Oil and Gas Site Security, Oil Measurement, and Gas Measurement Regulations, 55940-56077 [2020-16393]
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Federal Register / Vol. 85, No. 176 / Thursday, September 10, 2020 / Proposed Rules
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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
Bureau of Land Management,
Interior.
ACTION: Proposed rule.
AGENCY:
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
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SUMMARY:
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For Comments on InformationCollection 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 fbremner@
blm.gov. 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 rgood@blm.gov, 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 fbremner@blm.gov. 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
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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.
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
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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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,
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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
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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
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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 § 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
§ 3174.100 through § 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
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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 phasein 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 watervapor-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
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55943
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 §§ 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
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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 §§ 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
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some of the material at https://
publications.api.org.
The standards that are proposed to be
incorporated are summarized as part of
the section-by-section analysis for
§§ 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
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Chromatograph (GC) software and water
vapor detection methods;
• Reduce basic meter-tube inspection
frequency and remove detailed metertube inspection requirement for lowvolume 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.
specifically discussed in this section-bysection analysis, then the provision is
essentially the same as the existing
regulation.
B. Section-by-Section Discussion
The following discussion addresses
the proposed changes from the existing
regulation. If a provision is not
The following table provides a crosswalk comparison of proposed subpart
3170 to the corresponding sections in
existing subpart 3170:
1. Section-by-Section Discussion for
Changes to Subpart 3170
Existing subpart 3170 sec.
Proposed subpart 3170 sec.
3170.1 Authority .....................................................................................
3170.2 Scope .........................................................................................
3170.3 Definitions and acronyms ..........................................................
3170.4 Prohibitions against by-pass and tampering .............................
3170.5 [Reserved] ..................................................................................
3170.6 Variances ...................................................................................
3170.7 Required recordkeeping, records retention, and records submission.
3170.8 Appeal procedures .....................................................................
3170.9 Enforcement ...............................................................................
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.
The following discussion addresses
section-by-section changes in the
proposed subparts 3170 from the
existing subparts 3170.
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Section 3170.2 Scope
The BLM is proposing to add a new
paragraph (f) to § 3170.2. Proposed
§ 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, oilmeasurement, 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 nonFederal 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
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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 § 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
§ 3170.10 for consistency of numbering
across the part 3170 subparts.
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A new definition for ‘‘Alarm log’’
would be added in proposed § 3170.10.
Since the term would be used in
proposed subparts 3174 and 3175, its
definition belongs in § 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 § 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 § 3175.10 to
proposed § 3170.10 because the term is
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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 § 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 § 3173.12.’’ The proposed
definition of FMP is not couched in
terms of ‘‘BLM-approved’’ measurement
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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 § 3173.12(a)
and (b) would be deleted. Existing
§ 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 § 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 § 3173.60 later in this
preamble).
The proposed rule would relocate the
definition for ‘‘Land description’’ from
existing § 3173.1 to proposed § 3170.10,
with a minor revision. The term ‘‘Land
description’’ is used in subparts 3170
and 3173, so it belongs in § 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.
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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 § 3170.10.
Proposed § 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 § 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 § 3173.1 to
§ 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 § 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
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and the BLM believes the intent of the
purpose is already contained within the
first sentence.
Proposed § 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 § 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 § 3174.4(d) and
§ 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
§ 3174.4(d) and § 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 § 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
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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 § 3170.30(c) would clarify
that the procedures for requesting and
granting a variance under § 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
§ 3170.6 would be renumbered to
§ 3170.40. Both § 3170.6 and § 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
§ 3170.40 would revise the existing
language to match language in proposed
§ 3173.43(b) (existing § 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
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55947
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 § 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 § 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 § 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
§ 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:
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Existing subpart 3173 sec.
3173.1
3173.2
3173.3
3173.4
3173.5
truck.
3173.6
3173.7
3173.8
3173.9
3173.10
3173.11
3173.12
3173.13
Proposed subpart 3173 sec.
Definitions and acronyms ..........................................................
Storage and sales facilities—seals ............................................
Oil measurement system components—seals ..........................
Federal seals .............................................................................
Removing production from tanks for sale and transportation by
Water-draining operations ..........................................................
Hot oiling, clean-up, and completion operations .......................
Report of theft or mishandling of production .............................
Required recordkeeping for inventory and seal records ...........
Form 3160–5, Sundry Notices and Reports on Wells .............
Site facility diagram ....................................................................
Applying for a facility measurement point ...............................
Requirements for approved facility measurement points ........
3173.14 Conditions for commingling and allocation approval (surface
and downhole).
3173.15 Applying for a commingling and allocation approval ...............
3173.16 Existing commingling and allocation approvals .......................
3173.17 Relationship of a commingling and allocation approval to royalty-free use of production.
3173.18 Modification of a commingling and allocation approval ...........
3173.19 Effective date of a commingling and allocation approval ........
3173.20 Terminating a commingling and allocation approval ...............
3173.21 Combining production downhole in certain circumstances .....
3173.22 Requirements for off-lease measurement ...............................
3173.23 Applying for off-lease measurement ........................................
3173.24 Effective date of an off-lease measurement approval .............
3173.25 Existing approved off-lease measurement ..............................
3173.26 Relationship of off-lease measurement approval to royaltyfree use of production.
3173.27 Termination of off-lease measurement approval .....................
3173.28 Instances not constituting off-lease measurement, for which
no approval is required.
3173.29 Immediate assessments for certain violations .........................
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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 § 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 § 3173.80. The
proposed changes in § 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
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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 point numbers.
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 royaltyfree 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.
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 noncommingled 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
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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 noncommingled 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 § 3173.1
and relocate it to proposed § 3170.10.
The proposed rule would move the
revised definition for ‘‘Permanent
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measurement facility’’ from § 3173.1 to
§ 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
§ 3173.70(b)(5).
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Section 3173.20 Storage and Sales
Facilities—Seals
The proposed rule would clarify the
requirement in § 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 § 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 § 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 § 3173.21(a) would change
the sealing requirements for the
components on LACT meters and CMSs
that are currently contained in existing
§ 3173.3(a)(1), (a)(4), (a)(5), (a)(6), (a)(7),
(a)(8), (a)(9), (a)(10), (a)(12), and (a)(13).
Proposed § 3173.21would eliminate
seal requirements for the following seals
on LACT meters and CMSs:
§ 3173.3(a)(1) Sample probes;
§ 3173.3(a)(6) LACT meters or CMS;
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§ 3173.3(a)(9) Manual-sampling valves (if
so equipped)’
§ 3173.3(a)(10) Valves on diverter lines
larger than 1 inch in nominal diameter;
§ 3173.3(a)(12) Totalizer; and
§ 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 § 3173.3(a)(1), requiring a
seal for sample probes on LACTs or
CMSs, would be eliminated in proposed
§ 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 § 3173.3(a)(6), requiring a
seal for LACT meters or CMS, would be
eliminated in proposed § 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, higherproducing 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 § 3173.3(a)(9), requiring a
seal for manual sample valves, would be
eliminated in proposed § 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
§ 3173.20(c)(4) designates a sample cock
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valve on piping or tanks of less than 1inch 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 § 3173.20(c) and the proposed
sealing requirements on oil
measurement systems in proposed
§ 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 § 3173.3(a)(10), requiring a
seal for valves on divert lines larger than
1 inch in diameter, would be eliminated
in proposed § 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. Highervolume 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 § 3173.3(a)(12), requiring a
seal for the totalizer, would be
eliminated in proposed § 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 § 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 § 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 § 3173.3(a)(13), requiring a
seal for proving connections, would be
eliminated in proposed § 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
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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 § 3173.21(a)(3) would
modify the meter-assembly sealing
requirements now found in existing
§ 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 § 3173.21(a)(4) would
modify the seal requirement for a
temperature averager, now found in
existing § 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 § 3173.21(a)(5) would revise
the sealing requirement for a backpressure valve downstream of the meter,
now found in existing § 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, backpressure 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
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maintain the same level of measurement
accuracy at locations with fixed or nonautomatic adjusting back-pressure
valves downstream of the meter.
Proposed § 3173.21(a)(6) would
clarify the sealing requirement for drain
valves, now found in existing
§ 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 § 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 § 3173.6(a)
through (h) when water is drained from
a tank storing hydrocarbons.
This proposed rule would eliminate
the specific requirements in § 3173.6(a)
through (h) and instead defer to the sealrecord requirements in proposed
§ 3173.41(b), which are currently in
existing § 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
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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 § 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 § 3173.50 would revise and
renumber existing § 3173.11, which sets
out the requirements for site facility
diagrams.
Proposed § 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
§ 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 nonFederal 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 § 3173.50(c)(4) would
correct an editing error in existing
§ 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
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BLM inspectors to conduct appropriate
facility inspections.
Proposed § 3173.50(c)(6) would
remove the requirement in existing
§ 3173.11(c)(6) for an operator of a colocated production facility to include on
the site facility diagram a skeleton
diagram of the other operator’s colocated facility(ies). The proposed rule
would maintain the existing
requirement, in the second sentence of
existing § 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 § 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 § 3173.50(d)(1) would revise
the timeframe in existing § 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 § 3173.50(d)(2)
would change the timeframe in existing
§ 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
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‘‘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 § 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 § 3173.50(a)
and so the deletion of existing
3173.11(e)(1) and (e)(2) removes a
regulatory redundancy. Under
§ 3173.50(a), operators would still be
required to submit a site facility diagram
for a location not requiring an FMP
number.
Proposed § 3173.50(e) is a new section
that would change the timeframe in
existing § 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 nonFederal 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 § 3173.60 would revise the
existing requirements for the FMPnumber application process that are
now located in existing § 3173.12.
The proposed rule would change the
section title slightly from ‘‘Applying for
a facility measurement point’’ to
‘‘Applying for a facility measurement
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55951
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
§§ 3173.12(a)(1), (a)(2), and (b) because
these sections essentially define FMP,
off-lease measurement, and
commingling. Proposed § 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 § 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 §§ 3173.60(c)(1), (c)(2), and
(c)(3) would change the tiers in existing
§ 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
§§ 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 § 3173.60(c) would also
delete the enforcement language in
existing § 3173.12(e)(7). Subpart 3163
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provides standalone authority for an
Incident of Noncompliance (INC) and
civil penalties for noncompliance with
this part. In addition, proposed
§ 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 § 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
§ 3173.12(f). Existing § 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 § 3173.12(f)(2).
Proposed § 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
§ 3173.12(f)(3)(i) through (iii).
The BLM believes the proposed
changes in § 3173.60(d)(2)(i), (ii), and
(iii) would provide for consistent FMPnumber-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 § 3173.60(d)(2)(i) would
change the information required under
existing § 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
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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 § 3173.60(d)(2)(ii),
the equipment information required
under existing § 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
§ 3173.60(d)(2)(i) and (iii).
Proposed § 3173.60(d)(2)(iii) would
change the information requirements
under existing § 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
§ 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 § 3173.60(d)(3) would
replace the reference to API number in
existing § 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 § 3173.61 would revise the
requirements in existing § 3173.13 that
specify when operators must start using
their FMP numbers on production
reporting to ONRR and when they must
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notify the BLM of any permanent
changes made to an FMP.
