[Federal Register Volume 85, Number 176 (Thursday, September 10, 2020)]
[Proposed Rules]
[Pages 55940-56077]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2020-16393]



[[Page 55939]]

Vol. 85

Thursday,

No. 176

September 10, 2020

Part II





Department of the Interior





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Bureau of Land Management





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43 CFR Part 3170





Oil and Gas Site Security, Oil Measurement, and Gas Measurement 
Regulations; Proposed Rule

  Federal Register / Vol. 85 , No. 176 / Thursday, September 10, 2020 / 
Proposed Rules  

[[Page 55940]]


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DEPARTMENT OF THE INTERIOR

Bureau of Land Management

43 CFR Part 3170

[19X.LLWO310000.L13100000.PP0000]
RIN 1004-AE59


Oil and Gas Site Security, Oil Measurement, and Gas Measurement 
Regulations

AGENCY: Bureau of Land Management, Interior.

ACTION: Proposed rule.

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SUMMARY: On November 17, 2016, the Bureau of Land Management (BLM) 
published in the Federal Register three final rules dealing with 
onshore oil and gas measurement and site security. In accordance with 
Executive Order 13783, Promoting Energy Independence and Economic 
Growth (March 28, 2017), and Secretary's Order No. 3349, American 
Energy Independence, (March 29, 2017), the BLM reviewed the affected 
regulations to determine if certain provisions may have added 
regulatory burdens that unnecessarily encumber energy production, 
constrain economic growth, and prevent job creation. As a result of 
this review, and in light of implementation issues that have arisen, 
the BLM is now proposing to modify certain provisions to reduce 
unnecessary and burdensome regulatory requirements.

DATES: Send your comments on this proposed rule to the BLM on or before 
November 9, 2020. Information Collection Requirements: If you wish to 
comment on the information collection requirements in this proposed 
rule, please note that the Office of Management and Budget (OMB) is 
required to make a decision concerning the collection of information 
contained in this proposed rule between 30 and 60 days after 
publication of this proposed rule in the Federal Register. Therefore, 
comments should be submitted to OMB by October 13, 2020.

ADDRESSES: 
    Mail: U.S. Department of the Interior, Director (630), Bureau of 
Land Management, Mail Stop 2134LM, 1849 C St. NW, Washington, DC 20240, 
Attention: 1004-AE59.
    Personal or messenger delivery: U.S. Department of the Interior, 
Bureau of Land Management, 20 M Street SE, Room 2134 LM, Washington, DC 
20003, Attention: Regulatory Affairs.
    Federal eRulemaking Portal: https://www.regulations.gov. In the 
Searchbox, enter ``RIN 1004-AE59 and click the ``Search'' button. 
Follow the instructions at this website.

For Comments on Information-Collection Activities

    Written comments and suggestions on the information collection 
requirements should be submitted within 30 days of publication of this 
notice to www.reginfo.gov/public/do/PRAMain. Find this particular 
information collection by selecting ``Currently under 30-day Review--
Open for Public Comments'' or by using the search function. Please 
provide a copy of your comments to Bureau of Land Management, Faith 
Bremner, 20 M Street SE, Room 2134 LM, Washington, DC 20003, Attention: 
Regulatory Affairs (1004-AE59); or by email to [email protected]. Please 
reference OMB Control Numbers 1004-0207, 1004-0209, 1004-0210; 1004-
0137 in the subject line of your comments.
    Do not submit to OMB comments that do not pertain to the proposed 
rule's information-collection burdens. The BLM is not obligated to 
consider or include in the Administrative Record for the final rule any 
comments, which do not relate to the information collection burdens, 
that you improperly direct to OMB.

FOR FURTHER INFORMATION CONTACT: Rebecca Good, Acting Division Chief, 
Fluid Minerals Division, 307-261-7633 or [email protected], for information 
regarding the substance of this proposed rule or information about the 
BLM's Fluid Minerals program. For questions relating to regulatory 
process issues, contact Faith Bremner at 202-912-7441 or 
[email protected]. Persons who use a telecommunications device for the 
deaf (TDD) may call the Federal Relay Service (FRS) at 1-800-877-8339, 
24 hours a day, 7 days a week, to leave a message or question. You will 
receive a reply during normal business hours.

SUPPLEMENTARY INFORMATION:
I. List of Acronyms
II. Executive Summary
III. Public Comment Procedures
IV. Background
V. Incorporation by Reference of Industry Standards
VI. Discussion of the Proposed Rule
VII. Procedural Matters

I. List of Acronyms

AFMSS = Automated Fluid Minerals Support System
ATG = Automatic tank gauging
Bbl = Barrels
Bbl/d = Barrels per day
BLM = Bureau of Land Management
Btu = British thermal units
CA = Communitization agreement
CAA = Commingling and allocation agreement
CFR = Code of Federal Regulations
CMS = Coriolis measurement system
DOI = Department of the Interior
E.O. = Executive Order
EGM = Electronic gas metering
FMP = Facility Measurement Point
GAO = Government Accountability Office
GARVS = Gas Annual Reporting and Verification System
GC = Gas chromatograph
GS = General Schedule
GSA = Gas storage agreement
HV = High-volume
IMs = Instructional Memoranda
LACT = Lease Automatic Custody Transfer
LV = Low-volume
Mcf = Thousand cubic feet
Mcf/d = Thousand cubic feet per day
MDS = Measurement data system
NGL = Natural gas liquids
NGS = Natural gas storage facilities
OGOR = Oil and Gas Operations Report
ONRR = Office of Natural Resource Revenue
OPM = Office of Personnel Management
PMT = Production Measurement Team
PRA = Paperwork Reduction Act
QTR = Quantity transaction record
RIA = Regulatory Impact Analysis
SBA = Small Business Administration
Scf = Standard cubic foot
S.O. = Secretarial Order
SME = Subject matter expert
SWD = Salt water disposal
Tcf = Trillion cubic feet
Unit PA = Unit participation area.
VHV = Very-high-volume
VLV = Very-low-volume
WDP = Waste discharge permit
WDW = Water disposal well
WIW = Water injection well

II. Executive Summary

    On November 17, 2016, the Bureau of Land Management (BLM) published 
in the Federal Register the three following final rules: (1) ``Onshore 
Oil and Gas Operations; Federal and Indian Oil and Gas Leases; Site 
Security'' (81 FR 81365), codified at 43 CFR subparts 3170 and 3173; 
(2) ``Onshore Oil and Gas Operations; Federal and Indian Oil and Gas 
Leases; Measurement of Oil'' (81 FR 81462), codified at 43 CFR subpart 
3174; and (3) ``Onshore Oil and Gas Operations; Federal and Indian Oil 
and Gas Leases; Measurement of Gas'' (81 FR 81516), codified at 43 CFR 
subpart 3175. Collectively, we refer to these three rules as the ``2016 
Final Rules.''
    The 2016 Final Rules were prompted by external and internal 
oversight reviews, which found that many of the BLM's production 
measurement and accountability policies were outdated and 
inconsistently applied. The rules addressed some of the Government 
Accountability Office (GAO) concerns for areas of high risk with regard 
to production accountability. The rules also provided a process for 
approving new measurement technologies that meet defined performance 
standards.

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The rules became effective on January 17, 2017.
    Since the issuance of the 2016 Final Rules, representatives of the 
oil and gas industry and other interested stakeholders have raised a 
number of issues and concerns related to the implementation of the new 
regulations. The BLM agrees that there have been challenges with 
implementing some of the provisions of the 2016 Final Rules and has 
attempted to address some of them through administrative policy 
directives.\1\ However, the BLM can address other provisions only by 
revising the 2016 Final Rules through a rulemaking action.
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    \1\ These administrative policy directives were contained in 
three Instruction Memoranda (IMs): IM No. 2017-032 (Jan. 17, 2017), 
IM No. 2018-069 (June 29, 2018), and IM No. 2018-077 (June 29, 
2018). All three of these IMs are available on the BLM's website at 
https://www.blm.gov/policy/instruction-memorandum.
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    In addition, on March 28, 2017, President Trump issued Executive 
Order (E.O.) 13783, ``Promoting Energy Independence and Economic 
Growth'' (82 FR 16093). E.O. 13783 holds that ``[i]t is in the national 
interest to promote clean and safe development of our Nation's vast 
energy resources, while at the same time avoiding regulatory burdens 
that unnecessarily encumber energy production, constrain economic 
growth, and prevent job creation.'' E.O. 13783 directed Federal 
agencies, including the BLM, to ``review all existing regulations, 
orders, guidance documents, policies, and any other similar agency 
actions . . . that potentially burden the development or use of 
domestically produced energy resources, with particular attention to 
oil, natural gas, coal, and nuclear energy resources.'' E.O. 13783, 
Section 2(a). Notably, these Executive Orders did not prescribe 
specific outcomes, rather they directed review of the regulations, in 
accordance with all Federal laws.
    On March 29, 2017, the Secretary of the Interior issued Secretary's 
Order (S.O.) No. 3349, ``American Energy Independence.'' It directed 
DOI bureaus to ``identify all existing [DOI] actions . . . that 
potentially burden . . . the development or utilization of domestically 
produced energy resources, with particular attention to oil, natural 
gas, coal, and nuclear resources.'' S.O. 3349, Section 5(c)(v).
    The BLM reviewed the 2016 Final Rules for opportunities to address 
implementation challenges and to determine if certain provisions may 
impose regulatory burdens that unnecessarily encumber energy 
production, constrain economic growth, and prevent job creation. As a 
result of this review, the BLM is now proposing to modify certain 
provisions of 43 CFR subparts 3170, 3173, 3174, and 3175 to reduce 
unnecessary and burdensome regulatory requirements.
    The proposed rule would remove or revise requirements that the BLM 
has found to be unnecessarily burdensome, unclear, inconsistent, or 
otherwise problematic. The proposed rule would also adopt updated 
industry standards, where appropriate, and provide for the use of 
emerging measurement technologies. The BLM has concluded that the 
proposed changes will not affect its ability to implement GAO and 
Office of Inspector General (OIG) recommendations regarding oil and gas 
production reporting and accountability. The BLM does not anticipate 
that this proposed rule would have a significant impact on royalty 
revenues. First, as explained in the preamble to the 2016 rules, the 
goal of the 2016 rules was to reduce uncertainty, remove bias, and 
increase verifiability in production measurement. While improvements in 
these areas help to ensure accurate royalty payments, it is difficult 
to determine their likely overall impact because such improvements do 
not necessarily increase royalty revenues. See 81 FR 81553. The one 
provision from the 2016 rules that was specifically assessed in the 
2016 Regulatory Impact Analysis (RIA) and estimated to likely increase 
royalty revenues--the requirement that gas heating values be reported 
on a dry basis--is not being modified in this proposed rule.
    Furthermore, the BLM notes that this proposed rule would continue 
to address the major issues identified by the GAO in 2010 and 2015. 
Specifically, the GAO had faulted the BLM's prior regulatory regime for 
inconsistently tracking how oil and gas were measured and failing to 
account for current measurement technologies and standards. See 81 FR 
81463; 81 FR 81517. The 2016 rule addressed those issues, and this 
proposed rule would not backtrack on the BLM's progress in these areas. 
This proposed rule would maintain consistent, nation-wide measurement 
requirements and would allow for the use of current measurement 
technologies.

III. Public Comment Procedures

    If you wish to comment on this proposed rule, you may submit your 
comments to the BLM by mail, personal or messenger delivery, or through 
https://www.regulations.gov (see the ADDRESSES section).
    Please make your comments on the proposed rule as specific as 
possible, confine them to issues pertinent to the proposed rule, 
explain the reason for any changes you recommend, and include any 
supporting documentation. Where possible, your comments should 
reference the specific section or paragraph of the proposal that you 
are addressing. The BLM is not obligated to consider or include in the 
Administrative Record for the final rule comments that we receive after 
the close of the comment period (see DATES) or comments delivered to an 
address other than those listed previously (see ADDRESSES).
    Comments, including names and street addresses of respondents, will 
be available for public review at the address listed under ``ADDRESSES: 
Personal or messenger delivery'' during regular hours (7:45 a.m. to 
4:15 p.m.), Monday through Friday, except holidays. Before including 
your address, telephone number, email address, or other personal 
identifying information in your comment, be advised that your entire 
comment--including your personal identifying information--may be made 
publicly available at any time. While you can ask us in your comment to 
withhold from public review your personal identifying information, we 
cannot guarantee that we will be able to do so.
    As explained later, this proposed rule would include revisions to 
information collection requirements that must be approved by the Office 
of Management and Budget (OMB). If you wish to comment on the revised 
information collection requirements in this proposed rule, please note 
that such comments must be sent directly to the OMB in the manner 
described in the ADDRESSES section. The OMB is required to make a 
decision concerning the collection of information contained in this 
proposed rule between 30 and 60 days after publication of this document 
in the Federal Register. Therefore, a comment to the OMB on the 
proposed information collection revisions is best assured of being 
given full consideration if the OMB receives it by October 13, 2020.

IV. Background

    Americans enjoy a quality of life today that depends largely upon a 
stable and abundant supply of affordable energy. The Federal energy 
portfolio managed by the BLM includes oil and gas, coal, oil shale and 
tar sands, and, increasingly, renewable sources of energy, such as 
wind, solar and geothermal.
    Oil and gas from public and Indian lands are a significant part of 
this energy mix. For Fiscal Year (FY) 2018, sales of

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oil, gas, and natural gas liquids produced on Federal and Indian lands 
accounted for approximately 6 percent of all oil, 10 percent of all 
natural gas, and 7 percent of all natural gas liquids produced in the 
United States.
    The BLM manages the Federal Government's onshore subsurface mineral 
estate--about 700 million acres (30 percent of the U.S. landmass)--for 
the benefit of the American public. It also manages some aspects of oil 
and gas development for Indian tribes (not including the Osage Tribe).
    Consistent with statutory requirements, Federal lease contracts 
with private parties specify that royalties are owed on all production 
removed or sold from Federal and Indian oil and gas leases. The basis 
for those royalty payments is the measured volume and quality of the 
production from those leases. In FY 2018, over $2.14 billion in Federal 
royalties, rental payments, bonus bids, and other revenues, were 
generated from Federal onshore oil and gas leases. These revenues were 
split between the U.S. Treasury and the States where the development 
occurred. Also in FY 2018, over $830 million in royalties, rental 
payments and other revenues were generated from tribal oil and gas 
leases. All of these revenues were distributed to the appropriate 
tribes and individual allotment owners.
    Given the magnitude of this production and the BLM's statutory 
management obligations, it is critically important that the BLM ensure 
that operators accurately measure, report, and account for that 
production. To that end, the BLM has instituted regulations relating to 
site security, oil measurement, and gas measurement. The BLM maintains 
an inspection and enforcement program to ensure that operators comply 
with these regulations. Operators are required to report production 
volumes and submit royalty payments to the Office of Natural Resources 
Revenue (ONRR). The ONRR maintains an audit program to ensure that the 
government receives all royalties owed.
    The basis for this proposed rule is the Secretary of the Interior's 
authority under various Federal and Indian mineral leasing laws to 
manage oil and gas operations. These mineral leasing laws are: The 
Mineral Leasing Act of 1920, 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 of 1982, 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, 43 U.S.C. 1701 et 
seq. Each of these statutes gives the Secretary the authority to 
promulgate necessary and appropriate rules and regulations governing 
Federal and Indian (except Osage Tribe) oil and gas leases. See 30 
U.S.C. 189; 30 U.S.C. 359; 25 U.S.C. 396d; 25 U.S.C. 396; 25 U.S.C. 
2107; and 43 U.S.C. 1740.
    In recognition of the fact that not all oil and gas wells are 
identical due to geology and other circumstances, the Mineral Leasing 
Act provides the Secretary with statutory authority to reduce royalty 
rates ``for the purposes of encouraging the greatest ultimate recovery 
of [oil and gas] and in the interest of conservation of natural 
resources,'' whenever it is necessary to do so in order to ``promote 
development'' or because the lease could not be ``successfully 
operated'' otherwise. 30 U.S.C. 209. This provision acknowledges the 
changing economics of Federal oil and gas wells and provides guidance 
that, in cases such as marginal wells, the Secretary has discretion to 
prioritize production over royalties to ensure the maximum recovery of 
the resources.
    The primary statutory authority underpinning the BLM's site 
security and measurement regulations is in the Federal Oil and Gas 
Royalty Management Act of 1982 (FOGRMA) (30 U.S.C. 1701-1756). Congress 
enacted FOGRMA upon finding that ``the system of accounting with 
respect to royalties and other payments due and owing on oil and gas 
produced from [Federal and Indian] lease sites is archaic and 
inadequate.'' 30 U.S.C. 1701(a)(2). Among Congress' purposes in 
enacting FOGRMA was ``to define the authorities and responsibilities of 
the Secretary of the Interior to implement and maintain a royalty 
management system'' and ``to require the development of enforcement 
practices that ensure the prompt and proper collection and disbursement 
of oil and gas revenues owed to the United States and Indian lessors.'' 
30 U.S.C. 1701(b)(2)-(3). FOGRMA states that the Secretary ``shall 
establish a comprehensive inspection, collection and fiscal and 
production accounting and auditing system to provide the capability to 
accurately determine oil and gas royalties, interest, fines, penalties, 
fees, deposits, and other payments owed, and to collect and account for 
such amounts in a timely manner.'' 30 U.S.C. 1711(a). FOGRMA authorizes 
enforcement of this system through inspections, audits, investigations, 
and civil penalties. 30 U.S.C. 1711, 1717-19. FOGRMA also states that 
an operator shall develop and comply with a site security plan that 
conforms ``with such minimum standards as the Secretary may prescribe 
by rule, taking into account the variety of circumstances at lease 
sites.'' 30 U.S.C. 1712(b). FOGRMA contains a ``broad grant of 
rulemaking authority to achieve its objectives.'' Wyoming v. DOI, 2017 
WL 161428, *6 (D. Wyo. 2017). Specifically, FOGRMA states that ``the 
Secretary shall prescribe such rules and regulations as he deems 
reasonably necessary to carry out this chapter.'' 30 U.S.C. 1751(a).
    The Secretary's authority to regulate onshore oil and gas 
operations under the mineral leasing laws has been delegated to the 
BLM. In implementing this authority, the BLM has issued regulations 
governing onshore Federal and Indian oil and gas production. This 
proposed rule would modify the BLM's regulations pertaining to site 
security and the measurement of oil and gas produced or sold from a 
lease.
    The site security requirements in this proposed rule would ensure 
the proper and secure handling of production from Federal and Indian 
onshore oil and gas leases. The proper handling of this production is 
essential to accurate measurement, proper reporting, and overall 
production accountability. The oil and gas measurement requirements of 
this proposed rule would ensure accurate measurement and reporting of 
onshore oil and gas production. Taken together, the requirements of 
this proposed rule would ensure that the American public, Indian 
tribes, and allottees receive royalties owed to them on oil and gas 
production.
    On November 17, 2016, the BLM published in the Federal Register the 
three final rules: (1) ``Onshore Oil and Gas Operations; Federal and 
Indian Oil and Gas Leases; Site Security'' (81 FR 81365), codified at 
43 CFR subparts 3170 and 3173; (2) ``Onshore Oil and Gas Operations; 
Federal and Indian Oil and Gas Leases; Measurement of Oil'' (81 FR 
81462), codified at 43 CFR subpart 3174; and (3) ``Onshore Oil and Gas 
Operations; Federal and Indian Oil and Gas Leases; Measurement of Gas'' 
(81 FR 81516), codified at 43 CFR subpart 3175.
    The 2016 Final Rules were prompted by external and internal 
oversight reviews, which found that many of the BLM's production 
measurement and accountability policies were outdated and 
inconsistently applied. The rules addressed the concerns raised by the 
GAO that led the GAO to designate DOI's onshore production 
accountability as an area of high risk. GAO considers a program or 
operation

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to be high risk when, after evaluation, the program or operation is 
determined to be vulnerable to fraud, waste, abuse, and mismanagement, 
or in need of transformation. (https://www.gao.gov/highrisk/overview) 
The 2016 Final Rules also provided a process for approving new 
measurement technologies that meet defined performance goals. The rules 
became effective on January 17, 2017.
    On March 28, 2017, President Trump issued Executive Order (E.O.) 
13783, ``Promoting Energy Independence and Economic Growth'' (82 FR 
16093). E.O. 13783 directed Federal agencies, including the BLM, to 
``review all existing regulations, orders, guidance documents, 
policies, and any other similar agency actions. . . that potentially 
burden the development or use of domestically produced energy 
resources, with particular attention to oil, natural gas, coal, and 
nuclear energy resources.'' E.O. 13783, Section 2(a). On March 29, 
2017, then Secretary of the Interior Ryan Zinke issued S.O. 3349, 
entitled, ``American Energy Independence,'' to implement E.O. 13783. 
S.O. 3349 directed DOI bureaus to ``identify all existing [DOI] actions 
. . . that potentially burden . . . the development or utilization of 
domestically produced energy resources, with particular attention to 
oil, natural gas, coal, and nuclear resources.'' S.O. 3349, Section 
5(c)(v).
    Additionally, once the BLM began enforcing the 2016 Final Rules, 
the BLM became aware of practical implementation challenges associated 
with the rules. These challenges include differing interpretations of 
specific rule language among industry and BLM personnel, as well as the 
identification of less burdensome approaches that would achieve the 
same performance outcomes sought by the 2016 Final Rules. For example, 
Lease Automatic Custody Transfer (LACT) systems (composed of a meter, 
ability to prove the meter, devices for determining temperature, 
pressure, and liquid sampling, and a means for determining 
nonmerchantable oil, referenced under existing Sec.  3174.8(b)) are 
required to follow the industry standard API chapter 6.1 (API 6.1). The 
use of this API standard created confusion both within industry and the 
BLM with respect to what equipment was required as opposed to optional. 
To eliminate this confusion, this proposed rule, in Sec.  3174.100 
through Sec.  3174.108, would remove the reference to API 6.1 and would 
list the required equipment for Facility Measurement Point (FMP) LACT 
systems. Other examples of implementation challenges the BLM 
encountered include:
     The delay in the development of the AFMSS 2 system (the 
means by which operators would apply for FMP numbers) undermined the 
``phase-in'' periods in subpart 3174, as those phase-in periods were 
based on the dates on which operators were required to apply for FMP 
numbers.
     There were questions about how the rules should be applied 
to situations not specifically addressed in the regulation text, 
including temporary measurement equipment and gas storage agreements.
     Some operators employed water-vapor-detection devices that 
were not designed for natural gas applications, creating the potential 
for misreporting of hydrocarbon liquids as water.
     The time period indicated by the word ``monthly'' was 
found in practice not to be clear.
     The meaning of ``normal'' operating conditions for meter 
proving under subpart 3174 proved not to be clear when implemented.
     The recordkeeping requirements for water-draining 
operations in subpart 3173 proved to be burdensome.
    On June 22, 2017, the Department of the Interior (Interior) 
published a notice in the Federal Register requesting public input on 
how Interior could improve implementation of various regulatory reform 
initiatives--including those contained in E.O. 13783 and S.O. 3349--and 
identify regulations for repeal, replacement, or modification. 82 FR 
28429 (June 22, 2017). Among the comments Interior received in response 
to this request were five comments that directly addressed the site 
security and measurement regulations. Among the commenters were an 
individual, an oil and gas exploration and production company, two 
industry trade associations, and an Alaska Native Regional Corporation. 
The comments asked the BLM to make certain changes to the regulations, 
including: Updating the list of incorporated industry standards; 
providing for automatic acceptance of measurement devices meeting 
certain standards; more evenly phasing-in the subparts 3173 and 3174 
requirements; preserving existing variances, commingling agreements, 
and off-site measurement approvals; accommodating ``economically 
marginal'' properties; and, reducing the frequency of required meter 
provings and meter-tube inspections.
    In light of the foregoing, the BLM reviewed the 2016 Final Rules 
for opportunities to address the implementation challenges and to 
determine if certain provisions may have added regulatory burdens that 
unnecessarily encumber energy production, constrain economic growth, 
and prevent job creation. As a result of this review, the BLM is now 
proposing to modify certain provisions of 43 CFR subparts 3170, 3173, 
3174, and 3175 to remedy implementation issues and reduce unnecessary 
and burdensome regulatory requirements.
    When the BLM issued the 2016 Final Rules, it determined that none 
of the rules were economically significant according the criteria in 
E.O. 12866, ``Regulatory Planning and Review.'' However, regardless of 
classification under E.O. 12866, the 2016 Final Rules posed 
considerable costs to industry and the BLM.
    The BLM examined the burdens to industry and the BLM in its RIA for 
each of the 2016 Final Rules. Those estimated burdens are summarized as 
follows:
     For 43 CFR subpart 3173, $29.6 million in each of the 
first 3 years and $14.5 million per year thereafter (see 2016 RIA for 
subpart 3173, at p. 13);
     For 43 CFR subpart 3174, $6.1 million in each of the first 
3 years and $4.9 million per year thereafter (see 2016 RIA for subpart 
3174, at p. 11); and
     For 43 CFR subpart 3175, $20.3 million in each of the 
first 3 years and $12.4 million per year thereafter (see 2016 RIA for 
subpart 3175, at p. 11).
    In developing this proposed rule, the BLM has sought to reduce the 
regulatory burdens associated with the 2016 Final Rules while 
maintaining appropriate safeguards to ensure production accountability. 
While the proposed revisions would streamline, reduce, or eliminate 
some of the burdens associated with the 2016 Final Rules, the BLM 
believes that the 2019 revisions would not compromise the government's 
ability to ensure accurate and reliable royalty collection. The BLM 
would maintain its capacity to ensure a fair return to the American 
public and the tribes from oil and gas operations on the Federal and 
Indian mineral estate. Doing so without unduly burdening development, 
to ensure the Nation's energy security and independence, balances its 
royalty mission with the goals stated in E.O. 13783 and S.O. 3349 in a 
fully complimentary and appropriate manner.
    The BLM notes that, while the BLM was separately reviewing the 2016 
Final Rules and considering appropriate revisions, the Department of 
the Interior's Royalty Policy Committee (RPC), Subcommittee on 
Planning, Analysis, and Competitiveness, recommended that the BLM 
revise the 2016 Final Rules. The BLM is aware that the U.S. District 
Court for the District of

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Montana has enjoined ``further use or reliance on'' recommendations 
issued by the RPC. Western Organization of Resource Councils v. David 
Bernhardt, 9:18-cv-00139-DWM (D. Mont. 8/13/2019). To ensure compliance 
with the District Court's injunction, the BLM reviewed the RPC's 
recommendations and has confirmed that this proposed rule does not use 
or rely on RPC recommendations. Rather, the BLM is relying on facts, 
analysis, and recommendations, as set forth in the Background section 
of this proposed rule, that are independent of any recommendations of 
the RPC, including its subcommittees. To be clear, the BLM is not 
relying on any RPC recommendation in this proposed rule and this 
proposed rule is not intended to implement any RPC recommendation. 
Furthermore, the BLM requests that commenters refrain from using or 
relying on RPC recommendations in their comments.

V. Incorporation by Reference of Industry Standards

    This proposed rule would incorporate 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 incorporating by reference (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 and determined that they would achieve the intent of 43 CFR 
3174.31 through 3174.180 and 43 CFR 3175.31 through 3175.140 of this 
proposed rule. The legal effect of IBR is that the incorporated 
standards would become regulatory requirements. With the approval of 
the Director of the Federal Register, this proposed rule would 
incorporate the current versions of the standards listed.
    Some of the standards referenced in this section would be 
incorporated in their entirety. For other standards, the BLM would 
incorporate only those sections that are relevant to the rule, meet the 
intent of Sec. Sec.  3174.30 and 3175.30 of the proposed rule, and do 
not need further clarification.
    The National Technology Transfer and Advancement Act (NTTAA), 
Public Law 104-113 (NTTAA), 15 U.S.C. 3701 et seq. (Pub. L. 104-113), 
charges, with certain exceptions, that ``all Federal agencies and 
departments shall use technical standards that are developed or adopted 
by voluntary consensus standards bodies, using such technical standards 
as a means to carry out policy objectives or activities determined by 
the agencies and departments.'' The BLM may incorporate these standards 
into its regulations by reference without republishing the standards in 
their entirety in the regulations. The legal effect of incorporation by 
reference is that the incorporated standards become regulatory 
requirements. This incorporated material, like any other regulation, 
has the force and effect of law. Operators, lessees, and other 
regulated parties must comply with the documents incorporated by 
reference in the regulations.
    The incorporation of industry standards follows the requirements 
found in 1 CFR part 51. The industry standards in this proposed rule 
are eligible for incorporation under 1 CFR 51.7 because, among other 
things, they would 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 (4)). The 
language of incorporation in Sec. Sec.  3174.30 and 3175.30 meets the 
requirements of 1 CFR 51.9. Where appropriate, the BLM would 
incorporate by reference an industry standard governing a particular 
process and then impose 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 material that is proposed to be incorporated by reference is 
available for inspection at the Bureau of Land Management, Division of 
Fluid Minerals, 20 M Street SE, Washington, DC 20003, 202-912-7162; and 
at all BLM offices with jurisdiction over oil and gas activities; and 
is available from the sources listed below. Before visiting a BLM 
office during the Covid-19 pandemic, please call ahead to confirm that 
the office is open to the public. If it is not open, you may make an 
appointment to visit the office.
    All American Gas Association (AGA) documents are available for 
inspection and purchase from AGA, 400 North Capitol Street NW, Suite 
450, Washington, DC 20001; telephone 202-824-7000. All of 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 standards that are proposed to be incorporated are summarized 
as part of the section-by-section analysis for Sec. Sec.  3174.30 and 
3175.30 in section V of this preamble.

VI. Discussion of the Proposed Rule

1. Summary

    The following is a summary of the proposed modifications to 
subparts 3170, 3173, 3174, and 3175:

43 CFR subpart 3170--Onshore Oil and Gas Production: General

     Various changes are required to conform with the 
substantive changes to 43 CFR subparts 3173, 3174, and 3175.

43 CFR subparts 3173--Requirements for Site Security and Production 
Handling

     Reduce certain equipment seal requirements for equipment 
locations deemed to be of low risk to mishandling or theft;
     Reduce recordkeeping requirements associated with water 
draining operations;
     Reduce requirements for co-located facility on-site 
facility diagrams;
     Remove a requirement to submit a new site facility diagram 
when change of operator occurs;
     Increase volume thresholds for submitting FMP 
applications; and
     Remove immediate assessment for seals associated with LACT 
units.

43 CFR subpart 3174--Oil Measurement

     Update all incorporated API standards to the latest 
published edition;
     Create a third low-volume FMP category with no measurement 
uncertainty requirements;
     Add Production Measurement Team (PMT) review and BLM 
approval requirements for electronic thermometers, LACT sampling 
systems, temperature and pressure transducers, and temperature 
averaging devices;
     Delay the requirement for using BLM-approved equipment on 
existing high-volume FMPs and low-volume FMPs until such time as the 
equipment is replaced or the FMP elevates to a very-high-volume FMP; 
and
     Remove the immediate assessment for failure to notify the 
BLM of a LACT component failure.

43 CFR subpart 3175--Gas Measurement

     Update all incorporated API standards to the latest 
published edition;
     Add PMT review and BLM approval requirements for Gas

[[Page 55945]]

Chromatograph (GC) software and water vapor detection methods;
     Reduce basic meter-tube inspection frequency and remove 
detailed meter-tube inspection requirement for low-volume FMPs;
     Add initial meter-tube inspections for high- and very-high 
volume FMPs;
     Eliminate the requirement of installing composite samplers 
or on-line GCs for very-high volume FMPs; and
     Add language to make portions of the rule apply to gas 
meters associated with gas storage agreements.
    The proposed modifications to subparts 3170, 3173, 3174, and 3175 
are described in detail in the following section-by-section discussion.

B. Section-by-Section Discussion

    The following discussion addresses the proposed changes from the 
existing regulation. If a provision is not specifically discussed in 
this section-by-section analysis, then the provision is essentially the 
same as the existing regulation.
1. Section-by-Section Discussion for Changes to Subpart 3170
    The following table provides a cross-walk comparison of proposed 
subpart 3170 to the corresponding sections in existing subpart 3170:

 
------------------------------------------------------------------------
       Existing subpart 3170 sec.           Proposed subpart 3170 sec.
------------------------------------------------------------------------
3170.1 Authority.......................  3170.1 Authority.
3170.2 Scope...........................  3170.2 Scope.
3170.3 Definitions and acronyms........  3170.10 Definitions and
                                          acronyms.
3170.4 Prohibitions against by-pass and  3170.20 Prohibitions against by-
 tampering.                               pass and tampering.
3170.5 [Reserved]......................  3170.30 Alternative measurement
                                          equipment and procedures.
3170.6 Variances.......................  3170.40 Variances.
3170.7 Required recordkeeping, records   3170.50 Required recordkeeping,
 retention, and records submission.       records retention, and records
                                          submission.
3170.8 Appeal procedures...............  3170.60 Appeal procedures.
3170.9 Enforcement.....................  3170.70 Enforcement.
------------------------------------------------------------------------

    The following discussion addresses section-by-section changes in 
the proposed subparts 3170 from the existing subparts 3170.
Section 3170.2 Scope
    The BLM is proposing to add a new paragraph (f) to Sec.  3170.2. 
Proposed Sec.  3170.2(f) would expand the scope of the subpart 3170 
regulations to include ``measurement points on BLM-managed gas-storage 
agreements.'' Proposed subpart 3175 would add requirements for gas-
storage-agreement measurement points (discussed in detail later), thus 
necessitating this amendment to the Scope provision.
    The BLM is not proposing any other amendments to the Scope 
provision for subpart 3170. However, the BLM notes that industry 
representatives have recommended that the BLM set a Federal-interest 
threshold for application of its site-security, oil-measurement, and 
gas-measurement regulations to units and Communitization Agreements 
(CAs) (created for the cooperative development of multiple leases in a 
State regulatory agency's assigned drilling spacing (43 CFR 3217.11)) 
that produce a mix of Federal and non-Federal oil and gas. The 
rationale for this suggestion appears to be that the burdens associated 
with BLM regulation of site security and measurement at a unit or CA 
should be justified by a significant Federal interest in that unit or 
CA. The BLM has considered this suggestion, but has not put forth a 
proposed Federal-interest threshold due to the difficulty of 
identifying a threshold that would satisfy the BLM's obligations under 
FOGRMA and that would protect the Federal royalty interest in the 
variety of circumstances under which Federal oil and gas production 
occurs. The BLM is requesting comment on whether it should establish a 
Federal-interest threshold for applying its site-security and oil- and 
gas-measurement regulations to units and CAs. The BLM is particularly 
interested in comment on the following: The costs and benefits of 
setting a Federal-interest threshold; what an appropriate threshold 
would be; whether, and to what extent, such a threshold would 
jeopardize the Federal royalty interest or fail to satisfy the BLM's 
obligations under FOGRMA; and, whether a similar threshold could be 
adopted for applying the regulations to units and CAs producing Indian 
oil and gas. Finally, the BLM recognizes that the States in which 
Federal and Indian oil and gas production occurs have interests that 
may be impacted by BLM regulation of mixed-ownership units and CAs; the 
BLM therefore specifically requests comment from the governments of 
those States on this issue.
Section 3170.1 Definitions and Acronyms
    This proposed section corresponds to existing Sec.  3170.3 and 
would define the terms that are used in more than one part 3170 
subpart. The proposed rule would renumber the section to Sec.  3170.10 
for consistency of numbering across the part 3170 subparts.
    A new definition for ``Alarm log'' would be added in proposed Sec.  
3170.10. Since the term would be used in proposed subparts 3174 and 
3175, its definition belongs in Sec.  3170.10.
    The proposed rule would delete the definition for ``API (followed 
by a number).'' This definition was originally needed to accommodate an 
existing requirement that operators identify certain wells by their API 
numbers. Proposed changes to subparts 3173, 3174, and 3175 would delete 
all references to API well numbers and require operators to identify 
wells by their US well numbers. API transferred the unique well 
identifier standard to the Professional Petroleum Data Management 
(PPDM) in 2010. At that time, PPDM created the US well number as the 
new industry standard for identifying oil and gas wells.
    The proposed rule would modify the existing definition for ``By-
pass.'' The revised definition would state that piping around a meter 
with a double block and bleed valve or a series of valves that ensures 
valve integrity that is effectively sealed as required under proposed 
Sec.  3173.20 would not be considered a by-pass where approved by the 
BLM. The BLM believes the proposed change to the definition would allow 
for industry innovation in measurement while ensuring the FMP allows 
for oil or gas to flow with accountability.
    The proposed rule would modify the definition of ``Configuration 
log'' and move it from existing Sec.  3175.10 to proposed Sec.  3170.10 
because the term is

[[Page 55946]]

used in more than one part 3170 subpart. The proposed change to the 
definition would align it with the industry standard, API Chapter 21.1 
Flow Measurement Using Electronic Metering Systems--electronic Gas 
Measurement--Second Edition, thereby preventing confusion among 
industry and the BLM as to the meaning of the term.
    The BLM proposes to move the definition for ``Event log'' from 
existing subparts 3174 and 3175, where the term is used, to proposed 
Sec.  3170.10. This proposed rule would also modify the existing 
definition of ``event log'' to align it with the current industry 
standard published in API Chapter 21.1 Flow Measurement Using 
Electronic Metering Systems--electronic Gas Measurement--Second 
Edition. The proposed modification to the definition would add clarity 
and eliminate confusion over the use of the term by industry and the 
BLM.
    The BLM is proposing several changes to the definition of a 
``Facility measurement point (FMP).'' First, the definition would be 
expanded to include not only measurement affecting the calculation of 
the volume and quality of production from a Federal or Indian lease, 
unit Participating Area (PA) (part of unit area which has proven to be 
productive of oil or gas in paying quantities or which is necessary for 
unit operations and to which production is allocated), or CA for which 
royalty is owed, but also measurement affecting the calculation of the 
volume and quality of the production on native gas or oil from gas 
storage agreements, which royalty is also owed.
    Second, the proposed rule would remove from the FMP definition's 
second sentence the clause ``but is not limited to, the approved point 
of royalty measurement and.'' Upon review, the BLM does not foresee any 
circumstances under which an FMP is not relevant to the determination 
of the allocation of production to Federal or Indian leases, unit PAs, 
or CAs. Therefore, the clause was removed and the proposed definition 
reads, ``An FMP includes all measurement points relevant to determining 
the allocation of production to Federal or Indian leases, unit PAs, or 
CAs.''
    Third, the BLM is proposing to remove the fourth sentence from the 
existing definition, ``An FMP also includes a meter or measurement 
facility used in the determination of the volume or quality of royalty-
bearing oil or gas produced before BLM approval of an FMP under Sec.  
3173.12.'' The proposed definition of FMP is not couched in terms of 
``BLM-approved'' measurement points as the existing definition is 
written. Under the plain terms of the proposed definition, a 
measurement point affecting royalty or injection or withdrawal fees 
would be an FMP, even in the absence of BLM approval. The fourth 
sentence of the existing definition is therefore no longer necessary.
    Fourth, the BLM is proposing to reword the last sentence in the 
existing definition for an FMP that now says the BLM will not approve a 
gas processing plant tailgate meter located off the lease, unit or CA, 
as an FMP. Instead, the proposed rule would change the last sentence to 
say that an FMP cannot be located at the tailgate of a gas-processing 
plant located off the lease, unit, or CA. This change would reflect 
proposed changes to the BLM's FMP number approval process. Existing 
Sec.  3173.12(a) and (b) would be deleted. Existing Sec.  3173.12(b) 
says the BLM will not approve as an FMP a gas processing plant tailgate 
meter located off the lease, unit, or communitized area. The proposed 
change to the definition would incorporate the intent of the existing 
Sec.  3173.12(b) deleted paragraph.
    The last proposed change to the existing FMP definition involves 
adding a sentence to the FMP definition that would resolve the 
confusion over measuring flared volumes that has arisen since the BLM 
published its waste prevention regulations (43 CFR subpart 3179). In 
the proposed FMP definition, measurement points for flared volumes are 
not FMPs, even though royalty may be due on the flared volumes. 
Measurement and reporting requirements for flared gas are contained in 
43 CFR 3179.301.
    In addition to the proposed changes to the FMP definition, the BLM 
is proposing to add a definition for ``FMP number.'' The FMP number 
would be the number that the BLM would assign to the FMP after 
reviewing the operator's FMP number application. This change would 
reflect proposed changes to the BLM's FMP-number approval process (see 
discussion of proposed Sec.  3173.60 later in this preamble).
    The proposed rule would relocate the definition for ``Land 
description'' from existing Sec.  3173.1 to proposed Sec.  3170.10, 
with a minor revision. The term ``Land description'' is used in 
subparts 3170 and 3173, so it belongs in Sec.  3170.10. The revision 
would acknowledge that the U.S. Department of Interior's Manual of 
Surveying Instructions is periodically amended and that the most recent 
version would apply to specifications used in land descriptions.
    The proposed rule would add a definition for ``Measurement data 
system (MDS),'' which does not appear in the existing rule. The 
definition is needed because proposed subparts 3174 and 3175 would use 
this new term. Since this definition is used in more than one subpart, 
it should be located in proposed Sec.  3170.10.
    Proposed Sec.  3170.10 would add a new definition for ``Notify.'' 
Existing part 3170 does not have a definition for ``Notify,'' despite 
the fact the term is used throughout its subparts. In the existing 
regulation, responding to comments on Sec.  3174.7(d) and (e), the BLM 
agreed with the commenters the term ``Notify'' was ambiguous and 
required a definition. Notify could mean a Sundry Notice, phone call, 
or many other forms of communication. The operators were concerned they 
would be notifying the BLM in a manner consistent with the regulation. 
In addition, there was a concern the BLM would interpret the term 
differently across field offices. In one field office the term 
``Notify'' might mean Sundry Notice, while in another a phone call 
would suffice. Although the BLM defined ``Notify'' in the existing 
subpart 3174 preamble, the definition for ``Notify'' did not appear in 
the final regulation text in subpart 3170 or subpart 3174. Since the 
term ``Notify'' appears throughout the 3170 subpart, the BLM proposed 
to include the definition in subpart 3170. The BLM seeks to rectify 
this oversight by including the definition for ``Notify'' in proposed 
subpart 3170.
    The proposed rule would relocate the definition of ``Permanent 
measurement facility'' from existing Sec.  3173.1 to Sec.  3170.10. The 
proposed rule would also change the length of time that equipment used 
to determine the quantity or quality of production or to store 
production could be used at an FMP before it would be considered a 
permanent measurement facility. The existing definition defines 
permanent as being 6 months or longer. The 6-month standard was based 
on the BLM's typical time frame for conducting an initial environmental 
inspection of production facilities after a well has been completed. 
The revised rule would set a 3-months standard that would more 
accurately reflect the concept of permanent facilities. The BLM 
believes 3 months is a sufficient amount of time for operators to 
construct facilities and begin use of an FMP number.
    The proposed Sec.  3170.10 definition for Production Measurement 
Team (PMT) would delete the last sentence which states the purpose of 
the PMT. The final sentence of the definition is redundant

[[Page 55947]]

and the BLM believes the intent of the purpose is already contained 
within the first sentence.
    Proposed Sec.  3170.10 would add a definition for ``Temporary 
measurement facility.'' The existing rule does not address temporary 
measurement, but proposed subparts 3174 and 3175 would. This definition 
would specify that any measurement equipment in place for less than 3 
months would be considered temporary and would not need an FMP number 
even though the FMP is being used to measure production for the 
purposes of royalty collection.
    Proposed Sec.  3170.10 would add the new definition ``US well 
number'' to accommodate a proposed requirement that operators switch 
from using API well numbers to identify their wells to using US well 
numbers. Created by the PPDM Association in 2010, the US well number is 
the new industry standard for identifying oil and gas wells.
Section 3170.30 Alternative Measurement Equipment and Procedures
    This proposed new section would clarify the process that operators 
or manufacturers must follow to get BLM approval for using alternative 
oil or gas measurement equipment or measurement methods. The proposed 
language is substantially similar to language in existing Sec.  
3174.4(d) and Sec.  3174.13, with the biggest change being that it 
would apply to both oil and gas equipment and methods. In addition the 
proposed rule would require approval of alternative measurement 
equipment and procedures to meet or exceed the objectives in minimum 
standards in part 3170. Alternative measurement equipment and 
procedures would need to meet or exceed measurement performance 
requirements, audit trail and verification requirements, and site 
security requirements. This proposed new section would replace existing 
Sec.  3174.4(d) and Sec.  3174.13. Since these proposed requirements 
would apply to both oil and gas operations, they belong in proposed 
subpart 3170, which contains provisions that are common to multiple 
part 3170 subparts.
    The purpose of proposed Sec.  3170.30 is to allow the BLM to 
approve new measurement equipment and procedures not already approved 
for use in the regulations. The proposed section would require an 
operator or manufacturer requesting approval to submit appropriate data 
demonstrating that the proposed alternative equipment or measurement 
method/procedure meets or exceeds the performance standards, would not 
affect royalty income, production accountability, or site security. The 
BLM is proposing that the PMT would review operators' or manufacturers' 
requests for approval of alternative equipment or measurement methods/
procedures to ensure that the alternative equipment or measurement 
methods/procedures would meet or exceed the objectives of the 
applicable minimum standards of part 3170 and would not affect royalty 
income, production accountability, or site security. After reviewing 
the requests, the PMT would make recommendations to BLM management, 
including any suggested conditions of approval. After BLM approval, the 
PMT would post the make, model, range or software version (as 
applicable), or method/procedure on the BLM's website, making it 
available for use at all FMPs.
    Proposed Sec.  3170.30(c) would clarify that the procedures for 
requesting and granting a variance under Sec.  3170.40 of this subpart 
may not be used as an avenue for approving new measurement technology, 
methods, or equipment.
Section 3170.40 Variances
    Under this proposed rule, existing Sec.  3170.6 would be renumbered 
to Sec.  3170.40. Both Sec.  3170.6 and Sec.  3170.40 provide 
instructions on how an operator could electronically submit a request 
for a variance or, if electronic filing is not possible or practical, 
submit the request to a BLM field office. Proposed Sec.  3170.40 would 
revise the existing language to match language in proposed Sec.  
3173.43(b) (existing Sec.  3173.10(b)), which instructs operators on 
how to submit Sundry Notices. This change would create a uniform 
process for submitting variance requests, FMP number requests, site 
facility diagrams, and other requests for approval.
    The BLM requests comment on whether it should also include a State 
and tribal variance provision that would allow States and tribes to 
request that the BLM apply analogous State or tribal rules or 
regulations in place of the BLM's requirements. The BLM is interested 
in achieving administrative efficiencies where possible while also 
protecting the public and tribal interests in production accountability 
and royalty revenues. The BLM specifically requests comment on the 
following: The appropriate standard for granting a State or tribal 
variance; the scope of a State or tribal variance; the appropriate 
process for obtaining a State or tribal variance; and, the means by 
which the BLM could address changes to State or tribal rules or 
regulations on which a variance is based. The BLM notes that its 
regulations in 43 CFR subpart 3179 previously contained a State and 
tribal variance provision at Sec.  3179.401 (see 81 FR 83008 (Nov. 18, 
2016)). Although that provision has since been rescinded (see 83 FR 
49184 (Sept. 28, 2018)), the BLM requests comment on the extent to 
which former Sec.  3179.401 could serve as a model for a new State and 
tribal variance provision.
Section 3170.50 Required Recordkeeping, Records Retention, and Records 
Submission
    Proposed Sec.  3170.50(g) would require operators to include the 
``Land description'' on all records used to determine the quality, 
quantity, disposition, and verification of production from Federal or 
Indian leases, unit PAs, or CAs. Land description includes the quarter-
quarter section, section, township, range and principal meridian, or 
other authorized survey designation acceptable to the AO, such as 
metes-and-bounds, or latitude and longitude. A land description is 
needed in case there are errors in other areas of a record. For 
example, when an operator mistakenly enters the wrong Federal agreement 
number, the BLM uses other information in the record to determine which 
Federal agreement is the correct one. The land description can be an 
important source of information to confirm or refute the validity of a 
record when the record contains missing or erroneous information. 
Proposed Sec.  3170.50(g)(4) would also add ``Land description'' to the 
record-information requirement for facilities existing prior to the 
assignment of an FMP number. The need for the land description on 
records for facilities without an FMP number is the same for facilities 
with assigned FMP numbers.
2. Section-by-Section Discussion for Changes to Subpart 3173
    This proposed rule would renumber all of the sections and rename 
one section in the existing subpart 3173 in order to improve 
consistency among the various part 3170 regulations. The following 
table provides a cross-walk comparison of proposed subpart 3173 to 
existing subpart 3173:

[[Page 55948]]



------------------------------------------------------------------------
       Existing subpart 3173 sec.           Proposed subpart 3173 sec.
------------------------------------------------------------------------
3173.1 Definitions and acronyms........  3173.10 Definitions and
                                          acronyms.
3173.2 Storage and sales facilities--    3173.20 Storage and sales
 seals.                                   facilities--seals.
3173.3 Oil measurement system            3173.21 Oil measurement system
 components--seals.                       components--seals.
3173.4 Federal seals...................  3173.22 Federal seals.
3173.5 Removing production from tanks    3173.30 Removing production
 for sale and transportation by truck.    from tanks for sale and
                                          transportation by truck.
3173.6 Water-draining operations.......  3173.31 Water-draining
                                          operations.
3173.7 Hot oiling, clean-up, and         3173.32 Hot oiling, clean-up,
 completion operations.                   and completion operations.
3173.8 Report of theft or mishandling    3173.40 Report of theft or
 of production.                           mishandling of production.
3173.9 Required recordkeeping for        3173.41 Required recordkeeping
 inventory and seal records.              for inventory and seal
                                          records.
3173.10 Form 3160-5, Sundry Notices and  3173.43 Data submission and
 Reports on Wells.                        notification requirements.
3173.11 Site facility diagram..........  3173.50 Site facility diagram.
3173.12 Applying for a facility          3173.60 Applying for a facility
 measurement point.                       measurement point number.
3173.13 Requirements for approved        3173.61 Requirements for
 facility measurement points.             approved facility measurement
                                          point numbers.
3173.14 Conditions for commingling and   3173.70 Conditions for
 allocation approval (surface and         commingling and allocation
 downhole).                               approval (surface and
                                          downhole).
3173.15 Applying for a commingling and   3173.71 Applying for a
 allocation approval.                     commingling and allocation
                                          approval.
3173.16 Existing commingling and         3173.72 Existing commingling
 allocation approvals.                    and allocation approvals.
3173.17 Relationship of a commingling    3173.73 Relationship of a
 and allocation approval to royalty-      commingling and allocation
 free use of production.                  approval to royalty-free use
                                          of production.
3173.18 Modification of a commingling    3173.74 Modification of a
 and allocation approval.                 commingling and allocation
                                          approval.
3173.19 Effective date of a commingling  3173.75 Effective date of a
 and allocation approval.                 commingling and allocation
                                          approval.
3173.20 Terminating a commingling and    3173.76 Terminating a
 allocation approval.                     commingling and allocation
                                          approval.
3173.21 Combining production downhole    3173.80 Combining production
 in certain circumstances.                downhole in certain
                                          circumstances.
3173.22 Requirements for off-lease       3173.90 Requirements for off-
 measurement.                             lease measurement.
3173.23 Applying for off-lease           3173.91 Applying for off-lease
 measurement.                             measurement.
3173.24 Effective date of an off-lease   3173.92 Effective date of an
 measurement approval.                    off-lease measurement
                                          approval.
3173.25 Existing approved off-lease      3173.93 Existing approved off-
 measurement.                             lease measurement.
3173.26 Relationship of off-lease        3173.94 Relationship of off-
 measurement approval to royalty-free     lease measurement approval to
 use of production.                       royalty-free use of
                                          production.
3173.27 Termination of off-lease         3173.95 Termination of off-
 measurement approval.                    lease measurement approval.
3173.28 Instances not constituting off-  3173.96 Instances not
 lease measurement, for which no          constituting off-lease
 approval is required.                    measurement, for which no
                                          approval is required.
3173.29 Immediate assessments for        3173.190 Immediate assessments
 certain violations.                      for certain violations.
------------------------------------------------------------------------

    If a provision is not specifically discussed in this section-by-
section analysis, then the provision is essentially the same as the 
existing regulation.
Section 3173.10 Definitions and Acronyms
    This proposed section would clarify the definition of ``Appropriate 
valves'' by simplifying the language to say that such valves provide 
access to production (i.e., access to add or remove liquids from a tank 
or piping system) before it is measured for sale. It would further 
clarify that such valves would be subject to the proposed rule's 
sealing requirements at proposed Sec.  3170.20. This new definition 
would help BLM inspectors identify which valves are subject to the seal 
requirements and help operators comply with the regulation.
    This proposed section would include a new definition for 
``Completed.'' The term is used in proposed Sec.  3173.80. The proposed 
changes in Sec.  3173.80 are discussed later in this preamble.
    The proposed rule would significantly change the definition for 
``Economically marginal property.'' The existing regulation provides 
conditions under which a lease, unit PA, or CA may be defined as an 
economically marginal property. The existing regulation requires each 
lease, unit PA, or CA in a commingling application to meet one of the 
definitions of economically marginal property in order for the BLM to 
consider approving a request to commingle Federal or Indian production.
    The existing regulation lists three economic conditions under which 
a property may be considered economically marginal. The first economic 
condition is when revenue from production is so low that a prudent 
operator would elect to plug a well or shut-in a lease rather than 
invest resources to achieve non-commingled production. The second 
economic condition is when the expected revenue, net any associated 
operating costs, generated from oil or gas production is insufficient 
to cover the nominal cost of the capital expenditure required to 
achieve measurement of non-commingled oil or gas production over a 
payout period of 18 months. The third economic condition occurs when 
the net present value, or the discounted value of the royalties 
collected from production for the Federal or Indian leases, unit PAs, 
or CAs over the expected life of the equipment required to achieve non-
commingled production, is less than the capital expense of purchasing 
and installing this equipment.
    This proposed rule would eliminate the first condition for an 
economically marginal property. Upon review, the BLM believes the first 
and third conditions in the existing rule are essentially the same. The 
BLM proposes to change the existing second and third economic 
conditions to state that the capital expense would be based on the 
least expensive, practicable, alternative equipment required to achieve 
non-commingled measurement of production. This change would clarify for 
industry and the BLM the equipment that would be included in an 
economic analysis for identifying an economically marginal property. 
The proposed rule would retain the last sentence of the existing 
definition with only minor administrative changes.
    As discussed earlier in this preamble, the proposed rule would 
remove the definition of ``Land description'' from its current location 
in existing Sec.  3173.1 and relocate it to proposed Sec.  3170.10.
    The proposed rule would move the revised definition for ``Permanent

[[Page 55949]]

measurement facility'' from Sec.  3173.1 to Sec.  3170.10. The revised 
definition for ``Permanent measurement facility'' is discussed 
previously.
    The proposed rule would add a definition for the ``Propagation of 
uncertainty'' made necessary by the addition of a new condition for 
commingling in proposed Sec.  3173.70(b)(5).
Section 3173.20 Storage and Sales Facilities--Seals
    The proposed rule would clarify the requirement in Sec.  
3173.20(c)(2) that seals are not required on valves on water tanks, 
unless the valve could provide access to sales or storage tanks by 
water tank and oil tank by means of common piping. The BLM is proposing 
to add a diagram to Appendix A, subpart 3173, that would depict a 
common tank configuration and which valves in this configuration are 
appropriate valves, requiring seals, and which are not. The diagram is 
intended to address confusion over whether valves on water tanks that 
have the possibility of accessing oil are appropriate valves that must 
be sealed.
Section 3173.21 Oil Measurement System Components--Seals
    This section addresses requirements for sealing components used in 
LACT meters and Coriolis measurement systems (CMS). This section 
identifies the components that must be effectively sealed, as defined 
in Sec.  3173.10. The objective of this section is to eliminate the 
theft or mishandling that can occur when components that are used in 
determining the quantity or quality of oil are not properly sealed.
    Upon reviewing existing Sec.  3173.3, the BLM believes that some of 
the existing sealing requirements are excessive, while others are 
necessary, but are unclear and in need of revision. The proposed rule 
seeks to reduce the compliance burden on operators as well as the 
enforcement burden on the BLM. The BLM reviewed all oil measurement 
system components, eliminated seal requirements on those with minimal 
risk to site security, and revised the remaining requirements to 
provide clarity.
    Proposed Sec.  3173.21(a) would change the sealing requirements for 
the components on LACT meters and CMSs that are currently contained in 
existing Sec.  3173.3(a)(1), (a)(4), (a)(5), (a)(6), (a)(7), (a)(8), 
(a)(9), (a)(10), (a)(12), and (a)(13).
    Proposed Sec.  3173.21would eliminate seal requirements for the 
following seals on LACT meters and CMSs:

    Sec.  3173.3(a)(1) Sample probes;
    Sec.  3173.3(a)(6) LACT meters or CMS;
    Sec.  3173.3(a)(9) Manual-sampling valves (if so equipped)'
    Sec.  3173.3(a)(10) Valves on diverter lines larger than 1 inch 
in nominal diameter;
    Sec.  3173.3(a)(12) Totalizer; and
    Sec.  3173.3(a)(13) Prover connections.

    For each of these components, the BLM believes the burden of 
compliance outweighs the risk of the removal of unmeasured oil. The BLM 
requests comment on the assumptions made in the following proposals in 
this section.
    Existing Sec.  3173.3(a)(1), requiring a seal for sample probes on 
LACTs or CMSs, would be eliminated in proposed Sec.  3173.21(a). Sample 
probe seal requirements would be removed because a sample probe is 
difficult to remove in normal operations. Since a sample probe is 
difficult to remove in normal operations, it poses a low risk to 
measurement if the current requirement for a seal is removed. If a 
sample probe were removed, its removal would cause a noticeable 
pressure drop. This pressure drop is likely to be noted on a flow 
computer, thereby alerting the operator or the BLM to a change in flow 
conditions in the measurement system.
    Existing Sec.  3173.3(a)(6), requiring a seal for LACT meters or 
CMS, would be eliminated in proposed Sec.  3173.21(a). The existing 
regulation requires the sealing of LACT meters or CMS. Electronic 
meters cannot be opened and adjusted in the same way as a mechanical 
meter. New facilities with larger production volumes are generally 
using electronic meters for FMPs. Given the construction of electronic 
meters, it is impossible to seal components which affect the 
measurement of quality and quantity of oil because the components 
reside within the housing of the meter. Removal of the seal requirement 
for electronic meters on newer, higher-producing agreements poses low 
risk for improper measurement. Mechanical meters are more likely to be 
used on lower-production FMPs. The BLM believes the elimination of a 
seal requirement on these meters would not significantly affect 
production accountability, as higher-volume production facilities are 
safeguarded with the use of electronic meters.
    Existing Sec.  3173.3(a)(9), requiring a seal for manual sample 
valves, would be eliminated in proposed Sec.  3173.21(a). The proposed 
rule would remove this requirement because most manual sample valves 
are less than 1-inch nominal size. Historically, the BLM has used the 
1-inch nominal size to delineate the size beyond which the removal of 
product from a production facility without measurement becomes easier. 
For example, proposed Sec.  3173.20(c)(4) designates a sample cock 
valve on piping or tanks of less than 1-inch nominal size as not an 
appropriate valve subject to sealing requirements. The proposed change 
provides consistency with the designation of what is not an appropriate 
valve in the proposed Sec.  3173.20(c) and the proposed sealing 
requirements on oil measurement systems in proposed Sec.  
3173.21(a)(6). The BLM believes manual sample valves in a production 
facility are unlikely to provide easy access for the removal of oil 
that has not been measured for royalty purposes.
    Existing Sec.  3173.3(a)(10), requiring a seal for valves on divert 
lines larger than 1 inch in diameter, would be eliminated in proposed 
Sec.  3173.21(a). Generally, production sent to a divert line does not 
meet sales quality specifications and would not be measured for 
production reporting for royalty purposes. Higher-volume facilities use 
electronic metering systems and operators may have the Programmable 
Logic Controller configured to show a load rejection in the event log. 
The event log record would allow BLM inspectors as well as operators, 
to account for diverted production and control loss risk on higher-
volume properties. Removal of the requirement for a seal for valves on 
divert lines poses a low risk for theft and mishandling and continues 
to insure proper measurement of oil on which royalty is due.
    Existing Sec.  3173.3(a)(12), requiring a seal for the totalizer, 
would be eliminated in proposed Sec.  3173.21(a). The BLM recognizes 
the sealing of an electronic meter totalizer is impractical. A seal on 
a mechanical meter counter head and mechanical meter head will be 
required in proposed Sec.  3173.21(a)(3). The proposed rule eliminates 
the impractical requirement for electronic meters and includes the 
practical seal requirement on mechanical meters in proposed Sec.  
3173.21(a)(3). The removal of the requirement for a seal on a totalizer 
of an electronic meter has a low risk of theft or mishandling of 
production while still maintaining accurate measurement at the FMP.
    Existing Sec.  3173.3(a)(13), requiring a seal for proving 
connections, would be eliminated in proposed Sec.  3173.3(a). The 
removal of the requirement to seal proving connections would restore 
the standard in Onshore Order No. 3, which had no seal requirement for 
proving connections. Mishandling or theft downstream of an FMP where 
these seals are located would not affect royalty revenues because 
royalties would be assessed on volumes measured at the FMP. After 
further consideration, the BLM has determined that the concern for 
sealing the proving

[[Page 55950]]

valves to prevent falsification of meter proving reports is unwarranted 
because a BLM inspector would easily detect a proving report that has 
only a changed date or looks exactly like previous proving reports. 
Therefore, the BLM would remove this requirement in the proposed rule.
    Proposed Sec.  3173.21(a)(3) would modify the meter-assembly 
sealing requirements now found in existing Sec.  3173.3(a)(4). The 
existing regulation requires a meter assembly, including the counter 
head and meter head, to be sealed. The proposed new language would 
require operators to seal the mechanical counter head (totalizer) and 
meter head on a mechanical meter only. The existing regulation created 
confusion with respect to the sealing requirements on a non-mechanical 
or electronic meter. There is no practical way to seal these components 
on an electronic meter. This change would clarify that the sealing 
requirement applies to mechanical meters, and not to non-mechanical 
meters that are used for measurement.
    Proposed Sec.  3173.21(a)(4) would modify the seal requirement for 
a temperature averager, now found in existing Sec.  3173.3(a)(5). The 
revised language would no longer refer to a seal requirement for a 
temperature averager, but instead to a seal requirement for a stand-
alone temperature averager monitor. This proposed revision would 
eliminate any confusion over built-in temperature averagers, which are 
impossible to seal. The change in the proposed rule maintains the same 
level of risk for mismeasurement as the current rule and will continue 
to provide for accurate measurement.
    Proposed Sec.  3173.21(a)(5) would revise the sealing requirement 
for a back-pressure valve downstream of the meter, now found in 
existing Sec.  3173.3(a)(7). The proposed new language would clarify 
that the seal requirement would apply only to fixed, non-automatic 
adjusting, back-pressure valves downstream of the meter. The result 
would be that operators could use automatic-adjusting back-pressure 
valves as intended, without having to modify the equipment in order to 
add seals to valves that adjust automatically based on operating 
conditions. A seal is used to maintain a fixed operating condition. 
Automatic-adjusting, back-pressure valves downstream of the meter vary 
with operating conditions. Sealing a piece of equipment designed to 
adjust to operating conditions does not make sense. This change is 
likely to improve measurement at locations with automatic-adjusting 
back-pressure valves downstream of the meter and maintain the same 
level of measurement accuracy at locations with fixed or non-automatic 
adjusting back-pressure valves downstream of the meter.
    Proposed Sec.  3173.21(a)(6) would clarify the sealing requirement 
for drain valves, now found in existing Sec.  3173.3(a)(8). The new 
language would clarify that the requirement would apply to drain valves 
used on piping with a nominal pipe size of 1 inch or larger. The 
existing language applies to any drain valve in the system. This change 
would eliminate the need for operators to seal most drain valves on 
sample pots on LACT units. The BLM believes that the proposed 
requirement would adequately addresses security concerns regarding 
access to production without accountability and provide clarity for 
industry compliance and BLM inspection. The proposed change maintains a 
low risk for improper measurement, theft, or mishandling of production.
Section 3173.31 Water-Draining Operations
    Existing Sec.  3173.6 requires operators to document specific 
information when draining water from production storage tanks. The 
existing regulation requires the operator, purchaser, or transporter, 
as appropriate, to document information as specified in existing Sec.  
3173.6(a) through (h) when water is drained from a tank storing 
hydrocarbons.
    This proposed rule would eliminate the specific requirements in 
Sec.  3173.6(a) through (h) and instead defer to the seal-record 
requirements in proposed Sec.  3173.41(b), which are currently in 
existing Sec.  3173.9(b). In the current rule, the operator was not 
required to submit the required information to the BLM via Sundry 
Notice. Operators have only been required to maintain a record of the 
information. This proposed change in documentation during water-
draining operations would not negate an operator's obligation to report 
produced water to ONRR on the Oil and Gas Operations Report (OGOR) Part 
A. The proposed change would, however, eliminate unnecessary burdens on 
operators by reducing the existing records requirements of Federal or 
Indian agreement number, land description of tank location, unique tank 
number and nominal capacity, date of the opening gauge, opening gauge, 
total observed volume and free water measurement, closing gauge and 
total observed volume to those maintained in a seal record. After 
review, the BLM believes the existing documentation requirements add 
minimal value to production accountability and is information available 
through internal records for water disposal. The proposed revision 
would require the operator, purchaser, or transporter, as appropriate, 
to maintain all seal records and make them available to the BLM upon 
request.
Section 3173.43 Data Submission and Notification Requirements
    The proposed rule would make only minor changes to existing Sec.  
3173.10. In addition to renumbering the section, the proposed rule 
would change the section heading from ``Form 3160-5 Sundry Notices'' to 
``Data submission and notification requirements.'' The proposed rule 
would also update regulatory cross references in paragraphs (a)(1) 
through (a)(7).
Section 3173.50 Site Facility Diagram
    Proposed Sec.  3173.50 would revise and renumber existing Sec.  
3173.11, which sets out the requirements for site facility diagrams.
    Proposed Sec.  3173.50(c)(3) would require operators to use the 
complete US well number on the site facility diagrams when identifying 
wells flowing into headers, instead of the API well number, as 
explained in the previous discussion on proposed Sec.  3170.10. The 
complete US well number provides the most accurate unique well 
identification, including completion and sidetrack information. For BLM 
inspectors, the US well number provides a unique well identifier, 
critical for their production facility inspections when Federal or 
Indian wells are co-located with non-Federal or non-Indian wells. 
Created by the PPDM Association in 2010, the US well number is the new 
industry standard for identifying oil and gas wells.
    Proposed Sec.  3173.50(c)(4) would correct an editing error in 
existing Sec.  3173.11(c)(4) regarding how an operator should depict a 
co-located facility on its site-facility diagram. The proposed change 
would require the operator of a co-located facility to identify the co-
operator by name on the site facility diagram and identify with a box 
on the diagram the approximate location of the co-located facility. The 
BLM acknowledges that an operator of a Federal or Indian lease, unit 
PA, or CA is not responsible for another operator's co-located 
facility. However, a BLM inspector would need to understand the extent 
of the operator's responsibilities at a site with co-located 
facilities. The proposed change would reduce the burden on operators of 
Federal or trust minerals, acknowledge the limits of the operator's 
responsibility, and allow

[[Page 55951]]

BLM inspectors to conduct appropriate facility inspections.
    Proposed Sec.  3173.50(c)(6) would remove the requirement in 
existing Sec.  3173.11(c)(6) for an operator of a co-located production 
facility to include on the site facility diagram a skeleton diagram of 
the other operator's co-located facility(ies). The proposed rule would 
maintain the existing requirement, in the second sentence of existing 
Sec.  3173.11(c)(6), for one diagram in the case of storage facilities 
common to co-located facilities and operated by one operator. The 
proposed change would acknowledge the extent of an operator's 
responsibility on Federal or Indian leases, unit PAs, or CAs and reduce 
the burden and difficulty of creating diagrams for another operator's 
facilities. With the proposed change, BLM inspectors would continue to 
complete appropriate facility inspections effectively.
    Proposed Sec.  3173.50(c)(8) would give operators options, in 
addition to using the assigned FMP number, for identifying the 
measurement equipment used for royalty reporting on-site facility 
diagrams. The proposed change would also eliminate the requirement that 
operators wait to receive an FMP number before submitting amended or 
new diagrams. The proposed revision gives the operator greater 
flexibility when filling out the site facility diagram and allows for 
the timely submission of both new and amended diagrams where an FMP 
number has not yet been assigned. BLM inspectors would be able to 
conduct facility inspections whether the operator provides the BLM-
assigned FMP number, the unique identifiers, or station identification 
(ID) numbers for the measurement equipment on its diagram.
    Proposed Sec.  3173.50(d)(1) would revise the timeframe in existing 
Sec.  3173.11(d)(1) for when an operator would have to submit a new, 
permanent site-facility diagram. The time frame would be changed from 
30 days after the BLM assigns an FMP to 60 days after the facility 
becomes operational. In addition, proposed Sec.  3173.50(d)(2) would 
change the timeframe in existing Sec.  3173.11(d)(2) for when an 
operator would have to submit an amended site facility diagram for a 
modified, existing facility. That time frame would be changed from 30 
days to 60 days after the facility is modified. The proposed 60-day 
timeframe would also apply when a non-Federal facility located on a 
Federal lease or a federally approved unit or communitized area is 
constructed or modified. The BLM is proposing this change because many 
site-facility diagrams are not prepared ``in-house'' and the 30-day 
deadline is difficult for operators to meet. This proposed change would 
retain the new operator's responsibility to submit amended site 
facility diagrams when the facility is modified in any way. The BLM 
believes extending the timeframe for submission of site facility 
diagrams on new, permanent facilities and modified, existing facilities 
from 30 days to 60 days would not interfere with the BLM's 
responsibility for facility inspections.
    Proposed Sec.  3173.50 eliminates the requirement (in existing 
3173.11(e)) to submit a site facility diagram for a location for which 
an FMP is not required. The BLM believes the existing requirement is 
covered by the requirement in proposed Sec.  3173.50(a) and so the 
deletion of existing 3173.11(e)(1) and (e)(2) removes a regulatory 
redundancy. Under Sec.  3173.50(a), operators would still be required 
to submit a site facility diagram for a location not requiring an FMP 
number.
    Proposed Sec.  3173.50(e) is a new section that would change the 
timeframe in existing Sec.  3173.11(f) for when an operator must update 
and amend a diagram. The proposed rule would give operators 60 days, 
instead of the current 30 days, to update and amend a diagram after a 
facility is modified or a non-Federal facility located on a Federal 
lease or federally approved unit or communitized area is constructed or 
modified. The BLM supports this change because many site-facility 
diagrams are not prepared ``in-house'' and the 30-day deadline is 
difficult for operators to meet. The proposed change would also delete 
the requirement to submit a modified site-facility diagram when there 
is a change of operator and the only change to the diagram would be the 
new operator's name. The BLM estimates the operator burden to prepare a 
new site facility diagram to be 4 hours of operator staff time at 
$65.40 per hour for a total of $262.40 to prepare a new site facility 
diagram. The BLM believes the proposed changes will lessen the burden 
and cost on operators to comply with the regulations, while continuing 
to allow the BLM to ensure production accountability.
Section 3173.60 Applying for a Facility Measurement Point Number
    Proposed Sec.  3173.60 would revise the existing requirements for 
the FMP-number application process that are now located in existing 
Sec.  3173.12.
    The proposed rule would change the section title slightly from 
``Applying for a facility measurement point'' to ``Applying for a 
facility measurement point number.'' This change would more accurately 
reflect the process of applying for and receiving an FMP number as 
opposed to applying for an FMP, which already exists as the point of 
royalty measurement even before the BLM issues an FMP number for it. 
The BLM proposes to delete existing Sec. Sec.  3173.12(a)(1), (a)(2), 
and (b) because these sections essentially define FMP, off-lease 
measurement, and commingling. Proposed Sec.  3170.10 already defines 
these terms. The proposed regulation would seek to make the distinction 
between an FMP--the point where oil or gas produced from a Federal or 
Indian lease, unit PA, or CA is measured, and where the measurement 
affects the calculation of the volume or quality of production on which 
royalty or injection and withdrawal fees are owed--and the FMP number. 
An FMP exists whether or not the BLM has assigned an FMP number. The 
proposed change would keep the definition of an FMP separate from the 
application for an FMP number and prevent confusion. In order to 
accommodate this change, the word ``number'' would be inserted after 
the word ``FMP'' throughout the revised section. Proposed Sec.  
3173.60(a) would add reference to gas storage agreement involving 
native gas or oil to the requirement of applying for an FMP number. 
This change would be necessary to address the changes proposed to the 
FMP definition.
    Proposed Sec. Sec.  3173.60(c)(1), (c)(2), and (c)(3) would change 
the tiers in existing Sec.  3173.12(e) that dictate the timeframes 
under which operators of permanent existing facilities would be 
required to apply for FMP numbers. Each tier is grouped by monthly 
production amounts with assigned compliance dates that would fall 
either 1, 2, or 3 years after the effective date of the final rule. The 
tiers in existing Sec. Sec.  3173.12(c)(1), (c)(2), and (c)(3) were 
derived from 2010 production data that was available when the existing 
regulations were written. The proposed rule seeks to replace the 
existing tiers with tiers derived from 2017 production data. The 
revised tiers better reflect the current operating environment by 
dividing the 2017 production data into equal thirds creating the new 
tiers. The proposed tier change would keep the application submissions 
by year split into thirds, reducing the burden on the BLM to process 
the influx of applications for existing locations when this section of 
the regulation goes into effect.
    Proposed Sec.  3173.60(c) would also delete the enforcement 
language in existing Sec.  3173.12(e)(7). Subpart 3163

[[Page 55952]]

provides standalone authority for an Incident of Noncompliance (INC) 
and civil penalties for noncompliance with this part. In addition, 
proposed Sec.  3170.70 provides further assurance the subpart 3163 
enforcement mechanisms can be used to enforce the part 3170 
requirements. Given the enforcement authority in other parts of the 
BLM's regulations, the BLM is proposing to delete this language without 
affecting the BLM's enforcement capacity.
    Proposed Sec.  3173.60(d) would list the information that the 
operator must include in its Sundry Notice requesting approval of an 
FMP number. These requirements are now found in existing Sec.  
3173.12(f). Existing Sec.  3173.12(f)(2) requires the applicant to 
provide the applicable Measurement Type Code. The proposed rule would 
remove this requirement, since the Measurement Type Code will be 
generated automatically by the Automated Fluid Minerals Support System 
(AFMSS) 2 currently in development. In AFMSS 2, the FMP-number 
applicant will answer a series of questions on the FMP Sundry Notice. 
Based on the information submitted, AFMSS 2 will generate the FMP 
number. The first two digits of the FMP number will be the Measurement 
Type Code identifier. The BLM believes the AFMSS 2 application process 
negates the need for operators to provide the Measurement Type Code as 
required in existing Sec.  3173.12(f)(2).
    Proposed Sec.  3173.60(d)(2)(i) through (iii) would revise the 
information that operators are now required to provide in their FMP 
applications about the equipment used for oil and gas measurement under 
existing Sec.  3173.12(f)(3)(i) through (iii).
    The BLM believes the proposed changes in Sec.  3173.60(d)(2)(i), 
(ii), and (iii) would provide for consistent FMP-number-application-
information requirements for gas measurement, oil measurement by tank 
gauge, and oil measurement by LACT or CMS. The proposed changes would 
also prevent operators from having to submit unnecessary information 
during the FMP number application process or information they are 
already required to provide elsewhere in the regulation.
    Proposed Sec.  3173.60(d)(2)(i) would change the information 
required under existing Sec.  3173.12(f)(3)(i) on FMP number 
applications for gas measurement. The BLM is proposing to remove the 
requirement that operators list the ``station number, primary element 
(meter tube) size or serial number, and type of secondary device 
(mechanical or electronic)'' and replace it with a requirement that 
operators provide ``the unique meter ID, and elevation.'' The revised 
paragraph would still require gas-measurement FMP applicants to list 
the operator, purchaser, or transporter's name, as appropriate. This 
change would eliminate confusion as to what is required to identify the 
primary element, remove non-relevant information such as the type of 
secondary device, and include the elevation. The BLM believes the 
revised requirement would provide the information the BLM needs for 
production accountability and verification.
    Under proposed Sec.  3173.60(d)(2)(ii), the equipment information 
required under existing Sec.  3173.12(f)(3)(ii) would remain the same 
for those applying for FMP numbers to measure oil by tank gauge. The 
only change would be that applicants would be required to specify the 
name of the operator, purchaser, or transporter, as appropriate. The 
additional information would make the new paragraph consistent with the 
information required for gas measurement and oil measurement by LACT or 
CMS in proposed Sec.  3173.60(d)(2)(i) and (iii).
    Proposed Sec.  3173.60(d)(2)(iii) would change the information 
requirements under existing Sec.  3173.12(f)(3)(iii) on FMP number 
applications for measuring oil by LACT or CMS. Purchasers, 
transporters, or parties other than the operator frequently operate the 
LACTs and CMS systems. The proposed change would require the operator 
to identify the purchaser or transporter, as appropriate, and the 
unique meter ID. The proposed change would also delete the requirement 
to identify whether the equipment is LACT or CMS, the associated oil 
tank number or serial number, and tank size. Much of the information 
required in existing Sec.  3173.12(f)(3)(iii) is currently required on 
a site facility diagram. The proposed change would better serve the BLM 
with information connected to the associated record keeping 
requirements of the FMP, while reducing the burden on the operator.
    Proposed Sec.  3173.60(d)(3) would replace the reference to API 
number in existing Sec.  3173.12(f)(4) with US well number. The 
proposed change would make the regulation consistent with the current 
industry standard for a unique well identifier.
Section 3173.61 Requirements for Approved Facility Measurement Points
    Proposed Sec.  3173.61 would revise the requirements in existing 
Sec.  3173.13 that specify when operators must start using their FMP 
numbers on production reporting to ONRR and when they must notify the 
BLM of any permanent changes made to an FMP.
    Proposed Sec.  3173.61(a) would require all existing and new 
facilities to start using their FMP numbers when reporting production 
to ONRR starting with the third production month after the BLM assigns 
the FMP number(s). This would be a change from existing Sec.  
3173.13(a), which makes a distinction between existing facilities that 
are in operation 60 days on or before January 17, 2017, and new 
facilities that are in service 60 days after January 17, 2017. The 
existing rule requires existing facilities to begin using the FMP 
number for reporting production to ONRR on the OGOR starting with the 
fourth production month after the BLM assigns the number and new 
facilities to begin using the number starting with the first production 
month after the BLM assigns the number.
    The proposed change would eliminate the burden on operators and the 
BLM to identify whether a facility is an existing or new facility based 
on the existing rule's publication date. The requirement for using an 
FMP number when reporting production to ONRR on OGORs would be tied 
only to the BLM's assignment of the FMP number. The BLM believes this 
change would eliminate confusion that has developed under the existing 
regulations due to delays with the development of AFMSS 2--the system 
that will be used to assign FMP numbers.
    Proposed Sec.  3173.61(b)(1) would not change from existing Sec.  
3173.13(b)(1). This paragraph would require operators to file a Sundry 
Notice within 30 days describing any permanent changes or modifications 
made to an FMP, including any changes to the information on an 
application submitted under proposed Sec.  3173.60.
    Proposed Sec.  3173.61 would delete existing Sec.  3173.13(b)(2) 
requiring the operator to include details, such as the primary element, 
secondary element, LACT/CMS meter, tank number(s), and wells or 
facilities when describing any changes or modifications made to an FMP 
under existing Sec.  3173.13(b)(1). The BLM believes the existing 
requirement is redundant and adequately covered under proposed Sec.  
3173.61(b)(1), which states in part, ``These include any changes and 
modifications to the information listed on an application submitted 
under Sec.  3173.60.'' The information required for applying for an FMP 
number would be sufficient to inform the BLM of an FMP modification. 
The existing regulation requires information in excess of that required 
on an initial FMP number application. The BLM believes the

[[Page 55953]]

deletion improves understanding of requirements and eliminates a 
redundancy.
Section 3173.70 Conditions for Commingling and Allocation Approval 
(Surface and Downhole)
    Proposed Sec.  3173.70 would revise the existing requirements for 
commingling and allocation approval that are now located in existing 
Sec.  3173.14.
    The BLM believes that commingling of production reduces the 
environmental footprint of oil and gas facilities and operators' 
capital expenditures. However, when considering an application for 
commingling of production, the BLM has an obligation to ensure the 
accuracy of measurement, the ability to verify reported production 
volumes, and the ability to audit reported production volumes going 
back 7 years on Federal minerals and 6 years on Indian trust minerals, 
as required by law. Based on in-house modeling using Monte Carlo 
simulation of produced volumes from multiple Federal interest 
percentages--as well as referencing a paper presented by Phillip 
Stockton, ``Cost Benefit Analyses in the Design of Allocation 
Systems,'' at the 27th International North Sea Flow Measurement 
Workshop in 2009 \2\--the BLM is concerned about uncertainty of 
measurement in commonly used test allocation methods. Many commingling 
applications the BLM receives present an allocation scheme based on 
well tests or a single Federal or Indian agreement test containing 
multiple wells. In a test allocation method, production from a well or 
agreement is directed to a test separator and tank for a test period 
varying from hours to days. Production measured during this test period 
is used to calculate the proportionate production attributable to the 
well or agreement from the total commingled production for a reporting 
month. Typical test allocation methods have a higher overall 
uncertainty of measurement than measurement performance goals for FMPs 
in proposed Sec.  3174.31 and Sec.  3175.31. From modeling, the BLM 
believes the uncertainty of measurement in allocation methods is more 
of a concern when the Federal or Indian mineral interests in the 
agreements proposed for commingling are dissimilar. As the disparity in 
Federal or Indian mineral interest in the agreements proposed for 
commingling increases, the overall uncertainty of measurement 
increases. The BLM would like to ensure there is no greater uncertainty 
in measurement in commingling and allocation methods than in non-
commingled production. With the changes proposed in this section, the 
BLM would expand its ability to approve commingling of production while 
preserving measurement performance.
---------------------------------------------------------------------------

    \2\ Phillip Stockton, ``Cost Benefit Analyses in the Design of 
Allocation Systems,'' in 27th International North Sea Flow 
Measurement Workshop 2009: Tonsberg, Norway, 20-23 October 2009 (Red 
Hook, NY: Curran, 2010).
---------------------------------------------------------------------------

    Proposed Sec.  3173.70(a)(1)(i) and (a)(1)(iii) would rescind the 
requirement for the same revenue and royalty distribution that was 
initially required in IM 2013-152, Attachment 2-1 Royalty Distribution, 
and subsequently included in existing Sec.  3173.14(a)(1)(i) and 
(a)(1)(iii). In practice, the BLM has discovered that it is difficult 
for BLM engineers to determine the revenue and royalty distribution 
based on the Federal lease type while reviewing applications for 
commingling. The BLM would be willing to forego this requirement given 
the difficulty in implementing it and the low risk that the BLM would 
approve commingling of Federal leases that have significantly diverse 
revenue and royalty distribution.
    Proposed Sec.  3173.70(a)(2) would remove the parenthetical 
requirement that an operator include an allocation method for produced 
water in its commingling application. The BLM's focus is on produced 
oil and gas on which there is a royalty obligation. If an approved 
commingling operation experiences an upset that results in significant 
oil in its water tanks, the operator would be required to account for 
the oil in the water tank based on the approved allocation method of 
oil production. The BLM believes the proposed change would eliminate an 
unnecessary requirement for commingling allocation approval and reduce 
the regulatory burden on operators and the BLM.
    Proposed Sec.  3173.70(a)(3) would change existing Sec.  
3173.14(a)(3) to allow a lease, unit PA, or CA to be included in a 
proposed Commingling and Allocation Approval (CAA) if it has an 
approved Application for Permit to Drill (APD), but no production at 
the time of the application. Under existing Sec.  3173.14(a)(3), only 
leases, unit PAs, or CAs producing in paying quantities or, in the case 
of Federal leases, capable of producing in paying quantities, may be 
included in a proposed CAA. The proposed change would allow operators 
to apply for commingling approval before drilling wells, based on 
production volume projections, supported by offset-well decline curve 
data, presented in the commingling application in proposed Sec.  
3173.71(j). The BLM recognizes that operators base their drilling and 
production-facility economics on projected production volumes and 
regularly design new-well facilities based on offset-well information. 
The BLM believes the proposed change in requirements for commingling 
and allocation approval would allow operators to plan more efficiently 
while limiting the BLM's measurement accountability risk. In addition, 
proposed Sec.  3173.76--which is discussed later in this preamble--
includes new provisions for terminating CAAs based on projected oil or 
gas volumes or oil or gas quality if the actual production exceeds 
projections (i.e., volumes are higher than projected).
    Proposed Sec.  3173.70(b)(2) would increase the existing average 
monthly production over the preceding 12 months for each Federal or 
Indian lease, unit PA, or CA proposed for the CAA from less than 1,000 
Mcf of gas per month or 100 barrels (bbl) of oil per month to less than 
6,000 Mcf of gas per month or 1,000 bbl of oil per month. The existing 
production volume thresholds were chosen because properties producing 
below these thresholds would almost always qualify as economically 
marginal properties as defined in Sec.  3173.10 under the proposed rule 
and in conditions under which commingling may be approved in proposed 
Sec.  3173.70(b).
    The BLM calculated the existing 100 bbl per month oil threshold 
based on a cost to achieve non-commingled measurement of production of 
$50,000 for oil, estimating the cost of setting a single small tank. 
The production rate required to achieve an 18-month payout of this 
investment assuming a $60 per bbl oil price, including taxes, royalty 
payments, and fixed and variable operating costs would be approximately 
100 bbl per month. Based on industry input and recent applications 
received for commingling approval, the BLM believes that the assumed 
capital expense estimate does not reflect current capital expenditures 
or construction costs to segregate production. With the advent of 
horizontal drilling and higher well production, industry claims the 
total construction cost to build a new facility is between $450,000 and 
$650,000 per well. The increase in the commingling oil threshold is 
based on a new estimate of $500,000 to achieve non-commingled 
measurement of oil production. The production rate required to achieve 
an 18-month payout of this capital investment, assuming $50 per bbl oil 
price including taxes, royalty payments, and fixed and variable 
operating costs

[[Page 55954]]

would be approximately 1,000 bbl per month of oil.
    The BLM used a similar approach for determining the gas threshold 
of 1,000 Mcf per month in the existing rule. The production rate 
required to achieve an 18-month payout of this investment assuming a 
cost to achieve non-commingled gas production of $20,000, a $3 per 
MMBtu gas price, and including taxes, royalty payments, and operating 
expenses was approximately 1,000 Mcf per month. Assuming a capital 
expense of $200,000, the same relative increase as oil, to achieve non-
commingled production, a gas price of $3 per MMBtu, and including 
taxes, royalty payments, and operating expenses, the proposed gas 
threshold would increase to 6,000 Mcf per month.
    Proposed Sec.  3173.70(b)(5) would add a new paragraph with a new 
condition for commingling and allocation approvals and renumber 
existing Sec.  3713.14(b)(5) to Sec.  3173.70(b)(6). Proposed Sec.  
3713.70(b)(5) would provide operators an opportunity to demonstrate to 
the BLM an allocation uncertainty based on a propagation of uncertainty 
method similar to that published in the Guide to the Expression of 
Uncertainty in Measurement, International Organisation for 
Standardisation, ISO/IEC Guide 98:1995. The overall allocation 
uncertainty analysis must: Meet the performance goals in proposed Sec.  
3174.31 and proposed Sec.  3175.31; show no allocation bias as a result 
of commingling allocation; state what the assumed underlying 
distribution is of the volumes generated in the analysis and support 
the use of the stated underlying distribution assumption; and be 
limited to four leases, unit PAs, or CAs proposed for commingling. The 
BLM proposes to limit the number of leases, unit PAs, or CAs to four 
based on assumed limitations of spreadsheets typically used in most 
offices. The BLM is concerned with the inherent risk to the uncertainty 
of allocation measurement for Federal or Indian trust mineral 
percentages in a commingling and allocation approval. If the applicant 
is able to demonstrate no risk to Federal or Indian trust mineral 
measurement, then the BLM could agree to a commingling and allocation 
approval. The BLM seeks comments on this proposed new condition for 
commingling and allocation approval. Specifically, the BLM would 
request comment from the public on the following:

    1. Would the applicant be able to perform the required analysis?
    2. Would an applicant use this condition to apply for 
commingling and allocation approval?
    3. Is there a better condition/method for ensuring no risk to 
measurement of Federal or Indian trust mineral interest and 
approving commingling and allocation?

