopting and 
enforcing employee safety requirements.
    Several commenters stated it is imperative that tanks be maintained 
vapor tight and that there be a monitoring or inspection program to 
ensure compliance. The BLM agrees and the final rule has maintained the 
vapor tight integrity requirement for oil storage tanks. The BLM's 
inspection and enforcement program will continue to ensure compliance 
with this and all other oil and gas regulations. No additional changes 
were made to the final rule as a result of these comments.
    One commenter stated that if the oil is weathered or stabilized, 
there is no need for hatches and other connections to be vapor tight. 
The commenter did not explain how weathered or stabilized oil could 
negate the need for hatches and other connections to be vapor tight. 
The BLM disagrees that stabilized product does not require a vapor-
tight storage condition. The vapor tight integrity is an implied 
requirement of the current Order 4 and therefore will not require the 
operator to retrofit any existing equipment. In a unique situation 
where a variance could be justified, the operator could seek a variance 
through the appropriate BLM field office following the process outlined 
in Sec.  3170.6 of this part, a related rulemaking that is replacing 
Order 3, with approval by the AO. No additional changes were made to 
the final rule. This section in the final rule is now identified as 
Sec.  3174.5(b)(3).
    Section 3174.5(b)(5) of the proposed rule specified that all oil 
storage tanks must be clearly identified and have a unique number 
stenciled on them, maintained in a legible condition. Order 4 did not 
have a similar requirement. The BLM received several comments that said 
this section did not adequately communicate how the numbering system 
would work and how numbers are assigned to the tanks. The BLM agrees 
that this section was not clear. As a result of these comments, the 
final rule has been changed to specify that all oil storage tanks must 
be clearly identified with an operator-generated number that is unique 
to the lease, unit PA, or CA stenciled on the tank and maintained in a 
legible condition. This section now appears as Sec.  3174.5(b)(4) in 
the final rule.

[[Page 81479]]

    Section 3174.5(b)(6) of the proposed rule required each oil storage 
tank associated with an approved FMP by tank gauging to be set and 
maintained level. Several commenters said this requirement is 
unwarranted and unnecessary without offering any details. The BLM 
disagrees, as this is not a new requirement. Order 4 has a similar 
requirement, and the BLM believes that not requiring a tank to be set 
or maintained level would be unacceptable because it could result in 
uncertainty in measurement. Industry standards also dictate that tanks 
used for gauging operations should be level. No change resulted from 
these comments. This section now appears as Sec.  3174.5(b)(5) in the 
final rule.
    Section 3174.5(b)(7) of the proposed rule specified each oil 
storage tank associated with an approved FMP that has a tank-gauging 
system 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 maintained in a 
legible condition. One commenter, without offering any justification, 
said this requirement should apply only to tanks that are manually 
gauged. The BLM disagrees as this gauging reference point is also 
needed during the verification and calibration of an ATG system, not 
just for tanks that are measured by manual gauging. No change was made 
to the final rule as a result of this comment. This section now appears 
as Sec.  3174.5(b)(6) in the final rule.
    Section 3174.5(c) in the proposed rule required the operator to 
accurately calibrate each oil storage tank associated with an approved 
FMP that has a tank-gauging system, under either API 2.2A or API RP 
2556. Order 4 had a similar requirement. The BLM received a few 
comments on this section. One commenter pointed out that under the 
proposed rule, sales tank calibrations apparently can only be made 
using API MPMS Chapter 2.2A--Tank Strapping by Manual Method, when in 
fact other methodologies in Chapter 2 are available. The BLM agrees 
that industry standards provide additional methods for calibrating 
sales tanks. As a result of this comment, the BLM changed the final 
rule to incorporate industry standards API 2.2A, API 2.2B, or API 2.2C; 
and API RP 2556. One commenter stated the proposed rule did not clarify 
when or how often a sales tank calibration is required. The BLM 
disagrees. Section 3174.5(c)(2) clearly states when a sales tank 
calibration is required--if the tank is relocated, repaired, or the 
capacity is changed as a result of denting, damage, installation, 
removal of interior components or other alterations. No changes were 
made to the final rule as a result of this comment.
    One commenter said operators should be allowed to use formulas for 
estimating tank volumes. The formula of 1.67 bbl/inch is a tool 
operators use to estimate the volume stored in the tank. When the oil 
is sold, the commenter said, a more accurate measurement will be taken, 
ensuring that the operator is properly paid for the oil being sold, 
which will in turn result in the correct royalty payment to the 
government. This rule seeks to ensure accurate oil measurement, not 
volume estimates. This comment is not relevant to sales tank 
calibration. The final rule was not changed as a result of this 
comment.
    Section 3174.5(c)(1)(i) of the proposed rule specified the 
strapping table unit volume must be in barrels. The BLM received no 
comments and made no changes to this paragraph.
    Section 3174.5(c)(1)(ii) of the proposed rule specified the 
incremental height measurement on all tanks must be in \1/8\-inch 
increments. This was a change from the incremental height measurement 
in Order 4 of \1/4\-inch gauging accuracy for tanks of 1,000 bbl or 
less in capacity. The BLM received many comments on this section. The 
commenters consistently addressed the following two main points: (1) 
The benefits from the increase in accuracy would be minimal in 
comparison to the time and costs it would take to achieve the increased 
accuracy; and (2) The change would require operators to re-strap their 
tanks and generate new tank tables, and, in many cases, make major 
changes to their software programs, all at substantial costs. The BLM 
agrees that the costs of a change to \1/8\-inch increments for tank 
gauging on tanks that are 1,000 bbl or less in capacity is unnecessary 
because the additional cost burdens outweigh any potential accuracy 
gains. As a result of these comments, the rule has been changed to say 
that the incremental height measurement must match the gauging 
increments specified in Sec.  3174.6(b)(5)(i)(C), which requires \1/4\-
inch increments for tanks 1,000 bbl or less in capacity, and \1/8\-inch 
increments for tanks greater than 1,000 bbl in capacity. This is the 
same accuracy standard that has been in effect under Order 4. The BLM 
would like to note that API industry standards relative to manual tank 
gauging have conflicting tank-gauging increments. The BLM has chosen to 
retain the current Order 4 gauging increments requirement by following 
API 18.1 tank gauging increments for tanks that are 1,000 bbl and less 
and API 3.1A tank gauging increments for tanks greater than 1,000 bbl.
    Section 3174.5(c)(2) requires operators to recalibrate a sales tank 
if it is relocated or repaired, or the capacity is changed as a result 
of denting, damage, installation, removal of interior components, or 
other alterations. Order 4 had a nearly identical requirement. The BLM 
received a few comments on this section, all of which said there is no 
definition of how large the dent or alteration would need to be to 
trigger this requirement. The commenters also stated that the BLM must 
clarify the amount of volume displacement that would require action on 
the part of the operator. The final point that the commenters made also 
suggested that the BLM should offer a range of options that operators 
could take in response to denting, including tank inspection, and 
provide them an opportunity to avoid being in violation. For example, 
an insulated tank may be dented on the outside but the dent would have 
no impact on the inside due to several inches of insulation. Upon 
review of these comments, the BLM has made no change to the rule for 
the following reasons. The volume displacement from tank denting cannot 
be known until the dent has been measured and the impacts analyzed. To 
measure the impacts, this section requires re-strapping of the tank. 
The BLM has chosen not to allow an operator to ``estimate'' the impact 
of denting on a tank used for tank gauging as there would be no 
enforceable requirement to properly determine the resulting volume 
impacts. Denting of the insulation on a tank may or may not result in 
denting of the sales tank. If denting is observed on the insulation of 
a tank, it is the operator's responsibility to verify that no internal 
tank denting has occurred under the insulation.
    Section 3174.5(c)(3) requires operators to submit sales tank 
calibration charts (tank tables) to the AO within 30 days after 
calibration. Order 4 required them to be submitted to the AO upon 
request. The BLM received several comments on this section. A few 
commenters recommended extending the 30-day time period to 45 days to 
allow for more coordination time between transporter and operator. 
After considering these comments, the BLM agrees that transporters and 
operators may need more time to submit the tank tables to the BLM. As a 
result of these comments, the final rule now requires that tank tables 
must be submitted to the AO within 45 days after calibration. Tank 
tables may be in paper or electronic format. A couple of

[[Page 81480]]

commenters said this requirement is another example of the BLM getting 
into the day-to-day operations of industry. They said there is 
absolutely no reason for the BLM to have these charts, argued that they 
serve no purpose, suggested that this requirement is excessively 
prescriptive, and asked the BLM to justify the need for the charts. Oil 
tanks are constructed to API standards and have a common, industry-wide 
standard strapping chart, the commenters said, and these tanks are not 
proven once installed. The BLM disagrees with these comments, as the 
tank calibration charts (tank tables) are in fact unique for each tank, 
and therefore there should not be a common, industry-wide standard 
strapping chart in use where tank gauging is the method of measurement 
at an FMP. The BLM has a long history of using the tank tables on a 
daily basis for production verification efforts, such as during 
production inspections and records-analysis audits. No changes were 
made to the final rule as a result of these comments.
    The BLM has an affirmative obligation to maintain an audit trail 
supporting Federal and tribal oil production. A couple of commenters 
requested that the BLM continue to use the Order 4 requirement that 
operators submit their latest tank calibration charts when the AO 
requests them, in order to avoid confusion and give operators notice 
that an inspection is imminent. The BLM disagrees because the new 
requirement will serve as verification that the operator has had the 
tanks strapped as required, and enables the BLM to perform the required 
inspection activities. Additionally, the BLM has no obligation to 
provide operators notice that an inspection is imminent.
    One commenter said marginal producing leases should be exempt from 
tank-gauging requirements. The BLM disagrees. Marginal leases are 
already subject to tank-gauging requirements. Under this final rule, 
operators on marginal-producing leases are allowed to continue using 
manual tank gauging, which imposes only modest economic impact on these 
leases.
Section 3174.6 Oil Measurement by Tank Gauging--Procedures
    Section 3174.6 paragraphs (a) and (b) require operators to take the 
steps in the order prescribed in the following paragraphs to manually 
determine by tank gauging the quality and quantity of oil measured 
under field conditions at an FMP. The BLM received several comments on 
this section. The comments said the detailed tank-gauging procedures in 
this section do not align with the industry standard. The BLM partly 
agrees, in that industry standards for certain activities have several 
options for operators to follow for achieving the desired outcome. The 
proposed rule did not reflect all of those options. As a result of 
these comments, the final rule has been changed to reference the 
appropriate industry standards and remove any unnecessarily 
prescriptive requirements to ensure accurate measurement using tank 
gauging.
    Section 3174.6(b)(1) contains the requirement in Order 4 and the 
proposed rule that the tank be isolated for at least 30 minutes to 
allow contents to settle before proceeding with tank gauging 
operations. The BLM received a couple of comments on this section. The 
commenters said this requirement would be costly and is unnecessary, as 
this activity will not increase the accuracy of measurements. The BLM 
disagrees. This requirement will ensure that the tank is isolated and 
that the crude oil layer is still, with no surface foaming. In many 
liquid manual sampling applications, the product to be sampled contains 
a heavy component (such as free water) that tends to separate from the 
main component. In these instances, it should be recognized that until 
the heavy component completely settles out, sampling will likely result 
in varying sample qualities. No change was made to the final rule as a 
result of these comments.
    Section 3174.6(b)(2) contains the requirements for determining the 
temperature of oil contained in a sales tank that is used as an FMP. 
Operators must comply with paragraphs (b)(2)(i) through (iii) of this 
section and API 7 and API 7.3. The BLM received numerous comments on 
this section. Several commenters requested that the BLM eliminate the 
reference to mercury in paragraph (b)(2)(i). In the proposed rule, that 
paragraph required glass thermometers to be clean, be free of mercury 
separation, and have a minimum graduation of 1.0[emsp14][deg]F. The BLM 
agrees that the mercury reference should be removed because the EPA has 
banned mercury thermometers from use. As a result of these comments, 
the final rule has been changed to say that glass thermometers must be 
``free of fluid separation.''
    The BLM received a comment concerning paragraphs (ii) through (iv), 
which said the reported graduation and accuracy requirements for 
temperature measurement devices are different based on the technology 
employed (minimum graduation of 1.0 [deg]F for liquid-in-glass 
thermometer vs. minimum graduation of 0.1 [deg]F for portable 
electronic thermometers (PET)). The commenter did not elaborate, but we 
assume the commenter believes PETs should be as accurate as glass 
thermometers. This comment is not consistent with the mandate of 
keeping the uncertainty in the measured quantity to within a specified 
value, nor is it consistent with existing industry standards (API MPMS 
Chapter 7). The BLM disagrees in part with this comment since the BLM 
used the minimum graduations from the industry standard, of 1.0 [deg]F 
for glass and 0.1 [deg]F from electronic thermometers. For consistency, 
and as a result of this comment, the BLM is requiring an accuracy of 
0.5 [deg]F for both glass and electronic thermometers.
    Several commenters questioned the thermometer immersion times 
required in the proposed rule under paragraph (b)(2)(iii), which 
referenced API 7, Table 6. They also asked the BLM to allow alternate 
methods for determining opening oil temperatures, to alleviate 
potential safety and economic concerns. The BLM disagrees in part as 
the immersion times are an industry standard, but also agrees in part 
to allow alternate methods under API 7. The prescriptive requirements 
under paragraph (b)(2)(iii) have been removed because the final rule 
already states that operators must comply with API 7, which includes 
the Table 6 requirements. Furthermore, the BLM changed the rule to give 
operators more flexibility by allowing them to use alternate methods 
for temperature determinations under API 7 and API 7.3, as well as the 
option of using ATG/hybrid tank measurement systems, in order to 
address the safety concerns identified by commenters. As a result of 
these comments and changes, the final rule eliminates paragraph 
(b)(2)(iii) of the proposed rule, resulting in the renumbering of 
paragraph (b)(2)(iv) in the proposed rule to paragraph (b)(2)(iii) in 
this final rule.
    Section 3174.6(b)(3) of the proposed rule specified that sampling 
of oil removed from an FMP tank must yield a representative sample of 
the oil and its physical properties, and must comply with the 
procedures listed in paragraphs (i) through (iii) of this section and 
API 8.1. The BLM received several comments requesting that the final 
rule give operators other sampling options. The BLM agrees that other 
sampling options can still achieve the desired measurement uncertainty. 
As a result of these comments, the BLM removed the prescriptive 
requirements in paragraphs (b)(3)(i) through (iii), and added a 
reference to API 8.2's standards for automatic sampling procedures to 
the final rule.

[[Page 81481]]

    Section 3174.6(b)(4) of the proposed rule specified that tests for 
oil gravity must comply with paragraphs (b)(4)(i) through (iv) of this 
section and API 9.3. The BLM received a couple of comments on this 
section. One commenter said that API Chapter 9 contains additional 
methods for determining gravity that can be more appropriate to use 
(based on the conditions of the oil at sample time). Therefore, the 
commenter asserted that the final rule should simply specify that any 
API Chapter 9 methodology is appropriate for determining gravity. The 
commenter said the procedure outlined in the proposed section was not 
consistent with API 9.3. Another commenter stated that proposed 
paragraph (b)(4)(i), which required the use of a thermohydrometer for 
API gravity (density) measurement, would limit the use of new, 
automated, more accurate technology such as Coriolis meters and density 
gauges. The commenter said allowance should be made for other methods 
that can meet the uncertainty requirements of the regulation. The BLM 
agrees that this provision of the proposed rule was too prescriptive 
and unnecessarily limited potential compliance options. As a result of 
these comments, the following changes were made to the final rule:
     This section now incorporates by reference API 9.1, API 
9.2, or API 9.3 to allow additional methods to measure API gravity;
     Paragraph (b)(4)(i) is changed to include the use of a 
hydrometer in addition to a thermohydrometer;
     Proposed paragraph (b)(4)(ii) has been removed consistent 
with the BLM's determination that the provision was too prescriptive;
     Proposed paragraph (b)(4)(iii) is now paragraph (b)(4)(ii) 
and has been revised to require operators to allow the temperature to 
stabilize for at least 5 minutes; and
     Proposed paragraph (b)(4)(iv) is now paragraph (b)(4)(iii) 
and has been revised to require operators to read and record the 
observed API oil gravity to the nearest 0.1 degree, and to read and 
record the temperature reading to the nearest 1.0 [deg]F.
    Section 3174.6(b)(5) of the proposed rule required operators to 
take and record the tank opening gauge only after upper, middle, and 
outlet samples have been taken. It further required gauging to comply 
with paragraphs (b)(5)(i) through (b)(5)(v) of this section and API 
3.1A. One commenter said the opening measurement should be taken with a 
matched (bob and tape) and currently ``certified'' gauging tape. The 
comment recommended that the rule specify that the tape and bob shall 
be certified within the last year as specified in API 3.1A. The BLM 
agrees with this recommendation, as it is consistent with API 
standards. As a result, the BLM has included API 3.1A in this paragraph 
and has eliminated prescriptive language that repeats API 3.1A.
    Similar to the proposed rule, Sec.  3174.6(b)(5)(i) of the final 
rule contains the requirements for manual gauging. But in response to 
commenters' requests that the BLM allow automatic and hybrid tank 
gauging, as discussed earlier in this preamble, this section in the 
final rule includes a new paragraph (b)(5)(ii), which contains the 
requirements for ATG. During the initial years of rule implementation, 
the BLM will not limit which ATG makes or models operators can use, but 
starting 2 years after the effective date of this rule, operators will 
only be permitted to use the ATG makes and models that the BLM approves 
for use and lists on its Web site. To ensure that ATG equipment in use 
at that time meet with BLM approval, the BLM encourages operators, 
manufacturers, or other entities (e.g., trade associations) to pursue 
equipment approval prior to use. Paragraph (b)(5)(ii) identifies 
requirements for inspecting and verifying the accuracy of ATG systems 
and for maintaining a log of field verifications.
    Section 3174.6(b)(6) of the proposed rule required operators to 
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), and 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. The BLM received a few comments on this section. The 
commenters all addressed the fact that API 10.4 has been updated since 
the BLM published the proposed rule, and that the prescriptive 
requirements in paragraphs (b)(6)(i) through (iii) were not consistent 
with the revised industry standard. The BLM agrees that the API 
standard has been updated and that the requirements in paragraphs 
(b)(6)(i) through (iii) of the proposed rule are too prescriptive and 
inconsistent with the revised industry standard. Based on its review of 
the revised standard and as a result of these comments, the BLM removed 
the prescriptive requirements in paragraphs (b)(6)(i) through (iii). 
The final rule requires operators to determine S&W content by using API 
10.4, which has been incorporated into the final rule by reference.
    Without saying why, one commenter said the BLM should incorporate 
all sections of API Chapter 10 into the final rule. The BLM disagrees. 
Since the oil measurement at issue in this rule is inherently a ``field 
procedure,'' in which the S&W content is required to be determined and 
documented on the run ticket at the completion of the tank gauging/
custody transfer procedure, the BLM determined that the only applicable 
section is 10.4. This comment did not result in a change to the final 
rule.
    Section 3174.6(b)(7) requires operators, after conducting the S&W 
determination, to conduct the transfer operation and seal the effected 
valves under Sec. Sec.  3173.2 and 3173.5 of this part. There were no 
comments to this section.
    Section 3174.6(b)(8) requires operators to determine the tank 
closing temperature following procedures discussed in paragraph (b)(2) 
of this section. Any comments concerning temperature determination have 
been addressed earlier in the paragraph (b)(2) discussion.
    Section 3174.6(b)(9) requires operators to take the closing gauge 
using procedures in paragraph (b)(5) of this section. Any comments 
concerning gauging operations have been addressed in the paragraph 
(b)(5) discussion.
    Section 3174.6(b)(10) requires operators to end their tank-gauging 
operations by completing a measurement ticket in accordance with Sec.  
3174.12. The proposed rule included seven activities in paragraphs 
(b)(10)(i) through (vii) that dictated how operators should derive the 
data required for the measurement tickets. Some commenters said this 
list of activities was too prescriptive. In an effort to be less 
prescriptive, the BLM deleted paragraphs (b)(10)(i) through (vii) in 
the final rule and refers operators to the rule's measurement-ticket 
requirements.
Section 3174.7 LACT System--General Requirements
    Paragraphs (a) through (c) of this section in both the proposed and 
final rule refer operators to other sections of this rule for 
construction and operation requirements for LACT systems, proving 
requirements, and measurement tickets. The proposed rule in paragraph 
(a) included a reference to API standards and in paragraph (c) a table 
that listed the requirements and components of a LACT system, along 
with references to the sections of the proposed rule containing the 
minimum standards for each of those components. The BLM received 
several comments on these paragraphs.
    Several commenters said the BLM should not be so prescriptive and 
should instead require compliance with

[[Page 81482]]

the appropriate API standards. In general, the BLM agrees that 
following published industry standards can result in the desired 
measurement uncertainty, and paragraph (a) of the final rule now 
requires LACTs to meet the standards prescribed in the applicable API 
sections. Paragraph (b) of the final rule requires LACTs to be proven 
as prescribed in Sec.  3174.11 of this subpart. The proposed table of 
``Standards to measure oil by a LACT system'' from paragraph (c) has 
been removed. Although it was a handy reference that directed readers 
to requirements that were listed in other sections of the proposed 
rule, the table was redundant and unnecessary. Paragraph (c) in the 
final rule now refers to the requirement for completing measurement 
tickets under Sec.  3174.12(b).
    Several commenters were uncertain about whether the LACT 
requirements only applied to new facilities, with existing facilities 
grandfathered. Most of the commenters also suggested that bringing 
existing facilities into compliance within the 180-day implementation 
timeframe was either too expensive, impossible, or both. In response to 
these comments, and as discussed previously in this preamble, the BLM 
has clarified in the final rule that all facilities are subject to the 
new requirements, with operators required to come into compliance on a 
staggered schedule of between 1 and 4 years, depending on their levels 
of production. This was achieved by tying compliance to the requirement 
to apply for an FMP found in the new 43 CFR subpart 3173. These 
significantly extended time frames will give operators time to plan and 
budget for expenses in advance, while limiting the chances that there 
will be local or national shortages of equipment or technical 
expertise, as might have resulted from the original proposed, 180-day 
implementation period.
    Several commenters noted that in proposed paragraph (c), the BLM 
limited LACTs to those with PD meters, and suggested that other types 
of meters should be allowed. Most of those commenters specifically 
requested that Coriolis meters be allowed, but some requested that any 
type of meter permitted in API standards be allowed. This would include 
PD, Coriolis, and turbine meters. The BLM partly agrees and has changed 
the rule to allow Coriolis meters to be used with LACTs. However, the 
BLM does not agree that turbine meters should be allowed. In the BLM's 
experience, confirmed by many industry sources, turbine flowmeters are 
less accurate than PD and Coriolis meters and are more subject to wear 
and/or damage. As a result, the BLM will continue to disallow turbine 
meters in LACTs. The change to allow Coriolis meters in LACTs is found 
in Sec.  3174.8(a)(1). The definition of, proving standards for, and 
other specific requirements related to the use and operation of 
Coriolis meters are addressed by other sections of the final rule.
    One commenter stated that Sec.  3174.7(b) would require operators 
to generate an additional run ticket before proving, and that the BLM 
should take into account the additional cost associated with that extra 
run ticket. The BLM did analyze the financial impacts of increased run 
tickets in its Paperwork Reduction Act analysis, which was discussed in 
the proposed rule preamble. Another commenter pointed out that this 
additional run ticket is unnecessary in LACTs with flow computers as a 
flow computer is capable of implementing a new meter factor in the 
middle of a month without the operator having to close it. The BLM 
agrees and as a result of this comment, the BLM changed Sec.  
3174.12(b)(1) of the rule to remove the requirement that operators 
close a run ticket prior to proving LACT systems that utilize flow 
computers, which will reduce the overall cost to operators.
    One commenter said the BLM should remove requirements in proposed 
Sec. Sec.  3174.7(c) and 3174.8(b)(7) for S&W monitors at LACTs because 
there is no such thing as an ``S&W monitor.'' There are water monitors 
or water probes, the commenter continued, but water monitors are not 
part of any oil measurement system. Rather, operators use water 
monitors to divert the flow back to tanks for additional processing to 
remove large amounts of water from their production stream. The BLM 
agrees with this commenter's assessment. From a regulatory perspective, 
a water monitor should not be required equipment at a LACT because it 
does not help the BLM verify accurate measurement and net oil volumes. 
In the final rule, the BLM has incorporated LACT requirements from API 
6.1 and eliminated the table in Sec.  3174.7(c), along with the S&W 
monitor requirements in Sec.  3174.8(b)(7).
    Section 3174.7 paragraphs (d) and (e) retain current requirements 
that all components of a LACT system be accessible for inspection by 
the AO and that the AO be notified of all LACT system failures that may 
have resulted in measurement error. Numerous commenters stated that the 
term ``notify'' in paragraph (e)(1) was ambiguous and requested that 
the BLM define what forms of notification are acceptable and the time 
frame for notifying the AO. The BLM agrees that this term needs to be 
defined and has defined ``notify'' to mean ``to contact by any method, 
including but not limited to electronically (email), in-person, by 
telephone, by form 3160-5 (Sundry Notice), letter, or Incident of 
Noncompliance.'' This definition has been added to the definitions 
listed in 43 CFR 3170.3, part of the rulemaking that is replacing Order 
3.
    Numerous commenters stated that the 24-hour time frame in proposed 
paragraph (e)(1) regarding notifying the BLM of LACT system failure 
was: (1) Impractical, (2) Too restrictive; (3) Potentially unnecessary 
if the failure was small (less than 0.05 percent); (4) Unlikely to 
significantly affect the net oil volume; (5) Too expensive for 
operators to implement because additional monitoring equipment would be 
required; and (6) Would require speculation on the part of the 
operators as to when a malfunction occurred when no one was present at 
the time of the malfunction. Most commenters suggested requiring 
reporting within 7 days after discovery. The BLM partly agrees, and 
paragraph (e)(1) of the final rule now requires notification within 72 
hours after discovery. This time frame will 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 within a reasonable time frame without placing unnecessary 
burdens on the operator. Requiring notification within 72 hours will 
allow operators to deal with urgent situations while still being able 
to timely notify the BLM.
    Section 3174.7 paragraph (f) of the proposed rule would have 
retained the current Order 4 requirement that any tests conducted on 
oil samples taken from the LACT system samplers for determination of 
temperature, oil gravity, and S&W content meet the same minimum 
standards set in the manual tank gauging sections. However, the section 
of the preamble describing proposed Sec.  3174.7(f) incorrectly said 
the oil samples themselves had to comply with the standards in the 
manual tank gauging section, rather than the testing procedures used to 
measure temperature, gravity (density), and S&W content. One commenter 
pointed out that this section not only incorrectly implied that 
temperature is somehow calculated from the oil in the sample pot, it 
also incorrectly referred to the standard testing procedures designed 
for manual tank gauging, not for testing using automated samplers as 
required in LACTs. The commenter stated that the BLM should use the 
standards in API