Proposed § 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
§ 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 § 3173.61(b)(1) would not
change from existing § 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 § 3173.60.
Proposed § 3173.61 would delete
existing § 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 § 3173.13(b)(1). The
BLM believes the existing requirement
is redundant and adequately covered
under proposed § 3173.61(b)(1), which
states in part, ‘‘These include any
changes and modifications to the
information listed on an application
submitted under § 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
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deletion improves understanding of
requirements and eliminates a
redundancy.
Section 3173.70 Conditions for
Commingling and Allocation Approval
(Surface and Downhole)
Proposed § 3173.70 would revise the
existing requirements for commingling
and allocation approval that are now
located in existing § 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
§ 3174.31 and § 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
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).
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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.
Proposed § 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 § 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 § 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 § 3173.70(a)(3) would
change existing § 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
§ 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 § 3173.71(j).
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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 § 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 § 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 § 3173.10 under the proposed
rule and in conditions under which
commingling may be approved in
proposed § 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
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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 noncommingled 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 noncommingled 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 § 3173.70(b)(5) would add a
new paragraph with a new condition for
commingling and allocation approvals
and renumber existing § 3713.14(b)(5) to
§ 3173.70(b)(6). Proposed § 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
§ 3174.31 and proposed § 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?
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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 § 3173.71 would revise
existing requirements for commingling
and allocation approval applications
that are now located in existing
§ 3173.15.
Proposed § 3173.71(a) would remove
from existing § 3173.15(a) the provision
stating that, if the commingling and
allocation proposal includes off-lease
measurement, a separate Sundry Notice
required under existing § 3173.23 is
unnecessary as long as the information
required under existing § 3173.23(b)
through (e) and, where applicable,
existing § 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
§ 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 § 3173.10.
Proposed § 3173.71(b) would change
existing § 3173.15(b) to require an
operator to submit an off-lease
measurement Sundry Notice request
under proposed § 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.
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Proposed § 3173.71(c) would delete
the requirement in existing § 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 § 3173.70(a)(2).
Proposed § 3173.71(f) would amend
the requirement in existing § 3173.15(f)
for a surface-use plan of operations if
new surface disturbance is proposed for
the FMP or associated facilities on BLMmanaged 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 BLMmanaged 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 § 3173.71(g) and § 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 § 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 § 3173.15(g) and § 3173.15(i)
require an operator to submit the grant
application as part of its CAA
application. Proposed § 3173.71(i)
would reduce the requirement to the
operator providing an applicantcertified 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
§ 3172.71(f), the change in part (g)
would also reduce application
submission and review burdens on both
industry and the BLM.
Proposed § 3173.71(j) would change
the documentation requirements under
existing § 3173.15(j) to allow leases that
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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
§ 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 § 3173.71(j) would make it
consistent with proposed changes in
§ 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 § 3173.71(a) would change
existing § 3173.15(a) to require that gas
CAA applications must be submitted
separately from oil CAA applications.
Existing § 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 § 3173.71(a) for separate CAA
applications for oil and gas.
Section 3173.72 Existing Commingling
and Allocation Approvals
Proposed § 3173.72 would make small
changes to the BLM’s process, now
described in existing § 3173.16, for
reviewing existing commingling and
allocation approvals.
Proposed § 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
§ 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
§ 3173.16(a)(2)(ii) to less than 1,000 bbl
of oil per month. In the existing rule, the
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thresholds in § 3173.14(b)(2) and
§ 3173.16(a)(2) are identical. The
proposed regulation maintains identical
thresholds for these sections. The
increased production thresholds are
discussed earlier.
Proposed § 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 § 3173.74(b) would add
another condition to existing § 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 § 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 § 3173.80 would make a
small change to the BLM’s requirements
for combining production downhole
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that are now located in existing
§ 3173.21.
Proposed § 3173.80(a)(1) would
change the words in existing
§ 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 OffLease Measurement
Proposed § 3173.91 would clarify and
simplify the requirements for an offlease measurement application in
existing § 3173.23.
Proposed § 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 § 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 § 3173.91(f) and (g) would
require an operator applying for offlease 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
§ 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 § 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 § 3173.91 would delete
existing § 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 § 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
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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 § 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 § 3173.2.’’ Proposed
Immediate Assessment 1 in § 3173.190
would be changed to match the
definition in proposed § 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 § 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 § 3173.10. Where
an operator has systemic and reoccurring violations, the BLM may
always take appropriate enforcement
action.
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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. proposed subpart 3174
3174.1 Definitions and acronyms ..........................................................
3174.2 General requirements ................................................................
3174.3 Incorporation by reference (IBR) ...............................................
3174.4 Specific performance requirements ...........................................
New ...........................................................................................................
New ...........................................................................................................
New ...........................................................................................................
New ...........................................................................................................
New ...........................................................................................................
3174.2 General requirements ...................................................................
3174.2 General requirements ...................................................................
3174.5 Oil measurement by tank gauging—general requirements .........
3174.5 Oil measurement by tank gauging—general requirements .........
3174.5 Oil measurement by tank gauging—general requirements .........
3174.6 Oil measurement by tank gauging—procedures .......................
3174.6 Oil measurement by tank gauging—procedures .......................
3174.6 Oil measurement by tank gauging—procedures .......................
3174.6 Oil measurement by tank gauging—procedures .......................
3174.6 Oil measurement by tank gauging—procedures .......................
3174.6 Oil measurement by tank gauging—procedures .......................
3174.7 LACT systems—general requirements ......................................
3174.8 LACT systems—components and operating requirements .......
New ...........................................................................................................
3174.8 LACT systems—components and operating requirements .......
New ...........................................................................................................
3174.8 LACT systems—components and operating requirements .......
3174.8 LACT systems—components and operating requirements .......
3174.8 LACT systems—components and operating requirements .......
New ...........................................................................................................
3174.8 LACT systems—components and operating requirements .......
3174.10 Coriolis meter for LACT and CMS measurement applications—operating requirements.
3174.10 Coriolis meter for LACT and CMS measurement applications—operating requirements.
New ...........................................................................................................
3174.9 Coriolis measurement systems (CMS)—general requirements
and components.
New ...........................................................................................................
3174.11 Meter-proving requirements .....................................................
3174.11 Meter-proving requirements .....................................................
3174.11 Meter-proving requirements .....................................................
3174.11 Meter-proving requirements .....................................................
3174.11 Meter-proving requirements .....................................................
3174.11 Meter-proving requirements .....................................................
3174.11 Meter-proving requirements .....................................................
3174.11 Meter-proving requirements .....................................................
3174.11 Meter-proving requirements .....................................................
3174.12 Measurement tickets ................................................................
3174.12 Measurement tickets ................................................................
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Changes to Subpart 3174
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3174.10
3174.20
3174.30
3174.31
3174.40
3174.41
3174.42
3174.43
3174.50
3174.60
3174.70
3174.80
3174.81
3174.82
3174.83
3174.84
3174.85
3174.86
3174.87
3174.88
3174.90
3174.100
3174.101
3174.102
3174.103
3174.104
3174.105
3174.106
3174.107
3174.108
3174.110
Definitions and acronyms.
General requirements.
Incorporation by reference (IBR).
Specific measurement performance requirements.
Approved measurement equipment and data requirements.
Measurement equipment requiring BLM approval.
Measurement equipment approved by regulation.
Data submission and notification requirements.
Grandfathering.
Timeframes for compliance.
Measurement location.
Oil storage tank equipment.
Oil measurement by tank gauging.
Oil tank calibration.
Tank gauging procedures.
Tank oil sampling.
Determining S&W content.
Tank oil temperature determination.
Observed oil gravity determination.
Measuring tank fluid level
LACT systems—general requirements.
LACT systems—components and operating requirements.
Charging pump and motor.
Sampling and mixing system.
Air Eliminator.
LACT meter.
Electronic temperature averaging device.
Pressure-indicating device.
Meter Proving Connections.
Back Pressure and Check Valves.
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.
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Sec. existing subpart 3174
3174.12
Sec. proposed subpart 3174
Measurement tickets ................................................................
3174.13 Oil measurement by other methods ........................................
3174.14 Determination of oil volumes by methods other than measurement.
3174.15 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
§ 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 openingtank fluid level are currently found at
§ 3174.6(b)(5)(i)(A) through (E). Under
the proposed rule, the regulatory
citation for determining the tank fluid
level would be § 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
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Section 3174.10
Acronyms
Definitions and
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 § 3174.1 to the
definitions section for subpart 3170
(§ 3170.10), which defines terms that are
used in more than one of the part 3170
subparts.
The definition for ‘‘Base pressure’’ in
current § 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
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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.
software technologies that are associated
with liquids measurement.
Definitions for three new proposed oil
FMP categories would be added: ‘‘Veryhigh-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 ‘‘Lowvolume 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 § 3174.31(c), but would be
exempt from the minimum uncertainty
requirements found in proposed
§ 3174.31(a) and the requirement to
achieve measurement without
statistically significant bias in proposed
§ 3174.31(b). Under § 3174.50, lowvolume FMPs in service before the
effective date of the final rule would be
exempt from the BLM-approved
equipment requirements of proposed
§ 3174.41(a) through (i) until the listed
equipment is replaced, or production
levels at the FMP elevate it to the veryhigh-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.
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The proposed rule defines ‘‘Highvolume 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 highvolume FMPs would ensure that
measurements have no statistically
significant bias, would be verifiable
under proposed § 3174.31(b) and (c),
and would achieve an overall
measurement uncertainty of ±1.50
percent under proposed § 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 § 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 § 3174.41(a) through (i)
until the equipment listed in
§ 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 ‘‘Veryhigh-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 § 3174.31(b)
and (c), and would achieve an overall
measurement uncertainty of ±0.50
percent under proposed § 3174.31(a).
The BLM believes the production
volume threshold would make it
economically feasible for operators to
retrofit FMPs to meet the overall
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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 § 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.
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Section 3174.20
General Requirements
Currently located in existing § 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 § 3174.60, and a new § 3174.70.
Section 3174.30
Reference (IBR)
Incorporation by
Building on existing § 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
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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
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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, MasterMeter 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 custodytransfer 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
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previously approved for IBR and is
unchanged.
• API MPMS Chapter 7.1,
Temperature Determination—Liquid-inGlass 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-inglass 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.
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• 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
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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
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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.
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• 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
§ 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
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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 (§§ 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.
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• 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 § 3174.4,
this proposed section specifies the
measurement-performance requirement
for each FMP. The uncertainty volume
levels proposed in § 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
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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 highvolume (>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 § 3174.4(b)
would be renumbered to § 3174.31(b)
with no change to the language
concerning bias.
The existing paragraph § 3174.4(c)
would be renumbered to § 3174.31(c)
with no change to the language
concerning verifiability.
The existing paragraph § 3174.4(d),
requiring alternative equipment to meet
or exceed the performance requirements
of this section, would be moved to
§ 3170.3 because this requirement
applies to both subparts 3174 and 3175.