Section 3173.71 Applying for a Commingling and Allocation Approval
    Proposed Sec.  3173.71 would revise existing requirements for 
commingling and allocation approval applications that are now located 
in existing Sec.  3173.15.
    Proposed Sec.  3173.71(a) would remove from existing Sec.  
3173.15(a) the provision stating that, if the commingling and 
allocation proposal includes off-lease measurement, a separate Sundry 
Notice required under existing Sec.  3173.23 is unnecessary as long as 
the information required under existing Sec.  3173.23(b) through (e) 
and, where applicable, existing Sec.  3173.23(f) through (i), is 
included in the request for approval for commingling and allocation. 
The proposed rule would require a separate Sundry Notice for off-lease 
measurement approval. The BLM would regard the commingling and 
allocation approval as a separate decision from the off-lease 
measurement approval. The BLM believes this would provide clarity for 
operators and the BLM on processing a commingling and allocation 
application. The BLM can foresee cases where a commingling and 
allocation application would be approved, but the off-lease measurement 
would be denied. The proposed new language would separate a decision on 
a CAA application from a decision on off-lease measurement. In 
addition, proposed Sec.  3173.71(a) would require separate Sundry 
Notices for approval of commingling and allocation of oil or gas. The 
BLM would like to separate oil CAA applications from gas CAA 
applications since the economics for each are calculated differently 
based on the proposed definition of economically marginal property in 
Sec.  3173.10.
    Proposed Sec.  3173.71(b) would change existing Sec.  3173.15(b) to 
require an operator to submit an off-lease measurement Sundry Notice 
request under proposed Sec.  3173.91 separately from and simultaneously 
with the Sundry Notice requesting commingling and allocation approval. 
The proposed rule would eliminate the ability to apply for off-lease 
measurement and commingling on the same Sundry Notice. The BLM believes 
this change would allow for a single decision on a single Sundry 
Notice. Since the requests for off-lease measurement and commingling 
and allocation approvals are related, but separate decisions, the 
operator would submit the Sundry Notices simultaneously.
    Proposed Sec.  3173.71(c) would delete the requirement in existing 
Sec.  3173.15(c) to include the allocation of produced water in a 
commingling and allocation application. The BLM would eliminate this 
requirement for the same reasons stated in the earlier discussion of 
proposed Sec.  3173.70(a)(2).
    Proposed Sec.  3173.71(f) would amend the requirement in existing 
Sec.  3173.15(f) for a surface-use plan of operations if new surface 
disturbance is proposed for the FMP or associated facilities on BLM-
managed land within the boundaries of the leases, units, and 
communitized areas from which production would be commingled. The 
proposed rule would require an applicant-certified statement of a 
surface-use plan of operations if new surface disturbance is proposed 
in a commingling application on BLM-managed land. By submitting a 
certified statement, the applicant is presenting a sworn statement that 
a surface-use plan of operations for the CAA has been prepared pursuant 
to regulation. If the BLM were to request the surface-use plan of 
operations, the applicant should be prepared to provide the plan. The 
proposed change would reduce the application submission and application 
review burdens while ensuring a surface-use plan of operation has been 
prepared.
    Proposed Sec.  3173.71(g) and Sec.  3173.71(i) would remove the 
requirement that an operator submit a right-of-way grant with its 
application for commingling and allocation approval if any of its 
facilities would be located on Federal or Indian land. Proposed Sec.  
3173.15(g) would instead require an operator to provide an applicant-
certified statement that it already has a right-of-way grant, approved 
under 43 CFR part 2880 or approved under 43 CFR part 2800, as 
applicable, for Federal rights-of-way. Existing Sec.  3173.15(g) and 
Sec.  3173.15(i) require an operator to submit the grant application as 
part of its CAA application. Proposed Sec.  3173.71(i) would reduce the 
requirement to the operator providing an applicant-certified statement 
that it already has a right-of-way grant, approved under 25 CFR part 
169 for rights-of-way over Indian lands. With the submission of a 
certified statement, the applicant is presenting a sworn statement that 
a right-of-way grant has been obtained pursuant to the appropriate 
regulation. Like the proposed change in Sec.  3172.71(f), the change in 
part (g) would also reduce application submission and review burdens on 
both industry and the BLM.
    Proposed Sec.  3173.71(j) would change the documentation 
requirements under existing Sec.  3173.15(j) to allow leases that

[[Page 55955]]

are not yet producing to be included in an application for a CAA. An 
operator would have to document that each lease, unit PA, or CA 
proposed for commingling has an approved APD and has offset-well 
decline curve data and offset well oil gravity and/or gas Btu content 
to support the projected production estimates contained in the CAA 
application. Under existing Sec.  3173.15(j), only leases, unit PAs, or 
CAs producing in paying quantities or, in the case of Federal leases, 
capable of producing in paying quantities, may be included in a 
proposed CAA application. This proposed change under Sec.  3173.71(j) 
would make it consistent with proposed changes in Sec.  3173.70(a)(3), 
which would allow commingling and allocation agreements to include 
properties that are not yet producing. The BLM believes this change 
would make it easier for operators to apply for and receive commingling 
approvals.
    Proposed Sec.  3173.71(a) would change existing Sec.  3173.15(a) to 
require that gas CAA applications must be submitted separately from oil 
CAA applications. Existing Sec.  3173.15(k) requires operators to 
submit gas analyses, if the CAA request includes gas, and oil 
gravities, if the CAA request includes oil. The BLM would like to 
separate gas CAA applications from oil CAA applications, since the 
economics for each are calculated differently. The BLM's decision to 
approve a gas CAA is separate from its decision to approve an oil CAA. 
The proposed language would say that all gas analyses, including Btu 
content or oil gravities, as applicable, for previous periods of 
production from the leases, units, unit PAs, or communitized areas 
proposed for includes in the CAA, for up to 6 years before the date of 
the application for approval of the CAA. The proposed inclusion of ``as 
applicable'' is for consistency with the requirement in proposed Sec.  
3173.71(a) for separate CAA applications for oil and gas.
Section 3173.72 Existing Commingling and Allocation Approvals
    Proposed Sec.  3173.72 would make small changes to the BLM's 
process, now described in existing Sec.  3173.16, for reviewing 
existing commingling and allocation approvals.
    Proposed Sec.  3173.72(a)(2)(i) would increase the threshold for 
grandfathered surface commingling from less than 1,000 Mcf of gas per 
month in existing Sec.  3173.16(a)(2)(i) to less than 6,000 Mcf of gas 
per month, and from less than 100 bbl of oil per month in existing 
Sec.  3173.16(a)(2)(ii) to less than 1,000 bbl of oil per month. In the 
existing rule, the thresholds in Sec.  3173.14(b)(2) and Sec.  
3173.16(a)(2) are identical. The proposed regulation maintains 
identical thresholds for these sections. The increased production 
thresholds are discussed earlier.
    Proposed Sec.  3173.72(d) would add a new provision that would 
further clarify the grandfathering of existing downhole commingling. 
During the implementation of the existing regulation, confusion arose 
as to whether the grandfathering of an existing downhole commingling 
approval simultaneously granted new surface commingling approval or the 
grandfathering of an associated surface commingling approval. This new 
paragraph would further clarify what constitutes a grandfathered 
downhole commingling approval. The BLM believes the proposed change 
would clarify the extent of the grandfathering of downhole commingling 
approvals.
Section 3173.74 Modification of a Commingling and Allocation Approval
    Proposed Sec.  3173.74(b) would add another condition to existing 
Sec.  3173.18 that would require an operator to have the CAA 
reevaluated by the BLM when actual production exceeds the projected 
production in the commingling application. The proposed rule would 
allow the BLM to rescind or revise the approval, or modify its 
conditions of approval, if the CAA's actual production volumes and 
quality from any of the leases, unit PAs, or CAs exceed the production 
projections provided in the CAA application. The inclusion of this 
provision to reevaluate a CAA based on projected production would 
provide the BLM with recourse if the operator fails to provide accurate 
projections in the application for commingling and allocation approval.
Section 3173.76 Terminating a Commingling and Allocation Approval
    Proposed Sec.  3173.76(a)(4) would add another reason for the BLM 
to terminate a commingling and allocation approval. If the CAA's 
production quantity and quality exceeds the operator's projections in 
the CAA application, the BLM would retain the authority to terminate 
the approval. The proposed change provides the BLM with recourse when 
an operator's actual production no longer supports the commingling 
approval previously granted.
Section 3173.80 Combining Production Downhole in Certain Circumstances
    Proposed Sec.  3173.80 would make a small change to the BLM's 
requirements for combining production downhole that are now located in 
existing Sec.  3173.21.
    Proposed Sec.  3173.80(a)(1) would change the words in existing 
Sec.  3173.21(a)(1) from ``drilled into'' to ``completed in.'' The BLM 
does not believe this change would be substantive and the change in 
terms would more accurately describe the downhole situation.
Section 3173.91 Applying for Off-Lease Measurement
    Proposed Sec.  3173.91 would clarify and simplify the requirements 
for an off-lease measurement application in existing Sec.  3173.23.
    Proposed Sec.  3173.91(a) would add new language that would clarify 
that operators would be required to submit separate Sundry Notices for 
applications for off-lease measurement for each oil and gas FMP. 
Existing Sec.  3173.23(a) requires operators to submit only one Sundry 
Notice for an off-lease measurement application. The BLM believes a 
decision for an off-lease measurement approval for a gas FMP is a 
separate decision from an off-lease measurement approval for an oil 
FMP. As such, these applications should be submitted on separate Sundry 
Notices.
    Proposed Sec.  3173.91(f) and (g) would require an operator 
applying for off-lease measurement to submit an applicant-certified 
statement that it already has a right-of-way grant for a Federal right-
of-way under 43 CFR part 2880 or 43 CFR part 2800, as applicable, or a 
right-of-way grant over Indian land under 25 CFR part 169. Existing 
Sec.  3173.23(f) and (g) require an operator to submit the grant 
application as part of its off-lease measurement application. The 
proposed change would make this section consistent with changes in 
proposed Sec.  3173.71(g) and (i), which are the proposed application 
requirements for commingling and allocation approval. The BLM believes 
this change would reduce regulatory burdens on both applicants and the 
BLM. The BLM would retain the ability to request the operator provide 
supporting documentation of the right-of-way grant when needed.
    Proposed Sec.  3173.91 would delete existing Sec.  3173.23(j), 
which requires an operator to submit a statement with its off-lease 
measurement application that indicates whether the proposal includes 
all, or only a portion of, the production from the lease, unit, or CA. 
The BLM believes existing Sec.  3173.23(j) requirement is unnecessary 
when applications for off-lease measurement are submitted on an FMP 
basis. Production from all FMPs from any lease, unit PA, or CA are 
fully

[[Page 55956]]

accounted for on the OGORs. The removal of this requirement would 
reduce operator regulatory burden.
Section 3173.190 Immediate Assessments for Certain Violations
Table 1 to Proposed Sec.  3173.29--Violations Subject to an Immediate 
Assessment
    The proposed rule would change the wording in existing Immediate 
Assessment 1, which calls for a $1,000 assessment when ``an appropriate 
valve on an oil storage tank was not sealed, as required by Sec.  
3173.2.'' Proposed Immediate Assessment 1 in Sec.  3173.190 would be 
changed to match the definition in proposed Sec.  3173.10, which would 
require valves to be ``effectively'' sealed. This change would clarify 
that the immediate assessment would apply to valves that have a seal 
but the seal is not effective.
    The proposed rule would remove the existing Immediate Assessment 2, 
which calls for a $1,000 assessment when ``an appropriate valve or 
component on an oil metering system was not sealed, as required by 
Sec.  3173.3.'' This proposal is in response to the sheer numbers of 
seals that are regularly required for the effective sealing of some 
components of an oil metering system (LACT or CMS), where each missing 
or ineffective seal is a separate violation and immediate assessment. 
This would not affect the requirement to effectively seal an 
appropriate valve or component covered in proposed Sec.  3173.10. Where 
an operator has systemic and re-occurring violations, the BLM may 
always take appropriate enforcement action.
3. Section-By-Section Discussion for Changes to Subpart 3174
    The proposed rule would renumber all of the sections in existing 
subpart 3174. The goal of this renumbering is to achieve formatting 
consistency among the various part 3170 regulations. Each category 
(e.g., tank storage and tank gauging measurement, LACT measurement, 
Electronic Liquids Measurement (ELM), CMS, and Proving) has been re-
numbered to a series in blocks of 10. The following table provides a 
cross-walk comparison of proposed subpart 3174 section numbers and 
their headings with the current subpart 3174 section numbers and 
headings. New proposed sections are identified by the word ``New'' in 
the existing subpart 3174 column.

------------------------------------------------------------------------
       Sec. existing subpart 3174           Sec. proposed subpart 3174
------------------------------------------------------------------------
3174.1 Definitions and acronyms........  3174.10 Definitions and
                                          acronyms.
3174.2 General requirements............  3174.20 General requirements.
3174.3 Incorporation by reference (IBR)  3174.30 Incorporation by
                                          reference (IBR).
3174.4 Specific performance              3174.31 Specific measurement
 requirements.                            performance requirements.
New....................................  3174.40 Approved measurement
                                          equipment and data
                                          requirements.
New....................................  3174.41 Measurement equipment
                                          requiring BLM approval.
New....................................  3174.42 Measurement equipment
                                          approved by regulation.
New....................................  3174.43 Data submission and
                                          notification requirements.
New....................................  3174.50 Grandfathering.
3174.2 General requirements............  3174.60 Timeframes for
                                          compliance.
3174.2 General requirements............  3174.70 Measurement location.
3174.5 Oil measurement by tank gauging-- 3174.80 Oil storage tank
 general requirements.                    equipment.
3174.5 Oil measurement by tank gauging-- 3174.81 Oil measurement by tank
 general requirements.                    gauging.
3174.5 Oil measurement by tank gauging-- 3174.82 Oil tank calibration.
 general requirements.
3174.6 Oil measurement by tank gauging-- 3174.83 Tank gauging
 procedures.                              procedures.
3174.6 Oil measurement by tank gauging-- 3174.84 Tank oil sampling.
 procedures.
3174.6 Oil measurement by tank gauging-- 3174.85 Determining S&W
 procedures.                              content.
3174.6 Oil measurement by tank gauging-- 3174.86 Tank oil temperature
 procedures.                              determination.
3174.6 Oil measurement by tank gauging-- 3174.87 Observed oil gravity
 procedures.                              determination.
3174.6 Oil measurement by tank gauging-- 3174.88 Measuring tank fluid
 procedures.                              level
3174.7 LACT systems--general             3174.90 LACT systems--general
 requirements.                            requirements.
3174.8 LACT systems--components and      3174.100 LACT systems--
 operating requirements.                  components and operating
                                          requirements.
New....................................  3174.101 Charging pump and
                                          motor.
3174.8 LACT systems--components and      3174.102 Sampling and mixing
 operating requirements.                  system.
New....................................  3174.103 Air Eliminator.
3174.8 LACT systems--components and      3174.104 LACT meter.
 operating requirements.
3174.8 LACT systems--components and      3174.105 Electronic temperature
 operating requirements.                  averaging device.
3174.8 LACT systems--components and      3174.106 Pressure-indicating
 operating requirements.                  device.
New....................................  3174.107 Meter Proving
                                          Connections.
3174.8 LACT systems--components and      3174.108 Back Pressure and
 operating requirements.                  Check Valves.
3174.10 Coriolis meter for LACT and CMS  3174.110 Coriolis meter
 measurement applications--operating      operating requirements.
 requirements.
3174.10 Coriolis meter for LACT and CMS  3174.120 Electronic liquids
 measurement applications--operating      measurement, ELM (secondary
 requirements.                            and tertiary device).
New....................................  3174.121 Measurement data
                                          system, MDS.
3174.9 Coriolis measurement systems      3174.130 Coriolis measurement
 (CMS)--general requirements and          systems (CMS) -- general
 components.                              requirements and components.
New....................................  3174.140 Temporary measurement.
3174.11 Meter-proving requirements.....  3174.150 Meter-proving
                                          requirements.
3174.11 Meter-proving requirements.....  3174.151 Meter prover.
3174.11 Meter-proving requirements.....  3174.152 Meter proving runs.
3174.11 Meter-proving requirements.....  3174.153 Minimum proving
                                          frequency.
3174.11 Meter-proving requirements.....  3174.154 Excessive meter factor
                                          deviation.
3174.11 Meter-proving requirements.....  3174.155 Verification of the
                                          temperature transducer.
3174.11 Meter-proving requirements.....  3174.156 Verification of the
                                          pressure transducer (if
                                          applicable).
3174.11 Meter-proving requirements.....  3174.157 Density verification
                                          (if applicable).
3174.11 Meter-proving requirements.....  3174.158 Meter proving
                                          reporting requirements.
3174.12 Measurement tickets............  3174.160 Measurement tickets.
3174.12 Measurement tickets............  3174.161 Tank gauging
                                          measurement ticket.

[[Page 55957]]

 
3174.12 Measurement tickets............  3174.162 LACT system and CMS
                                          measurement ticket or volume
                                          statement.
3174.13 Oil measurement by other         3174.170 Oil measurement by
 methods.                                 other methods.
3174.14 Determination of oil volumes by  3174.180 Determination of oil
 methods other than measurement.          volumes by methods other than
                                          measurement.
3174.15 Immediate assessments..........  3174.190 Immediate assessments.
------------------------------------------------------------------------

    Another goal of this proposed numbering is to reduce the levels of 
section paragraphs and make it easier to locate and cite to specific 
requirements. For example, the existing subpart 3174 section that 
covers tank gauging is Sec.  3174.6. Within this section, under 
paragraph (b), there are four levels of subparagraphs, which makes 
discerning the individual requirements of that section unnecessarily 
complex. The specific provisions that cover the procedure for 
determining the opening-tank fluid level are currently found at Sec.  
3174.6(b)(5)(i)(A) through (E). Under the proposed rule, the regulatory 
citation for determining the tank fluid level would be Sec.  
3174.88(a)(1) through (3). The BLM believes this change would benefit 
both industry and the BLM by making regulatory requirements more clear.
    The following discussion provides a section-by-section explanation 
of the proposed changes to subpart 3174. If a provision is not 
specifically discussed in this section-by-section analysis, then the 
provision is essentially the same as the existing regulation
Section 3174.10 Definitions and Acronyms
    This section lists definitions and acronyms that are used in this 
subpart.
    This proposed rule would relocate the definitions for 
``Configuration log'' and ``Event log'' in current Sec.  3174.1 to the 
definitions section for subpart 3170 (Sec.  3170.10), which defines 
terms that are used in more than one of the part 3170 subparts.
    The definition for ``Base pressure'' in current Sec.  3174.1 would 
be modified to include the value of gauge pressure at base conditions. 
This change comes from requests by operators to include gauge pressure 
in the definition because they utilize gauge pressure units in their 
data systems, rather than absolute pressure units. By including the 
addition of the value of gauge pressure at base condition any confusion 
of whether use of gauge pressure units is acceptable would be removed.
    A definition for ``Electronic liquid measurement'' would be added 
to support a new section that would address emerging hardware and 
software technologies that are associated with liquids measurement.
    Definitions for three new proposed oil FMP categories would be 
added: ``Very-high-volume FMP,'' ``High-volume FMP,'' and ``Low-volume 
FMP.'' These definitions are needed to accommodate a new phase-in 
schedule for the subpart 3174 requirements, a third uncertainty level 
category for oil measurement, new grandfathering provisions, and 
specific exemptions from certain requirements. The proposed FMP 
category volume thresholds are tied primarily to the risk to royalty, 
based on uncertainty levels and anticipated costs to retrofit the FMPs 
to achieve these minimum uncertainty levels. The BLM requests comment 
on the proposed oil FMP categories and their associated measurement 
performance standards and requirement for BLM-approved equipment.
    The proposed rule defines ``Low-volume FMP'' as any FMP that 
measures 50 bbl. oil/day or less over the averaging period. Low-volume 
FMPs would have to meet minimum requirement to ensure that measurements 
are verifiable under proposed Sec.  3174.31(c), but would be exempt 
from the minimum uncertainty requirements found in proposed Sec.  
3174.31(a) and the requirement to achieve measurement without 
statistically significant bias in proposed Sec.  3174.31(b). Under 
Sec.  3174.50, low-volume FMPs in service before the effective date of 
the final rule would be exempt from the BLM-approved equipment 
requirements of proposed Sec.  3174.41(a) through (i) until the listed 
equipment is replaced, or production levels at the FMP elevate it to 
the very-high-volume category. It is anticipated that low-volume FMPs 
would primarily consist of operations that employ manual tank-gauge 
measurement and would encompass an estimated 81 percent of the total 
FMPs, representing about 7 percent of reported production in calendar 
year 2017. For this category, all equipment and measuring procedures 
used to measure the volume and quality of oil for royalty purposes 
would have to comply with the requirements of subpart 3174 within 2 
years of the effective date of the final rule.
    The proposed rule defines ``High-volume FMP'' as any FMP that 
measures more than 50 bbl/oil per day, but less than 500 bbl oil/day 
over the averaging period. Proposed requirements for high-volume FMPs 
would ensure that measurements have no statistically significant bias, 
would be verifiable under proposed Sec.  3174.31(b) and (c), and would 
achieve an overall measurement uncertainty of 1.50 percent 
under proposed Sec.  3174.31(a). The BLM believes the production volume 
threshold would make it economically feasible for operators to retrofit 
their FMPs to meet the overall uncertainty requirements. It is 
anticipated that this category would primarily consist of operations 
that employ manual tank-gauge measurement, automatic tank gauge (ATG), 
and LACT measurement, and would encompass an estimated 15 percent of 
the total FMPs, representing approximately 28 percent of reported 
production in calendar year 2017. Under Sec.  3174.50, high-volume FMPs 
in service before the effective date of the final rule would be exempt 
from the BLM-approved equipment requirements of proposed Sec.  
3174.41(a) through (i) until the equipment listed in Sec.  3174.41(a) 
through (i) is replaced, or the production levels at the FMP elevate it 
to the very-high-volume category. The new equipment would then be 
required to be BLM-approved equipment. For high-volume FMPs, all 
equipment and measuring procedures used to measure the volume and 
quality of oil for royalty purposes would have to comply with the 
requirements of subpart 3174 within 2 years of the effective date of 
the final rule.
    The proposed rule defines ``Very-high-volume FMP'' as any FMP that 
measures 500 bbl oil or more over the averaging period. Proposed 
requirements for high-volume FMPs would ensure that measurements have 
no statistically significant bias, are verifiable under proposed Sec.  
3174.31(b) and (c), and would achieve an overall measurement 
uncertainty of 0.50 percent under proposed Sec.  
3174.31(a). The BLM believes the production volume threshold would make 
it economically feasible for operators to retrofit FMPs to meet the 
overall

[[Page 55958]]

uncertainty requirements. It is anticipated this category would 
primarily consist of operations that employ LACT and CMS measurement 
and would encompass an estimated 3.8 percent of the total FMPs. This 
category would have the strictest measurement requirements of the three 
proposed FMP categories. For this category, all equipment and measuring 
procedures used to measure the volume and quality of oil for royalty 
purposes would have to comply with the requirements of subpart 3174 
within 1 year of the effective date of the final rule.
    A definition for ``Measurement period'' would be added to provide 
clear guidance when filling out measurement tickets, volume statements, 
and quantity transaction records.
    The proposed rule would remove the definition for ``Outage 
gauging'' as the proposed rule would not contain a reference to 
``outage gauging.'' The reason for removing the outage gauging option 
is discussed in the tank-gauge section later in this preamble.
    The existing definition for ``Quantity transaction record (QTR)'' 
would be modified to include flow computers on LACTs, as well as on 
CMS, and would include any other systems approved by the BLM. The 
existing rule only addresses a QTR generated by a CMS, which has 
resulted in some confusion among operators, not knowing if this 
definition covered reports generated by LACTs and other BLM-approved 
equipment as well. This proposed change is intended to remove any 
confusion over QTR requirements.
    The existing Sec.  3174.1 definition for ``Tertiary device'' would 
be removed as it would be covered by the new definition of ``Electronic 
liquids measurement.''
    The existing ``Vapor tight'' definition stated that vapor tight 
meant capable of holding pressure differential only slightly higher 
than that of installed pressure-relieving and vapor recovery devices. 
There has been confusion within industry that the definition meant if a 
pressure relieving device relieved pressure at its pre-set pressure on 
the tank then the vapor tight condition had been compromised. The 
existing definition for ``vapor tight'' would be modified to clarify 
the intent to retain the vapor tight condition to the settings of 
installed pressure-relieving or vapor-recovery devices. This proposed 
change is intended to remove any confusion over the meaning of vapor 
tight.
Section 3174.20 General Requirements
    Currently located in existing Sec.  3174.2, this section would list 
the general requirements that do not fit in any of the other more 
specific sections of the proposed rule. The proposed changes for this 
section are primarily administrative, such as updating cross references 
to reflect the new numbering of this proposed rule and removing the 
phase-in and commingling language, which would be revised and moved to 
a new Sec.  3174.60, and a new Sec.  3174.70.
Section 3174.30 Incorporation by Reference (IBR)
    Building on existing Sec.  3174.3, this proposed section lists 34 
industry standards and recommendations that are proposed for 
incorporation by reference, either in whole or in part.
     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; Reaffirmed August 
2017 (``API 2.2A''). This standard describes the procedures for 
calibrating upright cylindrical tanks used for storing oil. There are 
no substantive changes to this standard; we are proposing to add 
approval for the new reaffirmation date of this standard.
     API MPMS Chapter 2--Tank Calibration, Section 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. This standard was previously approved for IBR and is 
unchanged.
     API MPMS Chapter 2--Tank Calibration, Section 2C, 
Calibration of Upright Cylindrical Tanks Using the Optical-
triangulation Method; First Edition, January 2002; Reaffirmed April 
2013 (``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. There are no substantive 
changes to this standard; we are proposing to add approval for the new 
reaffirmation date of this standard.
     API MPMS Chapter 3.1A, Standard Practice for the Manual 
Gauging of Petroleum and Petroleum Products; Third Edition, August 
2013; Reaffirmed December 2018 (``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). There are no 
substantive changes to this standard; we are proposing to add approval 
for the new reaffirmation date of this standard.
     API MPMS Chapter 3--Tank Gauging, Section 1B--Standard 
Practice for Level Measurement of Liquid Hydrocarbons in Stationary 
Tanks by Automatic Tank Gauging; Third Edition, April 2018 (``API 
3.1B''). This standard describes the level measurement of liquid 
hydrocarbons in stationary, above ground, atmospheric storage tanks 
using ATGs. This standard discusses automatic tank gauging in general, 
accuracy, installation, commissioning, calibration, and verification of 
ATG that measure either innage or ullage. There are no substantive 
changes to this standard; we are proposing to add approval for the new 
edition number of this standard.
     API MPMS Chapter 3--Tank Gauging, Section 6, Measurement 
of Liquid Hydrocarbons by Hybrid Tank Measurement Systems; First 
Edition, February 2001; Errata September 2005; Reaffirmed January 2017 
(``API 3.6''). This standard describes the selection, installation, 
commissioning, calibration, and verification of Hybrid Tank Measurement 
Systems. This standard also provides a method of uncertainty analysis 
to enable users to select the correct components and configurations to 
address for the intended application. There are no substantive changes 
to this standard; we are proposing to add approval for the new 
reaffirmation date of this standard.
     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. This standard was previously approved for IBR and is unchanged.
     API MPMS Chapter 4--Proving Systems, Section 2--
Displacement Provers; Third Edition, September 2003; Reaffirmed March 
2011; Addendum February 2015 (``API 4.2''). This standard outlines the 
essential elements of meter provers that do, and also do not, 
accumulate a minimum of 10,000

[[Page 55959]]

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. This standard was previously approved 
for IBR and is unchanged.
     API MPMS Chapter 4.5, Master-Meter Provers; Fourth 
Edition, June 2016 (``API 4.5''). This standard covers the use of 
displacement and Coriolis meters as master meters. The requirements in 
this standard are for single-phase liquid hydrocarbons. This standard 
was previously approved for IBR and is unchanged.
     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. This 
standard was previously approved for IBR and is unchanged.
     API MPMS Chapter 4.8, Operation of Proving Systems; Second 
Edition September 2013 (``API 4.8''). This standard provides 
information for operating meter provers on single-phase liquid 
hydrocarbons. This standard was previously approved for IBR and is 
unchanged.
     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. This standard was previously approved for IBR and is 
unchanged.
     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-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. This standard was previously approved for IBR and is 
unchanged.
     API MPMS Chapter 7.1, Temperature Determination--Liquid-
in-Glass Thermometers; Second Edition, August 2017 (``API 7.1''). This 
standard describes how to correctly use various types of liquid-in-
glass thermometers to accurately determine the temperatures of 
hydrocarbon liquids. This standard is proposed for incorporation for 
its standards covering the use of liquid-in-glass thermometers for 
temperature determination in tank-gauging operations.
     API MPMS Chapter 7--Temperature Determination, Section 2--
Portable Electronic Thermometers; Third Edition, May 2018 (``API 
7.2''). This standard describes the methods, equipment, and procedures 
for manually determining the temperature of liquid petroleum and 
petroleum products by use of a portable electronic thermometer. This 
standard is proposed for incorporation for its standards covering the 
use of portable electronic thermometers for temperature determination 
in tank gauging operations.
     API MPMS Chapter 7--Temperature Determination, Section 4--
Dynamic Temperature Measurement; Second Edition, January 2018 (``API 
7.4''). This standard describes methods, equipment, installation, and 
operating procedures for the proper determination of the temperature of 
hydrocarbon liquids under dynamic conditions in custody transfer 
applications. This standard is proposed for incorporation for its 
standards covering the use of dynamic temperature determination in LACT 
and CMS operations.
     API MPMS Chapter 8.1, Standard Practice for Manual 
Sampling of Petroleum and Petroleum Products; Fourth Edition, October 
2013, (``API 8.1''). This standard covers procedures and equipment for 
manually obtaining samples of liquid petroleum and petroleum products 
from the sample point into the primary containers. This standard was 
previously approved for IBR and is unchanged.
     API MPMS Chapter 8.2, Standard Practice for Automatic 
Sampling of Petroleum and Petroleum Products; Fourth Edition, November 
2016 (``API 8.2''). This standard describes general procedures and 
equipment for automatically obtaining samples of liquid petroleum, 
petroleum products, and crude oils from a sample point into a primary 
container. There are no substantive changes to this standard; we are 
proposing to add approval for the new edition number of this standard.
     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. This 
standard was previously approved for IBR and is unchanged.
     API MPMS Chapter 9.1, Standard Test Method for Density, 
Relative Density, or API Gravity of Crude Petroleum and Liquid 
Petroleum Products by Hydrometer Method; Third Edition, December 2012; 
Reaffirmed, May 2017 (``API 9.1''). This standard 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 Kilopascal (kPa) (14.696 psi) or less. There 
are no substantive changes to this standard; we are proposing to add 
approval for the new reaffirmation date of this standard.
     API MPMS Chapter 9.2, Standard Test Method for Density or 
Relative Density of Light Hydrocarbons by Pressure Hydrometer; Third 
Edition, December 2012; Reaffirmed, May 2017 (``API 9.2''). This 
standard covers the determination of the density or relative density of 
light hydrocarbons including liquefied petroleum gases having a Reid 
vapor pressure exceeding 101.325 kPa (14.696 psi). There are no 
substantive changes to this standard; we are proposing to add approval 
for the new reaffirmation date of this standard.
     API MPMS Chapter 9.3, Standard Test Method for Density, 
Relative Density, and API Gravity of Crude Petroleum and Liquid 
Petroleum Products by Thermohydrometer Method; Third Edition, December 
2012; Reaffirmed, May 2017 (``API 9.3''). This standard covers the 
determination, 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. There 
are no substantive

[[Page 55960]]

changes to this standard; we are proposing to add approval for the new 
reaffirmation date of this standard.
     API MPMS Chapter 10.4, Determination of Water and/or 
Sediment in Crude Oil by the Centrifuge Method (Field Procedure); 
Fourth Edition, October 2013; Errata, March 2015 (``API 10.4''). This 
standard describes the field centrifuge method for determining both 
water and sediment, or sediment only, in crude oil. This standard was 
previously approved for IBR and is unchanged.
     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''). 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. This 
standard was previously approved for IBR and is unchanged.
     API MPMS Chapter 12.1.1--Calculation of Static Petroleum 
Quantities--Upright Cylindrical Tanks and Marine Vessels; Fourth 
Edition, February 2019 (API 12.1.1). This standard guides users through 
the necessary steps to calculate static liquid quantities at 
atmospheric conditions in upright, cylindrical tanks, and marine tank 
vessels. This standard is proposed for incorporation for its standards 
covering the calculation of net standard volume for tank gauging 
operations.
     API MPMS Chapter 12--Calculation of Petroleum Quantities, 
Section 2--Calculation of Petroleum Quantities Using Dynamic 
Measurement Methods and Volumetric Correction Factors, Part 2--
Measurement Tickets; Third Edition, June 2003; Reaffirmed February 2016 
(``API 12.2.2''). This standard provides standardized calculation 
methods for the quantification of liquids and specifies the equations 
for computing correction factors, rules for rounding, calculation 
sequences, and discrimination levels to be employed in the 
calculations. There are no substantive changes to this standard; we are 
proposing to add approval for the new reaffirmation date of this 
standard.
     API MPMS Chapter 12--Calculation of Petroleum Quantities, 
Section 2-- Calculation of Petroleum Quantities Using Dynamic 
Measurement Methods and Volumetric Correction Factors, Part 3--Proving 
Report; First Edition, October 1998; Reaffirmed May 2014 (``API 
12.2.3''). This standard provides standardized calculation methods for 
the determination of meter factors under defined conditions. The 
criteria contained 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. There are no substantive changes to this standard; we are 
proposing to add approval for the new reaffirmation date of this 
standard.
     API MPMS Chapter 12--Calculation of Petroleum Quantities, 
Section 2-- Calculation of Petroleum Quantities Using Dynamic 
Measurement Methods and Volumetric Correction Factors, Part 4--
Calculation of Base Prover Volumes by the Waterdraw Method; First 
Edition, December, 1997; Errata July 2009; Reaffirmed September 2014 
(``API 12.2.4''). This standard provides standardized calculation 
methods for the quantification of liquids and 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 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. There are no 
substantive changes to this standard; we are proposing to add approval 
for the new reaffirmation date of this standard.
     API MPMS Chapter 13.3, Measurement Uncertainty; Second 
Edition, December 2017 (``API 13.3''). This standard establishes a 
methodology for developing an uncertainty analysis. There are no 
substantive changes to this standard; we are proposing to add approval 
for the new edition number of this standard.
     API MPMS Chapter 14, Section 3, Orifice Metering of 
Natural Gas and Other Related Hydrocarbon Fluids--Concentric, Square-
edged Orifice Meters, Part 1, General Equations and Uncertainty 
Guidelines; Fourth Edition, September 2012; Errata July 2013; 
Reaffirmed, September 2017 (``API 14.3.1''). This standard provides 
reference for engineering equations and uncertainty estimations. There 
are no substantive changes to this standard; we are proposing to add 
approval for the new reaffirmation date of this standard.
     API MPMS Chapter 18--Custody Transfer, Section 1--
Measurement Procedures for Crude Oil Gathered From Lease Tanks by 
Truck; Third Edition, May 2018 (``API 18.1''). This standard describes 
the procedures, organized into a recommended sequence of steps, for 
manually determining the quantity and quality of crude oil being 
transferred under field conditions. There are no substantive changes to 
this standard; we are proposing to add approval for the new edition 
number of this standard.
     API MPMS Chapter 21--Flow Measurement Using Electronic 
Metering Systems, Section 2--Electronic Liquid Volume Measurement Using 
Positive Displacement and Turbine Meters; First Edition, June 1998; 
Reaffirmed October 2016 (``API 21.2''). This standard provides for the 
effective utilization of electronic liquid measurement systems for 
custody-transfer measurement of liquid hydrocarbons. There are no 
substantive changes to this standard; we are proposing to add approval 
for the new reaffirmation date of this standard.
     API Recommended Practice (RP) 12R1, Setting, Maintenance, 
Inspection, Operation and Repair of Tanks in Production Service; Fifth 
Edition, August 1997; Reaffirmed April 2008; Addendum 1, December 2017 
(``API RP 12R1''). This recommended practice is a guide on new tank 
installations and maintenance of existing tanks. Specific provisions of 
this recommended practice are identified as requirements in this final 
rule. There are no substantive changes to this standard; we are 
proposing to add approval for the new Addendum 1 to this standard.
     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. This standard was previously approved for IBR and is 
unchanged.
    The BLM is proposing to remove six industry standards that are 
currently incorporated by reference in existing Sec.  3174.3.
     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 6.1 is 
proposed for removal due to the vagueness of its content. It is

[[Page 55961]]

not clear to the BLM what constitutes the enforceable content within 
the standard. To ensure consistent understanding and enforcement of the 
requirements, this rule would remove this standard and include new 
sections in the proposed rule (Sec. Sec.  3174.101, 3174.103 and 
3174.107) to capture the requirements that were intended to be 
addressed by API 6.1.
     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 Chapter 7 is currently under revision by API. 
Many of the requirements in this chapter that were incorporated into 
the existing subpart 3174 have been included in the published editions 
of other API Chapter 7 sections. The BLM is therefore proposing to 
remove the general reference to Chapter 7 and include specific API 
Chapter 7 sections.
     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 7.3 is currently 
under revision by API. This proposed rule does not specifically address 
fixed tank temperature determination methods and dynamic temperature 
determination is covered under API 7.4. The BLM is therefore proposing 
to remove this standard.
     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; Errata July 2009; 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 12.2.1 is proposed for removal 
because the BLM believes the content within this standard is 
sufficiently covered in incorporated standards API 12.2.2, API 12.2.3 
and API 12.2.4.
     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 13.1 is 
proposed for removal because it has been superseded with no replacement 
available. The BLM believes the statistical concepts provided by this 
standard are sufficiently covered in incorporated API 13.3.
     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 18.2 is proposed for 
removal due to the confusion surrounding the standard's content and how 
the standard fits into the BLM's PMT review and the BLM's approval 
process. The BLM has found that there is significant confusion as to 
what methods and processes outlined in API 18.2 are automatically 
approved and supersede the requirement that operators follow the PMT 
review and BLM approval process for a method or process not 
specifically outlined in the regulations. The BLM did not intend for 
API 18.2 to override the PMT review and BLM approval process. Rather, 
this API standard was meant to assist industry in considering 
alternative methods for the BLM to review for approval. The BLM still 
recommends that industry use API 18.2 as guidance when considering 
alternative methods for the BLM to review for approval.
Section 3174.31 Specific Measurement Performance Requirements
    Currently located in existing Sec.  3174.4, this proposed section 
specifies the measurement-performance requirement for each FMP. The 
uncertainty volume levels proposed in Sec.  3174.31(a) align with the 
new FMP categories as previously discussed. The overall uncertainty 
tolerances have been reviewed, taking into consideration current 
equipment capabilities and industry standard practices and procedures. 
The BLM believes the current overall uncertainty tolerances of 0.50 percent and 1.50 percent are reasonable for 
very-high-volume (>15,000 Bbl per month) and high-volume (>1,500 Bbl 
per month and <15,000 Bbl/month) FMPs, respectively, and therefore the 
BLM would retain these uncertainty tolerances in the proposed rule. As 
in the current rule, the BLM believes the proposed rule's measurement 
uncertainties are reasonable, based on available equipment 
capabilities, industry standard practices and procedures, and BLM field 
experience. The BLM specifically requests comment on whether the 
proposed uncertainty requirements and production thresholds 
combinations are appropriate, or if different combinations should be 
considered. The BLM is particularly interested in the views of States 
and other non-Federal leaseholders with significant oil and gas 
production and who may have experience in implementing different 
thresholds based on their own assessments of risk tolerance and 
compliance costs. Specifically,
    (1) Are the proposed uncertainty levels and FMP category 
combinations reasonable or unreasonable and why?
    (2) What would be a better uncertainty level and FMP category 
recommendation to minimize risk of mismeasurement and compliance costs 
and why?
    Notably, the new low-volume FMP category would be exempt from 
overall uncertainty requirements. This exemption is intended to cover 
the wells that are such low producers that they could be rendered 
uneconomical by the measurement performance thresholds, thereby 
avoiding premature shut-in or plugging of these wells. The assumption 
is that measurement within this category will comply with the 
requirements for manual tank gauge operations, which tend to be the 
least expensive measurement process.
    The existing paragraph Sec.  3174.4(b) would be renumbered to Sec.  
3174.31(b) with no change to the language concerning bias.
    The existing paragraph Sec.  3174.4(c) would be renumbered to Sec.  
3174.31(c) with no change to the language concerning verifiability.
    The existing paragraph Sec.  3174.4(d), requiring alternative 
equipment to meet or exceed the performance requirements of this 
section, would be moved to Sec.  3170.3 because this requirement 
applies to both subparts 3174 and 3175.

[[Page 55962]]

Section 3174.40 Approved Measurement Equipment and Data Requirements
    The BLM is proposing to add new Sec. Sec.  3174.40 through 3174.43, 
which would consolidate approved measurement equipment and data 
requirements in one place, rather than having them scattered throughout 
the regulation, as they are in existing subpart 3174. This would make 
it easier for operators and BLM employees to find this information.
Section 3174.41 Measurement Equipment Requiring BLM Approval
    Under the proposed rule, the equipment requiring BLM approval prior 
to use would be listed in Sec.  3174.41. The introductory paragraph to 
Sec.  3174.41 would direct operators to the BLM's website to locate the 
list of PMT-reviewed and BLM-approved equipment and corresponding 
requirements. This section also would inform operators that the BLM 
website provides instructions on how to apply for BLM approval for a 
piece of equipment through the PMT, and would list the BLM's 
recommended equipment testing procedures. These testing procedures 
would be recommended, rather than required, and would not be adopted 
through the notice-and-comment rule-making process. The BLM is 
proposing to recommend testing procedures rather than adopt a set of 
required testing procedures through notice-and-comment rule-making to 
allow the BLM flexibility in modifying its recommended procedures as 
technology develops, based on experience and input from operators and 
manufacturers, without undergoing the time-consuming rule-making 
process. The BLM is concerned that codifying approved testing 
procedures by regulation would encumber the BLM and operators with 
outdated testing procedures that conflict with testing procedures 
developed by industry associations or are not workable for 
unanticipated technologies or methods. In addition, by recommending 
testing procedures as opposed to requiring operators to use specific 
approved procedures, the BLM would give operators additional 
flexibility in choosing which procedures to employ, so long as they can 
demonstrate that the testing procedure results in reliable data. As 
explained in the discussion of proposed Sec.  3170.30 earlier, the 
purpose of the PMT review process, and any associated testing 
procedures, would be to assess whether the proposed alternative 
equipment meets the minimum performance standards of subpart 3174. The 
BLM would tailor any recommended testing procedure to the narrow 
purpose of the PMT review process, which is verifying that the 
equipment meets the minimum performance standards codified in the 
regulation. The recommended testing procedures would be informed by the 
PMT's measurement expertise and, in general, would involve a baseline 
accuracy test and inform the PMT regarding a range of relevant 
operating conditions (e.g., pressure) in which the equipment meets the 
minimum performances standards. Where possible, the BLM's recommended 
testing procedures will reflect widely accepted testing procedures, 
such as those developed by other regulatory agencies, equipment testing 
authorities, and industry associations (e.g., the International 
Organization of Legal Metrology, the Measuring Instruments Directive, 
Measurement Canada, NIST, and API). The BLM recognizes that there is a 
tradeoff between this flexibility and allowing for public comment on 
testing procedures, through a rulemaking process. The BLM requests 
comment on this tradeoff. Finally, the BLM notes that the information 
provided on its website with respect to the PMT review process and its 
recommended testing procedures may be considered ``guidance documents'' 
subject to the requirements of Executive Order 13891, ``Promoting the 
Rule of Law Through Improved Agency Guidance Documents.''
Section 3174.42 Approved Measurement Equipment
    Under the proposed rule, the measurement equipment that would be 
automatically approved for use would be listed in Sec.  3174.42. The 
purpose of proposed Sec.  3174.42 is to better organize subpart 3174 by 
listing in one place the equipment that does not require additional BLM 
approval. Specific section citations are included as well in order to 
expedite locating the requirements for the pieces of equipment within 
subpart 3174.
Section 3174.43 Data Submission and Notification Requirements
    Under the proposed rule, Sec.  3174.43(a) would list the 
information that operators must submit to the BLM using a Sundry Notice 
and paragraph (b) would list the information that they must submit to 
the BLM upon request of the Authorized Officer (AO).
    The purpose of proposed Sec.  3174.43 is to better organize subpart 
3174 by listing in one place the data submission and notification 
requirements of subpart 3174. Specific section citations are included 
as well to expedite locating the requirement within subpart 3174.
Section 3174.50 Grandfathering
    The BLM is proposing new Sec.  3174.50, which introduces the 
concept of ``grandfathering'' to address certain facilities in 
operation prior to the effective date of this rule. The grandfathering 
provisions would no longer be applicable if the oil FMP moves to the 
proposed very-high volume category or if the measurement equipment is 
replaced.
    Under the existing regulations (Sec. Sec.  3174.6(b)(5)(ii)(A), 
3174.6(b)(5)(iii), 3174.8(a)(1), and 3174.9(a)), the operator can use 
only certain pieces of equipment that have been approved by the BLM, 
through the PMT, and placed on the list of BLM-approved equipment. The 
implementation of this provision was delayed until January 17, 2019, 
under Sec.  3174.2(g) and was further delayed by practical necessity 
(see IM 2018-077 (June 29, 2018)).
    Proposed Sec.  3174.50 would exempt all equipment listed in 
proposed Sec.  3174.41 that is in place at high- or low-volume FMPs on 
or before the effective date of the final rule from having to have 
approval prior to use. Equipment at very-high-volume FMPs, measurement 
data systems (see proposed Sec.  3174.121(a)) at high- and low-volume 
FMPs, and temporary measurement equipment (see proposed Sec.  3174.140) 
at high- and low-volume FMPs would not be exempt regardless of the date 
of installation.
    The BLM is not proposing to grandfather equipment installed at 
very-high-volume FMPs because of the higher risk of significant 
mismeasurement due to the high volume of oil measured and because the 
revenue resulting from the high volumes would make replacing equipment, 
if necessary, economically feasible. Portable electronic thermometers 
are not being proposed for grandfathering due to accuracy limitations 
between devices of different manufacture and models. Oil temperature is 
a significant factor in volume corrections to net standard volume. The 
BLM believes that grandfathering these devices without quantifying 
their accuracy at operating conditions could pose a significant risk to 
royalty income. Measurement data systems are not being proposed for 
grandfathering due to the potential that impacts to royalty income 
could be significant if net standard volume calculations are not 
properly calculated. Temporary measurement equipment is not proposed to 
be grandfathered due to issues that have been identified,

[[Page 55963]]

discussed further in the Sec.  3174.140 discussion later in the 
preamble.
    There are three reasons that the BLM is proposing to add this 
grandfathering provision. First, shortly after its inception, the PMT 
realized that the workload of reviewing data from all existing makes, 
models, and sizes of equipment requiring approval under existing 
subpart 3174 would be enormous and could take years to complete. 
Second, operators have expressed concerns about the cost of replacing 
existing equipment that was not on the BLM list of approved equipment, 
especially at lower-volume FMPs. Third, operators are concerned about 
purchasing equipment prior to the effective date of the implementation 
of the requirement to use of BLM-approved equipment. Specifically, 
operators are concerned about having to replace the newly purchased 
equipment should the equipment not be on the BLM's list of approved 
equipment. Grandfathering would allow any equipment in place at high- 
or low-volume FMPs prior to the effective date of the rule to remain in 
place until the equipment is replaced. Equipment installed after the 
effective date of the rule would not be grandfathered, but the 
requirement to use only BLM-approved equipment would not be effective 
until 2 years after the effective date of the rule.
    Based on these concerns, the BLM proposes grandfathering all 
equipment listed in Sec.  3174.41(a) through (i) and installed at high- 
or low-volume FMPs existing prior to the effective date of the final 
rule.
    The BLM believes almost all of the FMPs in the proposed low-volume 
category use manual tank gauging and would not have been subject to BLM 
approval under the current regulations. Therefore, grandfathering FMPs 
in this category would not be expected to have a substantive impact 
with respect to measurement accuracy or cost-savings.
    For the FMPs in the proposed high-volume category, the effect of 
grandfathering depends on the measurement method. If the FMP uses 
manual tank gauging, then there would be no incremental effect since 
the FMP would not have been subject to BLM approval under the current 
regulations. If the FMP uses measurement equipment, then that equipment 
would be grandfathered and would no longer be subject to BLM approval, 
as it is under the current regulations. The BLM notes that under 
current regulations, the uncertainty level is high enough such that 
most meters would easily meet the uncertainty level and be approved. 
Therefore, the grandfathering of this equipment would generally result 
in a reduction of administrative costs only. It would dramatically 
decrease the number of makes, models, and sizes of equipment that would 
be subject to review by the PMT and would assure operators that they 
would not have to replace this equipment, reducing a potential 
financial burden and providing some operational certainties to 
operators.
    The BLM notes that the proposed rule would increase the number of 
volumetric categories from two to three, and would reduce the 
production threshold for the most highly regulated category from 30,000 
bbl/month to 15,000 bbl/month. Compare current Sec.  3174.4 with 
proposed Sec. Sec.  3174.10, 3174.31. Due to this proposed change, more 
FMPs would fall in the ``very-high'' category and would be subject to 
more stringent measurement standards. On the whole, the BLM estimates 
that the additional costs associated with that change would more than 
offset the potential cost savings from the grandfathering provisions.
    The proposed grandfathering could have some impacts on the BLM's 
ability to ensure accurate measurement, the absence of statistically 
significant bias, and verifiability, all of which are required under 
the performance goals in both the existing regulations and the proposed 
regulations (see current Sec.  3174.4 and proposed Sec.  3174.31). For 
example, for high-volume FMPs, which must comply with the uncertainty 
performance goals under Sec.  3174.31 of the proposed rule, the 
grandfathering of equipment could impact the BLM's ability to ensure 
accurate measurement. The uncertainty calculation, which is used to 
determine and enforce overall uncertainty, would be based on the 
manufacturer's specifications for that device. It has been the BLM's 
experience that manufacturers develop specifications based on 
proprietary test procedures and test data interpretation methods that 
make it difficult to understand the actual field performance of their 
devices. The actual overall measurement uncertainty of these 
grandfathered devices has the potential to be substantially worse than 
the measurement uncertainty of those devices which are not 
grandfathered and that are subject to independent review and analysis 
by the PMT based on laboratory test data captured following the BLM 
test procedures.
    The BLM is concerned with the inherent risk to the measurement 
uncertainty for Federal or Indian trust mineral percentages in the 
grandfathering of equipment currently in use. The BLM seeks comments on 
these proposed new conditions for grandfathering of existing equipment. 
Specifically, the BLM would request comment from the public on the 
following:

    1. What would be the overall impact for not allowing or allowing 
this grandfathering option?
    2. Are the thresholds for the proposed grandfathering set at 
appropriate levels?
    3. Is there a better option or method for ensuring no risk to 
measurement of Federal or Indian trust mineral interest while 
allowing for the continued use of equipment currently in service?
Section 3174.60 Timeframes for Compliance
    The compliance timeframes for current subpart 3174 are located in 
existing Sec.  3174.2(e), (f), and (g). Proposed Sec.  3174.60 would 
establish new phase-in periods based on the FMP installation date and 
the FMP category (very-high-volume, high-volume, or low-volume).
    Proposed Sec.  3174.60(a) would require all FMPs installed after 
January 17, 2017, to comply with the existing and proposed subpart 3174 
requirements. The BLM believes this timeframe is justified because 
existing requirements became effective on January 17, 2017, and 
operators with FMPs installed after that date should already be meeting 
these requirements. The majority of the changes in this proposed rule 
would clarify existing requirements, or make minor modifications to 
existing requirements, and would not require immediate retrofitting. 
This further supports requiring immediate compliance for these FMPs.
    Based on the timing of the FMP number application process outlined 
in subpart 3173, the existing subpart 3174 phase-in periods for 
existing FMPs was intended to range from 1 to 3 years. Due to extended 
programming issues, the BLM's new AFMSS 2 data system's ability to 
accept FMP-number applications has been delayed, resulting in delays to 
the subpart 3174 phase-in periods. As of the publication of this 
proposed rule, the AFMSS 2 database is still not capable of accepting 
FMP number applications. For this reason the BLM is proposing Sec.  
3174.60(b) to modify the phase-in criteria for FMPs in existence after 
January 17, 2017. All very-high-volume FMPs existing as of January 17, 
2017, would need to comply with this rule within 1 year after the 
effective date of the final rule. All high-volume and low-volume FMPs 
existing as of January 17, 2017, would need to comply with this rule 
within 2 years after the effective date of the final rule. After the 
existing rule became effective on January 17, 2017, operators began

[[Page 55964]]

requesting to use ATG and Coriolis meters at their existing FMPs. 
Subpart 3174 is not structured to allow early compliance at existing 
FMPs. The BLM issued policy in IM 2018-069, June 29, 2018 giving 
guidance and recommendations to BLM field offices to facilitate early 
adoption of ATG and Coriolis meters. Proposed Sec.  3174.60(b)(3) would 
allow an operator to voluntarily begin full compliance with the 
requirements of this subpart at any FMP prior to the mandatory 
compliance dates specified in paragraphs (b)(1) and (b)(2). The BLM 
inspection and enforcement staff would need to inspect the FMP to the 
correct regulation, so the BLM would need to be notified if an FMP has 
begun early compliance. The operator would be required to notify the AO 
within 30 days by Sundry Notice of the date the FMP began early 
compliance.
    Proposed Sec.  3174.60(c) would require FMPs installed before 
January 17, 2017, to continue to comply with Onshore Oil and Gas Order 
No. 4, and any COAs, written orders, and applicable variances until the 
compliance deadlines specified in paragraph (b) are reached or the 
operator begins voluntary compliance with the subpart 3174 
requirements.
    Proposed Sec.  3174.60(d) would rescind all requirements and 
standards related to measurement of oil established by Onshore Oil and 
Gas Order No. 4, and any COAs, written orders, and variances once the 
phase-in date has passed.
    Proposed Sec.  3174.60(e) would delay the equipment-approval 
requirements that are listed in proposed Sec.  3174.41 for 2 years 
after the effective date of the final rule. This delay would provide 
the BLM with the time necessary to review and approve equipment as 
proposed in Sec.  3174.41.
Section 3174.70 Measurement Location.
    This new section would use identical language from existing Sec.  
3174.2 to prohibit commingling and off-lease measurement except where 
prior BLM approval has been obtained pursuant to the appropriate 
provisions in subpart 3173.
3174.80 Oil Storage Tank Equipment
    This new section proposes only one minor change for oil storage 
tanks from existing Sec.  3174.5(b). Under the proposed rule, 
compliance with standard API 12R1 would be limited to compliance with 
subsection 4 of that standard, as opposed to compliance with the entire 
recommended practice (RP). The existing rule incorporates the entire 
API RP 12R1, which requires the BLM to be involved in the maintenance 
and repair of tanks. The maintenance and repair of tanks is the 
responsibility of the operator and is not an appropriate subject for a 
regulation focused on accurate measurement.
    Paragraphs (a) through (d) contain requirements that apply to all 
oil storage tanks, whether a single tank or tank battery connected to a 
LACT or set up for tank gauging measurement.
    The requirements of paragraphs (e) and (f) would only apply to 
tanks configured for tank-gauging measurement.
3174.81 Oil Measurement by Tank Gauging
    This section would contain the same language as the existing Sec.  
3174.5(a), with the exception of updating the citations for the tank 
gauging requirements. This section identifies, by the reference to the 
relevant sections in the subpart, the required processes for obtaining 
the data necessary to determine total net standard volume removed from 
a tank by manual tank gauging operations.
3174.82 Oil Tank Calibration
    This section contains requirements for calibrating an oil storage 
tank when the tank is to be used as an FMP for tank-gauging operations. 
The same API standards are being proposed for incorporation as in 
current Sec.  3174.5(c), namely, API 2.2A, API 2.2B, API 2.2C, and API 
RP 2556.
    In addition to retaining the requirements of current Sec.  
3174.5(c), three additional requirements are being proposed for FMP 
oil-tank calibration. First, the tank-capacity tables would be required 
to be calculated for a tank-shell temperature of 60 [deg]F. This is 
recommended in API 2.2A and the BLM believes this should be a 
requirement, rather than an option. This change would standardize all 
FMP tank-capacity tables to one tank shell temperature. Second, FMP 
tank-capacity tables would be required to be recalculated if the 
reference gauge point is changed. This is another recommendation in API 
2.2A that the BLM believes should be a requirement in order to ensure 
the most accurate volumes are being obtained from FMP tank-capacity 
tables. Third, FMP tank-calibration charts (tank tables) would be 
required to be submitted to the AO by Sundry Notice within 45 days 
after a calibration or recalculation of charts. This is a change to the 
existing rule that only requires operators to submit FMP tank 
calibration charts to the AO after calibration without specifying how 
they are to be submitted. The BLM is proposing this change to require 
submission both upon initial calibration and whenever an FMP tank-
calibration chart is recalculated for any reason. The BLM needs to have 
the most current FMP tank-calibration charts in its records and is 
specifying in proposed Sec.  3174.82(d) that FMP tank-calibration 
charts (tank tables) would be required to be submitted to the AO by 
Sundry Notice would provide a common tracking mechanism for the BLM to 
use to ensure that this requirement has been met.
3174.83 Tank Gauging Procedures
    Proposed Sec.  3174.83(a) reiterates the requirement located in 
existing Sec.  3174.6(a). Proposed Sec.  3174.83 references other 
sections that contain procedures that operators must follow to 
determine the quality and quantity of oil measured under field 
conditions at an FMP. This section employs the same language as 
existing Sec.  3174.6(a) with exception of adding the cross-references 
to other sections.
    Proposed Sec.  3174.83(b) follows existing Sec.  3174.6(b), with 
the exception of removing a reference to API 18.2. The BLM proposes to 
remove the reference to API 18.2 because of the confusion surrounding 
the application of the content of the standard. The previous discussion 
of Sec.  3174.30 provides more detail concerning API 18.2 and the 
decision to not include it in revised subpart 3174.
    Proposed Sec.  3174.83(c) contains proposed changes to the run-
ticket section (existing Sec.  3174.12(a)). There has been confusion 
both within the BLM and industry as to what extent operators must 
complete the calculations required in existing Sec.  3174.12(a) during 
field operations. Some believe the existing rule requires that field 
operations must complete all the run-ticket calculations found in Sec.  
3174.12(a). This was not the BLM's intent. The current regulation 
dictates the required calculations, but not when or where these 
calculations could be made. This proposed section would clarify that 
the field staff is required to collect only the observed data specified 
in proposed Sec.  3174.161(a) in the field.
    Proposed Sec.  3174.83(d) expresses the same requirement as 
existing Sec.  3174.6(b)(1).
    Proposed Sec.  3174.83(e) reflects the requirement currently 
contained in existing Sec.  3174.6 (b)(7). However, the reference to 
``break[ing] the tank load line valve seal'' would be removed. There 
may be situations where the transfer is not to a tanker truck but 
rather down a pipeline, so this language

[[Page 55965]]

has been deleted to remove any potential confusion.
3174.84 Tank Oil Sampling
    This section reflects the requirement currently located in existing 
Sec.  3174.6(b)(3), with a proposed modification that would allow for 
alternative methods approved by the BLM.
3174.85 Determining S&W Content
    This section reflects the requirement currently located in existing 
Sec.  3174.6(b)(6). This proposed section employs the same language as 
current Sec.  3174.6(b)(6) with the exception of updating the cross-
references.
3174.86 Tank Oil Temperature Determination
    This section reflects the requirements currently located in 
existing Sec.  3174.6(b)(2) with a few clarifying changes.
    Under Sec.  3174.86 of the proposed rule, the BLM would eliminate 
the sentence in existing Sec.  3174.6(b)(2) which reads: ``Opening 
temperature may be determined before, during, or after sampling.'' The 
BLM has determined that this sentence may cause confusion and is 
unnecessary. The temperature of oil contained in an FMP tank would be 
required to be determined by following the requirements of paragraphs 
(a)(1) through (4) of this section, and be performed at the appropriate 
point during the custody transfer process in accordance with standard 
industry procedures.
    Under Sec.  3174.86(a) of the proposed rule, the BLM would add 
language that says, ``For tanks less than 5000 bbl nominal capacity, a 
single temperature measurement at the middle of the liquid may be 
used.'' The existing regulation does not have language concerning the 
temperature determination procedures based on the size of the tank. 
Therefore, there has been considerable confusion among operators and 
purchasers as to whether they were required to take multiple 
temperatures during the custody transfer procedure, or if the single 
temperature in the middle of the fluid column is sufficient. By 
including this language, the fact that a single temperature is 
sufficient for tanks of less than 5,000 bbls capacity is made clear.
    With Sec.  3174.86(c) of the proposed rule, the BLM is seeking to 
clarify and expand the use of electronic thermometers for tank oil-
temperature determination. The PMT would review the specific makes and 
models of electronic thermometers and the BLM would list the approved 
equipment at www.blm.gov. The temperature of the oil has a direct 
effect on the royalty determination; therefore, it is critical that the 
device that measures oil temperature be compliant with the performance 
standards of the proposed regulation. This change would bring the 
requirements for electronic thermometers in line with the standards for 
temperature transmitters that perform the same function in LACT and CMS 
transfers. The proposed change also seeks to expand the use of 
electronic thermometers to allow for a flow-weighted average of the 
temperature during the transfer in lieu of a single opening and closing 
point. The BLM recognizes that the functionality of many electronic 
thermometers allow for live data over the entire transfer period which 
can allow for a more representative average for the oil temperature. 
This change would still meet the intent of the current regulation, but 
would allow operators to create more automated systems if they desire.
3174.87 Observed Oil Gravity Determination
    This section reflects the requirements currently located in Sec.  
3174.6(b)(4). This proposed section employs the same language as that 
found in current Sec.  3174.6(b)(4), with exception of updating the 
cross-references.
3174.88 Measuring Tank Fluid Level
    Proposed Sec.  3174.88 would essentially retain the manual tank 
gauging and ATG methods of tank measurement found in current Sec.  
3174.6(b)(5). The proposed changes would primarily remove obsolete 
requirements and provide clarification on requirements that have caused 
confusion.
    In an attempt to simplify subpart 3174, proposed Sec.  3174.88(a) 
would remove references to outage gauging and to an outage gauging bob. 
The BLM is not aware of any outage gauging method of measurement taking 
place at any FMP.
    Under Sec.  3174.88(a) of the proposed rule, the BLM would 
eliminate the sentence from existing Sec.  3174.6(b)(5)(i)(E) which 
reads: ``The same tape and bob must be used for both opening and 
closing gauges.'' The BLM has determined that this sentence is 
unnecessary since all tapes and bobs are required to be verified for 
accuracy when new, when repaired, and at least annually from the in-
service date thereafter, by comparison with a reference (e.g., a master 
tape) in accordance with API MPMS 3.1A. Annex A. By removing the ``same 
tape and bob'' sentence, the tape and bob used for opening and closing 
gauging procedures does not have to be the same. However, the tape and 
bob measurement equipment must still be verified and in compliance with 
API MPMS 3.1A.
    Under Sec.  3174.88(a)(4) of the proposed rule, a suitable product-
indicating paste may be used, but the use of chalk or talcum powder 
would be prohibited. BLM field offices have stated that the product-
indicating paste available on the market has a melting point below the 
temperature of oil contained in the storage tanks. This creates a 
situation where the product being gauged is evaporating faster than the 
gauge tape can be read and the product indicating paste is ineffective 
in facilitating the reading of the gauge tape. API 3.1A discourages the 
use of chalk or talcum powder in the gauging procedure but also fails 
to address situations in which oil temperatures are higher than the 
melting point of known available product-indicating pastes.
    The BLM is requesting comments and recommendations on how to 
address tank gauging of evaporating product with temperatures above the 
melting point of known available product-indicating pastes.
    In proposed Sec.  3174.88(b)(2), the proposed rule would clarify 
the installation requirements for ATGs. The existing regulation 
incorporates API 3.1B; however, inspectors and operators have expressed 
confusion about the installation requirements. The proposed change 
would state the exact sections of the API 3.1B that provide guidance on 
ATG installation, and would also reference the manufacturer's 
recommendations and any conditions of approval the BLM has placed on 
the equipment.
    The proposed rule would modify the requirement for verification 
logs on ATGs. The existing regulation requires verification of the ATG 
each month (or before next sale, whichever is longer) and requires that 
the operator maintain a detailed log of the verifications that is 
available upon request to the BLM. This can create problems for BLM 
inspectors, as operators are not required to keep the log on site, so 
there is no immediately available evidence that an operator conducted 
the verifications as required by the regulation. This can result in an 
undue administrative burden on BLM inspectors, who must request 
operator's logs to verify the compliance. The proposed rule seeks to 
alleviate this burden with a requirement in Sec.  3174.88(b)(5) that 
operators provide a statement of date of last verification at the FMP. 
This would allow BLM inspectors to check for compliance without log 
requests to the operators.