[[Page 81483]]

8.1 for static (manual) tank gauging and the standards in API 8.2 and 
API 8.3 for automatic sampler systems in LACTs, rather than referencing 
incorrect methods. The BLM agrees that the proposed rule preamble 
contains an incorrect summary of the actual proposed regulatory 
requirement in Sec.  3174.7(f), and that the correct reference should 
be API 8.1 for sampling in static (manual) sampling and API 8.2 and API 
8.3 for automatic sampler systems within LACTs. With this 
clarification, Sec.  3174.7(f) in the final rule remains unchanged, 
although the recommendation to incorporate API 8.2 and API 8.3 by 
reference is accepted. The reference to this requirement is in Sec.  
3174.8(b)(1).
    Paragraph Sec.  3174.7(g) prohibits the use of automatic 
temperature/gravity compensators on LACT systems. Although Order 4 
requires these devices, this rule will require those automatic 
compensators to be replaced using an electronic temperature averaging 
device. Automatic temperature/gravity compensators 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. As a result, there is no ability to 
create an audit trail for these systems. As explained in the proposed 
rule, 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 the devices degrade the accuracy of measurement. 
Because there are relatively few LACT systems that still employ 
automatic temperature/gravity compensators, the BLM does not believe 
this requirement will result in significant costs to the industry.
    Several commenters objected to this requirement, stating that 
temperature averagers are expensive and not necessarily any more 
accurate than temperature compensators, and that this change would 
require operators to replace functioning equipment at significant cost 
for no readily apparent benefit. One commenter stated that existing 
equipment should be grandfathered as long as an audit trail exists, and 
that the BLM should provide scientific evidence that automatic 
temperature/gravity compensators are less accurate than temperature 
averaging devices. Other commenters said that the simultaneous demand 
for temperature averaging devices would drive up the cost of purchasing 
and installing these devices on LACT systems. Several commenters 
indicated that rather than bear such a cost, some operators would 
choose to shut in wells and cease production activities.
    In response to these comments, the BLM conducted field surveys of 
the companies that made the comments and determined that, in fact, they 
had very few LACTs that are still using automatic temperature/gravity 
compensators. Indeed, one of the companies had only one such LACT. The 
fact that very few LACTs still use automatic temperature/gravity 
compensators was confirmed by a major LACT manufacturer who stated that 
they sell very few automatic temperature/gravity compensators 
domestically, and that nearly all LACTs are currently equipped with 
temperature averagers. Further, this rule now provides for a phase-in 
of this new equipment over the next 1 to 4 years, based on when 
operators receive their FMP approvals, and the cost is relatively 
inexpensive (roughly $6,500 per LACT for the equipment). Regarding 
scientific studies or other data showing temperature averagers are more 
accurate, the BLM is not aware of any studies that show this. The main 
reason for the prohibition is that a temperature compensator is a 
mechanical device that does not have the capability for recording an 
``audit trail,'' and therefore is inconsistent with the BLM's 
production accountability obligations. For these reasons, no change was 
made in this final rule.
Section 3174.8 LACT System--Components and Operating Requirements
    Section 3174.8 contains LACT system components and operating 
requirements.
    This section is closely related to Sec.  3174.7 in that Sec.  
3174.7 contains general requirements for LACTs and states that LACTs 
must meet the construction and operation requirements and minimum 
standards of Sec.  3174.8. Section 3174.8 goes into detail on what 
those requirements and standards are. Consequently, many of the 
comments on this section are closely related to comments received on 
Sec.  3174.7.
    In the proposed rule, Sec.  3174.8(a) listed the components that 
each LACT must include. Several commenters said the BLM should not be 
so prescriptive and should instead require operators to comply with the 
appropriate API standards. One commenter stated this change would 
eliminate confusion and make it clear that Coriolis meters would be 
allowed as part of LACTs. In general, the BLM agrees that the original 
language was too prescriptive and may have inadvertently disallowed the 
use of Coriolis meters with LACTs. As a result of these comments, the 
final rule now simply requires LACTs to meet the standards prescribed 
in the applicable API sections. The list of all of the components 
required in LACTs has now been deleted from paragraph (a) and replaced 
with a statement that each LACT must include all equipment listed in 
API 6.1, with certain listed exceptions. The LACT components listed in 
Sec.  3174.8(a) are related to requirements for PD and Coriolis meters 
and electronic temperature averaging devices, and allow multiple means 
of applying back pressure to the LACT to ensure single-phase flow. 
LACTs must consist of meters that have been reviewed by the PMT, 
approved by the BLM, and identified and described on the nationwide 
approval list at the BLM Web site (www.blm.gov) (see Sec.  
3174.8(a)(1)). Initially, the BLM will have no PD or Coriolis meter 
make or models limitations, but starting 2 years after the effective 
date of the rule, operators can only use the PD or Coriolis meter makes 
and models that the BLM approves for use and lists on its Web site. To 
ensure that specific PD and Coriolis meters in use at that time meet 
with BLM approval, the BLM encourages operators, manufacturers, or 
other entities (e.g., trade associations) to pursue equipment approval 
prior to use.
    One commenter stated that proposed Sec.  3174.8 did not refer to 
industry standards for automatic sampling systems used with LACT and 
Coriolis meter systems, and that failure to provide minimal 
requirements could result in samples which were not representative, and 
therefore erroneous. The commenter also stated that proposed paragraph 
(b)(4), pertaining to standards for mixing of samples, should instead 
prescribe compliance with API 8.3, which contains the appropriate 
standards. Another commenter stated that proposed Sec.  3174.8(a) did 
not mention an inline mixer or any pressure/temperature 
instrumentation, and asked if these items were prohibited or just not 
considered necessary. The same commenter stated that proposed Sec.  
3174.8(b)(2) discussed sample probe locations when standards for 
automatic sampling had not yet been incorporated into the rule, and 
requested that rather than restating portions of the standards in the 
rule, the BLM should incorporate API MPMS Chapters 8.2 and 8.3 into the 
rule.
    The BLM agrees with the points raised in these comments and so, in 
the interest of eliminating uncertainty and errors, the final rule 
includes industry

[[Page 81484]]

standards for automatic sampling systems and for mixing of samples. The 
final rule now includes a requirement that sampling and mixing of 
samples must comply with the standards in API 8.2 and API 8.3, 
respectively.
    One commenter stated that the requirement in proposed Sec.  
3174.8(a)(10) and (b)(13) to have a back pressure valve and check valve 
downstream of the LACT could be met by allowing operators to use 
another common industry practice of placing a pump downstream. The BLM 
agrees that this arrangement would meet the intent of the requirement, 
which is to ensure single-phase flow through the meter, and has changed 
the rule accordingly. The revised requirement is more flexible and is 
found in the renumbered final rule at Sec.  3174.8(a)(3).
    One commenter noted that in proposed Sec.  3174.8(a)(7), the BLM 
limited LACTs to only using a PD meter, and said that any type of meter 
permitted in API standards should be allowed. These standards include 
PD, Coriolis, and turbine meters. The BLM partly agrees and has changed 
the rule to allow Coriolis meters because field and laboratory testing 
have proven the Coriolis meter to be reliable and accurate. However, 
the BLM does not agree that turbine meters should be allowed. In the 
BLM's experience, confirmed by many industry sources, turbine 
flowmeters are less accurate and are more subject to wear or damage. As 
a result, the BLM will continue to prohibit the use of turbine meters 
in LACTs. The change to allow Coriolis meters in LACTs is reflected in 
Sec.  3174.8(a)(1) of the final rule. References to the definition of, 
proving standards for, and other specific requirements for Coriolis 
meters are contained throughout the rule in appropriate sections.
    Section 3174.8(b) describes the system operating requirements for 
LACTs. Multiple comments were received on this section, many of which 
focused on making the requirements less prescriptive and instead 
referencing API standards more extensively.
    In general, in response to numerous comments that the proposed rule 
lacked flexibility, we have removed most of the prescriptive 
requirements in proposed Sec.  3174.8(b). This section now requires 
operators to follow the sampling-process standards in API 8.2 and API 
8.3 (the equipment and procedures to obtain and properly mix a 
representative sample); the standards for measuring the gravity 
(density) and S&W content of those samples in API 9.1, API 9.2, API 
9.3, and API 10.4; the standards for flow measurement using electronic 
meter systems in API 21.2; the standards for temperature determination 
in API 7; and the standards for calculating net oil volumes for each 
run ticket in API 12.2.1 and API 12.2.2. All of these API standards are 
incorporated by reference and listed in Sec.  3174.3.
    One commenter objected to the BLM's requirement in proposed Sec.  
3174.8(b)(1) that LACTs include an electrically driven pump sized to 
ensure: (1) A discharge pressure compatible with the meter used; and, 
(2) That the flow in the LACT main stream piping is turbulent, such 
that the measurement uncertainty levels proposed in Sec.  3174.3 are 
met. Instead, the commenter suggests that the BLM should require LACTs 
to meet uncertainty requirements without being so prescriptive. Another 
commenter stated that the BLM should be more flexible about the types 
of S&W monitors that would be allowed under proposed Sec.  3174.8(b)(7) 
because some manufacturers do not make the types of plastic-coated 
probes that this section required. The commenter also suggested that 
existing S&W monitoring technologies should be grandfathered. Several 
other commenters stated that the requirement for a back pressure valve 
in proposed Sec.  3174.8(b)(13) was too prescriptive and did not give 
operators the flexibility to use other methods to achieve the same 
result that back pressure valves provide--maintaining single-phase 
(oil-only) flow through the LACT meter. As discussed earlier, the BLM 
is keeping the requirement that LACT systems contain a back-pressure 
valve in the final rule at Sec.  3174.8(a)(3), but we agree with 
commenters that the requirement needs to be more flexible, and we have 
added language that gives operators the option of using other 
controllable means of applying back pressure to ensure single-phase 
flow. Also in response to these comments, the BLM removed most of the 
prescriptive requirements in proposed Sec.  3174.8(b) and replaced them 
with a requirement that operators meet the LACT system operating 
standards outlined in the applicable API standard incorporated by 
reference into the proposed rule. The only requirements that are 
spelled out in paragraph (b) are those requirements that are in 
addition to or different from standard API practices or that clarify 
which API standards are applicable.
    Several commenters expressed concern that retrofitting or replacing 
existing equipment to meet the requirements of Sec.  3174.8 was 
unnecessary and prohibitively expensive, and that existing facilities 
should be grandfathered, with some also suggesting that bringing 
existing facilities into compliance within the proposed 180-day 
implementation timeframe was either too expensive, impossible, or both. 
In response to these comments, the BLM has clarified in Sec.  3174.2 in 
the final rule that all equipment must comply with the new 
requirements, with operators required to come into compliance on a 
staggered schedule of between 1 and 4 years, depending on when they 
receive their FMP approvals, which is based on their production levels. 
This significantly extends the compliance timeframe and gives operators 
time to budget and plan for any required changes, while limiting the 
chances that there will be local or national shortages of equipment or 
technical expertise, such as might have resulted from the proposed 180-
day implementation period.
    One commenter stated that proposed Sec.  3174.8(b) should be 
revised to include a densitometer as optional equipment in the list of 
components, and that if density is provided, recordable, auditable, and 
verifiable, then the sampler and sample pot should not be required, 
which would save operators the cost of those components and lab 
analyses to determine S&W content. The commenter further said that if 
the sampler is not included in the list of components, then S&W content 
must be reported as zero percent, and the entire volume passing through 
the LACT meter would be reported as 100 percent oil. The BLM 
understands that there may be cases in which the operator would be 
willing to consider the entire produced stream as 100 percent oil, but 
the BLM believes that omitting the sampler and sample pot would create 
the potential for added confusion, and it is likely that most 
purchasers are going to require a sample grind-out anyway. For these 
reasons, no change was made to the rule as a result of this comment.
    One commenter pointed out that proposed Sec.  3174.8(b)(11)(ii), 
which required a temperature averaging device to take a temperature 
reading at least once per barrel, did not accord with API 21.2, 
Subsection 9.2.8.1, which requires such devices to be flow proportional 
and take a reading at least once every 5 seconds. The BLM agrees and 
has changed the rule accordingly. This provision in the final rule has 
been renumbered as Sec.  3174.8(b)(6)(ii) and now reads: ``The 
electronic temperature averaging device must be volume-weighted and 
take a temperature reading following API 21.2, Subsection 9.2.8 
(incorporated by reference, see Sec.  3174.3).''

[[Page 81485]]

Sections 3174.9 and 3174.10 Coriolis Measurement Systems
    Sections 3174.9 and 3174.10 pertain to CMS, which are not addressed 
in Order 4. Order 4 allows only for the use of PD meters with LACT 
systems. 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 Sec.  3174.4. 
Field and laboratory testing of Coriolis meters has proven them to be 
reliable and accurate meters when installed, configured, and operated 
correctly.
    One commenter said the final rule should allow operators to use 
truck-mounted CMS and submitted summarized data to support their view. 
The summarized data indicates significant differences between manual-
gauged volumes and truck-mounted Coriolis-metered volumes. A summary of 
these volume differences indicated that the truck-mounted Coriolis 
meter measured as much as 22.44 bbl less that the manual gauge 
measured. Missing from the data is the volume of the entire load. The 
BLM needs this information to understand how significant these 
variations are. The data also indicates significant differences in 
measured oil temperature (as much as 23 [deg]F) and gravity (as much as 
5 degrees) when compared to manual methods. The commenter did not 
explain these differences or explain or justify the data submitted. The 
BLM decided not to include the use of truck-mounted Coriolis metering 
in the final rule. Operators may seek approval to use the truck-mounted 
option through the PMT approval process, which is outlined in Sec.  
3174.13. The rule was not changed based on this comment.
    Another commenter suggested that the CMS could be used for gas 
measurement, in addition to oil measurement. The BLM has noted this 
comment; however, this subpart is dedicated to the measurement of oil. 
The rulemaking that is replacing Order 5 is a more appropriate venue 
for considering this comment, and this comment was directed to that 
rule team. The comment did not result in a change to this rule.
    Several commenters stated that the term ``CMS'' should not be used 
for a Coriolis LACT as it is simply a LACT. The BLM agrees with this 
comment and has no intention of replacing the term ``LACT'' with the 
term ``CMS.'' The rule as proposed was intended to allow the Coriolis 
meter to be used in a LACT as an alternative to the PD meter, or as a 
standalone meter independent of a LACT system. The term CMS refers only 
to the latter option. To clarify this issue, the final rule has been 
edited to state that a Coriolis meter may be used in a LACT or as a 
standalone CMS meter.
    Section 3174.9(b) specifies that Coriolis meters that have been 
reviewed by the PMT, approved by the BLM, and identified and described 
on the nationwide approval list at the BLM Web site (www.blm.gov) are 
approved for use. Initially, the BLM will have no Coriolis meter make 
or model limitations on the approved list, but starting 2 years after 
the effective date of the rule, operators will only be able to use the 
Coriolis meter makes and models that the BLM approves for use and lists 
on its Web site. To ensure that specific Coriolis meters in use at that 
time meet with BLM approval, the BLM encourages operators, 
manufacturers, or other entities (e.g., trade associations) to pursue 
equipment approval outlined in Sec.  3174.2(g) prior to use. 
Installations meeting the requirements described in this section and 
Sec.  3174.10 do not require additional BLM approval. CMS proving must 
meet the proving requirements described in Sec.  3174.11 and 
measurement tickets would be required, as described in Sec.  
3174.12(b).
    One commenter said requiring each operator to have its CMS approved 
would result in a large financial burden. The BLM disagrees because the 
PMT only needs to approve a particular make or model of Coriolis meters 
once. Once a meter make or model has been reviewed, approved, and 
posted on the BLM's Web site, the meter can be installed at any 
facility, subject to any COAs imposed by the PMT for its use. Existing 
installations that already meet the requirements in Sec. Sec.  3174.9 
and 3174.10 do not require additional BLM approval.\13\
---------------------------------------------------------------------------

    \13\ Additional comments on the PMT and the procedure that the 
PMT will use to approve devices are addressed in the discussion of 
Sec.  3174.13.
---------------------------------------------------------------------------

    Section 3174.9(c) requires that a CMS be proved following the 
frequency established under Sec.  3174.11. This proving frequency will 
ensure that operators periodically prove the CMS to provide 
verification that the meter is within the allowable tolerances. There 
were no comments on this section.
    Section 3174.9(d) requires that measurement (run) tickets be 
completed as required by Sec.  3174.12(b). This establishes the 
measurement-ticket time periods and minimum requirements for 
information that must be included on the tickets. There were no 
comments on this section.
    Section 3174.9(e) identifies the applicable API standards for the 
components that must be installed with a CMS at an FMP, and includes 
some additional requirements that operators using a CMS for oil 
measurement must follow. The proposed rule listed the components in 
exact order from upstream to downstream of a CMS. The BLM has opted to 
be less prescriptive in the final rule and is requiring operators to 
follow API 5.6 for the setup and installation of a CMS system.
    One of the prescriptive requirements in proposed Sec.  3174.9(e)(7) 
was for operators to install a density measurement verification point. 
One commenter asked that this term be defined. Since the BLM has 
removed the prescriptive requirements and this particular term from the 
rule, a definition is no longer needed. No change resulted from this 
comment.
    Another commenter said the BLM needs to allow for a connection 
point for a pycnometer. As discussed earlier, the BLM has removed the 
prescriptive, step-by-step requirements in this section. Should an 
operator wish to use this density-determination option, API 5.6 does 
allow for a density verification point that could be used as the point 
for installing the pycnometer. There was no change to the rule as a 
result of this comment.
    Section 3174.9(e)(1) and (2) sets accuracy thresholds for 
temperature and pressure measurement devices that are part of a CMS. 
These devices are required to calculate the CPL and CTL correction 
factors. The uncertainties of these devices will be used in the overall 
uncertainty calculation to ensure that the CMS meets or exceeds the 
uncertainty levels required by Sec.  3174.4. There were no comments on 
this section.
    Section 3174.9(e)(3) covers the options for handling S&W content 
when determining net volume. Measurement by LACT requires a composite 
sampling system and determines net oil volume by deducting S&W content. 
The CMS does not require a composite sampling system, but rather leaves 
the option to the operator to either install a composite sampling 
system to determine S&W content for deduction in net oil determination 
or to make no S&W content deduction in net oil determination. 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 ability to determine S&W content. Without the ability to accurately 
determine S&W content, Sec.  3174.9(e)(3) will require operators to 
report the S&W content as zero. The BLM may consider options to use 
other

[[Page 81486]]

methods to determine S&W content should acceptable technology or 
processes be proposed in the future. However, the BLM will only approve 
an alternate method of S&W content determination if the resulting 
overall measurement uncertainty is within the limits of Sec.  
3174.4(a).
    Several commenters stated that if the rule does not allow 
corrections for S&W content, operators will be required to report an 
inaccurate volume. The BLM agrees that failing to correct for S&W 
content could result in an inaccurate measurement of net volume of 
product sold. However, this rule gives the operator the option to 
determine S&W content; if the operator chooses not to install the 
necessary equipment to determine the accurate S&W content, then no 
deduction will be allowed. The inclusion of the CMS as a method to 
measure production does not make this the sole means of measurement. It 
will be at the discretion of the operator to determine which method of 
measurement is most effective for their operation. In certain 
operations where a composite sampling system cannot be installed, and 
the operator determines reporting S&W content as zero is inappropriate 
for their operation, other measurement options may be available, though 
the operator will have to seek review through the PMT. No change to the 
rule resulted from these comments.
    Relatedly, several commenters stated that the BLM should allow 
other methods to determine S&W content. The BLM agrees that other 
methods could be allowed, but the BLM does not currently have the data 
to review those options. As noted, under the final rule, an operator 
wishing to use a different option for determining S&W content will have 
to seek approval through the PMT process, as outlined in Sec.  3174.13. 
No change resulted from this comment.
    Section 3174.9(e)(4) requires single-phase flow through the CMS by 
means of applied back pressure. The proposed rule would have required 
operators to use a back pressure valve downstream of the Coriolis meter 
to achieve single-phase flow. Several commenters stated that there are 
other means of applying back pressure that are just as effective as 
using a back pressure valve, such as pumps downstream of the CMS. The 
BLM agrees and has changed the rule as a result of this comment. 
Instead of allowing only a back pressure valve, the BLM will allow the 
operator to use any means to apply sufficient back pressure to ensure 
single phase flow, so long as the approach meets the requirements of 
API 5.6.
    Section 3174.9(f) allows the API oil gravity to be determined by 
using one of two methods: (1) From a sample taken from a composite 
sample container; or (2) Directly from the average density measured by 
the Coriolis meter. This choice accommodates situations in which it is 
not feasible or an operator chooses to not install a composite sampling 
system due to economic or operating constraints. The BLM may consider 
other methods for determining the API gravity of the fluid, such as in-
line densitometer devices. However, the BLM will only approve 
alternative methods if resulting overall uncertainty is within the 
limits in Sec.  3174.4.
    One commenter suggested that the BLM should incorporate by 
reference the guidelines in API 8.2 and API 8.3 on composite sampling. 
Because a sample from a composite sample container is an acceptable 
method for determining the API oil gravity, the BLM agrees that the 
industry standard should be included and has incorporated API 8.2 for 
automatic sampling and API 8.3 for mixing and handling of samples into 
Sec.  3174.8(b)(1) of the final rule.
    Another commenter stated that the use of Tables 5A and 6A is 
inappropriate and that the flowing density should be corrected in 
accordance with API 11.1. The BLM agrees that Tables 5A and 6A are 
outdated and should not be used and has removed the language that 
referenced Tables 5A and 6A and replaced it with a reference to API 
11.1.
    Another commenter stated that abnormal events should be excluded 
from the average density calculation. The BLM assumes the commenter is 
referring to the fact that water, sand, or gas breakout may occur 
during a normal flowing regime. Excluding these abnormal events from 
the average density is allowed under the final rule, so long as an 
audit trail is maintained showing the full-flow density, including the 
period of flow that has been removed from the average density 
calculation. There is no change to the final rule as a result of this 
comment.
    Another commenter said that during proving, a density correction 
factor should be applied if the densitometer within the Coriolis meter 
varies from a master densitometer at the density verification point. 
The BLM disagrees with this comment. During the proving verification of 
the densitometer within the Coriolis meter, the density reading is 
compared to an independent density measurement. The difference between 
the indicated density determined from the Coriolis meter and the 
independently determined density must be within the specified density 
reference accuracy specification of the Coriolis meter. If the Coriolis 
densitometer exceeds the manufacturer's specification density 
tolerance, then the meter must be repaired or replaced, or an 
alternative method of density determination must be approved for use. 
Any alternative method must result in an overall uncertainty that is 
within the limits in Sec.  3174.4.
    Section 3174.9(g) requires that the net standard volume be 
calculated following API 12.2.1 and API 12.2.2. The proposed rule 
listed this requirement in Sec.  3174.10(g) and gave very prescriptive 
requirements for the calculation. However, in order to make the final 
rule less prescriptive and to rely on industry standards wherever 
possible and appropriate, the requirement has been moved to Sec.  
3174.9(g), and the prescriptive language has been removed in favor of 
the guidelines listed in API 12.2.1 and API 12.2.2.
    Several commenters said that net standard volume cannot be 
calculated by current Coriolis meters or any flow meter for that 
matter. The BLM agrees with these comments and for that reason there 
are no requirements in this rule that the CMS, or any meter, calculate 
and display net standard volume. No change was made to the rule as a 
result of these comments.
    Another commenter stated that operators should be allowed to apply 
a shrinkage factor to the net standard volume. The BLM disagrees 
because past experience in reviewing net oil determinations shows that 
applying a calculated shrinkage factor results in very high uncertainty 
for the metering systems. The resulting overall uncertainty would 
exceed the limits of Sec.  3174.4. Should new methods or technology for 
applying shrinkage factors be developed and proposed for use in the 
future, the PMT process described in Sec.  3174.13 would be used for 
review and approval of those methods or technologies. No change to the 
final rule has been made as a result of this comment.
Sec.  3174.10 Coriolis Meter for LACT and CMS Measurement 
Applications--Operating Requirements
    Section 3174.10(a) establishes the 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 applies to CMSs. The BLM did not receive 
comments on this section.
    Section 3174.10(b) establishes the minimum standards and 
specifications