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Section 3174.40 Approved
Measurement Equipment and Data
Requirements
The BLM is proposing to add new
§§ 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
§ 3174.41. The introductory paragraph
to § 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-andcomment 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 § 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
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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 § 3174.42. The purpose of
proposed § 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, § 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 § 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
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included as well to expedite locating the
requirement within subpart 3174.
Section 3174.50
Grandfathering
The BLM is proposing new § 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
(§§ 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 § 3174.2(g) and was further
delayed by practical necessity (see IM
2018–077 (June 29, 2018)).
Proposed § 3174.50 would exempt all
equipment listed in proposed § 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
§ 3174.121(a)) at high- and low-volume
FMPs, and temporary measurement
equipment (see proposed § 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 veryhigh-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,
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discussed further in the § 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 § 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 highvolume 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
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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
§ 3174.4 with proposed §§ 3174.10,
3174.31. Due to this proposed change,
more FMPs would fall in the ‘‘veryhigh’’ 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
§ 3174.4 and proposed § 3174.31). For
example, for high-volume FMPs, which
must comply with the uncertainty
performance goals under § 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
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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
Compliance
Timeframes for
The compliance timeframes for
current subpart 3174 are located in
existing § 3174.2(e), (f), and (g).
Proposed § 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 § 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 § 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 highvolume 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
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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
§ 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 § 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 § 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 § 3174.60(e) would delay
the equipment-approval requirements
that are listed in proposed § 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
§ 3174.41.
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Section 3174.70 Measurement
Location.
This new section would use identical
language from existing § 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 § 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
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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 § 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 tankgauging operations. The same API
standards are being proposed for
incorporation as in current § 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 § 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 °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 tankcapacity 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 tankcalibration 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
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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
§ 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 § 3174.83(a) reiterates the
requirement located in existing
§ 3174.6(a). Proposed § 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 § 3174.6(a) with
exception of adding the cross-references
to other sections.
Proposed § 3174.83(b) follows existing
§ 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 § 3174.30 provides more
detail concerning API 18.2 and the
decision to not include it in revised
subpart 3174.
Proposed § 3174.83(c) contains
proposed changes to the run-ticket
section (existing § 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 § 3174.12(a) during field
operations. Some believe the existing
rule requires that field operations must
complete all the run-ticket calculations
found in § 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 § 3174.161(a)
in the field.
Proposed § 3174.83(d) expresses the
same requirement as existing
§ 3174.6(b)(1).
Proposed § 3174.83(e) reflects the
requirement currently contained in
existing § 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
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has been deleted to remove any
potential confusion.
3174.84 Tank Oil Sampling
This section reflects the requirement
currently located in existing
§ 3174.6(b)(3), with a proposed
modification that would allow for
alternative methods approved by the
BLM.
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3174.85 Determining S&W Content
This section reflects the requirement
currently located in existing
§ 3174.6(b)(6). This proposed section
employs the same language as current
§ 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
§ 3174.6(b)(2) with a few clarifying
changes.
Under § 3174.86 of the proposed rule,
the BLM would eliminate the sentence
in existing § 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 § 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 § 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
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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 § 3174.6(b)(4). This
proposed section employs the same
language as that found in current
§ 3174.6(b)(4), with exception of
updating the cross-references.
3174.88 Measuring Tank Fluid Level
Proposed § 3174.88 would essentially
retain the manual tank gauging and ATG
methods of tank measurement found in
current § 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 § 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 § 3174.88(a) of the proposed
rule, the BLM would eliminate the
sentence from existing
§ 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
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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 § 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 productindicating pastes.
In proposed § 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
§ 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.
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This proposed change would also bring
the verification date requirements of
this part in line with the subpart 3175
information requirements that flowcomputer 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
§ 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 § 3174.90(a) and (b) would
use the same language as the existing
§ 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 § 3174.90(c) would have the
same language that is in existing
§ 3174.7(d), concerning the LACT
components being accessible for
inspection.
Proposed § 3174.90(d) would retain
the language of existing § 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 § 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
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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 § 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 § 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 § 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
§ 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 § 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
§ 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
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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 § 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 § 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 § 3174.90(i) is similar to
existing § 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 § 3174.90(j) restates the
requirement of existing § 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 §§ 3174.101 through 3174.108.
This section constitutes a change from
the existing § 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
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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.
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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 § 3174.8(b)(1). This proposed
rule seeks to replace the current
requirement for testing, pursuant to API
8.2. Existing § 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
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reduce the overall burden to operators
and simplify the inspection process for
the BLM.
Proposed § 3174.102(a) would use
identical language found in
§ 3174.8(b)(1) for sample extractor probe
requirements, with the exception of
§ 3174.102(a)(3), which would clarify
the sample-probe requirements found in
§ 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 § 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 § 3174.102(c) would expand
on language found in § 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
§ 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
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incorporated into the BLM’s regulatory
process.
Proposed § 3174.104(a) clarifies the
non-resettable totalizer requirement of
existing § 3174.8(b)(4). The proposed
rule would make it clear that the nonresettable totalizer display may reside in
an electronic flow computer. The nonresettable 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 nonresettable 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
§ 3174.8(b)(6). This proposed rule
would clarify a point of confusion in the
existing regulation by specifying in
proposed § 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
§ 3174.105(a), a stand-alone
temperature-averaging device would
require PMT review and BLM approval.
Similarly, under proposed
§ 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
§ 3174.8(b)(5) and § 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 pressuretransmitter approval is only referenced
indirectly in existing § 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
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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 § 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 bleedvalve 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.
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3174.108
Valves
Back-Pressure and Check
This section would retain existing
§ 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 § 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 backpressure valve when downstream
pressures constantly change.
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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 § 3174.10(b)
and would keep or modify the
remaining paragraphs of existing
§ 3174.10.
Proposed § 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 § 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 § 3174.110(c) is the same as
existing § 3174.10(a).
Proposed § 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 flowcomputer generated totalizer would not
fulfill the requirements of subpart 3174.
Proposed § 3174.110(e) would clarify
existing § 3174.10(d) by specifying
when a meter-verification procedure
must be conducted. Existing
§ 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
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proving process and at any time the AO
would request it. Two minor changes
would be made in the fourth sentence
of proposed § 3174.110(e): Adding the
word ‘‘reading’’ after the word ‘‘zero,’’
which was inadvertently left out of the
next-to-last sentence of existing
§ 3174.10(d), and changing a cross
reference.
Proposed § 3174.110(f) would require
the same on-site display requirements of
existing § 3174.10(e)(1) and (2) with
exception of moving the instantaneous
pressure reading and the instantaneous
temperature reading requirements to
proposed § 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
§ 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
§ 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 § 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 § 3174.120 from the Coriolis
meter requirements at proposed
§ 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
§ 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
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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.
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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
§ 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
§ 3174.9. This proposed rule would only
make minor changes to the requirements
of existing § 3174.9.
Paragraph (b) would require each
CMS to utilize an ELM and follow the
requirements of proposed § 3174.120.
This is intended to reflect the new ELM
section at proposed § 3174.120, and
would not impose burdensome
additional requirements since the ELM
section is comprised primarily of
existing requirements that are found in
existing § 3174.10. These organizational
changes are intended to make the
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requirements clearer and provide a
better organization of the requirements.
Paragraph (e) would add a new
provision (§ 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 § 3173.20 seal requirement for
multi-truck loads. The intent of that
section of § 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
§ 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 § 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 (§§ 3174.151 through 3174.158).
A meter proving is the procedure used
to determine a meter factor required to
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calculate the volume of liquid measured
through a meter. Currently all proving
requirements are found in existing
§ 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 § 3174.151 maintains the
existing meter-prover requirements
found in existing § 3174.11(b) and
includes new language that would add
flexibility for additional meter provers
as new technology emerges.
Under existing § 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 positivedisplacement 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 § 3174.152(a) would modify
the proving requirements currently
located in existing § 3174.11(c)(1) based
on feedback from operators and BLM
inspectors on the enforceability of the
existing regulation. Existing
§ 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
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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 °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 § 3174.152(b) reproduces
the requirement of current
§ 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 § 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
§ 3174.152(c) would incorporate all the
language from current § 3174.11(c)(3),
and would expand on the allowable
runs for a meter proving. The BLM
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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 §§ 3174.152(d), (e), (f), and
(g) would incorporate all the language
from existing §§ 3174.11(c)(4), (5), (7),
and (8) for meter factor computations
and acceptable meter factors ranges.
Proposed § 3174.152(h) would
incorporate the language from existing
§ 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 § 3174.152(i) would
combine and expand on the language
found in existing § 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 backpressure 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 backpressure systems, which would resolve
confusion concerning back-pressurevalve 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
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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 fixedsetting 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
§ 3174.11(d). This proposed section
would essentially retain the current
requirements of existing § 3174.11(d),
with the two following modifications.
Under existing § 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 § 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 § 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
§ 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:
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‘‘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 § 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 § 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 § 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 § 3174.11(c)(1). Proposed
§ 3174.152(a) would refine this normal
range criteria (as discussed in the
§ 3174.152(a) preamble section). The
proposed changes to the normal
condition would eliminate excessive
meter-factor deviation caused by
changing conditions because proposed
§ 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 § 3174.154(b) uses language
that is combined from existing
§ 3174.11(e)(1) and (3). This proposed
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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 § 3174.154(c) reflects
existing § 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
§ 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 § 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 § 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 § 3174.11(i) contains meterproving 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
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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
§ 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 provingreport formats.
Proposed § 3174.158(a) would retain
the data requirements listed in existing
§ 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
§ 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 meterfactor calculations are done correctly.
Proposed § 3174.158(b) would retain
the data requirements listed in existing
§ 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 § 3174.158(c) would change
the proving-report submission
requirements of existing § 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 §§ 3174.160–162 would
replace the measurement ticket
requirements contained in existing
§ 3174.12. Proposed § 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
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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 § 3174.161, the tankgauging 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 § 3174.161(a) would replace
parts of existing § 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 § 3174.12(a)
and with the additional requirement
that operators document the FMP
location information as required under
§ 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 § 3174.161(b) would replace
parts of existing § 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 °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
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60 °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 § 3174.162 would
reorganize the required information into
two categories—measurement tickets
and volume statements. Existing
§ 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 § 3174.162(a) would retain
the existing measurement-ticket
requirements in § 3174.12(b) and
introduce two additional requirements.
The proposed rule would require in
§ 3174.162(a)(1) the location
information found in § 3170.50(g) be
documented and would require in
§ 3174.162(a)(11) the net standard
volume be calculated and documented.
Proposed § 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 § 3170.50(g).
Proposed § 3174.162(c) would retain
the existing requirements in
§ 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
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timeframe that would apply to this
requirement.
3174.170 Oil Measurement by Other
Methods
Oil measurement by other methods is
currently addressed in existing
§ 3174.13. Most of the content of
existing § 3174.13 is proposed to be
moved to § 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
§ 3174.13(a) language about prior BLM
approval has been modified and
retained in proposed § 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 § 3174.14. This
section addresses how spilled oil, waste
oil, and slop oil must be reported to the
AO. Existing § 3174.14 says an operator
may not sell or otherwise dispose of
slop oil without prior written approval.