[[Page 55966]]

This proposed change would also bring the verification date 
requirements of this part in line with the subpart 3175 information 
requirements that flow-computer verification must be available on-site.
    The proposed rule would remove the references to dynamic 
measurement from the tank-gauging section of the regulation. The BLM 
has reviewed the existing regulation and found that the provisions 
regarding dynamic measurement do not fit in this section. The 
prescriptive nature of the process laid out for tank gauging is such 
that dynamic measurement would provide no benefit to the operator. The 
proposed regulation would let dynamic measurement be addressed by Sec.  
3174.170, the section pertaining to oil measurement by other methods. 
This move would reduce confusion, as any dynamic method would have to 
go through a PMT review process. The proposed change would also remove 
references to API 18.2 in general and would replace them with specific 
references to ATG, automatic temperature measurement, and automatic 
sampling in order to narrow the scope of the section and reduce 
confusion. The change would clarify this section while still allowing 
the operator to use other methods through the alternative methods 
approval process.
3174.90 LACT systems--General Requirements
    Proposed Sec.  3174.90(a) and (b) would use the same language as 
the existing Sec.  3174.7(a) and (b) for LACT construction, operation, 
and proving references, only updating regulatory citations to match 
proposed numbering changes for this subpart.
    Proposed Sec.  3174.90(c) would have the same language that is in 
existing Sec.  3174.7(d), concerning the LACT components being 
accessible for inspection.
    Proposed Sec.  3174.90(d) would retain the language of existing 
Sec.  3174.7(g), which prohibits the use of automatic temperature 
compensators and automatic temperature and gravity compensators, and 
would additionally make clear that these items would not be 
grandfathered under the new equipment grandfathering section (proposed 
Sec.  3174.50). Because there are relatively few LACT systems that 
still employ automatic temperature compensators or automatic 
temperature and gravity compensators, the BLM believes not 
grandfathering these items would not result in any significant costs to 
industry. In addition, because automatic temperature compensators or 
automatic temperature and gravity compensators used in LACT units do 
not meet the independent verification requirements of this subpart, 
they are not eligible for grandfathering. The BLM seeks comment on its 
assumption that not grandfathering this equipment would not result in 
significant costs to industry.
    Proposed Sec.  3174.90(e) would require the operator to notify the 
AO by Sundry Notice within 30 days after repair of any LACT system 
failures or equipment malfunctions that may have resulted in 
measurement error. Existing Sec.  3174.7(e) requires operators to 
notify the AO within 72 hours of a LACT failure that may have resulted 
in measurement error. Industry has expressed concerns with the 72-hour 
timeframe as being difficult to comply with, in that it may not be 
possible to notify the BLM about a failure within 72 hours while 
troubleshooting or repair operations might still be taking place. The 
BLM finds this to be a valid concern and, considering the trend towards 
implementing ELM in LACT systems and the audit capabilities of these 
ELM systems, the BLM believes a repair notification would still provide 
the BLM with the capability to ensure all production has been accounted 
for. The BLM believes a notification of LACT repair would provide the 
same regulatory benefit as a 72-hour notification of a LACT failure.
    Proposed Sec.  3174.90(f) would have the same language for tests 
conducted on oil samples extracted from a LACT system sampler for 
determination of sediment and water (S&W) content and observed oil 
gravity as found in existing Sec.  3174.7(f). This proposed rule would 
update regulatory citations to match proposed numbering changes for 
this subpart where referring to determination of S&W and observed oil 
gravity requirements.
    Proposed Sec.  3174.90(g) would require an average temperature to 
be calculated for the measurement period covered under the measurement 
ticket and require this average temperature to be used in determining 
the correction for the effect of temperature on a liquid (CTL 
correction factor). This proposed language would add clarification with 
respect to the time period for calculating the temperature average, 
i.e. the measurement period covered under the measurement ticket. 
Existing Sec.  3174.8(b)(6)(vi) states that the average temperature 
calculated since the measurement ticket was opened must be used in 
determining the CTL correction factor. There has been confusion within 
the BLM as to whether this requires averaging for the entire period 
covered by the measurement ticket or a short period of time from the 
opening of the measurement ticket could be used for an average 
temperature calculation. The BLM believes this proposed change 
adequately clarifies the intent of the existing requirement without 
imposing any additional burden on the operators.
    Proposed Sec.  3174.90(h) would add new pressure determination 
requirements in order to clarify when a pressure transducer would be 
required instead of a pressure gauge. The BLM believes there are 
circumstances where a pressure transducer should be required for higher 
accuracy. These circumstances pertain to ELM use and automatic-
adjusting back-pressure valves. Existing Sec.  3174.8(b)(5) requires a 
pressure-indicating device be installed and used to provide pressure 
data for calculating the CPL correction factor. This language is vague 
and has created confusion both within industry and the BLM with respect 
to what is meant by ``pressure-indicating device.'' Some interpreted 
this to mean a pressure gauge while others believed a pressure 
transducer is required. The BLM believes this proposed change 
adequately clarifies the conditions under which a pressure gauge would 
be allowed, and when a pressure transducer would be required. The BLM 
believes this change would impose minimal additional burden on 
operators, as the use of ELM and automatic-adjusting back-pressure 
valves are optional on high-volume FMP LACT systems, while providing 
the benefit of higher accuracy measurement.
    Proposed Sec.  3174.90(i) is similar to existing Sec.  
3174.8(b)(7), which requires the calculation of net standard volume for 
each measurement ticket. However, the proposed rule would give 
operators the flexibility to use other methods of calculation with BLM 
approval.
    Proposed Sec.  3174.90(j) restates the requirement of existing 
Sec.  3174.7(c), which pertains to completing measurement tickets.
3174.100 LACT Systems--Components and Operating Requirements
    This section introduces the LACT component and operational 
requirement sections of this rule, specifically proposed Sec. Sec.  
3174.101 through 3174.108. This section constitutes a change from the 
existing Sec.  3174.8(a) and (b) in that the BLM has decided not to 
incorporate the API 6.1 standards for equipment and operational 
requirements, but rather to list the minimum components and their 
respective operational requirements, similar to Onshore Order No 4. 
When subpart 3174 was initially proposed, it

[[Page 55967]]

listed LACT system components like Onshore Order No 4. However, the BLM 
received numerous comments stating that the rule should reference API 
6.1 rather than list each component. Since subpart 3174 was published, 
many within the BLM have expressed confusion over what constitutes the 
minimum equipment requirements within the API standard. Existing 
subpart 3174 says a LACT must include all the equipment listed in API 
6.1. In API 6.1, the reference to LACT components consists of a diagram 
that lists several pieces as ``optional.'' Existing subpart 3174 
therefore arguably removes any flexibility industry may need in LACT 
construction and operation. Many of the listed components in API 6.1 
are not necessary for determining quality and quantity of oil measured, 
and the BLM does not believe they should be considered mandatory 
equipment.
3174.101 Charging Pump and Motor
    This is a new section that does not have a corollary in existing 
subpart 3174. This section would require operators to install a charge 
pump and motor if the static head is insufficient to provide a net 
positive suction to achieve fluid pressure compatible with the oil 
fluid properties. Oil must be maintained under enough pressure to 
ensure the oil is above its bubble-point pressure to prevent gas 
flashing within the system. In order to meet this, the oil must be 
``pushed'' through the system, not ``pulled'' by some downstream means 
of suction.
3174.102 Sampling and Mixing System
    Sampling and mixing system requirements are currently located in 
existing Sec.  3174.8(b)(1). This proposed rule seeks to replace the 
current requirement for testing, pursuant to API 8.2. Existing Sec.  
3174.8(b)(1) requires all sampling systems, even those of the same 
design and construction to be individually tested. Operators expressed 
concern that compliance with this requirement to test all sampling 
systems, even those of the same design and construction, is 
unnecessarily burdensome and provides no benefit to the Federal 
Government. It is common for the same sampling-system design to be 
installed in many LACT units. The BLM agrees with this assessment and 
seeks to change the regulation to bring it in line with other equipment 
standards in the regulation and allow for a single test per design. The 
www.blm.gov website would list approved systems allowed on any 
location. The proposed change would reduce the overall burden to 
operators and simplify the inspection process for the BLM.
    Proposed Sec.  3174.102(a) would use identical language found in 
Sec.  3174.8(b)(1) for sample extractor probe requirements, with the 
exception of Sec.  3174.102(a)(3), which would clarify the sample-probe 
requirements found in Sec.  3174.8(b)(1)(iii). The BLM has received 
numerous questions from operators and inspectors about the current 
sample-probe marking requirement. The proposed changes would reduce 
confusion with respect to the marking of the sample probe. The intent 
of the current regulation is that the direction of the opening of a 
bevel cut probe be marked on the probe body. The proposed rule states 
this requirement more clearly.
    Proposed Sec.  3174.102(b) and (d) contain new requirements not 
found in the current rule concerning sampling frequency and mixing 
system objectives. These additions would further clarify the sampling 
requirements in order to address questions received from operators.
    Proposed Sec.  3174.102(c) would expand on language found in Sec.  
3174.8(b)(3) for sample container requirements. In addition to 
retaining the current language requiring the sample container be 
emptied and cleaned upon completion of sample withdrawal, this proposed 
rule would also add language for holding the sample under pressure and 
being equipped with a vapor-proof top closure to prevent the 
unnecessary escape of vapor. This additional language would further 
clarify sample container requirements to address questions received 
from operators.
3174.103 Air Eliminator
    This section does not have a corollary in existing subpart 3174. 
This section would require operators to install an air eliminator to 
prevent gas or air from entering the meter and causing mismeasurement 
of oil. The proposed rule would also allow the air eliminator to be 
integrated with an optional strainer device should an operator choose 
to configure the LACT this way.
3174.104 LACT Meter
    The existing regulation at Sec.  3174.8(a)(1) allows for the use of 
positive displacement (PD) and Coriolis meters on LACT units. The 
proposed rule would also allow for other meter types approved by the 
BLM. The BLM recognizes that other technologies could now, or in the 
future, meet the BLM's performance requirements for use on LACT units. 
This change would clarify how such technologies could be incorporated 
into the BLM's regulatory process.
    Proposed Sec.  3174.104(a) clarifies the non-resettable totalizer 
requirement of existing Sec.  3174.8(b)(4). The proposed rule would 
make it clear that the non-resettable totalizer display may reside in 
an electronic flow computer. The non-resettable totalizer could display 
through the flow computer, but the output must be from the meter. The 
BLM has recognized that some flow computers have the capability to 
generate totalizer readings from the flow computer itself. The intent 
of the existing regulation is that the meter must generate the values 
for the non-resettable totalizer. The proposed rule would clarify this 
intent while ensuring that operators have the convenience of displaying 
the meter reading through the flow computer.
3174.105 Electronic Temperature Averaging Device
    The BLM's requirements for electronic temperature averaging devices 
are currently located in existing Sec.  3174.8(b)(6). This proposed 
rule would clarify a point of confusion in the existing regulation by 
specifying in proposed Sec.  3174.105(f) that the BLM would allow a 
flow computer to perform the temperature averaging. The change makes 
clear that the regulation allows for stand-alone temperature averaging 
devices or temperature transmitters working in conjunction with a flow 
computer. Pursuant to proposed Sec.  3174.105(a), a stand-alone 
temperature-averaging device would require PMT review and BLM approval. 
Similarly, under proposed Sec.  3174.105(b), a temperature transducer 
must have received BLM approval. The approved equipment list at 
www.blm.gov would identify the makes and models of approved stand-alone 
temperature-averaging devices and temperature transducers.
3174.106 Pressure-Indicating Device
    The existing regulation, under Sec.  3174.8(b)(5) and Sec.  
3174.9(e)(1), allows operators to use a pressure transmitter on LACT 
systems and requires a pressure transmitter for CMS, but is silent on 
the approval process for that equipment. A requirement for pressure-
transmitter approval is only referenced indirectly in existing Sec.  
3174.1, the definitions section. The proposed change would remove any 
confusion by spelling out the requirements within this section.
    The BLM has heard from operators and BLM inspectors that the 
language in the existing regulation on placement of the pressure-
indicating device is not

[[Page 55968]]

clear. The proposed rule would clarify this requirement with new 
wording on pressure-indicating device placement. The concern pertained 
to LACT units where the pressure-indicating device was placed in the 
tee of the prover connection. Some inspectors and operators interpreted 
the wording of the existing regulation to disallow this placement. This 
was not the BLM's intent; therefore, the proposed change to the wording 
in Sec.  3174.106(a) would require the placement between the downstream 
side of the meter and the upstream side of the first valve in the 
prover connection. This change would assist in uniform enforcement of 
the regulation.
3174.107 Meter-Proving Connections
    This proposed section does not have a corollary in existing subpart 
3174. This section specifies requirements for meter-proving 
connections, including a leak detecting double block and bleed-valve 
configuration. Existing subpart 3174 does not reference meter-proving 
connections or leak-detection systems and instead incorporates the API 
6.1 standard, which is not sufficiently specific. Leak detection during 
the proving process is critical to determining an accurate meter 
factor. Any leakage through the prover loops will result in a meter 
factor that incorrectly adjusts for meter performance, potentially 
resulting in measurement bias, which could result in a loss of royalty.
3174.108 Back-Pressure and Check Valves
    This section would retain existing Sec.  3174.8(a)(3)'s requirement 
for operators to have back-pressure valves or other controllable means 
of applying back pressure on their LACT systems. Proposed Sec.  
3174.108 would also provide operators with the option of installing an 
automatic-adjusting back-pressure control to handle changing flowing 
conditions downstream. This option is being proposed because this 
technology has shown positive results in both meter performance and 
proving operations during field operations. LACTs that flow into 
constantly changing downstream pressures showed repeatability problems 
during proving operations. Provings performed on LACTs with automatic-
adjusting back-pressure control equipment have not shown the 
repeatability problems that are found on systems that have a fixed-
setting back-pressure valve when downstream pressures constantly 
change.
3174.110 Coriolis Meter Operating Requirements
    This section would provide operating requirements for the Coriolis 
meter--whether it is a stand-alone unit or is part of a LACT--and its 
transmitter. This section would remove the provision pertaining to 
meter specifications in existing Sec.  3174.10(b) and would keep or 
modify the remaining paragraphs of existing Sec.  3174.10.
    Proposed Sec.  3174.110(a) and (b) would require Coriolis meters 
and Coriolis transmitters to be on the approved equipment list at 
www.blm.gov. The proposed paragraph (a) requirement is currently 
located in existing Sec.  3174.9(b). Proposed paragraph (b) is new and 
it would allow for a Coriolis transmitter to have a separate approval 
from a Coriolis meter. A Coriolis meter is always used in conjunction 
with a transmitter. The BLM believes that this proposed change will 
alleviate concerns that each meter and transmitter combination would 
require additional individual approval. The BLM is seeking comments on 
how this can be achieved in practice. Specifically, the BLM requests 
comment from the public on the following:
    (1) How would a Coriolis meter be tested without a transmitter?
    (2) Does the performance of a Coriolis meter change based on the 
type of transmitter installed?
    (3) How would the BLM prevent the transmitter performance 
contributing to the meter uncertainty twice--first if a transmitter is 
required to test the Coriolis meter and second if a transmitter is 
tested separately?
    (4) Is there data to support the position that a transmitter's 
contribution to meter uncertainty is insignificant and therefore will 
not change a Coriolis meter's uncertainty?
    Proposed Sec.  3174.110(c) is the same as existing Sec.  
3174.10(a).
    Proposed Sec.  3174.110(d) would clarify the requirement for the 
non-resettable totalizer that is currently located in existing 
3174.10(c) by stating that the non-resettable totalizer display may 
reside in an electronic-flow computer, but it must be generated by the 
Coriolis meter. It further clarifies that a flow-computer generated 
totalizer would not fulfill the requirements of subpart 3174.
    Proposed Sec.  3174.110(e) would clarify existing Sec.  3174.10(d) 
by specifying when a meter-verification procedure must be conducted. 
Existing Sec.  3174.10(d) does not specify when the zero-verification 
procedure must be conducted. This rule would clearly state that a meter 
zero verification would need to be conducted during the proving process 
and at any time the AO would request it. Two minor changes would be 
made in the fourth sentence of proposed Sec.  3174.110(e): Adding the 
word ``reading'' after the word ``zero,'' which was inadvertently left 
out of the next-to-last sentence of existing Sec.  3174.10(d), and 
changing a cross reference.
    Proposed Sec.  3174.110(f) would require the same on-site display 
requirements of existing Sec.  3174.10(e)(1) and (2) with exception of 
moving the instantaneous pressure reading and the instantaneous 
temperature reading requirements to proposed Sec.  3174.120(b), and 
revising the requirement to display the gross standard volume and 
indicating this as the non-resettable totalizer reading. The non-
resettable totalizer is a reading of the indicated volume. The rule 
would change the display requirement under Sec.  3174.110(f)(iv) and 
(v) to require indicated volumes.
3174.120 Electronic Liquids Measurement, ELM (Secondary and Tertiary 
Device)
    This proposed section applies to flow computers (ELM systems) that 
are connected to Coriolis meters and their transmitters. Although this 
section does not have a direct corollary in existing subpart 3174, it 
contains many of the same requirements that appear in the existing 
Coriolis meter regulations at Sec.  3174.10. ELM systems take and 
utilize the data that Coriolis-meter transmitters feed them to make 
calculations and corrections. Not all Coriolis meters use ELM systems. 
The existing Coriolis meter regulations at Sec.  3174.10 have caused 
some confusion in the regulated community as to whether operators are 
required to use ELM systems with their Coriolis meters. The BLM hopes 
to eliminate this confusion by separating out the ELM systems 
requirements in proposed Sec.  3174.120 from the Coriolis meter 
requirements at proposed Sec.  3174.110.
    The existing regulation requires operators to use a tertiary device 
(flow computer and associated memory, calculation, and display 
functions) for all CMS FMPs. This existing requirement is mentioned 
minimally in the definitions section at existing Sec.  3174.1, under 
the definition for Coriolis measurement system (CMS), and provides 
little in the way of details for this requirement. The proposed changes 
bring the software-testing requirements for electronic oil measurement 
in line with the requirements of electronic gas measurement in subpart 
3175. The BLM believes that it is valuable to have uniformity in these 
requirements to

[[Page 55969]]

alleviate the burdens that having two differing test procedures would 
create only to achieve essentially the same results. Since the 
electronic oil measurement system software performs calculations that 
directly affect royalty reporting, the BLM has deemed it critical to 
ensure that the software meets the performance standards of the 
regulation. The proposed rule would specify the requirements for ELM 
systems and remove any ambiguity in the existing regulation.
3174.121 Measurement Data System (MDS)
    This section does not have a corollary in existing subpart 3174. 
This section would establish that measurement data systems (MDS) must 
be approved by the BLM for use at an FMP. MDS are designed to gather, 
edit, store, and report measurement data. The BLM has developed a test 
procedure that compares raw data retrieved from a flow computer 
directly to both edited and unedited data obtained from the MDS under 
test. The BLM would assess this data to ensure that the internal 
correction and volume calculations comply with the appropriate 
incorporated API standards for sequence and rounding, that raw data is 
preserved and maintained, and that edited data is clearly indicated as 
such. By requiring that MDSs be BLM approved, industry would not have 
any questions or confusion when selecting an MDS system for use at an 
FMP. This section would also allow the BLM to approve and list 
alternative methods of calculating net standard volume on the 
www.blm.gov website. Measurement data systems would not be subject to 
the exemption provided for in proposed Sec.  3174.50(a) and would have 
to be approved by the BLM prior to use.
3174.130 Coriolis Measurement Systems (CMS)--General Requirements and 
Components
    The BLM's general requirements for Coriolis measurement 
applications independent of LACT measurement systems are currently 
located in existing Sec.  3174.9. This proposed rule would only make 
minor changes to the requirements of existing Sec.  3174.9.
    Paragraph (b) would require each CMS to utilize an ELM and follow 
the requirements of proposed Sec.  3174.120. This is intended to 
reflect the new ELM section at proposed Sec.  3174.120, and would not 
impose burdensome additional requirements since the ELM section is 
comprised primarily of existing requirements that are found in existing 
Sec.  3174.10. These organizational changes are intended to make the 
requirements clearer and provide a better organization of the 
requirements.
    Paragraph (e) would add a new provision (Sec.  3174.130(e)(5)) to 
require block valves at both ends of the system in order to allow for 
zero-flow verification.
    Paragraph (g) would update the API standard reference for 
calculating net standard volume and include a provision to allow for 
alternative methods of calculating net standard volume that the BLM may 
approve and list on the www.blm.gov website.
    Paragraph (h) would clarify the requirements for CMS units that are 
attached to oil-hauling trucks or trailers that move between oil-
loading locations. Paragraphs (h)(7) and (8) would clarify that each 
truck load using a Truck Mounted Coriolis (TMC) CMS would require the 
seal on the sales valve to be replaced. This is to avoid confusion with 
the Sec.  3173.20 seal requirement for multi-truck loads. The intent of 
that section of Sec.  3173.20 is to deal with loads on multiple trucks 
that are recorded on a single run ticket. As each TMC would record a 
truck load on an ELM system attached to that truck, the seal on and off 
would need to be recorded for auditing purposes.
    The BLM is seeking comment on the total system performance that 
would be achievable for both truck mounted CMS and systems that are 
placed at the dumps of separators.
3174.140 Temporary Measurement
    The BLM is proposing to add a new Sec.  3174.140 to address 
temporary measurement. Temporary measurement is defined in 43 CFR 
3170.10 as a meter that is in place for less than 3 months and measures 
oil on which royalty is owed. Temporary measurement typically applies 
to an oil meter that is part of a measurement skid used to measure the 
production from a newly completed well before the permanent measurement 
facility is installed. The existing rule does not address temporary 
measurement.
    Under proposed Sec.  3174.140, a temporary oil meter would have to 
meet all the requirements of an FMP with some modified requirements 
based on the limited timeframe the meter will be on the location (for 
example, proving requirements).
3174.150 Meter-Proving Requirements
    This section introduces the eight following sections that specify 
the minimum requirements for conducting volumetric meter proving for 
all FMP meters (Sec. Sec.  3174.151 through 3174.158). A meter proving 
is the procedure used to determine a meter factor required to calculate 
the volume of liquid measured through a meter. Currently all proving 
requirements are found in existing Sec.  3174.11. By separating these 
requirements into sequential sections, the BLM believes this will make 
identifying and citing the specific requirements less burdensome for 
both industry and the BLM.
3174.151 Meter Prover
    Proposed Sec.  3174.151 maintains the existing meter-prover 
requirements found in existing Sec.  3174.11(b) and includes new 
language that would add flexibility for additional meter provers as new 
technology emerges.
    Under existing Sec.  3174.11(b), acceptable provers are PD master 
meters, Coriolis master meters, and displacement provers. These are the 
only meter provers identified as acceptable to the BLM at this time. 
Since publication of the existing regulations, industry has recommended 
that the BLM maintain the flexibility to accept future meter-proving 
methods and technology. This proposed rule would still recognize 
positive-displacement master meters, Coriolis master meters, and 
displacement provers as automatically accepted, but would also include 
the flexibility for the BLM to approve other provers. The BLM is 
proposing this addition to support the development of new technologies 
and procedures that meet the performance requirements of the regulation 
but that are not known or available at the time this proposed rule 
becomes final.
    The BLM is seeking comments on other proving technologies or 
procedures that are not presented in this proposed rule, but that meet 
its requirements.
3174.152 Meter-Proving Runs
    Proposed Sec.  3174.152(a) would modify the proving requirements 
currently located in existing Sec.  3174.11(c)(1) based on feedback 
from operators and BLM inspectors on the enforceability of the existing 
regulation. Existing Sec.  3174.11(c)(1) requires meter proving to be 
performed under normal operating fluid pressure, fluid temperature, and 
fluid type and composition. BLM inspectors have found it difficult to 
define a ``normal operating'' range and so enforcing this requirement 
has become burdensome. Therefore, the proposed rule would use the 
proving conditions at the time of proving to define the ``normal 
operating'' range for the period between the provings of the meter. 
This would allow inspectors to use proving reports from the previous 
period to ensure that the unit has stayed within the normal operating 
span for

[[Page 55970]]

that period. The limits of the ``normal range'' would remain the same 
as the current regulation, but with the ``normal'' point defined by the 
conditions at the time of proving. Whatever the flow rate, pressure, 
temperature, and API gravity the meter is proven at would become the 
new ``normal'' operational points, and the unit would have to maintain 
operation within 10 percent of that defined value for flow rate and 
pressure, 10 [deg]F of the temperature, and 5 degrees API for the 
gravity. The BLM seeks comments on these ranges and any supporting data 
that may show that the range should, without affecting the meter 
factor, be wider or narrower. The proposed changes also would address 
short-term changes in conditions that might occur between proving 
cycles. The intent of the existing regulation is not to require 
multiple meter provings for short-term operations like pigging or 
temporary spikes in temperature. Therefore, the proposed rule defines a 
period of time necessary for a change in operating conditions to 
require a proving.
    Since publication of the existing subpart 3174 regulations, 
industry has expressed concerns about the requirement of ``normal'' 
operating conditions for proving and has asked the BLM to consider a 
meter's linear range as a replacement for a ``normal'' operating 
condition requirement during proving operations. This proposed rule 
would address concerns on how ``normal'' operating conditions would be 
determined and used. The BLM is not familiar enough with the meter 
linear range concept to include it in this proposed rule, and instead 
requests that industry provide data on how to determine a meter's 
linear range and how this could be applied to meter provings.
    Proposed Sec.  3174.152(b) reproduces the requirement of current 
Sec.  3174.11(c)(2) requiring the use of pulse interpolation in 
accordance with API 4.6 if each proving run is not of sufficient volume 
to generate at least 10,000 pulses.
    Under existing Sec.  3174.11(c)(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 field proving conditions, 
like separator-mounted CMS where limited volumes of proving fluid is 
available, this has shown to be difficult to achieve. Proposed Sec.  
3174.152(c) would incorporate all the language from current Sec.  
3174.11(c)(3), and would expand on the allowable runs for a meter 
proving. The BLM recognizes that the API 4.8 standard provides a table 
for various runs and repeatability that meet a 0.027 percent 
uncertainty. Therefore, the proposed rule would incorporate that table 
into the regulation to allow greater proving flexibility while keeping 
the same performance standard for the proving.
    Proposed Sec. Sec.  3174.152(d), (e), (f), and (g) would 
incorporate all the language from existing Sec. Sec.  3174.11(c)(4), 
(5), (7), and (8) for meter factor computations and acceptable meter 
factors ranges.
    Proposed Sec.  3174.152(h) would incorporate the language from 
existing Sec.  3174.11(c)(6) for the use of multiple meter factors 
determined over a range of normal conditions. The BLM has not received 
much feedback on this provision in the existing regulations and does 
not know whether operators are using this method or if it can be 
applied to field operations. The BLM requests comments on this 
provision, including supporting data showing whether this concept is 
feasible for use at FMPs, needs additional refinement, or is not 
feasible and should be removed from the rule.
    Proposed Sec.  3174.152(i) would combine and expand on the language 
found in existing Sec.  3174.11(c)(9) and (10) relating to back-
pressure adjustments and composite meter factors. The existing rule 
separates the requirements for back-pressure valve adjustments at the 
conclusion of proving operations and composite meter-factor use.
    There has been confusion within the BLM and industry as to what 
back-pressure adjustments are allowed under the existing regulations 
after proving a meter. The existing regulation states that back-
pressure-valve adjustment is only allowed on PD meters. This was based 
on a BLM misconception about how Coriolis meters would be used; the BLM 
now realizes that the existing rule does not cover all possible LACT 
configurations. This proposed rule would allow automatic-adjusting 
back-pressure systems, which would resolve confusion concerning back-
pressure-valve adjustment after proving.
    The proposed rule would place restrictions on back-pressure 
adjustments when an operator chooses to use a composite meter factor. 
The existing rule only allows composite meter factors with PD meters. 
The BLM thought that Coriolis meters, whether used in a LACT or CMS, 
would have flow computers installed on them that would utilize a 
pressure transducer for live pressure readings when determining the 
CPL. The BLM now understands that operators use Coriolis meters in 
LACTs that do not have flow computers installed and want to use 
composite meter factor in these situations. These LACT systems are 
intended to flow at steady pressures with fixed-setting back-pressure 
valves. The BLM realizes that the existing rule does not cover this 
Coriolis/LACT configuration. The proposed rule would allow composite 
meter factors to be used with any meter, PD, Coriolis, or any other 
meter the BLM may approve, but would restrict a LACT using a composite 
meter factor to require fixed-setting back-pressure valves, and would 
include limitations to back pressure adjustments
3174.153 Minimum Proving Frequency
    The BLM's requirements for minimum proving frequency are currently 
located in existing Sec.  3174.11(d). This proposed section would 
essentially retain the current requirements of existing Sec.  
3174.11(d), with the two following modifications.
    Under existing Sec.  3174.11(d)(1), the operator must prove the FMP 
meter before production is removed or sold following initial meter 
installation. Industry has questioned the timing of this requirement 
and has requested that the BLM give operators more time before 
requiring them to conduct the initial proving. The BLM has considered 
this request and agrees that more time can be given without any 
negative impacts to measurement accuracy. Proposed Sec.  3174.153(a) 
would require that an FMP meter be proved within 15 days after the 
first flow after installation of the FMP meter. The BLM believes an 
additional 15 days would be enough time to fill all load lines and 
ensure proper meter functioning. A meter factor can be applied to 
measured volumes from the first flow through the time of closing the 
measurement ticket. An additional 15 days from first flow through a 
meter would not affect volumes reported for royalty determination.
    Under existing Sec.  3174.11(d)(4), the operator must prove the FMP 
meter when any event in which modification of mounting conditions 
occurs at the FMP meter. Industry seems to misunderstand the meaning of 
the general statement ``modification mounting conditions'' as it 
pertains to an event that would require an FMP meter to be proved 
before removal or sales of production. Proposed Sec.  3174.153(d) would 
require that an FMP meter be proved prior to removal or sales of 
production whenever the FMP meter is removed and reinstalled at the 
FMP. The BLM is proposing to simplify the existing language by saying:

[[Page 55971]]

``removal and reinstallation of the meter'' rather than ``modification 
of mounting conditions.'' This proposed change would address industry's 
confusion and still achieve the outcome of the proving frequency 
requirement.
3174.154 Excessive Meter Factor Deviation
    This proposed section would expand upon the provisions currently 
located in existing Sec.  3174.11(e). This rule would clarify existing 
language that defines excessive meter factor deviation. The existing 
rule considers any two successive provings where the meter factors 
differ by 0.0025 or more, as excessive. There has been 
confusion over what is meant by ``successive.'' In an attempt to 
address this confusion, the term ``successive'' would be replaced by 
``consecutive.''
    Proposed Sec.  3174.154(a) is a new section that is being proposed 
to address an omission in the existing rule. Onshore Order No. 4 
allowed an operator to provide an explanation to the BLM that an 
excessive-meter factor was not caused by a meter malfunction. The 
existing regulation does not include this option and, at existing Sec.  
3174.11(e), requires the operator to remove a meter from service no 
matter the cause of the excessive meter factor. The BLM has received 
many questions about why this option was not retained in subpart 3174. 
The primary explanation for an excessive meter factor, other than meter 
malfunction, is changing conditions, such as temperature, gravity, or 
flow rate. The intent of the existing regulation is that a meter must 
be proven if any one of the conditions, temperature, pressure, gravity, 
or flow rate changes beyond the normal range as defined in Sec.  
3174.11(c)(1). Proposed Sec.  3174.152(a) would refine this normal 
range criteria (as discussed in the Sec.  3174.152(a) preamble 
section). The proposed changes to the normal condition would eliminate 
excessive meter-factor deviation caused by changing conditions because 
proposed Sec.  3174.153(f) would require the operator to prove any FMP 
meter before a change in the flow rate, pressure, temperature, or 
gravity becomes severe enough to cause excessive meter factor 
deviation. The BLM is proposing to allow an operator to provide an 
explanation to the BLM that an excessive-meter factor was not caused by 
a meter malfunction because the BLM believes that it is appropriate to 
give operators the opportunity to explain an excessive meter factor on 
a case-by-case basis.
    Proposed Sec.  3174.154(b) uses language that is combined from 
existing Sec.  3174.11(e)(1) and (3). This proposed section would 
require an operator to remove a meter from service when a meter 
malfunction causes an excessive meter factor or when an operator does 
not provide, or the AO does not approve, an explanation for the 
excessive meter factor. This section would also include language that 
requires an operator to provide a description of any meter repair or 
adjustment on the subsequent proving report.
    Proposed Sec.  3174.154(c) reflects existing Sec.  3174.11(e)(2). 
This section would require the two consecutive meter factors to be 
averaged and applied to production measured between the dates of the 
two provings.
3174.155 Verification of the Temperature Transducer
    The BLM's requirements for verifying temperature-transducer output 
are currently located in existing Sec.  3174.11(f). In this proposed 
section, the verification requirements have not changed, but rather the 
language has been revised to include changes relating to the addition 
of the ELM section in the proposed rule. The primary changes to this 
section would be removing the reference to CMS and replacing it with a 
reference to ELM and changing all instances of ``the probe of the 
temperature averager'' to ``temperature transducer.''
3174.156 Verification of the Pressure Transducer (if Applicable)
    This proposed section lists the requirements for verifying the 
pressure transducer output and would be nearly identical to the 
existing language in current Sec.  3174.11(g). The BLM is not proposing 
any substantive change to subpart 3174's pressure transducer 
verification requirements.
3174.157 Density Verification (if Applicable)
    This proposed section lists the requirements for verifying the 
density output from a Coriolis meter, and would be nearly identical to 
the existing language in current Sec.  3174.11(g). The BLM is not 
proposing any substantive change to the density verification 
requirements of existing subpart 3174.
3174.158 Meter-Proving Reporting Requirements
    Existing Sec.  3174.11(i) contains meter-proving reporting 
requirements; however, this section does not clearly state what data 
operators must provide on a proving report. The existing language 
primarily requires operators to use proving forms that are available 
within two different API standards, and requires operators to provide 
some additional data covering lease number, meter ID number, the 
verification of the temperature and pressure transducers, and density 
verification. Proposed Sec.  3174.158 would provide a detailed list of 
the specific data required and would specify a required calculation 
sequence to be followed in the meter factor calculation. API forms are 
identified only as available examples of proving-report formats.
    Proposed Sec.  3174.158(a) would retain the data requirements 
listed in existing Sec.  3174.11(i)(2) and would add additional 
specific data that must be included on the list of minimum data 
required to be in a proving report. These additional data requirements 
would be the data that is currently found on the API forms referenced 
in current Sec.  3174.11(i)(1). The BLM believes that providing this 
level of detail in the proposed proving-report requirements, rather 
than referring operators to the API example forms, would remove any 
confusion about the exact data that is required on the report. The 
proposed minimum-data list contains the data necessary for the BLM to 
clearly identify the FMP meter, conduct an audit, verify that proving 
operations obtained the correct data, and determine that meter-factor 
calculations are done correctly.
    Proposed Sec.  3174.158(b) would retain the data requirements 
listed in existing Sec.  3174.11(i)(1), except for removing the 
reference to the example forms listed in the API standards. The 
reference to the API forms has created confusion with both industry and 
the BLM as to whether operators are required to use them or just 
provide the data within the forms in any format. Removing the reference 
and stating that any format would be acceptable is expected to clear up 
this confusion.
    Proposed Sec.  3174.158(c) would change the proving-report 
submission requirements of existing Sec.  3174.11(i)(3) from requiring 
an operator to submit each report within 14 days after a meter proving 
to only requiring an operator to submit a proving report when requested 
by the AO. This change has been proposed to make this regulation less 
burdensome to industry while retaining the BLM's audit capabilities for 
verifying proving reports.
3174.160 Measurement Tickets
    Proposed Sec. Sec.  3174.160-162 would replace the measurement 
ticket requirements contained in existing Sec.  3174.12. Proposed Sec.  
3174.160 provides an overview of the following two sections that 
require information that must appear on measurement tickets prior to 
oil-volume reporting on the

[[Page 55972]]

OGOR. The proposed rule would separate out the measurement-ticket 
requirements into individual sections according to the measurement 
type, tank gauging, and LACT or CMS. This prosed rule would retain the 
existing requirement that measurement tickets be made available upon 
request of the AO. The BLM believes this requirement is the least 
burdensome on industry while retaining the BLM's audit capabilities for 
verifying volume and quality.
3174.161 Tank Gauging Measurement Ticket
    Under proposed Sec.  3174.161, the tank-gauging measurement-ticket 
section would reorganize the required measurement-ticket information 
into two categories--one for field-data gathering operations and 
another for measurement-ticket calculations. There has been confusion 
within industry and the BLM over the existing requirements when 
documenting tank-gauging operations. Some BLM personnel believe a 
complete measurement ticket, including all temperature and density 
corrections and calculations, must be filled out by the operator, 
purchaser, or transporter at the time of the gauging operations. This 
proposed rule would clarify which data would be required to be 
documented at the time of the gauging operation in the field and what 
calculations could be done later.
    Proposed Sec.  3174.161(a) would replace parts of existing Sec.  
3174.12(a). This proposed section would specify the field-data 
gathering and documentation requirements. For field-data gathering, the 
proposed rule would include existing requirements from Sec.  3174.12(a) 
and with the additional requirement that operators document the FMP 
location information as required under Sec.  3170.50(g). Many within 
the BLM have been requesting that operators provide location data on 
their measurement tickets so they can identify the location of the FMP 
where the tank-gauging took place. Therefore, this proposed rule would 
include the location information requirement.
    Proposed Sec.  3174.161(b) would replace parts of existing Sec.  
3174.12(a). This proposed section would clarify the calculations and 
corrections that the operator must complete and document on the run 
ticket for tank gauging. The existing rule was not specific with 
respect to the correction of the API gravity to 60 [deg]F, and whether 
it must include the glass thermal expansion equation when using a 
hydrometer or thermohydrometer for gravity determination. The proposed 
rule would require the API oil gravity at the 60 [deg]F correction to 
include the glass thermal expansion equation. The proposed rule would 
eliminate the gross standard volume recording and proposes to require 
the total net standard volume be recorded. Many in industry and the BLM 
have questioned why net standard volume is not required to be 
calculated in the existing rule. This was an oversight. The existing 
regulation should have required operators to document it on the 
measurement ticket. Operators are already required to report net 
standard volumes on their OGORs.
3174.162 LACT System and CMS Measurement Ticket or Volume Statement
    Proposed Sec.  3174.162 would reorganize the required information 
into two categories--measurement tickets and volume statements. 
Existing Sec.  3174.12(b) only allows the operator to use a measurement 
ticket while proving a LACT system. Since the proposed rule would allow 
operators to use ELM and MDS systems, a second category for volume 
statements would be necessary. The BLM believes both of these 
categories would provide the audit capabilities required for verifying 
volume and quality.
    Proposed Sec.  3174.162(a) would retain the existing measurement-
ticket requirements in Sec.  3174.12(b) and introduce two additional 
requirements. The proposed rule would require in Sec.  3174.162(a)(1) 
the location information found in Sec.  3170.50(g) be documented and 
would require in Sec.  3174.162(a)(11) the net standard volume be 
calculated and documented.
    Proposed Sec.  3174.162(b) would be a new section that would 
accommodate the ELM systems and MDS systems. This section would allow 
for volume statements rather than measurement tickets for the 
documentation of the flow data and calculations to net standard volume. 
The volume statement would be generated from the ELM or MDS using 
unaltered, unprocessed, and unedited daily or hourly QTRs, and would 
require the information found in the API 21.2 standard. The volume 
statement would additionally be required to include the information 
listed in Sec.  3170.50(g).
    Proposed Sec.  3174.162(c) would retain the existing requirements 
in Sec.  3174.12(b)(2) that any accumulators used in the determination 
of average pressure, average temperature, and average density be reset 
to zero whenever a new measurement ticket is opened. It would also add 
the term ``measurement period'' to clarify the timeframe that would 
apply to this requirement.
3174.170 Oil Measurement by Other Methods
    Oil measurement by other methods is currently addressed in existing 
Sec.  3174.13. Most of the content of existing Sec.  3174.13 is 
proposed to be moved to Sec.  3170.30. This change would eliminate 
duplicate language on the process of applying for BLM approval of 
alternative equipment and methods through the PMT review process from 
subpart 3174 and relocate it to subpart 3170, which is common to all 
the part 3170 regulations. The existing Sec.  3174.13(a) language about 
prior BLM approval has been modified and retained in proposed Sec.  
3174.170. The proposed modification would remove references to tank 
gauge, LACT, and CMS and instead clarify that any method of oil 
measurement other than those addressed in this rule or listed on the 
www.blm.gov website require BLM approval.
3174.180 Determination of Oil Volumes by Methods Other Than Measurement
    This proposed section essentially reproduces existing Sec.  
3174.14. This section addresses how spilled oil, waste oil, and slop 
oil must be reported to the AO. Existing Sec.  3174.14 says an operator 
may not sell or otherwise dispose of slop oil without prior written 
approval. Proposed Sec.  3174.180 would require an operator to get 
prior written approval from the BLM for a sale or disposal of slop oil 
and also require the operator to notify the BLM via Sundry Notice of 
the volume sold or disposed. This change would ensure that a tracking 
and auditing mechanism for spilled oil, waste oil, and slop oil exists.
3174.190 Immediate Assessments
    The BLM has reviewed existing immediate assessments in Sec.  
3174.15 and is proposing to remove the immediate assessment for the 
failure to notify the AO of a LACT system failure or equipment 
malfunction within 72 hours that resulted in the use of an unapproved 
alternative measurement method (existing Sec.  3174.15, violation 2). 
There has been confusion as to whether the immediate assessment should 
be for a failure to notify within 72 hours of a LACT system failure or 
equipment malfunction, or whether it should be for the use of an 
unapproved alternative measurement method. Existing Sec.  3174.7(e)(1), 
requiring the 72-hour notification, would be revised under proposed 
Sec.  3174.90(e) so that the notification would be required within

[[Page 55973]]

30 days after repair of any LACT system failures or equipment 
malfunctions that may have resulted in measurement error, not when 
there is an initial failure. To be clear, there is no grace period for 
the use of unapproved equipment in the current or proposed rules. The 
use of an unapproved alternative measurement method would be covered by 
the immediate assessment for failure to obtain approval as required by 
proposed Sec.  3174.170. There are no changes proposed for the 
remaining existing four immediate assessments.
4. Section-By-Section Discussion for Changes to Subpart 3175
    This proposed rule would renumber and rename some of the sections 
in existing subpart 3175. This change is needed to reflect that this 
proposed rule would consolidate a number of existing sections into new 
sections, and add one new section and a new Appendix. The following 
table provides a cross-walk comparison of the proposed Sec.  3175 
numbering to the current subpart 3175 numbering. New proposed sections 
have ``New'' identified in the existing Sec.  3175 column.

------------------------------------------------------------------------
          Existing Sec.   3175                 Proposed Sec.   3175
------------------------------------------------------------------------
3175.10 Definitions and acronyms.......  3175.10 Definitions and
                                          acronyms.
3175.20 General requirements...........  3175.20 General requirements.
3175.30 Incorporation by reference       3175.30 Incorporation by
 (IBR).                                   reference (IBR).
3175.31 Specific measurement             3175.31 Specific measurement
 performance requirements.                performance requirements.
3175.40, 3175.43, 3175.44, 3175.46       3175.40 Measurement equipment
 through 3175.49.                         requiring BLM approval.
3175.41, 3175.42, 3175.45..............  3175.41 Approved measurement
                                          equipment.
New....................................  3175.43 Data submission and
                                          notification requirements.
3175.61 Grandfathering.................  3175.50 Grandfathering.
3175.60 Timeframes for compliance......  3175.60 Timeframes for
                                          compliance.
3175.70 Measurement location...........  3175.70 Measurement location.
3175.80 Flange-tapped orifice plates...  3175.80 Flange-tapped orifice
                                          plate.
3175.90 through 3175.94 Mechanical       3175.90 through 3175.94
 recorders.                               Mechanical recorders.
3175.100 through 3175.104 Electronic     3175.100 through 3175.104
 gas measurement.                         Electronic gas measurement.
3175.110 through 3175.121 Gas sampling   3175.110 through 3175.121 Gas
 and analysis.                            sampling and analysis.
3175.125 Calculation of heating value    3175.125 Calculation of heating
 and volume.                              value and volume.
3175.126 Reporting of heating value and  3175.126 Reporting of heating
 volume.                                  value and volume.
3175.130 through 3175.135 Transducer     3175.130 Requirements for
 testing protocol (removed).              GSAMPs.
3175.140 through 3175.144 Flow computer  3175.140 Temporary Measurement.
 software testing (removed).
3175.150 Immediate assessments.........  3175.150 Immediate assessments.
Appendix A--Atmospheric pressure.......  Appendix A--Atmospheric
                                          pressure.
New....................................  Appendix B--Maximum time
                                          between events.
------------------------------------------------------------------------

3175.10 Definitions and Acronyms
    Proposed Sec.  3175.10 would clarify the definition of ``Beta 
ratio.'' In the existing regulation, ``Beta ratio'' is defined as the 
``measured diameter of the orifice bore divided by the measured inside 
diameter of the meter tube,'' without specifying which measured 
diameter to use. The proposed definition would clarify that the 
``reference inside diameter'' (defined in proposed Sec.  3175.10) is 
required for determining the beta ratio.
    This rule would relocate the definition of ``Configuration log'' to 
43 CFR 3170.10, which contains definitions that are used in more than 
one subpart of part 3170. ``Configuration log,'' which is a list of 
programmable information used in electronic flow computers measuring 
oil or gas, is a term that is used in both subparts 3174 and 3175.
    The BLM would also relocate the definition of ``Event log'' from 
Sec.  3175.10 to the general definition section under 43 CFR 3170.10. 
The BLM is proposing this change because the term ``Event log'' is used 
in both subparts 3174 and 3175.
    The BLM is proposing to add a new definition for meters that are 
used in gas-storage agreements, which affect the determination of 
injection and withdrawal fees. This meter would be referred to as ``Gas 
storage agreement measurement points'' (GSAMP). The BLM is also 
proposing to add new requirements for these meters (see discussion of 
proposed Sec.  3175.130 later in this preamble). Under the existing 
regulations, meters used for gas-storage agreements are not FMPs 
because the definition of an FMP is limited to meters or measurement 
facilities that affect the determination of royalty. Because injection 
and withdrawal fees are not the same as royalties, the meters that are 
used to determine them are not FMPs by definition. Most gas-storage-
agreement contracts include language that requires injection and 
withdrawal meters to meet the standards found in the BLM's previous 
gas-measurement regulations known as Onshore Order No. 5, or subsequent 
regulations. However, this language is not consistent from agreement to 
agreement and has led to uncertainty over the BLM's authority to 
regulate these meters, especially under the existing subpart 3175 
regulations. The BLM believes that accurate measurement and proper 
reporting is essential to ensuring the public receives the proper fees 
for the use of Federal or Indian land for gas-storage purposes. The 
proposed requirement would help the BLM achieve this goal.
    Although most gas-storage areas use depleted oil and gas reservoirs 
to store gas, the gas withdrawn from a gas-storage agreement may still 
produce some gas and, in some cases, oil that was part of the original 
oil and gas deposit. This is often referred to as ``native'' oil and 
gas. Royalty is due on native oil and gas produced from Federal or 
Indian leases within the gas-storage agreement, just as it would be 
from any Federal or Indian lease. In these situations, the meters used 
to measure the withdrawn gas also measure some portion of native gas 
and oil. The definition of GSAMP clarifies that if the withdrawn gas 
contains native oil or gas, the meter measuring the withdrawn gas is an 
FMP and not a GSAMP. As such, the meter would have to comply with all 
applicable subparts 3173, 3174, and 3175 requirements relating to an 
FMP. It would be up to the BLM to determine if the meter is measuring 
only gas that was injected, in which case it would be a GSAMP, or gas 
that contains native oil or gas, in which case it would be an FMP.
    In some cases where some native gas is produced, the gas-storage 
agreement specifies that the royalty on a set amount of native gas is 
prepaid. The

[[Page 55974]]

meter measuring the gas in this case would be considered a GSAMP until 
the amount of native gas on which the pre-paid royalty is based is 
exceeded, at which point the meter would become an FMP.
    The BLM would add a definition of ``Nonanes-plus (C9+) 
analysis,'' a gas analysis in which gas components from methane 
(C1) to octane (C8) are split and individually 
measured, and components of nonanes (C9) and higher are 
lumped into a single grouping, because the term would be added to 
numerous sections of the rule and may not be consistently understood by 
all users. The existing regulation erroneously uses the term ``Extended 
analysis'' in conjunction with nonanes-plus. The BLM would eliminate 
the term ``Extended analysis'' in the proposed rule and would clarify 
that nonanes-plus (C9+) analysis refers to a single grouping 
of all components that are heavier than octane (C8).
    This rule would change the definition of ``Normal flowing point'' 
to clarify that the normal flowing points at a particular FMP are the 
average values of differential pressure, static pressure, and flowing 
temperature taken over a 1-day to 31-day time frame. The existing 
definition of ``Normal flowing point'' does not define the normal flow 
point as an average over time and is not adequate for either the agency 
or the public to determine these values, resulting in inconsistent use 
and enforcement. The proposed change would provide a clear 
understanding of what a normal flowing point is and how it would be 
determined. The BLM uses the normal flowing points when witnessing the 
verification of mechanical recorders and electronic gas measurement 
systems and when determining overall measurement uncertainty.
    This rule would add definitions for ``Published inside diameter'' 
and ``Reference inside diameter.'' Under the existing regulation, only 
the inside diameter of the meter tube is referenced, without clarifying 
which specific inside diameter is required. This has caused confusion 
for both operators and the BLM with respect to which diameter should be 
used for a given situation as required by this subpart. The BLM is 
proposing to define ``published'' and ``reference'' inside diameters of 
meter tubes to clarify when each of the defined inside diameters would 
be used in flow calculations and which would be used in table 
references for API MPMS 14.3.2 (Table 7, 8a, and 8b) to determine the 
minimum required meter tube lengths. The reason for this change is to 
achieve consistency with requirements and calculations in API MPMS 
14.3.2, which is incorporated by reference. The published inside 
diameter is the standard inside diameter as found in engineering 
handbooks. For example, the published inside diameter for 2-inch, 
Schedule 40 pipe is 2.067 inches. The published inside diameter is used 
to determine the minimum required lengths of meter tubes and placement 
of 19-tube bundle flow straighteners and isolating flow conditioners, 
if used (see 3175.80(i) and (n)). The reference inside diameter is 
calculated by averaging multiple inside diameter measurements taken 
upstream of the orifice plate and then correcting that average to a 
reference temperature. The reference inside diameter is used in the 
flow-rate equation, as required by Sec.  3175.103 in both the existing 
and proposed rules, and in the grandfathered flow-rate calculations 
defined in proposed Sec.  3175.50(2)(c)(i) (existing Sec.  
3175.61(b)(2)).
    The BLM would improve the existing definition of ``Upper calibrated 
limit'' by clarifying that it is commonly referred to in the oil and 
gas industry as ``span.'' The term ``upper calibrated limit'' was 
developed during the 2013 rewrite of gas standard API MPMS 21.1 and may 
not be familiar to the public. The addition of a reference to ``span'' 
would help readers who are more familiar with this term understand the 
new one.
3175.20 General Requirements
    Existing Sec.  3175.20 would be modified to reflect the new section 
numbering of the proposed regulation. Proposed Sec.  3175.20(b) would 
be added to address the additional sections on Gas storage agreement 
measurement points (GSAMP).
3175.30 Incorporation by Reference (IBR)
    Building on existing Sec.  3175.30, this proposed section lists 15 
industry standards, reports, and manuals that are proposed for 
incorporation by reference, either in whole or in part.
     AGA Report No. 3, Orifice Metering of Natural Gas and 
Other Related Hydrocarbon Fluids; Second Edition, September, 1985 
(``AGA Report No. 3 (1985)''). This report provides construction and 
installation requirements, and standardized implementation 
recommendations for the calculation of flow rate through concentric, 
square-edged, flange-tapped orifice meters. This standard was 
previously approved for IBR and is unchanged.
     AGA Transmission Measurement Committee Report No. 8, 
Compressibility Factors of Natural Gas and Other Related Hydrocarbon 
Gases; Second Edition, November 1992 (``AGA Report No. 8 (1992)''). 
This report presents detailed information for precise computations of 
compressibility factors and densities of natural gas and other 
hydrocarbon gases, calculation uncertainty estimations, and FORTRAN 
computer program listings. This standard was previously approved for 
IBR and is unchanged.
     AGA Transmission Measurement Committee Report No. 8, Part 
1, Thermodynamic Properties of Natural Gas and Related Gases, Detail 
and Gross Equations of State; Third Edition, April 2017 (``AGA Report 
No. 8 Part 1''). The part 1 is essentially the same computations of 
compressibility factors and densities of natural gas and other 
hydrocarbon gases, calculation uncertainty estimations, and FORTRAN 
computer program listings as the 1992 Second edition. This report is 
being proposed for incorporation because the BLM believes this revised 
standard would allow the use of a more accurate compressibility 
calculation while still retaining the older calculation for situations 
where the new calculation is not necessary or not practical.
     AGA Transmission Measurement Committee Report No. 8, Part 
2, Thermodynamic Properties of Natural Gas and Related Gases, GERG-2008 
Equation of State; First Edition, April 2017 (``AGA Report No. 8 Part 
2''). This part 2 introduces a new and more accurate computation known 
as ``GERG-2008''. This report is being proposed for incorporation 
because the BLM believes this new and more accurate computation known 
as ``GERG-2008 should be allowed under the proposed rule.
     API MPMS Chapter 14--Natural Gas Fluids Measurement, 
Section 1--Collecting and Handling of Natural Gas Samples for Custody 
Transfer; Seventh Edition, May 2016; Addendum, August 2017; Errata, 
August 2017 (``API 14.1''). This standard provides comprehensive 
guidelines for properly collecting, conditioning, and handling 
representative samples of natural gas that are at or above their 
hydrocarbon dew point. There are no substantive changes to this 
standard; we are proposing to add approval for the new Addendum and 
Errata to this standard.
     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''). This standard provides engineering equations and uncertainty

[[Page 55975]]

estimations for the calculation of flow rate through concentric, 
square-edge, flange-tapped orifice meters. This standard was previously 
approved for IBR and is unchanged.
     API MPMS Chapter 14, Section 3, Orifice Metering of 
Natural Gas and Other Related Hydrocarbon Fluids-- Concentric, Square-
edged Orifice Meters, Part 2, Specification and Installation 
Requirements; Fifth Edition, March 2016; Errata 1, March 2017; Errata 
2, January 2019) (``API 14.3.2''). This standard provides construction 
and installation requirements, and standardized implementation 
recommendations for the calculation of flow rate through concentric, 
square-edge, flange-tapped orifice meters. There are no substantive 
changes to this standard; we are proposing to add approval for the new 
Errata to this standard.
     API MPMS Chapter 14, Section 3, Orifice Metering of 
Natural Gas and Other Related Hydrocarbon Fluids-- Concentric, Square-
edged Orifice Meters, Part 3, Natural Gas Applications; Fourth Edition, 
November 2013 (``API 14.3.3''). This standard is an application guide 
for the calculation of natural gas flow through a flange-tapped, 
concentric orifice meter. This standard was previously approved for IBR 
and is unchanged.
     API MPMS Chapter 14, Natural Gas Fluids Measurement, 
Section 3, Concentric, Square-Edged Orifice Meters, Part 3, Natural Gas 
Applications, Third Edition, August, 1992 (``API 14.3.3 (1992)''). This 
standard is an application guide for the calculation of natural gas 
flow through a flange-tapped, concentric orifice meter. This standard 
was previously approved for IBR and is unchanged.
     API MPMS, Chapter 14.5, Calculation of Gross Heating 
Value, Relative Density, Compressibility and Theoretical Hydrocarbon 
Liquid Content for Natural Gas Mixtures for Custody Transfer; Third 
Edition, January 2009; Reaffirmed February 2014 (``API 14.5''). This 
standard presents procedures for calculating, at base conditions from 
composition, the following properties of natural gas mixtures: Gross 
heating value, relative density (real and ideal), compressibility 
factor, and theoretical hydrocarbon liquid content. This standard was 
previously approved for IBR and is unchanged.
     API MPMS Chapter 21.1, Flow Measurement Using Electronic 
Metering Systems--Electronic Gas Measurement; Second Edition, February 
2013 (``API 21.1''). This standard describes the minimum specifications 
for electronic gas measurement systems used in the measurement and 
recording of flow parameters of gaseous phase hydrocarbon and other 
related fluids for custody transfer applications utilizing industry 
recognized primary measurement devices. This standard was previously 
approved for IBR and is unchanged.
     GPA Midstream Standard 2166-17, Obtaining Natural Gas 
Samples for Analysis by Gas Chromatography, Reaffirmed 2017 (``GPA 
2166-17''). This standard recommends procedures for obtaining samples 
from flowing natural gas streams that represent the compositions of the 
vapor phase portion of the system being analyzed. This standard is 
being proposed for incorporation because, since the existing regulation 
published in November 2016, the GPA published a revised standard, GPA 
2166-17. Although there have been few changes from the 2005 standard, 
the BLM believes the revised version would result in gas samples that 
better represent the gas flowing through the FMP, which would help 
improve the accuracy of the heating value reported on the OGOR B. There 
are no substantive changes to this standard; we are proposing to add 
approval for the reaffirmation date of this standard.
     GPA Standard Midstream 2261-19, Analysis for Natural Gas 
and Similar Gaseous Mixtures by Gas Chromatography; Revised 2019 (``GPA 
2261-19''). This standard establishes a method to determine the 
chemical composition of natural gas and similar gaseous mixtures within 
set ranges using a gas chromatograph (CG). There are no substantive 
changes to this standard; we are proposing to add approval for the new 
revision date of this standard.
     GPA Midstream Standard 2198-16, Selection, Preparation, 
Validation, Care and Storage of Natural Gas and Natural Gas Liquids 
Reference Standard Blends; Revised 2016 (``GPA 2198-16''). This 
standard establishes procedures for selecting the proper natural gas 
and natural gas liquids reference standards, preparing the reference 
standards for use, verifying the accuracy of composition as reported by 
the manufacturer, and the proper care and storage of those reference 
standards to ensure their integrity as long as they are in use. This 
standard is being proposed for incorporation because, since the 
existing regulation published in November 2016, the GPA published a 
revised standard, GPA 2198-16. The BLM reviewed the revised standard 
and determined that the changes from the previous version will help 
improve the accuracy, reliability, and verifiability of reference 
standard blends.
     PRCI Contract-NX-19, Manual for the Determination of 
Supercompressibility Factors for Natural Gas; December 1962 (``PRCI NX 
19''). This manual presents detailed information for computations of 
compressibility factors and densities of natural gas and other 
hydrocarbon gases. This standard was previously approved for IBR and is 
unchanged.
    The BLM is proposing to remove four industry standards that are 
currently incorporated by reference in existing subpart 3175.
     API MPMS Chapter 22.2--Testing Protocol, Differential Flow 
Measurement Devices; First Edition, August 2005; Reaffirmed August 2012 
(``API 22.2''). This standard is a testing protocol for any flow meter 
operating on the principle of a local change in flow velocity, caused 
by the meter geometry, giving a corresponding change of pressure 
between two reference locations. API 22.2 is being proposed for removal 
because the regulatory language in existing Sec.  3175.47 on the 
testing process, which refers to API 22.2, would be replaced with a 
general reference to the PMT website for all equipment that requires 
BLM approval in proposed Sec.  3175.40. See the discussion of the PMT 
review process under Sec.  3175.40 later in this preamble.
     GPA Standard 2166-05, Obtaining Natural Gas Samples for 
Analysis by Gas Chromatography; Adopted as a tentative standard, 1966; 
Revised and Adopted as a standard 1968; Revised 1986, 2005 (GPA 2166-
05). This standard recommends procedures for obtaining samples from 
flowing natural gas streams that represent the compositions of the 
vapor phase portion of the system being analyzed. GPA 2166-05 is being 
proposed for removal because this standard has been replace by GPA 
2166-17.
     GPA Standard 2198-03, Selection, Preparation, Validation, 
Care and Storage of Natural Gas and Natural Gas Liquids Reference 
Standard Blends; Adopted 1998; Revised 2003 (GPA 2198-03). This 
standard establishes procedures for selecting the proper natural gas 
and natural gas liquids reference standards, preparing the reference 
standards for use, verifying the accuracy of composition as reported by 
the manufacturer, and the proper care and storage of those reference 
standards to ensure their integrity as long as they are in use. GPA 
2198-03 is being proposed for removal because this standard has been 
replaced by GPA 2198-16.

[[Page 55976]]

     GPA Standard 2286-14, ``Method for the Extended Analysis 
of Natural Gas and Similar Gaseous Mixtures by Temperature Program Gas 
Chromatography; Adopted as a standard 1995; Revised 2014 (``GPA 2286-
14''). This method is intended for the compositional analysis of 
natural gas and similar gaseous mixtures where precise physical 
property data of the hexanes and heavier fractions are required. The 
procedure is applicable for mixtures which may contain components of 
nitrogen, carbon dioxide, and/or hydrocarbon compounds C1-C14. GPA 
2286-14 is being proposed for removal because, since the existing 
regulations was published in November 2016, the BLM determined that 
this standard is primarily intended for laboratory use and is not 
applicable to the determination of gas composition in typical field 
applications.
3175.31 Specific Performance Requirements
    Existing Sec.  3175.31 establishes the minimum performance 
standards for uncertainty, bias, and verifiability. The BLM is 
proposing certain modifications to this section in order to clarify its 
requirements and facilitate the application of those requirements. 
Clarification of these requirements is of particular importance because 
this section established the minimum standards that all equipment and 
processes must meet for BLM approval.
    Existing Sec.  3175.31 (a) establishes flow-rate uncertainty limits 
for high- and very-high-volume FMPs. There are no uncertainty limits 
for low- and very-low-volume FMPs in the existing regulation and the 
BLM is not proposing to add any. The proposed rule would add a new 
paragraph (a)(3) to clarify that there are no uncertainty limits for 
low- and very-low-volume FMPs.
    Proposed Sec.  3175.31(b)(1) would increase the allowable 
uncertainty in average annual heating value for high-volume FMPs from 2 
percent to 3 percent. For very-high-volume FMPs, the average annual 
heating value uncertainty would be increased from 1 percent in existing 
Sec.  3175.31(b)(2) to 2 percent. The average annual heating value 
uncertainty is a measure of how well a 12-month average of heating 
values, as determined from spot samples, compares to a hypothetical 12-
month average based on continuous heating value measurement. The 
average annual heating value uncertainty is a function of how variable 
the heating value from spot sample to spot sample is and how often the 
spot samples are taken. For an FMP that has heating values that are 
fairly consistent from sample to sample, it may only take two or three 
samples to achieve a set level of uncertainty. On the other hand, if 
the heating values vary considerably from sample to sample, it may take 
10 or more samples to achieve the same level of uncertainty.
    The BLM developed the following equation (see existing Sec.  
3175.31(b)(4)) which defines the relationship between the number of 
samples taken over a year (N), the average annual heating value 
uncertainty
[GRAPHIC] [TIFF OMITTED] TP10SE20.047

and heating value variability from sample to sample (V95%).
[GRAPHIC] [TIFF OMITTED] TP10SE20.000

    In this equation, the number of samples required to achieve a set 
level of average annual heating value uncertainty changes as the square 
of the average annual heating value uncertainty. For example, if the 
heating value variability is 4 percent and the required 
level of uncertainty is 1 percent, then it would require 
the operator to take 15 samples per year. However, if the required 
level of uncertainty was increased to 2 percent, it would 
reduce the required number of samples per year to four.
    Since the existing rule published in November 2016, industry has 
expressed concern over Sec.  3175.115(b), which requires the operator 
to adjust the sampling frequency of high- or very-high-volume FMPs to 
achieve the levels of average annual heating value uncertainty required 
under Sec.  3175.31(b). By increasing the maximum level of uncertainty 
under the proposed rule, the maximum number of samples required per 
year would drop by 75 percent for very-high-volume FMPs and 56 percent 
for high-volume FMPs. The BLM believes that the proposed increase in 
average annual heating value uncertainty would alleviate much of 
industry's concern while still providing the BLM with an objective and 
performance-based method to establish spot sampling frequency. The BLM 
also believes the proposed uncertainty limits for average annual 
heating value are justified because they would match the uncertainty 
limits for volume determination. The BLM is specifically seeking 
comments on this proposed change. Both volume and heating value have 
equal effect on the amount of royalty due. Royalty is determined by a 
multiplication of the royalty rate (determined by the lease agreement), 
the volume (determined by a BLM compliant measurement point), the 
heating value (determined by a BLM approved sampling method), and the 
value (determined by ONRR).
    In the existing regulation, the defined limits for heating value 
uncertainty came from the BLM Threshold Analysis. In the time period 
between the publication of the current regulation, it has become clear 
that some costs were not considered in that calculation. The 
possibility of increased sampling frequency would incur additional 
administrative costs and visits to FMP locations for operators. Many 
times these locations are remote, which also creates additional 
associated cost with the sampling. The BLM has accounted for those 
additional costs in the proposed heating value uncertainty limits.
    Existing Sec.  3175.31(b) establishes heating value uncertainty 
limits for high- and very-high-volume FMPs. There are no uncertainty 
limits for low- and very-low-volume FMPs in the existing regulations 
and the BLM is not proposing to add any. The BLM would add a new 
paragraph (b)(3) to the proposed rule only to clarify that there are no 
uncertainty limits for low- and very-low-volume FMPs.
3175.40 Measurement Equipment Requiring BLM Approval
    The proposed rule would reorganize existing Sec.  3175.40, as well 
as make a number of changes to the requirements. Existing Sec.  3175.40 
lists the types of equipment that are allowed for use at FMPs. Some of 
this equipment, including flange-tapped orifice plates (existing Sec.  
3175.41), chart recorders (existing Sec.  3175.42, for low- and very-
low-volume FMPs only), and gas chromatographs (existing Sec.  3175.45) 
are automatically approved with no additional review required. Other 
equipment--including transducers (existing Sec.  3175.43), flow-
computer software (existing Sec.  3175.44), flow conditioners (existing 
Sec.  3175.46),

[[Page 55977]]

differential meters other than flange-tapped orifice plates (existing 
Sec.  3175.47), linear meters (existing Sec.  3175.48), and accounting 
systems (existing Sec.  3175.49)--requires BLM approval based on a 
review and recommendation from the PMT. The sections for each device 
requiring BLM approval include some description of the required 
testing.
    Under the proposed rule, the equipment requiring BLM approval would 
be grouped under revised Sec.  3175.40 and the equipment automatically 
approved would be grouped under revised Sec.  3175.41 (see discussion 
under Sec.  3175.41). All discussion regarding the testing and PMT 
review process under existing Sec.  3175.43 through Sec.  3175.49 would 
be removed and replaced with a statement directing the reader to the 
PMT section of the www.blm.gov website. The BLM is proposing these 
changes in order to streamline and better organize the regulations.
    As with the transducer and flow computer testing procedures 
(Sec. Sec.  3175.130 and 3175.140, respectively), all discussion 
relating to the testing and review process would also be removed and 
placed on the PMT website. The reason for this change is to achieve 
consistency with subpart 3174 (oil measurement) and to allow 
modifications to the testing and review processes based on experience 
and input from operators and manufacturers. As explained in the 
previous discussion of proposed Sec.  3170.30, the purpose of the PMT 
review process, and any associated testing procedures, will be to 
assess whether the proposed alternative equipment meets the minimum 
performance standards of subpart 3175.
    Existing Sec.  3175.48 addresses all types of linear gas meters. 
Under proposed Sec.  3175.40, linear meters would be listed as Coriolis 
meters (Sec.  3175.40(e)) and ultrasonic meters (Sec.  3175.40(f)). The 
BLM is proposing this change because the BLM estimates that the 
majority of linear meters used for gas measurement will fall into one 
of these two categories. All other types of linear meters would be 
reviewed as ``new technology'' by the PMT. The PMT will need to develop 
a testing procedure for all equipment covered under Sec.  3175.40. It 
would be difficult for the PMT to build a generic testing procedure for 
all linear meters due to the dramatic differences in technology and 
varied range of influence effects that such a widely diverse group of 
equipment would create.
    The proposed rule would add new Sec.  3175.40(g), which would 
address software used to capture and process output from a gas 
chromatograph (GC), to the list of devices that require BLM approval. 
The BLM is proposing to require BLM approval of this software because 
it is critical to the determination of heating value and relative 
density, both of which have a direct effect on the determination of 
royalty. In addition, the BLM is not aware of any industry standards 
that dictate how this software must function or any existing 
independent, third party, review of this software. Like other equipment 
and software requirements, the BLM would review GC software to ensure 
that it complies with the Sec.  3175.31 requirements, particularly with 
respect to verifiability and any potential bias that a software might 
produce.
    The raw output from a GC consists of a chromatogram, which is a 
graph of detector response over time. As a gas sample is run through a 
GC, the GC first sorts the molecules in the gas, typically by molecular 
weight, using a series of filters and devices known as columns. After 
flowing through these filters and columns, all the methane molecules, 
for example, are grouped together and segregated from the other 
molecules. Likewise, the ethane, propane, butane, and other molecules 
are each grouped and segregated. As the groups of segregated molecules 
flow out of the GC, they pass through a detector that generates a 
response, or ``blip,'' in relation to the size of the group of 
molecules. A large blip corresponds to a large concentration of that 
molecule in the gas sample. A software package captures this output 
from the GC and uses the size of the blip as well as the type of 
molecule to determine the concentration of each molecule in the gas 
sample. The BLM believes that PMT review of this software is critical 
to ensure the software is properly interpreting the output from the GC 
and accurately determining the molecular concentrations, which are 
ultimately used to calculate the heating value and relative density of 
the gas sample.
    The proposed rule would add water-vapor measurement equipment and 
methods to the list of devices that require BLM approval. The most 
common water-vapor measurement devices--chilled mirrors and laser 
detection devices--are automatically approved under the existing 
regulation (see Sec.  3175.126(a)(1)(i) and (ii)). Water vapor in a gas 
stream does not contribute any heating value and displaces hydrocarbon 
molecules, which do have heating value. As a result, water vapor 
reduces the heating value of gas, which in turn reduces the royalty 
value of the gas.
    Both the existing and proposed rules allow operators to reduce the 
gas heating value based on measured amounts of water vapor in the gas 
stream. Unlike other molecules, such as carbon dioxide and nitrogen, 
which also reduce the heating value of a gas, water vapor is not 
detected using a gas chromatograph; therefore, alternate means of 
measuring water vapor are commonly used, such as a chilled mirror and 
laser detection devices.
    Since the publication of the existing rule, the BLM has determined 
that both chilled mirrors and laser detection devices can vary in 
design and may have certain operating limitations that could affect the 
amount of water vapor they measure. For example, some laser detectors 
will mistake other components in the gas stream for water vapor, 
thereby overstating the amount of water vapor that is actually in the 
gas stream. Chilled mirrors also vary in design and can sometimes 
mistake hydrocarbons for water, which can cause errors in the measured 
water vapor content. By requiring PMT review and BLM approval of all 
water-vapor detection equipment and methods used at FMPs, the BLM can 
determine the accuracy of these devices and their operating limitations 
based on independent laboratory data. Like other equipment, the BLM 
would review these devices to ensure compliance with the Sec.  3175.31 
requirements, particularly with respect to any potential bias that a 
device might produce by falsely detecting hydrocarbons as water vapor.
    The proposed rule would add Sec.  3175.40(i), which would address 
measurement data systems. Under existing Sec.  3175.49, accounting 
systems used to report measurement data must be approved by the BLM. 
Since the publication of the existing regulation, the BLM has found 
that the term ``accounting system'' has caused confusion among 
operators, who sometimes assume this includes systems that maintain 
financial information. The proposed rule would not only move the 
requirement for accounting systems to obtain BLM approval to a new 
section, it would also rename accounting systems to ``measurement data 
systems'' in order to more accurately describe these systems. 
Measurement data systems are designed to gather, edit, store, and 
report measurement data and have nothing to do with financial 
information. The review process would allow the BLM to confirm that the 
measurement data systems will adequately preserve raw data and 
verifiability to meet the requirements of Sec.  3175.31.