[[Page 81487]]

for specific makes, models, and sizes of Coriolis meters. The 
specifications will allow the BLM to determine the overall measurement 
uncertainty of the CMS, to ensure that it meets the requirements of 
Sec.  3174.4, and to help insure that the meters are properly 
installed.
    One commenter recommended that the BLM remove the requirement for 
maintaining and submitting to the BLM upon request the Coriolis meter 
specifications found in Sec.  3174.10(b). The commenter said this 
requirement is not necessary for uncertainty-based measurement limits. 
The BLM disagrees. In order for the BLM to conduct a complete 
inspection of the CMS, it is necessary that all information required by 
this section be available to ensure that the Coriolis meter is 
operating within its design parameters, on which the uncertainty for 
the meter is based. No change in the final rule was made as a result of 
this comment.
    Proposed Sec.  3174.10(b)(iv) required that the minimum amounts of 
straight piping be installed upstream and downstream of the meter. 
Several commenters said that Coriolis meters do not require any 
specific amount of straight piping. The BLM agrees that pipe-length 
restrictions in Coriolis meter installations do not affect accurate 
measurement and has removed any reference to straight-pipe requirements 
for Coriolis meters from the rule.
    Section 3174.10(c) requires a non-resettable totalizer for 
indicated volume. This is to allow verification over multiple run 
tickets of gross production prior to any adjustments to net standard 
volume. There were no comments on this requirement.
    Proposed Sec.  3174.10(c) had a requirement for meter orientation. 
One commenter said the BLM should remove this requirement because it is 
too prescriptive and should instead require operators to follow API 
standards. The BLM agrees that the proposed language was too 
prescriptive. The final rule, in Sec.  3174.10(e), now requires 
operators to follow API 5.6.
    Section 3174.10(d) of the proposed rule required that 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. One commenter suggested 
that 24 hours is an unreasonably short period of time for this 
requirement, especially if the applicable changes occur on a weekend. 
The commenter recommended a period of at least 10 days, or a monthly 
report from the PLC log. After consideration of this proposed 
requirement, the submitted comment, and the proving requirements in the 
final rule, the BLM has decided to remove this notification requirement 
from the rule because any changes to a Coriolis meter internal 
calibration factor will require immediate proving of the meter as 
required in Sec.  3174.11(d)(8). An additional notification provides no 
benefit to the BLM.
    Section 3174.10(d) (paragraph (f) in the proposed rule) requires 
verification of the meter zero reading before proving the meter or any 
time the AO requests it. The proposed rule described the process for 
verifying the meter zero value. The BLM has changed the wording in the 
final rule to be less prescriptive and to require the operator to 
follow manufacturer guidelines. This gives the operator flexibility 
during the verification procedure.
    Several commenters said that requiring flow to be stopped during 
meter verification is an additional step and may disrupt normal 
operations. The BLM agrees that in order to verify that the meter is 
operating within the manufacturers' specifications, operators are 
required to verify the meter zero with no fluid flow. However, the BLM 
disagrees that meter zero verification is a disruption to normal 
operations. According to API standards and manufacturer 
recommendations, Coriolis meter zero verification is a part of normal 
operations. As discussed above, the final rule has been changed to 
require operators to follow manufacturer guidelines for meter zero 
verification; however, the requirement to verify meter zero remains in 
the final rule.
    Section 3174.10(e)(1) through (e)(4) (paragraphs (i)(1) through 
(i)(4) in the proposed rule) lists the information that the Coriolis 
meter must display onsite. As part of the BLM's verification process 
during field inspections, the AO must be able to access this 
information without the use of a laptop or other special equipment. A 
log must be maintained of all meter factors, zero verifications, and 
zero adjustments, and must be made available to the AO upon request. 
The proposed rule would have required operators to maintain the log 
onsite.
    The BLM received several comments stating that the requirement for 
a log to be maintained onsite containing the meter factor, zero 
verification, and zero adjustments is not practical. Because this 
information will not need to be readily available onsite for the AO to 
complete an inspection, the BLM agrees with the commenters and has 
changed the final rule in Sec.  3174.10(e)(4) to require that the log 
containing the meter factor, zero verification, and zero adjustments 
must be made available upon request.
    One commenter stated that the requirement in paragraph (e)(2) for 
the meter to display the instantaneous pressure has no valid use. The 
BLM disagrees with this statement as this information is needed as part 
of routine inspections conducted by the AO to verify the flowing volume 
in a meter. No changes were made as a result of this comment. Another 
commenter said that some Coriolis meters do not have the ability to 
display the density in pounds per barrel as originally required by the 
proposed rule. After contacting Coriolis system manufacturers, the BLM 
has confirmed that not all Coriolis meters have the ability to display 
this particular unit of measurement. Therefore, as a result of this 
comment, the requirement to display the density in pounds per barrel 
has been removed and other units of measurement (pounds per gallon or 
degrees API) have been added in Sec.  3174.10(e)(2)(i). One commenter 
said that daily volume totals may not be available for display. The BLM 
contacted manufacturers and confirmed that Coriolis meters are capable 
of displaying daily volume totals. As a result, there was no change in 
the final rule from this comment.
    Section 3174.10(f) requires that audit trail information listed in 
Sec.  3174.10(f)(1) through (4) be retained for the time period 
required in Sec.  3170.7, which is part of the rulemaking to replace 
Order 3. One commenter said that the requirements in Sec.  
3174.10(f)(2) and (4) may force operators to add a flow computer to a 
Coriolis LACT, which exceed the requirements of a PD LACT. This comment 
does not make sense because a Coriolis meter almost always has a flow 
computer. If an operator chooses to configure a Coriolis meter in a 
LACT without utilizing a flow computer, and display only a totalizer 
reading, then the requirements of Sec.  3174.10(f)(2) and (4) would not 
apply. No change resulted from this comment.
    Section 3174.10(g) requires that each Coriolis meter have an 
operable backup power supply or nonvolatile memory capable of retaining 
all data. This is to ensure that during a failure, all audit trail data 
is preserved to maintain compliance with these regulations. There were 
no comments on this section.
Section 3174.11 Meter-Proving Requirements
    Proposed Sec.  3174.11(a) and (b) would have established that a 
meter would not be eligible to be used for royalty determination unless 
it is proven to the

[[Page 81488]]

standards detailed in the proposed rule. The BLM received no comments 
on these paragraphs. The final rule specifies the minimum requirements 
for conducting volumetric meter proving for all FMP meters. Paragraph 
(a) in the proposed rule was carried forward to the final.
    A table in proposed paragraph (b) referred readers to the 
applicable paragraphs of this proposed section that contained the 
minimum standards for proving FMP meters. The BLM received no comments 
on this table. Nevertheless, the BLM did not include the paragraph (b) 
table in the final rule because the table did not provide substantive 
clarity or expedite reader access to the relevant paragraphs. This 
change resulted in the re-lettering of all subsequent section 
paragraphs in the final rule.
    Paragraph (c) in proposed Sec.  3174.11 (re-lettered to paragraph 
(b) in the final rule), established the acceptable types of meter 
provers that can be used to prove an FMP LACT or CMS. The BLM received 
a few comments objecting to the meter-proving requirements in this 
section of the final rule because they are not consistent with the 
referenced API specifications. These comments are addressed in the 
following text.
    Section 3174.11(b)(1) through (3) of the final rule describe and 
detail the requirements for acceptable meter provers, which include the 
master meters and displacement provers that are currently allowed under 
Order 4. Coriolis master meters, which were not addressed in Order 4, 
have been included in the final rule. The BLM believes that Coriolis 
technology has advanced to the point where Coriolis meters meet the 
accuracy and verifiability requirements required for master meters. The 
final rule does 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 use on viscous liquids, which include most 
crude oils. Because there are few tank provers currently in use on 
Federal and Indian leases, this requirement will not result in a 
significant cost to industry. One commenter on paragraph (b)(1) stated 
that the BLM requirement for master meter repeatability of 0.0002 (0.02 
percent) is inconsistent with API 4.5, which requires a repeatability 
of 0.0005 (0.05 percent). The BLM agrees with the commenter and made a 
change to the final rule consistent with the comment. The BLM believes 
that the paragraph (b)(1) repeatability requirement for master meter 
provers in the proposed rule was too restrictive and the API 4.8 (as 
referenced in API 4.5) specification of 0.0005 (0.05 percent) 
repeatability is within the uncertainty (0.027 percent) of 
BLM requirements.
    The BLM also made a change to the final rule based on a comment 
that the calibration of the master meter prover in the proposed rule 
was too frequent. The proposed rule required master meter provers to be 
calibrated no less frequently than once every 90 days. The BLM agrees 
that the 90-day frequency for proving master meters may be too 
frequent. The final rule changes the master meter calibration frequency 
to no less than once every 12 months, which is consistent with API 4.8, 
Subsection 10.2, which is referenced in API 4.5.
    One comment on paragraph (b)(2) of this section said the BLM 
displacement prover calibration requirements contradict API Chapter 
4.9. The BLM disagrees with the commenter since API 4.9 addresses 
calibration methods for displacement provers and not calibration 
frequency for displacement provers as specified in API 4.8. The BLM 
changed paragraph (b)(2) in the final rule by removing the prescriptive 
language found in paragraphs (b)(2)(i) and (ii) in the proposed rule, 
and by incorporating calibration frequency requirements of API 4.8, 
Subsection 10.
    Section 3174.11(b)(3) of the final rule (Sec.  3174.11(c)(3) of the 
proposed rule) requires the base prover volume of a displacement prover 
must be calculated under API 12.2.4. The BLM received no comments and 
made no changes to this requirement.
    Section 3174.11(b)(4) (paragraph (c)(4) in the proposed rule) 
establishes displacement prover sizing standards. These standards 
ensure that fluid velocity within the prover is within the limits 
recommended by API 4.2, Subsection 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. One commenter recommended replacing the proposed prover design 
language that referenced API 4.2 with language that references 
operating provers within design parameters set forth by the 
manufacturer and by API 4.8 and API 4.9.2. The BLM disagrees with the 
commenter that paragraph (b)(4) should reference API 4.8 and API 4.9.2 
since these standards deal with prover operation and are not relevant 
to paragraph(b)(4) design standards. Paragraph (b)(4) is specific to 
displacement prover design, which is covered under API 4.2. The BLM did 
not change the final rule in response to this comment.
    Section 3174.11(c) (paragraph (d) in the proposed rule) establishes 
the requirements for meter proving runs with respect to proving both 
the FMP LACT and CMS and the conditions required for proving these 
meter systems. The BLM received many comments objecting to certain 
requirements in proposed Sec.  3174.11(d) that deal with meter proving 
runs. The BLM responds to these comments as follows.
    Section 3174.11(c)(1) (paragraph (d)(1) in the proposed rule) 
expands on the current Order 4 requirement to prove a meter under 
``normal'' operating conditions. This section defines limits of flow 
rate, pressure, temperature, and API oil gravity that must exist during 
the proving to be considered ``normal'' operating condition. The BLM 
added this requirement because it realized 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 
paragraph also requires a multi-point meter proving if the LACT or CMS 
is subject to highly variable conditions. The multi-point meter proving 
establishes a minimum of 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 will then be applied according to Sec.  
3174.11(c)(6).
    One commenter noted that paragraph (c)(1) (paragraph (d)(1) in the 
proposed rule) lacks specifics on what normal operating temperature 
conditions mean and another commenter said the language should be 
changed to reflect situations where normal operating conditions vary, 
such as at multi-metering sites, and suggested a language change to 
``average for the batch period.'' The BLM agrees with the commenter 
that normal operating conditions, as they apply to oil temperature, 
were not adequately addressed in the proposed rule and that in some 
instances it may be difficult to identify the ``normal operating 
conditions'' of flowrate, pressure, temperature, and fluid density. The 
BLM added paragraph (c)(1)(iii) to the final rule to address normal oil 
operating temperature limits, which must be within 10 [deg]F of the 
normal operating temperature. With this addition, paragraphs 
(d)(1)(iii) and (d)(1)(iv) in the proposed rule have been renumbered to 
paragraphs (c)(1)(iv) and (c)(1)(v) in the final rule.

[[Page 81489]]

    The BLM made no change to the final rule regarding normal operating 
conditions to reflect variable metering conditions since this situation 
may be specific to regions and areas of the country and can be more 
adequately addressed by the specific BLM field office through the 
variance request process as outlined in Sec.  3170.6, which has been 
established as part of the rulemaking to replace Order 3.
    Section 3174.11 paragraphs (c)(2) through (c)(5) (paragraphs (d)(2) 
through (d)(5) in the proposed rule) 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 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 will be the 
arithmetic average of the five meter factors or average pulses from the 
five consecutive proving runs. This section also requires the meter 
factors to be calculated following the sequence described in API 
12.2.3. We received two comments on paragraph (c)(2) of this section. 
One commenter addressed the requirement that, during proving runs, 
there be a sufficient volume to generate at least 10,000 pulses from 
the FMP meter that is being proved. The commenter did not believe that 
the 10,000-pulse requirement is reasonable and said it would disallow 
the use of small-volume provers (SVPs). The BLM disagrees with the 
commenter on both points. The 10,000-pulse-per-proving-run resolution 
in the rule follows the API standard and the rule specifically allows 
small-volume provers as long as they meet the additional requirements 
in paragraph (c)(2). The BLM did not change the final rule in response 
to this comment. However, the BLM believes that it is appropriate to 
add clarifying language to paragraph (c)(2) in the final rule that 
reminds readers of the 10,000-pulse requirement in API 4.2, Subsection 
4.3.2. Another commenter asked why the proposed rule did not 
specifically address SVPs. SVPs come under the requirements for 
displacement provers and, under paragraph (c)(2), are required to use 
pulse interpolation as outlined in API 4.6, since their volume 
generates less than 10,000 meter pulses per proving run. The BLM did 
not change the final rule due to this comment.
    Two commenters on paragraph (c)(3) objected to the requirement that 
the five consecutive meter-proving runs have a repeatability of 0.0005 
(0.05 percent), saying that three proving runs could accomplish the 
same uncertainty. The BLM disagrees with these commenters and has 
decided to retain Order 4's requirement of a minimum of five proving 
runs. The BLM believes that this requirement achieves the desired 
consistency and uncertainty levels. The BLM made no change to the final 
rule due to these comments.
    One commenter on paragraph (c)(4) recommended that the BLM adopt 
the use of an average meter factor as determined from API 12.2.3. Upon 
review of this comment, the BLM agrees with the commenter that guidance 
on the calculation of the average meter factor is appropriate. Due to 
this comment, the BLM changed the final rule to incorporate API 12.2.3, 
Subsection 9 for purposes of calculating the average meter factor.
    Section 3174.11(c)(5) of the final rule (Sec.  3174.11(d)(5) of the 
proposed rule) requires that meter factor computations must follow the 
sequence described in API 12.2.3. The BLM received no comments and made 
no changes to this requirement.
    Section 3174.11(c)(6) (paragraph (d)(6) in the proposed rule) gives 
operators two methods for determining the multiple meter factors that 
are required under Sec.  3174.11(c)(1)(v). The first method is to 
combine the meter factors into a single arithmetic average. The second 
method is to curve-fit the meter factors and incorporate a real-time 
dynamic meter factor into the flow computer (this will apply primarily 
to CMS). Neither multi-point provings nor multi-point meter factors are 
discussed in Order 4. One commenter indicated that averaging meter 
factors was only valid in regions where impacts of nonlinearities are 
minimal and recommended deleting Sec.  3174.11(c)(6)(i). The BLM 
conducted further research into this comment and agrees with the 
commenter that averaging meter factors is only valid under certain 
conditions. Additional language pertaining to how to use the multiple 
meter factors is added to the final rule in paragraph (c)(6). This 
language will only permit the use of averaging meter factors if all 
meter factors in the range are within approximately 0.10 
percent of the average. It will also limit the use of the dynamic meter 
factor option to prevent any two neighboring meter factors that differ 
by more than approximately 0.2 percent from being used to derive a 
dynamic meter factor.
    Sections 3174.11(c)(7) and (c)(8) (paragraphs (d)(7) and (d)(8) in 
the proposed rule) set the minimum and maximum values that are 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. The BLM received no comments on 
paragraphs (c)(7) and (8).
    Section 3174.11(c)(9) (paragraph (d)(9) in the proposed rule) 
allows back pressure valve adjustment after proving only within the 
normal operating fluid flow rate and fluid pressure as prescribed in 
proposed Sec.  3174.11(c)(1). If the back pressure valve is adjusted 
after proving, the ``as left'' fluid flow rate and fluid pressure must 
be documented on the proving report. The BLM is requiring this 
documentation based on its field observations, which have shown this 
practice to affect the meter factor in certain areas of the country. 
Specifically, the BLM has observed that a change in back pressure 
outside the proving conditions can, in some cases, result in operators 
reporting incorrect volumes. Allowing back pressure valve adjustment 
after proving is not intended as a means to circumvent the displacement 
prover minimum and maximum velocity requirements in Sec.  3174.11(b)(4) 
of the final rule. Order 4 has no specific requirements relating to the 
adjustment of the back pressure valve after proving. The BLM received 
no comments on paragraph (c)(9).
    Section 3174.11(c)(10) (paragraph (d)(10) in the proposed rule) 
sets standards for the pressure used to calculate a CPL factor for a 
LACT's composite meter factor. It also prohibits 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 factor. The use of a composite meter 
factor is intended to make measurement tickets easier to complete 
because the CPL factor 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. One commenter 
stated that most Coriolis meters in the field do not have the 
capability to calculate a CPL factor and replacing them with a Coriolis 
meter that could calculate a CPL factor would be prohibitively costly. 
The BLM agrees with the commenter regarding the CPL factor capability 
currently available in existing Coriolis meters. However, the final 
rule does not require operators to have a Coriolis meter with this CPL 
factor feature. Therefore, the BLM made no change to the final rule as 
a result of this comment.

[[Page 81490]]

    Section 3174.11(d) (paragraph (e) in the proposed rule) establishes 
the minimum FMP meter-proving frequencies, and specifies certain events 
that will trigger additional meter provings. This section contains the 
meter-proving requirements that were previously located in the LACT 
section of Order 4 and consolidates in one place all of the meter-
proving requirements for both LACTs and CMSs.
    The BLM received many comments that objected to the provision in 
paragraph (d)(2) (paragraph (e)(2) of the proposed rule) that sets a 
threshold for when operators who run large volumes of oil through their 
meters must conduct additional FMP meter provings. The proposed rule 
would have required operators to prove their FMP meters each time the 
registered volume flowing through their meters increased by 50,000 bbl 
or quarterly, whichever occurred first. Currently under Order 4, 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.
    The BLM's rationale in the proposed rule for changing the proving 
threshold to 50,000 bbl/month was that it would have affected only 
about 5 percent of existing LACT systems nationwide, yet would have 
ensured that meter-factor changes would be corrected before large 
volumes of production were measured incorrectly, which could have an 
adverse impact on Federal or Indian royalty determinations.
    Many commenters objected to the proposed meter-proving-frequency 
threshold of 50,000 bbl/month. Most commenters said this new meter-
proving frequency would require them to perform excessive and costly 
meter provings in locations where the meters may not be easy to access, 
especially in bad weather. The BLM agrees that the 50,000 bbl/month 
threshold may be excessively costly and, after reviewing potential 
economic impacts, has decided to use a 75,000 bbl meter-proving 
frequency threshold in the final rule. This 75,000 bbl throughput 
threshold was determined by performing a statistical analysis to 
determine the volume at which the expected value of royalty under- or 
overpayment due to meter factors equals the $550 average cost of 
proving a meter. The royalty revenue impact depends not only on volumes 
but also on oil prices. The 50,000 bbl/month threshold in the proposed 
rule was determined when the U.S. Energy Information Administration's 
(EIA) 10-year West Texas Intermediate crude oil spot price was expected 
to average $95/bbl. Since then, the EIA's predicted 5-year average 
crude oil price has dropped significantly, to $67.58 per barrel. The 
BLM does not find the 50,000/bbl meter-proving threshold to be 
appropriate under this predicted lower oil-price environment.
    The BLM also revised the maximum and minimum proving frequencies 
for meter proving on higher-volume FMPs. Under Order 4, operators were 
required to prove their meters at least quarterly or, if total 
throughput exceeded 100,000 bbl/month, then they were required to prove 
monthly. In this final rule, operators must prove their meters every 3 
months (quarterly), or each time the registered volume flowing through 
the meter increases by 75,000 bbl, but no more frequently than monthly. 
For example, if a meter hits the 75,000 bbl threshold every 6 weeks, 
the operator must prove it every 6 weeks. If a meter has a 75,000 bbl 
throughput every 2 weeks, the operator must prove it once a month. The 
final rule was changed to include this new language.
    Two commenters on paragraph (d)(2) said meter-proving frequencies 
should be increased, based on a lower volume of throughput threshold, 
and another commenter said that frequent proving would increase 
accuracy. The BLM does not agree that the final rule should further 
increase the proving frequency beyond what was presented in the 
proposed rule. The comments lacked any substantive basis and did not 
justify how an increased proving frequency would result in increased 
accuracy or how the costs of those additional provings would be 
justified by any reduction in royalty risk. The BLM believes the 
proving frequency in the final rule is justified and results in the 
required accuracy. The BLM did not change the final rule in response to 
these comments.
    One commenter on paragraph (d)(6) of Sec.  3174.11 (paragraph 
(e)(6) of the proposed rule) said that requiring a meter proving due to 
a change in normal operating conditions was not practical and not 
needed. The BLM disagrees with this commenter and agrees with another 
commenter who, in his comment on paragraph (e), pointed out that 
temperature extremes in places like Alaska or North Dakota have a large 
impact on meter-factor change between different proving runs. Because a 
change in the normal operating conditions could significantly affect 
the meter factor, and therefore the accurate measurement of the oil 
volumes, the BLM made no change to the final rule due to this comment.
    Paragraph (d)(7) in Sec.  3174.11 (paragraph (e)(7) in the proposed 
rule) also expands the current Order 4 requirement that operators prove 
their meters after repair. The new requirements require proving any 
time the mechanical or electrical components of the meter have been 
changed, repaired, or removed. In addition to those circumstances, 
paragraph (d)(8) requires an operator to also prove its meter after 
internal calibration factors have been changed or reprogrammed. One 
commenter asked whether meters used in flowback operations are subject 
to the requirements in this section. Flowback meters are not required 
to comply with this rule's meter-proving requirements because flowback 
operations take place prior to the operator's receipt of an FMP 
approval under Sec.  3173.12, and more importantly meters used in these 
operations are not FMPs. The BLM did not change the final rule based on 
this comment.
    One commenter said that after initial meter installation, a period 
of 2 weeks should pass before the meter is proved. The commenter did 
not justify a 2-week delay. The BLM believes that a meter should be 
proved as soon as is reasonably possible. The BLM expects that meters 
will be proven immediately after installation. The BLM did not change 
the final rule based on this this comment.
    One commenter said that paragraph (d)(7) (paragraph (e)(7) in the 
proposed rule) is vague. The commenter specifically complained about 
language that required a meter proving after the mechanical or 
electrical components of the meter have been, among other things, 
``opened.'' The BLM agrees with the commenter and changed the final 
rule so that the paragraph, in its entirety, now requires a meter 
proving after ``the mechanical or electrical components of the meter 
have been changed, repaired, or removed'', and added (d)(8) to prove 
after ``internal calibration factors have been changed or 
reprogrammed.'' Another commenter questioned the need to reprove a 
meter each time its secondary element (transducer) or tertiary device 
is changed. The commenter contends that these elements have no direct 
effect on the meter performance. The BLM agrees with the commenter in 
part. An element can impact the accuracy of the measurement if it is 
not measuring temperature and pressure accurately. Changing out either 
of these elements would not require the meter to be reproved, but would 
require the new element(s) (transducers) to be verified upon their 
replacement as is required under Sec. Sec.  3174.11(f) and (g), and 
temperature and pressure transducer verification, respectively, during 
a