Proposed § 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 § 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 § 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
§ 3174.7(e)(1), requiring the 72-hour
notification, would be revised under
proposed § 3174.90(e) so that the
notification would be required within
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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 § 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
Existing § 3175
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Definitions and Acronyms
Proposed § 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
§ 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 § 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
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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 § 3175
numbering to the current subpart 3175
numbering. New proposed sections have
‘‘New’’ identified in the existing § 3175
column.
Proposed § 3175
3175.10 Definitions and acronyms ...........................................................
3175.20 General requirements ..............................................................
3175.30 Incorporation by reference (IBR) .............................................
3175.31 Specific measurement performance requirements ..................
3175.40, 3175.43, 3175.44, 3175.46 through 3175.49 ............................
3175.41, 3175.42, 3175.45 ......................................................................
New ...........................................................................................................
3175.61 Grandfathering .........................................................................
3175.60 Timeframes for compliance .....................................................
3175.70 Measurement location ..............................................................
3175.80 Flange-tapped orifice plates ....................................................
3175.90 through 3175.94 Mechanical recorders .....................................
3175.100 through 3175.104 Electronic gas measurement ......................
3175.110 through 3175.121 Gas sampling and analysis ........................
3175.125 Calculation of heating value and volume ..............................
3175.126 Reporting of heating value and volume .................................
3175.130 through 3175.135 Transducer testing protocol (removed) ......
3175.140 through 3175.144 Flow computer software testing (removed)
3175.150 Immediate assessments ...........................................................
Appendix A—Atmospheric pressure ........................................................
New ...........................................................................................................
3175.10
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3175.10
3175.20
3175.30
3175.31
3175.40
3175.41
3175.43
3175.50
3175.60
3175.70
3175.80
3175.90
3175.100
3175.110
3175.125
3175.126
3175.130
3175.140
3175.150
Appendix
Appendix
Definitions and acronyms.
General requirements.
Incorporation by reference (IBR).
Specific measurement performance requirements.
Measurement equipment requiring BLM approval.
Approved measurement equipment.
Data submission and notification requirements.
Grandfathering.
Timeframes for compliance.
Measurement location.
Flange-tapped orifice plate.
through 3175.94 Mechanical recorders.
through 3175.104 Electronic gas measurement.
through 3175.121 Gas sampling and analysis.
Calculation of heating value and volume.
Reporting of heating value and volume.
Requirements for GSAMPs.
Temporary Measurement.
Immediate assessments.
A—Atmospheric pressure.
B—Maximum time between events.
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 § 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-storageagreement 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 gasstorage purposes. The proposed
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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 gasstorage 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 gasstorage 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
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meter measuring the gas in this case
would be considered a GSAMP until the
amount of native gas on which the prepaid 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 1day 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
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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
§ 3175.103 in both the existing and
proposed rules, and in the
grandfathered flow-rate calculations
defined in proposed § 3175.50(2)(c)(i)
(existing § 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 § 3175.20 would be modified
to reflect the new section numbering of
the proposed regulation. Proposed
§ 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 § 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
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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
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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, squareedge, 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 flangetapped, 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
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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
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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 § 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
§ 3175.40. See the discussion of the
PMT review process under § 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.
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3175.31 Specific Performance
Requirements
Existing § 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 § 3175.31 (a) establishes
flow-rate uncertainty limits for highand very-high-volume FMPs. There are
no uncertainty limits for low- and verylow-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 § 3175.31(b)(1) would
increase the allowable uncertainty in
average annual heating value for highvolume 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 § 3175.31(b)(2) to 2
percent. The average annual heating
value uncertainty is a measure of how
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 § 3175.115(b), which
requires the operator to adjust the
sampling frequency of high- or veryhigh-volume FMPs to achieve the levels
of average annual heating value
uncertainty required under § 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
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well a 12-month average of heating
values, as determined from spot
samples, compares to a hypothetical 12month 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 § 3175.31(b)(4))
which defines the relationship between
the number of samples taken over a year
(N), the average annual heating value
uncertainty
and heating value variability from
sample to sample (V95%).
proposed heating value uncertainty
limits.
Existing § 3175.31(b) establishes
heating value uncertainty limits for
high- and very-high-volume FMPs.
There are no uncertainty limits for lowand 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 § 3175.40, as well as make a
number of changes to the requirements.
Existing § 3175.40 lists the types of
equipment that are allowed for use at
FMPs. Some of this equipment,
including flange-tapped orifice plates
(existing § 3175.41), chart recorders
(existing § 3175.42, for low- and verylow-volume FMPs only), and gas
chromatographs (existing § 3175.45) are
automatically approved with no
additional review required. Other
equipment—including transducers
(existing § 3175.43), flow-computer
software (existing § 3175.44), flow
conditioners (existing § 3175.46),
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• 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.
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Federal Register / Vol. 85, No. 176 / Thursday, September 10, 2020 / Proposed Rules
differential meters other than flangetapped orifice plates (existing
§ 3175.47), linear meters (existing
§ 3175.48), and accounting systems
(existing § 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
§ 3175.40 and the equipment
automatically approved would be
grouped under revised § 3175.41 (see
discussion under § 3175.41). All
discussion regarding the testing and
PMT review process under existing
§ 3175.43 through § 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
(§§ 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 § 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 § 3175.48 addresses all types
of linear gas meters. Under proposed
§ 3175.40, linear meters would be listed
as Coriolis meters (§ 3175.40(e)) and
ultrasonic meters (§ 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 § 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
§ 3175.40(g), which would address
software used to capture and process
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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
§ 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 watervapor 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 § 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.
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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 § 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
§ 3175.40(i), which would address
measurement data systems. Under
existing § 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
§ 3175.31.
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Federal Register / Vol. 85, No. 176 / Thursday, September 10, 2020 / Proposed Rules
3175.41 Approved Measurement
Equipment
The proposed rule would modify
§ 3175.41, to place all approved
measurement equipment in a single
section of the regulation. This
consolidation would replace the
existing § 3175.40, § 3175.41, § 3175.42,
§ 3175.43, § 3175.44, and § 3175.45.
3175.43 Data Submission and
Notification Requirements
Under proposed § 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.
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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
§ 3175.61, and relocate it to § 3175.50.
Under the existing regulations
(§§ 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 § 3175.60(a)(4) for
equipment installed on or before
January 17, 2017, and under
§ 3175.60(b)(2)(i) for equipment
installed after January 17, 2017. The
implementation of § 3175.40 was further
delayed by practical necessity (see BLM
Instruction Memorandum 2018–077).
The proposed new grandfathering
section (§ 3175.50(a)) would exempt all
equipment covered by § 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 BLMapproval 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 veryhigh-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
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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
§ 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 highvolume 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 § 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
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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 (§§ 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 § 3175.50(b)(1) would
clarify § 3175.61(a) of the existing
regulation. Both the existing and
proposed regulations grandfather certain
aspects of meter tubes installed at lowand 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
§ 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
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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 noncompliant meter tube with one that
complies with current industry
standards is significant, especially
considering that current industry metertube 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 § 3175.50(b)(2) would
expand on current § 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 § 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 § 3175.91(d)(7),
§ 3175.92(d)(2), § 3175.93(d),
§ 3175.101(c)(5), § 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 § 3175.50(c)(2)(i) would fix
two typographical errors in existing
§ 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
§ 3175.50(c)(2)(ii) keeps the current
language in existing § 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 highand very-high-volume FMPs had to
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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-lowvolume 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 § 3175.120(e) and
(f) of existing regulations). Under
existing §§ 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 §§ 3175.43 and 3175.44,
and §§ 3175.46 through 3175.49 of the
existing regulations. Under existing
regulations (see §§ 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
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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 2year 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 § 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 § 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 § 3175.80
define the requirements for orifice
metering of gas. The proposed rule seeks
to improve § 3175.80 based on feedback
from BLM field offices. The
introductory language in this section
would be changed to reference the
proposed § 3175.50 grandfathering
requirements.
With proposed § 3175.80(a), the BLM
would replace existing paragraph (a)
(which will become § 3175.80(c) of the
proposed rule) with new language that
would clarify a requirement in existing
Table 1 to § 3175.80. The first entry
(‘‘Fluid conditions’’) in Table 1 to
§ 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
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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 § 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 § 3175.80(b), the BLM
would replace existing paragraph (b)
(which would become § 3175.80(d) of
the proposed rule) with new language
that would clarify a requirement in
existing Table 1 to § 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 § 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 § 3175.80(f) would modify
the specific guidelines for maximum
time between inspections in existing
§ 3175.80(d). Under this proposed rule,
the BLM would move Table 1 to
§ 3175.115 to Appendix B of this
subpart, and add a reference to
Appendix B in proposed § 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 § 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-
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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
§ 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 § 3175.80(k).
Proposed § 3175.80(k) would change
the basic meter-tube inspection
frequencies from those required under
existing § 3175.80(h). Currently,
operators must perform a basic metertube inspection every year at very-highvolume FMPs, every 2 years at highvolume FMPs, and every 5 years at lowvolume 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 reexamined 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 veryhigh-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 § 3175.80(j))
and would change the name of the basic
meter-tube inspection to ‘‘routine’’ basic
meter-tube inspection.
Based on industry experience, metertube 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,
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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 § 3175.80(k)(3) based on
industry concerns. Under existing
§ 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
§ 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
§ 3175.61(a), if the meter tube is
grandfathered under existing
§ 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
§ 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 metertube inspection, performing a detailed
inspection under existing
§ 3175.80(i)(1)(ii) would provide no
value and the removal of the obstruction
would return the meter to normal
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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 § 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-highvolume 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-highvolume FMP. Proposed paragraph (iii) is
essentially the same as the current
requirement in existing § 3175.80(i).
New paragraph (iv) of proposed
§ 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 § 3175.80(i)(1)(iii).
Proposed § 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 § 3175.80(l)(2), the
BLM would modify the requirement in
existing § 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
§ 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 § 3175.80(p), the
BLM would move the requirements for
the sampling-probe location in the
meter tube. All three of these
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requirements are listed in existing
§ 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
§ 3175.112(b) to proposed § 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
§ 3175.112(b)(1), the BLM would
remove the restatement of the sample
probe requirements and replace it with
a cross reference to § 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 § 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 § 3175.91(a)(1) would revise
the language in the existing regulation
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in order to separate the guidelines for
gauge lines and manifold valves. The
change would dedicate § 3175.91(a)(1)
to gauge lines and create a new section
for valves and manifolds,
§ 3175.91(a)(2).
Proposed § 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 3⁄8inch 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 § 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
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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 flowrate 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 § 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
§ 3175.10 earlier, the reference inside
diameter is required for proper flow rate
calculation. Under § 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 § 3175.92
define the verification and calibration
requirements for mechanical recorders.
Proposed § 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
§ 3175.92(b)(2) would clarify the
timeframe requirements of Table 1 of
this subpart, and add a reference to
Appendix B in § 3175.92(b)(2). See the
discussion of Appendix B, later.