[[Page 55978]]

3175.41 Approved Measurement Equipment
    The proposed rule would modify Sec.  3175.41, to place all approved 
measurement equipment in a single section of the regulation. This 
consolidation would replace the existing Sec.  3175.40, Sec.  3175.41, 
Sec.  3175.42, Sec.  3175.43, Sec.  3175.44, and Sec.  3175.45.
3175.43 Data Submission and Notification Requirements
    Under proposed Sec.  3175.43, all the notification and data 
submission requirements would be consolidated and listed in one place. 
The BLM proposes to add this section to help operators identify and 
track the notification and data submission requirements. This section 
does not impose any new notification or reporting requirements.
3175.50 Grandfathering
    The BLM is proposing an expansion of the equipment that would be 
grandfathered in place and not require BLM approval. The BLM is 
proposing to revise subpart 3175's grandfathering provision, which 
appears in existing Sec.  3175.61, and relocate it to Sec.  3175.50. 
Under the existing regulations (Sec. Sec.  3175.43, 3175.44, and 
3175.46 through 3175.49), the operator can only use equipment that has 
been approved by the BLM, through the PMT, and then placed on the list 
of type-tested equipment. The implementation of this provision was 
delayed until January 17, 2019, under existing Sec.  3175.60(a)(4) for 
equipment installed on or before January 17, 2017, and under Sec.  
3175.60(b)(2)(i) for equipment installed after January 17, 2017. The 
implementation of Sec.  3175.40 was further delayed by practical 
necessity (see BLM Instruction Memorandum 2018-077). The proposed new 
grandfathering section (Sec.  3175.50(a)) would exempt all equipment 
covered by Sec.  3175.40 in place at very-low, low, and high-volume 
FMPs on or before the effective date of the final revised rule from the 
BLM-approval requirement. Equipment at very-high-volume FMPs would not 
be exempt, regardless of when it was installed. The BLM is not 
proposing to grandfather equipment installed at very-high-volume FMPs 
because of the higher risk of significant mismeasurement due to the 
high volume of gas measured and because the revenue resulting from the 
high production volumes would make replacing equipment, if necessary, 
economically feasible.
    There are three reasons that the BLM is proposing to add this 
grandfathering provision. First, shortly after its inception, the PMT 
realized that the workload of reviewing data from all existing makes, 
models, and sizes of equipment requiring approval under Sec.  3175.40 
would be enormous and could take years to complete, far longer than the 
originally projected 30- to 60-day review process. Second, operators 
have expressed concerns about the cost of replacing existing equipment 
that is not on the BLM list of approved equipment with equipment that 
is on the list, especially at lower-volume FMPs. Third, upon review of 
operator-supplied field data for some existing equipment approvals, it 
became clear to the PMT that such data was, in most cases, insufficient 
to perform statistically significant analysis. Without a controlled 
baseline, most data received provided little useful information about 
the performance of the device. The BLM understands that it is 
impractical for operators to remove outdated or obsolete equipment from 
the field and subject it to laboratory testing. The grandfathering 
provision of this proposed rule would balance the possible threat of 
uncertainty error against the imposed burden of such testing.
    Based on these concerns, the BLM is proposing to grandfather all 
equipment installed at very-low, low-, and high-volume FMPs on or 
before the effective date of the new final rule. This would 
dramatically decrease the number of makes, models, and sizes of 
equipment that would be subject to review by the PMT and would assure 
operators that they would not have to immediately replace this 
equipment.
    The proposed grandfathering could have some impacts on the BLM's 
ability to ensure accurate measurement, the absence of statistically 
significant bias, and verifiability, all of which are required under 
the performance goals in both the existing regulations and the proposed 
regulations. For example, for high-volume FMPs, which must comply with 
the uncertainty performance goals under Sec.  3175.31(a) of the 
existing regulations, the grandfathering of existing transducers, flow 
conditioners, linear meters, and differential meters other than flange-
tapped orifice plates could impact the BLM's ability to ensure accurate 
measurement. The current version of the BLM's uncertainty calculator, 
which is used to determine and enforce overall uncertainty, is based on 
the manufacturer's specifications for that device. It has been the 
BLM's experience that manufacturers develop specifications based on 
proprietary test procedures and test data interpretation methods that 
may overstate the actual field performance of their devices. By 
grandfathering these devices, the actual overall measurement 
uncertainty has the potential to be substantially greater than what is 
calculated using the uncertainty calculator. In contrast, those 
devices, which are not grandfathered, are subject to independent review 
and analysis by the PMT based on laboratory test data. The uncertainty 
and operating limitations of these devices determined by the PMT would 
be used in the uncertainty calculator, yielding a more realistic 
uncertainty calculation.
    For all devices covered by existing regulations (Sec. Sec.  
3175.43, 3175.44, and 3175.46 through 3175.49), the lack of PMT review 
of laboratory data could result in devices operating outside the limits 
over which they were tested. This could result in these devices 
operating at conditions that would lead to statistically significant 
bias.
    Notwithstanding the potential drawbacks of the proposed 
grandfathering, the majority of the meters affected by this proposal do 
not have an uncertainty requirement as part of their specific 
performance requirements, and compliance with the existing regulation 
could result in cost that would exceed a low producing or older well's 
income after that expense. The BLM believes the benefits of continued 
production outweigh the potential drawbacks and pose little risk to 
royalty accountability.
    Proposed Sec.  3175.50(b)(1) would clarify Sec.  3175.61(a) of the 
existing regulation. Both the existing and proposed regulations 
grandfather certain aspects of meter tubes installed at low- and high-
volume FMPs before January 17, 2017. During implementation of the 
existing regulations, numerous operators expressed confusion over the 
conditions for grandfathering, such as whether the grandfathering would 
still apply if they replaced the meter tube at an FMP that was in place 
before January 17, 2017. The wording of existing Sec.  3175.61(a) 
applies the grandfathering to ``meter tubes installed at low- and high-
volume FMPs before January 17, 2017. . . .'' The BLM has interpreted 
this to mean that the January 17, 2017, ``cut-off date'' applies to the 
date of the meter tube installation, not the date that the FMP was 
established. If the BLM had intended the latter interpretation, the 
wording would have been ``meter tubes at FMPs in place before January 
17, 2017. . . .'' In any case, this proposed rule would clarify this 
requirement by adding an explicit statement that if a meter tube is 
replaced it no longer qualifies for grandfathering.
    The current industry standards for meter tubes that would be 
grandfathered

[[Page 55979]]

under this proposed section have been in place since 1991 and are based 
on large amounts of laboratory testing and data analysis. The BLM 
believes that requiring meter tubes to comply with these standards is 
important for accurate and verifiable measurement. The only reason for 
grandfathering non-compliant meter tubes installed before January 17, 
2017, was to eliminate the cost of having to replace them with meter 
tubes that comply with the current industry standards, recognizing that 
there could be some adverse impact to measurement as a result. If an 
operator is going to change out a meter tube anyway (due to damage or 
excessive wear, for example) the BLM does not believe the additional 
expense of replacing the existing non-compliant meter tube with one 
that complies with current industry standards is significant, 
especially considering that current industry meter-tube standards have 
been in effect for 26 years. When a meter tube must be replaced, the 
only justification for grandfathering--expense--is largely eliminated.
    Proposed Sec.  3175.50(b)(2) would expand on current Sec.  
3175.61(a) in order to make clear that the BLM will accept measured 
inside pipe diameters that comply with AGA Report No. 3 (1985), Section 
4.3.3 (incorporated by reference, see Sec.  3175.30) for grandfathered 
meter tubes covered in this subpart. The BLM recognizes that much of 
the grandfathered equipment will not have reference inside diameters 
that meet the requirements of Sec.  3175.91(d)(7), Sec.  3175.92(d)(2), 
Sec.  3175.93(d), Sec.  3175.101(c)(5), Sec.  3175.102(e)(1)(iii), and 
therefore the BLM will allow the use of measured inside diameters that 
comply with AGA Report No. 3 (1985), Section 4.3.3 for flow-rate 
calculations.
    Proposed Sec.  3175.50(c)(2)(i) would fix two typographical errors 
in existing Sec.  3175.61(b)(2). This section refers to a variable 
called ``xi'' in ``API 14.3.3 (1992).'' The correct variable name is 
``x1'' and the reference should be API 14.3.3 (2013). Proposed Sec.  
3175.50(c)(2)(ii) keeps the current language in existing Sec.  
3175.61(b)(2), but segments the compressibility for clarity.
3175.60 Timeframes for Compliance
    The proposed rule would generally require all measuring procedures 
and equipment to comply with the proposed requirements by the effective 
date of the final rule. The BLM is not proposing phase-in periods, 
except in the special circumstances described in paragraphs (a) through 
(d) of this section. Under existing regulations, measuring procedures 
and equipment used at high- and very-high-volume FMPs had to comply 
with the requirements by January 17, 2018. Measuring procedures and 
equipment used at low-volume FMPs had to comply with the requirements 
by January 17, 2019, and, for very-low-volume FMPs, compliance is 
required after January 17, 2020. Because all FMPs, other than very-low-
volume FMPs, would already have to comply with the existing regulations 
by the time the final rule is published, and because most of the 
changes proposed under this rule would be less restrictive than those 
in the existing rule, the BLM did not see the need for phase-in 
periods, other than for the items specified in paragraphs (a) through 
(d) of this section.
    Section 3175.60(a) would require measuring equipment and procedures 
installed at very-low-volume FMPs before January 17, 2017, to comply 
with all of the requirements of this subpart as of the effective date 
of the final rule.
    Section 3175.60(b) would change the phase-in period for the 
requirement to enter gas analyses into the BLM's Gas Analysis Reporting 
and Verification System (GARVS) (see Sec.  3175.120(e) and (f) of 
existing regulations). Under existing Sec. Sec.  3175.60(a)(2) and 
3175.60(b)(2)(ii), the requirement to enter gas analyses into GARVS was 
delayed until January 17, 2019. (Note that this requirement was 
effectively delayed further through Washington Office Instruction 
Memorandum 2018-077.) In the proposed rule, the requirement to enter 
gas analyses into GARVS would go into effect 90 days after the BLM 
provides notice that GARVS is available for use. The BLM is proposing 
this change because the development and testing of GARVS may take much 
longer than expected given the complexity of GARVS. The BLM is not 
proposing a specific date for this requirement to become effective due 
to the difficulty in estimating time frames for development of GARVS.
    Section 3175.60(c) would change the phase-in period for the 
requirement to use only the BLM-approved equipment as specified in 
Sec. Sec.  3175.43 and 3175.44, and Sec. Sec.  3175.46 through 3175.49 
of the existing regulations. Under existing regulations (see Sec. Sec.  
3175.60(a)(4) and 3175.60(b)(2)(iii)), the requirement for operators to 
use only specified equipment that has been approved by the BLM becomes 
effective on January 17, 2019. Under the proposed rule, this deadline 
would be extended to 2 years after the effective date of the final 
rule. The BLM has established the PMT, which is responsible for 
reviewing equipment and making recommendations to the BLM as to whether 
the equipment should be placed on the list of approved equipment. The 
PMT has developed the testing procedures required for PMT review and 
has begun to review equipment. The BLM is proposing the 2-year 
extension of the deadline based on the PMT's current work and estimates 
of the time it will take the PMT to complete an initial review of 
equipment likely to be submitted by operators and manufacturers.
    Section 3175.60(d) would add a phase-in period for the requirement 
for electronic gas measurement systems to display the software version 
(see existing Sec.  3175.101(b)(4)). The reason the existing regulation 
requires the software version to be displayed is to allow BLM 
inspectors to check that the software version is on the BLM list of 
approved equipment. However, as described previously, the requirement 
to use only BLM-approved equipment (including software) would not come 
into effect until 2 years after the effective date of the new final 
rule. Therefore, there is no point in requiring EGM systems to display 
the software version until operators are required to use only BLM-
approved software versions.
    The BLM is proposing to delete existing Sec.  3175.60(c) and (d). 
Paragraph (c) requires operators to comply with Onshore Order No. 5 and 
the statewide NTLs during the phase-in periods and paragraph (d) 
rescinds Onshore Order No. 5 and the statewide NTLs once the phase-in 
periods end. If this rule is finalized as proposed, these paragraphs 
will not be needed. For all FMPs, the phase-in periods have ended and 
Onshore Order No. 5 and the statewide NTLs have been rescinded under 
paragraph (d).
3175.80 Flange-Tapped Orifice Plate (Primary Device)
    Existing and proposed Sec.  3175.80 define the requirements for 
orifice metering of gas. The proposed rule seeks to improve Sec.  
3175.80 based on feedback from BLM field offices. The introductory 
language in this section would be changed to reference the proposed 
Sec.  3175.50 grandfathering requirements.
    With proposed Sec.  3175.80(a), the BLM would replace existing 
paragraph (a) (which will become Sec.  3175.80(c) of the proposed rule) 
with new language that would clarify a requirement in existing Table 1 
to Sec.  3175.80. The first entry (``Fluid conditions'') in Table 1 to 
Sec.  3175.80, refers to API 14.3.1, Subsection 4.1, which describes 
the conditions of the fluid flowing the through the meter on which the

[[Page 55980]]

standard is based. These conditions include:
     Single phase;
     Homogeneous;
     Newtonian; and
     With a Reynolds number of 4,000 or greater.
    Because this reference in API 14.3.1 is a description of assumed 
fluid conditions used to develop the standard, rather than a 
requirement, it is unenforceable as written. Therefore, proposed Sec.  
3175.80(a)) would still refer to API 14.3.1, Subsection 4.1, but would 
also clarify that fluid conditions must comply with the description in 
API. The BLM received no comments on this issue during the promulgation 
of the existing regulation, but discovered the possible confusion in 
internal BLM discussions with field inspectors.
    With proposed Sec.  3175.80(b), the BLM would replace existing 
paragraph (b) (which would become Sec.  3175.80(d) of the proposed 
rule) with new language that would clarify a requirement in existing 
Table 1 to Sec.  3175.80. This modification would allow for greater 
clarity on the reference API 14.3.2, Subsection 6.2.1, and the 
perpendicularity requirements of the orifice plate.
    Under existing Sec.  3175.80(c), operators are required to inspect 
orifice plates every 2 weeks at FMPs measuring their first production 
or from wells that have been re-fractured. This proposed rule would 
remove the phrase ``if the inspection shows that'' from the existing 
requirement to replace the orifice plate if it does not comply with API 
14.3.2, Section 4. It is the BLM's understanding that this phrase was 
interpreted by some operators to mean that BLM personnel attendance is 
necessary at each inspection. The BLM did not intend for the operator 
to wait on BLM personnel to perform these inspections. Under this 
proposed rule, the operator or their representative would inspect the 
orifice plate and determine if the orifice plate met the requirements.
    Proposed Sec.  3175.80(f) would modify the specific guidelines for 
maximum time between inspections in existing Sec.  3175.80(d). Under 
this proposed rule, the BLM would move Table 1 to Sec.  3175.115 to 
Appendix B of this subpart, and add a reference to Appendix B in 
proposed Sec.  3175.80(f)(2). This removes the ambiguity with respect 
to the acceptable timeframes for compliance for this subpart. See 
discussion under Appendix B.
    Proposed Sec.  3175.80(j) would add an initial basic meter-tube 
inspection that would require operators to perform a basic meter-tube 
inspection within 1 year after installation of a very-high-volume FMP 
and within 2 years after installation of a high-volume FMP. This 
requirement would only apply to FMPs installed after the effective date 
of the new final rule. The BLM is proposing this requirement in order 
to help offset potential meter-tube measurement issues caused by well 
start-up that could go undetected due to the longer time between 
routine basic meter-tube inspections proposed under Sec.  3175.80(k). 
If a meter is subject to pitting, buildup of foreign substances, or 
obstructions, these issues will typically show up early in the life of 
the meter. During the basic meter-tube inspections that the BLM has 
witnessed up to the development of this proposed rule, BLM inspectors 
have discovered a high probability of loose material collecting in the 
flow line, partially blocking flow conditioners and orifice plates. The 
initial meter-tube inspection would allow operators to catch and 
resolve these problems before reverting to the routine basic meter-tube 
inspection frequencies proposed in Sec.  3175.80(k).
    Proposed Sec.  3175.80(k) would change the basic meter-tube 
inspection frequencies from those required under existing Sec.  
3175.80(h). Currently, operators must perform a basic meter-tube 
inspection every year at very-high-volume FMPs, every 2 years at high-
volume FMPs, and every 5 years at low-volume FMPs. Very-low-volume FMPs 
are exempt from basic meter-tube inspections. Industry has expressed 
concern about the cost associated with performing a basic meter-tube 
inspection at this frequency and the lost production that occurs when 
shutting down a meter to inspect the meter tube. Based on these 
concerns, the BLM re-examined the required inspection frequency and 
determined that in most cases, the BLM could achieve roughly the same 
confidence of meter-tube condition with fewer inspections. Under the 
proposed rule, operators would have to perform a basic meter-tube 
inspection every 5 years at both high- and very-high-volume FMPs, and 
every 10 years at low-volume FMPs. Very-low-volume FMPs would continue 
to be exempt. The BLM would also add a requirement for an initial basic 
meter-tube inspection for high- and very-high-volume FMPs (see 
discussion under proposed Sec.  3175.80(j)) and would change the name 
of the basic meter-tube inspection to ``routine'' basic meter-tube 
inspection.
    Based on industry experience, meter-tube problems, such as pitting 
and buildup of foreign substances, are more likely to happen at lower-
volume meters. High-volume meters tend to have high enough gas velocity 
through the meter that corrosive substances, which can cause pitting, 
such as standing water, cannot collect in the meter tube. Foreign 
substances, such as sludge and scale, also are less likely to 
accumulate where gas velocity is high. Although low-volume FMPs are 
more likely to have pitting and sludge buildup, the lower volume makes 
any potential mis-measurement less significant. The BLM believes the 
proposed routine basic meter-tube inspection frequency strikes a 
balance between economic burden on the operator and mitigating the risk 
of lost royalty.
    The BLM is proposing a number of changes in Sec.  3175.80(k)(3) 
based on industry concerns. Under existing Sec.  3175.80(i)(1)(i), the 
operator must clean the meter tube on a low-volume FMP if the basic 
meter-tube inspection shows pitting, obstructions, or a buildup of 
foreign substances. For high- and very-high-volume FMPs, the operator 
must perform a detailed meter-tube inspection under existing Sec.  
3175.80(i)(1)(ii) and make any necessary measurements to determine if 
the meter complies with API 14.3.2, Subsections 5.1 through 5.4 and API 
14.3.2, Subsection 6.2, or the requirements under existing Sec.  
3175.61(a), if the meter tube is grandfathered under existing Sec.  
3175.61(a). This typically involves removing the meter tube and 
measuring the inside diameter at multiple points with a micrometer. It 
also involves determining the surface roughness of the inside surface 
of the meter tube. A detailed meter-tube inspection can be costly.
    Industry has expressed two concerns specific to these requirements 
during outreach conducted after the release of the 2016 rule. First, 
industry pointed out that if an operator performs a basic meter-tube 
inspection on a low-volume FMP and the only identified problem is 
pitting, the operator is required to clean the meter tube under 
existing Sec.  3175.80(i)(1)(i). However, cleaning the meter tube will 
not resolve pitting issues and therefore provides no value. Second, if 
an operator performs a basic meter-tube inspection on a high- or very-
high-volume FMP and the only identified problem is an obstruction, such 
as debris in front of the orifice plate or flow conditioner, the 
problem can be easily resolved by removing the debris. As long as there 
were no other issues identified during the basic meter-tube inspection, 
performing a detailed inspection under existing Sec.  3175.80(i)(1)(ii) 
would provide no value and the removal of the obstruction would return 
the meter to normal

[[Page 55981]]

service, which is the overall goal of the meter inspection.
    The BLM agrees with these concerns and is proposing to make a 
number of changes to the basic meter-tube inspection requirements to 
address them. Under proposed Sec.  3175.80(k)(3), paragraphs (i) 
through (iii) would be added to identify a required course of action 
based on the results of the basic meter-tube inspection. If the only 
issue identified on a high- or very-high-volume FMP is an obstruction, 
proposed paragraph (i) would only require the operator to remove the 
obstruction; a detailed inspection would no longer be required. 
Proposed paragraph (ii) would only require the operator to clean the 
meter tube at low-volume FMPs if the basic meter-tube inspection 
identified a buildup of foreign substances. If the basic meter-tube 
inspection at a high- or very-high-volume FMP revealed pitting or a 
buildup of foreign substances, then the operator would have to perform 
a detailed meter-tube inspection. Proposed paragraph (iii) would 
require a detailed meter-tube inspection if the basic meter-tube 
inspection revealed pitting or the build-up of foreign substances at a 
high- or very-high-volume FMP. Proposed paragraph (iii) is essentially 
the same as the current requirement in existing Sec.  3175.80(i). New 
paragraph (iv) of proposed Sec.  3175.80(k)(3) would allow the operator 
to submit an extension request to perform a detailed meter-tube 
inspection, which is essentially the same as existing Sec.  
3175.80(i)(1)(iii).
    Proposed Sec.  3175.80(k)(7) would modify the language of the 
existing regulation to set new timelines for initial and routine basic 
inspections. This would reduce the frequency of routine basic 
inspections and add a category for initial inspections.
    Under proposed Sec.  3175.80(l)(2), the BLM would modify the 
requirement in existing Sec.  3175.80(i)(2) regarding documentation of 
detailed meter-tube inspections at FMPs installed after January 17, 
2017. The existing regulation requires the documentation to show that 
the meter tube complies with API 14.3.2, Subsections 5.1 through 5.4; 
however, it does not reference API 14.3.2, Subsection 6.2 which is 
referenced under existing Sec.  3175.80(i)(1)(ii). This omission was an 
oversight in the writing of the current regulation and the BLM is 
therefore proposing to add the reference to the corresponding section 
of the proposed rule.
    Under proposed Sec.  3175.80(p), the BLM would move the 
requirements for the sampling-probe location in the meter tube. All 
three of these requirements are listed in existing Sec.  3175.112(b). 
These requirements include locating the sample probe:
     At the first obstruction downstream of the primary device;
     At least five pipe diameters downstream of the primary 
device; and
     Vertically in a horizontal section of pipe (through a 
reference to API MPMS 14.1, Subsection 6.4.2).
    The BLM proposes to move these requirements from existing Sec.  
3175.112(b) to proposed Sec.  3175.80(p) in order to consolidate all 
meter-tube construction requirements under one section. The sample 
probe is generally considered to be part of the meter tube because 
having the sample probe too close to the orifice plate could reduce the 
accuracy of the meter. In addition, the BLM inspects the sample probe 
location as part of an inspection of the meter tube. In proposed Sec.  
3175.112(b)(1), the BLM would remove the restatement of the sample 
probe requirements and replace it with a cross reference to Sec.  
3175.80(p).
    The proposed section would also address exceptions for vertical 
meter tubes, which are not addressed in the existing regulations. Under 
the existing regulations, the requirement to mount the sample probe 
vertically in a horizontal section of pipe would effectively prohibit 
vertical meter tubes. For vertical meter tubes, the only way to comply 
with this requirement would be to install the sample probe after an 
elbow downstream of the primary device. However, the elbow would then 
become the first obstruction and the installation would no longer 
comply with the requirement that the sample probe must be the first 
obstruction downstream of the primary device.
    During the implementation of the existing regulation, the BLM has 
heard concerns from numerous operators that have vertical meter tubes. 
Vertical meter tubes are not prohibited under industry standards such 
as API MPMS 14.3.2 and, in some situations, can have advantages over 
horizontal meter tubes. The BLM believes that the failure to address 
vertical meter tubes in the existing regulations was an oversight that 
this proposed rule would fix.
3175.91 Installation and Operation of Mechanical Recorders
    Existing and proposed Sec.  3175.91 defines the installation and 
operation requirements for mechanical recorders. The proposed rule 
would clarify parts of the requirements for the connection of 
mechanical recording devices as well as the on-site information 
requirements.
    Proposed Sec.  3175.91(a)(1) would revise the language in the 
existing regulation in order to separate the guidelines for gauge lines 
and manifold valves. The change would dedicate Sec.  3175.91(a)(1) to 
gauge lines and create a new section for valves and manifolds, Sec.  
3175.91(a)(2).
    Proposed Sec.  3175.91(a)(2) would revise the language in the 
existing regulation to specify that valves, including those in 
manifolds, would have to have full opening internal diameters of not 
less than \3/8\ inch. The existing rule requires gauge lines, ports, 
and valves to have a nominal diameter of not less than \3/8\ inch. This 
rule would clarify this language because the term ``nominal'' is not 
typically associated with ports and valves. Instead, ports and valves 
are typically defined by their full-opening bore size. The term 
``nominal,'' as used with tubing, means that the outside diameter is 
approximately \3/8\ inch, but the inside diameter can vary based on the 
wall thickness. Most \3/8\-inch nominal tubing used for gauge lines has 
an inside diameter of 0.305 inches. The BLM changed the wording for 
gauge lines from \3/8\-inch inside diameter in the October 2015 
proposed rule to \3/8\-inch nominal diameter in the final rule due to 
comments that stated operators have historically used \3/8\-inch 
nominal tubing for the gauge lines and that requiring the tubing to 
have an internal diameter of \3/8\ inch would require replacement of 
virtually all gauge lines, which would be cost prohibitive. The 
requirement for \3/8\-inch gauge lines, ports, and valves originated 
from API 14.3.2, Subsection 5.4.3, which recommends that flange taps 
have a minimum \3/8\ inch internal diameter and that gauge lines not 
include sudden changes in inside diameter. By separating the 
requirements for gauge lines and valves and manifolds the BLM can use 
the term ``nominal'' for gauge lines, to address operator concerns, 
without creating a potential issue or confusion about the requirements 
as they relate to bore sizing for valves and manifolds.
    Proposed Sec.  3175.91(d)(6) would change the wording from ``Meter 
elevation'' to ``Elevation of or atmospheric pressure at the FMP'' for 
on-site data required for mechanical recorders. This would allow either 
the FMP elevation or the atmospheric pressure at the FMP to be 
indicated on site. This rule proposes to allow atmospheric pressure to 
be posted at the FMP instead of meter elevation because either value 
will allow the BLM to verify the flow computer is properly programmed. 
Atmospheric pressure tends to be more readily available to operators 
and the BLM will be able to verify the atmospheric pressure during

[[Page 55982]]

an inspection. The atmospheric pressure can influence the flow rate 
calculation in two ways. If the recorder is using a gauge-pressure 
chart, then the operator must add the value of the atmospheric pressure 
to the pressure reading from the chart to calculate flow rate. If the 
recorder is using an absolute pressure chart, then the operator must 
know the value of atmospheric pressure when the pen offset is verified 
or calibrated. In either case, if the wrong value of atmospheric 
pressure is used, the flow-rate calculation will be in error. The lower 
the gas pressure at the FMP, the more significant the error becomes. If 
the atmospheric pressure is posted on site, then the BLM can verify 
that pressure--at least to some degree--by using GPS elevation or the 
elevation listed on the APD, and cross-reference that elevation to the 
table in Appendix A of the rule.
    Proposed Sec.  3175.91(d)(7) would require the reference inside 
diameter of the meter tube to be maintained at the FMP. As discussed in 
the discussion of Sec.  3175.10 earlier, the reference inside diameter 
is required for proper flow rate calculation. Under Sec.  3175.91(d)(7) 
of the existing regulations, only the inside diameter of the meter tube 
is required to be on site, but it is not clear which specific inside 
diameter is required. As the intent of the on-site information is to 
verify accurate gas measurement, the reference inside diameter of the 
meter tube would be required on site to verify its use in flow rate 
calculations.
3175.92 Verification and Calibration of Mechanical Recorders
    Existing and proposed Sec.  3175.92 define the verification and 
calibration requirements for mechanical recorders.
    Proposed Sec.  3175.92(b)(1) would add language to specify the 
equipment covered by this requirement and clarify that the timeframes 
referred to in Table 1 are in months. Proposed Sec.  3175.92(b)(2) 
would clarify the timeframe requirements of Table 1 of this subpart, 
and add a reference to Appendix B in Sec.  3175.92(b)(2). See the 
discussion of Appendix B, later.
    Proposed Sec.  3175.92(b)(3) would delay routine verification for 
an FMP in non-flowing status. This section would require the 
verification to be conducted within 15 days after the flow is re-
initiated. Under this section, non-flowing status means at least 3 
months of non-flow, and does not include intermittently flowing on a 
weekly or daily basis. The existing regulations do not address FMPs in 
non-flowing status and requires operators to continue to perform 
routine verifications on them even if they have been shut in since the 
last verification. The BLM is proposing this change based on industry 
concern and that there is no public benefit to requiring routine 
verifications when an FMP is shut in for a long period of time.
    Proposed Sec.  3175.92(d)(2) would require the operator to document 
the reference inside diameter of the meter tube. As discussed 
previously, the reference inside diameter is required for proper flow-
rate calculation. The existing regulations require the inside diameter 
of the meter tube to be documented on site, but it is not clear which 
specific inside diameter is required. As the purpose of requiring the 
information is to verify accurate gas measurement, the BLM is proposing 
to clarify that it is the reference inside diameter of the meter tube 
that is required on the verification documentation.
    Proposed Sec.  3175.92(e)(1) would change the amount of time an 
operator has to notify the BLM prior to performing a verification after 
installation or following a repair. This rule would change the 
timeframe to 1 business day. The existing regulation requires a minimum 
of a 72-hour notice prior to performing the verification. The original 
72-hour requirement does not allow for sudden changes in scheduling due 
to unforeseen field conditions. The change to 1 business day would 
allow operators to provide a more accurate notification to the BLM.
    Proposed Sec.  3175.92(e)(2) would modify the wording in the time 
frame for notifying the BLM of a routine verification. Under existing 
Sec.  3175.92(e)(2), operators must notify the AO at least 72 hours 
before performing a verification or submit a monthly or quarterly 
schedule of verifications. Industry has expressed concern regarding the 
logistics of scheduling verifications, which can be difficult even 72 
hours in advance. The purpose of this requirement is to give the BLM 
some idea of when verifications occur in order to schedule the 
witnessing of the verification. After considering the industry 
concerns, the BLM is proposing to modify the requirement to allow 
operators to either provide at least 72-hours' notice to the AO or 
submit a list of FMPs that the operator plans to verify over the next 
month or next quarter. The operator would no longer have to notify the 
BLM or submit a schedule of when each FMP would be verified. This list 
would show all verifications planned for that month or quarter, but not 
the specific day for each location. The BLM believes the list of wells 
an operator intends to verify provides enough information to prioritize 
which verifications the BLM should witness. The BLM would then contact 
the operator to determine exactly when the operator would verify a 
given FMP.
    Proposed Sec.  3175.92(f) would clarify the threshold that triggers 
the requirement to submit amended OGOR and royalty reports to ONRR. 
Under existing Sec.  3175.92(f) amended reports are required if the 
verification error is greater than 2 percent or 2 Mcf/day, whichever is 
greater. The intent of this requirement in the existing regulations is 
not to require amended reports for an error of 2 Mcf/day or less, 
regardless of the error expressed as a percentage of the average flow 
rate. Although the current wording is technically correct, it has 
caused confusion. Therefore, the BLM is proposing to change the wording 
to read ``. . . if the verification error is greater than 2 percent and 
2 Mcf/day. . . .'' As with the current wording, the error would have to 
meet both thresholds in order to trigger the submission of amended 
reports.
3175.93 Integration Statements
    Existing and proposed Sec.  3175.93 contain the documentation 
requirements for integration statements. Proposed Sec.  3175.93(d) 
would require the reference inside diameter of the meter tube to be 
documented on the integration statement. As discussed previously, the 
reference inside diameter is required for proper flow-rate calculation. 
The existing regulations require the inside diameter of the meter tube 
to be documented on site, but it is not clear which specific inside 
diameter is required. As the purpose of requiring the information is to 
verify accurate gas measurement, the BLM is proposing to clarify that 
it is the reference inside diameter of the meter tube that is required.
3175.100 Electronic Gas Measurement (Secondary and Tertiary Devices)
    Existing and proposed Sec.  3175.100 provide an overview of the 
regulatory requirements of EGM systems based on FMP tier. Proposed 
Table 1 to proposed Sec.  3175.100, would change the frequency of 
routine verifications for high- and very-high-volume FMPs to every 6 
months for both tiers. The existing regulation requires routine 
verifications at a 3-month frequency for both tiers. The BLM requires 
routine verifications because all devices, including the transducers 
used in EGM systems, tend to drift, or lose their accuracy over time. 
In a verification, the reading of the transducer is compared to the 
reading of a certified pressure or temperature device. If the reading 
is outside the allowable tolerances defined in existing

[[Page 55983]]

Sec.  3175.102(c)(6), then the transducer must be adjusted, or 
calibrated, to match the reading from the certified pressure device. 
The BLM is proposing to reduce the frequency of verification because it 
has been the BLM's experience, through witnessing the verification of 
EGM systems that transducers rarely drift outside of the allowable 
tolerance. The BLM believes that most transducers in use today are 
stable enough that the verification frequency can be reduced to every 6 
months without adding significant risk to measurement. In addition, the 
BLM believes that the human interaction with the transducers and flow 
computer during a verification can introduce greater error and 
uncertainty than leaving them alone. The BLM seeks comments on this 
proposed change.
3175.101 Installation and Operation of Electronic Gas Measurement 
Systems
    Existing and proposed Sec.  3175.101 define the installation and 
operation requirements of EGM systems. The proposed rule would clarify 
parts of the requirements for the connection of EGM devices and modify 
the on-site information requirements.
    Under Sec.  3175.101(a) of the proposed rule, the BLM would 
establish requirements specific to gauge lines. While the revised 
requirements would not change from those in existing Sec.  3175.101(a), 
the section would be re-organized to separate out requirements that are 
specific to gauge lines and requirements that are specific to manifold 
ports and valves (see proposed Sec.  3175.101(a)(2)). The requirements 
for both gauge lines and manifold ports and valves are combined under 
existing Sec.  3175.101(a), which has caused some confusion, especially 
relating to required minimum diameters. The proposed rule would also 
clarify that the gauge-line requirements are only applicable if gauge 
lines are used. At many EGM system installations, the manifold and 
transducers are placed directly on top of the pressure taps without 
using gauge lines. This reduces costs and may provide better 
measurement than using gauge lines to connect the pressure taps, 
manifold, and transducers. The existing rule resulted in some confusion 
as to what applies when gauge lines are not used.
    Proposed Sec.  3175.101(a)(2) would revise the language in the 
existing regulation to specify that valves, including those in 
manifolds, would have full opening internal diameters of not less than 
\3/8\ inch. See the previous discussion of proposed Sec.  
3175.91(a)(2).
    Proposed new Sec.  3175.101(b)(4) would modify the existing 
requirement that operators display the software version at the FMP 
location. The proposed language would limit that requirement to high- 
and very-high volume FMPs. This would avoid forcing many existing 
locations to update equipment to meet the regulation. The BLM feels 
that the current requirement imposes an undue burden on operators while 
generating little benefit to royalty accountability.
    Proposed new Sec.  3175.101(b)(6) would modify a provision in Sec.  
3175.101(b)(5) of the existing regulation that requires operators to 
either display previous-period averages for differential pressure, 
static pressure, and temperature, or post a QTR on-site that is no more 
than 31 days old. A QTR includes average values of differential 
pressure, static pressure, and temperature for the month. The purpose 
of this requirement is twofold. First, when performing an on-site 
inspection, BLM inspectors need to know the previous period average 
differential pressure, static pressure, and flowing temperature to 
determine if the meter is operating within the volume uncertainty 
limits defined in Sec.  3175.31(a) of both the proposed and existing 
regulations. Second, when witnessing a meter verification, BLM 
inspectors need to know the averages to ensure that operators test the 
differential pressure, static pressure, and temperature transducers at 
those average values. Operators use the results of verifications at 
these average values to determine if they will have to submit amended 
reports as required under Sec.  3175.102(g).
    During implementation of the existing regulations, industry has 
found that many of their flow computers are not capable of displaying 
previous-period averages and that they must post the most recent QTRs 
at these locations. Industry has expressed concerns about the expense 
and logistical difficulties of posting a new QTR every month at every 
location where the flow computer is not capable of displaying the 
average values automatically. For locations that are not inside a meter 
house, the QTR must also be weather resistant which increases the time 
and expense of compliance. The BLM has also heard complaints that 
because the BLM inspects only a small percentage of FMPs every year, 
most of the time the BLM does not use the QTRs posted on site.
    After consideration of these concerns, the BLM is proposing a 
modification to the QTR posting requirement in the existing 
regulations. Instead of requiring operators to post recent QTRs at 
every location that does not have a flow computer capable of displaying 
the required average values, the BLM would require operators to submit 
the most recent QTR when the BLM requests it. The operator could submit 
the QTR through email or fax prior to the BLM going out to inspect the 
facility. The BLM believes this change would not affect its inspections 
because the inspectors would still have access to the average values 
needed for transducer verifications and uncertainty determination.
    Proposed Sec.  3175.101(c)(3) would change ``Elevation of the FMP'' 
to ``Elevation of or atmospheric pressure at the FMP'' in the list of 
data that must be maintained on site for EGM systems. This would allow 
for operators to provide either the FMP elevation or the atmospheric 
pressure at the FMP. The BLM is proposing to allow atmospheric pressure 
to be posted at the FMP instead of meter elevation because either value 
will allow the BLM to verify the flow computer. Atmospheric pressure 
tends to be more readily available to operators and the BLM will be 
able to verify the atmospheric pressure during an inspection. The 
atmospheric pressure can influence the flow-rate calculation in two 
ways. If the meter is using a gauge-pressure transducer, then the flow 
computer must add the value of the atmospheric pressure programmed into 
it to the pressure reading from the transducer to calculate flow rate. 
If the meter is using an absolute pressure transducer, then the 
operator must know the value of atmospheric pressure when the 
transducer is verified or calibrated. In either case, if the wrong 
value of atmospheric pressure is used, the flow-rate calculation will 
be in error. The lower the pressure at the FMP, the more significant 
the error becomes. If the atmospheric pressure is posted on site, then 
the BLM can verify that pressure--at least to some degree--by using GPS 
elevation or the elevation listed on the APD, and cross-reference that 
elevation to the table in Appendix A of the existing rule.
    Proposed Sec.  3175.101(c)(5) would require the reference inside 
diameter of the meter tube to be maintained at the FMP. As discussed 
earlier, the reference inside diameter is required for proper flow-rate 
calculation. The existing regulations require the inside diameter of 
the meter tube to be documented on site, but it is not clear which 
specific inside diameter is required. As the purpose of requiring the 
information is to verify accurate gas measurement, the BLM is proposing 
to clarify that it is the reference inside diameter of the meter tube 
that is required.
    Proposed Sec.  3175.101(c)(12) would clarify the requirement to 
maintain on site the date of the last primary-device

[[Page 55984]]

inspection. The current wording has caused confusion because operators 
are not sure whether they are supposed to post the last orifice-plate 
inspection date or the last meter-tube inspection date, since both of 
these are considered part of the primary device under the definition in 
Sec.  3175.10. The intent of the requirement was to post the last 
orifice-plate inspection date. The proposed rule would clarify that 
this requirement is specific to the orifice plate, or other primary 
device approved by the BLM.
    Proposed Sec.  3175.101(c)(13) would add a requirement that the 
operator post the last meter-tube inspection date. The BLM is proposing 
to add this requirement in order to allow BLM inspectors to verify that 
the operator is inspecting the meter tube at the frequency required 
under proposed Sec.  3175.80(l) and (m). The operator would post either 
the last basic meter-tube inspection date or the last detailed meter-
tube inspection date, whichever is more recent.
3175.102 Verification and Calibration of Electronic Gas Measurement 
Systems
    Existing and proposed Sec.  3175.102 define the verification and 
calibration requirements for EGM systems. The proposed update would 
modify and clarify this section, with a particular focus on the methods 
used to determine atmospheric pressure, verification frequency, 
stability and drift, reporting requirements. The proposed rule would 
also address confusion with respect to notification requirements.
    Proposed Sec.  3175.102(a)(3) would change the required accuracy of 
barometers used in the verification of absolute-pressure transducers 
from 0.05 psi to 0.06 psi (4 
millibars). Under both the proposed and existing regulation, operators 
have the option to use a barometer when verifying the ``zero'' reading 
of absolute-pressure transducers. With this option, the operator would 
first vent the transducer to the atmosphere, take a barometric pressure 
reading from the barometer, and then calibrate the transducer to read 
the same as the barometer. This option in not available for gauge-
pressure transducers. Because this option requires input from a 
barometer, the uncertainty of the barometer will affect the overall 
uncertainty of the measurement. Most barometers that are traceable to 
the National Institute of Standards and Technology have an uncertainty 
of 4 millibars, which is equivalent to about 0.06 psi. Barometers that have lower uncertainties are more 
expensive and more difficult to find. The BLM believes changing the 
uncertainty requirement to 0.06 psi would make compliant 
barometers more accessible without adding significant uncertainty to 
the overall measurement.
    Proposed new Sec.  3175.102(b)(1)(ii) would add a new maximum 
allowable time in days between any two routine EGM system verifications 
by referencing Appendix B. See the discussion of Appendix B later.
    New Sec.  3175.102(b)(1)(iii) would add language to the routine 
verification frequency requirements that would exempt an FMP in non-
flowing status from routine verifications. The new language would 
instead require that the verification be conducted within 15 days after 
the flow resumes. See the previous discussion of Sec.  3175.92(b)(3).
    The BLM is proposing to remove the requirement of existing Sec.  
3175.102(c)(3) that the operator replace any transducer that is found 
to have exceeded its specification for stability or drift on two 
consecutive verifications. Note that the BLM believes the terms 
``stability'' and ``drift'' are synonymous. When existing Sec.  
3175.130 was originally proposed in October 2015, the BLM would have 
required that operators perform a long-term stability test for 
transducers as part of the BLM's transducer approval process. The BLM 
found that the manufacturer's specifications for stability or drift 
were not well defined, not consistently interpreted, and that the 
manufacturers did not reveal their methods for determining this 
specification. The BLM ultimately removed this proposed requirement at 
the final rule stage, due to the cost of performing this test. The BLM 
included Sec.  3175.102(c)(3) in the final (existing) rule as an 
attempt to verify and enforce the manufacturer's specifications for 
stability or drift, in lieu of requiring a test for stability or drift.
    The BLM is proposing to delete this requirement because there is 
currently no practical way for the BLM to determine how much of the 
error determined during a transducer verification is due to stability 
or drift. When an operator verifies a transducer, the only data derived 
from the verification is the difference between the reading from the 
certified test device and the reading from the transducer. The error 
could be due to a number of factors, such as transducer uncertainty, 
ambient temperature effects, static pressure effects (for differential 
pressure transducers), or human errors made during the previous 
calibration. The only way to determine stability or drift from the 
verification is to back out all the other causes, which would require a 
complex series of calculations and a number of assumptions, which 
exceeds the BLM's current capacity.
    Proposed Sec.  3175.101(e)(1)(iii) would require the reference 
inside diameter of the meter tube to be documented. As discussed 
earlier, the reference inside diameter is required for proper flow-rate 
calculation. The existing regulations require the inside diameter of 
the meter tube to be documented on site, but it is not clear which 
specific inside diameter is required. As the purpose of requiring the 
information is to verify accurate gas measurement, the BLM is proposing 
to clarify that it is the reference inside diameter of the meter tube 
that is required.
    Proposed Sec.  3175.102(f)(1) would change the amount of time an 
operator has to notify the BLM prior to performing a verification after 
installation or following a repair. The BLM would change the timeframe 
for notification from a minimum of 72 hours to 1 business day. The 
original 72-hour requirement does not allow for sudden changes in 
scheduling due to unforeseen field conditions. The change to 1 business 
day would allow operators to provide a more accurate notification to 
the BLM.
    Proposed Sec.  3175.102(f)(2) would modify the wording in the 
existing regulation to address industry concerns related to providing 
advance notice to the AO. See the earlier discussion of Sec.  
3175.92(e)(2). Under Sec.  3175.102(f)(2) of the existing and proposed 
rule, operators must notify the AO at least 72 hours before performing 
a verification or submit a monthly or quarterly schedule of 
verifications. The proposed rule clarifies that the verification 
schedule need only identify the FMPs that will be verified during the 
month or quarter, rather than the date of each verification.
    Proposed Sec.  3175.102(g) would clarify the threshold that 
triggers the requirement for operators to submit amended OGOR and 
royalty reports to ONRR. Under Sec.  3175.102(g) of the existing 
regulation, amended reports are required if the verification error is 
greater than 2 percent or 2 Mcf/day, whichever is greater. Proposed 
Sec.  3175.102(g) clarifies the BLM's intent not to require amended 
reports for an error of 2 Mcf/day or less, regardless of the error 
expressed as a percentage of the average flow rate. See the previous 
discussion of Sec.  3175.92(f).
3175.103 Flow Rate, Volume, and Average Value Calculation
    Existing and proposed Sec.  3175.103 provides the minimum 
requirements for performing flow-rate, volume, and average-value 
calculations. The proposed rule would simplify some of

[[Page 55985]]

the language in this section to reduce confusion. Proposed Sec.  
3175.103(b) would require that the atmospheric pressure used to convert 
static pressure expressed in units of pounds per square inch gauge 
(psig) to units of pounds per square inch absolute (psia) must be 
determined using Appendix A of subpart 3175. The existing regulation 
requires the use of API 21.1, Annex B for the psig-to-psia conversion. 
Appendix A of subpart 3175 contains the same information as API 21.1, 
Annex B and does not require using secondary source material. This 
change to the rule would also be consistent with proposed Sec.  
3175.94(b) and other sections of this rule that require the use of 
atmospheric pressure.
3175.104 Logs and Records
    Existing Sec.  3175.104 defines the requirements for records and 
logs. The current regulation was found to be problematic and impose 
requirements that are beyond the capabilities of many flow computers 
currently in operation. The proposed regulation would modify the 
existing regulation to allow for the use of existing equipment while 
preserving accountability requirements.
    Proposed Sec.  3175.104(a)(2) would modify the existing regulation 
by changing the phrase ``decimal places'' with the phrase ``significant 
digits,'' as it relates to QTRs. The existing regulation requires the 
volume, flow time, and integral value or average extension to be 
reported to 5 decimal places and the average differential pressure, 
static pressure, and temperature to be reported to 3 decimal places. 
Industry has expressed concern that 5 decimal places can be impossible 
to achieve when dealing with large numbers. For example, reporting a 
volume of 1224.65219 Mcf of gas (5 decimal places) would exceed the 
number of significant digits stored in the flow computer or the 
measurement data system.
    The BLM acknowledges these concerns and is proposing to require 
volume, flow time, and integral value or average extension to be 
reported to 5 significant digits and the average differential pressure, 
static pressure, and temperature to be reported to 3 significant 
digits. When the existing regulation was proposed in October of 2015, 
it would have required ``significant digits.'' However, the BLM changed 
the language to ``decimal places'' in the final rule based on comments 
stating that reporting to a specified number of significant digits 
would be unworkable. This solution resulted in unintended consequences 
that might require many operators to modify or replace existing gas 
measurement systems. The goal of specifying the number of significant 
digits is to ensure the data provides enough resolution for the BLM to 
perform meaningful recalculations of the volume reported on the QTR. 
Further research into the issue shows that ``significant digits'' 
provides a more workable approach than ``decimal places.'' The BLM is 
seeking comment on this proposed change, and requests data to support 
the use of one term over the other.
3175.112 Sampling Probe and Tubing
    Existing Sec.  3175.112 contains the requirements for sample 
probes, tubing, and components of the sampling system. The proposed 
rule would clarify these requirements, specifically as they relate to 
material of components.
    Proposed Sec.  3175.112(c)(4) retains the prohibition on membranes, 
screens, or filters at any point in the sample probe. The BLM received 
several comments objecting to this prohibition in the current rule, but 
no data has been submitted to support the use of such devices. The BLM 
requests comments and data on this subject.
    Proposed Sec.  3175.112(d) would modify the language in the 
existing regulation to clarify the types of materials that could be 
used in gas sampling-system components. The existing regulation 
requires that sample tubing connecting the sample probe to the sample 
container or analyzer be made out of stainless steel or nylon 11. 
Operators have expressed confusion over whether other components of the 
sampling system, such as valves and nipples, must also be constructed 
of specific materials. The BLM agrees that the wording is not clear for 
components other than the sample tubing and is proposing to clarify 
that the material requirement applies to any component of the sampling 
system into which gas flows during the sample process. The goal of the 
requirement is to prevent alteration of the gas sample due to contact 
with materials such as carbon steel or aluminum. These and other 
materials can react with and contaminate the gas. The new wording of 
this requirement would also clarify that only components that have gas 
flow through or into them must be constructed of stainless steel or 
nylon 11. The requirement to use stainless steel or nylon 11 is based 
on API MPMS 14.1 and GPA 2166-17.
3175.113 Spot Samples--General Requirements
    Existing Sec.  3175.113 establishes the general requirements for 
spot sampling. The proposed rule would improve and clarify these 
requirements, specifically as they relate to non-flowing status, 
sampling notification, cylinder cleaning requirements, and the use of 
portable GC for spot sampling.
    Proposed Sec.  3175.113(a)(1) would modify the wording of existing 
Sec.  3175.113(a) to clarify that the FMP must be flowing when a gas 
sample is taken. The existing regulation implies this, but is not 
clear. The BLM is proposing this change because the current wording of 
the standard makes it difficult for the BLM to enforce this implied 
requirement when witnessing an operator taking a gas sample. A gas 
sample taken from a non-flowing meter is not representative of the gas 
flowing through the meter because a static gas volume can stratify 
based on the different densities of the components in the gas and the 
composition and heating value determined from a stratified gas volume 
will depend on where in the stratified column the sample was taken.
    Proposed Sec.  3175.113(a)(2) would modify the wording of existing 
Sec.  3175.113(a) to clarify what is meant by a ``non-flowing status'' 
at the time of sampling. This change is proposed in response to some 
operators interpreting the existing requirement to mean that any time 
an FMP is shut in, they had to take a sample within 15 days. For 
plunger lift and other intermittent-flowing FMPs, this would be 
unworkable.
    The existing requirement was intended to apply to FMPs that were 
shut in seasonally or for long periods, not to intermittently flowing 
FMPs. For example, a low-volume FMP requires a sample every 6 months, 
not to exceed 195 days between the samples. If an operator takes a gas 
sample at a low-volume FMP on February 1, 2019, the next sample would 
be due no later than August 15, 2019. If the operator shut its wells in 
from June 1 to September 1, it would not be able to take the next 
sample by August 15, 2019, as required, because the well would not be 
flowing and proposed Sec.  3175.113(a)(1) requires FMPs to be flowing 
when a sample is taken. The intent of proposed Sec.  3175.113(a)(2) is 
to clarify that if the FMP is in non-flowing status when the sample is 
due, the operator has 15 days from the day flow is re-initiated to take 
a sample. In the earlier example, assuming the wells flowing through 
the FMP were brought back on line on September 1, 2019, the operator 
would have until September 15, 2019, to take a sample.
    Under existing Sec.  3175.113(b), operators must notify the AO at 
least 72 hours before taking a sample or submit

[[Page 55986]]

a monthly or quarterly schedule of spot samples. Industry has expressed 
concern regarding the logistics of scheduling gas samples, which can be 
difficult even 72 hours in advance. The purpose of this requirement is 
to give the BLM some idea of when gas samples are taken in order for 
the BLM to be able to witness the sampling. After considering industry 
concerns, the BLM is proposing to modify this requirement to allow 
operators to submit a list of FMPs that the operator plans to sample 
over the next month or next quarter. The operator would no longer have 
to notify the BLM or submit a schedule of when each FMP would be 
sampled. The BLM believes the list of wells an operator intends to 
sample would provide enough information to prioritize which gas 
samplings the BLM should witness. The BLM would then contact the 
operator to find out when the operator expects to sample a given FMP.
    Proposed Sec.  3175.113(c)(3) would modify the language in existing 
Sec.  3175.113(c)(3) by updating the GPA reference from GPA 2166-05 to 
GPA 2166-17. Under proposed Sec.  3175.30, the BLM would incorporate 
GPA 2166-17, which is the latest published version of the standard.
    Proposed Sec.  3175.113(c)(3) would also allow operators to seek 
approval from the PMT for alternative methods of cleaning sample 
cylinders. The BLM is aware of several alternative sample-cylinder 
cleaning methods. The PMT would analyze laboratory test data that 
compares the effectiveness of the alternative method with the 
effectiveness of the method in Appendix A of GPA 2166-17. If the 
alternative method produces similar or better results, the PMT would 
recommend that the BLM approve the method, with conditions of approval, 
if necessary, and add it to the list of approved equipment and 
procedures on the BLM's website. Once approved, the alternative method 
would be available to all operators on Federal or Indian leases without 
any further review or approval required.
    Proposed Sec.  3175.113(d)(1) would prohibit the use of sampling 
separators while spot sampling with portable gas chromatographs. 
Sampling separators can cause condensation or vaporization of the 
heavier hydrocarbons in the gas stream due to temperature differences 
caused by the separator. The seventh edition of API MPMS Chapter 14, 
section 1 does not recommend using sampling separators due to the 
potential the separator may cause heat transfer. GPA Standard 2166-05 
also cautions against the use of sampling separators, stating that 
research has shown the misuse of separators can cause sample 
distortion, and that a separator is only useful for streams containing 
unwanted hydrocarbon droplets, amine, glycol, water, or other 
contaminants. GPA Standard 2166-05 also states that for clean, dry 
sample streams above the hydrocarbon dew point, the separator serves no 
useful purpose and could corrupt the sample. The BLM believes sampling 
separators create the risk that operators using this equipment will 
collect unrepresentative samples; the BLM is therefore proposing to 
prohibit their use in portable gas chromatograph sampling.
    Under the proposed rule, the BLM would remove Sec.  3175.113(d)(5) 
and (d)(6) of the existing regulations and replace them with different 
requirements (Sec.  3175.113(d)(5) through (d)(8)). These sections of 
the existing regulations require operators using portable gas 
chromatographs to run at least three analyses when sampling a low- or 
very-low-volume FMP and, for high- and very-high-volume FMPs, continue 
to take samples until the difference between three consecutive samples 
is 16 British thermal units per standard cubic foot (Btu/scf) or less 
for high-volume FMPs and 8 Btu/scf or less for very-high volume FMPs. 
The intent of these requirements was to provide the BLM with some 
objective quality assurance that the portable GC and associated 
sampling system are working properly. Operators have expressed concern 
that this requirement not only increases their documentation burdens, 
but can also be difficult, if not impossible, to achieve. Because 
existing Sec.  3175.113(d)(6) requires the heating value reported on 
the OGOR Part B to be the mean or median of the three heating values 
obtained under this section, operators would have to maintain a record 
of all three analyses that were performed.
    Current practice is for operators to maintain only documentation of 
the analysis they use for reporting royalty. This requirement has 
therefore resulted in a significant increase in the amount of 
documentation required. Also, a portable GC samples a live gas stream, 
unlike a laboratory GC that is sampling from an isolated volume 
contained in a sample cylinder. The composition of the live gas stream 
is constantly changing, which can make it difficult to obtain three 
consecutive samples that are within the tolerances required under 
existing Sec.  3175.113(d)(5). Many operators stated that these 
requirements were so onerous that they went away from the use of GCs 
and opted for other spot sampling methods, like the purge and fill 
method. In 2018, an industry group developed a standard operating 
procedure (SOP) that contained a number of objective measures to help 
ensure quality control when using a portable GC. The BLM recommended 
the use of this SOP in Washington Office Instruction Memorandum (IM) 
2018-069. Proposed Sec. Sec.  3175.113(d)(5) through 3175.113(d)(8) 
would incorporate many of the recommendations that were included in the 
SOP. The BLM believes that the objectives of existing Sec.  3175(d)(5) 
and (d)(6) can be met using the methods in proposed Sec.  3175(d)(5) 
through (d)(8).
    Proposed Sec.  3175.113(d)(5) would require the regulator for the 
GC to be heated or insulated to maintain the temperature of the sampled 
gas to at least 30 [deg]F above the hydrocarbon dew point. The 
hydrocarbon dew point is the temperature below which the heavier 
hydrocarbons in the gas begin to condense into a liquid phase. 
Capturing a representative sample of the gas flowing through the FMP 
requires the gas temperature to be maintained above the hydrocarbon dew 
point so that none of the gas components drop out of the gas stream 
prior to entering the GC. For most parts of the sampling system, the 
requirement in existing Sec.  3175.111(b) for maintaining the 
temperature of all of the sampling components to at least the 
hydrocarbon dew point is sufficient to prevent condensation. However, 
this requirement is not sufficient with pressure regulators because the 
drop in pressure through the regulator causes gas to expand, and the 
expanding gas causes additional cooling (known as the Joule-Thompson 
effect).
    Proposed Sec.  3175.113(d)(5) is similar to existing Sec.  
3175.112(c)(2), which requires external regulators that are part of the 
sample probe to be heated to 30 [deg]F above the hydrocarbon dew point. 
The proposed requirement would be specific to regulators that are part 
of a GC sampling system, but not part of the sampling probe. The 
rationale for existing Sec.  3175.112(c)(2) is the same as the 
rationale for this proposed requirement.
    Proposed Sec.  3175.113(d)(6) would require that gas chromatograph 
pressure regulators be set to the same pressure setting as the pressure 
at which the portable GC was calibrated or verified. Gas chromatographs 
work by injecting the gas sample through several columns, which 
segregate the individual components of the natural gas. A detector then 
measures the amount of each component as it exits the GC. The pressure 
of the gas coming into the GC can influence the rate at which it flows 
through the columns and the detector. This change in rate can alter the 
results from the GC. In order to ensure

[[Page 55987]]

accuracy, the gas pressure applied to the GC during field testing must 
match the gas pressure at which the GC is calibrated or verified.
    Proposed Sec.  3175.113(d)(7) would prohibit the first GC analysis 
at an FMP from being used to determine the heating value. The first run 
of gas through the GC may contain contaminates from previous samples 
and may not be representative of the gas flowing through the FMP. The 
first run should be used to purge the entire line and system with gas 
from the FMP being sampled.
    Proposed Sec.  3175.113(d)(8) would require that the sample line be 
purged and vented for a minimum of 2 minutes before sampling at each 
location. The BLM proposes this to maintain purity of the sample taken 
from the sample location, and to reduce any chance of contaminants from 
prior samples being mixed in with the current sample.
3175.114 Spot Samples--Allowable Methods
    Existing Sec.  3175.114 defines the allowable methods for spot 
sampling. The proposed rule would update the references to industry 
standard to make them current. Proposed Sec.  3175.114(a) would update 
the GPA reference in paragraphs (a)(1), (a)(2), and (a)(3) to the 
latest published version (GPA 2166-17) that is incorporated by 
reference in Sec.  3175.30. The BLM is not aware of any substantive 
changes between the version incorporated by reference in the existing 
rule (GPA 2166-05) and GPA 2166-17, as it relates to the three 
references discussed here.
3175.115 Spot Samples--Frequency
    Existing Sec.  3175.115 details the frequency requirements for spot 
sampling based on the FMP tier of the meter being sampled. The proposed 
rule would make compliance with these requirements more achievable for 
operators, while preserving the BLM's need for heating value 
determination.
    The industry has expressed concerns over the requirements in 
existing Sec.  3175.115(b). To address some of those concerns the BLM 
is proposing to modify the scope of the requirement to reduce the 
number of overall meters that will be affected. This paragraph allows 
the BLM to change the sampling frequency on high- and very-high-volume 
FMPs to achieve a set level of average annual heating value uncertainty 
as described in existing Sec.  3175.31(b), after the FMP has been in 
operation for 2 years. The primary concern expressed by industry was 
about the expense of taking samples every 2 weeks and installing 
composite samplers or on-line GCs at very-high-volume FMPs, as required 
in the existing regulation. Industry also stated that many of their 
FMPs have highly variable heating values, which put them at risk of 
having to conduct 2-week sampling and installing the required composite 
sampling systems or on-line GCs. Industry argued that heating value 
uncertainty is a function of the quality of sampling and analysis and 
is not the same as the variability in heating value from sample to 
sample.
    While the BLM is not proposing any changes to this section 
specifically, it is proposing changes to other sections that the BLM 
believes would alleviate much of the industry's concern. First, the BLM 
would increase the average annual heating value uncertainty from + or -
1 percent to + or -2 percent for very-high-volume FMPs and from + or -2 
percent to + or -3 percent for high-volume FMPs (see earlier discussion 
of Sec.  3175.31(b)(1) and (b)(2), respectively). The BLM would also 
eliminate the requirement to install composite samplers or on-line GCs 
at very-high-volume FMPs (see discussion of Sec.  3175.115(b)(5) 
earlier). The BLM believes these two changes would significantly reduce 
the potential costs imposed by this section.
    The BLM does not agree with industry's assertion that average 
annual heating value uncertainty is an inappropriate method of 
addressing spot sampling frequency and heating value variability from 
sample to sample. For more information, please see the preamble 
discussion of average annual heating value uncertainty in the proposed 
and final rule documents for existing subpart 3175 (80 FR 61675 and 81 
FR 81583).
    The BLM would delete existing Sec.  3175.115(b)(5), which requires 
operators to install composite samplers or on-line GCs at very-high-
volume FMPs when the BLM determines that the required level of average 
annual heating value uncertainty at an FMP cannot be achieved through 
spot sampling. The BLM is proposing to delete this requirement because 
it believes that the proposed increase in average annual heating value 
uncertainty would render this requirement largely unnecessary. 
Typically, the FMPs that are subject to the largest variability in 
heating value from sample to sample are lower-volume FMPs that are 
associated with plunger-lift operations. Very-high-volume FMPs tend to 
measure gas produced from newly drilled wells that do not need plunger 
lifts and have less heating value variability. In response to comments 
on the proposed rule for the existing regulations (see preamble 
discussion at 81 FR 81585), the BLM concluded that roughly 25 percent 
of the estimated 900 very-high-volume FMPs nationwide would not be able 
to meet the 1 percent performance requirement for average 
annual heating value uncertainty in Sec.  3175.31 through spot 
sampling. These FMPs under the existing regulation require the 
installation of an on-line GC or composite sampling system. The 25 
percent figure is based on a required average annual heating value 
uncertainty of 1 percent. By increasing the uncertainty 
from 1 percent to 2 percent, as proposed in 
Sec.  3175.31(b)(2), the BLM estimates the number of very-high-volume 
FMPs that would require a composite sampler or on-line GC would drop by 
a factor of 4. This would reduce the number of very-high-volume FMPs 
requiring a composite sampling system or an on-line GC from 25 percent 
to roughly 6 percent. The BLM does not believe it is necessary to 
include a requirement that would only apply to such a small number of 
FMPs.
    Proposed Sec.  3175.115(c) would move the existing Table 1 to Sec.  
3175.115 (Maximum Time Between Samples) to Appendix B of this subpart, 
and would refer the readers to Appendix B for this information. See the 
discussion of Appendix B, later.
    Proposed Sec.  3175.115(d) would increase the amount of time 
operators would have to install a composite sampling system or on-line 
GC from 30 days after the due date of the next sample to 90 days after 
the due date of the next sample. This proposed change is based on 
industry concerns that the lead-time operators need to plan for, order, 
and install on-line GCs or composite sampling systems is commonly 
greater than 30 days. During this 90-day period an operator would not 
have to take spot samples. While this will reduce heating value 
accountability during that period, the BLM believes that the potential 
benefits of an operator installing an on-line GC or composite sampling 
system, providing a more representative sample over the sampling 
period, outweigh the temporary loss of spot samples during the 90-day 
period.
3175.116 Composite Sampling Methods
    Existing Sec.  3175.116 defines the requirements for composite 
sampling. The existing regulation contains limited guidance on the use 
of this method. The proposed rule would provide clarity for operators 
and inspectors on this sampling method. The BLM is proposing several 
additional

[[Page 55988]]

requirements for composite sampling systems as discussed later. 
However, the BLM is not aware of any industry standards for composite 
samplers other than API MPMS 14.1.12.1. As a result, the BLM is 
soliciting information from the public regarding best practices for the 
design, installation and use of composite samplers.
    Proposed Sec.  3175.116(c) would add a requirement that sample 
cylinders used in composite sampling systems comply with the general 
spot-sample requirements under Sec.  3175.113(c). The existing 
regulation requires that sample cylinders be sized to ensure that the 
capacity is not exceeded within the normal collection frequency; 
however, it does not impose any additional requirements such as those 
for cylinders used in spot sampling. There are no requirements for the 
materials that are used to construct and clean the cylinders. The BLM 
believes that the omission of these requirements for composite sample 
systems was an oversight and will not add any additional burdens to 
industry, as they represent common industry best practice despite not 
being specifically stated in the referenced standard, API MPMS 
14.1.12.1.
    Proposed Sec.  3175.116(d) would add a new requirement that all 
components of the sampling system be heated to at least 30 [deg]F over 
the hydrocarbon dew point at all times. The BLM would add this 
requirement to prevent condensation and compensate for the effects of 
cooling under the Joule-Thompson effect as pressure is reduced when the 
gas runs through valves and fittings.
3175.117 On-Line Gas Chromatographs
    Proposed Sec.  3175.117(a) would update the reference to GPA 2166-
05, Appendix D, in the existing regulation, with GPA 2166-17, Appendix 
D, in the proposed rule. The BLM is not aware of any change in Appendix 
D from the previous version to the newest version. The BLM also 
requests comment and information from the public regarding industry 
standards or best practices for the selection, installation, and 
operation of on-line GCs.
3175.118 Gas Chromatograph Requirements
    Existing Sec.  3175.118 contains requirements for gas 
chromatographs. The proposed rule would update the references to 
industry standards to the most current editions and address the 
requirements for gas analysis more clearly, specifically addressing the 
confusion between the terms ``extended analysis'' and ``nonanes+''.
    Proposed Sec.  3175.118(c)(2) would update the referenced industry 
standard from GPA 2198-03 in the existing rule, to GPA 2198-16 in the 
proposed rule in order to stay up-to-date with the latest standards for 
verification and calibration gas standards. There are two changes in 
the updated GPA standard. First, GPA 2198-16 requires that the 
concentration of the gas used for verification and calibration be 
closer to the expected concentration of the gas sampled in the field 
than what was required under GPA 2198-03. While the older standard 
requires the concentration of each component to be no less than one-
half the concentration expected in the field, it did not place an upper 
limit for the concentration. The GPA 2198-16 standard places an upper 
limit of no more than double the expected concentration of the gas 
sampled in the field. For example, if the expected concentration of 
propane in the field sample were 4 mole percent, the concentration of 
propane in the calibration gas could be no less than 2 mole percent and 
no more than 8 mole percent, according the GPA 2198 standard. In 
addition, the GPA 2198-16 standard includes steps for the operator to 
take if the calibration gas has dropped below its hydrocarbon dew point 
and recommends heating the standard to 30 [deg]F above the hydrocarbon 
dew point for 4 hours before use. The older standard recommends that 
the calibration gas should be heated to 20 [deg]F above hydrocarbon dew 
point for 12 hours before use. The BLM does not believe either of these 
changes would place significant burdens on the operator.
    The proposed updated reference to GPA 2198-16 would also apply to 
proposed Sec.  3175.118(c)(3) and Sec.  3175.118(c)(4), which refer to 
GPA 2198-16, Section 6 and Section 5, respectively. The existing 
regulation references GPA 2198-03, Section 5 and Section 6. The only 
difference between these sections is the inclusion of reference 
standards for natural gas liquids. Because subpart 3175 only addresses 
natural gas, the inclusion of standards for natural gas liquids is not 
relevant to this rule.
    Under existing Sec.  3175.118(e) operators are required to perform 
extended analyses in accordance with GPA 2286-14. This proposed rule 
would remove this requirement. Existing Sec.  3175.119(b) requires 
operators to determine the concentrations of hexanes, heptanes, 
octanes, and nonanes+, if the mole percent of hexanes+ exceeds 0.5 mole 
percent. In the development of the existing subpart 3175, the BLM 
accepted comments on the proposed rule that suggested the BLM 
incorporate GPA 2286-14, because it would set standards for analyzing 
hexanes, heptanes, octanes, and nonanes+. The BLM agreed with this 
comment and added existing Sec.  3175.118(e) as a result. Also based on 
these comments, the BLM assumed that the term ``extended analysis'' was 
synonymous with the term ``C9+'' or ``nonanes plus'' 
analysis. Since publication of the existing rule in November 2016, the 
BLM has determined that the term ``extended analysis'' has a different 
meaning than a C9+ analysis and the incorporation of GPA 
2286-14 is inappropriate for the BLM's intended purpose. The 
incorporated GPA 2286-14 standard requires a third column that 
separates hydrocarbons up through C14. This is not needed in 
normal field conditions, because hydrocarbons above C9, or 
nonane, rarely exist in sufficient quantities to affect the heating 
value of the gas due to the high hydrocarbon dew point of larger 
hydrocarbon molecules. To reduce unnecessary burden on industry while 
still meeting the desired intent of a more detailed analysis, the BLM 
proposes to only require C9+ analysis. The new 
C9+ analysis is discussed in the proposed regulation within 
the definition of nonanes+ at Sec.  3175.10 and at Sec.  3175.119. The 
requirement to use GPA 2286-14 represents an unnecessary burden to 
industry. Under the proposed rule, the BLM would delete the reference 
to extended analysis and remove the incorporation by reference for GPA 
2286-14.
3175.119 Components To Analyze
    Existing Sec.  3175.119 defines the minimum requirements for 
component detail in gas analysis. The proposed modification to the 
language would alter those requirements based on detailed testing data 
that the BLM has received from Anadarko Petroleum showing when the 
greatest risk to royalty exists. All graphs shown in this section were 
provided by Anadarko.
    Proposed Sec.  3175.119(a)(7) would add flexibility to the 
requirement that gas must be analyzed for either C6+ or 
C9+. The existing regulation requires C6+ to be 
analyzed when the concentration of C6+ is 0.5 mole percent 
or less. Several operators have pointed out that this provision would 
prevent an operator from voluntarily performing a C9+ 
analysis when the concentration of C6+ was 0.5 mole percent 
or less. This was not the intent of the requirement because a 
C9+ analysis would exceed the minimum standard of 
C6+ and

[[Page 55989]]

would be acceptable to the BLM. As a result, the BLM proposes to change 
this requirement to clarify that a C9+ would also fulfill 
this requirement. However, the BLM would also clarify that if an 
operator voluntarily performs a C9+ analysis, they must 
include the individual concentrations of hexanes, heptanes, and octanes 
in the analysis.
    Proposed Sec.  3175.119(b) would require a C9+ analysis 
when the C6+ analysis exceeds 1 mole percent. The existing 
regulation requires a C9+ analysis when the C6+ 
analysis exceeds 0.5 mole percent. The BLM is proposing this change 
based on data provided by an operator who collected 2,466 gas samples 
and ran both a C6+ and C9+ on each sample. The 
following graph shows the difference in heating value between the 
C6+ analysis and the C9+ analysis for each sample 
as a function of the mole percent of C6+. Note that a 
negative difference indicates that the C6+ analysis yielded 
a lower heating value than the C9+ analysis.
[GRAPHIC] [TIFF OMITTED] TP10SE20.001

    To analyze this data, the BLM created three frequency plots; the 
first plot (Plot 1) includes only the samples where the mole percent of 
C6+ was between 0 and 0.5 mole percent, the second plot 
(Plot 2) includes only those samples where the mole percent of 
C6+ was between 0.5 mole percent and one mole percent, and 
the third plot (Plot 3) includes only those samples where the 
C6+ was 1 mole percent or greater. Each plot consists of 
``buckets,'' where each bucket contains samples where the Btu 
difference using a C6+ analysis and a C9+ 
analysis is shown on the X-axis. The Y-axis shows how many samples fall 
into each bucket. For example, in Plot 1, 919 of the samples showed 
that there was no difference in heating value between using a 
C6+ analysis and a C9+ analysis and 671 of the 
samples showed that the C6+ analysis resulted in a heating 
value one Btu/scf less than the C9+ analysis.
[GRAPHIC] [TIFF OMITTED] TP10SE20.002


[[Page 55990]]


[GRAPHIC] [TIFF OMITTED] TP10SE20.003

    The following table summarizes the results from the three plots:

----------------------------------------------------------------------------------------------------------------
                                                                        Concentration of C6+ (mole percent)
                                                                 -----------------------------------------------
                                                                                   0.5-1.0 (plot
                                                                   <0.5 (plot 1)        2)         >1.0 (plot 3)
----------------------------------------------------------------------------------------------------------------
Total samples...................................................           1,647             724              95
Average difference (Btu/scf)....................................           -0.43           -0.87           -2.66
Median difference (Btu/scf).....................................               0              -1              -2
Maximum heating value difference................................              -4              -6             -14
----------------------------------------------------------------------------------------------------------------

    From the three plots and summary table, the BLM believes there is a 
clear bias of under-reporting of heating value that increases as the 
mole percent of C6+ increases, when a C6+ 
analysis is used by an operator instead of a C9+ analysis. 
The absence of statistically significant bias is one of the performance 
goals of Sec.  3175.31(c)
    However, both the average and median difference between the heating 
values in a C6+ analysis and C9+ analysis are 1 
Btu/scf or less for C6+ concentrations of 1 mole percent or 
less (see Plots 1 and 2), which could be due to round-off error or 
otherwise considered as insignificant. The results from Plot 3 show an 
average difference

[[Page 55991]]

between a C6+ analysis and a C9+ analysis of 2.66 
Btu/scf, a median difference of -2 Btu/scf, and a maximum difference of 
14 Btu/scf. This analysis suggests that a C9+ analysis 
should be required when the concentration of C6+ exceeds 1 
mole percent. To confirm this conclusion, the BLM also did an economic 
analysis.
    In the development of the existing regulation, the BLM used a cost 
versus royalty-risk approach when determining thresholds. With this 
analysis, the threshold is set where the cost to an operator of 
implementing a requirement equals the amount of potential lost royalty 
if the higher standard is not met. For this analysis, the BLM made the 
following assumptions based on BLM field experience:

 Cost of C6+ analysis: $100
 Cost of C9+ analysis: $300
 Gas price: $3/MMBtu, $4/MMBtu
 Sample frequency: 360 days for high-volume FMPs and 180 days 
for very-high-volume FMPs
 Royalty rate: 12.5 percent

    The BLM then determined the mole percent of C6+ that 
resulted in $200 of lost royalty over the sampling period if a 
C9+ analysis was not conducted. Two hundred dollars is the 
assumed difference in cost between a C6+ analysis and a 
C9+ analysis. Note that the sampling frequencies assume the 
operator is following the alternative C9+ sampling schedule 
allowed in Sec.  3175.119(c). The following figure shows the break-even 
point for C9+ analysis as a function of average flow rate 
through the FMP. For example, for an FMP with an average flow rate of 
2,000 Mcf/day and an assumed gas price of $4/MMBtu, a C6+ 
mole percent threshold of 0.85 mole percent would be the break-even 
point. If the gas price were $3/MMBtu and an average FMP flow rate of 
2,000 Mcf/day, a C6+ mole percent of very close to 1 mole 
percent would be the break-even point.
[GRAPHIC] [TIFF OMITTED] TP10SE20.004

    Based on this analysis, the BLM believes that a threshold of 1 mole 
percent C6+ would exceed the break-even point, where the 
cost of performing a C9+ equals the potential for lost 
royalty if only a C6+ analysis was conducted. Therefore, the 
BLM concludes that this threshold would reduce burden to industry, as 
compared to the 0.5 mole percent threshold in the existing rule, while 
still providing the public and Indian tribes and allottees with a fair 
return. The BLM requests comment on these data and the changes proposed 
based on the BLM's review of the data.
3175.120 Gas Analysis Report Requirements
    Proposed Sec.  3175.120(a)(6) would insert the phrase ``if 
applicable'' to the requirement that the gas analysis report include 
the name of the laboratory where the analysis was performed. The BLM is 
proposing this change because gas analysis reports from portable GCs 
are not run in a laboratory; therefore, this requirement would not be 
applicable to them.
    Proposed Sec.  3175.120(a)(18) would remove the requirement that 
the gas analysis report must show the un-normalized mole percent for 
each component analyzed and instead only require the sum of the un-
normalized mole percents from all analyzed components. The un-
normalized mole percents represent the raw output of the GC and rarely 
add up to exactly 100 percent, due to uncertainties inherent to the GC. 
As a quality control measure, both the existing and proposed 
regulations require the total un-normalized percent to be within 97 
percent to 103 percent. A total un-normalized mole percent outside of 
this range could indicate problems with a GC, such as a leak, a bad 
column, or that the GC is out of calibration. The BLM is proposing to 
remove the requirement for gas analysis reports to include the un-
normalized mole percent of each component because the BLM does not use 
this information and collecting it is an unnecessary burden on 
operators.
    Proposed Sec.  3175.120(d) would clarify the reference for AGA 
Report No. 8 by specifying the parts containing the calculation method 
for base supercompressibility. This creates no additional burden or 
change from the current regulation. Proposed Sec.  3175.120(f) would 
remove the double reference to the ability to request a variance to 
remove the GARVS requirement. This change is made to clarify the 
language.
3175.125 Calculation of Heating Value and Volume
    Existing Sec.  3175.125 defines the minimum requirements for the 
calculation of heating value and volume. The proposed rule would 
clarify the requirement for averaging the heating value between two 
royalty measurement points. Under proposed Sec.  3175.125(b)(1), the 
existing requirement for calculating and reporting an average heating 
value

[[Page 55992]]

would only apply if a lease, unit PA, or CA has more than one FMP that 
doesn't yet have an FMP number. Once the BLM assigns FMP numbers, each 
FMP will report as individual line items on the OGOR, negating the need 
to average heating values when there are multiple FMPs. Under the 
existing regulation, if there is more than one FMP the average heating 
value is required in all circumstances. The BLM proposes this change to 
reduce unnecessary reporting burdens on industry by removing the 
requirement to report the average heating value for a lease, unit PA, 
or CA once the BLM assigns individual FMP numbers.
3175.126 Reporting of Heating Value and Volume
    Existing Sec.  3175.126 contains the reporting requirements for 
heating value and volume. The proposed rule would modify this language 
to clarify those requirements and expand on the requirements for 
devices used to measure water vapor. Under existing Sec.  
3175.126(a)(1), the reported heating value must be ``dry,'' unless the 
water vapor content is determined through actual measurement and 
reported on the gas-analysis report. However, the existing regulation 
does not explicitly state that the water vapor content must be included 
in the heating-value calculation. The proposed rule would insert the 
requirement for the measured water vapor content to be included in the 
heating value calculations. While not a change from existing 
requirements, the additional language would reduce operator confusion 
over the requirements of heating-value determination and reporting when 
water-vapor content has been measured.
    Existing Sec.  3175.126(a)(1)(i) lists chilled mirrors as an 
approved method of measuring water vapor. Under the proposed rule, the 
BLM would have to approve chilled mirrors by make and model and would 
place them on the list of approved equipment and methods at 
www.blm.gov. The BLM is proposing to add this requirement because there 
are numerous models of chilled mirrors on the market and the BLM has no 
assurance of how accurate these devices are or what operating 
limitations may apply to them. This requirement would specifically 
apply to manually operated chilled mirrors. Under proposed Sec.  
3175.126(a)(1)(ii), the BLM would apply the same requirements to 
automated chilled mirrors, for the same reasons.
    Existing Sec.  3175.126(a)(1)(ii) lists laser detectors as an 
approved method of measuring water vapor. Under the proposed rule, 
laser detectors would no longer be an approved method, but operators 
could submit individual laser detector makes and models to the BLM for 
review and approval under revised Sec.  3175.126(a)(1)(iii). The BLM is 
proposing this change based on concerns that these devices may have 
certain operating limits that the PMT should review (see the discussion 
of Sec.  3175.40(h) earlier).
    Proposed Sec.  3175.126(a)(1)(iii) would clarify that only those 
devices that are placed on the BLM's list of approved equipment can be 
used in the measurement of water vapor. The existing regulation only 
states that other devices would have to be approved by the BLM.
    Proposed Sec.  3175.126(a)(3) would change ``hexane+'' to ``hexane-
plus'' for consistent wording with the rest of the regulation. Under 
existing Sec.  3175.126(a)(3)(i), the BLM defines the required 
composition of hexanes-plus (60 percent hexanes, 30 percent heptanes, 
and 10 percent octanes). Under the proposed rule, the BLM would define 
the minimum heating value of hexanes-plus as 5,129 Btu/scf, which is 
equivalent to the heating value of the C6+ composition 
required in the existing rule. This change would allow flexibility for 
operators who may have contracts that specify a different composition 
for C6+. Under the proposed rule, the operator could use 
whatever assumed composition of C6+ they want to use, as 
long as the equivalent heating value of that composition is at least 
5,129 Btu/scf.
    The BLM also proposes that in lieu of using the minimum heating 
value for hexanes-plus required in proposed Sec.  3175.126(a)(3)(i), an 
operator may use the actual heating value of hexanes, heptanes, and 
octanes from the C9+ composition as determined under Sec.  
3175.119(c). Because these would be measured values of C6+, 
they would represent a more accurate heating value of the gas than an 
assumption of heating value under Sec.  3175.126(a)(3)(i). It would 
also allow the voluntary use of C9+ composition analysis for 
increased measurement accuracy on FMPs that have 1 mole percent or less 
of C6+.
    The BLM proposes to add a new paragraph Sec.  3175.126(a)(4) to 
define the minimum heating value of C9+. Under the existing 
regulation, no minimum heating value or specific composition is defined 
for C9+. Under the proposed rule, the BLM would define the 
minimum heating value of C9+ as 6,996 Btu/scf to remove any 
confusion on the acceptable heating value of C9+. Defining a 
minimum heating value instead of a specific composition would give 
operators flexibility in the composition they choose, as long as that 
composition has a heating value of at least 6,996 Btu/scf.
3175.130 GSAMP Requirements
    In addition to adding a definition for gas-storage agreement 
measurement points (GSAMP) in Sec.  3175.10, the BLM would also include 
requirements for these meters in proposed Sec.  3175.130.
    Paragraph 3175.130(a) would re-define the flow categories 
specifically for GSAMPs.
    Of the 35 gas-storage agreements currently in effect on Federal 
land, 28 of them pay the BLM a fee that is based on the volume of gas 
either injected into or withdrawn from the gas-storage reservoir. The 
withdrawal fee tends to be substantially higher than the injection fee, 
so this analysis is based only on the withdrawal fees, which are shown 
in the following figure. Each marker on the graph represents a GSA, 
with the round markers representing GSAs that are operating under a re-
negotiated contract as of September 6, 2018, and the triangle markers 
represent GSAs that are operating (or have operated and are now 
terminated) under the original contract fees. Gas storage agreements 
where the withdrawal fee is not based on the volume withdrawn are not 
shown on the graph.
    The BLM believes that GSAs with re-negotiated contracts represent a 
better and more up-to-date representation of withdrawal fees. Also, 
because most fees are subject to re-negotiation based on inflation, the 
higher fees are more representative of future prices than are the lower 
fees. Based on these assumptions, the BLM believes that a fair average 
value for withdrawal fees is $0.020/Mcf.
    To compare withdrawal fees to royalty value, the withdrawal fee 
must be converted to an MMBtu basis. Because withdrawn gas typically 
has a heating value of around 1 MMBtu/Mcf, the heating value equivalent 
price is the same as the price per Mcf, or $0.020/MMBtu. Dividing the 
typical royalty value of gas ($0.474/MMBtu) by $0.020/MMBtu yields a 
ratio of 23.7. In other words, on an economic basis, an MMBtu of gas 
produced from a lease well is worth at least 23.7 times as much as an 
MMBtu of gas injected into or withdrawn from a gas-storage agreement. 
Therefore, the BLM concludes that an equivalent threshold between low- 
and very-low-volume meters for GSAMPs would be 23.7 times greater than 
35 Mcf/day, which is 830 Mcf/day. The BLM would round this value to 800 
Mcf/day as the new threshold between low- and very-low-volume GSAMPs. 
The equivalent

[[Page 55993]]

threshold between a low- and high-volume FMP would be 4,700 Mcf/day 
using the same methodology. The following graph collects data from GSA 
reports from the BLM's system of Federal land records (LR2000) as of 
November 14, 2007, and with updated fee information as of September 6, 
2018; the information was compiled and placed in the graph by BLM 
petroleum engineer Rich Estabrook (retired).
[GRAPHIC] [TIFF OMITTED] TP10SE20.005

    Proposed Sec.  3175.130(b) would exempt GSAMPs from the gas-
sampling, analysis, and heating-value reporting requirements of Sec.  
3175.80(p), Sec.  3175.110, Sec.  3175.120, Sec.  3175.121, Sec.  
3175.125(a) and (b), and Sec.  3175.126. The purpose of taking and 
analyzing gas samples at an FMP is to determine three parameters: 
Heating value, which is a direct multiplier in the determination of 
royalty; relative density, which affects the volume calculation to some 
degree; and gas composition, which is used to determine compressibility 
and also affects the volume calculation, although to a much lesser 
degree. Most gas-storage sites are depleted oil and gas reservoirs with 
little to no recoverable oil or gas left in them. The gas that is 
stored in these reservoirs is typically transmission-quality gas that 
consists primarily of methane. Because the composition of the gas that 
is injected into or withdrawn from a gas-storage reservoir stays fairly 
constant over the life of the operation, the heating value and relative 
density also remain fairly constant. In addition, injection and 
withdrawal fees are only based on volume; therefore, heating value is 
not used in the calculation of fees. The slight changes in relative 
density and compressibility would have little impact on the volume 
calculation. The BLM does not believe that gas sampling, analysis, and 
reporting on the withdrawn gas has any public benefit in these cases.
    There are some gas-storage reservoirs where the gas withdrawn from 
the reservoir has a higher heating value than the gas injected into the 
reservoir. The enrichment of the gas is due to the production of 
royalty-bearing native oil and gas that still exists in the reservoir. 
The only way to determine how much native gas was produced is to 
compare the heating value of the gas injected with the heating value of 
the gas withdrawn. In addition, the heating value of the withdrawn gas 
may no longer be as consistent from month to month, due to the addition 
of native gas production. However, royalty is due on native oil and gas 
that is withdrawn from the GSA, therefore the meter measuring the 
withdrawal would be an FMP. The definition of GSAMP clarifies that if 
the meter measures both gas from a GSA and native gas, it is an FMP. As 
an FMP, the meter would have to comply with all sections of subpart 
3175, including the sections pertaining to gas sampling, gas analysis, 
and the reporting of heating value. The BLM is specifically seeking 
comments on this proposed GSAMP language.
    Existing Sec.  3175.130 pertains to a testing procedure for 
transducers. The proposed rule would remove this provision and, 
instead, place it on the website for the PMT. There are two reasons for 
this proposed change. First, the BLM wants consistency between the oil 
measurement rule (subpart 3174) and this rule. The oil measurement rule 
does not include testing procedures because they will be included on 
the PMT section of the www.blm.gov website. The BLM also decided that 
providing the testing procedures on the website would provide more 
flexibility if certain aspects of the procedures need to be modified 
based on experience and input from operators and manufacturers applying 
for BLM approval of their devices or procedures. As explained in the 
discussion of the proposed oil measurement rule earlier, the BLM 
recognizes that there is a tradeoff between flexibility and public 
participation in this approach to testing procedures. The BLM seeks 
comment on the merits of providing the test procedures for oil and gas 
measurement via the PMT website rather than codifying them in subparts 
3174 and 3175, respectively. The BLM also seeks comment on whether the 
test procedures would benefit from development in a notice-and-comment 
rulemaking or some other method that would afford greater public 
participation.