[[Page 81491]]

meter-proving operation. The BLM revised the final rule Sec.  
3174.11(f) and (g) to address the commenter's concern by making it 
clear that a change out of either one of these elements would not 
require the meter to be reproved, but would require the new element(s) 
(transducers) to be verified upon their replacement.
    Section 3174.11(e) (Sec.  3174.11(f) in the proposed rule) 
establishes what operators must do when there is excessive FMP meter 
factor deviation. This situation occurs when a meter factor, which is 
established in two successive provings, exceeds the allowable meter 
factor deviations. This section requires operators to take steps to 
bring the FMP meter back into compliance. It also requires operators to 
re-calculate the amount of production that was measured during the time 
period between these instances of excessive meter factor deviation. 
Paragraph (e) also requires operators to show the most recent meter 
factor and describe all subsequent repairs and adjustments on the 
proving reports that are required in paragraph (i) of this section.
    Section 3174.11(e) maintains the Order 4 requirements for excess 
meter factor deviation and the required actions if proving reflects a 
deviation in meter factor that exceeds 0.0025 between two 
successive meter provings.
    The BLM received comments objecting to the paragraph (e) 
requirement that the FMP meter be removed from service when found 
defective or when the meter factor is outside the proposed accuracy 
range. The comments raised the issue of temperature extremes, in places 
like Alaska or North Dakota, having a large impact on meter factor 
change from proving to proving, making it impossible for operators to 
meet the meter factor deviation requirement. The BLM agrees that 
changing temperatures do affect the proving meter factors. This 
situation could easily justify more frequent provings as the 
temperatures change, the commenter said. The BLM believes this issue is 
field office specific and is more appropriately addressed through the 
BLM's variance process, which is outlined in Sec.  3170.6, part of the 
rulemaking that is replacing Order 3.
    One commenter recommended changing the meter-factor deviation 
limits for meters from 0.0025 to 0.0050 
because, the commenter said, it is standard industry practice to 
consider volume measurements as accurate if the meter factor changes by 
plus or minus 0.0025 or less. It typically is not until the differences 
in the meter factors are between plus or minus 0.0025 and 0.0050 that a 
correction is applied. The BLM reviewed API 4.8 to verify the 
commenter's claims on meter-factor deviation limits that are the 
industry standard. API 4.8 states common practice for custody transfer 
applications is to accept new meter factors within the range of 0.10 
percent and 0.50 percent of the previous meter factor. The BLM did not 
accept this recommended change for several reasons: The commenter 
agrees it is standard industry practice to consider volume measurements 
as accurate if the meter factor changes by plus or minus 0.0025 or 
less, 0.0025 deviation between meter proving runs is 
currently the maximum deviation allowed under existing Order 4, 
proposed deviation falls within the acceptable deviation range 
recommended in API 4.8, and it will not increase current reporting 
requirements or add costs, but will ensure measurement accuracy. The 
BLM made no changes to the final rule based on these comments.
    Section 3174.11(f) (paragraph (g) in proposed rule) establishes 
standards for the verification procedure and the test equipment used in 
the temperature transducer verification. It states the limit threshold 
value required by the verifying sources as they pertain to the normal 
operating temperature of the tested fluid. It also requires that the 
temperature transducer and devices used as part of a LACT or CMS be 
verified as part of every proving.
    The BLM received quite a few comments objecting to the new 
requirement that operators verify the temperature transducers during 
the meter-proving process. One commenter said that the proposed rule's 
meter-proving frequencies would result in excessive and costly 
transducer verifications if the temperature transducers had to be 
verified during each meter proving, since the proposed rule would have 
required operators to prove their meters each time they measured 50,000 
bbl of oil, or quarterly, whichever occurred first. The BLM believes 
that this concern is no longer valid. Section 3174.11(d)(2) in the 
final rule has been revised and now requires operators to prove their 
meters every 3 months (quarterly), or each time the registered volume 
flowing through the meter increases by 75,000 bbl, but no more 
frequently than monthly. These changes reduced the burdens associated 
with the proving requirements in the proposed rule. Therefore, the BLM 
did not change the final rule in response to this comment.
    One commenter objected to the requirement that operators use an 
insulated water bath in the field to perform the temperature transducer 
verification process, stating that this type of process belongs in a 
laboratory-type environment and not in a field environment. The BLM 
disagrees with this commenter since an insulated water bath is a 
common, acceptable method of verification. The rule also states the 
transducer may be verified by utilizing a test thermometer well located 
within 12 inches of the probe of the temperature transducer. The BLM 
did not change the final rule in response to this comment.
    One commenter said that requiring operators to verify the 
temperature transducer as part of a LACT or CMS proving may require 
operators to acquire additional equipment and incur costs. The BLM 
agrees with the commenter that verifying the transducer will require an 
additional piece of equipment and potentially an initial cost to 
acquire test equipment, but believes third-party proving contractors 
already own such equipment. Moreover, the BLM believes routine 
transducer verification is vital to assure proper performance and to 
obtain an accurate liquid temperature for use in correcting for the 
thermal effects on the liquid, ensuring accurate oil measurement, and 
royalty determination. As a result, the BLM made no change to the final 
rule in response to this comment.
    Another commenter said the requirement for verification of 
temperature averaging devices in Sec.  3174.11(f) of the proposed rule 
conflicts with requirements in Sec.  3174.6(b)(2) for temperature 
resolution and accuracy. The commenter did not say how this requirement 
conflicts. The BLM disagrees that there is a conflict because the 
temperature accuracy required for temperature verification is 0.5 
[deg]F, which is consistent with temperature accuracies presented in 
other sections of the final rule and with manufacturer's 
recommendations. For example, the temperature display minimum 
graduation must be to the 0.1 [deg]F, as required in Sec.  
3174.8(b)(5)(iv), which means there is no practical difficulty in 
assessing compliance with the verification limits. The BLM made no 
change to the final rule in response to this comment.
    Section 3174.11(f)(3)(i) and (ii) of the final rule (Sec.  
3174.11(g)(3)(i) and (ii) of the proposed rule) requires that if the 
displayed reading of instantaneous temperature from the temperature 
averager or the temperature transducer and the reading from the test 
thermometer differ by more than 0.5 [deg]F, the temperature averager or 
temperature transducer must be either: (1) Adjusted to match the 
reading of the test

[[Page 81492]]

thermometer; or (2) Recalibrated, repaired, or replaced. Section 
3174.11(g)(3)(ii) of the proposed rule only required that the 
difference in temperature readings be noted on the meter proving report 
and all temperatures used until the next proving be adjusted by the 
difference. The BLM received no comments to this section, but 
reconsidered the requirement and the potential tracking and measurement 
errors in adjusting temperature readings between provings and decided 
that if the temperature averager or the temperature transducer is 
unable to be adjusted to the correct reading then it must be 
recalibrated, repaired, or replaced.
    Section 3174.11(g) of the final rule (paragraph (h) in the proposed 
rule) establishes the verification requirements for the pressure 
transducer during the meter-proving operations and states the threshold 
limit value required by the verifying sources as they pertain to the 
normal operating pressure of the tested fluid. It requires that the 
pressure transducer and devices used as part of a LACT or CMS be 
verified as part of every FMP proving and establishes standards for the 
verification procedure and the test equipment used in the pressure 
transducer verification. The BLM received many comments objecting to 
the new requirement that operators verify the pressure transducer 
during the meter-proving process. Two commenters said that the proposed 
rule's meter-proving frequencies would result in excessive and costly 
transducer verifications if the pressure transducers had to be verified 
during each meter proving. The BLM believes that this concern is no 
longer valid. As noted elsewhere, the proving burdens under this final 
rule have been reduced relative to the proposed rule. The proposed rule 
would have required operators to prove their meters each time they 
measured 50,000 bbl of oil, or quarterly, whichever occurred first. 
Section 3174.11(d)(2) of the final rule now requires operators to prove 
their meters every 3 months (quarterly), or each time the registered 
volume flowing through the meter increases by 75,000 bbl, but no more 
frequently than monthly. As a result, the BLM made no changes to the 
final rule in response to these comments.
    One commenter said that requiring operators to verify the pressure 
transducer as part of a LACT or CMS meter proving may require operators 
to acquire additional equipment and incur costs. The BLM agrees that 
verifying the transducer will require an additional piece of equipment 
and potentially an initial cost to acquire test equipment, but we 
believe that third-party proving contractors already own or can acquire 
such equipment. The BLM believes routine transducer verification is 
vital to accurate oil measurement and royalty determination. The BLM 
made no change to the final rule in response to this comment.
    One commenter had concerns with the requirement in paragraph (g)(1) 
(paragraph (h)(1) in the proposed rule) that the pressure sensor must 
be verified against a NIST-traceable device that is at least twice as 
accurate as the reference accuracy of the pressure sensor, saying the 
operator may not have test equipment capable of this accuracy. The 
commenter suggested that the BLM should allow equipment to be used that 
does not meet this accuracy requirement, and should provide guidance on 
how lower-accuracy equipment can be used. The BLM realizes that this 
high level of accuracy may not be achievable with test equipment the 
operator currently has and as a result has changed the rule in Sec.  
3174.11(g)(1) to require the test-pressure device to have a stated 
maximum uncertainty of no more than one-half of the accuracy required 
from the transducer being verified.
    Section 3174.11(h) (paragraph (i) in proposed rule) establishes the 
density verification requirements during the meter proving operations 
and states the limit threshold values required by the verifying sources 
as they pertain to the normal operating density of the tested fluid. 
For Coriolis meters, paragraph (h) requires verification using API 5.6, 
Subsection 9.1.2.1 if measured density is used to determine API oil 
gravity (instead of a hydrometer or thermohydrometer, which is 
generally required under Sec.  3174.6(b)(4)). This provides an 
independent verification that the Coriolis meter's density 
determination function is within the accuracy specification for that 
meter.
    The BLM received a few comments objecting to the new requirement 
for density verification during the FMP meter-proving process for a 
variety of reasons. One commenter recommended that the final rule refer 
to API 8.1, API 8.2, and API 8.3 if the compared density samples come 
from a sampling system. The BLM agrees with this recommendation and 
changed the final rule by adding references to API 8.1, API 8.2, and 
API 8.3. These references provide guidance to operators for performing 
composite sampling to verify oil density as required in the final rule 
under Sec.  3174.11(h).
    One commenter said that using a CMS meter instead of a PD meter 
would impose additional costs on operators to verify the CMS' density 
measurement. The BLM agrees in part that using a CMS would require 
additional density verification over what would be required on a PD 
meter. However, it is up to the operator to choose which meter type to 
use. The BLM did not change the final rule as a result of this comment.
    One commenter objected to the requirement for density verification 
during the FMP meter-proving process because, the commenter said, it 
would be costly and excessive to verify the transducer during each 
meter proving. The BLM believes that this concern has been addressed. 
The proposed rule would have required operators to prove their meters 
each time they measured 50,000 bbl of oil, or quarterly, whichever 
occurred first. Section 3174.11(d)(2) in the final rule has been 
revised and now requires operators to prove their meters every 3 months 
(quarterly), or each time the registered volume flowing through the 
meter increases by 75,000 bbl, but no more frequently than monthly.
    Section 3174.11(i) (paragraph (j) in the proposed rule) requires 
operators to report to the AO all meter-proving operations and volume 
adjustments made after any LACT system or CMS malfunction. This section 
provides additional requirements for data that need to be included on 
the meter-proving report beyond what is currently required under Order 
4. In one change to Order 4 requirements, the final rule requires 
operators to provide the unique meter or station ID number on each 
proving report as required under Sec.  3174.11(i)(2)(i). This section 
includes requirements for verification of the temperature averager or 
temperature transducer, verification of the pressure transducer, and an 
addition to the final rule for density verification documentation, as 
applicable, as well as any ``as left'' conditions if the back pressure 
valve is adjusted after proving, which operators also would have to 
document on the proving report.
    Many commenters asked that we clarify aspects of paragraph (i) 
(proposed paragraph (j)). One commenter recommended that we change 
Sec.  3174.11(i)(2)(iii) and (iv) to only require temperature and 
pressure transmitter information, if verified. The BLM disagrees with 
this commenter on when to report temperature and pressure transducer 
data, since this information has to be verified as part of each FMP 
meter proving. The BLM made no change to the rule in response to this 
comment. Three commenters asked the BLM to specify the format of the 
meter proving reports since

[[Page 81493]]

proposed paragraph (i)(3) specified no specific format. The proposed 
rule required the operator to submit the meter-proving report to the AO 
no later than 14 days after the meter proving. The BLM agrees with the 
commenters that this information should be added and changed the final 
rule to say that the meter proving reports may be transmitted to the AO 
either in hard copy or electronically.
    In addition to the comments on specific provisions above, the BLM 
received a few general comments on Sec.  3174.11. One commenter said 
the new regulations would impact marginal-producing wells and may force 
a premature abandonment of wells and a loss of public hydrocarbon 
resources. The commenter proposed that marginal and/or existing wells 
be exempt from both subpart 3174 and subpart 3175. The BLM disagrees 
that these regulations will force operators to abandon marginal wells. 
If an operator believes these regulations will force it to abandon a 
marginal well, that operator can obtain a variance from the regulations 
under Sec.  3170.6, which is part of the rulemaking that is replacing 
Order 3. The BLM made no change to the final rule in response to this 
comment.
    One commenter said the maximum and minimum velocity for PD meter 
provers was not relevant to SVPs and royalty issues associated with 
their use. The commenter recommended that the BLM adopt language that 
says, ``Provers must be operated within the design parameters of the 
manufacturer.'' The BLM disagrees with the commenter because the prover 
design requirements, including sizing by prover velocity, are found in 
the API standards incorporated in this rule. If the operator believes 
it can meet or exceed these requirements by other means, then the rule 
allows the operator to use the variance process outlined in Sec.  
3170.6. The BLM did not change the final rule in response to this 
comment.
    Two comments, made by the same commenter, voiced concerns that the 
proposed rule was suited to lighter oil regimes and did not address the 
differences in measurement that characterize heavy oil, steamflood, and 
cyclic steam operations. The commenter was concerned that the proposed 
rule's accuracy requirements would increase operating costs for heavy-
oil operators, resulting in possible violations of the measurement 
requirements. The BLM agrees with the commenter that these rules do not 
specifically address the measurement of heavy oil. However, these 
issues are field office specific and can be appropriately addressed 
through the variance process outlined in Sec.  3170.6.
Section 3174.12 Measurement Tickets
    Section 3174.12 specifies the data requirements for measurement 
tickets (run tickets) based on which method of oil measurement an 
operator uses, i.e., tank gauging, LACT system, or CMS. These 
requirements were previously found in Order 3.\14\ The purpose of the 
information in the run tickets is to enable the BLM to independently 
verify the quantity and quality of oil removed from the lease during 
production audits so as to ensure accurate measurement and proper 
reporting.
---------------------------------------------------------------------------

    \14\ The information on a run ticket is considered a source 
record, as defined in Sec.  3170.3, which is being promulgated as 
part of the rulemaking to replace Order 3. The retention 
requirements for such records is addressed in that rulemaking; 
however, the requirements as to substance are provided in this rule 
as explained above.
---------------------------------------------------------------------------

    The BLM received several comments on this section. Some comments 
questioned the requirement to complete a run ticket prior to proving a 
LACT or CMS utilizing flow computers. One commenter stated that this 
requirement is unnecessary as a flow computer is capable of 
implementing a new meter factor in the middle of a run without closing 
the run. The commenter asserted that the flow computer does this by 
applying the original meter factor to deliveries that occurred from the 
beginning of the month up to the point of proving and then applying the 
new meter factor after the point of proving until the end of the month. 
The BLM agrees that flow computers are capable of utilizing two meter 
factors as the commenter described, and of retaining an audit trail 
capability to track this. As a result of this comment, Sec.  
3174.12(b)(1) of the final rule has been changed to remove the 
requirement to close a run ticket prior to proving for LACT systems 
utilizing flow computers.
    One commenter stated that the proposed rule's run-ticket 
requirements for tank gauging did not specify a frequency for when run 
tickets will be required. The BLM disagrees with this comment as the 
proposed rule stated that measurement tickets must be completed 
``immediately after oil is measured by manual tank gauging.'' The BLM 
believes that this language is clear as to how frequently a measurement 
ticket needs to be completed but modified the final rule to say, 
``After oil is measured by tank gauging under Sec. Sec.  3174.5 and 
3174.6. . . .'' This change was made because the final rule allows the 
use of ATG equipment. The BLM made no changes to the rule as a result 
of this comment but did modify the requirements' language due to the 
inclusion of ATG equipment. The final rule now states ``After oil is 
measured by 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.''
    We received several comments requesting that we remove the 
requirement to list on measurement tickets the name of the operator's 
representative certifying the measurements. It was suggested that 
operators do not have enough field personnel to witness every oil tank 
haul and therefore would not be able to ``certify'' every tank sale. 
The commenters argued that this requirement could increase confusion 
and expense, requiring operators to schedule a sale only when a 
``company man'' can be present, and creating undue financial strain on 
operators having to hire staff to witness tank sales and nothing else. 
Another commenter said that the BLM needs to define the term 
``certify.'' Upon reviewing this requirement and the comments, the BLM 
agrees with the commenters, and deleted this requirement in proposed 
Sec.  3174.12(a)(14) from the rule. It should be noted, however, the 
operators remain responsible for the accuracy of information found on 
run tickets, irrespective of any requirement to certify the run ticket.
    Several commenters requested that the BLM remove from the rule the 
requirement that operators notify the AO within 7 days regarding their 
reasons for disagreeing with a tank gauge measurement. The commenters 
said this requirement is impractical because, in the field, it may take 
up to 30 days for a transporter's run ticket to show up in the 
operator's accounting system. One commenter said that operators should 
be able to correct relatively minor run-ticket discrepancies without 
having to report them to the BLM. Upon reviewing these comments, the 
BLM believes this requirement may create confusion both within the BLM 
and among operators as to when exactly the AO should be notified. For 
example, would a simple calculation error warrant AO notification? 
Would the operator need to explore a potential discrepancy before 
notifying the AO? The BLM believes this requirement could lead to 
significant confusion, with minimal benefit to the BLM. Therefore, this 
requirement in proposed Sec.  3174.12(a)(15) was removed from the rule. 
Instead, the BLM will address any run ticket discrepancies on a case-
by-

[[Page 81494]]

case basis during routine production inspections.
    One commenter stated that it may not be possible to reset 
temperature- and pressure-averaging equipment and density-determining 
equipment back to zero upon closing a run ticket, as is required by 
paragraph (b)(2) of this section, which could result in some operators 
having to replace equipment. The BLM is not aware of any non-resettable 
averaging equipment in use on Federal leases. This requirement is in 
the rule to ensure that the temperature, pressure, and density, which 
are required to be included on each run ticket, represent the average 
temperature, average pressure, and average density of the oil that 
actually flowed through the meter during the run-ticket period. If 
there is any non-resettable averaging equipment in use on any Federal 
or tribal lease, operators will be required to replace it. No change to 
the rule resulted from this comment.
    One commenter recommended that the BLM require hauler signatures on 
run tickets, but at the same time admitted that anyone can write or 
type someone else's name on a run ticket and not be the individual who 
is actually performing the task. The BLM agrees that a signature could 
identify a specific individual who filled out a run ticket, in case 
questions arise. But past experience with signature requirements 
resulted in BLM inspectors spending a lot of time tracking down 
signatures for no quantifiable benefit. For this reason, the BLM 
decided to not include a signature requirement. BLM regulations at 43 
CFR 3163.2(f)(1) include penalties for any person who knowingly or 
willfully prepares, maintains or submits false, inaccurate or 
misleading reports, notices, affidavits, records, data or other written 
information. The BLM believes this provision addresses any circumstance 
under which someone falsely enters another person's name on a run 
ticket. By only requiring the name(s) of the individual(s) performing 
the tank gauging, we will be acquiring the data we need for our 
verification requirements. No change was made to the rule as a result 
of this comment.
Section 3174.13 Oil Measurement by Other Methods
    Section 3174.13(a) provides that using any method of oil 
measurement other than tank gauging, LACT system, or CMS at an FMP 
requires prior BLM approval. Under Sec.  3174.13(b), the BLM will use 
the PMT as a central advisory body within the BLM to review and 
recommend approval of industry measurement technology not addressed in 
these regulations. The PMT is a panel of BLM employees who are oil and 
gas measurement experts.
    The process outlined in Sec.  3174.13(b) for reviewing new 
equipment allows the BLM to keep up with technology as it advances and 
approve its use without having to update its regulations. Under the 
rule, if the PMT recommends new equipment or measurement methods, and 
the BLM approves, the BLM will post the make, model, range or software 
version, or measurement method on the BLM Web site (www.blm.gov) as 
being appropriate for use at an FMP for oil measurement going forward.
    The PMT will consider new measurement technologies on a case-by-
case basis. The BLM believes this process will be used as other 
technologies or methods are developed and their reliability is 
established. For example, the BLM considered other meters for inclusion 
in this rule, such as turbine meters and ultrasonic meters; however, it 
ultimately decided not to include them in this rule because at this 
time there is insufficient testing to validate their accuracy and 
reliability under all operating conditions. However, if in the future 
the data demonstrates that these meters meet the performance standards 
of the rule, the PMT will be able to recommend that these meters be 
approved for use.
    If the PMT is able to make the required determination, it will 
recommend that the BLM approve the use of the applicable equipment or 
method, as is or subject to certain conditions. Such equipment or 
methods, and any applicable COAs, will be posted to the BLM Web site 
and be identified as being appropriate for use at an FMP for oil 
measurement without additional approvals from the BLM, subject to any 
limitations or conditions of use imposed by the PMT. Subsequent users 
of the same technology will not have to go through the PMT process, 
provided only that they comply with the identified conditions of use.
    Section 3174.13(c) provides that the procedures for requesting and 
granting a variance under Sec.  3170.6 cannot be used as an avenue for 
approving new technology or equipment. An operator can obtain approval 
of alternative oil measurement equipment or methods only through 
review, recommendation, and approval by the PMT under Sec.  3174.13.
    One commenter suggested that field-office staff are often in a 
better position than national office staff to collaborate with 
operators on pilot projects intended to prove alternative measurement 
methods. The BLM disagrees. Field-office staff typically do not have 
the necessary time and measurement expertise to conduct a complete 
analysis for approval of new technology. This rule includes a process 
for the BLM--through the PMT--to assess new technology and approve it 
when appropriate. Additionally, this rule responds in part to concern 
on the part of the Subcommittee, the GAO, and the OIG that the BLM 
lacked uniform national standards governing measurement. Leaving 
decisions about new equipment to field office staff would not address 
that concern.
    Several commenters wanted to know what they will have to do to get 
equipment approved for use through the PMT and included on the BLM Web 
site. One commenter objected to any requirement that operators pay for 
third-party testing of equipment in order to receive approval by the 
PMT. Upon reviewing the rule and careful consideration of this comment, 
the BLM re-evaluated the approval process for equipment and transducers 
that will be listed on the BLM Web site and changed the rule to clarify 
that an operator requesting approval must submit performance data, 
actual field test results, laboratory test data, or any other 
supporting data or evidence that demonstrates that the proposed 
equipment will meet or exceed this rule's objectives. The final rule is 
revised by adding in Sec.  3174.2(g) to explain how operators and 
manufacturers can obtain BLM approval for ATG equipment and specific 
meters, including approval of a particular make, model, and size, by 
submitting test data used to develop performance specifications to the 
PMT for review. Neither the proposed nor the final rule requires 
operators to pay for third parties to test equipment in order to 
receive PMT approval. However, should the submitted data fail to 
demonstrate to the PMT that the proposed equipment will meet or exceed 
this rule's objectives, the BLM may require additional testing before 
it grants approval.
    One commenter objected to the creation of the PMT, claiming it will 
stifle innovation, not provide timely reviews, and discourage 
development of new technology by increasing ``red tape.'' The BLM 
disagrees and in fact believes the PMT will increase the utilization of 
new technology and expedite new approvals. The BLM believes that once 
the PMT is fully staffed, reviews could take 30 to 60 days, assuming 
that operators and manufacturers have performed the proper testing and 
that all pertinent data is submitted to the PMT. Once the PMT reviews 
the data and makes a recommendation, and the BLM