Proposed § 3175.92(b)(3) would delay
routine verification for an FMP in nonflowing status. This section would
require the verification to be conducted
within 15 days after the flow is reinitiated. Under this section, nonflowing 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
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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 § 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 § 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 § 3175.92(e)(2) would
modify the wording in the time frame
for notifying the BLM of a routine
verification. Under existing
§ 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
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should witness. The BLM would then
contact the operator to determine
exactly when the operator would verify
a given FMP.
Proposed § 3175.92(f) would clarify
the threshold that triggers the
requirement to submit amended OGOR
and royalty reports to ONRR. Under
existing § 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 § 3175.93
contain the documentation
requirements for integration statements.
Proposed § 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 § 3175.100
provide an overview of the regulatory
requirements of EGM systems based on
FMP tier. Proposed Table 1 to proposed
§ 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
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§ 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 § 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 § 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
§ 3175.101(a), the section would be reorganized to separate out requirements
that are specific to gauge lines and
requirements that are specific to
manifold ports and valves (see proposed
§ 3175.101(a)(2)). The requirements for
both gauge lines and manifold ports and
valves are combined under existing
§ 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 § 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 § 3175.91(a)(2).
Proposed new § 3175.101(b)(4) would
modify the existing requirement that
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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 § 3175.101(b)(6) would
modify a provision in § 3175.101(b)(5)
of the existing regulation that requires
operators to either display previousperiod 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
§ 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
§ 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
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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 § 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 § 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 § 3175.101(c)(12) would
clarify the requirement to maintain on
site the date of the last primary-device
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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 § 3175.10. The intent of the
requirement was to post the last orificeplate 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 § 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
§ 3175.80(l) and (m). The operator
would post either the last basic metertube 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 § 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 § 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
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±0.06 psi would make compliant
barometers more accessible without
adding significant uncertainty to the
overall measurement.
Proposed new § 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 § 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 § 3175.92(b)(3).
The BLM is proposing to remove the
requirement of existing § 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
§ 3175.130 was originally proposed in
October 2015, the BLM would have
required that operators perform a longterm 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
§ 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
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number of assumptions, which exceeds
the BLM’s current capacity.
Proposed § 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 § 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 72hour 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 § 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
§ 3175.92(e)(2). Under § 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 § 3175.102(g) would clarify
the threshold that triggers the
requirement for operators to submit
amended OGOR and royalty reports to
ONRR. Under § 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
§ 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 § 3175.92(f).
3175.103 Flow Rate, Volume, and
Average Value Calculation
Existing and proposed § 3175.103
provides the minimum requirements for
performing flow-rate, volume, and
average-value calculations. The
proposed rule would simplify some of
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the language in this section to reduce
confusion. Proposed § 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 § 3175.94(b) and other
sections of this rule that require the use
of atmospheric pressure.
3175.104 Logs and Records
Existing § 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 § 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
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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 § 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 § 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 § 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 § 3175.113 establishes the
general requirements for spot sampling.
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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 § 3175.113(a)(1) would
modify the wording of existing
§ 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 § 3175.113(a)(2) would
modify the wording of existing
§ 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 intermittentflowing 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 lowvolume 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 § 3175.113(a)(1) requires
FMPs to be flowing when a sample is
taken. The intent of proposed
§ 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 § 3175.113(b),
operators must notify the AO at least 72
hours before taking a sample or submit
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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 § 3175.113(c)(3) would
modify the language in existing
§ 3175.113(c)(3) by updating the GPA
reference from GPA 2166–05 to GPA
2166–17. Under proposed § 3175.30, the
BLM would incorporate GPA 2166–17,
which is the latest published version of
the standard.
Proposed § 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 samplecylinder 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 § 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
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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 § 3175.113(d)(5) and
(d)(6) of the existing regulations and
replace them with different
requirements (§ 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
§ 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 § 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
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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 §§ 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 § 3175(d)(5) and
(d)(6) can be met using the methods in
proposed § 3175(d)(5) through (d)(8).
Proposed § 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 °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 § 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 § 3175.113(d)(5) is similar to
existing § 3175.112(c)(2), which requires
external regulators that are part of the
sample probe to be heated to 30 °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 § 3175.112(c)(2) is the same as
the rationale for this proposed
requirement.
Proposed § 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
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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 § 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 § 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.
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3175.114 Spot Samples—Allowable
Methods
Existing § 3175.114 defines the
allowable methods for spot sampling.
The proposed rule would update the
references to industry standard to make
them current. Proposed § 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
§ 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 § 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
§ 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-highvolume FMPs to achieve a set level of
average annual heating value
uncertainty as described in existing
§ 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
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samplers or on-line GCs at very-highvolume 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 veryhigh-volume FMPs and from + or ¥2
percent to + or ¥3 percent for highvolume FMPs (see earlier discussion of
§ 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-highvolume FMPs (see discussion of
§ 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
§ 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 lowervolume FMPs that are associated with
plunger-lift operations. Very-highvolume 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
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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 § 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 § 3175.31(b)(2),
the BLM estimates the number of veryhigh-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 § 3175.115(c) would move
the existing Table 1 to § 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 § 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 § 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
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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 § 3175.116(c) would add a
requirement that sample cylinders used
in composite sampling systems comply
with the general spot-sample
requirements under § 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 § 3175.116(d) would add a
new requirement that all components of
the sampling system be heated to at
least 30 °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 JouleThompson effect as pressure is reduced
when the gas runs through valves and
fittings.
3175.117 On-Line Gas
Chromatographs
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Proposed § 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 § 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
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confusion between the terms ‘‘extended
analysis’’ and ‘‘nonanes+’’.
Proposed § 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 °F above the hydrocarbon dew point
for 4 hours before use. The older
standard recommends that the
calibration gas should be heated to 20 °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 § 3175.118(c)(3) and
§ 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 § 3175.118(e) operators
are required to perform extended
analyses in accordance with GPA 2286–
14. This proposed rule would remove
this requirement. Existing § 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
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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
§ 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 § 3175.10 and at
§ 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 § 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 § 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
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Proposed § 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.
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.
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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.
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The following table summarizes the
results from the three plots:
Concentration of C6+
(mole percent)
Total samples ..............................................................................................................................
Average difference (Btu/scf) ........................................................................................................
Median difference (Btu/scf) ..........................................................................................................
Maximum heating value difference ..............................................................................................
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.
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The absence of statistically significant
bias is one of the performance goals of
§ 3175.31(c)
However, both the average and
median difference between the heating
values in a C6+ analysis and C9+
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¥0.43
0
¥4
0.5–1.0
(plot 2)
724
¥0.87
¥1
¥6
>1.0
(plot 3)
95
¥2.66
¥2
¥14
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
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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 highvolume FMPs and 180 days for veryhigh-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
§ 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.
Based on this analysis, the BLM
believes that a threshold of 1 mole
percent C6+ would exceed the breakeven 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.
this requirement would not be
applicable to them.
Proposed § 3175.120(a)(18) would
remove the requirement that the gas
analysis report must show the unnormalized 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 unnormalized percent to be within 97
percent to 103 percent. A total unnormalized 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 § 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
§ 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.
3175.120 Gas Analysis Report
Requirements
Proposed § 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,
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3175.125 Calculation of Heating Value
and Volume
Existing § 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
§ 3175.125(b)(1), the existing
requirement for calculating and
reporting an average heating value
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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 § 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
§ 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 § 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
§ 3175.126(a)(1)(ii), the BLM would
apply the same requirements to
automated chilled mirrors, for the same
reasons.
Existing § 3175.126(a)(1)(ii) lists laser
detectors as an approved method of
measuring water vapor. Under the
proposed rule, laser detectors would no
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longer be an approved method, but
operators could submit individual laser
detector makes and models to the BLM
for review and approval under revised
§ 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
§ 3175.40(h) earlier).
Proposed § 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 § 3175.126(a)(3) would
change ‘‘hexane+’’ to ‘‘hexane-plus’’ for
consistent wording with the rest of the
regulation. Under existing
§ 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
§ 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
§ 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 § 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 § 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
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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 § 3175.10, the BLM
would also include requirements for
these meters in proposed § 3175.130.
Paragraph 3175.130(a) would redefine 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 renegotiated 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 renegotiated 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-lowvolume GSAMPs. The equivalent
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threshold between a low- and highvolume 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).
Proposed § 3175.130(b) would exempt
GSAMPs from the gas-sampling,
analysis, and heating-value reporting
requirements of § 3175.80(p),
§ 3175.110, § 3175.120, § 3175.121,
§ 3175.125(a) and (b), and § 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 gasstorage 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 § 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.
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3175.140
Federal Register / Vol. 85, No. 176 / Thursday, September 10, 2020 / Proposed Rules
Temporary Measurement
The BLM is proposing to add a new
section under § 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 § 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 flowcomputer 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 oilmeasurement 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.
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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 § 3175.92(a), and the
second is for failure to conduct a routine
mechanical recorder verification as
required under § 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-
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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 § 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
§ 3175.115, which establishes the
maximum time between samples for a
given monthly frequency. For example,
under Table 1 to § 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 3month 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 § 3175.115 for these activities. To
address this issue, the BLM proposes to
move Table 1 to § 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://
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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
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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 onetime savings over 3 years);
Category 8. Orifice-Plate and MeterTube Inspections
Reducing the frequency of basic and
detailed metering-tube inspections
required for low-volume (LV) FMPs
under § 3175.80(j) and § 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 highvolume (HV) FMPs, and from once
every year to once every 5 years for VHV
FMPs ($2.1 million saved per year);
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Category 2. Sampling Requirements
Removing annual spot-sampling
requirements for very-low volume (VLV)
and LV FMPs that are actually GSAMPs
under § 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 § 3175.102(b)
($1.1 million saved per year);
Category 14. EGM Requirements for
Logs and Calculations
Removing under § 3175.104(a)(2) the
requirement that HV and VHV FMPs
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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 § 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 (§ 3174.43(a)(2),
and § 3174.90(e)), temperature averaging
device (§ 3174.105), pressure averaging
device (§ 3174.106(a)), flow computer
software (§ 3174.120(a)), and
measurement data system
(§ 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
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55995
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
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$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 foreignbased 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
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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
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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-togovernment 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.
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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
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
55997
by this proposed rule. For the existing
requirements unchanged by the
proposed rule, we used the existing
OMB-approved estimated hour and nonhour 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
responses and burdens
Proposed rule
responses and burdens
Changes in
responses and burdens
OMB control No.
Number of
responses
1004–0137
1004–0207
1004–0209
1004–0210
Number of
burden hours
Number of
responses
Number of
burden hours
Change in
responses
Change in
burden hours
...............................................
...............................................
...............................................
...............................................
301,663
93,975
11,742
430,782
1,835,888
69,640
5,884
95,068
222,919
89,045
1,382
246,726
1,772,543
59,740
5,166
66,507
(78,744)
(4,930)
(10,360)
(184,056)
(63,345)
(9,900)
(718)
(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
nonhour cost burdens
OMB control No.
khammond on DSKJM1Z7X2PROD with PROPOSALS2
1004–0137
1004–0207
1004–0209
1004–0210
Proposed rule
nonhour cost burdens
Changes in
nonhour cost burdens
...........................................................