[[Page 55994]]

3175.140 Temporary Measurement
    The BLM is proposing to add a new section under Sec.  3175.140 to 
address temporary measurement. Temporary measurement is defined in 43 
CFR 3170.10 as a meter that is in place for less than 3 months. 
Temporary measurement typically applies to a gas meter that is part of 
a measurement skid used to measure the oil and gas from a newly drilled 
well before the permanent measurement facility is installed. The 
existing rule does not address temporary measurement.
    Under proposed Sec.  3175.140, a temporary gas meter would have to 
meet all the requirements of an FMP except for the routine 
verifications required for mechanical recorders and EGM systems, basic 
meter-tube inspections, and detailed meter-tube inspections. The reason 
temporary meters would be exempt from these requirements is because a 
temporary meter is limited to 3 months of operation and the 
verifications and meter-tube inspections listed earlier would be done 
at intervals of 3 months or greater under the proposed rule.
    Section 3175.140 in the existing rule pertains to a testing 
procedure for flow-computer software. The proposed rule would remove 
this provision and, instead, place it on the website for the PMT. There 
are two reasons for this proposed change. First, the BLM wants 
consistency between the oil-measurement rule (subpart 3174) and this 
rule. The oil-measurement rule does not include testing procedures 
because they will be included on the PMT website. The BLM also decided 
that providing the testing procedures on the website would provide more 
flexibility if certain aspects of the procedures need to be modified 
based on experience and input from operators and manufacturers applying 
for BLM approval of their devices or procedures. As discussed earlier, 
the BLM is seeking comment on this approach to testing procedures.
3175.150 Immediate Assessments
    The proposed rule would remove two of the 10 immediate assessments, 
both related to mechanical recorders. The first is for failure to 
conduct a mechanical recorder verification after installation or 
following repair as required under Sec.  3175.92(a), and the second is 
for failure to conduct a routine mechanical recorder verification as 
required under Sec.  3175.92(b). The BLM is proposing to remove these 
immediate assessments because mechanical recorders are becoming less 
prevalent and are typically only found on very-low-volume FMPs where 
the risk of royalty loss is minimal.

Appendix B to 3175--Time Between Samples

    Appendix B of the proposed rule would contain a new table defining 
the maximum allowable time in days between required orifice-plate 
inspections, mechanical recorder and EGM system verifications, and spot 
sampling frequencies. The existing rule establishes the required 
monthly frequency for each of these activities, but there has been some 
confusion as to how this should be interpreted. For example, routine 
mechanical recorder verifications for a low-volume FMP must occur every 
3 months according to existing Table 1 to Sec.  3175.90. This frequency 
would suggest that if a verification was performed on January 1st, the 
next verification could occur as late as April 30th. This would result 
in 4 months between verifications instead of the intended 3 months. The 
same issue applies to verifications for EGM systems and routine 
orifice-plate inspection frequencies. To address this confusion for 
spot sampling frequency, the BLM included existing Table 1 to Sec.  
3175.115, which establishes the maximum time between samples for a 
given monthly frequency. For example, under Table 1 to Sec.  3175.115, 
for a required 3-month spot sampling frequency, no two consecutive spot 
samples can be more than 105 days apart. The BLM added this to the 
existing rule to accommodate unforeseen circumstances such as adverse 
weather, equipment breakdowns, or scheduling issues that would give 
operators some flexibility if they could not sample at the required 3-
month mark. Although the same issue applies to routine orifice-plate 
inspections, mechanical recorder verification, and EGM system 
verifications, the existing regulation does not include tables similar 
to Table 1 to Sec.  3175.115 for these activities. To address this 
issue, the BLM proposes to move Table 1 to Sec.  3175.115 to a new 
Appendix B and then reference Appendix B in the sections covering 
routine orifice-plate inspections, mechanical recorder verifications, 
EGM system verifications, and spot sampling.

C. Summary of Estimated Impacts

    The BLM reviewed the proposed rule and conducted an RIA and 
Environmental Assessment (EA) that examine the impacts of the proposed 
requirements. The draft RIA and draft EA have been posted in the docket 
for the proposed rule on the Federal eRulemaking Portal: https://www.regulations.gov. In the Searchbox, enter ``RIN 1004-AE59'', click 
the ``Search'' button, open the Docket Folder, and look under 
Supporting Documents.
    The BLM's 2019 proposed rule would reduce costs for both Federal 
and Indian onshore oil and gas operators and the BLM. The net present 
value of the estimated cost savings over a 10-year period is $112 
million (using a discount rate of 7 percent) or $132 million (using a 
discount rate of 3 percent). This equates to annual costs savings of 
about $16 million per year (annualized over the evaluation period). 
These cost savings are in 2019 dollars.
    In nominal terms, the proposed rule would generate a cost savings 
to the oil and gas industry and the Federal government averaging $23.1 
million in each of the first 3 years, followed by $11.7 million per 
year in cost savings thereafter. Of these amounts, 88 percent of the 
cost savings in first 3 years would accrue to the industry, and 96 
percent of the costs savings in year four and beyond would accrue to 
the industry.
    The proposed rule would remove or relax a number of requirements 
for equipment, testing, installation, and recordkeeping at existing and 
operations. These actions would reduce the cost of regulatory 
compliance for oil and gas operators producing from leases on Federal 
and Indian mineral estate compared to what it would cost them to comply 
with the 2016 Final Rules. Some provisions of the 2019 proposed rule 
would increase compliance costs for industry and the BLM, but are more 
than offset by the effect of other provisions that would decrease 
compliance costs.
    The largest cost reduction from a single provision in the proposed 
rule would come from an estimated $8.6 million reduction in non-hourly 
installation costs and hourly recordkeeping costs for oil and gas 
operators from less stringent requirements under 43 CFR 3173.72 and 
3173.90 for receiving CAA and offlease measurement approval, and less 
burdensome requirements to apply for such approval. Operators would 
also save an estimated $3.4 million in compliance costs and the BLM 
would save an estimated $2.1 million in administrative costs from 
proposed changes to 43 CFR 3173.61. This section would no longer 
require that oil and gas FMP application Sundry Notices include a 
description of the facility's primary element (meter tube), secondary 
element, LACT/CMS meter, tank number(s), and wells or facilities using 
the FMP. The BLM estimates that this change to 43 CFR 3173.61(b)(2) 
would

[[Page 55995]]

reduce industry recordkeeping time from 1 to 2 hours across-the-board, 
would reduce BLM recordkeeping time from 1.5 hours to 45 minutes for 
Sundry Notices and other documents submitted with FMP applications for 
existing facilities, and from 1 hour to 30 minutes of BLM time annually 
for FMP applications for new and modified facilities.
    There are also multiple cost-reducing provisions in 43 CFR subpart 
3175 that would also have a significant combined effect. The proposed 
revisions to subpart 3175 would reduce total industry compliance costs 
by $8.9 million per year for the first 3 years following its enactment, 
and $5.5 million each year after that. The savings for industry would 
include significant changes from the following provisions:
Category 1. Increased Gas Sampling Frequency
    Lower one-time, non-hourly installation costs under 43 CFR 
3175(b)(2) for very-high-volume (VHV) gas FMPs, which would no longer 
have to install GC meters if they are unable to achieve a minimum 
variance (uncertainty level) of their gas samples' heating values 
(measured in Btu per Mcf) ($3.1 million in annualized one-time savings 
over 3 years);
Category 8. Orifice-Plate and Meter-Tube Inspections
    Reducing the frequency of basic and detailed metering-tube 
inspections required for low-volume (LV) FMPs under Sec.  3175.80(j) 
and Sec.  3175.80(k)(3) from once every 5 years to once every 10 years, 
as well as from once every 2 years to once every 5 years for high-
volume (HV) FMPs, and from once every year to once every 5 years for 
VHV FMPs ($2.1 million saved per year);
Category 2. Sampling Requirements
    Removing annual spot-sampling requirements for very-low volume 
(VLV) and LV FMPs that are actually GSAMPs under Sec.  3175.130(b) and 
for any HV and VHV FMPs under 3175.113(a)(1) where no current 
production is taking place ($1.3 million saved per year from these and 
related provisions);
Category 5. Calibration Frequency
    Reducing from 3 months to 6 months the frequency with which HV and 
VHV FMPs must conduct routine EGM system verifications under Sec.  
3175.102(b) ($1.1 million saved per year);
Category 14. EGM Requirements for Logs and Calculations
    Removing under Sec.  3175.104(a)(2) the requirement that HV and VHV 
FMPs replace QTR devices that display fewer than five decimal places 
($0.5 million in annual one-time savings for years 1-3); and,
Category 4. Type Testing
    Grandfathering, under Sec.  3175.50(a), all transducers, flow 
computer software versions, isolating flow conditioners, differential 
primary devices, and linear measurement devices (Coriolis and 
ultrasonic meters) at VLV, LV, and HV FMPs from type testing for PMT 
approval of makes and models not listed on www.blm.gov ($0.4 million in 
annual one-time savings for years 1-3).
    While changes in 43 CFR subpart 3174 would have the impact of 
increasing compliance costs, they would be more than offset by the cost 
reductions from proposed changes to 43 CFR subparts 3173 and 3175 
described earlier. Nearly all of the increased compliance costs under 
43 CFR subpart 3174 would come from type testing and data submission to 
the PMT of new equipment and software makes and models grouped under 43 
CFR 3174.170--Oil measurement by other methods. These would include 
electronic thermometer (Sec.  3174.43(a)(2), and Sec.  3174.90(e)), 
temperature averaging device (Sec.  3174.105), pressure averaging 
device (Sec.  3174.106(a)), flow computer software (Sec.  3174.120(a)), 
and measurement data system (Sec.  3174.121(a)) makes and models not 
currently listed on www.blm.gov.

VII. Procedural Matters

Regulatory Planning and Review (E.O. 12866, E.O. 13563)

    Executive Order 12866 provides that the Office of Information and 
Regulatory Affairs (OIRA) within the Office of Management and Budget 
(OMB) will review all significant rules. The OIRA has determined that 
this proposed rule is significant because it would raise novel legal or 
policy issues.
    Executive Order 13563 reaffirms the principles of Executive Order 
12866 while calling for improvements in the Nation's regulatory system 
to promote predictability, to reduce uncertainty, and to use the best, 
most innovative, and least burdensome tools for achieving regulatory 
ends. The Executive Order directs agencies to consider regulatory 
approaches that reduce burdens and maintain flexibility and freedom of 
choice for the public where these approaches are relevant, feasible, 
and consistent with regulatory objectives. Executive Order 13563 
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. We have developed this 
rule in a manner consistent with these requirements.
    This proposed rule would revise portions of the BLM's 2016 Final 
Rules. We have developed this proposed rule in a manner consistent with 
the requirements in Executive Order 12866 and Executive Order 13563.
    The BLM reviewed the requirements of the proposed rule and 
determined that it will not adversely affect in a material way the 
economy, a sector of the economy, productivity, competition, jobs, the 
environment, public health or safety, or State, local, or tribal 
governments or communities. For more detailed information, see the RIA 
prepared for this proposed rule. The RIA has been posted in the docket 
for the proposed rule on the Federal eRulemaking Portal: https://www.regulations.gov. In the Searchbox, enter ``RIN 1004-AE59'', click 
the ``Search'' button, open the Docket Folder, and look under 
Supporting Documents.

Reducing Regulation and Controlling Regulatory Costs (E.O. 13771)

    This rule would be a deregulatory action under Section 3(a) E.O. 
13771.

Regulatory Flexibility Act

    The Regulatory Flexibility Act (5 U.S.C. 601 et seq.) (RFA) 
requires that Federal agencies prepare a regulatory flexibility 
analysis for rules subject to the notice-and-comment rulemaking 
requirements under the Administrative Procedure Act (5 U.S.C. 500 et 
seq.), if the rule would have a significant economic impact, whether 
detrimental or beneficial, on a substantial number of small entities. 
See 5 U.S.C. 601-612. Congress enacted the RFA to ensure that 
government regulations do not unnecessarily or disproportionately 
burden small entities. Small entities include small businesses, small 
governmental jurisdictions, and small not-for-profit enterprises.
    The BLM reviewed the SBA size standards for small businesses and 
the number of entities fitting those size standards as reported by the 
U.S. Census Bureau in the Economic Census. The BLM concludes that the 
vast majority of entities operating in the relevant sectors are small 
businesses as defined by the SBA. As such, the proposed rule would 
likely affect a substantial number of small entities.
    The BLM reviewed the proposed rule and estimates that it would 
generate cost savings for industry of $20.3 million per year for each 
of the first 3 years following enactment, followed by

[[Page 55996]]

$11.2 million per year after that. For each of the estimated 4,600 oil 
and gas entities operating on Federal and Indian onshore mineral 
leases, these savings would average $4,415 per entity per year for each 
of the first 3 years following enactment, followed by ongoing net 
savings of $2,425 per entity per year beginning in year 4. These 
estimated cost savings would provide relief to small operators which, 
the BLM notes, represent the overwhelming majority of operators of 
Federal and Indian leases.
    For the purpose of carrying out its review pursuant to the RFA, the 
BLM believes that the proposed rule would not have a ``significant 
economic impact on a substantial number of small entities,'' as that 
phrase is used in 5 U.S.C. 605. An initial regulatory flexibility 
analysis is therefore not required. In making a ``significant'' 
determination under the RFA, the BLM used an estimated per-entity cost 
savings to conduct a screening analysis. The analysis shows that the 
average reduction in compliance costs associated with this proposed 
rule are a small enough percentage of the profit margin for small 
entities, so as not be considered ``significant'' under the RFA. 
Details on this determination can be found in the RIA for the proposed 
rule. For the foregoing reasons, and those mentioned in the RIA at 
Section 2.9 Affected Small Entities, the Secretary of Interior 
certifies under 5 U.S.C. 605 (b), that this rule will not have a 
significant economic impact on a substantial number of small entities.

Small Business Regulatory Enforcement Fairness Act

    This proposed rule is not a major rule under 5 U.S.C. 804(2), the 
Small Business Regulatory Enforcement Fairness Act. This proposed rule:
    (a) Would not have an annual effect on the economy of $100 million 
or more.
    (b) Would not cause a major increase in costs or prices for 
consumers, individual industries, Federal, State, or local government 
agencies, or geographic regions.
    (c) Would not have a 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 (UMRA)

    This proposed rule would not impose an unfunded mandate on State, 
local, or tribal governments, or the private sector of $100 million or 
more per year. The proposed rule would not have a significant or unique 
effect on State, local, or tribal governments or the private sector. 
The proposed rule contains no requirements that would apply to State, 
local, or tribal governments. It would revise requirements that would 
otherwise apply to the private sector. A statement containing the 
information required by the Unfunded Mandates Reform Act (UMRA) (2 
U.S.C. 1531 et seq.) is not required for the proposed rule. This 
proposed rule is also not subject to the requirements of section 203 of 
UMRA because it contains no regulatory requirements that might 
significantly or uniquely affect small governments, because it contains 
no requirements that apply to such governments, nor does it impose 
obligations upon them.

Governmental Actions and Interference With Constitutionally Protected 
Property Right--Takings (Executive Order 12630)

    This proposed rule would not effect a taking of private property or 
otherwise have taking implications under Executive Order 12630. A 
takings implication assessment is not required. The proposed rule would 
revise many of the requirements placed on operators by the 2016 Final 
Rules. Operators would not have to undertake certain compliance 
activities, either operational or administrative, associated with those 
rules. Therefore, the proposed rule would impact some operational and 
administrative requirements on Federal and Indian lands. All such 
operations are subject to lease terms which expressly require that 
subsequent lease activities be conducted in compliance with 
subsequently adopted Federal laws and regulations.
    This proposed rule conforms to the terms of those leases and 
applicable statutes and, as such, the rule is not a government action 
capable of interfering with constitutionally protected property rights. 
Therefore, the BLM has determined that the rule would not cause a 
taking of private property or require further discussion of takings 
implications under Executive Order 12630.

Federalism (Executive Order 13132)

    Under the criteria in section 1 of Executive Order 13132, this 
proposed rule does not have sufficient federalism implications to 
warrant the preparation of a federalism summary impact statement. A 
federalism impact statement is not required.
    The proposed rule would not have a substantial direct effect on the 
States, on the relationship between the Federal Government and the 
States, or on the distribution of power and responsibilities among the 
levels of government. It would not apply to States or local governments 
or State or local governmental entities. The rule would affect the 
relationship between operators, lessees, and the BLM, but it does not 
directly impact the States. Therefore, in accordance with Executive 
Order 13132, the BLM has determined that this proposed rule does not 
have sufficient federalism implications to warrant preparation of a 
Federalism Assessment.

Civil Justice Reform (Executive Order 12988)

    This proposed rule complies with the requirements of Executive 
Order 12988. More specifically, this proposed rule meets the criteria 
of section 3(a), which requires agencies to review all regulations to 
eliminate errors and ambiguity and to write all regulations to minimize 
litigation. This proposed rule also meets the criteria of section 
3(b)(2), which requires agencies to write all regulations in clear 
language with clear legal standards.

Consultation and Coordination With Indian Tribal Governments (Executive 
Order 13175 and Departmental Policy)

    The Department strives to strengthen its government-to-government 
relationship with Indian tribes through a commitment to consultation 
with Indian tribes and recognition of their right to self-governance 
and tribal sovereignty.
    The BLM evaluated this proposed rule under the Department's 
consultation policy and under the criteria in Executive Order 13175 to 
identify possible effects of the rule on federally recognized Indian 
tribes. Since the BLM approves proposed operations on all Indian 
(except Osage Tribe) onshore oil and gas leases, the proposed rule has 
the potential to affect Indian tribes.
    In March 2019, the BLM sent a letter to each registered tribe 
informing them of a public rulemaking for parts 3170. The letter 
offered tribes the opportunity for individual government-to-government 
consultation for the new rule. Subsequent to the letter, each BLM 
Deputy State Director for Energy, Minerals and Realty received a 
presentation summarizing the proposed changes to the current rules to 
share with the tribes. To date, three tribes have expressed interest in 
formal consultation upon publication of this proposed rule. Future 
tribal consultation may occur on an ongoing basis.

[[Page 55997]]

Paperwork Reduction Act

1. Overview
    This proposed rule contains existing, revised, and new information 
collection (IC) activities for BLM regulations, and a submission to the 
OMB for review under the Paperwork Reduction Act of 1995 (PRA) (44 
U.S.C. et seq.). All information collections require approval under the 
PRA. We may not conduct, or sponsor, and you are not required to 
respond to a collection of information unless it displays a currently 
valid OMB control number. The OMB has reviewed and approved the 
information collection requirements associated with this rulemaking and 
assigned the following OMB control numbers. The proposed rule would 
affect the following control numbers:
     Onshore Oil and Gas Operations and Production (1004-0137, 
expiration October 31, 2021);
     Oil and Gas Facility Site Security (1004-0207, expiration 
May 31, 2023);
     Measurement of Oil (1004-0209, expiration April 30, 2023); 
and
     Measurement of Gas (1004-0210, expiration April 30, 2023).
    Please note that this section includes estimated hour and non-hour 
cost burdens associated with IC activities for OMB control numbers 
1004-0137, 1004-0207, 1004-0209, and 1004-0210 that are not addressed 
in this proposed rule. Therefore, the total burden estimates described 
herein exceed the estimated burdens associated with the regulatory 
provisions directly impacted by this proposed rule. For the existing 
requirements unchanged by the proposed rule, we used the existing OMB-
approved estimated hour and non-hour cost burdens.
    The BLM is seeking to renew the information collections for 3 years 
with the final rulemaking. The following description of the IC 
activities in this proposed rule includes estimates of annual burdens. 
Included in the burden estimates are the time for reviewing 
instructions, searching existing data sources, gathering and 
maintaining the data needed, and completing and reviewing each 
component of the proposed information collection.
2. Summary of Information Collection Activities

                                                     Proposed Rule Changes in Responses and Burdens
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                               Existing OMB approved       Proposed rule  responses and      Changes in  responses and
                                                               responses and burdens                  burdens                         burdens
                     OMB control No.                     -----------------------------------------------------------------------------------------------
                                                             Number of       Number of       Number of       Number of       Change in       Change in
                                                             responses     burden hours      responses     burden hours      responses     burden hours
--------------------------------------------------------------------------------------------------------------------------------------------------------
1004-0137...............................................         301,663       1,835,888         222,919       1,772,543        (78,744)        (63,345)
1004-0207...............................................          93,975          69,640          89,045          59,740         (4,930)         (9,900)
1004-0209...............................................          11,742           5,884           1,382           5,166        (10,360)           (718)
1004-0210...............................................         430,782          95,068         246,726          66,507       (184,056)        (28,561)
                                                         -----------------------------------------------------------------------------------------------
    Total...............................................         838,162       2,006,480         560,072       1,903,959       (278,090)       (102,524)
--------------------------------------------------------------------------------------------------------------------------------------------------------


                                                      Proposed Rule Changes in Nonhour Cost Burdens
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                      Existing OMB approved     Proposed rule  nonhour cost    Changes in  nonhour cost
                         OMB control No.                               nonhour cost burdens               burdens                      burdens
--------------------------------------------------------------------------------------------------------------------------------------------------------
1004-0137........................................................                  $29,370,000                  $29,370,000                            0
1004-0207........................................................                            0                            0                            0
1004-0209........................................................                    5,580,305                    4,070,305                 ($1,510,000)
1004-0210........................................................                   24,600,894                   10,996,945                 (13,603,949)
                                                                  --------------------------------------------------------------------------------------
    Total........................................................                   59,551,199                   44,437,250                 (15,113,949)
--------------------------------------------------------------------------------------------------------------------------------------------------------

Control Number 1004-0137
    Abstract: Various Federal and Indian mineral leasing statutes 
authorize the BLM to grant and manage onshore oil and gas leases on 
Federal and Indian (except Osage Tribe) lands. In order to fulfill its 
responsibilities under these statutes, the BLM needs to perform the 
information collection activities set forth in the regulations at 43 
CFR parts 3160 and 3170.
    Title of Collection: Onshore Oil and Gas Operations (43 CFR part 
3160 and 3170).
    OMB Control Number: 1004-0137.
    Form Numbers: 3160-3, 3160-4, 3160-5, and 3160-6.
    Type of Review: Revision of a currently approved collection.
    Respondents/Affected Public: Holders of onshore oil and gas leases 
on Federal and Indian (except Osage Tribe) lands, and applicants for 
such leases.
    Total Estimated Number of Annual Responses: 222,919.
    Estimated Completion Time per Response: Varies from 15 minutes to 
40 hours, depending on activity.
    Total Estimated Number of Annual Burden Hours: 1,772,543 hours.
    Respondent's Obligation: Required to obtain or retain a benefit.
    Frequency of Collection: On occasion, except for the following IC 
activities:
     Request for Approval of a Communitization Allocation 
Agreement (CAA), which must be submitted once;
     Response to Notice of Insufficient CAA, which must be 
submitted once;
     Request for Approval of a Facility Measurement Point (FMP) 
for Future Measurement Facilities, which must be submitted once;
     Request for Approval of an FMP for Existing Measurement 
Facilities, which must be submitted once; and
     Measurement Tickets, which must be submitted monthly.
    Total Estimated Annual Nonhour Burden Cost: $29.37 million.
    The current OMB inventory includes 1,835,888 annual burden hours 
for the related collection of information. We expect the burden 
estimate for the proposed rule will be 1,772,543 hours, which reflects 
a decrease of 78,744 responses and 63,345 hour burdens. The program 
changes for control number consist of IC activities moved from OMB 
Control Number 1004-0207 and 1004-0209, and for the large decrease in 
the measurement tickets burdens. The

[[Page 55998]]

proposed rule will not change the nonhour cost burden for this control 
number.
    From approved annual burden hours under 1004-0137, the rule 
proposes changes to the following burdens:
     Measurement Tickets (upon request), 43 CFR 3174.43(b)(6) 
and 3174.162, (-67,000 burden hours).
    The proposed rule adds the following burden hours:
     Request to Use Alternate Measurement System (One-Time), 43 
CFR 3170.30, (+400 burden hours),
     Request to Use Alternate Measurement System (Annual), 43 
CFR 3170.30, (+80 burden hours),
     Documentation of Early Adoption of 3174--foregoing phase-
in periods (Annual), 43 CFR 3174.43(a)(1) and 3174.60(b)(3), (+500 
burden hours),
     Documentation of Tank Calibration Table Strapping 
(Annual), 43 CFR 3174.43(a)(2) and 3174.82(d), (+2,500 burden hours),
     Notification of LACT System Failure, 43 CFR 3174.90, (+25 
burden hours),
     Documentation of Excessive Meter Factor Deviation 
(Annual), 43 CFR 3174.43(a)(4) and 3174.154(a), (+100 burden hours), 
and
     Approval for Slop or Waste Oil (Annual), 43 CFR 3174.14, 
(-50 burden hours).
Control Number 1004-0207
    Abstract: This collection of information enables the BLM to enforce 
security standards for Federal and Indian (except Osage Tribe) oil and 
gas leases.
    Title of Collection: Oil and Gas Facility Site Security (43 CFR 
subparts 3170 and 3173).
    OMB Control Number: 1004-0207.
    Form Number: None.
    Type of Review: Revision of a currently approved collection.
    Respondents/Affected Public: Oil and gas operators, lessees, 
operators, purchasers, transporters, and any other person directly 
involved in producing, transporting, purchasing, selling, or measuring 
oil or gas.
    Total Estimated Number of Annual Responses: 89,045.
    Estimated Completion Time per Response: Varies from 15 minutes to 5 
hours, depending on activity.
    Total Estimated Number of Annual Burden Hours: 59,740.
    Respondent's Obligation: Required to obtain or retain a benefit.
    Frequency of Collection: On occasion.
    Total Estimated Annual Nonhour Burden Cost: None.
    The current OMB inventory includes 69,640 annual burden hours for 
the related collection of information. We expect the burden estimate 
for the proposed rule will be 59,740 hours, which reflects a decrease 
of 4,930 responses and 9,900 annual burden hours.
    From approved annual burden hours under 1004-0207, the rule 
proposes changes to the following:
     Proposed Sec.  3173.31 would revise and replace two IC 
activities previously approved for Sec.  3173.6 (``Water Draining 
Operations --Data Collection'' and ``Water Draining Operations--
Recordkeeping and Records Submission). The proposed rule would replace 
these two IC activities with a single IC activity, i.e., ``Water-
Draining Operations.'' The estimated responses decrease by 5,000 (from 
65,000 for the two existing IC activities to 60,000 for the one 
proposed activity). The estimated burden hours decrease by 10,000 (from 
25,000 for the two existing IC activities to 15,000 for the one 
proposed), and
     The proposed rule includes one program change. From 
approved annual burden hours under 1004-0207, the rule proposes changes 
to the Report of Theft or Mishandling of Production (43 CFR 3173.40) 
(+100 annual burden hours). The estimated responses increase by 70 
(from 5 for the existing IC activity to 75 for the proposed activity). 
The estimated burden hours increase by 100 (from 50 for the existing IC 
activity to 150 for the proposed activity).
    There are no effects on estimated non-hour burdens.
Control Number 1004-0209
    Abstract: This collection of information enables the BLM to enforce 
standards for the measurement of oil produced from Federal and Indian 
(except Osage Tribe) leases.
    Title of Collection: Measurement of Oil (43 CFR part 3174).
    OMB Control Number: 1004-0209.
    Form Number: None.
    Type of Review: Revision of a currently approved collection.
    Respondents/Affected Public: Oil and gas operators.
    Total Estimated Number of Annual Responses: 1,382 responses.
    Estimated Completion Time per Response: Varies from 15 minutes to 
40 hours, depending on activity.
    Total Estimated Number of Annual Burden Hours: 5,166.
    Respondent's Obligation: Required to obtain or retain a benefit.
    Frequency of Collection: On occasion.
    Total Estimated Annual Nonhour Burden Cost: $4,070,305.
    The current OMB inventory includes 5,884 annual burden hours for 
the related collection of information. We expect the burden estimate 
for the proposed rule will be 5,166 hours, which reflects a decrease of 
10,360 responses and 718 hour burdens. The current nonhour cost burden 
is $5,580,305. We expect the nonhour cost burden for the proposed rule 
to $4,070,305, which reflects a decrease of $1,510,000.
    From approved annual burden hours under 1004-0209, the rule 
proposes removal of the following burdens:
     Documentation of Tank Calibration Table Strapping 
(Annual), 43 CFR 3174.5(c)(3), (-2,500 burden hours),
     Notification of LACT System Failure, 43 CFR 3174.7(e)(1), 
(-25 burden hours),
     Documentation of Testing for Approval of a Positive 
Displacement (PD) Meter (One-Time), 43 CFR 3174.8(a)(1), (-800 burden 
hours),
     Documentation of Testing for Approval of a Positive 
Displacement (PD) Meter (Annual), 43 CFR 3174.8(a)(1), (-80 burden 
hours),
     Onsite Data Display Requirements (Annual), 43 CFR 
3174.10(e), (-50 burden hours),
     Meter Prover Calibration Documentation (Annual), 43 CFR 
3174.11(b), (-75 burden hours),
     Meter Proving and Volume Adjustments Notification 
(Annual), 43 CFR 3174.11(i)(1), (-6 burden hours),
     Request to Use Alternate Oil Measurement System (One-
Time), 43 CFR 3174.13, (-400 burden hours),
     Request to Use Alternate Oil Measurement System (Annual), 
43 CFR 3174.13, (-80 burden hours), and
     Approval for Slop or Waste Oil (Annual), 43 CFR 3174.14, 
(-50 burden hours)
    From approved annual burden hours under 1004-0209, the rule 
proposes changes to the following burdens:
     Request for Exception to Uncertainty Requirements (One-
Time), 43 CFR 3174.31, (-120 burden hours),
     Request for Exception to Uncertainty Requirements 
(Annual), 43 CFR 3174.31(a)(2), (-40 burden hours),
     Documentation of Testing for Approval of Automatic Tank 
Gauging (ATG) Equipment (One-Time), 43 CFR 3174.41(a), (-300 burden 
hours),
     Documentation of Testing for Approval of Automatic Tank 
Gauging (ATG) Equipment (Annual), 43 CFR 3174.41(a), (-60 burden 
hours),
     Documentation of Testing for Approval of Coriolis Meter 
(One-Time), 43 CFR 3174.41(d) and (e), (+200 burden hours),
     Documentation of Testing for Approval of Coriolis Meter 
(Annual), 43 CFR 3174.41(d) and (e), (+20 burden hours),

[[Page 55999]]

     Log of ATG Verification (upon request) (Annual), 43 CFR 
3174.88(b)(4) and 43 CFR 3174.43(b)(1), (-1 burden hours),
     Documentation of Coriolis Meter Specifications and Zero 
Verification Procedure (upon request) (Annual), 43 CFR 3174.110(e) and 
43 CFR 3174.43(b)(2), (No change),
     Log of Meter Factors, Zero Verifications, and Zero 
Adjustments (upon request) (Annual),
     43 CFR 3174.110(e), (No change),
     ELM Audit Trail Requirements (upon request) (Annual), 43 
CFR 3174.130(h)(6) and 43 CFR 3174.43(b)(4), (+375 burden hours), and
     Meter Proving Reports (upon request) (Annual), 43 CFR 
3174.158(c) and 43 CFR 3174.43(b)(5), (+94 burden hours).
    Proposed rule introduces the following burden hours:
     Documentation of Testing for Approval of LACT Sampling 
System (One-Time), 43 CFR 3174.41(b), (+1200 burden hours),
     Documentation of Testing for Approval of LACT Sampling 
System (Annual), 43 CFR 3174.41(b), (+200 burden hours),
     Documentation of Testing for Approval of Stand-alone 
Temperature Averaging Device (One-Time), 43 CFR 3174.41(f), (+60 burden 
hours),
     Documentation of Testing for Approval of Stand-alone 
Temperature Averaging Device (Annual), 43 CFR 3174.41(f) and 43 CFR 
3174.105(a), (+20 burden hours),
     Documentation of Testing for Approval of Temperature and 
Pressure Transducers (One-Time), 43 CFR 3174.41(g) and (h), (+1,000 
burden hours),
     Documentation of Testing for Approval of Temperature and 
Pressure Transducers (Annual), 43 CFR 3174.41(g) and (h), (+100 burden 
hours),
     Documentation of Testing for Approval of Electronic Liquid 
Measurement Software (One-Time), 43 CFR 3174.41(i), (+320 burden 
hours),
     Documentation of Testing for Approval of Electronic Liquid 
Measurement Software (Annual), 43 CFR 3174.41(i), (+80 burden hours),
     Documentation of Testing for Approval of Portable 
Electronic Thermometers (One-Time), 43 CFR 3174.41(j), (+60 burden 
hours),
     Documentation of Testing for Approval of Portable 
Electronic Thermometers (Annual), 43 CFR 3174.41(j), (+20 burden 
hours),
     Documentation of Testing for Approval of Measurement Data 
Systems (One-Time), 43 CFR 3174.41(k), (+80 burden hours), and
     Documentation of Testing for Approval of Measurement Data 
Systems (Annual), 43 CFR 3174.41(k), (+40 burden hours).
Control Number 1004-0210
    Abstract: The information collection activities in this control 
number assist the BLM in ensuring the accurate measurement and proper 
reporting of all gas removed or sold from Federal and Indian (except 
Osage Tribe) leases, units, unit participating areas, and areas subject 
to communitization agreements, by providing a system for production 
accountability by operators, lessees, purchasers, and transporters.
    Title of Collection: Measurement of Gas (43 CFR subpart 3175).
    OMB Control Number: 1004-0210.
    Form Number: Equipment Application (New Form).
    Type of Review: Revision of a currently approved collection.
    Respondents/Affected Public: Holders of Federal and Indian (except 
Osage Tribe) oil and gas leases, operators, purchasers, transporters, 
any other person directly involved in producing, transporting, 
purchasing, or selling, including measuring, oil or gas through the 
point of royalty measurement or the point of first sale, and 
manufacturers of equipment or software used in measuring natural gas.
    Total Estimated Number of Annual Responses: 246,726.
    Estimated Completion Time per Response: Varies from 6 minutes to 80 
hours, depending on activity.
    Total Estimated Number of Annual Burden Hours: 66,507.
    Respondent's Obligation: Required to obtain or retain a benefit.
    Frequency of Collection: On occasion, except for information 
collection activities at 43 CFR 3175.115 and 3175.120, which require 
submission of gas analysis reports at frequencies that vary from 
monthly to annually.
    Total Estimated Annual Nonhour Burden Cost: $10,996,945.
    The current OMB inventory includes 95,068 annual burden hours for 
the related collection of information. We expect the burden estimate 
for the proposed rule will be 66,507 annual hour burdens, which 
reflects a decrease of 184,056 responses and 28,561 hour burdens. The 
current nonhour cost burdens equals $24,600,894. We expect the nonhour 
cost burdens for the proposed rule will be $10,996,945, which reflects 
a decrease of $13,603,949.
    From approved annual burden hours under 1004-0210, the rule 
proposes removal of the following burdens:

 Transducers--Test Data Collection and Submission for Existing 
Makes and Models (One-Time), 43 CFR 3175.43 and 3175.130, (-1,600 
annual burden hours)
 Transducers--Test Data Collection and Submission for Future 
Makes and Models, (Annual), 43 CFR 3175.43 and 3175.130, (-16 annual 
burden hours)
 Flow-computer software--Test Data Collection and Submission 
foe Existing Makes and Models (One-Time), 43 CFR 3175.44 and 3175.140 
though 3175.144, (-800 annual burden hours)
 Flow-computer software--Test Data Collection and Submission 
for Future Makes and Models (Annual), 43 CFR 3175.44 and 3175.140 
though 3175.144, (-160 annual burden hours)
 Isolating Flow Conditioners--Test Data Collection and 
Submission for Existing Makes and Models (One-Time), 43 CFR 3175.46, (-
240 annual burden hours)
 Differential Primary Devices Other than Flange-Tapped Orifice 
Plates--Test Data Collection and Submission for Existing Makes and 
Models (One-Time), 43 CFR 3175.47, (-240 annual burden hours)
 Linear Measurement Devices--Test Data Collection and 
Submission for Existing Makes and Models (One-Time), 43 CFR 3175.48, (-
400 annual burden hours)
 Linear Measurement Devices--Test Data Collection and 
Submission for Future Makes and Models (Annual), 43 CFR 3175.48, (-80 
annual burden hours)
 Accounting Systems--Test Data Collection and Submission for 
Future Makes and Models (One-Time), 43 CFR 3175.49, (-1600 annual 
burden hours)
 Accounting Systems--Test Data Collection and Submission for 
Future Makes and Models (Annual), 43 CFR 3175.49, (-160 annual burden 
hours)
 Sample Separator Cleaning--Documentation, 43 CFR 
3175.113(c)(3), (-757 annual burden hours)
 Gas Analysis--Composite Sampling (One-Time), 43 CFR 
3175.115(b)(5) (-21 annual burden hours)

    Proposed rule introduces changes in burden hours for the following:

 Measurement Equipment at FMPs (NEW Form), 43 CFR 3175.40, 
(+240 hours)
 Schedule of Basic Meter Tube Inspection, 43 CFR 3175.80(k)(4), 
(-6,278 annual burden hours)
 Basic Inspection Meter Tubes--Data Collection and Submission, 
43 CFR

[[Page 56000]]

3175.80(k), (-331 annual burden hours)
 Detailed Inspections of Meter Tubes--Data Collection and 
Submission, 43 CFR 3175.80(l) and (m), (-2,082 annual burden hours)
 Request for Extension of Time for a Detailed Meter Tube 
Inspection, 43 CFR 3175.80(k)(3), (-528 annual burden hours)
 Documentation of unedited QTR, configuration log, event log, 
and alarm log, 43 CFR 3175.104(a) through (d), (-3,136) annual burden 
hours)
 Notification of Schedule for Spot Sampling, 43 CFR 
3175.113(b), (+7,486 annual burden hours)
 Sample Cylinder Cleaning--Documentation, 43 CFR 
3175.113(c)(3), (-7,273 annual burden hours)
 Gas Analysis--Spot Sampling, 43 CFR 3175.115(a) and (b) and 
3175.116, (-778 annual burden hours)
 On-line Gas Chromatograph Specifications, 43 CFR 3175.117(c), 
(-10 annual burden hours)
 Gas Chromotograph Verification--Documentation, 43 CFR 
3715.118(c)(1) and (d), (-1,211 annual burden hours)
 Gas Analysis Report--Entry into GARVS, 43 CFR 3175.119(a) and 
3175.120(f), (-8,586 annual burden hours)

    The proposed rule will not change the following burden hours:

 Maintenance of Data at FMP, 43 CFR 3175.101(b) through (d)
 Redundancy Verification Check for Electronic Gas Measurement 
Systems, 43 CFR 3175.102(e)
 Notification of Verification, 43 CFR 3175.92(d) and (e) and 43 
CFR 3175.92(f)
 Evacuation and Pre-charge for the Helium Pop Method--
Documentation, 43 CFR 3175.114(a)(2)
 O-ring and Lubricant Composition for the Floating Piston 
Method--Documentation, 43 CFR 3175.114(a)(3)
 Gas Analysis--Extended Gas Analysis, 43 CFR 3175.119(b)
3. Information Collection Request
    The proposed rule would remove or revise requirements that the BLM 
has found to be unnecessarily burdensome, unclear, inconsistent, or 
otherwise problematic. The proposed rule would also adopt industry 
standards, where appropriate, and provide for the use of emerging 
measurement technologies. The following section describes the proposed 
regulatory changes potentially changing the collection of information 
burdens in OMB approved control numbers.
Proposed Revision of Control Number 1004-0137
    New uses for Form 3160-5 are included at 43 CFR parts 3170, 3173, 
and 3174 as a result of the proposed rule. The BLM now requests that 
the new uses and burdens for Form 3160-5 that are described under 
control number 1004-0207 and 1004-0209 be moved to 1004-0137. The BLM 
anticipates continuation of the other IC activities as authorized by 
the OMB Control Numbers 1004-0207, 1004-0209, and 1004-0210.
    The following describes proposed revisions of this control number.
    Proposed Sec.  3170.30, Alternative measurement equipment and 
procedures. Proposed Sec.  3170.30 would allow an operator or 
manufacturer to request approval, with supporting data, for the use of 
alternate oil and gas measurement equipment or measurement methods. 
Operators or manufacturers would submit to the BLM performance data, 
actual field test results, laboratory test data, or any other 
supporting data or evidence showing the proposed alternate oil or gas 
measurement equipment or method would meet or exceed the objectives of 
minimum standards.
    Proposed Sec.  3170.40, Variances (Form 3160-5). Existing Sec.  
3170.6 authorizes any party that is subject to the regulations in 43 
CFR part 3170 to request a variance from any of the regulations in part 
3170. While Sec.  3170.6 states that a request for a variance should be 
filed using the BLM's electronic system, it also allows the use of 
paper copies of Form 3160-5 (Sundry Notices).
    Proposed Sec.  3173.50, Site facility diagram (Form 3160-5). 
Existing Sec.  3173.11 requires a site facility diagram for all 
facilities, which is a primary mechanism for monitoring operators' 
compliance with measurement regulations and policy. These IC activities 
enable the BLM to verify, among other things, royalty-free-use volumes 
reported by the operator on its Oil and Gas Operations Reports. The 
proposed rule requires each site facility diagram be submitted with a 
completed Sundry Notice.
    Existing Sec.  3173.11(f) specifies that after a site facility 
diagram has been submitted, operators have an ongoing obligation to 
update and amend a site facility diagram when facilities are modified; 
a non-Federal facility located on a Federal lease or federally approved 
unit or communitized area is constructed or modified; or there is a 
change in operator.
    Proposed Sec.  3173.50 (c)(6) would remove the requirement for an 
operator of a co-located production facility to include on the site 
facility diagram a skeleton diagram of other operator's co-located 
facility(ies).
    Proposed Sec.  3173.50(d)(1) would revise the timeframe for when an 
operator would have to submit a new, permanent site-facility diagram. 
The timeframe would be changed from 30 days after the BLM assigns an 
FMP to 60 days after the facility becomes operational. In addition, 
proposed Sec.  3173.50(d)(2) would change the timeframe for when an 
operator would have to submit an amended site facility diagram for a 
modified, existing facility. That time frame would be changed from 30 
days to 60 days after the facility is modified. The proposed 60-day 
timeframe would also apply when a non-Federal facility located on a 
Federal lease or a federally approved unit or communitized area is 
constructed or modified.
    Proposed Sec.  3173.60, Applying for a facility measurement point 
number (Form 3160-5). Existing Sec.  3173.12 requires operators to 
obtain BLM approval of facility measurement points (FMPs). Existing 
Sec.  3173.12(d) applies to permanent measurement facilities that come 
into service after January 17, 2017. Existing Sec.  3173.12(e) applies 
to permanent measurement facilities in service before January 17, 2017. 
Both of these IC activities are one-time only. These activities assist 
the BLM in verifying production. All requests for an FMP must include 
the following:
     A complete Sundry Notice;
     The applicable Measurement Type Code specified in the 
BLM's Well Information System (WIS);
     For gas measurement, identification of the operator/
purchaser/transporter unique station number, meter tube size or serial 
number, and type of secondary device;
     For oil measurement, identification of the oil tank 
number(s) or tank serial number(s) and size of each tank, and whether 
the oil was measured by LACT or CMS if not measured by tank gauge;
     Where production from more than one well will flow to the 
requested FMP, a list of the API well numbers associated with the FMP; 
and
     FMP location by land description.
    This provision does not apply to temporary measurement equipment 
used during well testing operations. Each request must meet the 
requirements listed above.
    The BLM, through proposed Sec.  3173.60(d), is proposing to remove 
the requirement that operators list the ``station number, primary 
element (meter tube) size or serial number, and

[[Page 56001]]

type of secondary device (mechanical or electronic)'' and replace it 
with a requirement that operators provide ``the unique meter ID, and 
elevation.''
    Proposed Sec.  3173.60(d) would require the operator to identify 
the purchaser or transporter, and the unique meter ID. The proposed 
change would delete the requirement to identify whether the equipment 
is LACT or CMS, the associated oil tank number or serial number, and 
tank size.
    Proposed Sec.  3173.70, Conditions for commingling and allocation 
approval (surface and downhole); and Proposed Sec.  3173.71, Applying 
for commingling and allocation approval (Form 3160-5). Existing Sec.  
3173.16 requires an operator to submit information to correct any 
inconsistencies or deficiencies identified by the BLM, where an 
operator's request for assignment of an FMP number (see 43 CFR 3173.12) 
includes a facility associated with a CAA existing on January 17, 2017. 
Both of these IC activities are one-time only.
    Proposed Sec.  3173.70 would revise the existing requirements for 
commingling and allocation approval. When an operator is interested in 
commingling a lease or a unit, they would request approval from the 
BLM. The operator(s) would provide a methodology acceptable to the BLM 
for allocation among the leases or agreements, from which production is 
to be commingled, with a signed agreement if there are more than one 
party.
    Proposed Sec.  3173.71 would require a separate Sundry Notice for 
off-lease measurement approval.
    The proposed rule would require an applicant-certified statement of 
a surface-use plan of operations if new surface disturbance is proposed 
in a commingling application on BLM-managed land. This proposed change 
would reduce the application submission burden while ensuring a 
surface-use plan of operation has been prepared.
    The proposed rule would remove the requirement that an operator 
submit a right-of-way grant with its application for commingling and 
allocation approval if any of its facilities would be located on 
Federal or Indian land. The proposed rule would require the operator to 
provide an applicant-certified statement that it already has a right-
of-way grant for Federal rights-of-way.
    The proposed rule would require that gas CAA applications be 
submitted separately from oil CAA applications.
    Proposed Sec.  3173.74, Modification of a commingling and 
allocation approval (Form 3160-5). Proposed Sec.  3173.74(b) would add 
another condition that would require an operator to have the CAA 
reevaluated by the BLM when actual production exceeds the projected 
production in the commingling application. This change would not impact 
burden hours.
    Proposed Sec.  3173.91, Applying for off-lease measurement. 
Proposed Sec.  3173.91 would clarify and simplify the requirements for 
an off-lease measurement application. Operators would be required to 
submit separate Sundry Notices for applications for off-lease 
measurement for each oil and gas FMP.
    Proposed Sec.  3174.43, Data Submission and notification 
requirements (Form 3160-5). Proposed Sec.  3174.43(a) would revise 
several existing IC activities by adding a new requirement to use Form 
3160-5 (Sundry Notices and Reports on Wells), a form approved by OMB 
under control number 1004-0137. The BLM requests the revision of 
control number 1004-0137 to include these uses of Sundry Notices. 
Existing IC activities that would be affected by the proposed rule in 
this way are currently authorized under control number 1004-0209:
     Documentation of Tank Calibration Table Strapping (Annual) 
(Proposed Sec.  3174.82);
     Notification of LACT System Failure (Annual) (Proposed 
Sec.  3174.90); and
     Approval for Slop or Waste Oil (Annual) (Proposed Sec.  
3174.180).
    In addition, proposed Sec.  3174.120, would be regulatory 
authorities for a new use of Sundry Notices. This new IC activity would 
be labeled, ``Electronic Liquid Measurement'' (ELM).
    Proposed Sec.  3174.60, Timeframes for compliance. In addition, 
proposed Sec.  3174.60(b)(3) would include Sundry Notices in another 
new IC activity, i.e., ``Notification of Early Compliance.'' Proposed 
Sec.  3174.60(b)(3) would allow an operator to voluntarily begin full 
compliance with the requirements of 43 CFR subpart 3174 at any FMP 
prior to the mandatory compliance dates.
    Proposed Sec.  3174.82, Oil tank calibration. The proposed rule 
would retain the requirements in the existing regulations, but would 
add three requirements for FMP oil tank calibration. First, the tank-
capacity tables would be required to be calculated for a tank-shell 
temperature of 60-degree F. Second, FMP tank-capacity tables would be 
required to be recalculated if the references gauge point is changed. 
Third, FMP tank calibration charts would be required to be submitted to 
the AO by Sundry Notice within 45 days after a calibration or 
recalculation of charts. The existing regulations require operators to 
submit tank calibration charts to the AO after calibration without 
specifying how they are to be submitted. The BLM needs to have the most 
current tank-calibration charts to provide a common tracking mechanism.
    Proposed Sec.  3174.90, LACT system--general requirements. Burdens 
related to notification of LACT system failure would be moved from OMB 
control number 1004-0209, and put under 1004-0137. Proposed Sec.  
3174.90(e) would require the operator to notify the AO by Sundry Notice 
within 30 days after repair of any LACT system failures or equipment 
malfunctions that may have resulted in measurement error. Existing 
requirements require operators to notify the AO within 72 hours of a 
LACT failure. Industry expressed concerns with 72 hours being difficult 
to comply with.
    Proposed Sec.  3174.120, Electronic liquids measurement, ELM 
(secondary and tertiary device). The IC requirements at proposed Sec.  
3174.120 would apply to any FMP with ELM equipment installed. The 
proposed regulation would require each ELM device to display the values 
and corresponding units of measurement and meter factors. The following 
information would have to be accessible to the BLM at the FMP without 
the use of data-collection equipment, laptop computers, or any special 
equipment:
     The make, model, and size of each sensor; and
     The make, model, range, and calibrated span of the 
pressure and temperature transducer used to determine gross standard 
volume.
    The following information would have to be recorded and retained, 
and submitted to the BLM upon request:
     Retention of the QTR would be required on a daily (24 
hour) basis, except in circumstances where batch delivery duration is 
less than 24 hours. In these situations, hourly data retention would be 
required.
     The configuration log would have to comply with the API 
requirements and contain and identify all constant flow parameters used 
in generating the QTR.
     The event log would have to comply with the API 
requirements and be of sufficient capacity to record all events such 
that the operator can retain the information under the recordkeeping 
requirements.
     The type and duration of any of the alarm conditions would 
have to be recorded.
    Proposed Sec.  3174.154, Excessive meter factor deviation. The 
proposed rule would allow the operator to provide a statement 
explaining that the excessive-

[[Page 56002]]

meter factor was not caused by a meter malfunction on a case-by-case 
basis.
    Proposed Sec.  3174.160-3174.162 Measurement tickets. The proposed 
rule would separate out the measurement-ticket requirement into 
individual sections according to the measurement type. Measurement 
types would include tank gauging and LACT or CMS.
    Proposed Sec.  3174.180, Determination of oil volumes by methods 
other than measurement. This proposed section would require an operator 
to get prior written approval from the BLM for sale or disposal of slop 
oil and require the operator to notify the BLM via Sundry Notice of the 
volume sold or disposed. This change would ensure that a tracking and 
auditing mechanism for spill oil, waste oil, and slop oil exists. 
Burdens related this requirement would be moved from OMB control number 
1004-0209, and put under 1004-0137.
Proposed Revision of Control Number 1004-0207
    The following is an explanation of how the proposed regulatory 
changes would affect the various subpart's collections of information:
    Proposed Sec.  3170.50, Required Recordkeeping, Records Retention, 
and Records Submission. Proposed Sec.  3170.50(g) would revise the IC 
activity previously approved for Sec.  3170.7(g) by adding ``land 
description'' to the list of information that must be included in 
records that are used to determine quality, quantity, disposition, and 
verification of production. This proposed revision would not affect the 
estimated burdens of control number 1004-0207.
    Proposed Sec.  3173.31, Water-Draining Operations--Gauging. 
Proposed Sec.  3173.31 would revise and replace two IC activities 
previously approved for Sec.  3173.6 (``Water Draining Operations--Data 
Collection'' and ``Water Draining Operations--Recordkeeping and Records 
Submission''). The proposed regulation would remove the list of 
information specified for water draining operations, and instead refer 
to the IC requirements in existing Sec.  3173.41(b) (``Required 
Recordkeeping for Inventory and Seal Records''). Like the existing 
water-draining provisions, the proposed provision would assist the BLM 
in accurate accounting of oil and gas produced from Federal and Indian 
leases. This proposed revision would constitute a program change to 
control number 1004-0207 that would affect the estimated burdens as 
described above.
Proposal That Would Affect Both Control Number 1004-0209 and Control 
Number 1004-0210
    Alternative Measurement Equipment and Procedures. Proposed Sec.  
3170.30 would pertain to requests to use ``alternative measurement 
equipment and procedures.'' Proposed Sec.  3170.30 would apply to both 
oil and gas measurement, and would replace the procedures described in 
current Sec.  3174.13, which applies only to the measurement of oil. 
Proposed Sec.  3170.30 is not a new or separate IC activity, but rather 
an additional regulatory authority for other existing IC activities 
pertaining to measurement of oil and measurement of gas. Thus, proposed 
Sec.  3170.30 would not affect the estimated burdens of control numbers 
1004-0209 or 1004-0210.
Proposed Revision of Control Number 1004-0209
    The following is an explanation of how the proposed regulatory 
changes would affect the various subparts' collections of information:
    Proposed Sec.  3174.60, Timeframes for compliance. Proposed Sec.  
3174.60 would include deadlines that would be one-time only because 
they apply only to equipment in operation before the effective date of 
the rule, if finalized. For some other activities, there would be both 
an annual burden for some respondents, and a one-time burden in the 
initial implementation of the rule. Finally, some of these IC 
activities would apply only annually. The labels for IC activities in 
subpart 3174 indicate whether the activities are one-time or annual. 
These proposed changes would not affect the estimated burdens of 
control number 1004-0209.
    Proposed Sec.  3174.82, Oil tank calibration. The proposed 
requirement requires submission of tank calibration tables to the BLM 
within 45 days after calibration. This provision ensures that BLM 
personnel will have the latest charts when conducting inspections or 
audits. The requirements related to this section would be removed from 
this control number and included in OMB Control Number 1004-0137.
    Proposed Sec.  3174.83, Tank gauging--procedures. During field 
operations, operators must obtain and document data required under 
Proposed Sec.  3174.161. The proposed rule would clarify that field 
staff is required to collect only the observed data related to tank-
gauging measurement tickets.
    Proposed Sec.  3174.90, LACT systems--general requirements. 
Requirements related to Sec.  3174.7, LACT systems, would be removed 
from this control number and included in OMB Control Number 1004-0137. 
This proposed section would require the operator to notify the AO by 
Sundry Notice within 30 days after repair of any LACT system failures 
or equipment malfunctions that have resulted in measurement error.
    Proposed Sec.  3174.101, Charging pump and motor. This new section 
would require operators to install a charge pump and motor if the 
static head is insufficient to provide a net positive suction to 
achieve fluid pressure compatible with the oil fluid properties.
    Proposed Sec.  3174.102, Sampling and mixing system. This proposed 
rule seeks to replace the current requirement for testing of sampling 
systems, even those of the same design and construction to be 
individually tested. Operators expressed concern that compliance with 
this requirement to test all sampling systems, even those of the same 
design and construction, is unnecessarily burdensome and provides no 
benefit to the Federal Government. The BLM agrees with this assessment 
and seeks to change the regulation to bring it in line with other 
equipment standards in the regulation and allow for a single test per 
design. The proposed change would reduce the overall burden to 
operators and simplify the inspection process for the BLM.
    Proposed Sec.  3174.103, Air Eliminator. This new section would 
require operators to install an air eliminator to prevent gas or air 
from entering the meter and causing mismeasurement of oil.
    Proposed Sec.  3174.104, LACT Meter. The proposed rule would allow 
for other meter types on LACT units in addition to the use of positive 
displacement and Coriolis meters. This would not change burdens.
    Proposed Sec.  3174.105, Electronic temperature averaging device. 
The proposed rule would allow operators to use a flow computer to 
perform the temperature averaging. The change makes clear that the 
regulation allows for stand-alone temperature averaging devices or 
temperature transmitters working in conjunction with a flow computer. 
Pursuant to proposed Sec.  3174.105(a), a stand-alone temperature-
averaging device would require PMT review and BLM approval. Similarly, 
under proposed Sec.  3174.105(b), a temperature transducer must have 
received BLM approval.
    Proposed Sec.  3174.107, Meter Proving Connection. This new section 
specifies requirements for meter-proving connections, including a leak 
detecting double block and bleed-valve configuration. Existing subpart 
3174 does not reference meter-proving

[[Page 56003]]

connections or leak-detection systems and instead incorporates the API 
6.1 standard, which is not sufficiently specific. Leak detection during 
the proving process is critical to determining an accurate meter 
factor.
    Proposed Sec.  3174.110, Coriolis meter--operating requirements. 
This section would provide operating requirements for the Coriolis 
meter--whether it is a stand-alone unit or is part of a LACT--and its 
transmitter. Proposed Sec.  3174.110(a) and (b) would require Coriolis 
meters and Coriolis transmitters to be on the approved equipment list 
at www.blm.gov. The proposed 3174.9(b) is new and it would allow for a 
Coriolis transmitter to have a separate approval from a Coriolis meter. 
A Coriolis meter is always used in conjunction with a transmitter. The 
BLM believes that this proposed change will alleviate concerns that 
each meter and transmitter combination would require additional 
individual approval.
    Proposed Sec.  3174.120, Electronic liquid measurement system, ELM 
(secondary and tertiary device). This proposed section applies to flow 
computers (ELM systems) that are connected to Coriolis meters and their 
transmitters. Although this section does not have a direct corollary in 
existing subpart 3174, it contains many of the same requirements that 
appear in the existing Coriolis meter regulations at Sec.  3174.10.
    The modification to this regulation separates ELM system 
requirements from Coriolis meter requirements.
    The existing regulation requires operators to use a tertiary device 
(flow computer and associated memory, calculation, and display 
functions) for all CMS FMPs. The proposed changes bring the software-
testing requirements for electronic oil measurement in line with the 
requirements of electronic gas measurement in subpart 3175, which 
provides for uniformity in these requirements to alleviate the burdens 
that having two differing test protocols.
    Proposed Sec.  3174.121, Measurement data system. This new section 
would establish that measurement data systems (MDS) must be approved by 
the BLM for use at an FMP. MDS are designed to gather, edit, store, and 
report measurement data. By requiring that MDSs be BLM approved, 
industry would not have any questions or confusion when selecting an 
MDS system for use at an FMP.
    Proposed Sec.  3174.140, Temporary measurement. The BLM is 
proposing to add a new Sec.  3174.140 to address temporary measurement. 
A temporary oil meter would have to meet all the requirements of an FMP 
with some modified requirements based on the limited timeframe the 
meter will be on the location (for example, proving requirements).
    Proposed Sec.  3174.158, Meter proving reporting requirements. The 
proposed rule would provide a detailed list of specific data required 
for reporting, and would specify a required calculation sequence to be 
followed in the meter factor calculation. The BLM believes that 
providing a detailed list of required reporting data would remove any 
confusion about the exact data that is required on the report.
    Proposed Sec.  3174.158(c) would change the proving-report 
submission requirements of existing Sec.  3174.11(i)(3) from requiring 
an operator to submit each report within 14 days after a meter proving 
to only requiring an operator to submit a proving report when requested 
by the AO. This change has been proposed to make this regulation less 
burdensome to industry while retaining the BLM's audit capabilities for 
verifying proving reports.
    Proposed Sec.  3174.160, Measurement tickets. The proposed rule 
would separate out the measurement-ticket requirements into individual 
sections according to the measurement type, tank gauging, and LACT or 
CMS. This proposed rule would retain the existing requirement that 
measurement tickets be made available upon request of the AO. This 
requirement falls under OMB Control Number 1004-0137.
Proposed Revision of Control Number 1004-0210
    The following is an explanation of how the proposed regulatory 
changes would affect the various subparts' collections of information:
    Proposed Sec.  3175.40, Measurement equipment. The proposed rule 
would revise and replace some of these provisions pertaining to gas-
measurement equipment. The BLM is proposing these changes in order to 
streamline and better organize the regulations. Proposed Sec.  3175.40 
would replace the following existing regulations and associated IC 
activities:
     43 CFR 3175.43 and 3175.130 (Transducers--Test Data 
Collection and Submission for Existing Makes and Models; One-Time);
     43 CFR 3175.43 and 3175.130 (Transducers--Test Data 
Collection and Submission for Future Makes and Models; Annual);
     43 CFR 3175.44 and 3175.140 (Flow-Computer Software--Test 
Data Collection and Submission for Existing Makes and Models; One-
Time);
     43 CFR 3175.44 and 3175.140 (Flow-Computer Software--Test 
Data Collection and Submission for Future Makes and Models; Annual);
     43 CFR 3175.46 (Isolating Flow Conditioners--Test Data 
Collection and Submission for Existing Makes and Models; One-Time);
     43 CFR 3175.47 (Differential Primary Devices Other Than 
Flange-Tapped Orifice Plates--Test Data Collection and Submission for 
Existing Makes and Models; One-Time);
     43 CFR 3175.48 (Linear Measurement Devices--Test Data 
Collection and Submission for Existing Makes and Models; One-Time);
     43 CFR 3175.48 (Linear Measurement Devices--Test Data 
Collection and Submission for Future Makes and Models; Annual);
     43 CFR 3175.49 (Accounting Systems--Test Data Collection 
and Submission for Existing Makes and Models; One-Time); and
     43 CFR 3175.49 (Accounting Systems--Test Data Collection 
and Submission for Future Makes and Models; Annual).
    Proposed Sec.  3175.41, Approved measurement equipment. Proposed 
Sec.  3175.41 would provide that the following types of equipment are 
automatically approved for use if they meet standards prescribed in the 
regulations at subpart 3175:
     Flange-tapped orifice plates (existing Sec.  3175.41);
     Chart recorders for low- and very-low-volume FMPs 
(existing Sec.  3175.42); and
     Gas chromatographs (existing Sec.  3175.45).
    In addition, proposed Sec.  3175.41 would provide that the 
following types of equipment would be automatically approved if they 
meet standards prescribed in the regulations at subpart 3175:
     Transducers, when used at low- and very-low volume FMPs; 
and (existing Sec. Sec.  3175.43 and 3175.130); and
     Flow-computer software, when used at low- and very-low 
volume FMPs (existing Sec. Sec.  3175.44 and 3175.140).
    The existing regulations require BLM approval of all makes and 
models of transducers and flow-computer software developed and used at 
FMPs after January 17, 2017 (i.e., the effective date of the existing 
rule). Proposed Sec.  3175.41 would reduce the number of makes and 
model of transducers and flow-computer software that would be subject 
to these IC activities. BLM proposes to include a new form entitled, 
``Equipment Application Coversheet.'' Operators would be required to 
use BLM-approved measurement equipment. However, manufacturers of 
equipment would need to provide data

[[Page 56004]]

on testing equipment using the new form. The existing regulations 
explain that an oil and gas operator may have applied for review and 
approval because the equipment was old and no longer supported by the 
manufacturer. The proposed rule provides an exemption for the older 
equipment. Therefore, it's unlikely the BLM will receive data from an 
operator.
    Proposed Sec.  3175.60, Timeframes for compliance. Subpart 3175, as 
revised by the proposed rule, would include timeframes for compliance. 
These timeframes, at proposed 43 CFR 3175.60, would include deadlines 
that would be one-time-only because they apply only to equipment in 
operation before the effective date of the rule, if finalized. For some 
other activities, there would be both an annual burden for some 
respondents, and a one-time burden in the initial implementation of the 
rule. Finally, some of these IC activities would apply only annually. 
The labels for IC activities in subpart 3175 indicate whether the 
activities are one-time or annual. These proposed changes would not 
affect the estimated burdens of control number 1004-0210.
    Proposed Sec.  3175.80, Flange-tapped orifice plate (primary 
device). Proposed Sec.  3175.80 would revise existing IC activities 
pertaining to inspections and verifications of primary devices. Some of 
these information collection activities are usual and customary because 
they are required by gas sales contracts and/or industry standards. To 
the extent they are usual and customary, they are not ``burdens'' under 
the PRA (see 5 CFR 1320.3(b)(2)). A description of what is considered 
usual and customary is given for each applicable activity in the 
supporting statement.
    The proposed regulation would revise the following existing IC 
activities:
     Schedule of Basic Meter Tube Inspection;
     Basic Inspection of Meter Tubes--Data Collection and 
Submission;
     Detailed Inspection of Meter Tubes--Data Collection and 
Submission; and
     Request for Extension of Time for a Detailed Meter Tube 
Inspection.
    Proposed Sec.  3175.80(j) would add an initial basic meter-tube 
inspection that would require operators to perform a basic meter-tube 
inspection within 1 year after installation of a very-high-volume FMP 
and within 2 years after installation of a high-volume FMP. This 
requirement would only apply to FMPs installed after the effective date 
of the final rule.
    Proposed Sec.  3175.80(k) would require operators to perform a 
basic meter-tube inspection every 5 years at both high- and very-high-
volume FMPs, and every 10 years at low-volume FMPs. Very-low volume 
FMPs would continue to be exempt. The BLM would also add a requirement 
for an initial basic meter-tube inspection for high- and very-high-
volume FMPs.
    Under proposed Sec.  3175.80(k)(3), provisions would be added to 
identify a required course of action based on the results of the basic 
meter-tube inspection. If the only issue identified on a high- or very-
high-volume FMP is an obstruction, proposed paragraph (i) would only 
require the operator to remove the obstruction; a detailed inspection 
would no longer be required. Proposed paragraph (ii) would only require 
the operator to clean the meter tube at low-volume FMPs if the basic 
meter-tube inspection identified a buildup of foreign substances. If 
the basic meter-tube inspection at a high- or very-high-volume FMP 
revealed pitting or a buildup of foreign substances, then the operator 
would have to perform a detailed meter-tube inspection.
    Proposed Sec.  3175.92, Verification and calibration of mechanical 
recorders. Proposed Sec.  3175.92(e)(1) would change the amount of time 
an operator has to notify the BLM prior to performing a verification 
after installation or following a repair. This rule would change the 
timeframe to 1 business day. The existing regulation requires a minimum 
of a 72-hour notice prior to performing the verification. The change to 
1 business day would allow operators to provide a more accurate 
notification.
    Proposed Sec.  3175.92(e)(2) would modify the timeframe for 
notifying the BLM of routine verification. Currently, operators must 
notify the AO at least 72 hours before performing a verification or 
submit a monthly or quarterly schedule of verifications. The BLM is 
proposing to modify the requirement to allow operators to either 
provide at least 72-hours' notice to the AO or submit a list of FMPs 
that the operator plans to verify over the next month or next quarter. 
The operator would no longer have to notify the BLM or submit a 
schedule of when each FMP would be verified. This list would show all 
verifications planned for that month or quarter, but not the specific 
day for each location.
    Proposed Sec.  3175.101, Installation and operation of electronic 
gas measurement systems. Existing and proposed Sec.  3175.101 define 
the installation and operation requirements of EGM systems. The 
proposed rule would clarify parts of the requirements for the 
connection of EGM devices and modify the on-site information 
requirements.
    Proposed new Sec.  3175.101(b)(4) would modify the existing 
requirement that operators display the software version at the FMP 
location. The proposed language would limit that requirement to high- 
and very-high volume FMPs. The BLM feels that the current requirement 
imposes an undue burden on operators.
    Proposed new Sec.  3175.101(b)(6) would modify a provision that 
requires operators to either display previous-period averages for 
differential pressure, static pressure, and temperature, or post a QTR 
on-site that is no more than 31 days old. The BLM is proposing a 
modification to the QTR posting requirement in the existing 
regulations. Instead of requiring operators to post recent QTRs at 
every location that does not have a flow computer capable of displaying 
the required average values, the BLM would require operators to submit 
the most recent QTR when the BLM requests it.
    Proposed Sec.  3175.101(c)(3) would allow for operators to provide 
either the FMP elevation or the atmospheric pressure at the FMP. The 
BLM is proposing to allow atmospheric pressure to be posted at the FMP 
instead of meter elevation because either value will allow the BLM to 
verify the flow computer.
    Proposed Sec.  3175.101(c)(13) would add a requirement that the 
operator post the last meter-tube inspection date. The BLM is proposing 
to add this requirement in order to allow BLM inspectors to verify that 
the operator is inspecting the meter tube at the frequency required 
under proposed Sec.  3175.80(l) and (m). The operator would post either 
the last basic meter-tube inspection date or the last detailed meter-
tube inspection date, whichever is more recent.
    Proposed Sec.  3175.102, Verification and calibration of electronic 
gas measurement system. Existing and proposed Sec.  3175.102 define the 
verification and calibration requirements for EGM systems. The proposed 
update would modify and clarify this section, with a particular focus 
on the methods used to determine atmospheric pressure, verification 
frequency, stability and drift, reporting requirements. The proposed 
rule would also address confusion with respect to notification 
requirements.
    Proposed Sec.  3175.104, Logs and records. Existing Sec.  3175.104 
defines the requirements for records and logs pertaining to several 
categories of equipment. The BLM has determined that the level of 
detail required in the current regulation is beyond the capabilities of 
many operators' flow computers. The proposed regulation would modify 
the existing regulation to

[[Page 56005]]

allow for the use of existing equipment while preserving accountability 
requirements.
    Proposed Sec.  3175.104 would require the operator to retain, and 
submit to the BLM upon request, quantity transaction records (QTRs), 
configuration logs, event logs, and an alarm log, all of which comply 
with standards of the American Petroleum Institute (which are 
incorporated by reference in the proposed rule).
    Proposed Sec.  3175.113, Spot samples--general requirements. The 
BLM is proposing to modify this requirement to allow operators to 
submit a list of FMPs that the operator plans to sample over the next 
month or next quarter. The operator would no longer have to notify the 
BLM or submit a schedule of when each FMP would be sampled. The BLM 
believes the list of wells an operator intends to sample provides 
enough information to prioritize which gas samplings the BLM should 
witness.
    Proposed Sec.  3175.113(c)(3) would allow operators to seek 
approval from the PMT for alternative methods of cleaning sample 
cylinders.
    Under the proposed rule, the BLM would remove Sec.  3175.113(d)(5) 
and (d)(6) of the existing regulations and replace them with different 
requirements (Sec.  3175.113(d)(5) through (d)(8)). Operators have 
expressed concern that the existing requirement not only increases 
their documentation burdens, but can also be difficult, if not 
impossible, to achieve. In 2018, an industry group developed a standard 
operating procedure (SOP) that contained a number of objective measures 
to help ensure quality control when using a portable GC. The BLM 
recommended the use of this SOP in Washington Office Instruction 
Memorandum (IM) 2018-069. The proposed rule would incorporate many of 
the recommendations that were included in the SOP.
    Proposed Sec.  3175.115, Spot samples--frequency. The BLM would 
delete existing Sec.  3175.115(b)(5), which requires operators to 
install composite samplers or on-line GCs at very-high-volume FMPs when 
the BLM determines that the required level of average annual heating 
value uncertainty at an FMP cannot be achieved through spot sampling. 
The BLM is proposing to delete this requirement because it believes 
that the proposed increase in average annual heating value uncertainty 
would render this requirement largely unnecessary.
    Proposed Sec.  3175.115(d) would increase the amount of time 
operators would have to install a composite sampling system or on-line 
GC from 30 days after the due date of the next sample to 90 days after 
the due date of the next sample. This proposed change is based on 
industry concerns that the lead-time operators need to plan for, order, 
and install on-line GCs or composite sampling systems is commonly 
greater than 30 days. During this 90-day period an operator would not 
have to take spot samples.
    Proposed Sec.  3175.116, Composite sampling methods. Proposed Sec.  
3175.116(c) would add a requirement that sample cylinders used in 
composite sampling systems comply with the general spot-sample 
requirements under Sec.  3175.113(c). The BLM believes that the 
omission of these requirements for composite sample systems was an 
oversight and will add a slight increase in burdens to industry, 
although they represent common industry best practice. To reduce 
unnecessary burden on industry while still meeting the desired intent 
of a more detailed analysis, the BLM proposes to only require 
C9+ analysis. This change reduces the overall number of 
responses for this requirement.
    Proposed Sec.  3175.118, Gas chromatograph requirements. Under 
existing Sec.  3175.118(e) operators are required to perform extended 
analyses in accordance with GPA 2286-14. This proposed rule would 
remove this requirement.
    Proposed Sec.  3175.120, Gas analysis report requirements. Proposed 
Sec.  3175.120(a)(18) would remove the requirement that the gas 
analysis report must show the un-normalized mole percent for each 
component analyzed and instead only require the sum of the un-
normalized mole percents from all analyzed components. The BLM does not 
use this information and collecting it is an unnecessary burden on 
operators.
    Proposed Sec.  3175.125, Calculation of heating value and volume. 
Under proposed Sec.  3175.125(b)(1), the existing requirement for 
calculating and reporting an average heating value would only apply if 
a lease, unit PA, or CA has more than one FMP that doesn't yet have an 
FMP number. The BLM proposes this change to reduce unnecessary 
reporting burdens on industry by removing the requirement to report the 
average heating value for a lease, unit PA, or CA once the BLM assigns 
individual FMP numbers.
    Proposed Sec.  3175.140, Temporary measurement. The BLM is 
proposing to add a new section under Sec.  3175.140 to address 
temporary measurement. Temporary measurement is defined in 43 CFR 
3170.10 as a meter that is in place for less than 3 months. Temporary 
measurement typically applies to a gas meter that is part of a 
measurement skid used to measure the oil and gas from a newly drilled 
well before the permanent measurement facility is installed. The 
existing rule does not address temporary measurement.
    Under proposed Sec.  3175.140, a temporary gas meter would have to 
meet all the requirements of an FMP except for the routine 
verifications required for mechanical recorders and EGM systems, basic 
meter-tube inspections, and detailed meter-tube inspections.
    Some of the recordkeeping requirements in the proposed rule are 
``usual and customary'' within the meaning of 5 CFR 1320.3(b)(2), since 
they are commonly found in gas sales contracts and/or industry 
standards. Therefore, they are not among the ``burdens'' that must be 
disclosed under the Paperwork Reduction Act. Some other proposed 
activities in the regulations are usual and customary only in part. The 
burdens of those activities are analyzed to the extent they are not 
usual and customary.
    As part of our continuing effort to reduce paperwork and respondent 
burdens, we invite the public and other Federal agencies to comment on 
any aspect of this information collection, including:
    (1) Whether or not the collection of information is necessary for 
the proper performance of the functions of the agency, including 
whether or not the information will have practical utility;
    (2) The accuracy of our estimate of the burden for this collection 
of information, including the validity of the methodology and 
assumptions used;
    (3) Ways to enhance the quality, utility, and clarity of the 
information to be collected; and
    (4) Ways to minimize the burden of the collection of information on 
those who are to respond, including through the use of appropriate 
automated, electronic, mechanical, or other technological collection 
techniques or other forms of information technology, e.g., permitting 
electronic submission of response.
    Send your comments and suggestions on this information collection 
by the date indicated earlier.
    Written comments and recommendations for the proposed information 
collection should be sent on or before October 13, 2020 to 
www.reginfo.gov/public/do/PRAMain. Find the particular information 
collection by selecting ``Currently under Review--Open for Public 
Comments'' or by using the search function. If you submit comments to 
OMB on the IC activities in this proposed rule, you

[[Page 56006]]

should provide the BLM with a copy at one of the street addresses shown 
earlier in this proposed rule so that we can summarize all written 
comments and address them in the final rulemaking. Please do not submit 
to OMB comments that do not pertain to the proposed rule's IC burdens. 
The BLM is not obligated to consider or include in the Administrative 
Record for the final rule any comments, which do not relate to the 
information collection burdens, that you improperly direct to OMB.

National Environmental Policy Act

    The BLM has prepared a draft EA to determine whether this proposed 
rule would have a significant impact on the quality of the human 
environment under the National Environmental Policy Act of 1969 (NEPA) 
(42 U.S.C. 4321 et seq.). The draft EA will be shared with the public 
during the public comment period on the proposed rule. The BLM will 
respond to substantive comments on the EA. If the final EA supports the 
issuance of a Finding of No Significant Impact for the rule, the 
preparation of an environmental impact statement pursuant to the NEPA 
would not be required.
    The draft EA has been placed in the file for the BLM's 
Administrative Record for the rule at the address specified in the 
ADDRESSES section. The EA has also been posted in the docket for the 
rule on the Federal eRulemaking Portal: https://www.regulations.gov. In 
the Searchbox, enter ``RIN 1004-AE59'', click the ``Search'' button, 
open the Docket Folder, and look under Supporting Documents. The BLM 
invites the public to review the draft EA and suggests that anyone 
wishing to submit comments on the EA should do so in accordance with 
the instructions contained in the ``Public Comment Procedures'' section 
earlier.

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

    This proposed rule is not a significant energy action under the 
definition in Executive Order 13211. A statement of Energy Effects is 
not required.
    Section 4(b) of Executive Order 13211 defines a ``significant 
energy action'' as ``any action by an agency (normally published in the 
Federal Register) that promulgates or is expected to lead to the 
promulgation of a final rule or regulation, including notices of 
inquiry, advance notices of rulemaking, and notices of rulemaking: 
(1)(i) That is a significant regulatory action under Executive Order 
12866 or any successor order, and (ii) Is likely to have a significant 
adverse effect on the supply, distribution, or use of energy; or (2) 
That is designated by the Administrator of the Office of Information 
and Regulatory Affairs as a significant energy action.''
    The BLM reviewed the proposed rule, and we do not consider it to be 
a ``significant energy action'' as defined in Executive Order 13211. 
The BLM has found that the proposed rule would not be economically 
significant under Executive Order 12866. The proposed rule would revise 
certain requirements in the 2016 Final Rules in a manner that would 
reduce compliance burdens. While these savings are certainly beneficial 
to industry from both an operational and financial standpoint, the BLM 
finds that they are relatively minor when compared to industry net 
profits, and the changes are not expected to have an effect on the 
supply, distribution, or use of energy. Further, the Administrator of 
the Office of Information and Regulatory Affairs did not designate the 
proposed rule as a significant energy action.

Clarity of This Regulation (Executive Orders 12866, 12988, and 13563)

    We are required by Executive Orders 12866 (section 1(b)(12)), 12988 
(section 3(b)(1)(B)), and 13563 (section 1(a)), and by the Presidential 
Memorandum of June 1, 1988, to write all rules in plain language. This 
means that each rule must:
    (a) Be logically organized;
    (b) Use the active voice to address readers directly;
    (c) Use common, everyday words and clear language rather than 
jargon;
    (d) Be divided into short sections and sentences; and
    (e) Use lists and tables wherever possible.
    If you feel that we have not met these requirements, send us 
comments by one of the methods listed in the ADDRESSES section. To 
better help the BLM revise the rule, your comments should be as 
specific as possible. For example, you should tell us the numbers of 
the sections or paragraphs that you find unclear, which sections or 
sentences are too long, the sections where you feel lists or tables 
would be useful, etc.

Authors

    The principal authors of this proposed rule are: Michael McLaren, 
Richard Estabrook (Retired), Beth Poindexter, Stormy Phillips 
(Contractor), Michael Ford, and Barbara Sterling of the BLM Washington 
Office; assisted by Abdelgadir Elmadani of the BLM Eastern States 
Office, Gail Clayton of the BLM Farmington, New Mexico Field Office, 
Christopher DeVault of the BLM Montana State Office, Laura Lozier of 
the BLM Lander, Wyoming Field Office, Noell Sturdevant and Thomas 
Zelenka of the BLM New Mexico State Office, Matthew Wokosin of the BLM 
Dickinson, North Dakota Field Office, Faith Bremner of the BLM's 
Division of Regulatory Affairs, Michael Wade, Gregory Muehl and James 
Tichenor of the BLM Washington Office and by the Department of the 
Interior's Office of the Solicitor.