[[Page 81495]]

approves a piece of equipment, it is approved for use across the 
country on all Federal and Indian onshore leases and no further 
approvals are required. This is not the case for the current variance 
process, which requires approval by each field office for each instance 
such equipment is proposed for use, resulting in a duplicative approval 
process with inconsistent results.
    This commenter also said the BLM, the public, and industry would 
benefit from allowing companies to determine how they will meet the 
requirements of the regulation once it is in place, without the agency 
determining what equipment it will allow to fulfill the requirements of 
its regulation. The BLM agrees that a company should have the 
flexibility to determine how to best satisfy the performance 
requirements of the rule, but disagrees that the BLM should not be 
evaluating and approving equipment. The BLM has an affirmative 
obligation to determine that measurements on Federal oil and gas leases 
are meeting the applicable performance and verifiability standards. The 
final rule provides flexibility by including provisions that allow for 
variances for alternatives that meet or exceed the minimum requirements 
of the regulations and by including the PMT approval process in the 
rules to evaluate and approve new technology and measurement methods. 
The BLM believes that the final rule has already addressed the intent 
of this comment--to allow flexibility in measurement approaches. No 
change to the rule resulted from this comment.
    One commenter suggested that the BLM should list approved 
technology and not specific makes and models of equipment. The BLM 
partly agrees with the commenter, in that the PMT will be evaluating 
new technology and the list will include new technology as it is 
approved, but it will be approved and listed by make and model of the 
specific equipment based on the performance data. The BLM believes that 
there will always be manufacturing control and software differences 
that affect individual meter performance between competing 
manufacturers and these differences need to be captured in the 
uncertainty calculator. No changes to the rule resulted from these 
comments.
Section 3174.14 Determination of Oil Volumes by Methods Other Than 
Measurement
    Section 3174.14 does not change Order 4's existing 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.
    The BLM received two comments on this section. The first commenter 
said the section requires the operator to confirm ``slop oil'' is not 
recoverable, and cannot be treated and sold, and provide documentation 
to this effect. According to the commenter: (1) The proposed rule did 
not define a process for the operator to follow; (2) This requirement 
could impact water disposal when bottoms are pulled from a tank; and 
(3) The language is very open ended. The BLM disagrees that the rule 
does not define a process. The language found in this section is simply 
a codification of existing requirements and practices. Additionally, 
the proposed and final rules state that the first determination the 
operator must make is the amount of production that cannot be measured 
due to spillage or leakage. The second determination the operator must 
make is whether the production is waste oil or slop oil. And the third 
step that an operator must take, depending on whether it is waste or 
slop oil, is to either demonstrate to the AO that it is not 
economically feasible to put the product into marketable condition or 
get AO approval to sell or dispose of the slop oil.
    Regarding the second issue, the BLM notes that this is not a new 
requirement and it should not surprise operators that the requirements 
of this section could impact water disposal when bottoms are pulled 
from tanks should the contents meet the definition of waste oil or slop 
oil.
    As for the third issue, the BLM agrees that the language is 
somewhat open-ended because it is intended to address all potential 
situations that might occur in the field. No change has been made to 
the rule as a result of this comment.
    The second commenter said the rule should be changed to better 
define slop oil. The definition of slop oil is found in the definitions 
section of Sec.  3170.3, part of the rulemaking that is replacing Order 
3. This issue was addressed as part of that rulemaking; however, it 
should be noted that the BLM does not believe this definition is 
insufficient. No change has been made to the final rule as a result of 
this comment.
Section 3174.15 Immediate Assessments
    Section 3174.15 identifies certain acts of noncompliance that are 
subject to immediate assessments. This section includes violations that 
are not subject to immediate assessment under existing 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 beyond those 
specified in 43 CFR 3163.1(b). However, the BLM continues to incur 
costs associated with correcting the violations identified in Sec.  
3174.15. Accordingly, this rule adds five new violations that are 
subject to immediate assessments.
    As is explained in the proposed rule, the authority for the BLM to 
impose these assessments was explained in the preamble to the 1987 
final rule in which 43 CFR 3163.1 was originally promulgated:

    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 rule are 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.
    Some commenters argued that the immediate assessments in Sec.  
3174.15 are

[[Page 81496]]

inconsistent with due process because there is no opportunity for an 
operator to correct its violations before an assessment is imposed. To 
the contrary, the use of immediate assessments for breaches of the 
BLM's oil and gas regulations is well established and is consistent 
with the notice requirements of due process. Operators obligate 
themselves to fulfill the terms and conditions of the Federal or Indian 
oil and gas leases under which they operate, and these leases 
incorporate applicable regulations by reference. Thus, the immediate 
assessments contained in the regulations act as ``liquidated damages'' 
owed by operators that have breached their leases by breaching the 
regulations (see, e.g., M. John Kennedy, 102 IBLA 396, 400 (1988)). 
Operators are expected to know the obligations and requirements of the 
Federal or Indian oil and gas lease under which they operate; 
additional notice is not required.
    A number of commenters said the $1,000 assessment amounts are 
``excessive.'' One commenter said the BLM should adjust the assessment 
amounts on a case-by-case basis. The BLM does not agree. The $1,000 
assessments are in line with the amounts needed for the BLM to recover 
costs for staff and processing time associated with the inspection 
process. A fixed schedule of assessments also ensures their 
impartiality and uniformity. No changes to the rule resulted from these 
comments.
Enforcement
    As explained in the proposed rule, the final rule removes the 
enforcement, corrective action, and abatement period provisions of 
Order 3. In their place, the BLM will develop an Internal Inspection 
and Enforcement Handbook that will provide direction to BLM inspectors 
on how to classify a violation--as either major or minor--what the 
corrective action should be, and what the timeframes for correction 
should be. The AO will 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 timely fashion, and for immediate assessments for 
certain violations.
    As previously discussed in the proposed rule, the final rule allows 
the BLM to make a case-by-case determination of the severity of a 
violation, based on applicable definitions in the regulations. In 
deciding how severe a violation is, BLM inspectors must take into 
account whether a violation could result in ``immediate, substantial, 
and adverse impacts on public health and safety, the environment, 
production accountability, or royalty income.'' (Definition of ``major 
violation,'' 43 CFR 3160.0-5.) Under the existing definition of ``major 
violation,'' which is not being revised as part of this rulemaking, the 
same violation could be major or minor, depending on the context.
    Several commenters objected to this approach for a number of 
reasons. One concern was that if the BLM publishes an internal guidance 
document ``after the fact,'' meaning after the rule is final, industry 
will be precluded from commenting on or assessing the impact of such a 
document on their operations. Another concern was that a guidance 
document will create inconsistency between field offices and operators. 
However, the commenter provided no explanation as to how an internal 
guidance document will create inconsistency between field offices and 
operators, or what confusion industry will have concerning how the BLM 
enforces the regulations. In general, these comments misunderstand the 
nature of the Internal Inspection and Enforcement Handbook that the BLM 
will develop. The new Handbook will not establish new obligations to be 
imposed on the regulated community. Those obligations are spelled out 
in applicable regulations, orders, and permits, as well as the terms 
and conditions of leases and other agreements.
    Other commenters questioned why the Inspection and Enforcement 
Handbook was not part of the public notice and comment process. 
Internal guidance documents that direct agency personnel how to 
implement existing agency policies are not required to follow the 
public notice and comment process. No change to the rule resulted from 
this comment.
    Additional comments suggested that the BLM may not promulgate new 
binding regulations in internal ``guidance'' documents. The BLM agrees 
with this comment and will not be promulgating any binding regulations 
within the internal guidance document. The overarching enforcement 
infrastructure of 43 CFR subpart 3163 remains in effect, and the 
definitions of ``major violation'' and ``minor violation'' in Sec.  
3160.0-5 remain unchanged. It is these duly promulgated regulations 
(among other authorities), and not the Inspection and Enforcement 
Handbook, that will provide the legal basis for the BLM's enforcement 
actions; BLM's enforcement actions must be consistent with these 
regulations irrespective of what may be contained in its Inspection and 
Enforcement Handbook. As noted above, it is this rule and other duly 
promulgated regulations that establish the standards to which an 
operator will be held.
    Several commenters asserted that removing internal enforcement 
provisions from the regulations that were promulgated with public 
notice and comment, and ``concealing'' them in non-public policy 
documents that can be altered without notice and in the absence of 
public input, is inconsistent with the requirements of the 
Administrative Procedures Act (APA). The BLM does not agree with these 
comments as they misunderstand the nature of the new Handbook. The 
operative requirements to which operators are subject are spelled out 
in duly promulgated regulations, consistent with APA requirements. 
Internal agency guidance documents on how to implement those 
requirements are not subject to the APA's notice and comment 
requirements. No change to the rule resulted from these comments.
    A few other commenters said industry has a right to know by what 
standards they are being judged and penalized. The BLM agrees and 
believes this rule very clearly describes the standards industry must 
meet in the oil measurement context. As stated above, in deciding how 
severe a violation is, BLM inspectors will 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.) One commenter suggested that the 
BLM provide internal standards to industry at the earliest opportunity. 
The BLM agrees and will make the internal Inspection and Enforcement 
Handbook available to the public once it is completed.
    Several commenters expressed concern that industry has not seen any 
proposed violations that may result in enforcement actions prior to the 
BLM's adoption of the Inspection and Enforcement Handbook. The BLM 
wishes to further clarify what a violation is. Any deviation from the 
rules and regulations, without an approved variance from the AO, is a 
violation, and any violation will result in enforcement action. The 
Handbook will not alter that fundamental structure in any way.
    Additional commenters said the BLM's process for developing 
violations and corrective actions is not transparent. Again, these 
comments misunderstand the nature of the forthcoming internal guidance. 
Operators are obligated to follow the

[[Page 81497]]

rules and regulations applicable to their operations, including the 
requirements of this final rule, or they are in violation and subject 
to potential enforcement actions by the BLM. The Inspection and 
Enforcement Handbook will simply guide BLM staff on how to identify 
violations and provide guidance on which enforcement actions should be 
taken, it does not answer the underlying question of what is or is not 
a violation. No changes to the rule resulted from these comments.
Miscellaneous Changes to Other BLM Regulations in 43 CFR Part 3160
    Because this rule replaces Order 4, the BLM is making two related 
changes to provisions in 43 CFR part 3160.
    1. Section 3162.7-2, Measurement of oil, has been rewritten to be 
consistent with this rule.
    2. Section 3164.1, Onshore Oil and Gas Orders, the table has been 
revised to remove the reference to Order 4.
    The BLM received no comments on these sections and they remain as 
proposed.

C. General Comments on the Proposed Rule

Regulatory Burden
    The BLM received numerous comments that said the cumulative 
economic impact of this and other rules that the BLM has adopted or 
plans to finalize in the coming months will result in unnecessary and 
restrictive regulations, increased burdens and costs to both industry 
and the BLM without any documented financial benefits to taxpayers, and 
job loss in the oil and gas industry. The commenters noted that in 
addition to this rulemaking, the BLM is finalizing rules that will 
update and replace Orders 3 and 5. In addition, on February 8, 2016, 
the BLM published in the Federal Register a proposed rule entitled 
Waste Prevention, Production Subject to Royalties, and Resource 
Conservation (81 FR 6616), which seeks to curtail the wasteful venting 
and flaring of Federal and Indian gas. Commenters also flagged the 
BLM's new regulations on hydraulic fracturing that were to go into 
effect on June 24, 2015 (The rule is currently vacated by order of the 
District Court of Wyoming, that Order is on appeal to the U.S. Court of 
Appeals for the Tenth Circuit.) The BLM does not agree with these 
comments for two primary reasons. First, this rule codifies existing 
requirements found in Order 4, adopts industry standards and practices 
that are already in use, and has built in compliance flexibility that 
increases opportunities for operators to deploy new technologies, 
potentially reducing costs. Notably, this rule expands compliance 
opportunities because, for the first time, it establishes measurement 
performance standards that can be used by operators to identify and 
evaluate alternative measurement methods and equipment. Second, 
improved accuracy also has the potential to benefit operators, because 
measurement uncertainty has an equal chance of favoring the government 
or the lessee.
    Other commenters said that the costs to retrofit many of the 
facilities to bring them into compliance with this rule and the BLM's 
proposed rules on gas measurement and site security would outweigh any 
foreseeable economic benefits to operators and government entities. The 
commenters contend that the proposed rule would impose significant and 
harmful burdens on operators and the industry as a whole causing 
operators to shut in, plug, and abandon producing wells, possibly 
leading to a loss of royalty and tax revenue for the Federal 
Government, as well as tribal, State, and local governments. Several 
commenters recommended that the BLM withdraw the proposed rule at this 
time due to its negative economic impacts, and argued that the BLM 
could accomplish much of what it seeks to do through this proposed rule 
by simply updating the content of Orders 4 and 5 to reflect current 
voluntary consensus standards developed by professional industry 
groups. The BLM disagrees with the suggestion that these rules are 
unnecessary and will result in plugged wells, or lost jobs. First, the 
current economic conditions in the oil and gas sector identified by the 
commenters are a direct result of the significant drop in oil prices 
over the last year and a half, which has been accounted for in the 
threshold analyses performed by the BLM. For example, the recent drop 
in oil prices led the BLM to change the various thresholds between 
draft and final rule, as explained in this preamble. Second, with 
respect to the suggestion that BLM should have simply updated Orders 4 
and 5 with references to the relevant industry standards, it must be 
noted that such an approach was not available to the BLM. Order 4 was 
promulgated using the APA's Notice and Comment procedures; therefore 
any updates to it required BLM to undertake Notice and Comment 
rulemaking. Under those procedures, the BLM is forbidden from 
incorporating industry standards, unless it is incorporating them into 
codified regulations, which is the primary reason this rule is being 
codified.
    With respect to the concerns about cost, the BLM believes that this 
rule will increase opportunities for operators to reduce costs thanks 
to the rule's built-in flexibility. As noted, this rule includes 
specific performance standards that will enable operators to identify 
and evaluate alternative methods and equipment for oil measurement. In 
addition, the rule includes provisions expressly authorizing ATG 
systems and the use of Coriolis meters (either as a component of a LACT 
system or as a standalone metering system). Finally, as explained 
elsewhere, the rule incorporates the latest industry standards and 
establishes a PMT to evaluate new equipment and methodologies, so that 
the BLM can review and approve such equipment and methodologies as they 
are developed. This flexibility is not available in the current Order 
4, which requires operators to obtain case-by-case variances before 
they may use new equipment or methods.
Retroactivity
    A number of commenters argued that the rule is impermissibly 
``retroactive.'' These comments argued that the rule is retroactive 
because it will apply to measurement systems whose existence pre-dates 
the rule's effective date. While the BLM agrees that truly retroactive 
regulations raise legal concerns, those concerns are not implicated 
here because this rule is not retroactive. The comments misunderstand 
the nature of the ``retroactive'' regulations that the law disfavors. 
``A law does not operate `retrospectively' merely because it is applied 
in a case arising from conduct antedating the statute's enactment or 
upsets expectations based in prior law'' (Landgraf v. USI Film Prods., 
511 U.S. 244, 269 (1994) (internal citations omitted)). Rather, the 
test for retroactivity is whether the new regulation ``attaches new 
legal consequences to events completed before its enactment.'' Id. at 
270. The rule at hand does not attach any new legal consequence to the 
past use of existing measurements systems. As the U.S. Court of Appeals 
for the District of Columbia Circuit has explained, the fact that a 
change in the law adversely affects pre-existing arrangements does not 
render that law ``retroactive:''

    It is often the case that a business will undertake a certain 
course of conduct based on the current law, and will then find its 
expectations frustrated when the law changes. This has never been 
thought to constitute retroactive lawmaking, and indeed most 
economic regulation would be unworkable if all laws disrupting prior 
expectations were deemed suspect.


[[Page 81498]]


Chemical Waste Mgmt., Inc. v. EPA, 869 F.2d 1526, 1536 (D.C. Cir. 
1989). Thus, despite the fact that this rule may require companies to 
update or modify their existing measurement systems, the rule is 
nonetheless prospective--not retroactive--in nature. The obligation to 
accurately measure and account for oil produced from both new and 
existing facilities is ongoing and track the productions each day it 
occurs.
National Technology Transfer and Advancement Act of 1995
    The National Technology Transfer and Advancement Act of 1995 
(NTTAA), codified as a note to 15 U.S.C. 272, directs agencies to 
utilize technical standards that are developed by voluntary consensus 
standards bodies. In this rule, the BLM is adopting certain oil 
measurement standards developed by the API. Some commenters argued that 
the NTTAA obligates the BLM to adopt all oil measurement standards 
developed by voluntary consensus standards bodies. This position 
overstates the requirements of the NTTAA. The NTTAA does not require an 
agency to adopt voluntary consensus standards where it would be 
``impractical.'' NTTAA Section 12(d)(3). The Office of Management and 
Budget's (OMB) guidance for implementing the NTTAA defines 
``impractical'' to include circumstances in which the use of certain 
standards ``would fail to serve the agency's regulatory, procurement, 
or program needs; be infeasible; be inadequate, ineffectual, 
inefficient, . . . or impose more burdens, or be less useful, than 
those of another standard'' (OMB Circular A-119, pg. 20.) Furthermore, 
the OMB has explained that the NTTAA ``does not preempt or restrict 
agencies' authorities and responsibilities to make regulatory decisions 
authorized by statute . . . [including] determining the level of 
acceptable risk and risk-management, and due care; setting the level of 
protection; and balancing risk, cost, and availability of alternative 
approaches in establishing regulatory requirements'' (OMB Circular A-
119, pg. 25.) The BLM has studied the available voluntary consensus 
standards for oil measurement and has chosen to adopt a workable suite 
of these standards that will meet the BLM's regulatory needs in an 
effective and feasible manner. To adopt all available voluntary 
consensus standards would be ``impractical'' in that it would involve 
the adoption of standards the BLM has judged to be less effective, 
feasible, or useful. In addition, the commenters reading of the NTTAA 
would, contrary to OMB guidance, preempt the BLM's statutory authority 
to promulgate rules and regulations that it deems necessary to 
accomplish the purposes of the MLA and FOGRMA.
III. Overview of Public Involvement and Consistency With GAO 
Recommendations

Public Outreach

    The BLM conducted extensive public and tribal outreach on this rule 
both prior to its publication as a proposed rule and during the public 
comment period on the proposed rule. Prior to the publication of the 
proposed rule, the BLM held both tribal and public forums to discussion 
potential changes to the rule. In 2011, the BLM held three tribal 
meetings in Tulsa, Oklahoma (July 11, 2011); Farmington, New Mexico 
(July 13, 2011); and Billings, Montana (August 24, 2011). 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 those meetings, the BLM opened a 36-day informal comment 
period, during which 13 comment letters were submitted. The comments 
received during that comment period were summarized in the preamble for 
the proposed rule (80 FR 58952).
    The proposed rule was made available for public comment from 
September 30, 2015 through December 14, 2015. During that period, the 
BLM held tribal and public meetings on December 1 (Durango, Colorado), 
December 3 (Oklahoma City, Oklahoma), and December 8 (Dickinson, North 
Dakota). The BLM also held a tribal webinar on November 19, 2015. In 
total, the BLM received 106 comment letters on the proposed rule, the 
substance of which are addressed in the Section-by-Section analysis of 
this preamble.
Consistency With GAO Recommendations
    As explained in the background section of this preamble, three 
outside independent entities--the Subcommittee, the OIG, and the GAO--
have repeatedly found that the BLM's oil measurement rules do not 
provide sufficient assurance that operators pay the royalties due. 
Specifically, these groups found that the BLM needed updated guidance 
on oil measurement technologies, to address existing technological 
advances, as well as technologies that might be developed in the 
future. These groups have all found that the BLM's existing guidance is 
``unconsolidated, outdated, and sometimes insufficient,'' and more 
specifically, that:
     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;
     Some BLM policy and guidance is outdated and some policy 
memoranda have expired; and
     Some BLM State offices have issued their own NTLs for oil 
and gas operations, which lack a national perspective and may introduce 
inconsistencies among the States with respect to the same types of 
operations.
    The final rule addresses these recommendations by establishing 
nationwide performance requirements for oil measurement that addresses 
uncertainty factors, bias, and the verifiability of measurement. The 
rule specifically addresses technological advances in oil metering 
technology since Order 4 was promulgated. It affirmatively allows the 
use of those technologies that have been shown to be sufficiently 
reliable and accurate. It also updates the BLM's requirements related 
to proper measurement, documentation, and recordkeeping. Going forward 
the final rules establishes a process for the BLM to review, and 
approve for use, new oil measurement technology and systems.

IV. Procedural Matters

Executive Orders 12866 and 13563, Regulatory Planning and Review

    Executive Order (E.O.) 12866 provides that the Office of 
Information and Regulatory Affairs (OIRA) will review all significant 
rules. OIRA has determined that this rule is not significant.
    E.O. 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.