...........................................................
...........................................................
...........................................................
$29,370,000
0
5,580,305
24,600,894
$29,370,000
0
4,070,305
10,996,945
0
0
($1,510,000)
(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
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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
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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
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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).
khammond on DSKJM1Z7X2PROD with PROPOSALS2
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
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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 § 3173.31 would revise
and replace two IC activities previously
approved for § 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 nonhour 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
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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),
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• 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
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• 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:
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55999
• 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 (OneTime), 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 (OneTime), 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 (OneTime), 43 CFR 3175.47, (¥240 annual
burden hours)
• Linear Measurement Devices—Test
Data Collection and Submission for
Existing Makes and Models (OneTime), 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
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khammond on DSKJM1Z7X2PROD with PROPOSALS2
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.
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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 § 3170.30, Alternative
measurement equipment and
procedures. Proposed § 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 § 3170.40, Variances (Form
3160–5). Existing § 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 § 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 § 3173.50, Site facility
diagram (Form 3160–5). Existing
§ 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 § 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.
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Proposed § 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 colocated facility(ies).
Proposed § 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 § 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 § 3173.60, Applying for a
facility measurement point number
(Form 3160–5). Existing § 3173.12
requires operators to obtain BLM
approval of facility measurement points
(FMPs). Existing § 3173.12(d) applies to
permanent measurement facilities that
come into service after January 17, 2017.
Existing § 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
§ 3173.60(d), is proposing to remove the
requirement that operators list the
‘‘station number, primary element
(meter tube) size or serial number, and
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type of secondary device (mechanical or
electronic)’’ and replace it with a
requirement that operators provide ‘‘the
unique meter ID, and elevation.’’
Proposed § 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 § 3173.70, Conditions for
commingling and allocation approval
(surface and downhole); and Proposed
§ 3173.71, Applying for commingling
and allocation approval (Form 3160–5).
Existing § 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 § 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 § 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 BLMmanaged 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 applicantcertified statement that it already has a
right-of-way grant for Federal rights-ofway.
The proposed rule would require that
gas CAA applications be submitted
separately from oil CAA applications.
Proposed § 3173.74, Modification of a
commingling and allocation approval
(Form 3160–5). Proposed § 3173.74(b)
would add another condition that
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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 § 3173.91, Applying for offlease measurement. Proposed § 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 offlease measurement for each oil and gas
FMP.
Proposed § 3174.43, Data Submission
and notification requirements (Form
3160–5). Proposed § 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
§ 3174.82);
• Notification of LACT System
Failure (Annual) (Proposed § 3174.90);
and
• Approval for Slop or Waste Oil
(Annual) (Proposed § 3174.180).
In addition, proposed § 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 § 3174.60, Timeframes for
compliance. In addition, proposed
§ 3174.60(b)(3) would include Sundry
Notices in another new IC activity, i.e.,
‘‘Notification of Early Compliance.’’
Proposed § 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 § 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 tankcapacity 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
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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 § 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 § 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 § 3174.120, Electronic
liquids measurement, ELM (secondary
and tertiary device). The IC
requirements at proposed § 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 § 3174.154, Excessive meter
factor deviation. The proposed rule
would allow the operator to provide a
statement explaining that the excessive-
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meter factor was not caused by a meter
malfunction on a case-by-case basis.
Proposed § 3174.160–3174.162
Measurement tickets. The proposed rule
would separate out the measurementticket requirement into individual
sections according to the measurement
type. Measurement types would include
tank gauging and LACT or CMS.
Proposed § 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.
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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 § 3170.50, Required
Recordkeeping, Records Retention, and
Records Submission. Proposed
§ 3170.50(g) would revise the IC activity
previously approved for § 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 § 3173.31, Water-Draining
Operations—Gauging. Proposed
§ 3173.31 would revise and replace two
IC activities previously approved for
§ 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 § 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.
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Proposal That Would Affect Both
Control Number 1004–0209 and Control
Number 1004–0210
Alternative Measurement Equipment
and Procedures. Proposed § 3170.30
would pertain to requests to use
‘‘alternative measurement equipment
and procedures.’’ Proposed § 3170.30
would apply to both oil and gas
measurement, and would replace the
procedures described in current
§ 3174.13, which applies only to the
measurement of oil. Proposed § 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 § 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 § 3174.60, Timeframes for
compliance. Proposed § 3174.60 would
include deadlines that would be onetime 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 § 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 § 3174.83, Tank gauging—
procedures. During field operations,
operators must obtain and document
data required under Proposed
§ 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 § 3174.90, LACT systems—
general requirements. Requirements
related to § 3174.7, LACT systems,
would be removed from this control
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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 § 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 § 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 § 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 § 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 § 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
§ 3174.105(a), a stand-alone
temperature-averaging device would
require PMT review and BLM approval.
Similarly, under proposed
§ 3174.105(b), a temperature transducer
must have received BLM approval.
Proposed § 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
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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 § 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
§ 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 § 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 § 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 § 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 § 3174.140, Temporary
measurement. The BLM is proposing to
add a new § 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
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limited timeframe the meter will be on
the location (for example, proving
requirements).
Proposed § 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 § 3174.158(c) would change
the proving-report submission
requirements of existing § 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 § 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 § 3175.40, Measurement
equipment. The proposed rule would
revise and replace some of these
provisions pertaining to gasmeasurement equipment. The BLM is
proposing these changes in order to
streamline and better organize the
regulations. Proposed § 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
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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 FlangeTapped 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 § 3175.41, Approved
measurement equipment. Proposed
§ 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 § 3175.41);
• Chart recorders for low- and verylow-volume FMPs (existing § 3175.42);
and
• Gas chromatographs (existing
§ 3175.45).
In addition, proposed § 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
§§ 3175.43 and 3175.130); and
• Flow-computer software, when
used at low- and very-low volume FMPs
(existing §§ 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 § 3175.41
would reduce the number of makes and
model of transducers and flowcomputer 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
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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 § 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 § 3175.80, Flange-tapped
orifice plate (primary device). Proposed
§ 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 § 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-highvolume 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 § 3175.80(k) would require
operators to perform a basic meter-tube
inspection every 5 years at both high-
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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 metertube inspection for high- and very-highvolume FMPs.
Under proposed § 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 § 3175.92, Verification and
calibration of mechanical recorders.
Proposed § 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 § 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 72hours’ 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 § 3175.101, Installation and
operation of electronic gas measurement
systems. Existing and proposed
§ 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 § 3175.101(b)(4) would
modify the existing requirement that
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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 § 3175.101(b)(6) would
modify a provision that requires
operators to either display previousperiod 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 § 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 § 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
§ 3175.80(l) and (m). The operator
would post either the last basic metertube inspection date or the last detailed
meter-tube inspection date, whichever
is more recent.
Proposed § 3175.102, Verification and
calibration of electronic gas
measurement system. Existing and
proposed § 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 § 3175.104, Logs and
records. Existing § 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
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allow for the use of existing equipment
while preserving accountability
requirements.
Proposed § 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 § 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 § 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 § 3175.113(d)(5) and
(d)(6) of the existing regulations and
replace them with different
requirements (§ 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 § 3175.115, Spot samples—
frequency. The BLM would delete
existing § 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 § 3175.115(d) would
increase the amount of time operators
would have to install a composite
sampling system or on-line GC from 30
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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 § 3175.116, Composite
sampling methods. Proposed
§ 3175.116(c) would add a requirement
that sample cylinders used in composite
sampling systems comply with the
general spot-sample requirements under
§ 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 § 3175.118, Gas
chromatograph requirements. Under
existing § 3175.118(e) operators are
required to perform extended analyses
in accordance with GPA 2286–14. This
proposed rule would remove this
requirement.
Proposed § 3175.120, Gas analysis
report requirements. Proposed
§ 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 § 3175.125, Calculation of
heating value and volume. Under
proposed § 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 § 3175.140, Temporary
measurement. The BLM is proposing to
add a new section under § 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
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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 § 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
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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.
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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
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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
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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
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.
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
§ 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,
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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.
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§ 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 BLMmanaged gas storage agreements.
§ 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
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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 § 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
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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 § 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
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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 quarterquarter section, section, township,
range, and principal meridian, or other
authorized survey designation
acceptable to the AO, such as metesand-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
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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 nonIndian 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 BLMcontracted 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.
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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:
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.
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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.
§ 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.
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§ 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
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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 § 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.
§ 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
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56009
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
§ 3170.30.
§ 3170.50 Required recordkeeping,
records retention, and records submission.
(a) Lessees, operators, purchasers,
transporters, and any other person
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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
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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.
§ 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.
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§ 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.
■ 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
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Subpart 3173—Requirements for Site
Security and Production Handling
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§ 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
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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.
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§ 3173.20
seals.
56011
Storage and sales facilities—
(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;
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(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.
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(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 §§ 3174.101 through
3174.108) and CMSs (see § 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.
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 oilmetering-system component that does
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§ 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
§ 3174.161(a) or § 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
§ 3174.161(a) or § 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.
§ 3173.31
§ 3173.21 Oil measurement system
components—seals.
§ 3173.22
not comply with the requirements in
§§ 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 §§ 3173.20 and 3173.21.
(c) A Federal seal may not be removed
without the approval of the AO or AR.
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 § 3173.41(b).
§ 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).
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(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.
§ 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.
§ 3173.41 Required recordkeeping for
inventory and seal records.
(a) The operator must perform an endof-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:
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{[(X + Y ¥ W) / Z1] * Z2} + 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} + 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.
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§ 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
§ 3173.50);
(2) Request for an FMP number (see
§ 3173.60);
(3) Request for FMP amendments (see
§ 3173.61(b));
(4) Requests for approval of off-lease
measurement (see § 3173.91);
(5) Request to amend an approval of
off-lease measurement (see
§ 3173.91(k));
(6) Requests for approval of CAAs (see
§ 3173.71); and
(7) Request to modify a CAA (see
§ 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
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(2) Does not have access to the
internet.
§ 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 81⁄2″ 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 colocated 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
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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.
§ 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
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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
§ 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
§ 3173.61.
(d) All requests for FMP number
approval must include the following:
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(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.
§ 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 § 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
§ 3173.50).
§ 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:
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(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.
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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 § 3174.31 or § 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 noncommingled 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.
§ 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
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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 § 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 § 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
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56015
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.
§ 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
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standards and requirements for a CAA
under § 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
§ 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
§ 3173.70 and the operator does not
correct the deficiencies, the AO may
terminate the existing CAA under
§ 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.
§ 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.
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§ 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.
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(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.
§ 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.
§ 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
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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
(§ 3173.12) or CAA (§ 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.
§ 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 §§ 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.
§ 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,
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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
§ 3173.12) may be filed concurrently
with the request for off-lease
measurement.
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§ 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
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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 offlease 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.
§ 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.
§ 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 offlease measurement approval under
§ 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
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56017
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 offlease measurement under § 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
§ 3173.90 and the operator does not
correct the deficiencies, the AO may
terminate the existing off-lease
measurement approval under § 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 § 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.
§ 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.
§ 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
§§ 3173.90 through 3173.94.