List of Subjects in 43 CFR Part 3170

    Administrative practice and procedure, Flaring, Government 
contracts, Incorporation by reference, Indians-lands, Immediate 
assessments, Mineral royalties, Oil and gas exploration, Oil and gas 
measurement, Public lands--mineral resources, Reporting and record 
keeping requirements, Royalty-free use, Venting.

Casey Hammond,
Principal Deputy Assistant Secretary, Exercising the Authority of the 
Assistant Secretary, Land and Minerals Management.

43 CFR Chapter II

    For the reasons set out in the preamble, the Bureau of Land 
Management proposes to amend 43 CFR part 3170 as follows:

PART 3170--ONSHORE OIL AND GAS PRODUCTION

0
1. The authority citation for part 3170 continues to read as follows:

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

0
2. Revise subpart 3170 to read as follows:
Subpart 3170--Onshore Oil and Gas Production: General
Sec.
3170.1 Authority.
3170.2 Scope.
3170.10 Definitions and acronyms.
3170.20 Prohibitions against by-pass and tampering.
3170.30 Alternative measurement equipment and procedures.
3170.40 Variances.
3170.50 Required recordkeeping, records retention, and records 
submission.
3170.60 Appeal procedures.
3170.70 Enforcement.

Subpart 3170--Onshore Oil and Gas Production: General


Sec.  3170.1   Authority.

    The authorities for promulgating the regulations in this part are 
the Mineral Leasing Act, 30 U.S.C. 181 et seq.; the Mineral Leasing Act 
for Acquired Lands, 30 U.S.C. 351 et seq.; the Federal Oil and Gas 
Royalty Management Act,

[[Page 56007]]

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, 43 U.S.C. 1701 et seq. Each of these statutes gives 
the Secretary the authority to promulgate necessary and appropriate 
rules and regulations governing Federal and Indian (except Osage Tribe) 
oil and gas leases. See 30 U.S.C. 189; 30 U.S.C. 359; 25 U.S.C. 396d; 
25 U.S.C. 396; 25 U.S.C. 2107; and 43 U.S.C. 1740. Under Secretary's 
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 on Indian lands. 
235 DM 1.1.K.


Sec.  3170.2   Scope.

    The regulations in this part apply to:
    (a) All Federal onshore and Indian oil and gas leases (other than 
those of the Osage Tribe);
    (b) Indian Mineral Development Act (IMDA) agreements for oil and 
gas, unless specifically excluded in the agreement or unless the 
relevant provisions of the rule are inconsistent with the agreement;
    (c) Leases and other business agreements for the development of 
tribal energy resources under a Tribal Energy Resource Agreement 
entered into with the Secretary, unless specifically excluded in the 
lease, other business agreement, or Tribal Energy Resource Agreement;
    (d) State or private tracts committed to a federally approved unit 
or communitization agreement (CA) as defined by or established under 43 
CFR subpart 3105 or 43 CFR part 3180;
    (e) All onshore facility measurement points where oil or gas 
produced from the leases or agreements identified earlier in this 
section is measured; and
    (f) Measurement points on BLM-managed gas storage agreements.


Sec.  3170.10   Definitions and acronyms.

    (a) As used in this part, the term:
    Alarm log means a log for recording any system alarm, user-defined 
alarm, or error conditions (such as out-of-range temperature or 
pressure) that occur. This includes a description of each alarm 
condition and the times the condition occurred and cleared.
    Allocated or allocation means a method or process by which 
production is measured at a central point and apportioned to the 
individual lease, or unit Participating Area (PA), or CA from which the 
production originated.
    Audit trail means all source records necessary to verify and 
recalculate the volume and quality of oil or gas production measured at 
a facility measurement point (FMP) and reported to the Office of 
Natural Resources Revenue (ONRR).
    Authorized officer (AO) has the same meaning as defined in 43 CFR 
3000.0-5.
    Averaging period means the previous 12 months or the life of the 
meter, whichever is shorter. For Facility Measurement Points (FMPs) 
that measure production from a newly drilled well, the averaging period 
excludes production from that well that occurred in or before the first 
full month of production. (For example, if an oil FMP and a gas FMP 
were installed to measure only the production from a new well that 
first produced on April 10, the averaging period for this FMP would not 
include the production that occurred in April (partial month) and May 
(full month) of that year.)
    Bias means a shift in the mean value of a set of measurements away 
from the true value of what is being measured.
    By-pass means any piping or other arrangement around or avoiding a 
meter or other measuring device or method (or component thereof) at an 
FMP that allows oil or gas to flow without accountability. Equipment 
that permits the changing of the orifice plate of a gas meter without 
bleeding the pressure off the gas meter run (e.g., senior fitting) is 
not a by-pass. Piping around a meter with a double block and bleed 
valve (or a series of valves that ensure valve integrity) that must be 
effectively sealed under Sec.  3173.20, could be approved by the AO or 
be part of a PMT-approved process and would not be a by-pass.
    Commingling, for production accounting and reporting purposes, 
means combining, before the point of royalty measurement, production 
from more than one lease, unit PA, or CA, or production from one or 
more leases, unit PAs, or CAs with production from State, local 
governmental, or private properties that are outside the boundaries of 
those leases, unit PAs, or CAs. Combining production from multiple 
wells within a single lease, unit PA, or CA, or combining production 
downhole from different geologic formations within the same lease, unit 
PA, or CA, is not considered commingling for production accounting 
purposes.
    Communitization agreement (CA) means an agreement to combine a 
lease, or a portion of a lease that cannot otherwise be independently 
developed and operated in conformity with an established well spacing 
or well development program, with other tracts for purposes of 
cooperative development and operations.
    Communitized area means the area committed to a BLM approved 
communitization agreement.
    Condition of Approval (COA) means a site-specific requirement 
included in the approval of an application that may limit or modify the 
specific actions covered by the application. Conditions of approval may 
minimize, mitigate, or prevent impacts to public lands or resources.
    Configuration log means a record that contains and identifies all 
selected flow parameters used in the generation of a quantity 
transaction record.
    Days means consecutive calendar days, unless otherwise indicated.
    Event log means an electronic record of all exceptions and changes 
to the flow parameters contained within the configuration log that have 
an impact on a quantity transaction record.
    Facility means:
    (i) A site and associated equipment used to process, treat, store, 
or measure production from or allocated to a Federal or Indian lease, 
unit PA, or CA that is located upstream of or at (and including) the 
approved point of royalty measurement; and
    (ii) A site and associated equipment used to store, measure, or 
dispose of produced water that is located on a lease, unit, or 
communitized area.
    Facility measurement point (FMP) means a point where oil or gas 
produced from a Federal or Indian lease, unit PA, CA, or gas storage 
agreement involving production of native gas or oil is measured and the 
measurement affects the calculation of the volume or quality of 
production on which royalty is owed or a point where fluid is measured 
on a Federal or Indian storage agreement and the measurement affects 
the calculation of the volume or quality of fluid on which injection 
and withdrawal fees are owed. An FMP includes all measurement points 
relevant to determining the allocation of production to Federal or 
Indian leases, unit PAs, or CAs. However, allocation facilities that 
are part of a commingling and allocation approval under Sec.  3173.71 
or that are part of a commingling and allocation approval approved 
after July 9, 2013, are not FMPs. An FMP must be located on the lease, 
unit, or

[[Page 56008]]

communitized area unless the BLM approves measurement off the lease, 
unit, or CA (see 43 CFR 3162.7-2, 3162.7-3, 3173.71, 3173.72, 3173.92, 
and 3173.93). An FMP cannot be located at the tailgate of a gas 
processing plant located off the lease, unit, or CA. Measurement points 
for flared volumes are not FMPs.
    FMP number means a number assigned by the BLM to the FMP after 
review of an FMP application.
    Gas means any fluid, either combustible or noncombustible, 
hydrocarbon or non-hydrocarbon, that has neither independent shape nor 
volume, but tends to expand indefinitely and exists in a gaseous state 
under metered temperature and pressure conditions.
    Incident of Noncompliance (INC) means a BLM-issued documentation 
that identifies violations and notifies the recipient of required 
corrective actions.
    Land description means a location surveyed in accordance with the 
U.S. Department of the Interior's Manual of Surveying Instructions 
(2009), as amended, that includes the quarter-quarter section, section, 
township, range, and principal meridian, or other authorized survey 
designation acceptable to the AO, such as metes-and-bounds, or latitude 
and longitude.
    Lease has the same meaning as defined in 43 CFR 3160.0-5.
    Lessee has the same meaning as defined in 43 CFR 3160.0-5.
    Measurement data system (MDS) means a system that captures and 
stores source records from the flow computer at an FMP. The MDS is used 
by operators to validate, balance, and report volume and quality. An 
MDS does not include Supervisory Control and Data Acquisition (SCADA) 
systems.
    NIST traceable means an unbroken and documented chain of 
comparisons relating measurements from field or laboratory instruments 
to a known standard maintained by the National Institute of Standards 
and Technology (NIST).
    Notice to lessees and operators (NTL) has the same meaning as 
defined in 43 CFR 3160.0-5.
    Notify means to contact by any method including, but not limited 
to, electronically (e.g., email), in person, by telephone, by Form 
3160-5 (Sundry Notice), by letter.
    Off-lease measurement means measurement at an FMP that is not 
located on the lease, unit, or communitized area from which the 
production came.
    Oil means a mixture of hydrocarbons that exists in the liquid phase 
at the temperature and pressure at which it is measured. Condensate is 
considered to be oil for purposes of this part. Gas liquids extracted 
from a gas stream upstream of the approved point of royalty measurement 
are considered to be oil for purposes of this part.
    (i) Clean oil or Pipeline oil means oil that is of such quality 
that it is acceptable to normal purchasers.
    (ii) Slop oil means oil that is of such quality that it is not 
acceptable to normal purchasers and is usually sold to oil reclaimers. 
Oil that can be made acceptable to normal purchasers through special 
treatment that can be economically provided at existing or modified 
facilities or using portable equipment at or upstream of the FMP is not 
slop oil.
    (iii) Waste oil means oil that has been determined by the AO or 
authorized representative to be of such quality that it cannot be 
treated economically and put in a marketable condition with existing or 
modified lease facilities or portable equipment, cannot be sold to 
reclaimers, and has been determined by the AO to have no economic 
value.
    Operator has the same meaning as defined in 43 CFR 3160.0-5.
    Participating area (PA) has the same meaning as defined in 43 CFR 
3180.0-5.
    Permanent measurement facility means all equipment used on-site for 
3 months or longer, that is used for the purposes of determining the 
quantity or quality of production, or for the storage of production, 
and which meets the definition of an FMP under this section.
    Point of royalty measurement means a BLM-approved FMP at which the 
volume and quality of oil or gas which is subject to royalty is 
measured. The point of royalty measurement is to be distinguished from 
meters that determine only the allocation of production to particular 
leases, unit PAs, CAs, or non-Federal and non-Indian properties. The 
point of royalty measurement is also known as the point of royalty 
settlement.
    Production means oil or gas removed from a well bore and any 
products derived therefrom.
    Production Measurement Team (PMT) means a panel of members from the 
BLM (which may include BLM-contracted experts) that reviews changes in 
industry measurement technology, methods, and standards to determine 
whether regulations should be updated, and provides guidance on 
measurement technologies and methods not addressed in current 
regulation.
    Purchaser means any person or entity who legally takes ownership of 
oil or gas in exchange for financial or other consideration.
    Source record means any unedited and original record, document, or 
data that is used to determine volume and quality of production, 
regardless of format or how it was created or stored (e.g., paper or 
electronic). It includes, but is not limited to, raw and unprocessed 
data (e.g., instantaneous and continuous information used by flow 
computers to calculate volumes); gas charts; measurement tickets; 
calibration, verification, prover, and configuration reports; pumper 
and gauger field logs; volume statements; event logs; seal records; and 
gas analyses.
    Statistically significant describes a difference between two data 
sets that exceeds the threshold of significance.
    Tampering means any deliberate adjustment or alteration to a meter 
or measurement device, appropriate valve, or measurement process that 
could introduce bias into the measurement or affect the BLM's ability 
to independently verify volumes or qualities reported.
    Temporary measurement facility means an FMP in place for less than 
3 months. A temporary measurement facility will not receive an FMP 
number.
    Threshold of significance means the maximum difference between two 
data sets (a and b) that can be attributed to uncertainty effects. The 
threshold of significance is determined as follows:
[GRAPHIC] [TIFF OMITTED] TP10SE20.006

where:

Ts = Threshold of significance, in percent
Ua = Uncertainty (95 percent confidence) of data set a, 
in percent
Ub = Uncertainty (95 percent confidence) of data set b, 
in percent

    Total observed volume (TOV) means the total measured volume of all 
oil, sludges, sediment and water, and free water at the measured or 
observed temperature and pressure.
    Transporter means any person or entity who legally moves or 
transports oil or gas from an FMP.
    US well number means a unique, permanent, numeric identifier 
assigned to each well drilled for oil and gas in the United States, 
which includes the completion code. The US well number replaces the old 
API well number.
    Uncertainty means the statistical range of error that can be 
expected between a measured value and the true value of what is being 
measured. Uncertainty is determined at a 95 percent confidence level 
for the purposes of this part.
    Unit means the land within a unit area as defined in 43 CFR 3180.0-
5.

[[Page 56009]]

    Unit PA means the unit participating area, if one is in effect, the 
exploratory unit if there is no associated participating area, or an 
enhanced recovery unit.
    Variance means an approved alternative to a provision or standard 
of a regulation, Onshore Oil and Gas Order, or NTL.
    (b) As used in this part, the following additional acronyms apply:
    API means American Petroleum Institute.
    BLM means the Bureau of Land Management.
    Btu means British thermal unit.
    CMS means Coriolis Measurement System.
    LACT means lease automatic custody transfer.
    OGOR means Oil and Gas Operations Report (Form ONRR-4054 or any 
successor report).
    ONRR means the Office of Natural Resources Revenue, U.S. Department 
of the Interior, and includes any successor agency.
    S&W means sediment and water.
    WIS means Well Information System or any successor electronic 
filing system.


Sec.  3170.20   Prohibitions against by-pass and tampering.

    (a) All by-passes are prohibited.
    (b) Tampering with any measurement device, component of a 
measurement device, or measurement process is prohibited.
    (c) Any by-pass or tampering with a measurement device, component 
of a measurement device, or measurement process may, together with any 
other remedies provided by law, result in an assessment of civil 
penalties, pursuant to 30 U.S.C. 1719 and 43 CFR 3163.2, for knowingly 
or willfully:
    (1) Taking, removing, transporting, using, or diverting oil or gas 
from a lease site without valid legal authority; or
    (2) Preparing, maintaining, or submitting false, inaccurate, or 
misleading reports, records, or information.


Sec.  3170.30   Alternative measurement equipment and procedures.

    (a) Any operator or manufacturer may request approval for the use 
of alternate oil or gas measurement equipment or measurement methods. 
Any operator or manufacturer requesting such approval must submit to 
the BLM performance data, actual field test results, laboratory test 
data, or any other supporting data or evidence requested by the BLM 
demonstrating that the proposed alternate oil or gas measurement 
equipment or method would meet or exceed the objectives of the 
applicable minimum standards of part 3170 and would not affect royalty 
income, production accountability, or site security.
    (b) The PMT will review the submitted data to ensure that the 
alternate oil and gas measurement equipment or method meets the 
standards of part 3170. The PMT will make a recommendation, including 
conditions of approval, to the BLM to approve use of the equipment or 
method that the PMT determines meets the standards of part 3170. If the 
PMT recommends, and the BLM approves, new measurement equipment or 
methods, the BLM will post the make, model, range or software version 
(as applicable), or method on the BLM website www.blm.gov as being 
appropriate for use at an FMP for oil or gas 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.  3170.40 may not be used as an avenue for approving new 
measurement technology, methods, or equipment. Approval of alternative 
oil or gas measurement equipment or methods must be obtained by 
following the requirements of this section.


Sec.  3170.40   Variances.

    (a) Any party subject to a requirement of a regulation in this part 
may request a variance from that requirement.
    (1) A request for a variance must include the following:
    (i) Identification of the specific requirement from which the 
variance is requested;
    (ii) Identification of the length of time for which the variance is 
requested, if applicable;
    (iii) An explanation of the need for the variance;
    (iv) A detailed description of the proposed alternative means of 
compliance;
    (v) A showing that the proposed alternative means of compliance 
will produce a result that meets or exceeds the objectives of the 
applicable requirement for which the variance is requested; and
    (vi) The FMP number(s) for which the variance is requested, if 
applicable.
    (2) A request for a variance must be submitted as a separate 
document from any plans or applications. A request for a variance that 
is submitted as part of a master development plan, application for 
permit to drill, right-of-way application, or application for approval 
of other types of operations, rather than submitted separately, will 
not be considered. Approval of a plan or application that contains a 
request for a variance does not constitute approval of the variance. A 
separate request for a variance may be submitted simultaneously with a 
plan or application. For plans or applications that are contingent upon 
the approval of the variance request, the BLM encourages the 
simultaneous submission of the variance request and the plan or 
application.
    (3) The party requesting the variance must submit a Form 3160-5, 
Sundry Notices and Reports on Wells (Sundry Notice) electronically to 
the BLM office having jurisdiction over the lease, unit, or CA, using 
WIS, unless the submitter:
    (i) Is a small business, as defined by the U.S. Small Business 
Administration; and
    (ii) Does not have access to the internet.
    (4) The AO, after considering all relevant factors, may approve the 
variance, or approve it with COAs, only if the AO determines that:
    (i) The proposed alternative means of compliance meets or exceeds 
the objectives of the applicable requirement(s) of the regulation;
    (ii) Approving the variance will not adversely affect royalty 
income and production accountability; and
    (iii) Issuing the variance is consistent with maximum ultimate 
economic recovery, as defined in 43 CFR 3160.0-5.
    (5) The decision whether to grant or deny the variance request is 
entirely within the BLM's discretion.
    (6) A variance from the requirements of a regulation in this part 
does not constitute a variance from provisions of other regulations, 
including Onshore Oil and Gas Orders.
    (b) The BLM reserves the right to rescind a variance or modify any 
COA of a variance due to changes in Federal law, technology, 
regulation, BLM policy, field operations, noncompliance, or other 
reasons. The BLM will provide a written justification if it rescinds a 
variance or modifies a COA.
    (c) The procedures for requesting and granting a variance under 
this section must not be used as an avenue for approving new 
measurement technology, methods, or equipment. Approval of alternative 
oil and gas measurement equipment or methods must be obtained through 
the PMT, following the requirements under Sec.  3170.30.


Sec.  3170.50   Required recordkeeping, records retention, and records 
submission.

    (a) Lessees, operators, purchasers, transporters, and any other 
person

[[Page 56010]]

directly involved in producing, transporting, purchasing, selling, or 
measuring oil or gas through the point of royalty measurement or the 
point of first sale, whichever is later, must retain all records, 
including source records, that are relevant to determining the quality, 
quantity, disposition, and verification of production attributable to 
Federal or Indian leases for the periods prescribed in paragraphs (c) 
through (e) of this section.
    (b) This retention requirement applies to records generated during 
or for the period for which the lessee or operator has an interest in 
or conducted operations on the lease, or in which a person is involved 
in transporting, purchasing, or selling production from the lease.
    (c) For Federal leases, and units or CAs that include Federal 
leases, but do not include Indian leases, the record holder must 
maintain records for:
    (1) Seven years after the records are generated; unless,
    (2) A judicial proceeding or demand involving such records is 
timely commenced, in which case the record holder must maintain such 
records until the final nonappealable decision in such judicial 
proceeding is made, or with respect to that demand is rendered, unless 
the Secretary or their designee or the applicable delegated State 
authorizes in writing an earlier release of the requirement to maintain 
such records.
    (d) For Indian leases, and units or CAs that include Indian leases, 
but do not include Federal leases, the record holder must maintain 
records for:
    (1) Six years after the records are generated; unless,
    (2) The Secretary or their designee notifies the record holder that 
the Department of the Interior has initiated or is participating in an 
audit or investigation involving such records, in which case the record 
holder must maintain such records until the Secretary or their designee 
releases the record holder from the obligation to maintain the records.
    (e) For units and communitized areas that include both Federal and 
Indian leases, 6 years after the records are generated. If the 
Secretary or their designee has notified the record holder within those 
6 years that an audit or investigation involving such records has been 
initiated, then:
    (1) If a judicial proceeding or demand is commenced within 7 years 
after the records are generated, the record holder must retain all 
records regarding production from the lease, unit PA, or CA until the 
final nonappealable decision in such judicial proceeding is made, or 
with respect to that demand is rendered, unless the Secretary or their 
designee authorizes in writing a release of the requirement to maintain 
such records before a final nonappealable decision is made or rendered.
    (2) If a judicial proceeding or demand is not commenced within 7 
years after the records are generated, the record holder must retain 
all records regarding production from the unit or communitized area 
until the Secretary or their designee releases the record holder from 
the obligation to maintain the records;
    (f) The lessee, operator, purchaser, or transporter must maintain 
an audit trail.
    (g) All records, including source records, that are used to 
determine quality, quantity, disposition, and verification of 
production attributable to a Federal or Indian lease, unit PA, or CA, 
must include the FMP number or the lease, unit PA, or CA number, land 
description along with a unique equipment identifier (e.g., a unique 
tank identification number and meter ID), and the name of the company 
that created the record. For all facilities existing prior to the 
assignment of an FMP number, all records must include the following 
information:
    (1) The name of the operator;
    (2) The lease, unit PA, or CA number;
    (3) The well or facility name and number; and
    (4) Land description.
    (h) Upon request of the AO, the operator, purchaser, or transporter 
must provide such records to the AO as may be required by regulation, 
written order, Onshore Order, NTL, or COA.
    (i) All records must be legible.
    (j) All records requiring a signature must also have the signer's 
printed name.


Sec.  3170.60   Appeal procedures.

    (a) BLM decisions, orders, assessments, or other actions under the 
regulations in this part are administratively appealable under the 
procedures prescribed in 43 CFR 3165.3(b), 3165.4, and part 4.
    (b) For any recommendation made by the PMT, and approved by the 
BLM, a party affected by such recommendation may file a request for 
discretionary review by the Assistant Secretary for Land and Minerals 
Management. The Assistant Secretary may delegate this review function 
as they deem appropriate, in which case the affected party's 
application for discretionary review must be made to the person or 
persons to whom the Assistant Secretary's review function has been 
delegated.


Sec.  3170.70   Enforcement.

    Noncompliance with any of the requirements of this part or any 
order issued under this part may result in enforcement actions under 43 
CFR subpart 3163 or any other remedy available under applicable law or 
regulation.
0
3. Revise subpart 3173 to read as follows:
Subpart 3173--Requirements for Site Security and Production Handling
Sec.
3173.10 Definitions and acronyms.
3173.20 Storage and sales facilities--seals.
3173.21 Oil measurement system components--seals.
3173.22 Federal seals.
3173.30 Removing production from tanks for sale and transportation 
by truck.
3173.31 Water-draining operations.
3173.32 Hot oiling, clean-up, and completion operations.
3173.40 Report of theft or mishandling of production.
3173.41 Required recordkeeping for inventory and seal records.
3173.43 Data submission and notification requirements.
3173.50 Site facility diagram.
3173.60 Applying for a facility measurement point number.
3173.61 Requirements for approved facility measurement points.
3173.70 Conditions for commingling and allocation approval (surface 
and downhole).
3173.71 Applying for a commingling and allocation approval.
3173.72 Existing commingling and allocation approvals.
3173.73 Relationship of a commingling and allocation approval to 
royalty-free use of production.
3173.74 Modification of a commingling and allocation approval.
3173.75 Effective date of a commingling and allocation approval.
3173.76 Terminating a commingling and allocation approval.
3173.80 Combining production downhole in certain circumstances.
3173.90 Requirements for off-lease measurement.
3173.91 Applying for off-lease measurement.
3173.92 Effective date of an off-lease measurement approval.
3173.93 Existing approved off-lease measurement.
3173.94 Relationship of off-lease measurement approval to royalty-
free use of production.
3173.95 Termination of off-lease measurement approval.
3173.96 Instances not constituting off-lease measurement, for which 
no approval is required.
3173.190 Immediate assessments for certain violations.
Appendix A to Subpart 3173--Examples of Site Facility Diagrams

[[Page 56011]]

Subpart 3173--Requirements for Site Security and Production 
Handling


Sec.  3173.10   Definitions and acronyms.

    (a) As used in this subpart, the term:
    Access means the ability to:
    (i) Add liquids to or remove liquids from any tank or piping 
system, through a valve or combination of valves or by moving liquids 
from one tank to another tank; or
    (ii) Enter any component in a measuring system affecting the 
accuracy of the measurement of the quality or quantity of the liquid 
being measured.
    Appropriate valves means those valves that provide access to 
production before it is measured for sales and that are subject to the 
sealing requirements of this subpart.
    Authorized representative (AR) has the same meaning as defined in 
43 CFR 3160.0-5.
    Business day means any day Monday through Friday, excluding Federal 
holidays.
    Commingling and allocation approval (CAA) means a formal allocation 
agreement to combine production from two or more sources (leases, unit 
PAs, CAs, or non-Federal or non-Indian properties) before that product 
reaches an FMP.
    Completed means when oil or gas is first produced through wellhead 
equipment from the ultimate producing interval after casing has been 
run.
    Economically marginal property means a lease, unit PA, or CA--
    (i) For which:
    (A) The expected revenue (minus any associated operating costs) 
generated from crude-oil or natural-gas production volumes on that 
property is not sufficient to cover the cost of the capital 
expenditures based on the least expensive practicable alternative 
average cost to construct facilities typical for the area required to 
achieve measurement of non-commingled production of oil or gas from 
that property over a payout period of 18 months; or
    (B) The royalty net present value (RNPV) is less than the cost of 
the capital expenditures for the least expensive, practicable 
alternative required to achieve measurement of non-commingled 
production of oil or gas from that property.
    (ii) Both the payout period and the RNPV are determined separately 
for each lease, unit PA, or CA oil or gas FMP. Oil FMPs are evaluated 
using estimated revenue (minus taxes and operating costs) from crude 
oil production, as defined in this section, while gas FMPs are 
evaluated using estimated revenue (minus taxes and operating costs) 
from natural gas production, as defined in this section.
    Effectively sealed means the placement of a seal in such a manner 
that the sealed component cannot be accessed, moved, or altered without 
breaking the seal.
    Free water means the measured volume of water that is present in a 
container and that is not in suspension in the contained liquid at 
observed temperature.
    Maximum ultimate economic recovery has the same meaning as defined 
in 43 CFR 3160.0-5.
    Mishandling means failing to measure or account for removal of 
production from a facility.
    Payout period means the time required, in months, for the cost of 
an investment in an oil or gas FMP for a specific lease, unit PA, or CA 
to be covered by the nominal revenue earned from crude oil production, 
for an oil FMP, or natural gas production, for a gas FMP, minus taxes, 
royalties, and any operating and variable costs. The payout period is 
determined separately for each oil or gas FMP for a given lease, unit 
PA, or CA.
    Piping means a tubular system (e.g., metallic, plastic, fiberglass, 
or rubber) used to move fluids (liquids and gases).
    Production phase means that event during which oil is delivered 
directly to or through production equipment to the storage facilities 
and includes all operations at the facility other than those defined by 
the sales phase.
    Propagation of uncertainty, in statistics, means the effect of 
variables' uncertainties on the uncertainty of a function based on 
those variables.
    Royalty Net Present Value (RNPV) means the net present value of all 
Federal or Indian royalties paid on revenue earned from crude oil 
production or natural gas production from an oil or gas FMP for a given 
lease, unit PA, or CA over the expected life of metering equipment that 
must be installed for that lease, unit PA, or CA to achieve non-
commingled measurement.
    Sales phase means that event during which oil is removed from 
storage facilities for sale at an FMP.
    Seal means a uniquely numbered device that completely secures 
either a valve or those components of a measuring system that affect 
the quality or quantity of the oil being measured.
    (b) As used in this subpart, the following additional acronyms 
apply:
    BIA means the Bureau of Indian Affairs.
    BMP means Best Management Practice.


Sec.  3173.20   Storage and sales facilities--seals.

    (a) All lines entering or leaving any oil storage tank must have 
valves capable of being effectively sealed during the production and 
sales phases unless otherwise provided under this subpart. Appropriate 
valves must be in an operable condition and accurately reflect whether 
the valve is open or closed. During the production phase, all 
appropriate valves that allow unmeasured production to be removed from 
storage must be effectively sealed in the closed position. During any 
other phase (sales, water drain, or hot oiling), and prior to taking 
the top tank gauge measurement, all appropriate valves that allow 
unmeasured production to enter or leave the sales tank must be 
effectively sealed in the closed position (see appendix A to subpart 
3173). Each unsealed or ineffectively sealed appropriate valve is a 
separate violation.
    (b) Valves or combinations of valves and tanks that provide access 
to the production before it is measured for sales are considered 
appropriate valves and are subject to the seal requirements of this 
subpart (see Appendix A to subpart 3173). If there is more than one 
valve on a line from a tank, the valve closest to the tank must be 
sealed. All appropriate valves must be in an operable condition and 
accurately reflect whether the valve is open or closed.
    (c) The following are not considered appropriate valves and are not 
subject to the sealing requirements of this subpart:
    (1) Valves on production equipment (e.g., separator, dehydrator, 
gun barrel, or wash tank);
    (2) Valves on water tanks, provided that the possibility of access 
to production in the sales and storage tanks does not exist through a 
common circulating, drain, overflow, or equalizer system;
    (3) Valves on tanks that contain oil that has been determined by 
the AO or AR to be waste or slop oil;
    (4) Sample cock valves used on piping or tanks with a Nominal Pipe 
Size of 1 inch or less in diameter;
    (5) Fill-line valves during shipment when a single tank with a 
nominal capacity of 500 barrels (bbl) or less is used for collecting 
marginal production of oil produced from a single well (i.e., 
production that is less than 3 bbl per day). All other seal 
requirements of this subpart apply;
    (6) Gas line valves used on piping with a Nominal Pipe Size of 1 
inch or less used as tank bottom ``roll'' lines, provided there is no 
access to the contents of the storage tank and the roll lines cannot be 
used as equalizer lines;

[[Page 56012]]

    (7) Valves on tank heating systems that use a fluid other than the 
contents of the storage tank (i.e., steam, water, or glycol);
    (8) Valves used on piping with a Nominal Pipe Size of 1 inch or 
less connected directly to the pump body or used on pump bleed off 
lines;
    (9) Tank vent-line valves; and
    (10) Sales, equalizer, or fill-line valves on systems where 
production may be removed only through approved oil metering systems 
(e.g., LACT or CMS). However, any valve that allows access for removing 
oil before it is measured through the metering system must be 
effectively sealed (see appendix A to subpart 3173).
    (d) Tampering with any appropriate valve is prohibited. Tampering 
with an appropriate valve may result in an assessment of civil 
penalties under 30 U.S.C. 1719 and 43 CFR 3163.2 for knowingly or 
willfully preparing, maintaining, or submitting false, inaccurate, or 
misleading reports, records, or written information, or knowingly or 
willfully taking, removing, transporting, using, or diverting oil or 
gas from a lease site without valid legal authority, together with any 
other remedies provided by law.


Sec.  3173.21  Oil measurement system components--seals.

    (a) Components used for quantity or quality determination of oil 
must be effectively sealed to indicate tampering. Such components 
include, but are not limited to, the following components of LACT 
meters (see Sec. Sec.  3174.101 through 3174.108) and CMSs (see Sec.  
3174.130):
    (1) Sampler volume control;
    (2) All valves on lines entering or leaving the sample container, 
excluding the safety pop-off valve (if so equipped). Each valve must be 
sealed in the open or closed position, as appropriate;
    (3) Mechanical counter head (totalizer) and meter head;
    (4) Stand-alone temperature averager monitor;
    (5) Non-automatic adjusting, fixed, back pressure valve pressure 
adjustment downstream of the meter;
    (6) Any drain valves larger than 1 inch in nominal diameter in the 
system; and
    (7) Right-angle drive.
    (b) Each missing or ineffectively sealed component is a separate 
violation.


Sec.  3173.22   Federal seals.

    (a) In addition to any INC issued for a seal violation, the AO or 
AR may place one or more Federal seals on any appropriate valve, 
sealing device, or oil-metering-system component that does not comply 
with the requirements in Sec. Sec.  3173.2 and 3173.3 if the operator 
is not present, refuses to cooperate with the AO or AR, or is unable to 
correct the noncompliance.
    (b) The placement of a Federal seal does not constitute compliance 
with the requirements of Sec. Sec.  3173.20 and 3173.21.
    (c) A Federal seal may not be removed without the approval of the 
AO or AR.


Sec.  3173.30  Removing production from tanks for sale and 
transportation by truck.

    (a) When a single truckload constitutes a completed sale, the 
driver must possess documentation containing the information required 
in Sec.  3174.161(a) or Sec.  3174.162.
    (b) When multiple truckloads are involved in a sale and the oil 
measurement method is based on the difference between the opening and 
closing gauges, the driver of the last truck must possess the 
documentation containing the information required in Sec.  3174.161(a) 
or Sec.  3174.162. All other drivers involved in the sale must possess 
a trip log or manifest.
    (c) After the seals have been broken, the purchaser or transporter 
is responsible for the entire contents of the tank until it is 
resealed.


Sec.  3173.31  Water-draining operations.

    When water is drained from a production storage tank, the operator, 
purchaser, or transporter, as appropriate, must document the 
information as required in Sec.  3173.41(b).


Sec.  3173.32  Hot oiling, clean-up, and completion operations.

    (a) During hot oil, clean-up, or completion operations, or any 
other situation where the operator removes oil from storage, 
temporarily uses it for operational purposes, and then returns it to 
storage on the same lease, unit PA, or communitized area, the operator 
must document the following information:
    (1) Federal or Indian lease, unit PA, or CA number(s);
    (2) Tank location by land description;
    (3) Unique tank number and nominal capacity;
    (4) Date of the opening gauge;
    (5) Opening gauge measurement (gauged manually or automatically) to 
the nearest \1/2\ inch;
    (6) Unique identifying number of each seal removed;
    (7) Closing gauge measurement (gauged manually or automatically) to 
the nearest \1/2\ inch;
    (8) Unique identifying number of each seal installed;
    (9) How the oil was used; and
    (10) Where the oil was used (i.e., well or facility name and 
number).
    (b) During hot oiling, line flushing, or completion operations or 
any other situation where the operator removes production from storage 
for use on a different lease, unit PA, or communtized area, the 
production is considered sold and must be measured in accordance with 
the applicable requirements of this subpart and reported as sold to 
ONRR on the OGOR under 30 CFR part 1210 subpart C for the period 
covering the production in question.


Sec.  3173.40  Report of theft or mishandling of production.

    (a) No later than the next business day after discovery of an 
incident of apparent theft or mishandling of production, the operator, 
purchaser, or transporter must report the incident to the AO. All oral 
reports must be followed up with a written incident report within 10 
business days of the oral report.
    (b) The incident report must include the following information:
    (1) Company name and name of the person reporting the incident;
    (2) Lease, unit PA, or CA number, well or facility name and number, 
and FMP number, as appropriate;
    (3) Land description of the facility location where the incident 
occurred;
    (4) The estimated volume of production removed;
    (5) The manner in which access was obtained to the production or 
how the mishandling occurred;
    (6) The name of the person who discovered the incident;
    (7) The date and time of the discovery of the incident; and
    (8) Whether the incident was reported to local law enforcement 
agencies and/or company security.


Sec.  3173.41   Required recordkeeping for inventory and seal records.

    (a) The operator must perform an end-of-month inventory (gauged 
manually or automatically) that records: TOV in storage (measured to 
the nearest \1/2\ inch) subtracting free water, the volume not 
corrected for temperature/S&W, and the volume as reported to ONRR on 
the OGOR;
    (1) The end-of-month inventory must be completed within  3 days of the last day of the calendar month; or
    (2) The end of month inventory must be a calculated ``end of 
month'' inventory based on daily production that takes place between 
two measured inventories that are not more than 31, nor fewer than 20, 
days apart. The calculated monthly inventory is determined based on the 
following equation:


[[Page 56013]]


{[(X + Y - W) / Z1] * Z2{time}  + X = A,

where:

A = calculated end of month inventory;
W = first inventory measurement;
X = second inventory measurement;
Y = gross sales volume between the first and second inventory;
Z1 = number of actual days produced between the first and second 
inventory; and
Z2 = number of actual days produced between the second inventory and 
end of calendar month for which the OGOR report is due.

    For example: If the first inventory measurement performed on 
January 12 is 125 bbl, the second inventory measurement performed on 
February 10 is 150 bbl, the gross sales volume between the first and 
second inventory is 198 bbl, and February is the calendar month for 
which the report is due. For purposes of this example, we assume 
February had 28 days and that the well was non-producing for two of 
those days.
    {[(150 bbl + 198 bbl - 125 bbl)/29 days] * 16 days{time}  + 150 bbl 
= 273 bbl for the February end-of-month inventory.
    (b) For each seal, the operator must maintain a record that 
includes:
    (1) The unique identifying number of each seal and the valve or 
meter component on which the seal is or was used;
    (2) The date of installation or removal of each seal;
    (3) For valves, the position (open or closed) in which it was 
sealed; and
    (4) The reason the seal was removed.


Sec.  3173.43   Data submission and notification requirements.

    (a) The operator must submit a Form 3160-5, Sundry Notices and 
Reports on Wells (Sundry Notice) for the following:
    (1) Site facility diagrams (see Sec.  3173.50);
    (2) Request for an FMP number (see Sec.  3173.60);
    (3) Request for FMP amendments (see Sec.  3173.61(b));
    (4) Requests for approval of off-lease measurement (see Sec.  
3173.91);
    (5) Request to amend an approval of off-lease measurement (see 
Sec.  3173.91(k));
    (6) Requests for approval of CAAs (see Sec.  3173.71); and
    (7) Request to modify a CAA (see Sec.  3173.74).
    (b) The operator must submit all Sundry Notices electronically to 
the BLM office having jurisdiction over the lease, unit, or CA using 
WIS, unless the submitter:
    (1) Is a small business, as defined by the U.S. Small Business 
Administration; and
    (2) Does not have access to the internet.


Sec.  3173.50   Site facility diagram.

    (a) A site facility diagram is required for all facilities.
    (b) Except for the requirement to submit a Form 3160-5, Sundry 
Notice, with the site facility diagram, no format is prescribed for 
site facility diagrams. The diagram should be formatted to fit on an 
8\1/2\'' by 11'' sheet of paper, if possible, and must be legible and 
comprehensible to an individual with an ordinary working knowledge of 
oil field operations (see appendix A to subpart 3173). If more than one 
page is required, each page must be numbered (in the format ``N of X 
pages'').
    (c) The diagram must:
    (1) Reflect the position of the production and water recovery 
equipment, piping for oil, gas, and water, and metering or other 
measuring systems in relation to each other, but need not be to scale;
    (2) Commencing with the header, identify all of the equipment, 
including, but not limited to, the header, wellhead, piping, tanks, and 
metering systems located on the site, and include the appropriate 
valves and any other equipment used in the handling, conditioning, or 
disposal of production and water, and indicate the direction of flow;
    (3) Identify by the complete US well number the wells flowing into 
headers;
    (4) If another operator operates a co-located facility, the 
operator must identify the co-operator by name on the diagram and 
identify with a box on the diagram the approximate location of the co-
located facility;
    (5) Indicate which valve(s) must be sealed and in what position 
during the production and sales phases and during other production 
activities (e.g., circulating tanks or drawing off water), which may be 
shown by an attachment, if necessary;
    (6) For storage facilities common to co-located facilities operated 
by one operator, one diagram is sufficient;
    (7) Clearly identify the lease, unit PA, or CA to which the diagram 
applies, the land description of the facility, and the name of the 
company submitting the diagram, and any co-located facilities;
    (8) Clearly identify, on the diagram or as an attachment, all 
meters and measurement equipment. Specifically identify all assigned 
FMP numbers or the unique identifiers or station ID numbers of the 
measurement equipment used for royalty reporting; and
    (9) If the operator claims royalty-free use, clearly identify the 
equipment for which the operator claims royalty-free use. The operator 
must either:
    (i) For each engine, motor, or major component (e.g., compressor, 
separator, dehydrator, heater-treater, or tank heater) powered by 
production from the lease, unit PA, or CA, state the volume (oil or 
gas) consumed (per day or per month) and how the volume is determined; 
or
    (ii) Measure the volume used, by meter or tank gauge.
    (d) The operator must submit a new site facility diagram as 
follows:
    (1) For new, permanent facilities that become operational after 
[EFFECTIVE DATE OF FINAL RULE], a site facility diagram within 60 days 
after the facility becomes operational; or
    (2) For a facility that is in service on or before [EFFECTIVE DATE 
OF FINAL RULE], and that has a site facility diagram on file with the 
BLM that meets the minimum requirements of Onshore Oil and Gas Order 3, 
Site Security, an amended site facility diagram meeting the 
requirements of this section is not due until 60 days after the 
existing facility is modified, or a non-Federal facility located on a 
Federal lease or federally approved unit or communitized area is 
constructed or modified.
    (e) After a site facility diagram has been submitted that complies 
with the requirements of this part, the current operator has an ongoing 
obligation to update and amend the diagram within 60 days after such 
facility is modified or, a non-Federal facility located on a Federal 
lease or federally approved unit or communitized area is constructed or 
modified.


Sec.  3173.60  Applying for a facility measurement point number.

    (a) The operator must submit separate applications for approval of 
an FMP number that measures oil produced from a lease, unit PA, or CA, 
gas storage agreement involving native gas or oil, or under a CAA that 
complies with the requirements of this subpart, and an FMP number that 
measures gas produced from the same lease, unit PA, or CA, or under a 
CAA that complies with the requirements of this subpart. This 
requirement applies even if the measurement equipment or facilities are 
at the same location.
    (b) For a permanent measurement facility that comes into service 
after [EFFECTIVE DATE OF FINAL RULE], the operator must apply for 
approval of the FMP number before any production leaves the permanent 
measurement facility. This requirement does not apply to measurement 
equipment at any temporary measurement facility used

[[Page 56014]]

during well-testing operations. After timely submission and prior to 
approval of an FMP number request, an operator must use the lease, unit 
PA, or CA number for reporting production to ONRR, until the BLM 
assigns an FMP number, at which point the operator must use the FMP 
number for all reporting to ONRR as set forth in Sec.  3173.61.
    (c) For a permanent measurement facility in service on or before 
[EFFECTIVE DATE OF FINAL RULE], the operator must apply for BLM 
approval of an FMP number within the time prescribed in this paragraph, 
based on the production level of any one of the leases, unit PAs, or 
CAs, whether or not they are part of a CAA. The deadline to apply for 
an FMP number approval applies to both oil and gas measurement 
facilities measuring production from that lease, unit PA, or CA.
    (1) For a stand-alone lease, unit PA, or CA that produced 4,500 Mcf 
or more of gas per month or 500 bbl or more of oil per month, the 
deadline is [DATE ONE YEAR AFTER EFFECTIVE DATE OF FINAL RULE].
    (2) For a stand-alone lease, unit PA, or CA that produced 1,000 Mcf 
or more, but less than 4,500 Mcf of gas per month, or 50 bbl or more, 
but less than 500 bbl of oil per month, the deadline is [DATE TWO YEARS 
AFTER EFFECTIVE DATE OF FINAL RULE].
    (3) For a stand-alone lease, unit PA, or CA that produced less than 
1,000 Mcf of gas per month or less than 50 bbl of oil per month, the 
deadline is [DATE THREE YEARS AFTER THE EFFECTIVE DATE OF THE FINAL 
RULE].
    (4) For a stand-alone lease, unit PA, or CA that has not produced 
for a year or more before [EFFECTIVE DATE OF FINAL RULE], the operator 
must apply for an FMP number prior to the resumption of production.
    (5) The production levels identified in paragraphs (d)(1) through 
(3) of this section should be calculated using the average production 
of oil or gas over the 12 months preceding the effective date of this 
section or over the period the lease, unit PA, or CA has been in 
production, whichever is shorter.
    (6) If the operator of any facility covered by this section applies 
for an FMP number approval by the deadline in this paragraph, the 
operator may continue using the lease, unit PA, or CA number for 
reporting production to ONRR, until the BLM assigns an FMP number, at 
which point the operator must use the FMP number for all reporting to 
ONRR as set forth in Sec.  3173.61.
    (d) All requests for FMP number approval must include the 
following:
    (1) A complete Sundry Notice requesting approval of each FMP; and
    (2) Information about the equipment used for oil and gas 
measurement, including, for:
    (i) ``Gas measurement,'' specify the name of the operator/
purchaser/transporter, as appropriate, the unique meter identification, 
and elevation;
    (ii) ``Oil measurement by tank gauge,'' specify name of the 
operator/purchaser/transporter, as appropriate, and the oil tank number 
or tank serial number and size in barrels or gallons for all tanks 
associated with measurement at an FMP; and
    (iii) ``Oil measurement by LACT or CMS,'' specify the name of 
operator/purchaser/transporter, as appropriate, and unique meter 
identification;
    (3) Where production from more than one well will flow to the 
requested FMP, list the US well numbers associated with the FMP; and
    (4) FMP location by land description.
    (f) A request for approval of an FMP number may be submitted 
simultaneously with separate requests for off-lease measurement and/or 
CAA.


Sec.  3173.61   Requirements for approved facility measurement points.

    (a) An operator must start reporting production to ONRR on its OGOR 
using an FMP number for the third production month after the BLM 
assigns the FMP number(s), and every month thereafter. (For example, 
for a facility that is assigned an FMP number on January 15, 2021, the 
effective date of the FMP is the April 2021 production report.)
    (b)(1) The operator must file a Sundry Notice that describes any 
changes or modifications made to the FMP within 30 days after the 
change. This requirement does not apply to temporary modifications 
(e.g., for maintenance purposes). These include any changes and 
modifications to the information listed on an application submitted 
under Sec.  3173.60.
    (2) The Sundry Notice must specify what was changed and the 
effective date, and include, if appropriate, an amended site facility 
diagram (see Sec.  3173.50).


Sec.  3173.70   Conditions for commingling and allocation approval 
(surface and downhole).

    (a) Subject to the exceptions provided in paragraph (b) of this 
section, the BLM may grant a CAA only if the proposed allocation method 
used for commingled measurement does not have the potential to affect 
the determination of the total quantity or quality of production on 
which royalty is owed. All the Federal or Indian leases, unit Pas, or 
CAs proposed for commingling must meet the following conditions:
    (1) The proposed commingling includes production from more than 
one:
    (i) Federal lease, unit PA, or CA, where each lease, unit PA, or CA 
proposed for commingling has 100 percent Federal mineral interest, and 
the same fixed royalty rate;
    (ii) Indian tribal lease, unit PA, or CA, where each lease, unit 
PA, or CA proposed for commingling is wholly owned by the same tribe 
and has the same fixed royalty rate;
    (iii) Federal unit PA or CA, where each unit PA, or CA proposed for 
commingling has the same proportion of Federal interest, and each 
interest is subject to the same fixed royalty rate. (For example, the 
BLM could approve a commingling request under this paragraph where an 
operator proposes to commingle two Federal CAs of mixed ownership and 
both CAs are 50 percent Federal and 50 percent private, so long as the 
Federal interests have the same royalty rates.); or
    (iv) Indian unit PA or CA, where each unit PA or CA proposed for 
commingling has the same proportion of Indian interests, and each 
interest is held by the same tribe and has the same fixed royalty rate;
    (2) The operator or operators provide a methodology acceptable to 
the BLM for allocation among the leases or agreements from which 
production is to be commingled, with a signed agreement if there is 
more than one operator.
    (3) The applicant demonstrates to the AO that each lease, unit PA, 
or CA proposed for inclusion in the CAA is producing in paying 
quantities (or, in the case of Federal leases, capable of production in 
paying quantities) pending approval of the CAA, or the applicant 
demonstrates to the AO that a lease, unit PA, or CA proposed for 
inclusion in the CAA has an approved Application for Permit to Drill.
    (b) The BLM may also approve a CAA in instances where the proposed 
commingling of production involves production from Federal or Indian 
leases, unit PAs, or CAs that do not meet the criteria of paragraph 
(a)(1) of this section (e.g., the commingling of leases, unit PAs, or 
CAs with different royalty rates, or where the commingling involves 
multiple mineral ownerships). In order to be approved, a CAA under this 
paragraph must meet the requirements of paragraphs (a)(2) through (3) 
of this section and at least one of the following conditions must be 
met:
    (1) The Federal or Indian lease, unit PA, or CA meets the 
definition of an economically marginal property.

[[Page 56015]]

However, if the BLM determines that the economically marginal Federal 
or Indian lease, unit PA, or CA included in a CAA ceases to be an 
economically marginal property, then this condition is no longer met;
    (2) The average monthly production over the preceding 12 months for 
each Federal or Indian lease, unit PA, or CA proposed for the CAA on an 
individual basis is less than 6,000 Mcf of gas per month, or 1,000 bbl 
of oil per month;
    (3) A CAA that includes Indian leases, unit PAs, or CAs has been 
authorized under tribal law or otherwise approved by a tribe;
    (4) The CAA covers the downhole commingling of production from 
multiple formations that are covered by separate leases, unit PAs, or 
CAs, where the BLM has determined that the proposed commingling from 
those formations is an acceptable practice for the purpose of achieving 
maximum ultimate economic recovery and resource conservation;
    (5) The applicant must provide an overall allocation uncertainty 
analysis calculated by using propagation of uncertainty method of the 
Federal or Indian mineral interest percentage for each lease, unit PA, 
or CA proposed for commingling which meets the following criteria:
    (i) Overall allocation uncertainty analysis must meet the 
performance goals in Sec.  3174.31 or Sec.  3175.31;
    (ii) The analysis must show no allocation bias as a result of 
commingling allocation;
    (iii) The analysis must state what the assumed underlying 
distribution is of the volumes generated in the analysis and support 
the use of the underlying distribution assumption; and
    (iv) The analysis must be limited to four leases, unit PAs, or CAs 
proposed for commingling approval.
    (6) There are overriding considerations that indicate the BLM 
should approve a commingling application in the public interest, 
notwithstanding potential negative royalty impacts from the allocation 
method. Such considerations could include topographic or environmental 
considerations that make non-commingled measurement physically 
impractical or undesirable, in view of where additional measurement and 
related equipment necessary to achieve non-commingled measurement would 
have to be located.


Sec.  3173.71   Applying for a commingling and allocation approval.

    To apply for a CAA, the applicant must submit the following, if 
applicable, to the BLM office having jurisdiction over the leases, unit 
PAs, or CAs from which production is proposed to be commingled:
    (a) A completed Sundry Notice requesting approval of commingling 
and allocation of either oil or gas;
    (b) A completed Sundry Notice for approval of off-lease measurement 
under Sec.  3173.91, if any of the proposed FMPs are outside the 
boundaries of any of the leases, units, or CAs from which production 
would be commingled. The Sundry Notice for off-lease measurement 
approval must be submitted simultaneously with the Sundry Notice 
requesting commingling approval;
    (c) A proposed allocation agreement, including a proposed 
allocation methodology, with an example of how the methodology would be 
applied, signed by each operator of each of the leases, unit PAs, or 
CAs from which production would be included in the CAA;
    (d) A list of all Federal or Indian lease, unit PA, or CA numbers 
in the proposed CAA, specifying the type of production (i.e., oil or 
gas) for which commingling is requested;
    (e) A map or maps (topographic map, if applying under Sec.  
3173.70(b)(6)) of appropriate scale showing the following:
    (1) The boundaries of all the leases, units, unit PAs, or 
communitized areas whose production is proposed to be commingled; and
    (2) The location of existing or planned facilities and the relative 
location of all wellheads (including the US well number) and piping 
included in the CAA, and existing FMPs or FMPs proposed to be installed 
to the extent known or anticipated;
    (f) An applicant-certified statement of a surface-use plan of 
operations, if new surface disturbance is proposed for the FMP and its 
associated facilities are located on BLM-managed land within the 
boundaries of the leases, units, and communitized areas from which 
production would be commingled;
    (g) An applicant-certified statement of a right-of-way grant 
approval under 43 CFR part 2880, if the proposed FMP is on a pipeline, 
or approved under 43 CFR part 2800, if the proposed FMP is a meter or 
storage tank. This requirement applies only when new surface 
disturbance is proposed for the FMP, and its associated facilities are 
located on BLM-managed land outside any of the leases, units, or 
communitized areas where production would be commingled;
    (h) Written approval from the appropriate surface-management 
agency, if new surface disturbance is proposed for the FMP and its 
associated facilities are located on Federal land managed by an agency 
other than the BLM;
    (i) An applicant-certified statement of a right-of-way grant 
approval for the proposed FMP, filed under 25 CFR part 169, with the 
appropriate BIA office, if any of the proposed surface facilities are 
on Indian land outside the lease, unit, or communitized area from which 
the production would be commingled;
    (j) Documentation demonstrating that each of the leases, unit PAs, 
or CAs proposed for inclusion in the CAA is producing in paying 
quantities (or, in the case of Federal leases, is capable of production 
in paying quantities) pending approval of the CAA. If the leases are 
not yet producing, documentation that a lease, unit PA, or CA proposed 
for inclusion has an approved Application for Permit to Drill, 
including offset well decline curve data to support projected 
production volumes presented in the commingling application;
    (k) All gas analyses, including Btu content or oil gravities as 
applicable, for previous periods of production from the leases, units, 
unit PAs, or communitized areas proposed for inclusion in the CAA, for 
up to 6 years before the date of the application for approval of the 
CAA. Gas analysis and oil gravity data is not needed if the CAA falls 
under paragraph (a)(1) of this section.


Sec.  3173.72   Existing commingling and allocation approvals.

    Upon receipt of an operator's request for assignment of an FMP 
number to a facility associated with a CAA existing on [EFFECTIVE DATE 
OF FINAL RULE], the AO will review the existing CAA and take the 
following action:
    (a) The AO will grandfather the existing CAA and associated off-
lease measurement, where applicable, if the existing CAA meets one of 
the following conditions:
    (1) The existing CAA involves downhole commingling that includes 
Federal or Indian leases, unit PAs, or CAs; or
    (2) The existing CAA is for surface commingling and the average 
production rate over the previous 12 months for each Federal or Indian 
lease, unit PA, and CA included in the CAA is:
    (i) Less than 6,000 Mcf per month for gas; or
    (ii) Less than 1,000 bbl per month for oil.
    (b) If the existing CAA does not meet the conditions of paragraph 
(a)(1) or (2) of this section, the AO will review the CAA for 
consistency with the minimum

[[Page 56016]]

standards and requirements for a CAA under Sec.  3173.14.
    (1) The AO will notify the operator in writing of any 
inconsistencies or deficiencies with an existing CAA. The operator must 
correct any inconsistencies or deficiencies that the AO identifies, 
provide the additional information that the AO has requested, or 
request an extension of time from the AO, within 20 business days after 
receipt of the AO's notice. When the AO is satisfied that the operator 
has corrected any inconsistencies or deficiencies, the AO will 
terminate the existing CAA and grant a new CAA based on the operator's 
corrections.
    (2) The AO may terminate the existing CAA and grant a new CAA with 
new or amended COAs to make the approval consistent with the 
requirements under Sec.  3173.70 in connection with approving the 
requested FMP. If the operator appeals any COAs of the new CAA, the 
existing CAA approval will continue in effect during the pendency of 
the appeal.
    (3) If the existing CAA does not meet the standards and 
requirements of Sec.  3173.70 and the operator does not correct the 
deficiencies, the AO may terminate the existing CAA under Sec.  3173.76 
and deny the request for an FMP number for the facility associated with 
the existing CAA.
    (c) If the AO grants a new CAA to replace an existing CAA under 
paragraph (b) of this section, the new CAA is effective on the first 
day of the month following its approval. Any new allocation percentages 
resulting from the new CAA will apply from the effective date of the 
CAA forward.
    (d) The grandfathering of an existing downhole commingling approval 
does not constitute a new surface commingling approval or the 
grandfathering of an associated surface commingling approval.


Sec.  3173.73   Relationship of a commingling and allocation approval 
to royalty-free use of production.

    A CAA does not constitute approval of off-lease royalty-free use of 
production as fuel in facilities located at an FMP approved under the 
CAA.


Sec.  3173.74   Modification of a commingling and allocation approval.

    (a) A CAA must be modified when:
    (1) There is a modification to the allocation agreement;
    (2) Additional leases, unit PAs, or CAs are proposed for inclusion 
in the CAA; or
    (3) There is permanent production cessation from any of the leases, 
unit PAs, or CAs within the CAA.
    (b) When a CAA was based on projected production quantity and 
quality and any of the leases, unit PAs, or CAs exceeds the production 
projections provided by the applicant, then the CAA must be reevaluated 
and the approval may be rescinded, revised, or COAs modified.
    (c) To request a modification of a CAA, all operators must submit 
to the AO:
    (1) A completed Sundry Notice describing the modification 
requested;
    (2) A new allocation methodology, including an allocation 
methodology and an example of how the methodology is applied, if 
appropriate; and
    (3) Certification by each operator in the CAA that it agrees to the 
CAA modification.
    (d) A change in operator does not trigger the need to modify a CAA.


Sec.  3173.75   Effective date of a commingling and allocation 
approval.

    (a) If the BLM approves a CAA, the effective date of the CAA is the 
first day of the month following first production through the FMPs for 
the CAA.
    (b) If the BLM approves a modification, the effective date is the 
first day of the month following approval of the modification.
    (c) A CAA does not modify any of the terms of the leases, units, or 
CAs covered by the CAA.


Sec.  3173.76  Terminating a commingling and allocation approval.

    (a) The AO may terminate a CAA for any reason, including, but not 
limited to, the following:
    (1) Changes in technology, regulation, or BLM policy;
    (2) Operator non-compliance with the terms or COAs of the CAA or 
this subpart; or
    (3) The AO determines that a lease, unit, or CA subject to the CAA 
has terminated, or a unit PA subject to the CAA has ceased production; 
or
    (4) A CAA was based on projected production quantity and quality 
and any of the leases, unit PAs, or CAs exceeds the production 
projections provided by the applicant.
    (b) If only one lease, unit PA, or CA remains subject to the CAA, 
the CAA terminates automatically.
    (c) An operator may terminate its participation in a CAA by 
submitting a Sundry Notice to the BLM. The Sundry Notice must identify 
the FMP(s) for the lease(s), unit PA(s), or CA(s) previously subject to 
the CAA. Termination by one operator does not mean the CAA terminates 
as to all other participating operators, so long as one of the other 
provisions of this subpart is met and the remaining operators submit a 
Sundry Notice requesting a new CAA as outlined in paragraph (e) of this 
section.
    (d) The AO will notify in writing all operators who are a party to 
the CAA of the effective date of the termination and any 
inconsistencies or deficiencies with their CAA approval that serve as 
the reason(s) for termination. The operator must correct any 
inconsistencies or deficiencies that the AO identifies, provide the 
additional information that the AO has requested, or request an 
extension of time from the AO, within 20 business days after receipt of 
the BLM's notice, or the CAA is terminated.
    (e) If a CAA is terminated, each lease, unit PA, or CA that was 
included in the CAA may require a new FMP number(s) or a new CAA. 
Operators will have 30 days to apply for a new FMP number (Sec.  
3173.12) or CAA (Sec.  3173.15), if applicable. The existing FMP number 
may be used for production reporting until a new FMP number is assigned 
or CAA is approved.


Sec.  3173.80  Combining production downhole in certain circumstances.

    (a)(1) Combining production from a single well completed in 
different hydrocarbon pools or geologic formations (e.g., a directional 
well) underlying separate adjacent properties (whether Federal, Indian, 
State, or private), where none of the hydrocarbon pools or geologic 
formations underlie or are common to more than one of the respective 
properties, constitutes commingling for purposes of Sec. Sec.  3173.70 
through 3173.76.
    (2) If any of the hydrocarbon pools or geologic formations underlie 
or are common to more than one of the properties, the operator must 
establish a unit PA (see 43 CFR part 3180) or CA (see 43 CFR 3105.2-1--
3105.2-3), as applicable, rather than applying for a CAA.
    (b) Combining production downhole from different geologic 
formations on the same lease, unit PA, or CA in a single well requires 
approval of the AO (see 43 CFR 3162.3-2), but it is not considered 
commingling for production accounting purposes.


Sec.  3173.90  Requirements for off-lease measurement.

    The BLM will consider granting a request for off-lease measurement 
if the request:
    (a) Involves only production from a single lease, unit PA, CA, or 
CAA;
    (b) Provides for accurate production accountability;
    (c) Is in the public interest (considering factors such as BMPs,

[[Page 56017]]

topographic and environmental conditions that make on-lease measurement 
physically impractical, and maximum ultimate economic recovery); and
    (d) Occurs at an approved FMP. A request for approval of an FMP 
(see Sec.  3173.12) may be filed concurrently with the request for off-
lease measurement.


Sec.  3173.91  Applying for off-lease measurement.

    To apply for approval of off-lease measurement, the operator must 
submit the following to the BLM office having jurisdiction over the 
leases, units, or communitized areas:
    (a) A completed Sundry Notice, with separate applications for each 
oil and gas FMP;
    (b) Justification for off-lease measurement (considering factors 
such as BMPs, topographic and environmental issues, and maximum 
ultimate economic recovery);
    (c) A topographic map or maps of appropriate scale showing the 
following:
    (1) The boundary of the lease, unit, unit PA, or communitized area 
from which the production originates; and
    (2) The location of existing or planned facilities and the relative 
location of all wellheads (including the US well number for each well) 
and piping included in the off-lease measurement proposal, and existing 
FMPs or FMPs proposed to be installed to the extent known or 
anticipated;
    (d) The surface ownership of all land on which equipment is, or is 
proposed to be, located;
    (e) If any of the proposed off-lease measurement facilities are 
located on non-federally owned surface, a written concurrence must be 
signed by the owner(s) of the surface and the owner(s) of the 
measurement facilities, including each owner's name, address, and 
telephone number, granting the BLM unrestricted access to the off-lease 
measurement facility and the surface on which it is located, for the 
purpose of inspecting any production, measurement, water handling, or 
transportation equipment located on the non-Federal surface up to and 
including the FMP, and for otherwise verifying production 
accountability. If the ownership of the non-Federal surface or of the 
measurement facility changes, the operator must obtain and provide to 
the AO the written concurrence required under this paragraph from the 
new owner(s) within 30 days of the change in ownership;
    (f) An applicant certified statement of a right-of-way grant 
(Standard Form 299) approved under 43 CFR part 2880, if the proposed 
off-lease FMP is on a pipeline, or under 43 CFR part 2800, if the 
proposed off-lease FMP is a meter or storage tank. This requirement 
applies only when new surface disturbance is proposed for the FMP and 
its associated facilities are located on BLM-managed land;
    (g) An applicant certified statement of a right-of-way grant 
approval under 25 CFR part 169 with the appropriate BIA office, if any 
of the proposed surface facilities are on Indian land outside the 
lease, unit, or communitized area from which the production originated;
    (h) Written approval from the appropriate surface-management 
agency, if new surface disturbance is proposed for the FMP and its 
associated facilities are located on Federal land managed by an agency 
other than the BLM;
    (i) An application for approval of off-lease royalty-free use (if 
required under applicable rules), if the operator proposes to use 
production from the lease, unit, or CA as fuel at the off-lease 
measurement facility without payment of royalty; and
    (j) If the operator is applying for an amendment of an existing 
approval of off-lease measurement, the operator must submit a completed 
Sundry Notice required under paragraph (a) of this section, and 
information required under paragraphs (b) through (j) of this section 
to the extent the information previously submitted has changed.


Sec.  3173.92  Effective date of an off-lease measurement approval.

    If the BLM approves off-lease measurement, the approval is 
effective on the date that the approval is issued, unless the approval 
specifies a different effective date.


Sec.  3173.93  Existing approved off-lease measurement.

    (a) Upon receipt of an operator's request for assignment of an FMP 
number to a facility associated with an off-lease measurement approval 
existing on [EFFECTIVE DATE OF FINAL RULE], the AO will review the 
existing approved off-lease measurement for consistency with the 
minimum standards and requirements for an off-lease measurement 
approval under Sec.  3173.22. The AO will notify the operator in 
writing of any inconsistencies or deficiencies.
    (b) The operator must correct any inconsistencies or deficiencies 
that the AO identifies, provide any additional information the AO 
requests, or request an extension of time from the AO, within 20 
business days after receipt of the AO's notice. The extension request 
must explain the factors that will prevent the operator from complying 
within 20 days and provide a timeframe under which the operator can 
comply.
    (c) In connection with approving an FMP application, the AO may 
terminate the existing off-lease measurement approval and grant a new 
off-lease measurement approval with new or amended COAs to make the 
approval consistent with the requirements for off-lease measurement 
under Sec.  3173.90 in connection with approving the requested FMP. If 
the operator appeals the new off-lease measurement approval, the 
existing off-lease measurement approval will continue in effect during 
the pendency of the appeal.
    (d) If the existing off-lease measurement approval does not meet 
the standards and requirements of Sec.  3173.90 and the operator does 
not correct the deficiencies, the AO may terminate the existing off-
lease measurement approval under Sec.  3173.95 and deny the request for 
an FMP number for the facility associated with the existing off-lease 
measurement approval.
    (e) If the existing off-lease measurement approval under this 
section is consistent with the requirements under Sec.  3173.90, then 
that existing off-lease measurement is grandfathered and will be part 
of the FMP approval.
    (f) If the BLM grants a new off-lease measurement approval to 
replace an existing off-lease measurement approval, the new approval is 
effective on the first day of the month following its approval.


Sec.  3173.94  Relationship of off-lease measurement approval to 
royalty-free use of production.

    Approval of off-lease measurement does not constitute approval of 
off-lease royalty-free use of production as fuel in facilities located 
at an FMP approved under the off-lease measurement approval.


Sec.  3173.95  Termination of off-lease measurement approval.

    (a) The BLM may terminate off-lease measurement approval for any 
reason, including, but not limited to, the following:
    (1) Changes in technology, regulation, or BLM policy; or
    (2) Operator non-compliance with the terms or conditions of 
approval of the off-lease measurement approval or Sec. Sec.  3173.90 
through 3173.94.
    (b) The BLM will notify the operator in writing of the effective 
date of the

[[Page 56018]]

termination and any inconsistencies or deficiencies with its off-lease 
measurement approval that serve as the reason(s) for termination. The 
operator must correct any inconsistencies or deficiencies that the BLM 
identifies, provide any additional information the AO requests, or 
request an extension of time from the AO within 20 business days after 
receipt of the BLM's notice, or the off lease measurement approval 
terminates on the effective date.
    (c) The operator may terminate the off-lease measurement by 
submitting a Sundry Notice to the BLM. The Sundry Notice must identify 
the new FMP(s) for the lease(s), unit(s), or CA(s) previously subject 
to the off-lease measurement approval.
    (d) If off-lease measurement is terminated, each lease, unit PA, or 
CA that was subject to the off-lease measurement approval may require a 
new FMP number(s) or a new off-lease measurement approval. Operators 
will have 30 days to apply for a new FMP number or off-lease 
measurement approval, whichever is applicable. The existing FMP number 
may be used for production reporting until a new FMP number is assigned 
or off-lease measurement is approved.


Sec.  3173.96  Instances not constituting off-lease measurement, for 
which no approval is required.

    (a) If the approved FMP is located on the well pad of a 
directionally or horizontally drilled well that produces oil and gas 
from a lease, unit, or communitized area on which the well pad is not 
located, measurement at the FMP does not constitute off-lease 
measurement. However, if the FMP is located off of the well pad, 
regardless of distance, measurement at the FMP constitutes off-lease 
measurement, and BLM approval is required under Sec. Sec.  3173.90 
through 3173.94.
    (b) If a lease, unit, or CA consists of more than one separate 
tract whose boundaries are not contiguous (e.g., a single lease 
comprises two or more separate tracts), measurement of production at an 
FMP located on one of the tracts is not considered to be off-lease 
measurement if:
    (1) The production is moved from one tract within the same lease, 
unit, or communitized area to another area of the lease, unit, or 
communitized area on which the FMP is located; and
    (2) Production is not diverted during the movement between the 
tracts before the FMP, except for production used royalty free.


Sec.  3173.190  Immediate assessments for certain violations.

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

     Table 1 to Sec.   3173.190: Violations Subject to an Immediate
                               Assessment
------------------------------------------------------------------------
                                                            Assessment
                       Violation:                           amount per
                                                            violation:
------------------------------------------------------------------------
1. An appropriate valve on an oil storage tank was not            $1,000
 effectively sealed, as required by Sec.   3173.20......
2. A Federal seal is removed without prior approval of             1,000
 the AO or AR, as required by Sec.   3173.22............
3. Oil was not properly measured before removal from               1,000
 storage for use on a different lease, unit, or CA, as
 required by Sec.   3173.32(b)..........................
4. An FMP was bypassed, in violation of Sec.   3170.22..           1,000
5. Theft or mishandling of production was not reported             1,000
 to the BLM, as required by Sec.   3173.40..............
6. Records necessary to determine quantity and quality             1,000
 of production were not retained, as required by Sec.
 3170.32................................................
7. FMP application was not submitted, as required by               1,000
 Sec.   3173.60.........................................
8. (i) For facilities that begin operation after                   1,000
 [EFFECTIVE DATE OF FINAL RULE], BLM approval for off-
 lease measurement was not obtained before removing
 production, as required by Sec.   3173.91..............
(ii) Facilities that were in operation on or before
 [EFFECTIVE DATE OF FINAL RULE], are subject to an
 assessment if they do not have an existing BLM approval
 for off-lease measurement..............................
9. (i) For facilities that begin operation after                   1,000
 [EFFECTIVE DATE OF FINAL RULE], BLM approval for
 surface commingling was not obtained before removing
 production, as required by Sec.   3173.71..............
(ii) Facilities that were in operation on or before
 [EFFECTIVE DATE OF FINAL RULE], are subject to an
 assessment if they do not have an existing BLM approval
 for surface commingling................................
10. (i) For facilities that begin operation after                  1,000
 [EFFECTIVE DATE OF FINAL RULE], BLM approval for
 downhole commingling was not obtained before removing
 production, as required by Sec.   3173.71..............
(ii) Facilities that were in operation on or before
 [EFFECTIVE DATE OF FINAL RULE], are subject to an
 assessment if they do not have an existing BLM approval
 for downhole commingling...............................
------------------------------------------------------------------------

Appendix A to Subpart 3173--Examples of Site Facility Diagrams

I. Diagrams

1. Site Facility Diagrams and Sealing of Valve Introduction
2. Diagrams

------------------------------------------------------------------------
        Diagrams              Appendix pages            Description
------------------------------------------------------------------------
I-A....................  1-1....................  Simple gas well
                                                   without equipment.
I-B....................  1-2....................  Simple gas well with
                                                   equipment.
I-C....................  1-3 thru 1-5...........  Single operator with
                                                   co-located facilities
                                                   single oil tank, gas,
                                                   and water storage.
I-D....................  1-6 and 1-8............  Oil sales with
                                                   multiple oil tanks,
                                                   gas, and water
                                                   storage.
I-E....................  1-9 thru 1-12..........  Co-located facilities
                                                   with multiple
                                                   operators, oil sales
                                                   by Lease Automatic
                                                   Custody Transfer
                                                   (LACT) system, gas,
                                                   and water storage.
I-F....................  1-13 thru 1-16.........  On-lease gas plant,
                                                   with oil sales by
                                                   LACT, Liquefied
                                                   Petroleum Gas (LPG)/
                                                   Natural Gas Liquids
                                                   (NGL) sales by LACT,
                                                   inlet gas, tailgate
                                                   gas, flared or vented
                                                   and plant process gas
                                                   used.

[[Page 56019]]

 
I-G....................  1-17 thru 1-19.........  Enhanced recovery
                                                   water injection or
                                                   other water disposal
                                                   facility.
I-H....................  1-20 thru 1-22.........  Pod Facility.
I-I....................  1-23 thru 1-25.........  Water recycle system
                                                   with water disposal
                                                   options by pipeline
                                                   or truck.
------------------------------------------------------------------------

    1. Site Facility Diagrams and Sealing of Valve Introduction 
Appendix to 3173 is provided not as a requirement but solely as an 
example to aid operators, purchasers, and transporters in determining 
what valves are considered to be ``appropriate valves'' subject to the 
seal requirements of this proposed rule, and to aid in the preparation 
of facility diagrams. It is impossible to include every type of 
equipment that could be used or situation that could occur in 
production activities. In making the determination of what is an 
``appropriate valve,'' the entire facility must be considered as a 
whole, including the facility size, the equipment type, and the on-
going activities at the facility. The signature block, in which a 
company representative certifies each diagram's accuracy, may be placed 
directly on the diagram or on a separate piece of paper accompanying 
the diagram. As shown in this appendix, the signature block may appear 
in a box or as a line of text.
BILLING CODE 4310-84-P

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BILLING CODE 4310-84-C
0
4. Revise subpart 3174 to read as follows:
Subpart 3174--Measurement of Oil
Sec.
3174.10 Definitions and acronyms.
3174.20 General requirements.
3174.30 Incorporation by reference (IBR).
3174.31 Specific measurement performance requirements.

[[Page 56045]]

3174.40 Approved measurement equipment and data requirements.
3174.41 Measurement equipment requiring BLM approval.
3174.42 Approved measurement equipment.
3174.43 Data submission and notification requirements.
3174.50 Grandfathering.
3174.60 Timeframes for compliance.
3174.70 Measurement location.
3174.80 Oil storage tank equipment.
3174.81 Oil measurement by tank gauging.
3174.82 Oil tank calibration.
3174.83 Tank gauging procedures.
3174.84 Tank oil sampling.
3174.85 Determining S&W content.
3174.86 Tank oil temperature determination.
3174.87 Observed oil gravity determination.
3174.88 Measuring tank fluid level.
3174.90 LACT systems--general requirements.
3174.100 LACT systems--components and operating requirements.
3174.101 Charging pump and motor.
3174.102 Sampling and mixing system.
3174.103 Air eliminator.
3174.104 LACT meter.
3174.105 Electronic temperature averaging device.
3174.106 Pressure-indicating device.
3174.107 Meter-proving connections.
3174.108 Back-pressure and check valves.
3174.110 Coriolis meter operating requirements.
3174.120 Electronic liquids measurement, ELM (secondary and tertiary 
device).
3174.121 Measurement data system (MDS).
3174.130 Coriolis measurement systems (CMS)--general requirements 
and components.
3174.140 Temporary measurement.
3174.150 Meter-proving requirements.
3174.151 Meter prover.
3174.152 Meter-proving runs.
3174.153 Minimum proving frequency.
3174.154 Excessive meter factor deviation.
3174.155 Verification of the temperature transducer.
3174.156 Verification of the pressure transducer (if applicable).
3174.157 Density verification (if applicable).
3174.158 Meter proving reporting requirements.
3174.160 Measurement tickets.
3174.161 Tank gauging measurement ticket.
3174.162 LACT system and CMS measurement ticket or volume statement.
3174.170 Oil measurement by other methods.
3174.180 Determination of oil volumes by methods other than 
measurement.
3174.190 Immediate assessments.


Sec.  3174.10   Definitions and acronyms.

    (a) As used in this subpart, the term:
    Barrel (bbl) means 42 standard United States gallons.
    Base pressure means:
    (i) 0.0 pounds per square inch, gauge (psig);
    (ii) 14.696 pounds per square inch, absolute (psia); or
    (iii) Local atmospheric pressure for static measurement.
    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.
    Coriolis measurement system (CMS) means a metering system using a 
Coriolis meter in conjunction with an ELM, 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.
    Coriolis meter means a device, which determines a mass flow rate by 
means of the interaction between a flowing fluid and oscillation of 
tube(s). 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.
    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.
    Electronic liquids measurement (ELM) means all the hardware and 
software necessary to convert indicated volume, meter factor, flowing 
temperature, and flowing pressure to a gross standard volume or net 
standard volume that is used to determine Federal royalty. This 
includes, but is not limited to, any BLM-approved meter, temperature 
transducer, pressure transducer, flow computer, display, memory, and 
any internal or external processes used to edit and present the data or 
values measured.
    Gross standard volume means a volume of oil corrected to base 
pressure and temperature, and includes meter factor as applicable.
    High-volume FMP means any FMP that measures more than 1,500, but 
less than 15,000 bbl oil/month over the averaging period.
    Indicated volume means the uncorrected volume indicated by the 
meter in a LACT system or the Coriolis meter in a CMS. For a positive 
displacement meter, the indicated volume is represented by the non-
resettable totalizer on the meter head. For Coriolis meters, the 
indicated volume is the uncorrected (without the meter factor) mass of 
liquid divided by the density.
    Innage 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.
    Low-volume FMP means any FMP that measures 1,500 bbl oil/month or 
less over the averaging period.
    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.
    Measurement period means the duration between the opening date and 
time and closing date and time of a measurement ticket or QTR volume 
statement.
    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.
    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 a 
flow computer on a LACT, CMS, or other system approved by the BLM that 
summarizes the daily and/or hourly volume calculated by the flow 
computer and the average or totals of the dynamic

[[Page 56046]]

data that is used in the calculation of gross standard volume. Volumes 
can be displayed as observed and/or gross standard volume, as required.
    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 at the 
installed pressure-relieving or vapor-recovery devices' settings.
    Very-high-volume FMP means any FMP that measures 15,000 bbl oil/
month or more over the averaging period.
    (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.  3170.10 of this part.
    COA has the meaning set forth in Sec.  3170.10 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.  3170.10 of this part.
    PMT means Production Measurement Team.
    PSIA means pounds per square inch, absolute.
    S&W means sediment and water.


Sec.  3174.20   General requirements.

    (a) Measurement of all oil at an FMP must comply with the standards 
prescribed in this subpart.
    (b) Oil may be stored only in tanks that meet the requirements of 
Sec.  3174.80.
    (c) An operator must obtain a BLM-approved FMP number under 
Sec. Sec.  3173.60 and 3173.61 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 (d) of this section.
    (d) Meters used for allocation under a commingling and allocation 
approval under Sec.  3173.70 are not required to meet the requirements 
of this subpart.


Sec.  3174.30   Incorporation by reference (IBR).