[[Page 81499]]

Regulatory Flexibility Act

    The BLM certifies that this final rule will not have a significant 
economic effect on a substantial number of small entities as defined 
under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.). 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. The Small Business Act applies to oil and gas 
extraction firms with fewer than 1,250 employees, oil and gas drilling 
firms with fewer than 1,000 employees, and firms providing oil and gas 
support activities with annual receipts of no more than $38.5 million. 
These small entities must be considered as being at ``arm's length'' 
from the control of any parent companies.
    Of the 6,460 domestic firms involved in onshore oil and gas 
extraction in 2013, U.S. Census data show that 99 percent (or 6,370) 
had fewer than 500 employees, which means that nearly all U.S. firms 
involved in oil and gas extraction in 2013 fell within the SBA's size 
standard of fewer than 1,250 employees. Of the 2,097 firms 
participating in oil and gas drilling activities in 2013, U.S. Census 
data show that 2,044 had fewer than 500 employees, which means that 
nearly all U.S. firms involved in oil and gas support activities in 
2013 fell within the SBA's size standard of fewer than 1,000 employees. 
There were another 8,877 firms involved in drilling and other support 
functions in 2012. Of the firms providing support functions, 96 percent 
(8,561) had annual net receipts of no more than $35 million, with a 
greater number below the SBA's $38.5 million threshold.
    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 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.
    On an ongoing basis, we estimate the changes to the LACT meter 
proving frequency requirements based on volume throughput will increase 
the regulated community's total annual costs by $67,650. This amount 
corresponds to the cost of an estimated 123 additional annual provings 
per year at 28 LACT systems on 19 leases, CAs, or PAs flowing between 
31,250 bbl/month/meter and 100,000 bbl/month/meter. This includes 75 
additional provings ($41,250 in cost) for 22 LACT systems on 15 leases, 
CAs, or PAs flowing at least 31,250 bbl/month/meter and below 75,000 
bbl/month/meter, and 48 additional provings ($26,400 in cost) for six 
LACT systems on four leases, CA, or PA's flowing at least 75,000 bbl/
month/meter and below 100,000 bbl/month/meter. Currently, LACT systems 
for both of these groups of systems would be proven monthly for LACTs 
measuring 100,000 bbl/month or greater, or once every 3 months (four 
times per year). Under the new rule, meters at the first group of LACT 
systems (31,250 bbl/month/meter up to 75,000 bbl/month/meter) would be 
proven every 75,000 bbl, or from 5 to 11 times per year, while meters 
in the second group of LACT systems (75,000 bbl/month/meter up to 
100,000 bbl/month/meter) would be proven monthly, or 12 times each 
year. There would be no change in proving frequency for properties 
producing at or above 100,000 bbl/month/meter (one proving per month, 
or 12 per year) or below 31,250 bbl/month/meter (one proving per 
quarter, or four per year).
    In addition, there will be a one-time cost to retrofit an estimated 
20 percent of existing LACT systems of about $1.9 million, or a one-
time average cost of about $6,500 for each of an estimated 
approximately 296 existing LACT systems. This amounts to an average 
one-time cost of $519 for each of the approximately 3,700 lessees/
operators conducting oil production operations on Federal or Indian 
leases. The requirement for operators to conduct tank strappings to 
submit revised calibration tables to the BLM will have an annual cost 
to operators of $4.0 million per year (approximately $1,080 per 
entity), plus an additional $0.2 million in industry paperwork costs 
for submitting these tables, and $0.2 million in additional costs to 
the BLM to process these paperwork submissions. When adding the 
additional cost of hourly recordkeeping and non-hourly provisions in 
the final rule, the BLM estimates that the rule will have a total 
impact of $3.3 million in one-time costs and $4.6 million in annual 
costs. When the one-time costs are annualized for the first 3 years 
following the enactment of the final rule, and combined with annual 
costs for these years, the BLM estimates a total annualized cost of 
$5.7 million per year, or $1,540 per entity per year, for years 1-3 
after the final rule's effective date. After year three, costs will 
equal the estimated annual cost of $4.6 million, or $1,240 per entity 
per year. All of the provisions apply to entities regardless of size. 
However, entities with the greatest activity likely will experience the 
greatest increase in compliance costs.
    Based on the available information, we conclude that the final rule 
will not have a significant impact on a substantial number of small 
entities. The final rule will cost each entity an average of less than 
$2,000 per year, which will impact expected annual operator net income 
by less than 0.01 percent, as described in the Regulatory Impact 
Analysis for this rule. 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 final rule is not a major rule under 5 U.S.C. 804(2), the 
Small Business Regulatory Enforcement Fairness Act. This rule will not 
have an annual effect on the economy of $100 million or more. As 
explained under the preamble discussion concerning E.O. 12866, 
Regulatory Planning and Review, changes to oil measurement under this 
final rule relative to the existing requirements of Order 4 will 
increase the cost associated with the development and production of 
crude oil resources under Federal and Indian oil and gas leases by 
about $4.8 million annually. Of this amount, about $3.9 million/year 
will be borne by industry, and $0.9 million/year by the BLM. There will 
also be a one-time cost of about $1.9 million to retrofit an estimated 
20 percent of existing LACT systems, borne entirely by industry.
    Based on the cost figures above, the estimated annual increased 
cost to the estimated 3,700 lessees/operators conducting oil production 
operations on Federal or Indian leases for implementing these changes 
is about $1,055 per year, and a one-time average cost of about $520 per 
entity.
    This final rule:
     Will not cause a major increase in costs or prices for 
consumers, individual industries, Federal, State, tribal, or local 
government agencies, or geographic regions; and
     Will not have significant adverse effects on competition, 
employment, investment, productivity, innovation, or the ability of 
U.S.-based enterprises to compete with foreign-based enterprises.

Unfunded Mandates Reform Act

    In accordance with the Unfunded Mandates Reform Act (2 U.S.C. 1501 
et seq.), the BLM finds that:
     This final rule will not ``significantly or uniquely'' 
affect small

[[Page 81500]]

governments. A Small Government Agency Plan is unnecessary.
     This final rule will not produce a Federal mandate of $100 
million or greater in any single year.
    The final rule is not a ``significant regulatory action'' as it 
will not require anything of any non-Federal governmental entity.

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

    Under E.O. 12630, the final rule would not have significant takings 
implications. A takings implication assessment is not required. This 
final rule will 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 that expressly require that subsequent lease activities 
be conducted in compliance with applicable Federal laws and 
regulations. The final rule conforms to the terms of those Federal 
leases and applicable statutes, and as such the final rule is not a 
governmental action capable of interfering with constitutionally 
protected property rights. Therefore, the final rule will not cause a 
taking of private property and does not require further discussion of 
takings implications under this E.O.

Executive Order 13132, Federalism

    In accordance with E.O. 13132, the BLM finds that the final rule 
will not have significant Federalism effects. A Federalism assessment 
is not required. This final rule will not change the role of or shift 
responsibilities among Federal, State, and local governmental entities. 
It does not relate to the structure and role of the States and will 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 final rule on federally 
recognized Indian tribes. The BLM approves proposed operations on all 
Indian (except Osage Tribe) onshore oil and gas leases. Therefore, the 
final rule has the potential to affect Indian tribes. In conformance 
with the Secretary's policy on tribal consultation, the BLM held tribal 
consultation meetings to which more than 175 tribal entities were 
invited, both before the rule was proposed and during the public 
comment period on the proposed rule. The consultations were held in:
Pre-Publication Meetings
     Tulsa, Oklahoma on July 11, 2011;
     Farmington, New Mexico on July 13, 2011; and
     Billings, Montana on August 24, 2011.
     Tribal workshop and webcast in Washington, DC on April 24, 
2013.
Post-Publication Meetings
     The BLM hosted a webinar to discuss the requirements of 
the proposed rule and solicit feedback from affected tribes on November 
19, 2015; and
     In-person meetings were held in:
    [cir] Durango Colorado, on December 1, 2015;
    [cir] Oklahoma City, Oklahoma, on December 3, 2015; and
    [cir] Dickinson, North Dakota, on December 8, 2015.
    The BLM also met with interested tribes on a one-on-one basis, if 
requested to address questions on the proposed rule prior to the 
publication of the final rule. In each instance, the purpose of these 
meetings was to solicit feedback and comments from the tribes. The 
primary concerns expressed by tribes related to the subordination of 
tribal laws, rules, and regulations by the proposed rule; tribal 
representation on the Department's Gas and Oil Measurement Team; and 
the BLM's Inspection and Enforcement program's ability to enforce the 
terms of this rule. In general, the tribes, as royalty recipients, 
expressed support for the goals of the rulemaking, namely accurate 
measurement. With respect to tribal representation on the Department's 
Gas and Oil Measurement Team, it should be noted that the team is 
internal to BLM. That said, the BLM will continue to consult with 
tribes on measurement issues that impact them and their resources. None 
of the tribal comments received were directed specifically at this 
rule's oil measurement requirements, and therefore no changes were made 
as a result of these comments. While the BLM will continue to address 
these concerns, none of the concerns affect the substance of the 
proposed rule.

Executive Order 12988, Civil Justice Reform

    Under E.O. 12988, the Office of the Solicitor has determined that 
the final rule will not unduly burden the judicial system and meets the 
requirements of Sections 3(a) and 3(b)(2) of the E.O. The Office of the 
Solicitor has reviewed the final 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 E.O. 13352, the BLM has determined that this final rule will 
not impede cooperative conservation and will 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 involved 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 provides that the programs, 
projects, and activities are consistent with protecting public health 
and safety.

Paperwork Reduction Act

    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 
requests and requirements that an individual, partnership, or 
corporation obtain information, and report it to a Federal agency. See 
44 U.S.C. 3502(3); 5 CFR 1320.3(c) and (k).
    This rule contains information collection activities that require 
approval by the OMB under the Paperwork Reduction Act. The BLM included 
an information collection request in the proposed rule. OMB has 
approved the information collection for the final rule under control 
number 1004-0209.
    The information collection activities in this rule are described 
below along with estimates of the annual burdens. Included in the 
burden estimates are the time for reviewing instruction, searching 
existing data sources, gathering and maintaining the data needed, and 
completing and reviewing each component of the proposed information 
collection.

Summary of Information Collection Activities

    Title: Measurement of Oil (43 CFR parts 3160 and 3170).
    Forms: None.

[[Page 81501]]

    OMB Control Number: 1004-0209.
    Description of Respondents: Oil and gas operators.
    Abstract: This final rule replaces Onshore Oil and Gas Order Number 
4, Measurement of Oil (Order 4) with new regulations that will be 
codified at 43 CFR parts 3160 and 3170. This rule establishes minimum 
standards for the measurement of oil produced from Federal and Indian 
(except Osage Tribe) leases to ensure accurate measurement and 
accounting. It also updates the minimum standards for oil measurement 
to reflect the considerable changes in technology and industry 
practices that have occurred since 1989, when Order 4 was issued.
    Frequency of Collection: On occasion.
    Obligation to Respond: Required to obtain or retain benefits.
    Estimated Annual Responses: 11,707.
    Estimated One-Time Responses: 35.
    Estimated Annual Reporting and Recordkeeping ``Hour'' Burden: 
3,284.
    Estimated One-Time Reporting and Recordkeeping ``Hour'' Burden: 
2,600.

Discussion of Information Collection Activities

    The information collection activities in the final rule are 
discussed below.

Request for Exception to Uncertainty Requirements (43 CFR 3174.4(a)(2))

    The final rule, at 43 CFR 3174.4(a), requires each FMP to achieve 
certain overall uncertainty levels. An operator may seek an exception 
to the prescribed uncertainty levels by submitting a request to a BLM 
State Director. The operator must show that meeting the required 
uncertainly level would involve extraordinary cost or unacceptable 
adverse environmental effects. The State Director may grant such a 
request only with written concurrence from the PMT (prepared in 
coordination with the Deputy Director). This provision enables the BLM 
to determine whether or not it is reasonable to grant an exception to 
uncertainty requirements.

Tank Calibration Tables (43 CFR 3174.5(c)(3))

    Section 3174.5(c)(3) requires submission of tank calibration tables 
to the BLM within 30 days after calibration. This provision ensures 
that BLM personnel will have the latest charts when conducting 
inspections or audits.

Approval of Automatic Tank Gauging (ATG) Equipment (43 CFR 
3174.6(b)(5)(ii)(A)); and Log of ATG Verification (43 CFR 
3174.6(b)(5)(ii)(C))

    The procedures for oil measurement by tank gauging must comply with 
the requirements outlined in 43 CFR 3174.6. Beginning on January 17, 
2019, only the specific makes and models of ATG that are identified and 
described at the BLM Web site (www.blm.gov) are approved for use.
    If an operator chooses to use a particular make or model of ATG 
equipment, the operator (or the manufacturer of the ATG equipment) must 
seek and obtain BLM approval of the particular make and model of that 
equipment by submitting a request to the PMT, consisting of a panel of 
BLM employees who are oil and gas measurement experts. The submission 
must describe the test data used to develop performance specifications. 
After reviewing the test data, the PMT will recommend whether or not to 
approve the ATG equipment. This information collection activity enables 
the BLM to consider approving new technologies not yet addressed in its 
regulations.
    The operator must inspect its ATG equipment and verify its accuracy 
at least once a month, or prior to sales, whichever is later. In 
addition, the BLM may request inspection and verification at any time.
    If the operator finds ATG equipment to be out of tolerance, the 
operator must calibrate the equipment prior to sales, and must maintain 
a log of field verifications. That operator must make the log available 
to the BLM upon request. The log must include the following 
information:
     The date of verification;
     The as-found manual gauge readings;
     The as-found ATG readings; and
     Whether the ATG equipment was field-calibrated.
    If the ATG equipment was field-calibrated, the as-left manual gauge 
readings and as-left ATG readings must be recorded. This information 
collection activity enables the BLM to ensure the accuracy of tank 
gauging by ATG systems.

Notification of LACT System Failure (43 CFR 3174.7(e)(1))

    Section 3174.7(e)(1) requires the operator to notify the BLM within 
72 hours of any LACT system failures or equipment malfunctions which 
may have resulted in measurement error. As defined at proposed Sec.  
3174.1, a LACT system consists of components designed to provide for 
the unattended custody transfer of oil produced from a lease, unit PA, 
or Communitized Area (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. This information 
collection requirement enables the BLM to verify that operators account 
for all oil volumes.

Approval of a Positive Displacement (PD) Meter (43 CFR 3174.8(a)(1)); 
and Approval of a Coriolis Meter (43 CFR 3174.9(b))

    Section 3174.8(a)(1) requires each custody transfer meter to be a 
PD meter or a Coriolis meter. A PD meter measures liquid by constantly 
and mechanically isolating flowing liquid into segments of known 
volume. A Coriolis meter measures liquid via the interaction between a 
flowing fluid and oscillation of tubes. Beginning on January 17, 2019, 
only the specific make, models, and sizes of PD meters and Coriolis 
meters and associated software that are identified and described at 
www.blm.gov are approved for use.
    If an operator chooses to use a particular make or model of PD 
meter or Coriolis meter, the operator (or the manufacturer of the 
meter) must seek and obtain BLM approval of that particular make and 
model by submitting a request to the PMT. The submission must describe 
the test data used to develop performance specifications. After 
reviewing the test data, the PMT will recommend whether or not to 
approve the meter. This information collection activity enables the BLM 
to consider approving new technologies not yet addressed in its 
regulations.

Coriolis Meter Specification and Zero Verification Procedure (43 CFR 
3174.10(b)(2) and (d)); Zero Verification Log (43 CFR 3174.10(b)(2) and 
(e)(4)); and Audit Trail Requirements for Coriolis Measurement System 
(CMS) (43 CFR 3174.10(b)(2) and (f))

    Section 3174.10(b)(2) requires the operator to submit Coriolis 
meter specifications to the BLM upon request. The meter specification 
of a Coriolis meter must clearly identify the make and model of the 
Coriolis meter to which they apply and must include the following:
     The reference accuracy for both mass flow rate and 
density, stated in either percent of reading, percent of full scale, or 
units of measure;
     The effect of changes in temperature and pressure on both 
mass flow and fluid density readings;
     The effect of flow rate on density readings;
     The stability of the zero reading for volumetric flow 
rate;
     Design limits for flow rate and pressure; and

[[Page 81502]]

     Pressure drop through the meter as a function of flow rate 
and fluid viscosity.
    Section 3174.10(d) requires the operator to provide the BLM with a 
copy of the zero value verification procedure upon request.
    Section 3174.10(e)(4) requires the operator to maintain a log 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. The log must be made available to the 
BLM upon request.
    Section 3174.10(f) requires the operator to record and retain, and 
submit to the BLM upon request, the following information:
     Quantity transaction record (QTR) in accordance with the 
requirements for a measurement ticket (at 43 CFR 3174.12(b));
     Configuration log that contains and identifies all 
constant flow parameters used in generating the QTR;
     Event log of sufficient capacity to record all events such 
that the operator can retain the information under the recordkeeping 
requirements of 43 CFR 3170.7; and
     Alarm log that records the type and duration of any of the 
following alarm conditions:
    [cir] Density deviations from acceptable parameters; and
    [cir] Instances in which the flow rate exceeded the manufacturer's 
maximum recommended flow rate or were below the manufacturer's minimum 
recommended flow rate.

These information collection activities will assist the BLM in ensuring 
real-time, on-line measurement of oil.

Meter Proving and Volume Adjustments Notification (43 CFR 
3174.11(i)(1)); and Meter Proving Reports (43 CFR 3174.11(i)(3))

    Section 3174.11 specifies the minimum requirements for conducting 
volumetric meter proving for all FMP meters. Meter proving verifies the 
accuracy of a meter.
    Under 43 CFR 3174.11(i)(1), an operator must report to the BLM all 
meter-proving and volume adjustments after any LACT system or CMS 
malfunction. The operator must use the appropriate form in API 12.2.3 
or API 5.6 (both incorporated by reference at 43 CFR 3174.3), or use a 
similar format showing the same information as the API form, provided 
that the calculation of meter factors maintains the proper calculation 
sequence and rounding.
    In addition, a meter-proving report must show the:
     Unique meter ID number;
     Lease number, CA number, or unit PA number;
     The temperature from the test thermometer and the 
temperature from the temperature averager or temperature transducer;
     For pressure transducers, the pressure applied by the 
pressure test device and the pressure reading from the pressure 
transducer at the three points required under paragraph (g)(3) of this 
section;
     For density verification (if applicable), the 
instantaneous flowing density (as determined by Coriolis meter), and 
the independent density measurement, as compared under 43 CFR 3174.(h); 
and
     The ``as left'' fluid flow rate and fluid pressure, if the 
back pressure valve is adjusted after proving as described in 43 CFR 
3174.11(c)(9).
    Under Sec.  3174.11(i)(3), the operator must submit the meter-
proving report to the BLM no later than 14 days after the meter 
proving. The proving report may be either in a hard copy or electronic 
format.
    These information collection activities will assist in ensuring the 
accuracy of meters.

Tank Gauging Run Tickets (43 CFR 3174.12(a)); and LACT or CMS Run 
Tickets (43 CFR 3174.12(b))

    A run ticket is the evidence of receipt or delivery of oil issued 
by a pipeline, other carrier, or purchaser. The amount of oil 
transferred from storage is recorded on a run ticket. The amount of 
payment for oil is based upon information contained in the run ticket.
    Tank gauging (43 CFR 3174.12(a))--After oil is measured by tank 
gauging, the operator, purchaser, or transporter, as appropriate, must 
complete a uniquely numbered measurement ticket, in either paper or 
electronic format, with the following information:
     Lease, unit, or CA number;
     Unique tank number and nominal tank capacity;
     Opening and closing dates and times;
     Opening and closing gauges and observed temperatures in 
[deg]F;
     Observed volume for opening and closing gauge;
     Total gross standard volume removed from the tank;
     Observed API oil gravity and temperature in [deg]F;
     API oil gravity at 60 [deg]F;
     S&W percent;
     Unique number of each seal removed and installed;
     Name of the individual performing the manual tank gauging; 
and
     Name of the operator.
    LACT or CMS (43 CFR 3174.12(b))--The operator, purchaser, or 
transporter, as appropriate, must complete a uniquely numbered 
measurement ticket, in either paper or electronic format, at the 
beginning of every month, and (unless a flow computer is being used in 
accordance with 43 CFR 3174.10) before conducting proving operations on 
a LACT system. The following information is required:
     Lease, unit, or CA number;
     Unique meter ID number;
     Opening and closing dates;
     Opening and closing totalizer readings of the indicated 
volume;
     Meter factor, indicating if it is a composite meter 
factor;
     Total gross standard volume removed through the LACT 
system or CMS;
     API oil gravity;
     The average temperature in [deg]F;
     The average flowing pressure in psig;
     S&W percent;
     Unique number of each seal removed and installed;
     Name of the purchaser's representative; and
     Name of the operator.

Request To Use Alternate Oil Measurement System (43 CFR 3174.13)

    Section 3174.13 requires prior BLM approval for any method of oil 
measurement other than manual tank gauging, LACT system, or CMS at an 
FMP. 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 measurement equipment would meet or 
exceed the objectives of the applicable minimum requirements at 43 CFR 
subpart 3174 and would not affect royalty income or production 
accountability.
    The PMT will review and make recommendations in response to 
requests to use alternate oil-measurement equipment. This information 
collection activity enables the BLM to consider approving new 
technologies not yet addressed in its regulations.

Approval for Slop or Waste Oil (43 CFR 3174.14)

    When production cannot be measured due to spillage or leakage, the 
amount of production must be determined by using any method the BLM 
approves or prescribes. This category of production includes, but is 
not limited to, oil that is classified as slop oil or waste oil.

[[Page 81503]]

    No oil may be classified or disposed of as waste oil unless the 
operator can demonstrate to the satisfaction of the BLM that it is not 
economically feasible to put the oil into marketable condition.
    The operator may not sell or otherwise dispose of slop oil without 
prior written approval from the BLM. Following the sale or disposal of 
slop oil, the operator must notify the BLM in writing of the volume 
sold or disposed of and the method used to compute the volume.
    The following table itemizes the estimated hour burdens for this 
rule:

                                             Estimated Hour Burdens
----------------------------------------------------------------------------------------------------------------
                                                                     Number of       Hours per
                        Type of response                             responses       response       Total hours
A.                                                                            B.              C.              D.
----------------------------------------------------------------------------------------------------------------
Request for Exception to Uncertainty Requirements--43 CFR                      5              40             200
 3174.4(a)(2)--One-Time.........................................
Request for Exception to Uncertainty Requirements--43 CFR                      2              40              80
 3174.4(a)(2)--Annual...........................................
Documentation of Tank Calibration Table Strapping--43 CFR                 10,000             .25           2,500
 3174.5(c)(3)--Annual...........................................
Documentation of Testing for Approval of Automatic Tank Gauging                5              80             400
 (ATG) Equipment--43 CFR 3174.6(b)(5)(ii)(A)--One-Time..........
Documentation of Testing for Approval of Automatic Tank Gauging                1              80              80
 (ATG) Equipment--43 CFR 3174.6(b)(5)(ii)(A)--Annual............
Log of ATG Verification--43 CFR 3174.6(b)(5)(ii)(C)--Annual.....              18             0.1             1.8
Notification of LACT System Failure--43 CFR 3174.7(e)(1)--Annual             100            0.25              25
Documentation of Testing for Approval of a Positive Displacement              10              80             800
 (PD) Meter--43 CFR 3174.8(a)(1)--One-Time......................
Documentation of Testing for Approval of a Positive Displacement               1              80              80
 (PD) Meter--43 CFR 3174.8(a)(1)--Annual........................
Documentation of Testing for Approval of a Coriolis Meter 43 CFR              10              80             800
 3174.9(b)--One Time............................................
Documentation of Testing for Approval of a Coriolis Meter 43 CFR               1              80              80
 3174.9(b)--Annual..............................................
Documentation of Zero Verification Procedure--43 CFR                         100             0.1              10
 3174.10(b)(2) and (d)--Annual..................................
Zero Verification Log--43 CFR 3174.10(b)(2) and (e)(4)--Annual..             100             0.1              10
Audit Trail Requirements for Coriolis Measurement System (CMS)--             500            0.25             125
 43 CFR 3174.10(b)(2) and (f)--Annual...........................
Onsite Data Display Requirements--43 CFR 3174.10(e)--Annual.....             500             0.1              50
Meter Prover Calibration Documentation--43 CFR 3174.11(b)--                  150             0.5              75
 Annual.........................................................
Meter Proving and Volume Adjustments Notification--43 CFR                     60             0.1               6
 3174.11(i)(1)--Annual..........................................
Meter Proving Reports--43 CFR 3174.11(i)(3)--Annual.............             123            0.25              31
Request to Use Alternate Oil Measurement System--43 CFR 3174.13--              5              80             400
 One Time.......................................................
Request to Use Alternate Oil Measurement System--43 CFR 3174.13--              1              80              80
 Annual.........................................................
Approval for Slop or Waste Oil--43 CFR 3174.14--Annual..........              50               1              50
                                                                 -----------------------------------------------
    Total Annual Costs..........................................          11,707  ..............           3,284
                                                                 -----------------------------------------------
    Total One-Time Costs........................................              35  ..............           2,600
----------------------------------------------------------------------------------------------------------------

National Environmental Policy Act (NEPA)