(b) The BLM will notify the operator
in writing of the effective date of the
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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.
§ 3173.96 Instances not constituting offlease 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
§§ 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 offlease 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.
§ 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 § 3173.190: VIOLATIONS SUBJECT TO AN IMMEDIATE ASSESSMENT
Assessment
amount per
violation:
Violation:
1. An appropriate valve on an oil storage tank was not effectively sealed, as required by § 3173.20 ..............................................
2. A Federal seal is removed without prior approval of the AO or AR, as required by § 3173.22 .....................................................
3. Oil was not properly measured before removal from storage for use on a different lease, unit, or CA, as required by
§ 3173.32(b) .....................................................................................................................................................................................
4. An FMP was bypassed, in violation of § 3170.22 ...........................................................................................................................
5. Theft or mishandling of production was not reported to the BLM, as required by § 3173.40 ........................................................
6. Records necessary to determine quantity and quality of production were not retained, as required by § 3170.32 ......................
7. FMP application was not submitted, as required by § 3173.60 ......................................................................................................
8. (i) For facilities that begin operation after [EFFECTIVE DATE OF FINAL RULE], BLM approval for off-lease measurement
was not obtained before removing production, as required by § 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 [EFFECTIVE DATE OF FINAL RULE], BLM approval for surface commingling was
not obtained before removing production, as required by § 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 [EFFECTIVE DATE OF FINAL RULE], BLM approval for downhole commingling
was not obtained before removing production, as required by § 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
$1,000
1,000
1,000
1,000
1,000
1,000
1,000
1,000
1,000
1,000
2. Diagrams
I. Diagrams
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1. Site Facility Diagrams and Sealing of
Valve Introduction
I–A
I–B
I–C
I–D
I–E
Diagrams
Appendix pages
.....................
.....................
.....................
.....................
.....................
1–1
1–2
1–3
1–6
1–9
I–F .....................
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...................
...................
thru 1–5 .....
and 1–8 .....
thru 1–12 ...
1–13 thru 1–16
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Description
Simple gas well without equipment.
Simple gas well with equipment.
Single operator with co-located facilities single oil tank, gas, and water storage.
Oil sales with multiple oil tanks, gas, and water storage.
Co-located facilities with multiple operators, oil sales by Lease Automatic Custody Transfer (LACT) system, gas, and water storage.
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.
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Diagrams
Appendix pages
I–G ....................
I–H .....................
I–I ......................
1–17 thru 1–19
1–20 thru 1–22
1–23 thru 1–25
Description
Enhanced recovery water injection or other water disposal facility.
Pod Facility.
Water recycle system with water disposal options by pipeline or truck.
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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
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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
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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
Subpart 3174—Measurement of Oil
4. Revise subpart 3174 to read as
follows:
Sec.
3174.10
3174.20
■
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Definitions and acronyms.
General requirements.
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3174.30 Incorporation by reference (IBR).
3174.31 Specific measurement performance
requirements.
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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.
§ 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
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(iii) Local atmospheric pressure for
static measurement.
Base temperature means 60 °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 BLMapproved 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
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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 nonresettable 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 tamperproof 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 mastermeter 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
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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
§ 3170.10 of this part.
COA has the meaning set forth in
§ 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
§ 3170.10 of this part.
PMT means Production Measurement
Team.
PSIA means pounds per square inch,
absolute.
S&W means sediment and water.
§ 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 fedreg.legal@nara.gov 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 https://
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
§ 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
§ 3174.20 General requirements.
approved for § 3174.82(a).
(a) Measurement of all oil at an FMP
(3) API MPMS Chapter 2—Tank
must comply with the standards
Calibration, Section 2C—Calibration of
prescribed in this subpart.
Upright Cylindrical Tanks Using the
(b) Oil may be stored only in tanks
Optical-triangulation Method; First
that meet the requirements of § 3174.80. Edition, January 2002; Reaffirmed, April
2013 (‘‘API 2.2C’’), IBR approved for
(c) An operator must obtain a BLM§ 3174.82(a).
approved FMP number under
§§ 3173.60 and 3173.61 of this part for
(4) API MPMS Chapter 3.1A, Standard
each oil measurement facility where the Practice for the Manual Gauging of
measurement affects the calculation of
Petroleum and Petroleum Products;
the volume or quality of production on
Third Edition, August 2013; Reaffirmed,
which royalty is owed (i.e., oil tank used December 2018 (‘‘API 3.1A’’), IBR
for tank gauging, LACT system, CMS, or approved for §§ 3174.80(f), 3174.88(a).
other approved metering device), except
(5) API MPMS Chapter 3—Tank
as provided in paragraph (d) of this
Gauging, Section 1B—Standard Practice
section.
for Level Measurement of Liquid
(d) Meters used for allocation under a Hydrocarbons in Stationary Tanks by
Automatic Tank Gauging; Third Edition,
commingling and allocation approval
under § 3173.70 are not required to meet April 2018 (‘‘API 3.1B’’), IBR approved
for § 3174.88(b).
the requirements of this subpart.
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(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 § 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
§ 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 §§ 3174.151(b), (d), and (e),
3174.152(b).
(9) API MPMS Chapter 4.5, MasterMeter Provers; Fourth Edition, June
2016 (‘‘API 4.5’’), IBR approved for
§ 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 § 3174.152(b).
(11) API MPMS Chapter 4.8,
Operation of Proving Systems; Second
Edition, September 2013 (‘‘API 4.8’’),
IBR approved for §§ 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 § 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 §§ 3174.130(e), 3174.157.
(14) API MPMS Chapter 7.1,
Temperature Determination—Liquid-inGlass Thermometers; Second Edition,
August 2017 (‘‘API 7.1’’), IBR approved
for § 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 § 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 § 3174.105(c).
(17) API MPMS Chapter 8.1, Standard
Practice for Manual Sampling of
Petroleum and Petroleum Products;
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Fourth Edition, October 2013 (‘‘API
8.1’’), IBR approved for §§ 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 §§ 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
§§ 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
§ 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 § 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 § 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
§ 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
§§ 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 § 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 §§ 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
§§ 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
§ 3174.151(c).
(29) API MPMS Chapter 13. 3,
Measurement Uncertainty; Second
Edition, December 2017 (‘‘API 13.3’’),
IBR approved for § 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 § 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 §§ 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
§§ 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 § 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
§ 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; https://
infostore.saiglobal.com/store/.
§ 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
§ 3174.30):
TABLE 1 TO § 3174.31(a)(1): VOLUME MEASUREMENT UNCERTAINTY LEVELS
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FMP category
Very-high-volume ............
High-volume ....................
Low-volume ....................
If the averaging
period volume
(see definition
43 CFR 3170.3) is:
The overall
volume measurement
uncertainty must
be within:
1. Greater than or equal to 15,000 bbl/month ...................
2. Greater than 1,500 but less than 15,000 bbl/month .....
3. Less than or equal to 1,500 bbl/month .........................
±0.50 percent
±1.50 percent
N/A
(2) A BLM State Director may grant an
exception to the uncertainty levels
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prescribed in paragraph (a)(1) of this
section, but only upon:
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(i) A showing that meeting the
required uncertainly level would
involve extraordinary cost or
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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.
§ 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.
khammond on DSKJM1Z7X2PROD with PROPOSALS2
§ 3174.41 Measurement equipment
requiring BLM approval.
Except as provided in § 3174.50, the
following equipment requires BLM
approval prior to use, and must appear
on the list of PMT-reviewed and BLMapproved equipment maintained at
www.blm.gov. BLM approval will be
based upon a showing that the
equipment meets or exceeds the
performance requirements of § 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
§ 3174.88(b)(1));
(b) LACT sampling systems (see
§ 3174.102);
(c) Positive displacement meters (see
§ 3174.104);
(d) Coriolis meters (see § 3174.104
and § 3174.110(a));
(e) Coriolis transmitters (see
§ 3174.104 and § 3174.110(b));
(f) Stand-alone temperature averaging
devices (see § 3174.105(a));
(g) Temperature transducers (see
§ 3174.105(b));
(h) Pressure transducers (see
§ 3174.106(a));
(i) Flow computers and installed
particular software versions (see
§ 3174.120(a));
(j) Portable electronic thermometers
(see § 3174.86(c));
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(k) Measurement data systems (see
§ 3174.121(a)); and
(l) Temporary measurement (see
§ 3174.140).
§ 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 § 3174.85);
(b) Liquid-in-glass thermometers (see
§ 3174.86);
(c) Hydrometers and
thermohydrometers (see § 3174.87); and
(d) Manual gauging tapes (see
§ 3174.88(a)).
§ 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
§ 3174.60(b)(3));
(2) FMP tank calibration charts (tank
tables) (see § 3174.82(d));
(3) Notification after repair of any
LACT system failures or equipment
malfunctions that may have resulted in
measurement error (see § 3174.90(e)(1));
(4) Justification for excessive meter
factor deviation (see § 3174.154(a));
(5) Prior AO approval to sell or
dispose of slop oil (see § 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
§ 3174.180(c)).
(b) Operators must submit the
following information to the BLM upon
request of the AO:
(1) ATG Field verification log (see
§ 3174.88(b)(4));
(2) Coriolis meter zero value
verification procedure (see
§ 3174.110(e));
(3) Log of all meter factors, zero
verifications, and zero adjustments (see
§ 3174.110(e));
(4) ELM Audit trail data including
QTR, configuration log, event log, and
alarm log (see § 3174.120(d));
(5) Meter proving report (see
§ 3174.158(c)); and
(6) Measurement tickets (see
§ 3174.160).
§ 3174.50
Grandfathering.
(a) The equipment listed in
§ 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 § 3174.41.
(b) For any high- or low-volume FMP,
if any of the equipment listed in
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§ 3174.41(a) through (i) is replaced after
[EFFECTIVE DATE OF FINAL RULE], it
is no longer exempt from the approval
requirement in § 3174.41.
(c) Any high- or low-volume FMP that
changes category and becomes a veryhigh-volume FMP is no longer exempt
from the approval requirements in
§ 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.
§ 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
§ 3174.41 will be required after [DATE
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TWO YEARS AFTER EFFECTIVE DATE
OF FINAL RULE].
§ 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
§§ 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
§§ 3173.90 and 3173.91 of this part.
§ 3174.80
Oil storage tank equipment.
khammond on DSKJM1Z7X2PROD with PROPOSALS2
(a) Each tank used for oil storage must
comply with the recommended
practices listed in API RP 12R1,
Subsection 4 (incorporated by reference,
see § 3174.30).
(b) Each oil storage tank must be
connected, maintained, and operated in
compliance with §§ 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 operatorgenerated 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 § 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.
§ 3174.81
gauging.
Oil measurement by tank
Oil measurement by tank gauging
must accurately compute the total net
standard volume of oil withdrawn from
a properly calibrated FMP tank by
following §§ 3174.82 through 3174.88
and 3174.31 to determine the quantity
and quality of oil being removed.
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§ 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 § 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 § 3174.87(a)(3);
(3) The tank capacity tables must be
calculated for a tank shell temperature
of 60 °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.
§ 3174.83
Tank-gauging procedures.