    (a) Certain material is incorporated by reference into this part 
with the approval of the Director of the Federal Register under 5 
U.S.C. 552(a) and 1 CFR part 51. To enforce any edition other than 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 as follows. It 
is also available for inspection at the National Archives and Records 
Administration (NARA). For information on the availability of this 
material at NARA, email [email protected] or go to 
www.archives.gov/federal-register/cfr/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 all 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; Reaffirmed, August 2017 
(``API 2.2A''), IBR approved for Sec.  3174.82(a).
    (2) API MPMS Chapter 2--Tank Calibration, Section 2B, Calibration 
of Upright Cylindrical Tanks Using the Optical Reference Line Method; 
First Edition, March 1989; Reaffirmed, January 2013 (``API 2.2B''), IBR 
approved for Sec.  3174.82(a).
    (3) API MPMS Chapter 2--Tank Calibration, Section 2C--Calibration 
of Upright Cylindrical Tanks Using the Optical-triangulation Method; 
First Edition, January 2002; Reaffirmed, April 2013 (``API 2.2C''), IBR 
approved for Sec.  3174.82(a).
    (4) API MPMS Chapter 3.1A, Standard Practice for the Manual Gauging 
of Petroleum and Petroleum Products; Third Edition, August 2013; 
Reaffirmed, December 2018 (``API 3.1A''), IBR approved for Sec. Sec.  
3174.80(f), 3174.88(a).
    (5) API MPMS Chapter 3--Tank Gauging, Section 1B--Standard Practice 
for Level Measurement of Liquid Hydrocarbons in Stationary Tanks by 
Automatic Tank Gauging; Third Edition, April 2018 (``API 3.1B''), IBR 
approved for Sec.  3174.88(b).
    (6) API MPMS Chapter 3--Tank Gauging, Section 6--Measurement of 
Liquid Hydrocarbons by Hybrid Tank Measurement Systems; First Edition, 
February 2001; Errata, September 2005; Reaffirmed, January 2017 (``API 
3.6''), IBR approved for Sec.  3174.88(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.  3174.152.
    (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.  
3174.151(b), (d), and (e), 3174.152(b).
    (9) API MPMS Chapter 4.5, Master-Meter Provers; Fourth Edition, 
June 2016 (``API 4.5''), IBR approved for Sec.  3174.151(a).
    (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.  
3174.152(b).
    (11) API MPMS Chapter 4.8, Operation of Proving Systems; Second 
Edition, September 2013 (``API 4.8''), IBR approved for Sec. Sec.  
3174.151(a) and (b), 3174.152(c).
    (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.  
3174.151(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.  
3174.130(e), 3174.157.
    (14) API MPMS Chapter 7.1, Temperature Determination--Liquid-in-
Glass Thermometers; Second Edition, August 2017 (``API 7.1''), IBR 
approved for Sec.  3174.86 introductory paragraph and (b).
    (15) API MPMS Chapter 7--Temperature Determination, Section 2--
Portable Electronic Thermometers; Third Edition, May 2018 (``API 
7.2''), IBR approved for Sec.  3174.86 introductory paragraph.
    (16) API MPMS Chapter 7--Temperature Determination, Section 4--
Dynamic Temperature Measurement; Second Edition, January 2018 (``API 
7.4''), IBR approved for Sec.  3174.105(c).
    (17) API MPMS Chapter 8.1, Standard Practice for Manual Sampling of 
Petroleum and Petroleum Products;

[[Page 56047]]

Fourth Edition, October 2013 (``API 8.1''), IBR approved for Sec. Sec.  
3174.84, 3174.157.
    (18) API MPMS Chapter 8.2, Standard Practice for Automatic Sampling 
of Petroleum and Petroleum Products; Fourth Edition, November 2016 
(``API 8.2''), IBR approved for Sec. Sec.  3174.102, 3174.157.
    (19) 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 2015 (``API 8.3''), IBR approved for Sec. Sec.  3174.102, 
3174.157.
    (20) API MPMS Chapter 9.1, Standard Test Method for Density, 
Relative Density, or API Gravity of Crude Petroleum and Liquid 
Petroleum Products by Hydrometer Method; Third Edition, December 2012; 
Reaffirmed, May 2017 (``API 9.1''), IBR approved for Sec.  3174.87.
    (21) API MPMS Chapter 9.2, Standard Test Method for Density or 
Relative Density of Light Hydrocarbons by Pressure Hydrometer; Third 
Edition, December 2012; Reaffirmed, May 2017 (``API 9.2''), IBR 
approved for Sec.  3174.87.
    (22) API MPMS Chapter 9.3, Standard Test Method for Density, 
Relative Density, and API Gravity of Crude Petroleum and Liquid 
Petroleum Products by Thermohydrometer Method; Third Edition, December 
2012; Reaffirmed, May 2017 (``API 9.3''), IBR approved for Sec.  
3174.87.
    (23) API MPMS Chapter 10.4, Determination of Water and/or Sediment 
in Crude Oil by the Centrifuge Method (Field Procedure); Fourth 
Edition, October 2013; Errata, March 2015 (``API 10.4''), IBR approved 
for Sec.  3174.85.
    (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.  3174.90(g), (h), and (i), 3174.120(d), 3174.121(c), 
3174.130(f) and (g), 3174.161(b), 3174.162(a).
    (25) API MPMS Chapter 12.1.1, Calculation of Static Petroleum 
Quantities--Upright Cylindrical Tanks and Marine Vessels; Fourth 
Edition, February 2019 (API 12.1.1), IBR approved for Sec.  
3174.161(b).
    (26) API MPMS Chapter 12--Calculation of Petroleum Quantities, 
Section 2--Calculation of Petroleum Quantities Using Dynamic 
Measurement Methods and Volumetric Correction Factors, Part 2--
Measurement Tickets; Third Edition, June 2003; Reaffirmed, February 
2016 (``API 12.2.2''), IBR approved for Sec. Sec.  3174.90(i), 
3174.121(c), 3174.130(g), 3174.162(a).
    (27) API MPMS Chapter 12--Calculation of Petroleum Quantities, 
Section 2--Calculation of Petroleum Quantities Using Dynamic 
Measurement Methods and Volumetric Correction Factors, Part 3--Proving 
Report; First Edition, October 1998; Reaffirmed, May 2014 (``API 
12.2.3''), IBR approved for Sec. Sec.  3174.105(d), 3174.106(b), 
3174.152(c) and (e), 3174.158 introductory paragraph and (a).
    (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; Errata, July 2009; Reaffirmed, September 2014 
(``API 12.2.4''), IBR approved for Sec.  3174.151(c).
    (29) API MPMS Chapter 13. 3, Measurement Uncertainty; Second 
Edition, December 2017 (``API 13.3''), IBR approved for Sec.  
3174.31(a).
    (30) API MPMS Chapter 14, Section 3, Orifice Metering of Natural 
Gas and Other Related Hydrocarbon Fluids--Concentric, Square-edged 
Orifice Meters, Part 1: General Equations and Uncertainty Guidelines; 
Fourth Edition, September 2012; Errata, July 2013; Reaffirmed, 
September 2017 (``API 14.3.1''), IBR approved for Sec.  3174.31(a).
    (31) API MPMS Chapter 18--Custody Transfer, Section 1--Measurement 
Procedures for Crude Oil Gathered From Lease Tanks by Truck; Third 
Edition, May 2018 (``API 18.1''), IBR approved for Sec. Sec.  
3174.83(b), 3174.88(a).
    (32) API MPMS Chapter 21--Flow Measurement Using Electronic 
Metering Systems, Section 2--Electronic Liquid Volume Measurement Using 
Positive Displacement and Turbine Meters; First Edition, June 1998; 
Reaffirmed, October 2016 (``API 21.2''), IBR approved for Sec. Sec.  
3174.90(h), 3174.105(e), 3174.106(c), 3174.120(e), 3174.130(f), 
3174.162(b).
    (33) API Recommended Practice (RP) 12R1, Setting, Maintenance, 
Inspection, Operation and Repair of Tanks in Production Service; Fifth 
Edition, August 1997; Reaffirmed, April 2008; Addendum 1, December 2017 
(``API RP 12R1''), IBR approved for Sec.  3174.80(a).
    (34) API RP 2556, Correction Gauge Tables for Incrustation; Second 
Edition, August 1993; Reaffirmed, November 2013 (``API RP 2556''), IBR 
approved for Sec.  3174.82(a).

    Note 1 to paragraph (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.  3174.31   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 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 (both incorporated by reference, see Sec.  3174.30):

 Table 1 to Sec.   3174.31(a)(1): Volume Measurement Uncertainty Levels
------------------------------------------------------------------------
                                                          The overall
                                    If the averaging         volume
           FMP category               period volume       measurement
                                     (see definition    uncertainty must
                                   43 CFR 3170.3) is:      be within:
------------------------------------------------------------------------
Very-high-volume.................  1. Greater than or  0.50
                                    equal to 15,000     percent
                                    bbl/month.
High-volume......................  2. Greater than     1.50
                                    1,500 but less      percent
                                    than 15,000 bbl/
                                    month.
Low-volume.......................  3. Less than or     N/A
                                    equal to 1,500
                                    bbl/month.
------------------------------------------------------------------------

    (2) A BLM State Director may grant an exception to the uncertainty 
levels prescribed in paragraph (a)(1) of this section, but only upon:
    (i) A showing that meeting the required uncertainly level would 
involve extraordinary cost or

[[Page 56048]]

unacceptable adverse environmental impacts; and
    (ii) Written concurrence of the PMT, prepared in coordination with 
the BLM Director or his or her delegate.
    (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.


Sec.  3174.40   Approved measurement equipment and data requirements.

    Sections 3174.41 through 3174.43 list the following:
    (a) Equipment that requires BLM approval before operators may use 
it at an FMP;
    (b) Approved equipment that operators may use at an FMP if that 
equipment meets the requirements of this subpart; and
    (c) Information that this subpart requires operators to submit to 
the BLM.


Sec.  3174.41  Measurement equipment requiring BLM approval.

    Except as provided in Sec.  3174.50, the following equipment 
requires BLM approval prior to use, and must appear on the list of PMT-
reviewed and BLM-approved equipment maintained at www.blm.gov. BLM 
approval will be based upon a showing that the equipment meets or 
exceeds the performance requirements of Sec.  3174.31. To obtain 
approval, the applicant must submit an application to the PMT. 
Recommended testing procedures will be listed at www.blm.gov.
    (a) Automatic tank gauge (ATG) (see Sec.  3174.88(b)(1));
    (b) LACT sampling systems (see Sec.  3174.102);
    (c) Positive displacement meters (see Sec.  3174.104);
    (d) Coriolis meters (see Sec.  3174.104 and Sec.  3174.110(a));
    (e) Coriolis transmitters (see Sec.  3174.104 and Sec.  
3174.110(b));
    (f) Stand-alone temperature averaging devices (see Sec.  
3174.105(a));
    (g) Temperature transducers (see Sec.  3174.105(b));
    (h) Pressure transducers (see Sec.  3174.106(a));
    (i) Flow computers and installed particular software versions (see 
Sec.  3174.120(a));
    (j) Portable electronic thermometers (see Sec.  3174.86(c));
    (k) Measurement data systems (see Sec.  3174.121(a)); and
    (l) Temporary measurement (see Sec.  3174.140).


Sec.  3174.42  Approved measurement equipment.

    The following equipment is approved for use if it meets the 
requirements specified in this subpart:
    (a) Centrifuge tubes (see Sec.  3174.85);
    (b) Liquid-in-glass thermometers (see Sec.  3174.86);
    (c) Hydrometers and thermohydrometers (see Sec.  3174.87); and
    (d) Manual gauging tapes (see Sec.  3174.88(a)).


Sec.  3174.43   Data submission and notification requirements.

    (a) Operators must submit the following information to the BLM 
using a Sundry Notice:
    (1) Notification to the AO of the date an FMP begins voluntary 
early compliance with this subpart (see Sec.  3174.60(b)(3));
    (2) FMP tank calibration charts (tank tables) (see Sec.  
3174.82(d));
    (3) Notification after repair of any LACT system failures or 
equipment malfunctions that may have resulted in measurement error (see 
Sec.  3174.90(e)(1));
    (4) Justification for excessive meter factor deviation (see Sec.  
3174.154(a));
    (5) Prior AO approval to sell or dispose of slop oil (see Sec.  
3174.180(c)); and
    (6) Notification of the volume of slop oil sold or disposed of and 
the method used to compute the volume (see Sec.  3174.180(c)).
    (b) Operators must submit the following information to the BLM upon 
request of the AO:
    (1) ATG Field verification log (see Sec.  3174.88(b)(4));
    (2) Coriolis meter zero value verification procedure (see Sec.  
3174.110(e));
    (3) Log of all meter factors, zero verifications, and zero 
adjustments (see Sec.  3174.110(e));
    (4) ELM Audit trail data including QTR, configuration log, event 
log, and alarm log (see Sec.  3174.120(d));
    (5) Meter proving report (see Sec.  3174.158(c)); and
    (6) Measurement tickets (see Sec.  3174.160).


Sec.  3174.50   Grandfathering.

    (a) The equipment listed in Sec.  3174.41(a) through (i) and 
installed or used at a high- or low-volume FMP prior to [EFFECTIVE DATE 
OF FINAL RULE] is exempt from the approval requirements in Sec.  
3174.41.
    (b) For any high- or low-volume FMP, if any of the equipment listed 
in Sec.  3174.41(a) through (i) is replaced after [EFFECTIVE DATE OF 
FINAL RULE], it is no longer exempt from the approval requirement in 
Sec.  3174.41.
    (c) Any high- or low-volume FMP that changes category and becomes a 
very-high-volume FMP is no longer exempt from the approval requirements 
in Sec.  3174.41.
    (d) Portable electronic thermometers, measurement data systems, and 
temporary measurement are not subject to the exemption provided for in 
paragraph (a) and must be approved by the BLM prior to use.


Sec.  3174.60  Timeframes for compliance.

    (a) All equipment used to measure the volume and quality of oil for 
royalty purposes at an FMP installed after January 17, 2017, must 
comply with the requirements of this subpart starting [EFFECTIVE DATE 
OF FINAL RULE].
    (b) All equipment and measuring procedures used to measure the 
volume and quality of oil for royalty purposes that were in use before 
January 17, 2017, must comply with the requirements of this subpart as 
follows:
    (1) Very-high-volume FMPs must comply starting [DATE ONE YEAR AFTER 
EFFECTIVE DATE OF FINAL RULE];
    (2) High-volume and low-volume FMPs must comply starting [DATE TWO 
YEARS AFTER EFFECTIVE DATE OF FINAL RULE]; or
    (3) An operator may voluntarily begin full compliance with the 
requirements of this subpart at any FMP prior to the mandatory 
compliance dates specified in paragraphs (b)(1) and (2) of this 
section. The operator must notify the AO within 30 days by Sundry 
Notice of the date the FMP began early compliance.
    (c) Prior to the compliance time frames identified in paragraph (b) 
of this section, measurement procedures and equipment used to measure 
oil for royalty purposes that were in use prior to January 17, 2017, 
must continue to comply with the requirements of Onshore Oil and Gas 
Order No. 4, Measurement of Oil, and any COAs, written orders, and 
variances applicable to that equipment.
    (d) All requirements and standards related to measurement of oil 
established by Onshore Oil and Gas Order No. 4, Measurement of Oil, and 
any COAs, written orders, and variances based on Onshore Oil and Gas 
Order No. 4 are rescinded as of the compliance time frames identified 
in paragraph (b) of this section.
    (e) Equipment approvals under Sec.  3174.41 will be required after 
[DATE

[[Page 56049]]

TWO YEARS AFTER EFFECTIVE DATE OF FINAL RULE].


Sec.  3174.70   Measurement location.

    (a) Commingling and allocation. Oil produced from a lease, unit PA, 
or CA may not be commingled with production from other leases, unit 
PAs, or CAs or non-Federal properties before the point of royalty 
measurement, unless prior approval is obtained under Sec. Sec.  3173.70 
and 3173.71 of this part.
    (b) Off-lease measurement. Oil must be measured on the lease, unit 
PA, or CA, unless approval for off-lease measurement is obtained under 
Sec. Sec.  3173.90 and 3173.91 of this part.


Sec.  3174.80  Oil storage tank equipment.

    (a) Each tank used for oil storage must comply with the recommended 
practices listed in API RP 12R1, Subsection 4 (incorporated by 
reference, see Sec.  3174.30).
    (b) Each oil storage tank must be connected, maintained, and 
operated in compliance with Sec. Sec.  3173.20, 3173.31, and 3173.32 of 
this part.
    (c) 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.
    (d) 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.
    (e) Each oil storage tank associated with an FMP that has a tank-
gauging system must be set and maintained level.
    (f) Each oil storage tank associated with an FMP that has a tank-
gauging system must be equipped with a distinct gauging reference point 
consistent with the definition found in API 3.1A, Subsection 3.14 
(incorporated by reference, see Sec.  3174.30). 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.


Sec.  3174.81  Oil measurement by tank gauging.

    Oil measurement by tank gauging must accurately compute the total 
net standard volume of oil withdrawn from a properly calibrated FMP 
tank by following Sec. Sec.  3174.82 through 3174.88 and 3174.31 to 
determine the quantity and quality of oil being removed.


Sec.  3174.82  Oil tank calibration.

    (a) The operator must accurately calibrate each oil storage tank 
associated with an FMP that has a tank-gauging system using API 2.2A, 
API 2.2B, or API 2.2C, and API RP 2556 (all incorporated by reference, 
see Sec.  3174.30).
    (b) The operator must determine FMP tank capacity tables by tank 
calibration using actual tank measurements.
    (1) The unit volume must be in barrels (bbl);
    (2) The incremental height measurement must match the gauging 
increments specified in Sec.  3174.87(a)(3);
    (3) The tank capacity tables must be calculated for a tank shell 
temperature of 60 [deg]F; and
    (4) FMP tank capacity tables must be recalculated if the reference 
gauge point is changed.
    (c) An FMP tank must be recalibrated 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
    (d) FMP tank calibration charts (tank tables) must be submitted to 
the AO by Sundry Notice within 45 days after calibration or 
recalculation of charts.


Sec.  3174.83   Tank-gauging procedures.

    (a) The procedures for oil measurement by tank gauging must comply 
with the requirements outlined in this section and Sec. Sec.  3174.83 
through 3174.88 to determine the quality and quantity of oil measured 
under field conditions at an FMP.
    (b) The operator must follow the operation sequence identified in 
API 18.1, Subsection 6 (incorporated by reference, see Sec.  3174.30).
    (c) During field operations, operators must obtain and document the 
data required under Sec.  3174.161(a).
    (d) The operator must 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 as 
required under Sec.  3173.20 of this part.
    (e) After transfer is complete, the operator must close the tank 
valve and seal the valve as required under Sec. Sec.  3173.20 and 
3173.30 of this part.


Sec.  3174.84  Tank oil sampling.

    Sampling operations must be conducted prior to taking the opening 
gauge, except where the BLM approves an automatic sampling system or 
alternative process. Oil sampling operations conducted on an FMP tank 
must yield a representative sample of the oil and its physical 
properties and must comply with the provisions in API 8.1 pertaining to 
sampling from storage tanks (incorporated by reference, see Sec.  
3174.30).


Sec.  3174.85  Determining S&W content.

    Using the oil samples obtained under Sec.  3174.84, the operator 
must determine the S&W content of the oil in the tank, according to API 
10.4 (incorporated by reference, see Sec.  3174.30).


Sec.  3174.86   Tank oil temperature determination.

    When determining the temperature of oil contained in an FMP tank, 
the operator must comply with paragraphs (a) through (d) of this 
section, API 7.1, Subsections 6.1 through 6.2 and Subsections 7.1 
through 7.1.2.2, or API 7.2, Subsections 7.1 through 7.2.2 and 7.2.5 
through 7.2.9 (both incorporated by reference, see Sec.  3174.30).
    (a) For tanks less than 5,000 bbl nominal capacity, a single 
temperature measurement at the middle of the liquid may be used.
    (b) 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. Refer to API 7.1, Subsection 6.1.1.3 (incorporated by 
reference, see Sec.  3174.30) for allowable American Society for 
Testing and Materials (ASTM) tank thermometers meeting these 
requirements.
    (c) Electronic thermometers must have a minimum graduation of 0.1 
[deg]F and have an accuracy of 0.5 [deg]F. The specific 
makes and models of electronic thermometers identified and described at 
www.blm.gov are approved for use. If an electronic thermometer is used, 
a flow-weighted average can be used in lieu of a single-point opening 
and closing temperature.
    (d) Record the temperature to the nearest 1.0 [deg]F for glass 
thermometers or 0.1 [deg]F for electronic thermometers.


Sec.  3174.87  Observed oil gravity determination.

    Tests for oil gravity must comply with paragraphs (a) through (c) 
of this section and API 9.1, API 9.2, or API 9.3 (all incorporated by 
reference, see Sec.  3174.30).
    (a) 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.
    (b) Allow the temperature to stabilize for at least 5 minutes prior 
to reading the thermometer.
    (c) 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.

[[Page 56050]]

Sec.  3174.88  Measuring tank fluid level.

    The operator must take and record the opening gauge only after 
samples have been taken. Gauging must comply with either paragraph (a) 
of this section for manual gauging, or paragraph (b) of this section 
for automatic tank gauging.
    (a) For manual innage gauging, the operator must comply with the 
requirements of API 3.1A, Subsections 4.1 through 4.2.2.3 and 5.1 
through 5.4, and API 18.1, Subsection 6.8 (both incorporated by 
reference, see Sec.  3174.30) and the following:
    (1) A proper innage-gauging bob must be used;
    (2) 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;
    (3) The operator must either obtain two consecutive identical 
gauging measurements for any tank regardless of size, or:
    (i) For tanks of 1,000 bbl or less in nominal capacity, obtain 
three consecutive measurements that are within 1/4 inch of each other 
and average these three measurements to the nearest 1/4 inch; or
    (ii) For tanks greater than 1,000 bbl in nominal capacity, obtain 
three consecutive measurements within 1/8 inch of each other, averaging 
these three measurements to the nearest 1/8 inch.
    (4) A suitable product-indicating paste may be used on the tape to 
facilitate the reading. The use of chalk or talcum powder is 
prohibited.
    (b) For automatic tank gauging (ATG), comply with the requirements 
of API 3.1B, and API 3.6, Subsection 6.2, (both incorporated by 
reference, see Sec.  3174.30) and the following:
    (1) The specific makes and models of ATG that are identified and 
described at www.blm.gov are approved for use;
    (2) The ATG must be installed per the requirements of API 3.1B, 
Subsections 5, 6, and 7 (incorporated by reference, see Sec.  3174.30), 
the manufacturer's recommendations, and any COAs from the BLM equipment 
approval;
    (3) The ATG must be inspected and its accuracy verified to within 
1/4 inch in for tanks of 1,000 bbl or less in nominal 
capacity or within 1/8 inch for tanks greater than 1,000 
bbl in nominal capacity in accordance with procedures outlined in API 
3.1B, Subsection 9 (incorporated by reference, see Sec.  3174.30) prior 
to FMP measurement, but no more frequently than monthly, or any time at 
the request of the AO. If the ATG is found to be out of the 
manufacturer's tolerance, the ATG must be calibrated prior to FMP 
measurement;
    (4) A detailed log of field verifications must be maintained and 
available upon request. The log must be in compliance with Sec.  
3170.50(g) of this part and 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; and
    (5) The date of last ATG field verification must be maintained at 
the FMP in legible condition, in compliance with Sec.  3170.50(g) of 
this part, and accessible to the AO at all times.


Sec.  3174.90   LACT system--general requirements.

    (a) A LACT system must meet the construction and operation 
requirements and minimum standards of this section and Sec. Sec.  
3174.31 and 3174.100.
    (b) A LACT system must be proven as prescribed in Sec.  3174.150.
    (c) All components of a LACT system must be accessible for 
inspection by the AO.
    (d) Automatic temperature compensators and automatic temperature 
and gravity compensators are prohibited and are not grandfathered 
equipment under Sec.  3174.50.
    (e) The operator must notify the AO by Sundry Notice within 30 days 
after repair of any LACT system failures or equipment malfunctions that 
may have resulted in measurement error. 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 S&W content and observed oil gravity must 
meet the requirements and minimum standards in Sec. Sec.  3174.85 and 
3174.87.
    (g) The average temperature for the measurement ticket must be 
calculated for the measurement period covered under the measurement 
ticket and must be the temperature used to calculate the CTL correction 
factor using API 11.1 (incorporated by reference, see Sec.  3174.30).
    (h) The pressure for the measurement ticket must be determined by:
    (1) A direct reading of the installed pressure gauge; or,
    (2) If the LACT is equipped with an ELM system or an automatic 
adjusting back-pressure control, then the system must utilize a 
pressure transducer. If using a pressure transducer, the average 
pressure must be calculated beginning when the measurement ticket was 
opened. The average pressure must be calculated by the volumetric 
averaging method using API 21.2, Subsection 9.2.13.2a (incorporated by 
reference, see Sec.  3174.30) and must be used to calculate the CPL 
correction factor using API 11.1. (incorporated by reference, see Sec.  
3174.30).
    (i) Calculate the net standard volume of each measurement ticket 
following API 11.1 and API 12.2.2, Subsections 9, 10, and 11 
(incorporated by reference, see Sec.  3174.30) or any other BLM-
approved methods.
    (j) Measurement tickets must be completed under Sec.  3174.162.


Sec.  3174.100  LACT system--components and operating requirements.

    Unless otherwise approved, each LACT system must include all of the 
equipment listed in Sec. Sec.  3174.101 through 3174.108 and LACT 
operation must meet the requirements of Sec. Sec.  3174.101 through 
3174.108.


Sec.  3174.101   Charging pump and motor.

    Where the static head is insufficient to provide a net positive 
suction head for desired fluid pressure and flowrates, the LACT system 
must include an electrically-driven charge pump that has a discharge 
pressure rate compatible with the meter used and is sized to assure 
turbulent flow in the LACT main stream piping.


Sec.  3174.102  Sampling and mixing system.

    Sampling and mixing systems that are identified and described at 
www.blm.gov are approved for use. Sampling and mixing must be conducted 
in accordance with API 8.2 and API 8.3 (both incorporated by reference, 
see Sec.  3174.30) and the following:
    (a) The sample extractor probe must:
    (1) Be inserted within the center half of the flowing stream;
    (2) Be horizontally oriented; and
    (3) Have external markings that show the orientation of the probe 
in relation to fluid flow direction.
    (b) Sampling frequency must be proportioned to the flow rate 
through the meter and must be based on maximizing the number of grabs 
for the composite-sample container for the measurement period;
    (c) The composite-sample container must be capable of holding the 
sample under pressure, must be equipped with a vapor-proof top closure, 
and must be operated to prevent the unnecessary escape of vapor. The 
composite sample container must be emptied and cleaned upon completion 
of sample withdrawal and when closing a run ticket; and
    (d) The mixing system must completely blend the sample (inside the

[[Page 56051]]

composite sample container) into a homogeneous mixture before and 
during the withdrawal of a portion of the sample for testing.


Sec.  3174.103  Air eliminator.

    An air eliminator must be installed to prevent air or gas from 
entering the meter. The air eliminator may be integrated with an 
optional strainer.


Sec.  3174.104   LACT meter.

    The LACT meter must be a positive displacement meter, a Coriolis 
meter (see Sec.  3174.110), or other meter approved by the BLM. The 
specific make, models, and sizes of positive displacement, Coriolis 
meter, Coriolis transmitter, or other approved meters that are 
identified and described at www.blm.gov are approved for use.
    (a) The LACT meter must be equipped with a non-resettable 
totalizer. The non-resettable totalizer display may reside in an 
electronic flow computer.
    (b) The LACT meter must include or allow for the attachment of a 
device that generates at least 8,400 pulses per barrel of registered 
volume.


Sec.  3174.105   Electronic temperature averaging device.

    The electronic temperature averaging device may be a stand-alone 
device or a function of a flow computer and must be installed, 
operated, and maintained as follows:
    (a) The specific makes and models of stand-alone electronic 
temperature averaging devices that are identified and described at 
www.blm.gov are approved for use.
    (b) The specific makes and models of temperature transducers that 
are identified and described at www.blm.gov are approved for use.
    (c) The temperature thermowell and transducer must be installed no 
further than 5 pipe diameters downstream from the meter, in compliance 
with API 7.4, Subsections 6.3 and 7.2 (incorporated by reference, see 
Sec.  3174.30);
    (d) The temperature averaging device must have a reference accuracy 
of 0.5 [deg]F or better, and have a minimum display 
discrimination level in accordance with API 12.2.3, Subsection 11.2, 
table 3 (incorporated by reference, see Sec.  3174.30);
    (e) 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.  3174.30); and
    (f) The temperature averaging device must include a display of 
instantaneous temperature and the average temperature calculated since 
the measurement ticket was opened. The display may be a function of an 
electronic flow computer.


Sec.  3174.106   Pressure-indicating device.

    The pressure-indicating device may be either a pressure gauge or 
pressure transducer and must be installed, operated, and maintained as 
follows:
    (a) The system must have a pressure-indicating device located 
downstream of the meter, but on the upstream side of the first valve of 
the prover connection. The pressure-indicating device must be capable 
of providing pressure data to calculate the CPL correction factor. The 
specific makes and models of pressure transducers that are identified 
and described at www.blm.gov are approved for use.
    (b) The pressure-indicating device must have a minimum display 
discrimination level in accordance with API 12.2.3, Subsection 11.2, 
table 4 (incorporated by reference, see Sec.  3174.30); and
    (c) If a pressure transducer is used, it must be used in 
conjunction with an electronic pressure-averaging device. A pressure-
averaging device may be a function of a flow computer:
    (1) The electronic pressure averaging device must include a display 
of instantaneous pressure and the average pressure calculated since the 
measurement ticket was opened. The display may be a function of an 
electronic flow computer; and
    (2) The electronic pressure averaging device must be volume-
weighted and take a pressure reading in accordance with API 21.2, 
Subsection 9.2.8 (incorporated by reference, see Sec.  3174.30).


Sec.  3174.107  Meter-proving connections.

    All meter-proving connections must be installed downstream from the 
LACT meter and upstream of back-pressure control. The line valve(s) 
must be installed between the inlet and outlet of the prover loop and 
must be configured with a double block and bleed design feature to 
provide for leak testing during proving operations. All valves must be 
full opening valves.


Sec.  3174.108  Back-pressure and check valves.

    The back-pressure and check valves must be installed downstream 
from the meter-proving connections. Back pressure must be applied by 
either a back-pressure valve or other controllable means of applying 
back pressure. Back pressure may be maintained by an automatic-
adjusting back-pressure control to adjust for changing flowing 
conditions. Back-pressure control must maintain a pressure that is 
above the bubble point of the liquid to prevent the formation of vapor, 
ensuring single phase flow.


Sec.  3174.110  Coriolis meter operating requirements.

    (a) The specific makes, models, and sizes of Coriolis meters that 
are identified and described at www.blm.gov are approved for use.
    (b) The specific makes and models of Coriolis transmitters that are 
identified and described at www.blm.gov are approved for use.
    (c) 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.
    (d) The Coriolis meter must have a non-resettable internal 
totalizer for indicated volume. The non-resettable totalizer display 
may reside in an electronic flow computer, but must be generated from 
the Coriolis meter. A flow-computer-generated totalizer does not comply 
with the requirements of this subpart.
    (e) Meter zero verification must be conducted during the proving 
process, or any time the AO requests it. 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 reading has been 
adjusted, the meter must be proven as required by Sec.  3174.150. A 
copy of the zero value verification procedure must be made available to 
the AO upon request. 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 to the AO upon request.
    (f) The required on-site information may be displayed on a Coriolis 
meter display or may reside in an electronic flow computer. The display 
must provide the following information:
    (1) The 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 on the device or the ELM 
display:

[[Page 56052]]

    (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 cumulative indicated volume through the meter (non-
resettable totalizer) (bbl); and
    (v) The previous day's indicated volume through the meter (bbl).


Sec.  3174.120  Electronic liquids measurement system, ELM (secondary 
and tertiary device).

    Any FMP with an ELM installed must comply with the requirements of 
this section. An ELM is required on all very-high-volume FMPs, and all 
CMS regardless of FMP category.
    (a) The specific makes and models of flow computers and software 
versions that are identified and described at www.blm.gov are approved 
for use.
    (b) For each ELM, the following values and corresponding units of 
measurement must be displayed:
    (1) The instantaneous density of liquid (pounds/bbl, pounds/gal, or 
degrees API);
    (2) The instantaneous indicated volumetric flow rate through the 
meter (bbl/day);
    (3) The meter factor;
    (4) The instantaneous pressure (psi);
    (5) The instantaneous temperature ([deg]F);
    (6) The average temperature calculated since the measurement ticket 
was opened;
    (7) The cumulative indicated volume through the meter (non-
resettable totalizer) (bbl); and
    (8) The previous day's indicated volume through the meter (bbl).
    (c) The following information must be correct, must be maintained 
in a legible condition, and must be accessible to the AO at the FMP 
without the use of data-collection equipment, laptop computers, or any 
special equipment:
    (1) The make, model, and size of each sensor; and
    (2) The make, model, range, and calibrated span of the pressure and 
temperature transducer used to determine gross standard volume.
    (d) Calculated volumetric output of the ELM must incorporate the 
meter factor and correct for CTL and CPL in accordance with API 11.1 
(incorporated by reference, see Sec.  3174.30).
    (e) The information specified in paragraphs (e)(1) through (4) of 
this section must be recorded and retained under the recordkeeping 
requirements of Sec.  3170.50(g) of this part. The audit trail must 
comply with API 21.2, Subsection 10 (incorporated by reference, see 
Sec.  3174.30). All data must be available and submitted to the BLM 
upon request.
    (1) Quantity transaction record (QTR): Retention of QTR data must 
be on a daily (24-hour) basis, except in circumstances where batch 
delivery duration is less than 24 hours. In these situations, hourly 
data retention is required. The QTR must follow the requirements for a 
measurement ticket in Sec.  3174.162.
    (2) Configuration log: The configuration log must comply with the 
requirements of API 21.2, Subsection 10.2 (incorporated by reference, 
see Sec.  3174.30). 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.  
3174.30). 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.  3170.50(g) of this part.
    (4) Alarm log: The type and duration of any of the following alarm 
conditions must be recorded:
    (i) Deviations from acceptable density parameters for Coriolis flow 
meters;
    (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;
    (iii) Instances in which the temperature of the fluid exceeded the 
calibrated span of the temperature transmitter;
    (iv) Instances in which the pressure of the fluid exceeded the 
calibrated span of the pressure transmitter;
    (v) Any power loss to the meter or instance in which the ELM no 
longer detects the meter output; and
    (vi) Instances in which any other meter output exceeds its user-
defined span of operation.
    (5) The alarm log may be part of the event log and fulfill the 
requirements of this subpart, as long as protections are in place to 
ensure that excessive alarming will not affect the event log's 
compliance with the record-keeping requirements of this subpart.
    (f) Each ELM must have installed and maintained in an operable 
condition a backup power supply or a nonvolatile memory capable of 
retaining all required raw data in the unit's memory for at least 35 
days to ensure that the audit-trail information required under 
paragraph (e) of this section is protected.


Sec.  3174.121  Measurement data system (MDS).

    (a) The specific MDS that are identified (by name and version) and 
described at www.blm.gov are approved for use. MDS are not 
grandfathered under Sec.  3174.50.
    (b) The MDS must comply with the recordkeeping requirements of 
Sec.  3170.50(g) of this part.
    (c) The MDS must calculate net standard volume in accordance with 
API 11.1 and API 12.2.2, Subsections 9, 10 and 11 (both incorporated by 
reference, see Sec.  3174.30) or other methods approved by the BLM.
    (d) The MDS must maintain and preserve the raw data from the 
primary and secondary elements of the system as well as clearly show 
edits and corrections made by the user.


Sec.  3174.130  Coriolis measurement systems (CMS)--general 
requirements and components.

    This section applies to Coriolis measurement applications 
independent of LACT measurement systems.
    (a) A CMS must meet the requirements and minimum standards of this 
section and Sec. Sec.  3174.31 and 3174.110.
    (b) A CMS must be equipped with an ELM system meeting the 
requirements of Sec.  3174.120.
    (c) A CMS system must be proven in compliance with Sec.  3174.150.
    (d) CMS measurement tickets must be completed under Sec.  3174.162.
    (e) A CMS at an FMP must be installed with the components listed in 
API 5.6, Subsection 6.3 (incorporated by reference, see Sec.  3174.30). 
Additional requirements are as follows:
    (1) The pressure transducer must meet the requirements of Sec.  
3174.106(a), (b), and (c);
    (2) Temperature determinations must meet the requirements of Sec.  
3174.105(b) and (c);
    (3) If nonzero S&W content is to be used in determining net oil 
volume, the sampling system must meet the requirements of Sec.  
3174.102 and any tests conducted on oil samples for determination of 
S&W content must meet the requirements of Sec.  3174.85. If no sampling 
system is used, or the sampling system does not meet the requirements 
of Sec.  3174.102, the S&W content must be reported as zero;
    (4) Sufficient back pressure must be applied to ensure single-phase 
flow through the meter; and
    (5) Block valves must be present at both ends of the system to 
allow for a zero-flow verification.
    (f) The API oil gravity reported for the measurement-ticket period 
must be

[[Page 56053]]

determined by one of the following methods:
    (1) Determined from a composite sample taken pursuant to Sec.  
3174.87; 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.  3174.30). Density must be 
corrected to base temperature and pressure using API 11.1 (incorporated 
by reference, see Sec.  3174.30).
    (g) Calculate the net standard volume at the close of each 
measurement ticket following the guidelines in API 11.1 and API 12.2.2, 
Subsections 9, 10 and 11 (both incorporated by reference, see Sec.  
3174.30) or any method approved by the BLM identified and described at 
www.blm.gov.
    (h) If the CMS is mounted on a truck or trailer that travels 
between locations, referred to as a Truck-Mounted Coriolis (TMC), the 
unit must meet all requirements of the CMS, subject to the following 
special considerations:
    (1) The TMC is required to meet the performance requirements of a 
very-high-volume FMP;
    (2) The meter factor used during the truck load at an FMP must be 
derived from a prove that is within the defined ``normal operating 
conditions'' of Sec.  3174.150 for that location;
    (3) The display and on-site information requirements of the CMS 
only apply when the TMC is at that location;
    (4) The proving frequency will be based on the total volume passing 
through the TMC meter, not the volume at any specific location, and 
will include non-Federal or non-tribal volumes that may have passed 
through the meter;
    (5) The notification requirements of the proving must be followed, 
including the ability for a BLM representative to witness the prove, 
even if the proving is not carried out on a BLM location;
    (6) The operator must make available, at the request of an AO, data 
for non-Federal and non-tribal transfers, in which the TMC was used so 
that a full audit can be conducted (such data may be de-identified);
    (7) The sales line between the TMC and the sales valve at the FMP 
must be connected before the seal is broken on the valve;
    (8) The seal on the sales valve must be replaced at the end of each 
truck load using a TMC (multi-truck loads without seal replacement are 
prohibited);
    (9) The operator must show the TMC will be able to comply with the 
audit trail requirements of Sec.  3173; and
    (10) Any variations from these requirements are considered 
alternative methods of measurement and will require PMT review and BLM 
approval.


Sec.  3174.140  Temporary measurement.

    Measurement equipment at any temporary measurement facility must 
meet the requirements of this subpart, subject to the following special 
considerations:
    (a) Temporary measurement facilities must meet the performance 
requirements of very-high-volume FMPs;
    (b) Any temporary measurement facility that meets the definition of 
LACT or CMS must be proved on the location within 72 hours of first 
flow through the meter. If the meter is on location for less than 72 
hours, it must be proved so a meter factor can be established before it 
is removed from service; and
    (c) Any temporary measurement facility must be identified as such 
and provide a unique identification number that can be tied to the 
location for all records.


Sec.  3174.150  Meter-proving requirements.

    Sections 3174.151 through 3174.158 specify the minimum requirements 
for conducting volumetric meter proving for all FMP meters.


Sec.  3174.151  Meter prover.

    Acceptable provers are positive-displacement master meters, 
Coriolis master meters, and displacement provers, or other provers 
approved by the BLM and identified and described at www.blm.gov. 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 the serial number assigned to and inscribed on the prover, was 
calibrated as follows:
    (a) Master meters must have a meter factor within 0.9900 to 1.0100 
as 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, Table 2 (incorporated by reference, see Sec.  3174.30). 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 3 
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 in accordance with API 4.8, Annex B.2 (incorporated by 
reference, see Sec.  3174.30).
    (b) Displacement provers must meet the requirements of API 4.2 
(incorporated by reference, see Sec.  3174.30) and be calibrated using 
the water-draw method under API 4.9.2 (incorporated by reference, see 
Sec.  3174.30), at the calibration frequencies specified in API 4.8, 
Subsection 10.1(b) (incorporated by reference, see Sec.  3174.30).
    (c) The base prover volume of a displacement prover must be 
calculated in accordance with API 12.2.4 (incorporated by reference, 
see Sec.  3174.30).
    (d) Displacement provers must be sized to obtain a displacer 
velocity through the prover that is within the appropriate range during 
proving in accordance with API 4.2, Subsection 4.3.4.2, Minimum 
Displacer Velocities and Subsection 4.3.4.1, Maximum Displacer 
Velocities (incorporated by reference, see Sec.  3174.30).
    (e) Fluid velocity must be calculated using API 4.2, Subsection 
4.3.4.3, Equation 12 (incorporated by reference, see Sec.  3174.30).


Sec.  3174.152  Meter-proving runs.

    Meter proving must follow the applicable section(s) of API 4.1, 
Proving Systems (incorporated by reference, see Sec.  3174.30).
    (a) Meter proving must be performed under normal operating 
conditions. The normal operating condition will be established by the 
flow rate, fluid pressure, fluid temperature, and fluid gravity, at the 
time of proving. These established normal operating conditions will be 
in effect until the next proving. Except for impacts from any routine 
activities, such as pipeline pigging operations or temporary 
interruptions not lasting more than 3 consecutive days or any 7 days 
total within the proving period cycle, the flow rate, fluid pressure, 
fluid temperature, and fluid gravity, must remain in the following 
ranges or the conditions for normal operating will no longer be met and 
a new proving is required:
    (1) The oil flow rate through the LACT or CMS must remain within 10 
percent of the flow rate established during the proving;
    (2) The pressure as measured by the LACT or CMS must remain within 
10 percent of the pressure established during the proving. Back 
pressure may be adjusted after prover connection,

[[Page 56054]]

prior to proving to establish the normal condition;
    (3) The temperature as measured by the LACT or CMS must remain 
within 10 [deg]F of the operating temperature established during the 
proving; and
    (4) The gravity of the oil must remain within 5 degrees API of the 
oil gravity established during the proving.
    (b) If each proving run is not of sufficient volume to generate at 
least 10,000 pulses, as specified by API 4.2, Subsection 4.3.2.1 
(incorporated by reference, see Sec.  3174.30), from the positive 
displacement meter or the Coriolis meter, then pulse interpolation must 
be used in accordance with API 4.6, Pulse Interpolation (incorporated 
by reference, see Sec.  3174.30).
    (c) 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.  3174.30), or from any of the number of runs 
indicated in API 4.8 Table A.1 (incorporated by reference, see Sec.  
3174.30) that will result in the 0.027 percent uncertainty 
repeatability criteria.
    (d) The new meter factor is the arithmetic average of the meter-
generated pulses or intermediate meter factors calculated from the 
proving runs under paragraph (c) of this section.
    (e) Meter factor computations must follow the sequence described in 
API 12.2.3, Subsection 12 (incorporated by reference, see Sec.  
3174.30).
    (f) The meter factor must be at least 0.9900 and no more than 
1.0100.
    (g) The initial meter factor for a new or repaired meter must be at 
least 0.9950 and no more than 1.0050.
    (h) If multiple meter factors are determined over a range of normal 
operating conditions, then:
    (1) 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
    (2) The metering system may apply a dynamic meter factor derived 
(e.g., using linear interpolation, polynomial fit, etc.) from the 
series of meter factors determined over the range of normal operating 
conditions, so long as no two neighboring meter factors differ by more 
than 0.0020.
    (i) Composite meter factors may only be used with a fixed-setting, 
back-pressure system. If a composite meter factor is calculated, the 
CPL value used must be calculated from the fluid flowing pressure at 
the conclusion of the proving operations, after the prover has been 
disconnected and all back-pressure adjustments are completed. After the 
prover has been disconnected and the fixed back-pressure setting has 
been adjusted, the back-pressure valve must be sealed under Sec.  
3173.21 of this part.


Sec.  3174.153   Minimum proving frequency.

    The operator must prove any FMP meter before removal or sales of 
production after any of the following events:
    (a) Within 15 days of the first flow after installation of the FMP;
    (b) 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;
    (c) Meter zeroing (Coriolis meter);
    (d) Removal and reinstallation of the meter;
    (e) A change in fluid temperature that exceeds the transducer's 
calibrated span;
    (f) A change in the flow rate, pressure, temperature, or gravity 
that exceeds the normal operating conditions as defined in Sec.  
3174.152(a);
    (g) The mechanical or electrical components of the meter are 
changed, repaired, or removed;
    (h) Internal calibration factors are changed or reprogrammed; and
    (i) At the request of the AO.


Sec.  3174.154   Excessive meter factor deviation.

    If the difference in meter factors between any two consecutive 
provings exceeds 0.0025 then:
    (a) The operator must submit by Sundry Notice for approval to the 
AO a statement explaining that the meter did not malfunction; or
    (b) If the AO does not approve the explanation that the meter did 
not malfunction or the operator did not provide one, then the meter 
must be immediately removed from service, checked for damage or wear, 
adjusted or repaired, and re-proved before returning the meter to 
service. The proving report submitted under Sec.  3174.158 must clearly 
describe all repairs and adjustments; and
    (c) The arithmetic average of the two consecutive meter factors 
(the previous meter factor and the excessive meter factor) must be 
applied to the production measured through the meter between the date 
of the previous meter proving and the date of the excessive meter 
factor proving.


Sec.  3174.155   Verification of the temperature transducer.

    As part of each required meter proving and upon replacement, the 
temperature transducer used in conjunction with a temperature averager 
for a LACT system and the temperature transducer used in conjunction 
with an ELM must be verified against a known standard according to the 
following:
    (a) The temperature transducer must be compared with a test 
thermometer traceable to NIST and with a stated accuracy of 0.25 [deg]F or better;
    (b) The temperature reading displayed on the temperature average 
display or ELM display must be compared with the reading of the test 
thermometer using one of the following methods:
    (1) The test thermometer must be placed in a test thermometer well 
located not more than 12 inches from the probe of the temperature 
transducer; or
    (2) Both the test thermometer and probe of the 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.
    (c) The displayed reading of instantaneous temperature from the 
temperature average display or ELM display 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:
    (1) The temperature transducer must be adjusted to match the 
reading of the test thermometer; or
    (2) The temperature transducer must be recalibrated, repaired, or 
replaced.


Sec.  3174.156  Verification of the pressure transducer (if 
applicable).

    (a) As part of each required meter proving and upon replacement, 
the pressure transducer must be compared with a test pressure device 
(dead weight or pressure gauge) traceable to NIST and having a stated 
maximum uncertainty of no more than one-half of the accuracy required 
from the transducer being verified.
    (b) The pressure reading displayed on the pressure transducer must 
be compared with the reading of the test pressure device.
    (c) The pressure transducer must be tested at the following three 
points:

[[Page 56055]]

    (1) Zero (atmospheric pressure);
    (2) 100 percent of the calibrated span of the pressure transducer; 
and
    (3) A point that represents the normal flowing pressure through the 
Coriolis meter.
    (d) 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.


Sec.  3174.157   Density verification (if applicable).

    If the API gravity of oil is determined from the average density 
measured by the Coriolis meter (rather than from a composite sample), 
then during each proving of the Coriolis meter, the instantaneous 
flowing density determined by the Coriolis meter must be verified by 
comparing it with an independent density measurement as specified under 
API 5.6, Subsection 9.1.2.1 (incorporated by reference, see Sec.  
3174.30). 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 (all incorporated by reference, see Sec.  3174.30), 
as appropriate.


Sec.  3174.158   Meter proving reporting requirements.

    Meter proving reports may be in any format showing the information 
required in this section, provided that the calculation of meter 
factors maintains the proper calculation sequence and rounding. For 
example: The forms listed in API 12.2.3, Subsection 13 or API 5.6 
Appendix C (see Sec.  3174.30 for availability information) may be 
used.
    (a) Each meter proving report must contain the following 
information recorded at the discrimination levels described in API 
12.2.3, Section 11 (incorporated by reference, see Sec.  3174.30):
    (1) The information identified and required under the recordkeeping 
requirements of Sec.  3170.50(g) of this part;
    (2) Unique meter identification number;
    (3) Meter specification data;
    (4) Fluid data;
    (5) Liquid properties at metering condition;
    (6) Report data, including previous and current flow rates, 
totalizer, API gravity at 60 [deg]F, and meter factor;
    (7) For each proving run the following raw data must be documented:
    (i) Run number;
    (ii) Temperature of prover and meter;
    (iii) Pressure of prover and meter; and
    (iv) Pulses and/or intermediate meter factor, as applicable;
    (8) Calculation of correction factors for both prover and meter;
    (9) Calculation of meter factors;
    (10) The temperature from the test thermometer and the temperature 
from the temperature averager or temperature transducer in accordance 
with Sec.  3174.155;
    (11) For pressure transducers (if applicable), the pressure applied 
by the pressure test device and the pressure reading from the pressure 
transducer at the three points required under Sec.  3174.156(c);
    (12) For density verification (if applicable), the instantaneous 
flowing density (as determined by the Coriolis meter), and the 
independent density measurement, as compared under Sec.  3174.157; and
    (13) If a composite meter factor will be used, the ``as left'' 
fluid flowing pressure after disconnecting the prover.
    (b) In addition to the information required under paragraph (a) of 
this section, 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.
    (c) The meter-proving report must be made available to the AO upon 
request.


Sec.  3174.160  Measurement tickets.

    Sections 3174.161 through 3174.162 outline the information required 
to be included on a uniquely numbered measurement ticket or volume 
statement, in either paper or electronic format, that must be completed 
prior to oil-volume reporting on an OGOR. Measurement tickets must be 
made available to the AO upon request.


Sec.  3174.161   Tank-gauging measurement ticket.

    (a) The following information must be documented during the field 
tank-gauging operation by the operator, purchaser, or transporter, as 
appropriate:
    (1) The information identified and required under the recordkeeping 
requirements of Sec.  3170.50(g) of this part;
    (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 API oil gravity and temperature in [deg]F;
    (6) S&W content percent;
    (7) Unique number of each seal removed and installed; and
    (8) Name of the individual performing the tank gauging.
    (b) The following information is required to be calculated and 
documented on the measurement ticket upon the completion of the 
measurement ticket by the operator, purchaser, or transporter, as 
appropriate:
    (1) Observed volume for opening and closing gauge, using tank-
specific calibration charts (see Sec.  3174.52);
    (2) API oil gravity at 60 [deg]F, following API 11.1 (incorporated 
by reference, see Sec.  3174.30), utilizing the glass thermal expansion 
equation when using hydrometer or thermohydrometer; and
    (3) Total net standard volume removed from the tank following API 
11.1 and API 12.1.1, Subsections 10 and 11, (both incorporated by 
reference, see Sec.  3174.30) or other methods approved by the BLM.


Sec.  3174.162  LACT system and CMS measurement ticket or volume 
statement.

    At the beginning of every month, the operator, purchaser, or 
transporter, as appropriate, must document either a measurement ticket 
under paragraph (a) of this section, or a volume statement under 
paragraph (b) of this section. A measurement ticket under paragraph (a) 
of this section must also be closed when proving operations are 
conducted.
    (a) A measurement ticket must include the following:
    (1) The information identified and required under the recordkeeping 
requirements of Sec.  3170.50(g) of this part;
    (2) The unique meter identification number;
    (3) Opening and closing dates and times;
    (4) Opening and closing totalizer readings of the indicated volume;
    (5) The meter factor, if meter factor is a composite meter factor, 
indicate as such;
    (6) Total gross standard volume removed through the LACT system or 
CMS;
    (7) 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;
    (8) The average temperature for the measurement period in [deg]F;
    (9) The average flowing pressure for the measurement period in 
psig;
    (10) S&W content percent;

[[Page 56056]]

    (11) Total net standard volume following API 11.1 and API 12.2.2, 
Subsections 9, 10 and 11 (both incorporated by reference, see Sec.  
3174.30) or other methods approved by the BLM.
    (12) Unique number of each seal removed and installed; and
    (13) Name of the purchaser's representative; or
    (b) A volume statement must be generated by an ELM system from 
unaltered, unprocessed, and unedited daily or hourly (as applicable, 
see Sec.  3174.120) QTRs or from measurement-data systems that have 
been approved by the BLM (see Sec.  3174.121). The volume statement 
must contain the information identified in API 21.2, Subsection 10.3.1 
(incorporated by reference, see Sec.  3174.30). Volume statements must 
include the information identified and required under the recordkeeping 
requirements of Sec.  3170.50(g) of this part.
    (c) Any accumulators used in the determination of average pressure, 
average temperature, and average density for the measurement period 
must be reset to zero whenever a new measurement ticket is opened.


Sec.  3174.170   Oil measurement by other methods.

    Any method of oil measurement other than the methods addressed in 
this rule or listed on the www.blm.gov website used at an FMP requires 
prior BLM approval (see Sec.  3170.30 of this part).


Sec.  3174.180  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 may include, 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 by Sundry Notice from the AO. Following 
the sale or disposal of slop oil, the operator must notify the AO by 
Sundry Notice of the volume sold or disposed of and the method used to 
compute the volume.


Sec.  3174.190  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.   3174.190: 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.   3174.100.........................
2. Missing or nonfunctioning FMP CMS components, as                1,000
 required by Sec.   3174.130............................
3. Failure to meet the proving frequency requirements              1,000
 for an FMP, detailed in Sec.   3174.153................
4. Failure to obtain a written approval, as required by            1,000
 Sec.   3174.170, before using any oil measurement
 method other than tank gauging, LACT system, or CMS at
 a FMP..................................................
------------------------------------------------------------------------

0
5. Revise subpart 3175 to read as follows:

Subpart 3175--Measurement of Gas

Sec.
3175.10 Definitions and acronyms.
3175.20 General requirements.
3175.30 Incorporation by reference.
3175.31 Specific performance requirements.
3175.40 Measurement equipment requiring BLM approval.
3175.41 Approved measurement equipment.
3175.43 Data submission and notification requirements.
3175.50 Grandfathering.
3175.60 Timeframes for compliance.
3175.70 Measurement location.
3175.80 Flange-tapped orifice plate (primary device).
3175.90 Mechanical recorder (secondary device).
3175.91 Installation and operation of mechanical recorders.
3175.92 Verification and calibration of mechanical recorders.
3175.93 Integration statements.
3175.94 Volume determination.
3175.100 Electronic gas measurement (secondary and tertiary device).
3175.101 Installation and operation of electronic gas measurement 
systems.
3175.102 Verification and calibration of electronic gas measurement 
systems.
3175.103 Flow rate, volume, and average value calculation.
3175.104 Logs and records.
3175.110 Gas sampling and analysis.
3175.111 General sampling requirements.
3175.112 Sampling probe and tubing.
3175.113 Spot samples--general requirements.
3175.114 Spot samples--allowable methods.
3175.115 Spot samples--frequency.
3175.116 Composite sampling methods.
3175.117 On-line gas chromatographs.
3175.118 Gas chromatograph requirements.
3175.119 Components to analyze.
3175.120 Gas analysis report requirements.
3175.121 Effective date of a spot or composite gas sample.
3175.125 Calculation of heating value and volume.
3175.126 Reporting of heating value and volume.
3175.130 Requirements for gas storage agreement measurement points 
(GSAMPs).
3175.140 Temporary measurement.
3175.150 Immediate assessments.
Appendix A to Subpart 3175--Table of Atmospheric Pressures
Appendix B to Subpart 3175-- Maximum Time Between Required Actions


Sec.  3175.10  Definitions and acronyms.

    (a) As used in this subpart, the term:
    AGA Report No. (followed by a number) means a standard prescribed 
by the American Gas Association, with the number referring to the 
specific standard.
    Area ratio means the smallest unrestricted area at the primary 
device divided by the cross-sectional area of the meter tube. For 
example, the area ratio (Ar) of an orifice plate is the area 
of the orifice bore (Ad) divided by the area of the meter 
tube (AD). For an orifice plate with a bore diameter (d) of 
1.000 inches in a meter tube with an inside diameter (D) of 2.000 
inches the area ratio is 0.25 and is calculated as follows:

[[Page 56057]]

[GRAPHIC] [TIFF OMITTED] TP10SE20.032

    As-found means the reading of a mechanical or electronic transducer 
when compared to a certified test device, prior to making any 
adjustments to the transducer.
    As-left means the reading of a mechanical or electronic transducer 
when compared to a certified test device, after making adjustments to 
the transducer, but prior to returning the transducer to service.
    Atmospheric pressure means the pressure exerted by the weight of 
the atmosphere at a specific location.
    Beta ratio means the reference inside diameter of the orifice bore 
divided by the reference inside diameter of the meter tube. This is 
also referred to as a diameter ratio.
    Bias means a systematic shift in the mean value of a set of 
measurements away from the true value of what is being measured.
    British thermal unit (Btu) means the amount of heat needed to raise 
the temperature of one pound of water by 1 [deg]F.
    Component-type electronic gas measurement system means an 
electronic gas measurement system comprising transducers and a flow 
computer, each identified by a separate make and model, from which 
performance specifications are obtained.
    Discharge coefficient means an empirically derived correction 
factor that is applied to the theoretical differential flow equation in 
order to calculate a flow rate that is within stated uncertainty 
limits.
    Effective date of a spot or composite gas sample means the first 
day on which the relative density and heating value determined from the 
sample are used in calculating the volume and quality on which royalty 
is based.
    Electronic gas measurement (EGM) means all of the hardware and 
software necessary to convert the static pressure, differential 
pressure, and flowing temperature developed as part of a primary 
device, to a quantity, rate, or quality measurement that is used to 
determine Federal royalty. For orifice meters, this includes the 
differential-pressure transducer, static-pressure transducer, flowing-
temperature transducer, on-line gas chromatograph (if used), flow 
computer, display, memory, and any internal or external processes used 
to edit and present the data or values measured.
    Element range means the difference between the minimum and maximum 
value that the element (differential-pressure bellows, static-pressure 
element, and temperature element) of a mechanical recorder is designed 
to measure.
    Gas storage agreement measurement point (GSAMP) means a point where 
the gas injected and withdrawn from a gas-storage agreement is measured 
and the measurement affects the calculation of the injection and 
withdrawal fees paid to the Federal Government, but does not affect the 
calculation of royalty due on native oil or gas produced from the gas 
storage area. The GSAMP will not be the FMP for the measurement of 
volumes for royalty determinations on native oil or gas produced from 
the gas storage area.
    GPA (followed by a number) means a standard prescribed by the Gas 
Processors Association, with the number referring to the specific 
standard.
    Heating value means the gross heat energy released by the complete 
combustion of one standard cubic foot of gas at 14.73 pounds per square 
inch absolute (psia) and 60 [deg]F.
    Heating value variability means the deviation of previous heating 
values over a given time period from the average heating value over 
that same time period, calculated at a 95 percent confidence level. 
Unless otherwise approved by the BLM, variability is determined with 
the following equation:

[[Page 56058]]

[GRAPHIC] [TIFF OMITTED] TP10SE20.033

    High-volume Facility Measurement Point (or high-volume FMP) means 
any FMP that measures more than 200 Mcf/day, but less than or equal to 
1,000 Mcf/day over the averaging period.
    Hydrocarbon dew point (HCDP) means the temperature at which 
hydrocarbon liquids begin to form within a gas mixture. For the purpose 
of this regulation, the hydrocarbon dew point is the flowing 
temperature of the gas measured at the FMP, unless otherwise approved 
by the AO.
    Integration means a process by which the lines on a circular chart 
(differential pressure, static pressure, and flowing temperature) used 
in conjunction with a mechanical chart recorder are re-traced or 
interpreted in order to determine the volume that is represented by the 
area under the lines. An integration statement documents the values 
determined from the integration.
    Live input variable means a datum that is automatically obtained in 
real time by an EGM system.
    Low-volume FMP means any FMP that measures more than 35 Mcf/day, 
but less than or equal to 200 Mcf/day, over the averaging period.
    Lower calibrated limit means the minimum engineering value for 
which a transducer was calibrated by certified equipment, either in the 
factory or in the field.
    Mean means the sum of all the values in a data set divided by the 
number of values in the data set.
    Mole percent means the number of molecules of a particular type 
that are present in a gas mixture divided by the total number of 
molecules in the gas mixture, expressed as a percentage.
    Nonanes-plus (C9+) analysis means a gas analysis that individually 
measures the gas components from methane (C1) through 
octanes (C8). Components with higher molecular weights than 
octanes (C8) are grouped together into the nonanes-plus 
(C9+) component.
    Normal flowing point means the average differential pressure, 
static pressure, and flowing temperature at an FMP taken over a time 
period of not less than 1 day and not more than 31 days.
    Primary device means the volume-measurement equipment installed in 
a pipeline that creates a measurable and predictable pressure drop in 
response to the flow rate of fluid through the pipeline. It includes 
the pressure-drop device, device holder, pressure taps, required 
lengths of pipe upstream and downstream of the pressure-drop device, 
and any flow conditioners that may be used to establish a fully 
developed symmetrical flow profile.
    Published inside diameter means the inside diameter of a pipe 
published in a standard piping table as a function of nominal pipe size 
and schedule. For example, the published inside diameter of a 2-inch 
pipe is 2.067 inches.
    Qualified test facility means a facility with currently certified 
measurement systems for mass, length, time, temperature, and pressure 
traceable to the NIST primary standards or applicable international 
standards approved by the BLM.
    Quantity transaction record (QTR) means a report generated by an 
EGM system that summarizes the daily and hourly volumes calculated by 
the flow computer and the average or totals of the dynamic data that is 
used in the calculation of volume.
    Redundancy verification means a process of verifying the accuracy 
of an EGM system by comparing the readings of two sets of transducers 
placed on the same primary device.
    Reference inside diameter means the measured inside diameter 
corrected to a reference temperature (68 [deg]F).
    Reynolds number means the ratio of the inertial forces to the 
viscous forces of the fluid flow, and is defined as:
[GRAPHIC] [TIFF OMITTED] TP10SE20.034

Where:

Re = the Reynolds number
V = velocity
[rho] = fluid density
D = inside meter tube diameter
[micro] = fluid viscosity

    Secondary device means the differential-pressure, static-pressure, 
and temperature transducers in an EGM system, or a mechanical recorder, 
including the differential pressure, static pressure, and temperature 
elements, and the clock, pens, pen linkages, and circular chart.
    Self-contained EGM system means an EGM system in which the 
transducers and flow computer are identified by a single make and model 
number from which the performance specifications for the transducers 
and flow computer are obtained. Any change to the make or model numbers 
of either a transducer or a flow computer within a self-contained EGM 
system changes the system to a component-type EGM system.
    Senior fitting means a type of orifice plate holder that allows the 
orifice plate to be removed, inspected, and replaced

[[Page 56059]]

without isolating and depressurizing the meter tube.
    Standard cubic foot (scf) means a cubic foot of gas at 14.73 psia 
and 60 [deg]F.
    Standard deviation means a measure of the variation in a 
distribution, and is equal to the square root of the arithmetic mean of 
the squares of the deviations of each value in the distribution from 
the arithmetic mean of the distribution.
    Tertiary device means, for EGM systems, the flow computer and 
associated memory, calculation, and display functions.
    Threshold of significance means the maximum difference between two 
data sets (a and b) that can be attributed to uncertainty effects. The 
threshold of significance is determined as follows:
[GRAPHIC] [TIFF OMITTED] TP10SE20.035

Where:

Ts = Threshold of significance, in percent
Ua = Uncertainty (95 percent confidence) of data set a, 
in percent
Ub = Uncertainty (95 percent confidence) of data set b, 
in percent

    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.
    Turndown means a reduction of the measurement range of a transducer 
in order to improve measurement accuracy at the lower end of its scale. 
It is typically expressed as the ratio of the upper range limit to the 
upper calibrated limit.
    Type test means a test on a representative number of a specific 
make, model, and range of a device to determine its performance over a 
range of operating conditions.
    Uncertainty means the range of error that could occur between a 
measured value and the true value being measured, calculated at a 95 
percent confidence level.
    Upper calibrated limit means the maximum engineering value for 
which a transducer was calibrated by certified equipment, either in the 
factory or in the field. This is also referred to as span.
    Upper range limit (URL) means the maximum value that a transducer 
is designed to measure.
    Verification means the process of determining the amount of error 
in a differential pressure, static pressure, or temperature transducer 
or element by comparing the readings of the transducer or element with 
the readings from a certified test device with known accuracy.
    Very-high-volume FMP means any FMP that measures more than 1,000 
Mcf/day over the averaging period.
    Very-low-volume FMP means any FMP that measures 35 Mcf/day or less 
over the averaging period.
    (b) As used in this subpart the following additional acronyms carry 
the meaning prescribed:
    GARVS means the BLM's Gas Analysis Reporting and Verification 
System.
    GC means gas chromatograph.
    GPA means the Gas Processors Association.
    Mcf means 1,000 standard cubic feet.
    psia means pounds per square inch--absolute.
    psig means pounds per square inch--gauge.


Sec.  3175.20  General requirements.

    (a) Measurement of all gas at an FMP must comply with the standards 
prescribed in Sec. Sec.  3175.10 through 3175.126; Sec.  3175.140, if 
applicable; and Sec.  3175.150, except as otherwise approved under 
Sec.  3170.40 of this part.
    (b) Measurement of all gas at a GSAMP must comply with the 
standards prescribed in Sec.  3175.130, except as otherwise approved 
under Sec.  3170.40 of this part.


Sec.  3175.30  Incorporation by reference.

    (a) Certain material identified is incorporated by reference into 
this part with the approval of the Director of the Federal Register 
under 5 U.S.C. 552(a) and 1 CFR part 51. To enforce any edition other 
than 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; and at all BLM offices with 
jurisdiction over oil and gas activities; and is available from the 
sources listed as follows. It is also available for inspection at the 
National Archives and Records Administration (NARA). For information on 
the availability of this material at NARA, email [email protected] 
or go to www.archives.gov/federal-register/cfr/ibr-locations.html.
    (b) American Gas Association (AGA), 400 North Capitol Street NW, 
Suite 450, Washington, DC 20001; telephone 202-824-7000.
    (1) AGA Report No. 3, Orifice Metering of Natural Gas and Other 
Related Hydrocarbon Fluids; Second Edition, September, 1985 (``AGA 
Report No. 3 (1985)''), IBR approved for Sec. Sec.  3175.50(b) and (c), 
3175.80(n), and 3175.94(a).
    (2) AGA Transmission Measurement Committee Report No. 8, 
Compressibility Factors of Natural Gas and Other Related Hydrocarbon 
Gases; Second Edition, November 1992 (``AGA Report No. 8 (1992)''), IBR 
approved for Sec.  3175.50(c).
    (3) AGA Transmission Measurement Committee Report No. 8, Part 1, 
Thermodynamic Properties of Natural Gas and Related Gases, Detail and 
Gross Equations of State; Third Edition, April 2017 (``AGA Report No. 8 
Part 1''), IBR approved for Sec. Sec.  3175.103(a), 3175.120(d).
    (4) AGA Transmission Measurement Committee Report No. 8, Part 2, 
Thermodynamic Properties of Natural Gas and Related Gases, GERG-2008 
Equation of State; First Edition, April 2017 (``AGA Report No. 8 Part 
2''), IBR approved for Sec. Sec.  3175.103(a), 3175.120(d).
    (c) American Petroleum Institute (API), 1220 L Street NW, 
Washington, DC 20005; telephone 202-682-8000. API also offers free, 
read-only access to all of the material at http://publications.api.org.
    (1) API Manual of Petroleum Measurement Standards (MPMS) Chapter 
14--Natural Gas Fluids Measurement, Section 1--Collecting and Handling 
of Natural Gas Samples for Custody Transfer; Seventh Edition, May 2016; 
Addendum, August 2017; Errata, August 2017 (``API 14.1''),'' IBR 
approved for Sec. Sec.  3175.80(p), 3175.112(c), 3175.113(c), 
3175.114(b).
    (2) 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. Sec.  3175.31(a), 3175.80(a).
    (3) API MPMS Chapter 14, Section 3, Orifice Metering of Natural Gas 
and Other Related Hydrocarbon Fluids-- Concentric, Square-edged Orifice 
Meters, Part 2: Specification and Installation Requirements; Fifth 
Edition, March 2016; Errata 1, March 2017; Errata 2, January 2019 
(``API 14.3.2''), IBR approved for Sec. Sec.  3175.50(b), 3175.80(b), 
(e) through (i), (l) through (o), Table 1 to Sec.  3175.80.
    (4) API MPMS Chapter 14, Section 3, Orifice Metering of Natural Gas 
and Other Related Hydrocarbon Fluids-- Concentric, Square-edged Orifice 
Meters, Part 3: Natural Gas

[[Page 56060]]

Applications; Fourth Edition, November 2013 (``API 14.3.3 (2013)''),'' 
IBR approved for Sec. Sec.  3175.50(c), 3175.94(a), and 3175.103(a).
    (5) API MPMS Chapter 14, Natural Gas Fluids Measurement, Section 3, 
Concentric, Square-Edged Orifice Meters, Part 3, Natural Gas 
Applications, Third Edition, August, 1992 (``API 14.3.3 (1992)''), IBR 
approved for Sec.  3175.50(c).
    (6) API MPMS, Chapter 14.5, Calculation of Gross Heating Value, 
Relative Density, Compressibility and Theoretical Hydrocarbon Liquid 
Content for Natural Gas Mixtures for Custody Transfer; Third Edition, 
January 2009; Reaffirmed, February 2014 (``API 14.5''), IBR approved 
for Sec. Sec.  3175.120(c), and 3175.125(a).
    (7) API MPMS Chapter 21.1, Flow Measurement Using Electronic 
Metering Systems--Electronic Gas Measurement; Second Edition, February 
2013 (``API 21.1''), IBR approved for Table 1 to Sec.  3175.100, 
Sec. Sec.  3175.101(e), 3175.102(a) and (c) through (e), 3175.103(c), 
and 3175.104(a) through (d).
    (d) Gas Processors Association (GPA), 6526 E 60th Street, Tulsa, OK 
74145; telephone 918-493-3872.
    (1) GPA Midstream Standard 2166-17, Obtaining Natural Gas Samples 
for Analysis by Gas Chromatography; Reaffirmed 2017 (``GPA 2166-17''), 
IBR approved for Sec. Sec.  3175.113(c), 3175.114(a), and 3175.117(a).
    (2) GPA Midstream Standard 2261-19, Analysis for Natural Gas and 
Similar Gaseous Mixtures by Gas Chromatography; Revised 2019 (``GPA 
2261-19''),'' IBR approved for Sec.  3175.118(a) and (c).
    (3) GPA Midstream Standard 2198-16, Selection, Preparation, 
Validation, Care and Storage of Natural Gas and Natural Gas Liquids 
Reference Standard Blends; Revised 2016 (``GPA 2198-16''), IBR approved 
for Sec.  3175.118(c).
    (e) Pipeline Research Council International (PRCI), 3141 Fairview 
Park Dr., Suite 525, Falls Church, VA 22042; telephone 703-205-1600.
    (1) PRCI Contract-NX-19, Manual for the Determination of 
Supercompressibility Factors for Natural Gas; December 1962 (``PRCI NX 
19''), IBR approved for Sec.  3175.50(c).
    (2) [Reserved]

    Note 1 to paragraphs (b) through (e): 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 Ave., Paramus, NJ 07652; telephone 201-986-1131; http://infostore.saiglobal.com/store/.

Sec.  3175.31  Specific performance requirements.

    (a) Flow rate measurement uncertainty levels. (1) For high-volume 
FMPs, the measuring equipment must achieve an overall flow rate 
measurement uncertainty within 3 percent.
    (2) For very-high-volume FMPs, the measuring equipment must achieve 
an overall flow rate measurement uncertainty within 2 
percent.
    (3) There is no uncertainty requirement for low- and very-low-
volume FMPs.
    (4) The determination of uncertainty is based on the values of 
flowing parameters (e.g., differential pressure, static pressure, and 
flowing temperature for differential meters or velocity, mass flow 
rate, or volumetric flow rate for linear meters) determined as follows, 
listed in order of priority:
    (i) The average flowing parameters listed on the most recent daily 
QTR, if available to the BLM at the time of the uncertainty 
determination; or
    (ii) The average flowing parameters from the previous day, as 
required under Sec.  3175.101(b)(4)(i) through (iii) (for differential 
meters).
    (5) The uncertainty must be calculated under API 14.3.1, Section 12 
(incorporated by reference, see Sec.  3175.30) or other methods 
approved by the AO.
    (b) Heating value uncertainty levels. (1) For high-volume FMPs, the 
measuring equipment must achieve an annual average heating value 
uncertainty within 3 percent.
    (2) For very-high-volume FMPs, the measuring equipment must achieve 
an annual average heating value uncertainty within 2 
percent.
    (3) There is no heating value uncertainty requirement for low- and 
very-low-volume FMPs.
    (4) Unless otherwise approved by the AO, the average annual heating 
value uncertainty must be determined as follows:
[GRAPHIC] [TIFF OMITTED] TP10SE20.036

    (c) Bias. For low-volume, high-volume, and very-high-volume FMPs, 
the measuring equipment used for either flow rate or heating value 
determination must achieve measurement without statistically 
significant bias.
    (d) Verifiability. An operator may not use measurement equipment 
for which the accuracy and validity of any input, factor, or equation 
used by the measuring equipment to determine quantity, rate, or heating 
value are not independently verifiable by the BLM. Verifiability 
includes the ability to independently recalculate the volume, rate, and 
heating value based on source records and field observations.


Sec.  3175.40  Measurement equipment requiring BLM approval.

    Except as allowed under Sec.  3175.50(a), all makes, models, sizes, 
and software versions of the devices listed in this section that are 
used at FMPs must be

[[Page 56061]]

approved by the BLM and posted in the PMT section at www.blm.gov. BLM 
approval will be based upon a showing that the equipment meets or 
exceeds the performance requirements of Sec.  3175.31. To obtain 
approval, the applicant must submit an application to the PMT. 
Recommended testing procedures will be listed at www.blm.gov.
    (a) Transducers, when used at high- and very-high volume FMPs;
    (b) Flow-computer software, when used at high- and very-high volume 
FMPs;
    (c) Isolating flow conditioners;
    (d) Differential pressure meters other than flange-tapped orifice 
plates;
    (e) Coriolis meters;
    (f) Ultrasonic meters;
    (g) Software used to capture and process the output from a GC;
    (h) Water vapor measurement equipment and methods; and
    (i) Measurement data systems.


Sec.  3175.41  Approved measurement equipment.

    The measurement equipment described in this section is approved for 
use at FMPs, provided it meets or exceeds the minimum standards 
prescribed in this subpart:
    (a) Flange-tapped orifice plates, associated fittings, and meter 
tubes that are constructed, installed, operated, and maintained in 
accordance with the standards in Sec.  3175.80;
    (b) Chart recorders, when used in conjunction with low- and very-
low volume FMPs, that are installed, operated, and maintained in 
accordance with the standards in Sec.  3175.90;
    (c) GCs that meet the standards in Sec. Sec.  3175.117 and 3175.118 
for determining heating value and relative density;
    (d) Transducers, when used at low- and very-low volume FMPs, must 
meet the requirements of Sec.  3175.102; and
    (e) Flow-computer software, when used at low- and very-low volume 
FMPs, must meet the requirements of Sec.  3175.101.


Sec.  3175.43  Data submission and notification requirements.

    (a) The operator must submit the following to the AO upon request:
    (1) Documentation of orifice-plate inspection for FMPs measuring 
gas from newly drilled or hydraulically fractured wells (see Sec.  
3175.80(e));
    (2) Documentation of routine orifice-plate inspection (see Sec.  
3175.80(e));
    (3) Documentation of basic meter-tube inspection (see Sec.  
3175.80(j)(6));
    (4) Documentation of detailed meter-tube inspection (see Sec.  
3175.80(l));
    (5) Documentation of mechanical recorder verification after repair 
or installation (see Sec.  3175.92(d));
    (6) Documentation of routine mechanical recorder verification (see 
Sec.  3175.92(d));
    (7) Documentation of EGM system verification after repair or 
installation (see Sec.  3175.102(e));
    (8) Documentation of routine EGM system verification (see Sec.  
3175.102(e));
    (9) EGM audit trail data including QTR, configuration log, event 
log, and alarm log (see Sec.  3175.104);
    (10) MDS audit trail data including QTR, configuration log, event 
log, and alarm log (see Sec.  3175.104(e));
    (11) GC verification report (see Sec.  3175.118(d)); and
    (12) Gas analysis report (see Sec.  3175.120).
    (b) Notification requirements to the AO: The operator must notify 
the AO at the specified time period listed in this paragraph before 
conducting the following procedures:
    (1) Twenty-four (24) hours prior to performing a detailed meter-
tube inspection (see Sec.  3175.80(k)(3));
    (2) Seventy-two (72) hours prior to performing a basic meter-tube 
inspection (see Sec.  3175.80(j)(4)); and
    (3) Seventy-two (72) hours prior to taking a gas sample (see Sec.  
3175.113(b)).


Sec.  3175.50   Grandfathering.