    The BLM prepared an environmental assessment (EA), a Finding of No 
Significant Impact (FONSI), and a Decision Record (DR) that conclude 
that the final rule would not constitute a major Federal action 
significantly affecting the quality of the human environment under 
NEPA, 42 U.S.C. 4332(2)(C). Therefore, a detailed environmental impact 
statement (EIS) under NEPA is not required. A copy of the EA, FONSI, 
and DR are available for review and on file in the BLM Administrative 
Record at the location specified in the ADDRESSES section.
    As explained in the EA, FONSI, and DR, the final rule would not 
have a significant effect on the human environment because, for the 
most part, its requirements involve changes that are of an 
administrative, technical, or procedural nature that apply to the BLM's 
and the lessee's or operator's administrative processes. For example, 
the rule allows operators to use a CMS or an ATG/hybrid tank 
measurement system without receiving a variance from the BLM as they 
must do now. The final rule also adopts a process and criteria that 
will allow for the PMT to review any new measurement system or method 
approval requests submitted to the BLM.
    Overall 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 standards, 
such as the requirement that operators replace their automatic 
temperature/gravity compensators with temperature averaging devices, 
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 final EA.
    A draft of the EA was shared with the public during the public 
comment period on the proposed rule. As part of that process, the BLM 
received comments on the EA. Commenters questioned the BLM's level of 
NEPA documentation, whether or not the BLM had met the ``hard look'' 
test of describing the environmental consequences of the proposed 
action, and the BLM's ability to reach a FONSI based on the level of 
analysis. One commenter requested a complete NEPA revision with formal 
scoping of the EA and a meaningful socioeconomic analysis. Many 
commenters questioned the use of three separate EAs to disclose impacts 
of Order 3, Order 4, and Order 5, stating that the Council on 
Environmental Quality (CEQ) regulations require connected actions to be 
evaluated in a single document. These commenters suggested a single EIS 
to address all three rules.
    CEQ's NEPA regulations at 40 CFR 1508.18 identify new or revised 
agency rules and regulations as an example of a Federal action. 
Drafting new agency regulations that ``are of an administrative . . . 
technical, or

[[Page 81504]]

procedural nature'' is categorically excluded from NEPA review pursuant 
to 43 CFR 46.210(i). The BLM nevertheless chose to complete a more 
robust level of NEPA documentation in the form of an EA. By preparing a 
separate EA for new subpart 3173, 3174, and 3175 regulations, the BLM 
was able to disclose the potential environmental effects of the Federal 
agency decisions on each of the regulations. Clearly, the BLM's level 
of analysis was more thorough than the categorical exclusion 
documentation required by NEPA. Additionally, a thorough socioeconomic 
analysis was completed in the BLM's regulatory impact analysis of the 
proposed rule, which was referenced in the EA.
    Other commenters stated the BLM did not adequately address 
potential surface impacts to private land, minimized environmental 
surface impacts, did not address a reasonable range of alternatives, 
and did not adequately describe the Affected Environment. The BLM 
anticipates that in the majority of cases, operators will use existing 
surface disturbances such as existing well pad locations in connection 
with activities undertaken in compliance with the final rule, which 
will minimize new surface construction and surface impacts. Any new 
facilities will likely be constructed on a lease, relocated to an 
existing facility, or retrofitted to an existing facility. Similarly, 
the codification of BLM regulations does not hinder or prevent 
development of private minerals. The likelihood of impacts to private 
surface is low. In the rare instance that new pipelines or other 
facilities must be developed on private surface to comply with this 
rule, BLM authorization for activities on split estate would include 
site-specific NEPA documentation, with appropriate project-level 
mitigation. The BLM's obligation under NEPA is to analyze alternatives 
that would meet the Bureau's purpose and need and allow for a reasoned 
choice to be made. As described in the EA, a number of alternatives 
were considered, but eliminated from detailed study because they did 
not meet the purpose and need. Discussion of the affected environment 
should only contain data and analysis commensurate in detail with the 
importance of the impacts, which the BLM anticipates to be minimal.
    The EA, FONSI, and DR were updated to address these comments, but 
the updates did not change the BLM's overall 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 rule amends the BLM's oil production regulations, it 
will 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 rule strengthen the BLM's production 
accountability requirements for operators holding Federal and Indian 
oil leases. As discussed previously, among other things, this rule 
establishes objective measurement performance standards, updates 
recordkeeping requirements, and establishes uniform national 
requirements for operators who wish to use CMSs or ATG systems. As 
explained in detail in the BLM's regulatory impact analysis, all of 
these changes will increase the regulated community's annual costs by 
about $3.9 million, or about $1,055 per entity per year.
    The BLM expects that the rule will 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 rule, the BLM did not conduct or use a study, 
experiment, or survey requiring peer review under the Information 
Quality Act (Pub. L. 106-554, Appendix C Title IV, 515, 114 Stat. 
2763A-153).

Authors

    The principal authors of this final rule are Mike McLaren, 
Petroleum Engineer, BLM Pinedale Field Office; Tom Zelenka, Petroleum 
Engineer, BLM New Mexico State Office; Chris DeVault, I&E Coordinator, 
BLM Montana State Office; Jeff Prude, Petroleum Engineer, BLM 
Bakersfield Field Office; and Frank Sanders, Petroleum Engineer, BLM 
Worland Field Office. The team was assisted by Faith Bremner, Jean 
Sonneman and Ian Senio, Office of Regulatory Affairs, BLM Washington 
Office; Michael Ford, Economist, BLM Washington Office; Barbara 
Sterling, Natural Resource Specialist, BLM Colorado State Office; Bryce 
Barlan, Senior Policy Analyst, BLM, Washington Office; Michael Wade, 
BLM Washington Office; Rich Estabrook, BLM Washington Office; Dylan 
Fuge, Counselor to the Director, BLM Washington Office; Christopher 
Rhymes, Attorney Advisor, Office of the Solicitor, Department of the 
Interior; and Geoffrey Heath (now retired).

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: October 6, 2016.
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 is amending 43 CFR parts 3160 and 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 for part 3170 continues to read as follows:

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


0
5. Add subpart 3174 to part 3170, to read as follows:

[[Page 81505]]

Subpart 3174--Measurement of Oil

Sec.
3174.1 Definitions and acronyms.
3174.2 General requirements.
3174.3 Incorporation by reference (IBR).
3174.4 Specific measurement performance requirements.
3174.5 Oil measurement by tank gauging--general requirements.
3174.6 Oil measurement by 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 meter for LACT and CMS measurement applications--
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 14.696 pounds per square inch, absolute (psia).
    Base temperature means 60 [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 CMS.
    Coriolis meter means a device which by means of the interaction 
between a flowing fluid and oscillation of tube(s) infers a mass flow 
rate. The meter also infers the density by measuring the natural 
frequency of the oscillating tubes. The Coriolis meter consists of 
sensors and a transmitter, which convert 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 
gross standard 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.
    Dynamic meter factor means a kinetic meter factor derived by linear 
interpolation or polynomial fit, used for conditions where a series of 
meter factors have been determined over a range of normal operating 
conditions.
    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.
    Indicated volume means the uncorrected volume indicated by the 
meter in a lease automatic custody transfer system or the Coriolis 
meter in a CMS. For a positive displacement meter, the indicated volume 
is represented by the non-resettable totalizer on the meter head. For 
Coriolis meters, the indicated volume is the uncorrected (without the 
meter factor) mass of liquid divided by the density.
    Innage 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(s), unit PA(s), or CA(s) 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) line 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 line 
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.
    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.
    Tertiary device means, for a CMS, the flow computer and associated 
memory, calculation, and display functions.
    Transducer means an electronic device that converts a physical 
property, such as pressure, temperature, or electrical resistance, into 
an electrical output signal that varies proportionally with the 
magnitude of the physical property. Typical output signals are in the 
form of electrical potential (volts), current (milliamps), or digital 
pressure or temperature readings. The term transducer includes devices 
commonly referred to as transmitters.
    Vapor tight means capable of holding pressure differential only 
slightly higher than that of installed pressure-relieving or vapor 
recovery devices.
    (b) As used in this subpart, the following acronyms carry the 
meaning prescribed:
    API means American Petroleum Institute.
    CA has the meaning set forth in Sec.  3170.3 of this part.
    COA has the meaning set forth in Sec.  3170.3 of this part.
    CPL means correction for the effect of pressure on a liquid.
    CTL means correction for the effect of temperature on a liquid.
    NIST means National Institute of Standards and Technology.
    PA has the meaning set forth in Sec.  3170.3 of this part.
    PMT means Production Measurement Team.
    PSIA means pounds per square inch, absolute.
    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 PA, or CA, unless 
approval for off-lease measurement is obtained under Sec. Sec.  3173.22 
and 3173.23 of this part.
    (c) Oil produced from a lease, unit PA, or CA may not be commingled 
with

[[Page 81506]]

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 
tank gauging, LACT system, CMS, or other approved metering device), 
except as provided in paragraph (h) of this section.
    (e) Except as provided in paragraph (h) of this section, all 
equipment used to measure the volume of oil for royalty purposes 
installed after January 17, 2017 must comply with the requirements of 
this subpart.
    (f) Except as provided in paragraph (h) of this section, measuring 
procedures and equipment used to measure oil for royalty purposes, that 
is in use on January 17, 2017, must comply with the requirements of 
this subpart on or before the date the operator is required to apply 
for an FMP number under 3173.12(e) of this part. Prior to that date, 
measuring procedures and equipment used to measure oil for royalty 
purposes, that is in use on January 17, 2017 must continue to comply 
with the requirements of Onshore Oil and Gas Order No. 4, Measurement 
of oil, Sec.  3164.1(b) as contained in 43 CFR part 3160, (revised 
October 1, 2016), and any COAs and written orders applicable to that 
equipment.
    (g) The requirement to follow the approved equipment lists 
identified in Sec. Sec.  3174.6(b)(5)(ii)(A), 3174.6(b)(5)(iii), 
3174.8(a)(1), and 3174.9(a) does not apply until January 17, 2019. The 
operator or manufacturer must obtain approval of a particular make, 
model, and size by submitting the test data used to develop performance 
specifications to the PMT to review.
    (h) Meters used for allocation under a commingling and allocation 
approval under Sec.  3173.14 are not required to meet the requirements 
of this subpart.


Sec.  3174.3  Incorporation by reference (IBR).

    (a) Certain material specified in 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 
listed in this section. To enforce any edition other than that 
specified in this section, the BLM must publish a rule in the Federal 
Register, and the material must be reasonably available to the public. 
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; at all BLM offices with jurisdiction over oil and 
gas activities; and is available from the sources listed below. 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.
    (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 http://publications.api.org.
    (1) API Manual of Petroleum Measurement Standards (MPMS) Chapter 
2--Tank Calibration, Section 2A, Measurement and Calibration of Upright 
Cylindrical Tanks by the Manual Tank Strapping Method; First Edition, 
February 1995; Reaffirmed February 2012 (``API 2.2A''), IBR approved 
for Sec.  3174.5(c).
    (2) API MPMS Chapter 2--Tank Calibration, Section 2.2B, Calibration 
of Upright Cylindrical Tanks Using the Optical Reference Line Method; 
First Edition, March 1989, Reaffirmed January 2013 (``API 2.2B''), IBR 
approved for Sec.  3174.5(c).
    (3) API MPMS Chapter 2--Tank Calibration, Section 2C, Calibration 
of Upright Cylindrical Tanks Using the Optical-triangulation Method; 
First Edition, January 2002; Reaffirmed May 2008 (``API 2.2C''), IBR 
approved for Sec.  3174.5(c).
    (4) API MPMS Chapter 3, Section 1A, Standard Practice for the 
Manual Gauging of Petroleum and Petroleum Products; Third Edition, 
August 2013 (``API 3.1A''), IBR approved for Sec. Sec.  3174.5(b), 
3174.6(b).
    (5) API MPMS Chapter 3--Tank Gauging, Section 1B, Standard Practice 
for Level Measurement of Liquid Hydrocarbons in Stationary Tanks by 
Automatic Tank Gauging; Second Edition, June 2001; Reaffirmed August 
2011 (``API 3.1B''), IBR approved for Sec.  3174.6(b).
    (6) API MPMS Chapter 3--Tank Gauging, Section 6, Measurement of 
Liquid Hydrocarbons by Hybrid Tank Measurement Systems; First Edition, 
February 2001; Errata September 2005; Reaffirmed October 2011 (``API 
3.6''), IBR approved for Sec.  3174.6(b).
    (7) API MPMS Chapter 4--Proving Systems, Section 1, Introduction; 
Third Edition, February 2005; Reaffirmed June 2014 (``API 4.1''), IBR 
approved for Sec.  3174.11(c).
    (8) API MPMS Chapter 4--Proving Systems, Section 2, Displacement 
Provers; Third Edition, September 2003; Reaffirmed March 2011, Addendum 
February 2015 (``API 4.2''), IBR approved for Sec. Sec.  3174.11(b) and 
(c).
    (9) API MPMS Chapter 4, Section 5, Master-Meter Provers; Fourth 
Edition, June 2016, (``API 4.5''), IBR approved for Sec.  3174.11(b).
    (10) API MPMS Chapter 4--Proving Systems, Section 6, Pulse 
Interpolation; Second Edition, May 1999; Errata April 2007; Reaffirmed 
October 2013 (``API 4.6''), IBR approved for Sec.  3174.11(c).
    (11) API MPMS Chapter 4, Section 8, Operation of Proving Systems; 
Second Edition, September 2013 (``API 4.8''), IBR approved for Sec.  
3174.11(b).
    (12) API MPMS Chapter 4--Proving Systems, Section 9, Methods of 
Calibration for Displacement and Volumetric Tank Provers, Part 2, 
Determination of the Volume of Displacement and Tank Provers by the 
Waterdraw Method of Calibration; First Edition, December 2005; 
Reaffirmed July 2015 (``API 4.9.2''), IBR approved for Sec.  
3174.11(b).
    (13) API MPMS Chapter 5--Metering, Section 6, Measurement of Liquid 
Hydrocarbons by Coriolis Meters; First Edition, October 2002; 
Reaffirmed November 2013 (``API 5.6''), IBR approved for Sec. Sec.  
3174.9(e), 3174.11(h) and (i).
    (14) API MPMS Chapter 6--Metering Assemblies, Section 1, Lease 
Automatic Custody Transfer (LACT) Systems; Second Edition, May 1991; 
Reaffirmed May 2012 (``API 6.1''), IBR approved for Sec.  3174.8(a) and 
(b).
    (15) API MPMS Chapter 7, Temperature Determination; First Edition, 
June 2001, Reaffirmed February 2012 (``API 7''), IBR approved for 
Sec. Sec.  3174.6(b), 3174.8(b).
    (16) API MPMS Chapter 7.3, Temperature Determination--Fixed 
Automatic Tank Temperature Systems; Second Edition, October 2011 (``API 
7.3''), IBR approved for Sec.  3174.6(b).
    (17) API MPMS Chapter 8, Section 1, Standard Practice for Manual 
Sampling of Petroleum and Petroleum Products; Fourth Edition, October 
2013 (``API 8.1''), IBR approved for Sec. Sec.  3174.6(b), 3174.11(h).
    (18) API MPMS Chapter 8, Section 2, Standard Practice for Automatic 
Sampling of Petroleum and Petroleum Products; Third Edition, October 
2015 (``API 8.2''), IBR approved for Sec. Sec.  3174.6(b), 3174.8(b), 
3174.11(h).
    (19) API MPMS Chapter 8--Sampling, Section 3, Standard Practice for 
Mixing

[[Page 81507]]

and Handling of Liquid Samples of Petroleum and Petroleum Products; 
First Edition, October 1995; Errata March 1996; Reaffirmed, March 2010 
(``API 8.3''), IBR approved for Sec. Sec.  3174.8(b), 3174.11(h).
    (20) API MPMS Chapter 9, Section 1, Standard Test Method for 
Density, Relative Density, or API Gravity of Crude Petroleum and Liquid 
Petroleum Products by Hydrometer Method; Third Edition, December 2012 
(``API 9.1''), IBR approved for Sec. Sec.  3174.6(b), 3174.8(b).
    (21) API MPMS Chapter 9, Section 2, Standard Test Method for 
Density or Relative Density of Light Hydrocarbons by Pressure 
Hydrometer; Third Edition, December 2012 (``API 9.2''), IBR approved 
for Sec. Sec.  3174.6(b), 3174.8(b).
    (22) 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; Third Edition, 
December 2012 (``API 9.3''), IBR approved for Sec. Sec.  3174.6(b), 
3174.8(b).
    (23) API MPMS Chapter 10, Section 4, Determination of Water and/or 
Sediment in Crude Oil by the Centrifuge Method (Field Procedure); 
Fourth Edition, October 2013; Errata March 2015 (``API 10.4''), IBR 
approved for Sec. Sec.  3174.6(b), 3174.8(b).
    (24) API MPMS Chapter 11--Physical Properties Data, Section 1, 
Temperature and Pressure Volume Correction Factors for Generalized 
Crude Oils, Refined Products and Lubricating Oils; May 2004, Addendum 1 
September 2007; Reaffirmed August 2012 (``API 11.1''), IBR approved for 
Sec. Sec.  3174.9(f), 3174.12(a).
    (25) API MPMS Chapter 12--Calculation of Petroleum Quantities, 
Section 2, Calculation of Petroleum Quantities Using Dynamic 
Measurement Methods and Volumetric Correction Factors, Part 1, 
Introduction; Second Edition, May 1995; Reaffirmed March 2014 (``API 
12.2.1''), IBR approved for Sec. Sec.  3174.8(b), 3174.9(g).
    (26) API MPMS Chapter 12--Calculation of Petroleum Quantities, 
Section 2, Calculation of Petroleum Quantities Using Dynamic 
Measurement Methods and Volumetric Correction Factors, Part 2, 
Measurement Tickets; Third Edition, June 2003; Reaffirmed September 
2010 (``API 12.2.2''), IBR approved for Sec. Sec.  3174.8(b), 
3174.9(g).
    (27) API MPMS Chapter 12--Calculation of Petroleum Quantities, 
Section 2, Calculation of Petroleum Quantities Using Dynamic 
Measurement Methods and Volumetric Correction Factors, Part 3, Proving 
Report; First Edition, October 1998; Reaffirmed March 2009 (``API 
12.2.3''), IBR approved for Sec.  3174.11(c) and (i).
    (28) API MPMS Chapter 12--Calculation of Petroleum Quantities, 
Section 2, Calculation of Petroleum Quantities Using Dynamic 
Measurement Methods and Volumetric Correction Factors, Part 4, 
Calculation of Base Prover Volumes by the Waterdraw Method; First 
Edition, December 1997; Reaffirmed March 2009; Errata July 2009 (``API 
12.2.4''), IBR approved for Sec.  3174.11(b).
    (29) API MPMS Chapter 13--Statistical Aspects of Measuring and 
Sampling, Section 1, Statistical Concepts and Procedures in 
Measurements; First Edition, June 1985 Reaffirmed February 2011; Errata 
July 2013 (``API 13.1''), IBR approved for Sec.  3174.4(a).
    (30) API MPMS Chapter 13, Section 3, Measurement Uncertainty; First 
Edition, May, 2016 (``API 13.3''), IBR approved for Sec.  3174.4(a).
    (31) API MPMS Chapter 14, Section 3, Orifice Metering of Natural 
Gas and Other Related Hydrocarbon Fluids--Concentric, Square-edged 
Orifice Meters, Part 1, General Equations and Uncertainty Guidelines; 
Fourth Edition, September 2012; Errata July 2013 (``API 14.3.1''), IBR 
approved for Sec.  3174.4(a).
    (32) API MPMS Chapter 18--Custody Transfer, Section 1, Measurement 
Procedures for Crude Oil Gathered From Small Tanks by Truck; Second 
Edition, April 1997; Reaffirmed February 2012 (``API 18.1''), IBR 
approved for Sec.  3174.6(b).
    (33) API MPMS Chapter 18, Section 2, Custody Transfer of Crude Oil 
from Lease Tanks Using Alternative Measurement Methods, First Edition, 
July 2016 (``API 18.2''), IBR approved for Sec.  3174.6(b).
    (34) API MPMS Chapter 21--Flow Measurement Using Electronic 
Metering Systems, Section 2, Electronic Liquid Volume Measurement Using 
Positive Displacement and Turbine Meters; First Edition, June 1998; 
Reaffirmed August 2011 (``API 21.2''), IBR approved for Sec. Sec.  
3174.8(b), 3174.9(f), 3174.10(f).
    (35) API Recommended Practice (RP) 12R1, Setting, Maintenance, 
Inspection, Operation and Repair of Tanks in Production Service; Fifth 
Edition, August 1997; Reaffirmed April 2008 (``API RP 12R1''), IBR 
approved for Sec.  3174.5(b).
    (36) API RP 2556, Correction Gauge Tables For Incrustation; Second 
Edition, August 1993; Reaffirmed November 2013 (``API RP 2556''), IBR 
approved for Sec.  3174.5(c).

    Note 1 to Sec.  3174.3(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.  3174.4  Specific measurement performance requirements.

    (a) Volume measurement uncertainty levels. (1) The FMP must achieve 
the following overall uncertainty levels as calculated in accordance 
with statistical concepts described in API 13.1, the methodologies in 
API 13.3, and the quadrature sum (square root of the sum of the 
squares) method described in API 14.3.1, Subsection 12.3 (all 
incorporated by reference, see Sec.  3174.3) or other methods approved 
under paragraph (d):

     Table 1 to Sec.   3174.4--Volume Measurement Uncertainty Levels
------------------------------------------------------------------------
                                                The overall  volume
  If the averaging period  volume (see     measurement  uncertainty must
     definition  43 CFR 3170.3) is:                 be within:
------------------------------------------------------------------------
1. Greater than or equal to 30,000 bbl/   0.50 percent.
 month.
2. Less than 30,000 bbl/month...........  1.50 percent.
------------------------------------------------------------------------

    (2) 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 PMT, prepared in coordination with 
the Deputy Director.
    (b) Bias. The measuring equipment used for volume determinations 
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) Alternative equipment. The PMT will make a determination under 
Sec.  3174.13 of this subpart regarding whether proposed alternative 
equipment or measurement procedures meet or exceed the objectives and 
intent of this section.

[[Page 81508]]

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

    (a) Measurement objective. Oil measurement by tank gauging must 
accurately compute the total net standard volume of oil withdrawn from 
a properly calibrated sales tank by following the activities prescribed 
in Sec.  3174.6 and the requirements of Sec.  3174.4 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 
comply with the recommended practices listed in API RP 12R1 
(incorporated by reference, see Sec.  3174.3).
    (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. Unless connected to a vapor recovery or 
flare system, all tanks must have a pressure-vacuum relief valve 
installed at the highest point in the vent line or connection with 
another tank. All hatches, connections, and other access points must be 
installed and maintained in accordance with manufacturers' 
specifications.
    (4) All oil storage tanks must be clearly identified and have an 
operator-generated number unique to the lease, unit PA, or CA, 
stenciled on the tank and maintained in a legible condition.
    (5) Each oil storage tank associated with an approved FMP that has 
a tank-gauging system must be set and maintained level.
    (6) Each oil storage tank associated with an approved FMP that has 
a tank-gauging system must be equipped with a distinct gauging 
reference point, consistent with API 3.1A (incorporated by reference, 
see Sec.  3174.3). The height of the reference point must be stamped on 
a fixed bench-mark plate or stenciled on the tank near the gauging 
hatch, and be maintained in a legible condition.
    (c) Sales tank calibrations. The operator must accurately calibrate 
each oil storage tank associated with an approved FMP that has a tank-
gauging system using either API 2.2A, API 2.2B, or API 2.2C; and API RP 
2556 (all incorporated by reference, see Sec.  3174.3). 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 match gauging 
increments specified in Sec.  3174.6(b)(5)(i)(C);
    (2) Recalibrate a sales tank if it is relocated or 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 45 days after calibration. Tank tables may be in paper or 
electronic format.


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

    (a) The procedures for oil measurement by tank gauging must comply 
with the requirements outlined in this section.
    (b) The operator must follow the procedures identified in API 18.1 
or API 18.2 (both incorporated by reference, see Sec.  3174.3) as 
further specified in this paragraph to determine the quality and 
quantity of oil measured under field conditions at an FMP.
    (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 (iii) of this section, API 7, and API 7.3 
(both incorporated by reference, see Sec.  3174.3). Opening temperature 
may be determined before, during, or after sampling.
    (i) Glass thermometers must be clean, be free of fluid separation, 
have a minimum graduation of 1.0 [deg]F, and have an accuracy of 0.5 [deg]F.
    (ii) Electronic thermometers must have a minimum graduation of 0.1 
[deg]F and have an accuracy of 0.5 [deg]F.
    (iii) 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 operations must be conducted prior 
to taking the opening gauge unless automatic sampling methods are being 
used. Sampling of oil removed from an FMP tank must yield a 
representative sample of the oil and its physical properties and must 
comply with API 8.1 or API 8.2 (both incorporated by reference, see 
Sec.  3174.3).
    (4) Determine observed oil gravity. Tests for oil gravity must 
comply with paragraphs (b)(4)(i) through (iii) of this section and API 
9.1, API 9.2, or API 9.3 (all incorporated by reference, see Sec.  
3174.3).
    (i) The hydrometer or thermohydrometer (as applicable) 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) Allow the temperature to stabilize for at least 5 minutes 
prior to reading the thermometer.
    (iii) Read and record the observed API oil gravity to the nearest 
0.1 degree. Read and record the temperature reading to the nearest 1.0 
[deg]F.
    (5) Measure the opening tank fluid level. Take and record the 
opening gauge only after samples have been taken, unless automatic 
sampling methods are being used. Gauging must comply with either 
paragraph (b)(5)(i) of this section, API 3.1A, and API 18.1 (both 
incorporated by reference, see Sec.  3174.3); or paragraph (b)(5)(ii) 
of this section, API 3.1B, API 3.6, and API 18.2 (all incorporated by 
reference, see Sec.  3174.3); or paragraph (b)(5)(iii) of this section 
for dynamic volume determination.
    (i) For manual gauging, comply with the requirements of API 3.1A 
and API 18.1 (both incorporated by reference, see Sec.  3174.3) and the 
following:
    (A) The proper bob must be used for the particular measurement 
method, i.e., either innage gauging or outage gauging;
    (B) A gauging tape must be used. The gauging tape must be made of 
steel or corrosion-resistant material with graduation clearly legible, 
and must not be kinked or spliced;
    (C) Either obtain two consecutive identical gauging measurements 
for any tank regardless of size, or:
    (1) For tanks of 1,000 bbl or less in capacity, three consecutive 
measurements that are within 1/4-inch of each other and average these 
three measurements to the nearest \1/4\ inch; or
    (2) For tanks greater than 1,000 bbl in capacity, three consecutive 
measurements within \1/8\ inch of each other, averaging these three 
measurements to the nearest \1/8\ inch.
    (D) A suitable product-indicating paste may be used on the tape to 
facilitate the reading. The use of chalk or talcum powder is 
prohibited; and
    (E) The same tape and bob must be used for both opening and closing 
gauges.
    (ii) For automatic tank gauging (ATG), comply with the requirements 
of API 3.1B, API 3.6, and API 18.2 (all incorporated by reference, see 
Sec.  3174.3) and the following:
    (A) The specific makes and models of ATG that are identified and 
described at www.blm.gov are approved for use;
    (B) The ATG must be inspected and its accuracy verified to within 
\1/4\ inch in accordance with API 3.1B, Subsection 9 
(incorporated by reference, see Sec.  3174.3) at least once a month or

[[Page 81509]]

prior to sales, whichever is latest, or any time at the request of the 
AO. If the ATG is found to be out of tolerance, the ATG must be 
calibrated prior to sales; and
    (C) A log of field verifications must be maintained and available 
upon request. The log must include the following information: The date 
of verification; the as-found manual gauge readings; the as-found ATG 
readings; and whether the ATG was field calibrated. If the ATG was 
field calibrated, the as-left manual gauge readings and as-left ATG 
readings must be recorded.
    (iii) For dynamic volume determination under API 18.2, Subsection 
10.1.1, (incorporated by reference, see Sec.  3174.3), the specific 
makes and models of in-line meters that are identified and described at 
www.blm.gov are approved for use.
    (6) Determine S&W content. Using the oil samples obtained pursuant 
to paragraph (b)(3) of this section, determine the S&W content of the 
oil in the sales tanks, according to API 10.4 (incorporated by 
reference, see Sec.  3174.3).
    (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. Following procedures in Sec.  
3174.12.


Sec.  3174.7  LACT system--general requirements.

    (a) A LACT system must meet the construction and operation 
requirements and minimum standards of this section, Sec.  3174.8, and 
Sec.  3174.4.
    (b) A LACT system must be proven as prescribed in Sec.  3174.11 of 
this subpart.
    (c) Measurement tickets must be completed under Sec.  3174.12(b) of 
this subpart.
    (d) All components of a LACT system must be accessible for 
inspection by the AO.
    (e)(1) The operator must notify the AO, within 72 hours after 
discovery, of any LACT system failures or equipment malfunctions that 
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.  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 equipment listed in API 6.1 (incorporated by reference, see Sec.  
3174.3), with the following exceptions:
    (1) The custody transfer meter must be a positive displacement 
meter or a Coriolis meter. The specific make, models, and sizes of 
positive displacement or Coriolis meter and associated software that 
are identified and described at www.blm.gov are approved for use.
    (2) An electronic temperature averaging device must be installed.
    (3) Meter back pressure must be applied by a back pressure valve or 
other controllable means of applying back pressure to ensure single-
phase flow.
    (b) LACT system operating requirements. Operation of all LACT 
system components must meet the requirements of API 6.1 (incorporated 
by reference, see Sec.  3174.3) and the following:
    (1) Sampling must be conducted according to API 8.2 and API 8.3 
(both incorporated by reference, see Sec.  3174.3) and the following:
    (i) The sample extractor probe must be inserted within the center 
half of the flowing stream;
    (ii) The extractor probe must be horizontally oriented; and
    (iii) The external body of the extractor probe must be marked with 
the direction of the flow.
    (2) Any tests conducted on oil samples extracted from LACT system 
samplers for determination of oil gravity and S&W content must meet the 
requirements of either API 9.1, API 9.2, or API 9.3, and API 10.4 (all 
incorporated by reference, see Sec.  3174.3).
    (3) The composite sample container must be emptied and cleaned upon 
completion of sample withdrawal.
    (4) The positive displacement or Coriolis meter (see Sec.  3174.10) 
must be equipped with a non-resettable totalizer. The meter must 
include or allow for the attachment of a device that generates at least 
8,400 pulses per barrel of registered volume.
    (5) The system must have a pressure-indicating device downstream of 
the meter, but upstream of meter-proving connections. The pressure-
indicating device must be capable of providing pressure data to 
calculate the CPL correction factor.
    (6) An electronic temperature averaging device must be installed, 
operated, and maintained as follows:
    (i) The temperature sensor must be placed in compliance with API 7 
(incorporated by reference, see Sec.  3174.3);
    (ii) The electronic temperature averaging device must be volume-
weighted and take a temperature reading following API 21.2, Subsection 
9.2.8 (incorporated by reference, see Sec.  3174.3);
    (iii) The average temperature for the measurement ticket must be 
calculated by the volumetric averaging method using API 21.2, 
Subsection 9.2.13.2a (incorporated by reference, see Sec.  3174.3);
    (iv) The temperature averaging device must have a reference 
accuracy of 0.5[emsp14][deg]F or better, and have a minimum 
graduation of 0.1[emsp14][deg]F; and
    (v) The temperature averaging device must include a display of 
instantaneous temperature and the average temperature calculated since 
the measurement ticket was opened.
    (vi) The average temperature calculated since the measurement 
ticket was opened must be used to calculate the CTL correction factor.
    (7) Determination of net standard volume: Calculate the net 
standard volume at the close of each measurement ticket following the 
guidelines in API 12.2.1 and API 12.2.2 (both incorporated by 
reference, see Sec.  3174.3).


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

    The following Coriolis measurement systems section is intended for 
Coriolis measurement applications independent of LACT measurement 
systems.
    (a) A CMS must meet the requirements and minimum standards of this 
section, Sec.  3174.4, and Sec.  3174.10.
    (b) The specific makes, models, and sizes of Coriolis meters and 
associated software that have been reviewed by the PMT, as provided in 
Sec.  3174.13, approved by the BLM, and identified and described at 
www.blm.gov are approved for use.
    (c) A CMS system must be proven at the frequency and under the 
requirements of Sec.  3174.11 of this subpart.
    (d) Measurement tickets must be completed under Sec.  3174.12(b) of 
this subpart.
    (e) A CMS at an FMP must be installed with the components listed in

[[Page 81510]]

API 5.6 (incorporated by reference, see Sec.  3174.3). Additional 
requirements are as follows:
    (1) The pressure transducer must meet the requirements of Sec.  
3174.8(b)(5) of this subpart.
    (2) Temperature determination must meet the requirements of Sec.  
3174.8(b)(6) of this subpart.
    (3) If nonzero S&W content is to be used in determining net oil 
volume, the sampling system must meet the requirements of Sec.  
3174.8(b)(1) through (3) of this subpart. If no sampling system is 
used, or the sampling system does not meet the requirements of Sec.  
3174.8(b)(1) through (3) of this subpart, the S&W content must be 
reported as zero;
    (4) Sufficient back pressure must be applied to ensure single phase 
flow through the meter.
    (f) 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) Determined from a composite sample taken pursuant to Sec.  
3174.8(b)(1) through (3) of this subpart; or
    (2) Calculated from the average density as measured by the CMS over 
the measurement ticket period under API 21.2, Subsection 9.2.13.2a 
(incorporated by reference, see Sec.  3174.3). Density must be 
corrected to base temperature and pressure using API 11.1 (incorporated 
by reference, see Sec.  3174.3).
    (g) Determination of net standard volume. Calculate the net 
standard volume at the close of each measurement ticket following the 
guidelines in API 12.2.1 and API 12.2.2 (both incorporated by 
reference, see Sec.  3174.3).


Sec.  3174.10  Coriolis meter for LACT and CMS measurement 
applications--operating requirements.

    (a) Minimum electronic pulse level. The Coriolis meter must 
register the volume of oil passing through the meter as determined by a 
system that constantly emits electronic pulse signals representing the 
indicated volume measured. The pulse per unit volume must be set at a 
minimum of 8,400 pulses per barrel.
    (b) Meter specifications. (1) The Coriolis meter specifications 
must 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 volumetric flow rate. 
The specifications must be stated in percent of reading, percent of 
full scale, or units of measure;
    (iv) Design limits for flow rate and pressure; and
    (v) 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) Non-resettable totalizer. The Coriolis meter must have a non-
resettable internal totalizer for indicated volume.
    (d) Verification of meter zero value using the manufacturer's 
specifications. If the indicated flow rate is within the manufacturer's 
specifications for zero stability, no adjustments are required. If the 
indicated flow rate is outside the manufacturer's specification for 
zero stability, the meter's zero reading must be adjusted. After the 
meter's zero has been adjusted, the meter must be proven required by 
Sec.  3174.11. A copy of the zero value verification procedure must be 
made available to the AO upon request.
    (e) Required on-site information. (1) The Coriolis meter display 
must be readable without using data collection units, laptop computers, 
or any special equipment, and must be on-site and accessible to the AO.
    (2) For each Coriolis meter, the following values and corresponding 
units of measurement must be displayed:
    (i) The instantaneous density of liquid (pounds/bbl, pounds/gal, or 
degrees API);
    (ii) The instantaneous indicated volumetric flow rate through the 
meter (bbl/day);
    (iii) The meter factor;
    (iv) The instantaneous pressure (psi);
    (v) The instantaneous temperature ([deg]F);
    (vi) The cumulative gross standard volume through the meter (non-
resettable totalizer) (bbl); and
    (vii) The previous day's gross standard volume through the meter 
(bbl).
    (3) The following information must be correct, 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. The log must be made available upon request.
    (f) Audit trail requirements. The information specified in 
paragraphs (f)(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, Subsection 10 
(incorporated by reference, see Sec.  3174.3). All data must be 
available and submitted to the BLM upon request.
    (1) Quantity transaction record (QTR). Follow the requirements for 
a 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, Subsection 10.2 (incorporated by reference, 
see Sec.  3174.3). 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, Subsection 10.6 (incorporated by reference, see Sec.  
3174.3). 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 was below the manufacturer's minimum 
recommended flow rate.
    (g) Data protection. Each Coriolis meter 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 (f) 
of this section is protected.


Sec.  3174.11  Meter-proving requirements.

    (a) Applicability. This section specifies the minimum requirements 
for

[[Page 81511]]

conducting volumetric meter proving for all FMP meters.
    (b) 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 on site and available for 
review by the AO. The certificate must show 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 0.0005 
(0.05 percent repeatability) as described in API 4.5, Subsection 6.5 
(incorporated by reference, see Sec.  3174.3). The master meter must 
not be mechanically compensated for oil gravity or temperature; its 
readout must indicate units of volume without corrections. The meter 
factor must be documented on the calibration certificate and must be 
calibrated at least once every 12 months. New master meters must be 
calibrated immediately and recalibrated in three months. Master meters 
that have undergone mechanical repairs, alterations, or changes that 
affect the calibration must be calibrated immediately upon completion 
of this work and calibrated again 3 months after this date under API 
4.5, API 4.8, Subsection 10.2, and API 4.8, Annex B (all incorporated 
by reference, see Sec.  3174.3).
    (2) Displacement provers must meet the requirements of API 4.2 
(incorporated by reference, see Sec.  3174.3) and be calibrated using 
the water-draw method under API 4.9.2 (incorporated by reference, see 
Sec.  3174.3), at the calibration frequencies specified in API 4.8, 
Subsection 10.1(b) (incorporated by reference, see Sec.  3174.3).
    (3) The base prover volume of a displacement prover must be 
calculated under API 12.2.4 (incorporated by reference, see Sec.  
3174.3).
    (4) Displacement provers must be sized to obtain a displacer 
velocity through the prover that is within the appropriate range during 
proving under API 4.2, Subsection 4.3.4.2, Minimum Displacer Velocities 
and API 4.2, Subsection 4.3.4.1, Maximum Displacer Velocities 
(incorporated by reference, see Sec.  3174.3).
    (5) Fluid velocity is calculated using API 4.2, Subsection 4.3.4.3, 
Equation 12 (incorporated by reference, see Sec.  3174.3).
    (c) Meter proving runs. Meter proving must follow the applicable 
section(s) of API 4.1, Proving Systems (incorporated by reference, see 
Sec.  3174.3).
    (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;
    (iii) The temperature as measured by the LACT or CMS during the 
proving must be within 10 [deg]F of the normal operating temperature; 
and
    (iv) The gravity of the oil during proving must be within 5[deg] 
API of the normal oil gravity.
    (v) If the normal flow rate, pressure, temperature, or oil gravity 
vary by more than the limits defined in paragraphs (c)(i) through 
(c)(iv) of this section, meter provings must be conducted, at a 
minimum, under the three following conditions: 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, as specified by API 4.2, Subsection 4.3.2 
(incorporated by reference, see Sec.  3174.3), from the positive 
displacement meter or the Coriolis meter, then pulse interpolation must 
be used in accordance with API 4.6 (incorporated by reference, see 
Sec.  3174.3).
    (3) Proving runs must be made until the calculated meter factor or 
meter generated pulses from five consecutive runs match within a 
tolerance of 0.0005 (0.05 percent) between the highest and the lowest 
value in accordance with API 12.2.3, Subsection 9 (incorporated by 
reference, see Sec.  3174.3).
    (4) The new meter factor is the arithmetic average of the meter 
generated pulses or intermediate meter factors calculated from the five 
consecutive runs in accordance with API 12.2.3, Subsection 9 
(incorporated by reference, see Sec.  3174.3).
    (5) Meter factor computations must follow the sequence described in 
API 12.2.3 (incorporated by reference, see Sec.  3174.3).
    (6) If multiple meters factors are determined over a range of 
normal operating conditions, then:
    (i) If all the meter factors determined over a range of conditions 
fall within 0.0020 of each other, then a single meter factor may be 
calculated for that range as the arithmetic average of all the meter 
factors within that range. The full range of normal operating 
conditions may be divided into segments such that all the meter factors 
within each segment fall within a range of 0.0020. In this case, a 
single meter factor for each segment may be calculated as the 
arithmetic average of the meter factors within that segment; or
    (ii) The metering system may apply a dynamic meter factor derived 
(using, e.g., linear interpolation, polynomial fit, etc.) from the 
series of meter factors determined over the range of normal operating 
conditions, so long as no two neighboring meter factors differ by more 
than 0.0020.
    (7) The meter factor must be at least 0.9900 and no more than 
1.0100.
    (8) The initial meter factor for a new or repaired meter must be at 
least 0.9950 and no more than 1.0050.
    (9) For positive displacement meters, the back pressure valve may 
be adjusted after proving only within the normal operating fluid flow 
rate and fluid pressure as described in paragraph (c)(1) of this 
section. If the back pressure valve is adjusted after proving, the 
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 with a Coriolis meter.
    (d) 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) Every 3 months (quarterly) after the last proving, or each time 
the registered volume flowing through the meter, as measured on the 
non-resettable totalizer from the last proving, increases by 75,000 
bbl, whichever comes first, but no more frequently than monthly;
    (3) Meter zeroing (Coriolis meter);
    (4) Modification of mounting conditions;
    (5) A change in fluid temperature that exceeds the transducer's 
calibrated span;
    (6) A change in pressure, density, or flow rate that exceeds the 
operating proving limits;
    (7) The mechanical or electrical components of the meter have been 
changed, repaired, or removed;
    (8) Internal calibration factors have been changed or reprogrammed; 
or
    (9) At the request of the AO.
    (e) Excessive meter factor deviation. (1) If the difference between 
meter factors established in two successive

[[Page 81512]]

provings exceeds 0.0025, the meter must be immediately 
removed from service, checked for damage or wear, adjusted or repaired, 
and reproved 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 (i) of this 
section must clearly show the most recent meter factor and describe all 
subsequent repairs and adjustments.
    (f) Verification of the temperature transducer. As part of each 
required meter proving and upon replacement, the temperature averager 
for a LACT system and the temperature transducer used in conjunction 
with a CMS must be verified against a known standard according to the 
following:
    (1) The temperature averager or temperature transducer 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 temperature transducer must be compared with the reading of the test 
thermometer using one of the following methods:
    (i) The test thermometer must be placed in a test thermometer well 
located not more than 12 from the probe of the temperature 
averager or temperature transducer; or
    (ii) Both the test thermometer and probe of the temperature 
averager or temperature transducer must be placed in an insulated water 
bath. The water bath temperature must be within 20 [deg]F of the normal 
flowing temperature of the oil.
    (3) The displayed reading of instantaneous temperature from the 
temperature averager or the temperature transducer must be compared 
with the reading from the test thermometer. If they differ by more than 
0.5 [deg]F, then the difference in temperatures must be noted on the 
meter proving report and:
    (i) The temperature averager or temperature transducer must be 
adjusted to match the reading of the test thermometer; or
    (ii) The temperature averager or temperature transducer must be 
recalibrated, repaired, or replaced.
    (g) Verification of the pressure transducer (if applicable). (1) As 
part of each required meter proving and upon replacement, the pressure 
transducer must be compared with a test pressure device (dead weight or 
pressure gauge) traceable to NIST and with a stated maximum uncertainty 
of no more than one-half of the accuracy required from the transducer 
being verified.
    (2) The pressure reading displayed on the pressure transducer 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) 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 pressure transducer vary by more than the 
required accuracy of the pressure transducer, the pressure transducer 
must be adjusted to read within the stated accuracy of the test 
pressure device.
    (h) Density verification (if applicable). As part of each required 
meter proving, 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, Subsection 9.1.2.1 (incorporated by reference, 
see Sec.  3174.3). The difference between the indicated density 
determined from the Coriolis meter and the independently determined 
density must be within the specified density reference accuracy 
specification of the Coriolis meter. Sampling must be performed in 
accordance with API 8.1, API 8.2, or API 8.3 (incorporated by 
reference, see Sec.  3174.3), as appropriate.
    (i) 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.  3174.3), 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 (i)(1) 
of this section, each meter-proving report must also show the:
    (i) Unique meter ID 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 temperature transducer;
    (iv) For pressure transducers, the pressure applied by the pressure 
test device and the pressure reading from the pressure transducer at 
the three points required under paragraph (g)(3) of this section;
    (v) For density verification (if applicable), the instantaneous 
flowing density (as determined by Coriolis meter), and the independent 
density measurement, as compared under paragraph (h) of this section; 
and
    (vi) The ``as left'' fluid flow rate and fluid pressure, if the 
back pressure valve is adjusted after proving as described in paragraph 
(c)(9) of this section.
    (3) The operator must submit the meter-proving report to the AO no 
later than 14 days after the meter proving. The proving report may be 
either in a hard copy or electronic format.


Sec.  3174.12  Measurement tickets.

    (a) Tank gauging. After oil is measured by 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 PA, or CA number;
    (2) Unique tank number and nominal tank capacity;
    (3) Opening and closing dates and times;
    (4) Opening and closing gauges and observed temperatures in [deg]F;
    (5) Observed volume for opening and closing gauge, using tank 
specific calibration charts (see Sec.  3174.5(c));
    (6) Total gross standard volume removed from the tank following API 
11.1 (incorporated by reference, see Sec.  3174.3);
    (7) Observed API oil gravity and temperature in [deg]F;
    (8) API oil gravity at 60 [deg]F, following API 11.1 (incorporated 
by reference, see Sec.  3174.3);
    (9) S&W content percent;
    (10) Unique number of each seal removed and installed;
    (11) Name of the individual performing the tank gauging; and
    (12) Name of the operator.
    (b) LACT system and CMS. (1) At the beginning of every month, and, 
unless the operator is using a flow computer under Sec.  3174.10, 
before conducting proving operations on a LACT system, 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 PA, or CA number;

[[Page 81513]]

    (ii) Unique meter ID number;
    (iii) Opening and closing dates;
    (iv) Opening and closing totalizer readings of the indicated 
volume;
    (v) Meter factor, indicating if it is a composite meter factor;
    (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 observed API oil gravity and temperature must be 
indicated in [deg]F and the API oil gravity must be indicated at 60 
[deg]F. For API oil gravity determined from average density (CMS only), 
the average uncorrected density must be determined by the CMS;
    (viii) The average temperature in [deg]F;
    (ix) The average flowing pressure in psig;
    (x) S&W content percent;
    (xi) Unique number of each seal removed and installed;
    (xii) Name of the purchaser's representative; and
    (xiii) Name of the operator.
    (2) Any 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 tank gauging, LACT 
system, or CMS at an FMP requires prior BLM approval.
    (b)(1) Any operator requesting approval to use alternate oil 
measurement equipment or measurement method 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 or method 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 or method meets the requirements of 
this subpart and will make a recommendation to the BLM to approve use 
of the equipment or method, disapprove use of the equipment or method, 
or approve use of the equipment or method with conditions for its use. 
If the PMT recommends, and the BLM approves new equipment or methods, 
the BLM will post the make, model, range or software version (as 
applicable), or method on the BLM Web site www.blm.gov as being 
appropriate for use at an FMP for oil measurement without further 
approval by the BLM, subject to any conditions of approval identified 
by the PMT and approved by the BLM.
    (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.
    (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.

Table 1 to Sec.   3174.15--Violations Subject to an Immediate Assessment
------------------------------------------------------------------------
              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 of this subpart...........
2. Failure to notify the AO within 72 hours, as required           1,000
 by Sec.   3174.7(e) of this subpart, of any FMP LACT
 system failure or equipment malfunction resulting in
 use of an unapproved alternate method of measurement...
3. Missing or nonfunctioning FMP CMS components as                 1,000
 required by Sec.   3174.9 of this subpart..............
4. Failure to meet the proving frequency requirements              1,000
 for an FMP, detailed in Sec.   3174.11 of this subpart.
5. Failure to obtain a written approval, as required by            1,000
 Sec.   3174.13 of this subpart, before using any oil
 measurement method other than tank gauging, LACT
 system, or CMS at a FMP................................
------------------------------------------------------------------------

[FR Doc. 2016-25405 Filed 11-16-16; 8:45 am]
 BILLING CODE 4310-84-P