    (a) Exemption. Equipment listed in Sec.  3175.40(a) through (f) 
that was installed at a very-low, low-, or high-volume FMP prior to 
[EFFECTIVE DATE OF FINAL RULE] is exempt from the approval requirement 
in Sec.  3175.40. Any of the equipment listed in Sec.  3175.40(a) 
through (i) that was installed after [EFFECTIVE DATE OF FINAL RULE] 
must meet the approval requirement in Sec.  3175.40.
    (b) Meter tubes. (1) Meter tubes installed at low- and high-volume 
FMPs before January 17, 2017, are exempt from the meter tube 
requirements of API 14.3.2, Subsection 6.2 (incorporated by reference, 
see Sec.  3175.30) and Sec.  3175.80(h) and (m). For high-volume FMPs, 
the BLM will add an uncertainty of 0.25 percent to the 
discharge coefficient uncertainty when determining overall meter 
uncertainty under Sec.  3175.31(a), unless the operator provides data 
to the PMT that shows a lower uncertainty is justified, and the BLM 
approves a lower uncertainty. If a meter tube is replaced, it must meet 
the requirements of API 14.3.2, Subsection 6.2 (incorporated by 
reference, see Sec.  3175.30), and Sec.  3175.80(h) and (m). Meter 
tubes grandfathered under this section must still meet the following 
requirements:
    (i) Orifice plate eccentricity must comply with AGA Report No. 3 
(1985), Section 4.2.4 (incorporated by reference, see Sec.  3175.30);
    (ii) Meter tube construction and condition must comply with AGA 
Report No. 3 (1985), Section 4.3.4 (incorporated by reference, see 
Sec.  3175.30); and
    (iii) Meter tube lengths.
    (A) Meter tube lengths must comply with AGA Report No. 3 (1985), 
Section 4.4 (dimensions ``A'' and ``A'' from Figures 4-8) (incorporated 
by reference, see Sec.  3175.30).
    (B) If the upstream meter tube contains a 19-tube bundle flow 
straightener or isolating flow conditioner, the installation must 
comply with Sec.  3175.80(i);
    (2) For meter tubes installed at very-low-, low-, and high-volume 
FMPs before January 17, 2017, operators may use the measured inside 
diameter of the meter tube as required by AGA Report No. 3 (1985), 
Section 4.3.3 (incorporated by reference, see Sec.  3175.30), in lieu 
of the reference inside diameter of the meter tube for the requirements 
of Sec. Sec.  3175.91(d)(7), 3175.92(d)(2), 3175.93(d), 3175.101(c)(5), 
and 3175.102(e)(1)(iii), and flow-rate calculations. If a meter tube is 
replaced, operators must use the reference inside diameter of the meter 
tube to meet the requirements of Sec. Sec.  3175.91(d)(7), 
3175.92(d)(2), 3175.93(d), 3175.101(c)(5), and 3175.102(e)(1)(iii), and 
for flow-rate calculations.
    (c) EGM software. (1) EGM software installed at very-low-volume 
FMPs before January 17, 2017, is exempt from the requirements in Sec.  
3175.103(a)(1). However, flow-rate calculations must still be 
calculated in accordance with AGA Report No. 3 (1985), Section 6, or 
API 14.3.3 (1992) (both incorporated by reference, see Sec.  3175.30), 
and supercompressibility calculations must still be calculated in 
accordance with PRCI NX 19 or AGA Report No. 8 (1992) (both 
incorporated by reference, see Sec.  3175.30).
    (2) EGM software installed at low-volume FMPs before January 17, 
2017, is exempt from:
    (i) The requirements at Sec.  3175.103(a)(1)(i), if the 
differential-pressure to static-pressure ratio, based on the monthly 
average differential pressure and static pressure, is less than the 
value of ``x1'' shown in API 14.3.3 (2013), Annex G, Table G.1 
(incorporated by reference, see Sec.  3175.30). However, flow-rate 
calculations must still be calculated in accordance with API 14.3.3 
(1992) (incorporated by reference, see Sec.  3175.30); and

[[Page 56062]]

    (ii) The requirements at Sec.  3175.103(a)(1)(ii). However, 
compressibility must still be calculated in accordance with AGA Report 
No. 8 (1992) (incorporated by reference, see Sec.  3175.30).


Sec.  3175.60   Timeframes for compliance.

    Except as provided in paragraphs (a) through (d) of this section, 
the measuring procedures and equipment installed at any FMP or GSAMP, 
per Sec.  3175.130, must comply with all of the requirements of this 
subpart as of [EFFECTIVE DATE OF FINAL RULE].
    (a) Measuring equipment and procedures installed at very-low-volume 
FMPs before January 17, 2017, must comply with all of the requirements 
of this subpart as of [EFFECTIVE DATE OF FINAL RULE].
    (b) The gas analysis reporting requirements of Sec.  3175.120(e) 
and (f) of this subpart will begin 90 days after the BLM notifies 
operators that GARVS is available for use.
    (c) Equipment approvals required in Sec.  3175.40 will be required 
after [DATE TWO YEARS AFTER EFFECTIVE DATE OF FINAL RULE].
    (d) EGM systems must display the flow computer software version as 
required by Sec.  3175.101(b)(4) after [DATE TWO YEARS AFTER EFFECTIVE 
DATE OF FINAL RULE].


Sec.  3175.70   Measurement location.

    (a) Commingling and allocation. Gas produced from a lease, unit PA, 
or CA may not be commingled with production from other leases, unit 
PAs, CAs, or non-Federal properties before the point of royalty 
measurement, unless prior approval is obtained under 43 CFR subpart 
3173.
    (b) Off-lease measurement. Gas must be measured on the lease, unit, 
or CA unless approval for off-lease measurement is obtained under 43 
CFR subpart 3173.


Sec.  3175.80   Flange-tapped orifice plate (primary device).

    Except as provided in Sec.  3175.50, all flange-tapped orifice 
plates must comply with the following standards and requirements. 
(Note: Table 1 to this section lists the standards in this subpart and 
the API standards that the operator must follow to install and maintain 
flange-tapped orifice plates. A requirement applies when a column is 
marked with an ``x'' or a number.).
    (a) Fluid conditions must comply with API 14.3.1, Subsection 4.1 
(incorporated by reference, see Sec.  3175.30).
    (b) Orifice plate eccentricity must comply with API 14.3.2, 
Subsection 6.2.1 (incorporated by reference, see Sec.  3175.30), and 
the perpendicularity of the orifice plate holder must maintain the 
plane of the orifice plate at an angle of 90 degrees to the meter tube 
axis.
    (c) The Beta ratio must be no less than 0.10 and no greater than 
0.75.
    (d) The orifice bore diameter must be no less than 0.45 inches.
    (e) For FMPs measuring production from wells first coming into 
production, or from existing wells that have been re-fractured 
(including FMPs already measuring production from one or more other 
wells), the operator must inspect the orifice plate upon installation 
and then every 2 weeks thereafter. If the orifice plate does not comply 
with API 14.3.2, Section 4 (incorporated by reference, see Sec.  
3175.30), the operator must replace the orifice plate. When the orifice 
plate complies with API 14.3.2, Section 4, the operator thereafter must 
inspect the orifice plate as prescribed in paragraph (f) of this 
section.
    (f)(1) The operator must pull and inspect the orifice plate at the 
frequency (in months) identified in Table 1 to Sec.  3175.80 of this 
section.
    (2) The time between any two orifice-plate inspections must not 
exceed the time frames shown in appendix B of this subpart.
    (3) The operator must replace orifice plates that do not comply 
with API 14.3.2, Section 4 (incorporated by reference, see Sec.  
3175.30), with an orifice plate that does comply with these standards.
    (g) The operator must retain documentation for every plate 
inspection and must include that documentation as part of the 
verification report (see Sec.  3175.92(d) for mechanical recorders, or 
Sec.  3175.102(e) for EGM systems). The operator must provide that 
documentation to the BLM upon request. The documentation must include:
    (1) The information required in Sec.  3170.50(g) of this part;
    (2) Plate orientation (bevel upstream or downstream);
    (3) Measured orifice bore diameter;
    (4) Plate condition (documenting compliance with API 14.3.2, 
Section 4 (incorporated by reference, see Sec.  3175.30));
    (5) The presence of oil, grease, paraffin, scale, or other 
contaminants on the plate;
    (6) Time and date of inspection; and
    (7) Whether or not the plate was replaced.
    (h) Meter tubes must meet the requirements of API 14.3.2, 
Subsections 5.1 through 5.4 (incorporated by reference, see Sec.  
3175.30).
    (i) If flow conditioners are used, they must be either isolating-
flow conditioners approved by the BLM and installed under BLM 
requirements (see Sec.  3175.41) or 19-tube-bundle flow straighteners 
constructed in compliance with API 14.3.2, Subsections 5.5.2 through 
5.5.4, and located in compliance with API 14.3.2, Subsection 6.3 
(incorporated by reference, see Sec.  3175.30).
    (j) After initial installation of a meter tube at an FMP on or 
after [EFFECTIVE DATE OF FINAL RULE], the operator must perform an 
initial basic meter-tube inspection (see paragraph (k)(2) through (7) 
of this section) within the following timeframes:
    (1) For a very-high-volume FMP, within 1 year of the installation 
date; and
    (2) For a high-volume FMP, within 2 years of the installation date.
    (k) Routine basic meter-tube inspection. (1) Conduct a basic 
inspection of meter tubes within the timeframe (in years) specified in 
Table 1 to this section;
    (2) Conduct a basic meter-tube inspection that is able to identify 
obstructions, pitting, and buildup of foreign substances (e.g., grease 
and scale);
    (3) If the basic meter-tube inspection identifies obstructions, 
pitting, or buildup of foreign substances, the operator must take one 
of the following actions, as applicable, within 30 days:
    (i) For low, high, and very-high volume FMPs, if the basic meter-
tube inspection only indicates the presence of an obstruction (such as 
debris in front of the flow conditioner), the operator must remove the 
obstruction;
    (ii) For low-volume FMPs, if the basic inspection indicates the 
buildup of foreign substances, the operator must clean the meter tube 
of the buildup (no action is required if the basic meter-tube 
inspection only identifies pitting);
    (iii) For high and very-high volume FMPs, if the basic inspection 
indicates pitting or the buildup of foreign substances, the operator 
must repair or clean the tube and then perform a detailed meter-tube 
inspection under paragraph (l) of this section; or
    (iv) Submit a request to the AO for an extension of the 30-day 
timeframe, justifying the need for the extension.
    (4) Notify the AO at least 72 hours in advance of performing a 
basic inspection or submit a monthly or quarterly schedule of basic 
inspections to the AO in advance;
    (5) Conduct additional inspections, as the AO may require, if 
warranted by conditions such as corrosive or erosive-flow (e.g., high 
hydrogen sulfide (H2S) or carbon dioxide (CO2) 
content) or

[[Page 56063]]

signs of physical damage to the meter tube;
    (6) Maintain documentation of the findings from the basic meter-
tube inspection including:
    (i) The information required in Sec.  3170.50(g) of this part;
    (ii) The time and date of inspection;
    (iii) The type of equipment used to make the inspection; and
    (iv) A description of findings, including location and severity of 
pitting, obstructions, and buildup of foreign substances; and
    (7) Complete the first inspection after [EFFECTIVE DATE OF FINAL 
RULE] within the timeframes (in years) given in Table 1 to this 
section. The timeframes start:
    (i) For meter tubes at high- or very-high-volume FMPs installed on 
or after [EFFECTIVE DATE OF FINAL RULE], when the initial basic meter-
tube inspection was performed;
    (ii) For meter tubes at low-volume FMPs installed on or after 
[EFFECTIVE DATE OF FINAL RULE], when flow first goes through the meter;
    (iii) For meter tubes at FMPs installed before [EFFECTIVE DATE OF 
FINAL RULE], when the previous basic or detailed meter-tube inspection 
was performed, or [EFFECTIVE DATE OF FINAL RULE], whichever is earlier.
    (l)(1) If a detailed inspection is required under paragraph 
(k)(3)(iii) of this section, the operator must physically measure and 
inspect the meter tube to determine if the meter tube complies with API 
14.3.2, Subsections 5.1 through 5.4 and Subsection 6.2 (incorporated by 
reference, see Sec.  3175.30), or the requirements under Sec.  
3175.50(b), if the meter tube is grandfathered under Sec.  3175.50(b). 
If the meter tube does not comply with the applicable standards, the 
operator must repair the meter tube to bring the meter tube into 
compliance with these standards or replace the meter tube with one that 
meets these standards.
    (2) For all high- and very-high volume FMPs installed after 
[EFFECTIVE DATE OF FINAL RULE], the operator must perform a detailed 
inspection under paragraph (l) of this section before operation of the 
meter. The operator may submit documentation showing that the meter 
tube complies with API 14.3.2, Subsections 5.1 through 5.4 and 
Subsection 6.2 (incorporated by reference, see Sec.  3175.30) in lieu 
of performing a detailed inspection.
    (3) The operator must notify the AO at least 24 hours before 
performing a detailed inspection.
    (m) The operator must retain documentation of all detailed meter-
tube inspections, demonstrating that the meter tube complies with API 
14.3.2, Subsections 5.1 through 5.4 (incorporated by reference, see 
Sec.  3175.30), and showing all required measurements. The operator 
must provide such documentation to the BLM upon request for every 
meter-tube inspection. Documentation must also include the information 
required in Sec.  3170.50(g) of this part.
    (n)(1) Meter-tube lengths and the location of 19-tube-bundle flow 
straighteners, if applicable, must comply with API 14.3.2, Subsection 
6.3 (incorporated by reference, see Sec.  3175.30).
    (2) For Beta ratios of less than 0.5, the location of 19-tube 
bundle flow straighteners installed in compliance with AGA Report No. 3 
(1985), Section 4.4 (incorporated by reference, see Sec.  3175.30), 
also complies with the location of 19-tube bundle flow straighteners as 
required in paragraph (1) of this section.
    (3) If the diameter ratio ([beta]) falls between the values in 
Tables 7, 8a, or 8b of API 14.3.2, Subsection 6.3 (incorporated by 
reference, see Sec.  3175.30), the length identified for the larger 
diameter ratio in the appropriate Table is the minimum requirement for 
meter-tube length and determines the location of the end of the 19-
tube-bundle flow straightener closest to the orifice plate. For 
example, if the calculated diameter ratio is 0.41, use the table entry 
for a 0.50 diameter ratio.
    (o)(1) Thermometer wells used for determining the flowing 
temperature of the gas as well as thermometer wells used for 
verification (test well) must be located in compliance with API 14.3.2, 
Subsection 6.5 (incorporated by reference, see Sec.  3175.30).
    (2) Thermometer wells must be located in such a way that they can 
sense the same flowing gas temperature that exists at the orifice 
plate. The operator may accomplish this by physically locating the 
thermometer well(s) in the same ambient temperature conditions as the 
primary device (such as in a heated meter house) or by installing 
insulation and/or heat tracing along the entire meter run. If the 
operator chooses to use insulation to comply with this requirement, the 
AO may prescribe the quality of the insulation based on site-specific 
factors such as ambient temperature, flowing temperature of the gas, 
composition of the gas, and location of the thermometer well in 
relation to the orifice plate (i.e., inside or outside of a meter 
house).
    (3) Where multiple thermometer wells have been installed in a meter 
tube, the flowing temperature must be measured from the thermometer 
well closest to the primary device.
    (4) Thermometer wells used to measure or verify flowing temperature 
must contain a thermally conductive liquid.
    (p) The sample probe must be the first obstruction, and at least 
five published inside pipe diameters, downstream of the primary device.
    (1) For horizontal meter tubes, the sample probe must also be 
located in the meter tube vertically at the top of a straight run of 
pipe in accordance with API 14.1, Subsection 6.4.2 (incorporated by 
reference, see Sec.  3175.30).
    (2) For vertical meter tubes, the sample probe must be mounted 
perpendicular to the vertical meter tube.

                      Table 1 to Sec.   3175.80: Standards for Flange-Tapped Orifice Plates
----------------------------------------------------------------------------------------------------------------
                                              Reference (API standards
                  Subject                    incorporated by reference,      VL         L         H        VH
                                                 see Sec.   3175.30)
----------------------------------------------------------------------------------------------------------------
Fluid conditions..........................  Sec.   3175.80(a)...........      n/a         x         x         x
Orifice plate construction and condition..  API 14.3.2, Section 4.......        x         x         x         x
Orifice plate eccentricity and              Sec.   3175.80(b)...........      n/a         x         x         x
 perpendicularity **.
Beta ratio range..........................  Sec.   3175.80(c)...........      n/a         x         x         x
Minimum orifice size......................  Sec.   3175.80(d)...........      n/a       n/a         x         x
New FMP orifice-plate inspection *........  Sec.   3175.80(e)...........      n/a         x         x         x
Routine orifice-plate inspection            Sec.   3175.80(f)...........       12         6         3         1
 frequency, in months *.
Documentation of orifice-plate inspection.  Sec.   3175.80(g)...........        x         x         x         x
Meter-tube construction and condition **..  Sec.   3175.80(h)...........      n/a         x         x         x
Flow conditioners including 19-tube         Sec.   3175.80(i)...........      n/a         x         x         x
 bundles.
Initial basic meter-tube inspection.......  Sec.   3175.80(j)...........      n/a       n/a         x         x

[[Page 56064]]

 
Routine basic meter-tube inspection         Sec.   3175.80(k)...........      n/a        10         5         5
 frequency, in years *.
Detailed meter-tube inspection *..........  Sec.   3175.80(l)...........      n/a       n/a         x         x
Documentation of detailed meter-tube        Sec.   3175.80(m)...........      n/a       n/a         x         x
 inspection.
Meter-tube length **......................  Sec.   3175.80(n)...........      n/a         x         x         x
Thermometer wells.........................  Sec.   3175.80(o)...........      n/a         x         x         x
Sample probe location.....................  Sec.   3175.80(p)...........        x         x         x         x
----------------------------------------------------------------------------------------------------------------
VL=Very-low-volume FMP; L=Low-volume FMP; H=High-volume FMP; VH=Very-high-volume FMP.
* = Immediate assessment for non-compliance under Sec.   3175.150.
** = Applies to all very-high-volume FMPs and meter tubes installed at low- and high-volume FMPs after
  [EFFECTIVE DATE OF FINAL RULE]. See Sec.   3175.50 for requirements pertaining to meter tubes installed at low-
   and high-volume FMPs before [EFFECTIVE DATE OF FINAL RULE].

Sec.  3175.90   Mechanical recorder (secondary device).

    (a) The operator may use a mechanical recorder as a secondary 
device only on very-low-volume and low-volume FMPs.
    (b) Table 1 to this section lists the standards that the operator 
must follow to install, operate, and maintain mechanical recorders. A 
requirement applies when a column is marked with an ``x'' or a number.

      Table 1 to Sec.   3175.90: Standards for Mechanical Recorders
------------------------------------------------------------------------
             Subject                   Reference         VL         L
------------------------------------------------------------------------
Applications for use............  Sec.   3175.90(a).        x         x
Manifolds and gauge/impulse       Sec.   3175.91(a).      n/a         x
 lines.
Differential-pressure pen         Sec.   3175.91(b).      n/a         x
 position.
Flowing temperature recording...  Sec.   3175.91(c).      n/a         x
On-site data requirements.......  Sec.   3175.91(d).        x         x
Operating within the element      Sec.   3175.91(e).        x         x
 ranges.
Verification after installation   Sec.   3175.92(a).        x         x
 or following repair *.
Routine verification and          Sec.   3175.92(b).        6         3
 verification frequency, in
 months *.
Routine verification procedures.  Sec.   3175.92(c).        x         x
Documentation of verification...  Sec.   3175.92(d).        x         x
Notification of verification....  Sec.   3175.92(e).        x         x
Volume correction...............  Sec.   3175.92(f).      n/a         x
Test equipment recertification..  Sec.   3175.92(g).        x         x
Integration statement             Sec.   3175.93....        x         x
 requirements.
Volume determination............  Sec.   3175.94(a).        x         x
Atmospheric pressure............  Sec.   3175.94(b).        x         x
------------------------------------------------------------------------
VL=Very-low-volume FMP; L=Low-volume FMP.
* = Immediate assessment for non-compliance under Sec.   3175.150.

Sec.  3175.91   Installation and operation of mechanical recorders.

    (a) The connection between the pressure taps and the mechanical 
recorder must meet the following requirements:
    (1) Gauge lines must:
    (i) Have a nominal diameter of not less than \3/8\-inch;
    (ii) Be sloped upwards from the pressure taps at a minimum pitch of 
1 inch per foot of length with no visible sag;
    (iii) Have the same internal diameter along their entire length; 
and
    (iv) Be no longer than 6 feet.
    (2) Valves, including the valves in manifolds, must have a full-
opening internal diameter of not less than \3/8\-inch;
    (3) There must not be any tees except for the static-pressure line; 
and
    (4) There must be no connections to any other devices or more than 
one differential-pressure bellows and static-pressure element.
    (b) The differential-pressure pen must record at a minimum reading 
of 10 percent of the differential-pressure-bellows range for the 
majority of the flowing period. This requirement does not apply to 
inverted charts.
    (c) The flowing temperature of the gas must be continuously 
recorded and used in the volume calculations under Sec.  3175.94(a)(1).
    (d) The following information must be maintained at the FMP in a 
legible condition, in compliance with Sec.  3170.50(g) of this part, 
and accessible to the AO at all times:
    (1) Differential-pressure-bellows range;
    (2) Static-pressure-element range;
    (3) Temperature-element range;
    (4) Relative density (specific gravity) of the gas;
    (5) Static-pressure units of measure (psia or psig);
    (6) Elevation of or atmospheric pressure at the FMP;
    (7) Reference inside diameter of the meter tube;
    (8) Primary device type;
    (9) Orifice-bore or other primary-device dimensions necessary for 
device verification, Beta- or area-ratio determination, and gas-volume 
calculation;
    (10) Make, model, and location of approved isolating flow 
conditioners, if used;
    (11) Location of the downstream end of 19-tube-bundle flow 
straighteners, if used;
    (12) Date of last primary-device inspection; and
    (13) Date of last meter verification.
    (e) The differential pressure, static pressure, and flowing 
temperature elements must be operated between the

[[Page 56065]]

lower- and upper-calibrated limits of the respective elements.


Sec.  3175.92   Verification and calibration of mechanical recorders.

    (a) Verification after installation or following repair. (1) Before 
performing any verification of a mechanical recorder required in this 
part, the operator must perform a leak test. The verification must not 
proceed if leaks are present. The leak test must be conducted in a 
manner that will detect leaks in the following:
    (i) All connections and fittings of the secondary device, including 
meter manifolds and verification equipment;
    (ii) The isolation valves; and
    (iii) The equalizer valves.
    (2) The operator must adjust the time lag between the differential- 
and static-pressure pens, if necessary, to be 1/96 of the chart 
rotation period, measured at the chart hub. For example, the time lag 
is 15 minutes on a 24-hour test chart and 2 hours on an 8-day test 
chart.
    (3) The meter's differential pen arc must be able to duplicate the 
test chart's time arc over the full range of the test chart, and must 
be adjusted, if necessary.
    (4) The as-left values must be verified in the following sequence 
against a certified pressure device for the differential-pressure and 
static-pressure elements (if the static-pressure pen has been offset 
for atmospheric pressure, the static-pressure element range is in 
psia):
    (i) Zero (vented to atmosphere);
    (ii) 50 percent of element range;
    (iii) 100 percent of element range;
    (iv) 80 percent of element range;
    (v) 20 percent of element range; and
    (vi) Zero (vented to atmosphere).
    (5) The following as-left temperatures must be verified by placing 
the temperature probe in a water bath with a certified test 
thermometer:
    (i) Approximately 10 [deg]F below the lowest expected flowing 
temperature;
    (ii) Approximately 10 [deg]F above the highest expected flowing 
temperature; and
    (iii) At the expected average flowing temperature.
    (6) If any of the readings required in paragraph (a)(4) or (5) of 
this section vary from the test device reading by more than the 
tolerances shown in Table 1 to paragraph (a)(6), the operator must 
replace and verify the element for which readings were outside the 
applicable tolerances before returning the meter to service.

       Table 1 to Paragraph (a)(6): Mechanical Recorder Tolerances
------------------------------------------------------------------------
                  Element                          Allowable error
------------------------------------------------------------------------
Differential Pressure.....................  0.5%
Static Pressure...........................  1.0%
Temperature...............................  2 [deg]F
------------------------------------------------------------------------

    (7) If the static-pressure pen is offset for atmospheric pressure:
    (i) The atmospheric pressure must be calculated under Appendix A to 
this subpart; and
    (ii) The pen must be offset prior to obtaining the as-left 
verification values required in paragraph (a)(4) of this section.
    (b) Routine verification frequency. (1) The differential pressure 
bellows, static pressure element, and temperature element must be 
verified in accordance with the requirements of paragraph (c) of this 
section at the frequency specified (in months) in Table 1 to Sec.  
3175.90; and
    (2) The time between any two verifications must not exceed the time 
frames shown in Appendix B of this subpart; or
    (3) If an FMP is in non-flowing status at the time that a routine 
verification is due, a routine verification must be conducted within 15 
days after flow is re-initiated. For the purpose of this section, non-
flowing status means no flow goes through the FMP for at least 3 months 
due to seasonal outages or long-term maintenance or repair issues. Non-
flowing status does not apply to meters at FMPs that flow 
intermittently on a daily or weekly basis.
    (c) Routine verification procedures. (1) Before performing any 
verification required in this part, the operator must perform a leak 
test in the manner required under paragraph (a)(1) of this section.
    (2) No adjustments to the pens or linkages may be made until an as-
found verification is obtained. If the static pen has been offset for 
atmospheric pressure, the static pen must not be reset to zero until 
the as-found verification is obtained.
    (3) The operator must obtain the as-found values of differential 
and static pressure against a certified pressure device at the readings 
listed in paragraph (a)(4) of this section, with the following 
additional requirements:
    (i) If there is sufficient data on site to determine the point at 
which the differential and static pens normally operate, the operator 
must also obtain an as-found value at those points;
    (ii) If there is not sufficient data on site to determine the 
points at which the differential and static pens normally operate, the 
operator must also obtain as-found values at 5 percent of the element 
range and 10 percent of the element range; and
    (iii) If the static-pressure pen has been offset for atmospheric 
pressure, the static-pressure element range is in units of psia.
    (4) The as-found value for temperature must be taken using a 
certified test thermometer placed in a test thermometer well if there 
is flow through the meter and the meter tube is equipped with a test 
thermometer well. If there is no flow through the meter or if the meter 
is not equipped with a test thermometer well, the temperature probe 
must be verified by placing it along with a test thermometer in an 
insulated water bath.
    (5) The element undergoing verification must be calibrated 
according to manufacturer specifications if any of the as-found values 
determined under paragraph (c)(3) or (4) of this section are not within 
the tolerances shown in Table 1 to paragraph (a)(6) of this section, 
when compared to the values applied by the test equipment.
    (6) The operator must adjust the time lag between the differential- 
and static-pressure pens, if necessary, to be 1/96 of the chart 
rotation period, measured at the chart hub. For example, the time lag 
is 15 minutes on a 24-hour test chart and 2 hours on an 8-day test 
chart.
    (7) The meter's differential pen arc must be able to duplicate the 
test chart's time arc over the full range of the test chart, and must 
be adjusted, if necessary.
    (8) If any adjustment to the meter was made, the operator must 
perform an as-left verification on each element adjusted using the 
procedures in paragraphs (c)(3) and (4) of this section.
    (9) If, after an as-left verification, any of the readings required 
in paragraph (c)(3) or (4) of this section vary by more than the 
tolerances shown in Table 1 to paragraph (a)(6) of this section when 
compared with the test-device reading, any element which has readings 
that are outside of the applicable tolerances must be replaced and 
verified under this section before the operator returns the meter to 
service.
    (10) If the static-pressure pen is offset for atmospheric pressure:
    (i) The atmospheric pressure must be calculated under appendix A to 
this subpart; and
    (ii) The pen must be offset prior to obtaining the as-left 
verification values required in paragraph (c)(3) of this section.
    (d) Documentation of verification. The operator must retain 
documentation of each verification, as required under

[[Page 56066]]

Sec.  3170.50(g) of this part, and submit it to the BLM upon request. 
This documentation must include:
    (1) The time and date of the verification and the prior 
verification date;
    (2) Primary-device data (reference inside diameter of the meter 
tube and differential-device size and Beta or area ratio) if the 
orifice plate is pulled and inspected;
    (3) The type and location of taps (flange or pipe, upstream or 
downstream static tap);
    (4) Atmospheric pressure used to offset the static-pressure pen, if 
applicable;
    (5) Mechanical recorder data (make, model, and differential 
pressure, static pressure, and temperature element ranges);
    (6) The normal operating points for differential pressure, static 
pressure, and flowing temperature;
    (7) Verification points (as-found and applied) for each element;
    (8) Verification points (as-left and applied) for each element, if 
a calibration was performed;
    (9) Names, contact information, and affiliations of the person 
performing the verification and any witness, if applicable; and
    (10) Remarks, if any.
    (e) Notification of verification. (1) For verifications performed 
after installation or following repair, the operator must notify the AO 
at least 1 business day before conducting the verifications;
    (2) For routine verifications, the operator must notify the AO at 
least 72 hours before conducting the verification or submit a monthly 
or quarterly verification schedule to the AO in advance that identifies 
the FMPs that will be verified during that month or quarter.
    (f) Volume correction. If, during the verification, the combined 
errors in as-found differential pressure, static pressure, and flowing 
temperature taken at the normal operating points tested result in a 
flow-rate error greater than 2 percent and 2 Mcf/day, the volumes 
reported on the OGOR and on royalty reports submitted to ONRR must be 
corrected beginning with the date that the inaccuracy occurred. If that 
date is unknown, the volumes must be corrected beginning with the 
production month that includes the date that is halfway between the 
date of the last verification and the date of the current verification. 
For example: Meter verification determined that the meter was reading 4 
Mcf/day high at the normal operating points. The average flow rate 
measured by the meter is 90 Mcf/day, yielding an error of 4.4 percent. 
There is no indication of when the inaccuracy occurred. The date of the 
current verification was Dec 15, 2015. The previous verification was 
conducted on June 15, 2015. The royalty volumes reported on OGOR B that 
were based on this meter must be corrected for the 4 Mcf/day error back 
to September 15, 2015.
    (g) Test equipment recertification. Test equipment used to verify 
or calibrate elements at an FMP must be certified at least every 2 
years. Documentation of the recertification must be on-site during all 
verifications and must show:
    (1) Test equipment serial number, make, and model;
    (2) The date on which the recertification took place;
    (3) The test equipment measurement range; and
    (4) The uncertainty determined or verified as part of the 
recertification.


Sec.  3175.93   Integration statements.

    An unedited integration statement must be retained and made 
available to the BLM upon request. The integration statement must 
contain the following information:
    (a) The information required in Sec.  3170.50(g) of this part;
    (b) The name of the company performing the integration;
    (c) The month and year for which the integration statement applies;
    (d) Reference inside diameter of the meter tube (inches);
    (e) The following primary device information, as applicable:
    (1) Orifice bore diameter (inches); or
    (2) Beta or area ratio, discharge coefficient, and other 
information necessary to calculate the flow rate;
    (f) Relative density (specific gravity);
    (g) CO2 content (mole percent);
    (h) Dinitrogen (N2) content (mole percent);
    (i) Heating value calculated under Sec.  3175.125 (Btu/standard 
cubic feet);
    (j) Atmospheric pressure or elevation at the FMP;
    (k) Pressure base;
    (l) Temperature base;
    (m) Static-pressure tap location (upstream or downstream);
    (n) Chart rotation (hours or days);
    (o) Differential-pressure bellows range (inches of water);
    (p) Static-pressure element range (psi); and
    (q) For each chart or day integrated:
    (1) The time and date on and time and date off;
    (2) Average differential pressure (inches of water);
    (3) Average static pressure;
    (4) Static-pressure units of measure (psia or psig);
    (5) Average temperature ([deg]F);
    (6) Integrator counts or extension;
    (7) Hours of flow; and
    (8) Volume (Mcf).


Sec.  3175.94  Volume determination.

    (a) The volume for each chart integrated must be determined as 
follows:

V = IMV x IV

where:

V = reported volume, Mcf
IMV = integral multiplier value, as calculated under this section
IV = the integral value determined by the integration process (also 
known as the ``extension,'' ``integrated extension,'' and 
``integrator count'')

    (1) If the primary device is a flange-tapped orifice plate, a 
single IMV must be calculated for each chart or chart interval using 
the following equation:
[GRAPHIC] [TIFF OMITTED] TP10SE20.037

where:

Cd = discharge coefficient or flow coefficient, 
calculated under API 14.3.3 (2013) or AGA Report No. 3 (1985), 
Section 5 (both incorporated by reference, see Sec.  3175.30)
[beta] = Beta ratio.
Y = gas expansion factor, calculated under API 14.3.3 (2013), 
Subsection 5.6 or AGA Report No. 3 (1985), Section 5
d = orifice diameter, in inches
Zb = supercompressibility at base pressure and 
temperature
Gr = relative density (specific gravity)
Zf = supercompressibility at flowing pressure and 
temperature
Tf = average flowing temperature, in degrees Rankine

    (2) For other types of primary devices, the IMV must be calculated 
using the equations and procedures recommended by the PMT and approved 
by the BLM, specific to the make, model, size, and area ratio of the 
primary device being used.
    (3) Variables that are functions of differential pressure, static 
pressure, or flowing temperature (e.g., Cd, Y, 
Zf) must use the average values of differential pressure, 
static pressure, and flowing temperature as determined from the 
integration statement and reported on the integration statement for the 
chart or chart interval integrated. The flowing temperature must be the 
average flowing temperature reported on the integration statement for 
the chart or chart interval being integrated.
    (b) Atmospheric pressure used to convert static pressure in psig to 
static pressure in psia must be determined under appendix A to this 
subpart.

[[Page 56067]]

Sec.  3175.100   Electronic gas measurement (secondary and tertiary 
device).

    Except as provided in Sec.  3175.50, the standards and requirements 
in this section apply to all EGM systems used at FMPs. (Note: Table 1 
to this section lists the standards in this subpart and the API 
standards that the operator must follow to install and maintain EGM 
systems. A requirement applies when a column is marked with an ``x'' or 
a number.)

                  Table 1 to Sec.   3175.100--Standards for Electronic Gas Measurement Systems
----------------------------------------------------------------------------------------------------------------
                                              Reference (API standards
                  Subject                    incorporated by reference,      VL         L         H        VH
                                                 see Sec.   3175.30)
----------------------------------------------------------------------------------------------------------------
EGM system commissioning..................  API 21.1, Subsection 7.3....      n/a         x         x         x
Access and data security..................  API 21.1, Section 9.........        x         x         x         x
No-flow cutoff............................  API 21.1, Subsection 4.4.5..        x         x         x         x
Manifolds and gauge lines.................  Sec.   3175.101(a)..........      n/a         x         x         x
Display requirements......................  Sec.   3175.101(b)..........        x         x         x         x
On-site information.......................  Sec.   3175.101(c)..........        x         x         x         x
Operating within the calibrated limits....  Sec.   3175.101(d)..........      n/a         x         x         x
Flowing-temperature measurement...........  Sec.   3175.101(e)..........      n/a         x         x         x
Verification after installation or          Sec.   3175.102(a)..........        x         x         x         x
 following repair *.
Routine verification frequency, in months   Sec.   3175.102(b)..........       12         6         6         6
 *.
Routine verification procedures...........  Sec.   3175.102(c)..........        x         x         x         x
Redundancy verification...................  Sec.   3175.102(d)..........        x         x         x         x
Documentation of verification.............  Sec.   3175.102(e)..........        x         x         x         x
Notification of verification..............  Sec.   3175.102(f)..........        x         x         x         x
Volume correction.........................  Sec.   3175.102(g)..........      n/a         x         x         x
Test-equipment requirements...............  Sec.   3175.102(h)..........        x         x         x         x
Flow-rate calculation **..................  Sec.   3175.103(a)..........        x         x         x         x
Atmospheric pressure......................  Sec.   3175.103(b)..........        x         x         x         x
Volume calculation........................  Sec.   3175.103(c)..........        x         x         x         x
QTR requirements..........................  Sec.   3175.104(a)..........        x         x         x         x
Configuration log requirements............  Sec.   3175.104(b)..........        x         x         x         x
Event log.................................  Sec.   3175.104(c)..........        x         x         x         x
Alarm log.................................  Sec.   3175.104(d)..........        x         x         x         x
Accounting systems........................  Sec.   3175.104(e)..........        x         x         x         x
----------------------------------------------------------------------------------------------------------------
VL=Very-low-volume FMP; L=Low-volume FMP; H=High-volume FMP; VH=Very-high-volume FMP.
* = Immediate assessment for non-compliance under Sec.   3175.150.
** = Applies to all high- and very-high-volume FMPs and FMPs installed at low- and very-low-volume FMPs after
  [EFFECTIVE DATE OF FINAL RULE]. See Sec.   3175.50 for requirements pertaining to FMPs installed at low- and
  very-low-volume FMPs before EFFECTIVE DATE OF FINAL RULE].

Sec.  3175.101   Installation and operation of electronic gas 
measurement systems.

    (a) The connection between the pressure taps and the secondary 
device must meet the following requirements:
    (1) If gauge lines are used, they must:
    (i) Have a nominal diameter of not less than \3/8\-inch;
    (ii) Be sloped upwards from the pressure taps at a minimum pitch of 
1 inch per foot of length with no visible sag;
    (iii) Have the same internal diameter along their entire length; 
and
    (iv) Be no longer than 6 feet.
    (2) Valves, including the valves in manifolds, must have a full-
opening internal diameter of not less than \3/8\-inch;
    (3) There must not be any tees, except for the static-pressure 
line; and
    (4) There must be no connections to any other devices or more than 
one differential pressure and static-pressure transducer. If the 
operator is employing redundancy verification, two differential 
pressure and two static-pressure transducers may be connected.
    (b) Each FMP must include a display, which must:
    (1) Be readable without the need for data-collection units, laptop 
computers, a password, or any special equipment;
    (2) Be on site and in a location that is accessible to the AO;
    (3) Include the units of measure for each required variable;
    (4) For high- and very-high volume FMPs, display the software 
version;
    (5) Display the previous-day's volume, as well as the following 
variables consecutively:
    (i) Current flowing static pressure with units (psia or psig);
    (ii) Current differential pressure (inches of water);
    (iii) Current flowing temperature ([deg]F); and
    (iv) Current flow rate (Mcf/day or scf/day); and
    (6) Either display or, at the request of the AO, provide an hourly 
or daily QTR (see Sec.  3175.104(a)) no more than 31 days old showing 
the following information:
    (i) Previous-period (for this section, previous period means at 
least 1 day prior, but no longer than 1 month prior) average 
differential pressure (inches of water);
    (ii) Previous-period average static pressure with units (psia or 
psig); and
    (iii) Previous-period average flowing temperature ([deg]F);
    (c) The following information must be maintained at the FMP in a 
legible condition, in compliance with Sec.  3170.50(g) of this part, 
and accessible to the AO at all times:
    (1) The unique meter identification number;
    (2) Relative density (specific gravity);
    (3) Elevation of or the atmospheric pressure at the FMP;
    (4) Primary device information, such as orifice bore diameter 
(inches) or Beta or area ratio and discharge coefficient, as 
applicable;
    (5) Reference inside diameter of the meter tube;
    (6) Make, model, and location of approved isolating flow 
conditioners, if used;
    (7) Location of the downstream end of 19-tube-bundle flow 
straighteners, if used;
    (8) For self-contained EGM systems, make and model number of the 
system;

[[Page 56068]]

    (9) For component-type EGM systems, make and model number of each 
transducer and the flow computer;
    (10) URL and upper calibrated limit for each transducer;
    (11) Location of the static-pressure tap (upstream or downstream);
    (12) Last orifice plate or other BLM-approved primary-device 
inspection date;
    (13) Last meter-tube inspection date; and
    (14) Last secondary device verification date.
    (d) The differential pressure, static pressure, and flowing 
temperature transducers must be operated between the lower and upper 
calibrated limits of the transducer. The BLM may approve the 
differential pressure to exceed the upper calibrated limit of the 
differential-pressure transducer for brief periods in plunger lift 
operations; however, the differential pressure may not exceed the URL.
    (e) The flowing temperature of the gas must be continuously 
measured and used in the flow-rate calculations under API 21.1, Section 
4 (incorporated by reference, see Sec.  3175.30).


Sec.  3175.102   Verification and calibration of electronic gas 
measurement systems.

    (a) Transducer verification and calibration after installation or 
repair. (1) Before performing any verification required in this 
section, the operator must perform a leak test in the manner prescribed 
in Sec.  3175.92(a)(1).
    (2) The operator must verify the points listed in API 21.1, 
Subsection 7.3.3 (incorporated by reference, see Sec.  3175.30), by 
comparing the values from the certified test device with the values 
used by the flow computer to calculate flow rate. If any of these as-
left readings vary from the test equipment reading by more than the 
tolerance determined by API 21.1, Subsection 8.2.2.2, Equation 24, then 
that transducer must be replaced and the new transducer must be tested 
under this paragraph.
    (3) For absolute static-pressure transducers, the value of 
atmospheric pressure used when the transducer is vented to atmosphere 
must be calculated under Appendix A to this subpart, measured by a 
NIST-certified barometer with a stated accuracy of 0.06 psi 
(4 millibars) or better, or obtained from an absolute-
pressure calibration device.
    (4) Before putting a meter into service, the differential-pressure 
transducer must be tested at zero with full working pressure applied to 
both sides of the transducer. If the absolute value of the transducer 
reading is greater than the reference accuracy of the transducer, 
expressed in inches of water column, the transducer must be re-zeroed.
    (b) Routine verification frequency. (1) If redundancy verification 
under paragraph (d) of this section is not used:
    (i) The differential pressure, static pressure, and temperature 
transducers must be verified under the requirements of paragraph (c) of 
this section at the frequency specified in Table 1 to Sec.  3175.100, 
in months; and
    (ii) The time between any two verifications must not exceed the 
time frames shown in appendix B of this subpart; or
    (iii) If an FMP is in non-flowing status at the time that a routine 
verification is due, a routine verification must be conducted within 15 
days after flow is re-initiated. For the purpose of this section, non-
flowing status means no flow goes through the FMP for at least 6 months 
due to seasonal outages or long-term maintenance or repair issues. Non-
flowing status does not apply to meters at FMPs that flow 
intermittently on a daily or weekly basis.
    (2) If redundancy verification under paragraph (d) of this section 
is used, the differential pressure, static pressure, and temperature 
transducers must be verified under the requirements of paragraph (d) of 
this section. In addition, the transducers must be verified under the 
requirements of paragraph (c) of this section at least annually.
    (c) Routine verification procedures. Verifications must be 
performed according to API 21.1, Subsection 8.2 (incorporated by 
reference, see Sec.  3175.30), with the following exceptions, 
additions, and clarifications:
    (1) Before performing any verification required under this section, 
the operator must perform a leak test consistent with Sec.  
3175.92(a)(1).
    (2) An as-found verification for differential pressure, static 
pressure and temperature must be conducted at the normal operating 
point of each transducer.
    (i) The normal operating point is the mean value taken over a 
previous time period not less than 1 day or greater than 1 month. 
Acceptable mean values include means weighted based on flow time and 
flow rate.
    (ii) For differential and static-pressure transducers, the pressure 
applied to the transducer for this verification must be within five 
percentage points of the normal operating point. For example, if the 
normal operating point for differential pressure is 17 percent of the 
upper calibrated limit, the normal point verification pressure must be 
between 12 percent and 22 percent of the upper calibrated limit.
    (iii) For the temperature transducer, the water bath or test 
thermometer well must be within 20 [deg]F of the normal operating point 
for temperature.
    (3) If a transducer is calibrated, the as-left verification must 
include the normal operating point of that transducer, as defined in 
paragraph (c)(2) of this section.
    (4) The as-found values for differential pressure obtained with the 
low side vented to atmospheric pressure must be corrected to working-
pressure values using API 21.1, Annex H, Equation H.1 (incorporated by 
reference, see Sec.  3175.30).
    (5) The verification tolerance for differential and static pressure 
is defined by API 21.1, Subsection 8.2.2.2, Equation 24 (incorporated 
by reference, see Sec.  3175.30). The verification tolerance for 
temperature is equivalent to the uncertainty of the temperature 
transmitter or 0.5 [deg]F, whichever is greater.
    (6) All required verification points must be within the 
verification tolerance before returning the meter to service.
    (7) Before putting a meter into service, the differential-pressure 
transducer must be tested at zero with full working pressure applied to 
both sides of the transducer. If the absolute value of the transducer 
reading is greater than the reference accuracy of the transducer, 
expressed in inches of water column, the transducer must be re-zeroed.
    (d) Redundancy verification procedures. Redundancy verifications 
must be performed as required under API 21.1, Subsection 8.2 
(incorporated by reference, see Sec.  3175.30), with the following 
exceptions, additions, and clarifications:
    (1) The operator must identify which set of transducers is used for 
reporting on the OGOR (the primary transducers) and which set of 
transducers is used as a check (the check set of transducers);
    (2) For every calendar month, the operator must compare the flow-
time linear averages of differential pressure, static pressure, and 
temperature readings from the primary transducers with those from the 
check transducers;
    (3) If for any transducer the difference between the averages 
exceeds the tolerance defined by the following equation:
[GRAPHIC] [TIFF OMITTED] TP10SE20.038

Where:

Ap is the reference accuracy of the primary transducer 
and

[[Page 56069]]

Ac is the reference accuracy of the check transducer.

    (4) The operator must verify both the primary and check transducer 
under paragraph (c) of this section within the first 5 days of the 
month following the month in which the redundancy verification was 
performed. For example, if the redundancy verification for March 
reveals that the difference in the flow-time linear averages of 
differential pressure exceeded the verification tolerance, both the 
primary and check differential-pressure transducers must be verified 
under paragraph (c) of this section by April 5th.
    (e) Documentation requirements. The operator must retain 
documentation of each verification for the period required under Sec.  
3170.50 of this part, including calibration data for transducers that 
were replaced, and submit it to the BLM upon request.
    (1) For routine verifications, this documentation must include:
    (i) The information required in Sec.  3170.50(g) of this part;
    (ii) The time and date of the verification and the last 
verification date;
    (iii) Primary device data (reference inside diameter of the meter 
tube and orifice plate or differential-device size, Beta or area 
ratio);
    (iv) The type and location of taps (flange or pipe, upstream or 
downstream static tap);
    (v) The flow computer make and model;
    (vi) The make and model number for each transducer, for component-
type EGM systems;
    (vii) Transducer data (make, model, differential, static, 
temperature URL, and upper calibrated limit);
    (viii) The normal operating points for differential pressure, 
static pressure, and flowing temperature;
    (ix) Atmospheric pressure;
    (x) Verification points (as-found and applied) for each transducer;
    (xi) Verification points (as-left and applied) for each transducer, 
if calibration was performed;
    (xii) The differential-device inspection date and condition (e.g., 
clean, sharp edge, or surface condition);
    (xiii) Verification equipment make, model, range, accuracy, and 
last certification date;
    (xiv) The name, contact information, and affiliation of the person 
performing the verification and any witness, if applicable; and
    (xv) Remarks, if any.
    (2) For redundancy verification checks, this documentation must 
include;
    (i) The information required in Sec.  3170.50(g) of this part;
    (ii) The month and year for which the redundancy check applies;
    (iii) The makes, models, upper range limits, and upper calibrated 
limits of the primary set of transducers;
    (iv) The makes, models, upper range limits, and upper calibrated 
limits of the check set of transducers;
    (v) The information required in API 21.1, Annex I (incorporated by 
reference, see Sec.  3175.30);
    (vii) The tolerance for differential pressure, static pressure, and 
temperature as calculated under paragraph (d)(2) of this section; and
    (viii) Whether or not each transducer required verification under 
paragraph (c) of this section.
    (f) Notification of verification. (1) For verifications performed 
after installation or following repair, the operator must notify the AO 
at least 1 business day before conducting the verifications;
    (2) For routine verifications, the operator must notify the AO at 
least 72 hours before conducting the verification or submit a monthly 
or quarterly verification schedule to the AO in advance that identifies 
the FMPs that will be verified during that month or quarter.
    (g) Amended reports. If, during the verification, the combined 
errors in as-found differential pressure, static pressure, and flowing 
temperature taken at the normal operating points tested result in a 
flow-rate error greater than 2 percent and 2 Mcf/day, the volumes 
reported on the OGOR and on royalty reports submitted to ONRR must be 
corrected beginning with the date that the inaccuracy occurred. If that 
date is unknown, the volumes must be corrected beginning with the 
production month that includes the date that is half-way between the 
date of the last verification and the date of the present verification. 
See the example in Sec.  3175.92(f).
    (h) Test equipment requirements. (1) Test equipment used to verify 
or calibrate transducers at an FMP must be certified at least every 2 
years. Documentation of the certification must be on site and made 
available to the AO during all verifications and must show:
    (i) The test equipment serial number, make, and model;
    (ii) The date on which the recertification took place;
    (iii) The range of the test equipment; and
    (iv) The uncertainty determined or verified as part of the 
recertification.
    (2) Test equipment used to verify or calibrate transducers at an 
FMP must meet the following accuracy standards:
    (i) The accuracy of the test equipment, stated in actual units of 
measure, must be no greater than 0.5 times the reference accuracy of 
the transducer being verified, also stated in actual units of measure; 
or
    (ii) The equipment must have a stated accuracy of at least 0.10 
percent of the upper calibrated limit of the transducer being verified.


Sec.  3175.103   Flow rate, volume, and average value calculation.

    (a) The flow rate must be calculated as follows:
    (1) For flange-tapped orifice plates, the flow rate must be 
calculated under:
    (i) API 14.3.3 (2013), Section 4 and Section 5 (incorporated by 
reference, see Sec.  3175.30); and
    (ii) AGA Report No. 8 Part 1 or Part 2 (both incorporated by 
reference, see Sec.  3175.30), for supercompressibility.
    (2) For primary devices other than flange-tapped orifice plates, 
for which there are no industry standards, the flow rate must be 
calculated under the equations and procedures recommended by the PMT 
and approved by the BLM, specific to the make, model, size, and area 
ratio of the primary device used.
    (b) Atmospheric pressure used to convert static pressure in psig to 
static pressure in psia must be determined using appendix A of this 
subpart.
    (c) Hourly and daily gas volumes, average values of the live input 
variables, flow time, and integral value or average extension as 
required under Sec.  3175.104 must be determined under API 21.1, 
Section 4 and Annex B (incorporated by reference, see Sec.  3175.30).


Sec.  3175.104   Logs and records.

    (a) The operator must retain, and submit to the BLM upon request, 
the original, unaltered, unprocessed, and unedited daily and hourly 
QTRs, which must contain the information identified in API 21.1, 
Subsection 5.2 (incorporated by reference, see Sec.  3175.30), with the 
following additions and clarifications:
    (1) The information required in Sec.  3170.50(g) of this part;
    (2) The volume, flow time, and integral value or average extension 
must be reported to at least 5 significant digits. The average 
differential pressure, static pressure, and temperature as calculated 
in Sec.  3175.103(c), must be reported to at least 3 significant 
digits; and
    (3) A statement of whether the operator has submitted the integral 
value or average extension.
    (b) The operator must retain, and submit to the BLM upon request, 
the

[[Page 56070]]

original, unaltered, unprocessed, and unedited configuration log, which 
must contain the information specified in API 21.1, Subsection 5.4 
(including the flow-computer snapshot report in Subsection 5.4.2), and 
Annex G (incorporated by reference, see Sec.  3175.30), with the 
following additions and clarifications:
    (1) The information required in Sec.  3170.50(g) of this part;
    (2) Software/firmware identifiers under API 21.1, Subsection 5.3 
(incorporated by reference, see Sec.  3175.30);
    (3) For very-low-volume FMPs only, the fixed temperature, if not 
continuously measured ([deg]F); and
    (4) The static-pressure tap location (upstream or downstream);
    (c) The operator must retain, and submit to the BLM upon request, 
the original, unaltered, unprocessed, and unedited event log. The event 
log must comply with API 21.1, Subsection 5.5 (incorporated by 
reference, see Sec.  3175.30), with the following additions and 
clarifications: The event log must have sufficient capacity and must be 
retrieved and stored at intervals frequent enough to maintain a 
continuous record of events as required under Sec.  3170.50 of this 
part, or the life of the FMP, whichever is shorter.
    (d) The operator must retain an alarm log and provide it to the BLM 
upon request. The alarm log must comply with API 21.1, Subsection 5.6 
(incorporated by reference, see Sec.  3175.30).
    (e) Records may only be submitted from measurement data system 
names and versions and flow computer makes and models that have been 
approved by the BLM (see Sec.  3175.41).


Sec.  3175.110  Gas sampling and analysis.

    The standards and requirements in this section apply to all gas 
sampling and analyses. (Note: Table 1 to this section lists the 
standards in this subpart and the API standards that the operator must 
follow to take a gas sample, analyze the gas sample, and report the 
findings of the gas analysis. A requirement applies when a column is 
marked with an ``x'' or a number.)

                              Table 1 to Sec.   3175.110: Gas Sampling and Analysis
----------------------------------------------------------------------------------------------------------------
                  Subject                             Reference              VL         L         H        VH
----------------------------------------------------------------------------------------------------------------
Methods of sampling.......................  Sec.   3175.111(a)..........        x         x         x         x
Heating requirements......................  Sec.   3175.111(b)..........        x         x         x         x
Samples taken from probes.................  Sec.   3175.112(a)..........      n/a         x         x         x
Location of sample probe..................  Sec.   3175.112(b)..........      n/a         x         x         x
Sample probe design and type..............  Sec.   3175.112(c)..........      n/a         x         x         x
Sample tubing.............................  Sec.   3175.112(d)..........      n/a         x         x         x
Spot sample while flowing.................  Sec.   3175.113(a)..........        x         x         x         x
Notification of spot samples..............  Sec.   3175.113(b)..........        x         x         x         x
Sample cylinder requirements..............  Sec.   3175.113(c)..........        x         x         x         x
Spot sampling using portable GCs..........  Sec.   3175.113(d)..........        x         x         x         x
Allowable methods of spot sampling........  Sec.   3175.114(a)..........        x         x         x         x
Low pressure sampling.....................  Sec.   3175.114(b)..........        x         x         x         x
Spot sampling frequency, low- and very-low- Sec.   3175.115(a)..........       12         6       n/a       n/a
 volume FMPs (in months) *.
Initial spot sampling frequency, high- and  Sec.   3175.115(a)..........      n/a       n/a         3         1
 very-high-volume FMPs (in months) *.
Adjustment of spot sampling frequencies,    Sec.   3175.115(b)..........      n/a       n/a         x         x
 high- and very-high-volume FMPs.
Maximum time between samples..............  Sec.   3175.115(c)..........        x         x         x         x
Installation of composite sampler or on-    Sec.   3175.115(d)..........        x         x         x         x
 line GC.
Removal of composite sampler or on-line GC  Sec.   3175.115(e)..........        x         x         x         x
Composite sampling methods................  Sec.   3175.116.............        x         x         x         x
On-line gas chromatographs................  Sec.   3175.117.............        x         x         x         x
Gas chromatograph requirements............  Sec.   3175.118.............        x         x         x         x
Minimum components to analyze.............  Sec.   3175.119(a)..........        x         x         x         x
C9+ analysis..............................  Sec.   3175.119(b) and (c)..      n/a       n/a         x         x
Gas analysis report requirements..........  Sec.   3175.120.............        x         x         x         x
Effective date of spot and composite        Sec.   3175.121.............        x         x         x         x
 samples.
----------------------------------------------------------------------------------------------------------------
VL=Very-low-volume FMP; L=Low-volume FMP; H=High-volume FMP.
VH=Very-high-volume FMP.
* = Immediate assessment for non-compliance under Sec.   3175.150.

Sec.  3175.111  General sampling requirements.

    (a) Samples must be taken by one of the following methods:
    (1) Spot sampling under Sec. Sec.  3175.113 to 3175.115;
    (2) Flow-proportional composite sampling under Sec.  3175.116; or
    (3) On-line gas chromatograph under Sec.  3175.117.
    (b) At all times during the sampling process, the minimum 
temperature of all gas sampling components must be the lesser of:
    (1) The flowing temperature of the gas measured at the time of 
sampling; or
    (2) 30 [deg]F above the calculated hydrocarbon dew point of the 
gas.


Sec.  3175.112  Sampling probe and tubing.

    (a) Samples taken from probes. All gas samples must be taken from a 
sample probe that complies with the requirements of paragraphs (b) and 
(c) of this section.
    (b) Location of sample probe. (1) The sampling probe must be 
located as specified in Sec.  3175.80(p).
    (2) The sample probe must be exposed to the same ambient 
temperature as the primary device. The operator may accomplish this by 
physically locating the sample probe in the same ambient temperature 
conditions as the primary device (such as in a heated meter house) or 
by installing insulation and/or heat tracing along the entire meter 
run. If the operator chooses to use insulation to comply with this 
requirement, the AO may prescribe the quality of the insulation based 
on site-specific factors such as ambient temperature, flowing

[[Page 56071]]

temperature of the gas, composition of the gas, and location of the 
sample probe in relation to the orifice plate (i.e., inside or outside 
of a meter house).
    (c) Sample probe design and type. (1) Sample probes must be 
constructed from stainless steel.
    (2) If a regulating type of sample probe is used, the pressure-
regulating mechanism must be inside the pipe or maintained at a 
temperature of at least 30 [deg]F above the hydrocarbon dew point of 
the gas.
    (3) The sample probe length must be the shorter of:
    (i) The length necessary to place the collection end of the probe 
in the center one-third of the pipe cross-section; or
    (ii) The recommended length of the probe in Table 1 in API 14.1, 
Subsection 6.4 (incorporated by reference, see Sec.  3175.30).
    (4) The use of membranes, screens, or filters at any point in the 
sample probe is prohibited.
    (d) Sample tubing. All components of the sampling system through or 
into which gas flows during the sampling process must be constructed of 
stainless steel or nylon 11. This includes, but is not limited to, the 
sample probe, the sample line including valves and nipples, and the 
sample cylinder.


Sec.  3175.113  Spot samples--general requirements.

    (a) Sampling while flowing. (1) The FMP must be flowing when a 
sample is taken.
    (2) If an FMP is in a non-flowing status at the time that a sample 
is due, a sample must be taken within 15 days after flow is re-
initiated. Documentation of the non-flowing status of the FMP must be 
entered into GARVS as required under Sec.  3175.120(f). For the purpose 
of this section, non-flowing status means no flow goes through the FMP 
for at least one month due to seasonal outages or long-term maintenance 
or repair issues. Non-flowing status does not apply to meters at FMPs 
that flow intermittently on a daily or weekly basis.
    (b) Notification of spot samples. The operator must submit a 
monthly or quarterly schedule of spot samples to the AO in advance of 
taking samples that identifies the FMPs to be sampled during the month 
or quarter.
    (c) Sample cylinder requirements. Sample cylinders must:
    (1) Comply with API 14.1, Subsection 9.1 (incorporated by 
reference, see Sec.  3175.30);
    (2) Have a minimum capacity of 300 cubic centimeters; and
    (3) Be cleaned before sampling in accordance with GPA 2166-17, 
Appendix A (incorporated by reference, see Sec.  3175.30), or an 
equivalent method. The operator must maintain documentation of cleaning 
(see Sec.  3170.50 of this part), have the documentation available on 
site during sampling, and provide it to the BLM upon request. 
Equivalent method(s) of cleaning must be approved by the BLM through 
the PMT.
    (d) Spot sampling using portable gas chromatographs. (1) The use of 
sampling separators is prohibited.
    (2) The sample port and inlet to the sample line must be purged 
using the gas being sampled before completing the connection between 
them.
    (3) The portable GC must be operated, verified, and calibrated 
under Sec.  3175.118.
    (4) The documentation of verification or calibration required in 
Sec.  3175.118(d) must be available for inspection by the BLM at the 
time of sampling.
    (5) Regulator assembly must be heated and/or insulated in a manner 
to ensure they are maintained at least 30 [deg]F above the hydrocarbon 
dew point during sampling.
    (6) The regulator must be set to deliver the sample gas to the 
portable GC at the same pressure at which it was validated or 
calibrated.
    (7) The first run at each location must not be used to determine 
the heating value.
    (8) Vent the sample line through the sample valve at the 
chromatograph for a minimum of 2 minutes before sampling at each 
location. If the prior sample contained high H2S, the sample 
system must be purged with ultra-high purity helium instead of sample 
gas before sampling.


Sec.  3175.114  Spot samples--allowable methods.

    (a) Spot samples must be obtained using one of the following 
methods:
    (1) Purging--fill and empty method. Samples taken using this method 
must comply with GPA 2166-17, Section 9.1 (incorporated by reference, 
see Sec.  3175.30);
    (2) Helium ``pop'' method. Samples taken using this method must 
comply with GPA 2166-17, Section 9.5 (incorporated by reference, see 
Sec.  3175.30). The operator must maintain documentation demonstrating 
that the cylinder was evacuated and pre-charged before sampling and 
make the documentation available to the AO upon request;
    (3) Floating piston cylinder method. Samples taken using this 
method must comply with GPA 2166-17, Sections 9.7.1 to 9.7.3 
(incorporated by reference, see Sec.  3175.30). The operator must 
maintain documentation of the seal material and type of lubricant used 
and make the documentation available to the AO upon request;
    (4) Portable gas chromatograph. Samples taken using this method 
must comply with Sec.  3175.118; or
    (5) Alternative methods. Other methods approved by the BLM (through 
the PMT) and posted at www.blm.gov.
    (b) If the operator uses either a purging--fill and empty method or 
a helium ``pop'' method, and if the flowing pressure at the sample port 
is less than or equal to 15 psig, the operator may also employ a 
vacuum-gathering system. Samples taken using a vacuum-gathering system 
must comply with API 14.1, Subsection 11.10 (incorporated by reference, 
see Sec.  3175.30), and the samples must be obtained from the discharge 
of the vacuum pump.


Sec.  3175.115  Spot samples--frequency.

    (a) Unless otherwise required under paragraph (b) of this section, 
spot samples for all FMPs must be taken and analyzed at the frequency 
(once during every period, stated in months) prescribed in Table 1 to 
Sec.  3175.110.
    (b) After the time frames listed in paragraph (b)(1) of this 
section, the BLM may change the required sampling frequency for high-
volume and very-high-volume FMPs if the BLM determines that the 
sampling frequency required in Table 1 in Sec.  3175.110 is not 
sufficient to achieve the heating value uncertainty levels required in 
Sec.  3175.31(b).
    (1) Timeframes for implementation. (i) For high-volume FMPs, the 
BLM may change the sampling frequency no sooner than 2 years after the 
FMP begins measuring gas or [DATE FOUR YEARS AFTER EFFECTIVE DATE OF 
FINAL RULE], whichever is later; and
    (ii) For very-high-volume FMPs, the BLM may change the sampling 
frequency or require compliance with paragraph (b)(5) of this section 
no sooner than 1 year after the FMP begins measuring gas or [DATE THREE 
YEARS AFTER EFFECTIVE DATE OF FINAL RULE], whichever is later.
    (2) Calculations on sampling frequencies. The BLM will calculate 
the new sampling frequency needed to achieve the heating value 
uncertainty levels required in Sec.  3175.31(b). The BLM will base the 
sampling frequency calculation on the heating value variability. The 
BLM will notify the operator of the new sampling frequency.
    (3) Duration of adjusted sampling frequencies. The new sampling 
frequency will remain in effect until the

[[Page 56072]]

heating value variability justifies a different frequency.
    (4) Adjusted spot-sampling frequency limitation. The new sampling 
frequency will not be more frequent than once every 2 weeks nor less 
frequent than once every 6 months.
    (c) The time between any two samples must not exceed the time 
frames shown in appendix B of this subpart.
    (d) If a composite sampling system or an on-line GC is installed 
under Sec.  3175.116 or Sec.  3175.117, it must be installed and 
operational no more than 90 days after the due date of the next sample.
    (e) The required sampling frequency for an FMP at which a composite 
sampling system or an on-line gas chromatograph is removed from service 
is prescribed in paragraph (a) of this section.


Sec.  3175.116   Composite sampling methods.

    (a) Composite samplers must be flow-proportional.
    (b) Samples must be collected using a positive-displacement pump.
    (c) Sample cylinders must comply with Sec.  3175.113(c) and must be 
sized to ensure the cylinder capacity is not exceeded within the normal 
collection frequency.
    (d) All components of the sampling system must be heated to at 
least 30 [deg]F above the HCDP at all times.


Sec.  3175.117   On-line gas chromatographs.

    (a) On-line GCs must be installed, operated, and maintained in 
accordance with GPA 2166-17, Appendix D (incorporated by reference, see 
Sec.  3175.30), and the manufacturer's specifications, instructions, 
and recommendations.
    (b) The GC must comply with the verification and calibration 
requirements of Sec.  3175.118. The results of all verifications must 
be submitted to the AO upon request.
    (c) Upon request, the operator must submit to the AO the 
manufacturer's specifications and installation and operational 
recommendations.


Sec.  3175.118   Gas chromatograph requirements.

    (a) All GCs must be installed, operated, and calibrated under GPA 
2261-19 (incorporated by reference, see Sec.  3175.30).
    (b) Samples must be analyzed until the un-normalized sum of the 
mole percent of all gases analyzed is between 97 and 103 percent.
    (c) A GC may not be used to analyze any sample from an FMP until 
the verification meets the standards of this paragraph (c).
    (1) GCs must be verified under GPA 2261-19, Section 6 (incorporated 
by reference, see Sec.  3175.30), not less than once every 7 days.
    (2) All gases used for verification and calibration must meet the 
standards of GPA 2198-16, Sections 3 and 4 (incorporated by reference, 
see Sec.  3175.30).
    (3) All new gases used for verification and calibration must be 
authenticated prior to verification or calibration under the standards 
of GPA 2198-16, Section 6 (incorporated by reference, see Sec.  
3175.30).
    (4) The gas used to calibrate a GC must be maintained under GPA 
2198-16, Section 5 (incorporated by reference, see Sec.  3175.30).
    (5) If the composition of the gas used for verification as 
determined by the GC varies from the certified composition of the gas 
used for verification by more than the reproducibility values listed in 
GPA 2261-19, Section 10 (incorporated by reference, see Sec.  3175.30), 
the GC must be calibrated under GPA 2261-19, Section 6 (incorporated by 
reference, see Sec.  3175.30).
    (6) If the GC is calibrated, it must be re-verified under paragraph 
(c)(5) of this section.
    (d) The operator must retain documentation of the verifications for 
the period required under Sec.  3170.50 of this part, and make it 
available to the BLM upon request. The documentation must include:
    (1) The components analyzed;
    (2) The response factor for each component;
    (3) The peak area for each component;
    (4) The mole percent of each component as determined by the GC;
    (5) The mole percent of each component in the gas used for 
verification;
    (6) The difference between the mole percents determined in 
paragraphs (d)(4) and (5) of this section, expressed in relative 
percent;
    (7) Evidence that the gas used for verification and calibration:
    (i) Meets the requirements of paragraph (c)(2) of this section, 
including a unique identification number of the calibration gas used, 
the name of the supplier of the calibration gas, and the certified list 
of the mole percent of each component in the calibration gas;
    (ii) Was authenticated under paragraph (c)(3) of this section prior 
to verification or calibration, including the fidelity plots; and
    (iii) Was maintained under paragraph (c)(4) of this section, 
including the fidelity plot made as part of the calibration run;
    (8) The chromatograms generated during the verification process;
    (9) The time and date the verification was performed; and
    (10) The name and affiliation of the person performing the 
verification.


Sec.  3175.119   Components to analyze.

    (a) The gas must be analyzed for the following components:
    (1) Methane;
    (2) Ethane;
    (3) Propane;
    (4) Iso Butane;
    (5) Normal Butane;
    (6) Pentanes;
    (7)(i) Hexanes-plus (C6+); or
    (ii) Nonanes-plus (C9+), hexanes, heptanes, and octanes;
    (8) Carbon dioxide; and
    (9) Nitrogen.
    (b) When the concentration of C6+ exceeds 1 mole 
percent, a C9+ analysis must be conducted.
    (c) In lieu of testing each sample for the components required 
under paragraph (b) of this section, the operator may periodically test 
for C9+ and adjust the assumed C6+ heating value 
to match the heating value of hexanes, heptanes, octanes, and 
C9+ from the C9+ analysis (see Sec.  
3175.126(a)(3)(ii)). The adjusted C6+ heating value must be 
applied to the mole percent of C6+ analyses until the next 
C9+ analysis is done under paragraph (b) of this section. 
The minimum analysis frequency for the components listed in paragraph 
(b) of this section is as follows:
    (1) For high-volume FMPs, once per year; and
    (2) For very-high-volume FMPs, once every 6 months.


Sec.  3175.120   Gas analysis report requirements.

    (a) The gas analysis report must contain the following information:
    (1) The information required in Sec.  3170.50(g) of this part;
    (2) The date and time that the sample for spot samples was taken 
or, for composite samples, the date the cylinder was installed and the 
date the cylinder was removed;
    (3) The date and time of the analysis;
    (4) For spot samples, the effective date, if other than the date of 
sampling;
    (5) For composite samples, the effective start and end date;
    (6) The name of the laboratory where the analysis was performed, if 
applicable;
    (7) The device used for analysis (i.e., GC, calorimeter, or mass 
spectrometer);
    (8) The make and model of analyzer;
    (9) The date of last calibration or verification of the analyzer;

[[Page 56073]]

    (10) The flowing temperature at the time of sampling;
    (11) The flowing pressure at the time of sampling, including units 
of measure (psia or psig);
    (12) The flow rate at the time of sampling;
    (13) The ambient air temperature at the time of sampling;
    (14) Whether or not heat trace or any other method of heating was 
used;
    (15) The type of sample (i.e., spot-cylinder, spot-portable GC, 
composite);
    (16) The sampling method if spot-cylinder (e.g., fill and empty, 
helium pop);
    (17) A list of the components of the gas tested;
    (18) The total un-normalized mole percent of the components tested;
    (19) The normalized mole percent of each component tested, 
including a summation of those mole percents;
    (20) The ideal heating value (Btu/scf);
    (21) The real heating value (Btu/scf), dry basis;
    (22) The hexanes-plus heating value (Btu/scf), if applicable;
    (23) The pressure base and temperature base;
    (24) The relative density; and
    (25) The name of the company obtaining the gas sample.
    (b) Components that are listed on the analysis report, but not 
tested, must be annotated as such.
    (c) The heating value and relative density must be calculated under 
API 14.5 (incorporated by reference, see Sec.  3175.30).
    (d) The base supercompressibility must be calculated under AGA 
Report No. 8, Part 1 or Part 2 (incorporated by reference, see Sec.  
3175.30).
    (e) The operator must submit all gas analysis reports to the BLM 
within 15 days of the due date for the sample as specified in Sec.  
3175.115.
    (f) The operator must submit all gas analysis reports and other 
required information electronically through the GARVS. The BLM will 
consider granting a variance to the electronic-submission requirement 
only in cases where the operator demonstrates that it is a small 
business, as defined by the U.S. Small Business Administration, and 
does not have access to the internet.


Sec.  3175.121   Effective date of a spot or composite gas sample.

    (a) Unless otherwise specified on the gas analysis report, the 
effective date of a spot sample is the date on which the sample was 
taken.
    (b) The effective date of a spot gas sample may be no later than 
the first day of the production month following the operator's receipt 
of the laboratory analysis of the sample.
    (c) Unless otherwise specified on the gas analysis report, the 
effective date of a composite sample is the first of the month in which 
the sample was removed.
    (d) The provisions of this section apply only to OGORs, QTRs, and 
gas sample reports generated after [EFFECTIVE DATE OF FINAL RULE].


Sec.  3175.125   Calculation of heating value and volume.

    (a) Methodology. The heating value of the gas sampled must be 
calculated as follows:
    (1) Gross heating value is defined by API 14.5, Subsection 3.7 
(incorporated by reference, see Sec.  3175.30) and must be calculated 
under API 14.5, Subsection 7.1 (incorporated by reference, see Sec.  
3175.30); and
    (2) Real heating value must be calculated by dividing the gross 
heating value of the gas calculated under paragraph (a)(1) of this 
section by the compressibility factor of the gas at 14.73 psia and 60 
[deg]F.
    (b) Average heating value determination. (1) If a lease, unit PA, 
or CA has more than one FMP without an FMP number, the average heating 
value for the lease, unit PA, or CA for FMPs without an FMP number for 
a reporting month must be the volume-weighted average of heating 
values, calculated as follows:
[GRAPHIC] [TIFF OMITTED] TP10SE20.039

HVi = the heating value for FMPi, during the 
reporting month (see Sec.  3175.120(b)(2) if an FMP has multiple 
heating values during the reporting month), in Btu/scf
Vi = the volume measured by FMPi, during the reporting 
month, in Btu/scf
Subscript i represents each FMP for the lease, unit PA, or CA
n = the number of FMPs for the lease, unit PA, or CA

    (2) If the effective date of a heating value for an FMP is other 
than the first day of the reporting month, the average heating value of 
the FMP must be the volume-weighted average of heating values, 
determined as follows:
[GRAPHIC] [TIFF OMITTED] TP10SE20.040

where:

HVi = the heating value for FMPi, in Btu/scf
HVi,j = the heating value for FMPi, for 
partial month j, in Btu/scf
Vi,j = the volume measured by FMPi, for 
partial month j, in Btu/scf
Subscript i represents each FMP for the lease, unit PA, or CA
Subscript j represents a partial month for which heating value 
HVi,j is effective
m = the number of different heating values in a reporting month for 
an FMP

    (c) Volume calculation methodology. The volume must be determined 
under Sec. Sec.  3175.94 (mechanical recorders) or 3175.103(c) (EGM 
systems).

[[Page 56074]]

Sec.  3175.126  Reporting of heating value and volume.

    (a) The gross heating value and real heating value, or average 
gross heating value and average real heating value, as applicable, 
derived from all samples and analyses must be reported on the OGOR in 
units of Btu/scf under the following conditions:
    (1) Containing no water vapor (``dry''), unless the water vapor 
content has been determined through actual on-site measurement, 
included in heating value calculations, and reported on the gas 
analysis report. The heating value may not be reported on the basis of 
an assumed water-vapor content. Acceptable methods of measuring water 
vapor are:
    (i) Makes and models of chilled mirrors approved by the BLM and 
placed on the list of approved equipment and methods maintained at 
www.blm.gov;
    (ii) Automated chilled mirrors approved by the BLM and placed on 
the list of approved equipment and methods maintained at www.blm.gov; 
and
    (iii) Other equipment and methods approved by the BLM and placed on 
the list of approved equipment and methods maintained at www.blm.gov;
    (2) Adjusted to a pressure of 14.73 psia and a temperature of 60 
[deg]F;
    (3) For samples analyzed under Sec.  3175.119(a), and 
notwithstanding any provision of a contract between the operator and a 
purchaser or transporter, the composition of hexanes-plus must have a 
heating value not less than:
    (i) 5129 Btu/scf (equivalent heating value of 60 percent hexanes, 
30 percent heptanes, and 10 percent octanes.); or
    (ii) The heating value of the C9+ composition determined 
under Sec.  3175.119(c); and
    (4) For samples analyzed under Sec.  3175.119(b), and 
notwithstanding any provision of a contract between the operator and 
purchaser or transporter, the composition of C9+ must have a 
heating value not less than 6,996 Btu/scf.
    (b) The volume for royalty purposes must be reported on the OGOR in 
units of Mcf as follows:
    (1) The volume must not be adjusted for water-vapor content or any 
other factors that are not included in the calculations required in 
Sec.  3175.94 or Sec.  3175.103; and
    (2) The volume must match the monthly volume(s) shown in the 
unedited QTR(s) or integration statement(s) unless edits to the data 
are documented under paragraph (c) of this section.
    (c) Edits and adjustments to reported volume or heating value. (1) 
If for any reason there are measurement errors stemming from an 
equipment malfunction that results in discrepancies to the calculated 
volume or heating value of the gas, the volume or heating value 
reported during the period in which the volume or heating value error 
persisted must be estimated.
    (2) All edits made to the data before the submission of the OGOR 
must be documented and include verifiable justifications for the edits 
made. This documentation must be maintained under Sec.  3170.50 of this 
part and must be submitted to the BLM upon request.
    (3) All values on daily and hourly QTRs that have been changed or 
edited must be clearly identified and must be cross referenced to the 
justification required in paragraph (c)(2) of this section.
    (4) The volumes reported on the OGOR must be corrected beginning 
with the date that the inaccuracy occurred. If that date is unknown, 
the volumes must be corrected beginning with the production month that 
includes the date that is half way between the date of the previous 
verification and the most recent verification date.


Sec.  3175.130   Requirements for gas storage agreement measurement 
points (GSAMPs).

    Gas storage agreement measurement points must meet the requirements 
of this subpart subject to the following specifications and exemptions:
    (a) A meter at a GSAMP is:
    (1) Very-low volume if it measures 800 Mcf/day or less over the 
averaging period;
    (2) Low volume if it measures more than 800Mcf/day and 4,700 Mcf/
day or less over the averaging period; or
    (3) High volume if it measures more than 4,700 Mcf/day over the 
averaging period.
    (b) A GSAMP is exempt from the following sections of this subpart:
    (1) Section 3175.110;
    (2) Section 3175.80(p);
    (3) Section 3175.120;
    (4) Section 3175.121;
    (5) Section 3175.125(a) and (b); and
    (6) Section 3175.126.


Sec.  3175.140   Temporary measurement.

    Measurement equipment at any temporary measurement facility must 
meet the requirements of this subpart with the following exceptions:
    (a) Routine mechanical recorder verifications under Sec.  
3175.92(b) are not required;
    (b) Routine EGM system verification under Sec.  3175.102(b) are not 
required;
    (c) Basic meter-tube inspections under Sec.  3175.80(j) are not 
required; and
    (d) Detailed meter-tube inspections under Sec.  3175.80(k)(1) are 
not required.


Sec.  3175.150   Immediate assessments.

    (a) Certain instances of noncompliance warrant the imposition of 
immediate assessments upon discovery. Imposition of any of these 
assessments does not preclude other appropriate enforcement actions.
    (b) The BLM will issue the assessments for the violations listed as 
follows:

     Table 1 to Sec.   3175.150--Violations Subject to an Immediate
                               Assessment
------------------------------------------------------------------------
                                                            Assessment
                       Violation:                           amount per
                                                            violation:
------------------------------------------------------------------------
1. New FMP orifice-plate inspections were not conducted           $1,000
 as required by Sec.   3175.80(e).......................
2. Routine FMP orifice-plate inspections were not                  1,000
 conducted as required by Sec.   3175.80(f).............
3. Basic meter-tube inspections were not conducted as              1,000
 required by Sec.   3175.80(j)..........................
4. Detailed meter-tube inspections were not conducted as           1,000
 required by Sec.   3175.80(k)..........................
5. An initial EGM-system verification was not conducted            1,000
 as required by Sec.   3175.102(a)......................
6. Routine EGM-system verifications were not conducted             1,000
 as required by Sec.   3175.102(b)......................
7. Spot samples for low-volume and very-low-volume FMPs            1,000
 were not taken as required by Sec.   3175.115(a).......
8. Spot samples for high- and very-high-volume FMPs were           1,000
 not taken as required by Sec.   3175.115(a) and (b)....
------------------------------------------------------------------------

BILLING CODE 4310-84-P

[[Page 56075]]

[GRAPHIC] [TIFF OMITTED] TP10SE20.041


[[Page 56076]]


[GRAPHIC] [TIFF OMITTED] TP10SE20.042


[[Page 56077]]


[GRAPHIC] [TIFF OMITTED] TP10SE20.043


    Appendix B to Subpart 3175--Maximum Time Between Required Actions
------------------------------------------------------------------------
                                                Then the maximum time
 If the required frequency is once every:   between required actions (in
                                                      days) is:
------------------------------------------------------------------------
2 weeks...................................                            18
Month.....................................                            45
2 months..................................                            75
3 months..................................                           105
6 months..................................                           195
12 months.................................                           395
------------------------------------------------------------------------

[FR Doc. 2020-16393 Filed 9-2-20; 4:15 pm]
BILLING CODE 4310-84-C