(a) The procedures for oil
measurement by tank gauging must
comply with the requirements outlined
in this section and §§ 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 § 3174.30).
(c) During field operations, operators
must obtain and document the data
required under § 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 § 3173.20 of this part.
(e) After transfer is complete, the
operator must close the tank valve and
seal the valve as required under
§§ 3173.20 and 3173.30 of this part.
§ 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
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56049
tanks (incorporated by reference, see
§ 3174.30).
§ 3174.85
Determining S&W content.
Using the oil samples obtained under
§ 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 § 3174.30).
§ 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 § 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 °F, and have
an accuracy of ±0.5 °F. Refer to API 7.1,
Subsection 6.1.1.3 (incorporated by
reference, see § 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 °F
and have an accuracy of ±0.5 °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 °F for glass thermometers or
0.1 °F for electronic thermometers.
§ 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
§ 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 °F.
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§ 3174.88
Federal Register / Vol. 85, No. 176 / Thursday, September 10, 2020 / Proposed Rules
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
§ 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
§ 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 § 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 § 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;
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(4) A detailed log of field verifications
must be maintained and available upon
request. The log must be in compliance
with § 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 § 3170.50(g) of this part, and
accessible to the AO at all times.
§ 3174.90 LACT system—general
requirements.
(a) A LACT system must meet the
construction and operation
requirements and minimum standards
of this section and §§ 3174.31 and
3174.100.
(b) A LACT system must be proven as
prescribed in § 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 § 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 §§ 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
§ 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
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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
§ 3174.30) and must be used to calculate
the CPL correction factor using API
11.1. (incorporated by reference, see
§ 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 § 3174.30) or any other BLMapproved methods.
(j) Measurement tickets must be
completed under § 3174.162.
§ 3174.100 LACT system—components
and operating requirements.
Unless otherwise approved, each
LACT system must include all of the
equipment listed in §§ 3174.101 through
3174.108 and LACT operation must
meet the requirements of §§ 3174.101
through 3174.108.
§ 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.
§ 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 § 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
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composite sample container) into a
homogeneous mixture before and during
the withdrawal of a portion of the
sample for testing.
§ 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.
§ 3174.104
LACT meter.
The LACT meter must be a positive
displacement meter, a Coriolis meter
(see § 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 nonresettable 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.
khammond on DSKJM1Z7X2PROD with PROPOSALS2
§ 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 § 3174.30);
(d) The temperature averaging device
must have a reference accuracy of ±0.5
°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 § 3174.30);
(e) The electronic temperature
averaging device must be volumeweighted and take a temperature
reading following API 21.2, Subsection
9.2.8 (incorporated by reference, see
§ 3174.30); and
(f) The temperature averaging device
must include a display of instantaneous
temperature and the average
temperature calculated since the
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measurement ticket was opened. The
display may be a function of an
electronic flow computer.
§ 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 pressureindicating 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
§ 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
§ 3174.30).
§ 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.
§ 3174.108
valves.
Back-pressure and check
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-
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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.
§ 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
§ 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:
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Subsection 10 (incorporated by
reference, see § 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 § 3174.162.
§ 3174.120 Electronic liquids measurement
(2) Configuration log: The
system, ELM (secondary and tertiary
configuration log must comply with the
device).
requirements of API 21.2, Subsection
Any FMP with an ELM installed must
10.2 (incorporated by reference, see
comply with the requirements of this
§ 3174.30). The configuration log must
section. An ELM is required on all verycontain and identify all constant flow
high-volume FMPs, and all CMS
parameters used in generating the QTR.
regardless of FMP category.
(3) Event log: The event log must
(a) The specific makes and models of
comply
with the requirements of API
flow computers and software versions
21.2, Subsection 10.6 (incorporated by
that are identified and described at
reference, see § 3174.30). In addition,
www.blm.gov are approved for use.
the event log must be of sufficient
(b) For each ELM, the following
capacity to record all events such that
values and corresponding units of
the operator can retain the information
measurement must be displayed:
under the recordkeeping requirements
(1) The instantaneous density of
of § 3170.50(g) of this part.
liquid (pounds/bbl, pounds/gal, or
(4) Alarm log: The type and duration
degrees API);
of any of the following alarm conditions
(2) The instantaneous indicated
must be recorded:
volumetric flow rate through the meter
(i) Deviations from acceptable density
(bbl/day);
parameters
for Coriolis flow meters;
(3) The meter factor;
(ii) Instances in which the flow rate
(4) The instantaneous pressure (psi);
exceeded the manufacturer’s maximum
(5) The instantaneous temperature
recommended flow rate or was below
(°F);
the manufacturer’s minimum
(6) The average temperature
calculated since the measurement ticket recommended flow rate;
(iii) Instances in which the
was opened;
temperature of the fluid exceeded the
(7) The cumulative indicated volume
calibrated span of the temperature
through the meter (non-resettable
transmitter;
totalizer) (bbl); and
(iv) Instances in which the pressure of
(8) The previous day’s indicated
the fluid exceeded the calibrated span of
volume through the meter (bbl).
(c) The following information must be the pressure transmitter;
(v) Any power loss to the meter or
correct, must be maintained in a legible
condition, and must be accessible to the instance in which the ELM no longer
detects the meter output; and
AO at the FMP without the use of data(vi) Instances in which any other
collection equipment, laptop computers,
meter output exceeds its user-defined
or any special equipment:
(1) The make, model, and size of each span of operation.
(5) The alarm log may be part of the
sensor; and
event log and fulfill the requirements of
(2) The make, model, range, and
this subpart, as long as protections are
calibrated span of the pressure and
in place to ensure that excessive
temperature transducer used to
alarming will not affect the event log’s
determine gross standard volume.
compliance with the record-keeping
(d) Calculated volumetric output of
requirements of this subpart.
the ELM must incorporate the meter
(f) Each ELM must have installed and
factor and correct for CTL and CPL in
accordance with API 11.1 (incorporated maintained in an operable condition a
backup power supply or a nonvolatile
by reference, see § 3174.30).
memory capable of retaining all
(e) The information specified in
required raw data in the unit’s memory
paragraphs (e)(1) through (4) of this
for at least 35 days to ensure that the
section must be recorded and retained
audit-trail information required under
under the recordkeeping requirements
paragraph (e) of this section is
of § 3170.50(g) of this part. The audit
protected.
trail must comply with API 21.2,
khammond on DSKJM1Z7X2PROD with PROPOSALS2
(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).
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§ 3174.121
(MDS).
Measurement data system
(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 § 3174.50.
(b) The MDS must comply with the
recordkeeping requirements of
§ 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 § 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.
§ 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 §§ 3174.31 and
3174.110.
(b) A CMS must be equipped with an
ELM system meeting the requirements
of § 3174.120.
(c) A CMS system must be proven in
compliance with § 3174.150.
(d) CMS measurement tickets must be
completed under § 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 § 3174.30). Additional
requirements are as follows:
(1) The pressure transducer must meet
the requirements of § 3174.106(a), (b),
and (c);
(2) Temperature determinations must
meet the requirements of § 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 § 3174.102 and any tests
conducted on oil samples for
determination of S&W content must
meet the requirements of § 3174.85. If
no sampling system is used, or the
sampling system does not meet the
requirements of § 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
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determined by one of the following
methods:
(1) Determined from a composite
sample taken pursuant to § 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
§ 3174.30). Density must be corrected to
base temperature and pressure using
API 11.1 (incorporated by reference, see
§ 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
§ 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 veryhigh-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
§ 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 nonFederal 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 § 3173; and
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(10) Any variations from these
requirements are considered alternative
methods of measurement and will
require PMT review and BLM approval.
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Sections 3174.151 through 3174.158
specify the minimum requirements for
conducting volumetric meter proving
for all FMP meters.
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 § 3174.30).
(b) Displacement provers must meet
the requirements of API 4.2
(incorporated by reference, see
§ 3174.30) and be calibrated using the
water-draw method under API 4.9.2
(incorporated by reference, see
§ 3174.30), at the calibration frequencies
specified in API 4.8, Subsection 10.1(b)
(incorporated by reference, see
§ 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
§ 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 § 3174.30).
(e) Fluid velocity must be calculated
using API 4.2, Subsection 4.3.4.3,
Equation 12 (incorporated by reference,
see § 3174.30).
§ 3174.151
§ 3174.152
§ 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.
§ 3174.150
Meter-proving requirements.
Meter prover.
Acceptable provers are positivedisplacement 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
§ 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
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Meter-proving runs.
Meter proving must follow the
applicable section(s) of API 4.1, Proving
Systems (incorporated by reference, see
§ 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,
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prior to proving to establish the normal
condition;
(3) The temperature as measured by
the LACT or CMS must remain within
10 °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 § 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 § 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 § 3174.30), or from any of
the number of runs indicated in API 4.8
Table A.1 (incorporated by reference,
see § 3174.30) that will result in the
0.027 percent uncertainty repeatability
criteria.
(d) The new meter factor is the
arithmetic average of the metergenerated 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 § 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
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neighboring meter factors differ by more
than 0.0020.
(i) Composite meter factors may only
be used with a fixed-setting, backpressure 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 backpressure 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 § 3173.21 of this
part.
§ 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 nonresettable 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 § 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.
§ 3174.154
deviation.
Excessive meter factor
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 § 3174.158 must
clearly describe all repairs and
adjustments; and
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(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.
§ 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 °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 °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 °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.
§ 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:
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(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.
§ 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
§ 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
§ 3174.30), as appropriate.
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§ 3174.158 Meter proving reporting
requirements.
§ 3174.160
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 § 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
§ 3174.30):
(1) The information identified and
required under the recordkeeping
requirements of § 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 °F, and meter factor;
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(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
§ 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
§ 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
§ 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.
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.
§ 3174.161
ticket.
Tank-gauging measurement
(a) The following information must be
documented during the field tankgauging operation by the operator,
purchaser, or transporter, as
appropriate:
(1) The information identified and
required under the recordkeeping
requirements of § 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 °F;
(5) Observed API oil gravity and
temperature in °F;
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56055
(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 § 3174.52);
(2) API oil gravity at 60 °F, following
API 11.1 (incorporated by reference, see
§ 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
§ 3174.30) or other methods approved
by the BLM.
§ 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 § 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 °F and
the API oil gravity must be indicated at
60 °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 °F;
(9) The average flowing pressure for
the measurement period in psig;
(10) S&W content percent;
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(11) Total net standard volume
following API 11.1 and API 12.2.2,
Subsections 9, 10 and 11 (both
incorporated by reference, see
§ 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
§ 3174.120) QTRs or from measurementdata systems that have been approved
by the BLM (see § 3174.121). The
volume statement must contain the
information identified in API 21.2,
Subsection 10.3.1 (incorporated by
reference, see § 3174.30). Volume
statements must include the information
identified and required under the
recordkeeping requirements of
§ 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.
§ 3174.170
methods.
Oil measurement by other
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 § 3170.30 of this part).
(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.
§ 3174.180 Determination of oil volumes
by methods other than measurement.
§ 3174.190
(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.
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.
Immediate assessments.
TABLE 1 TO § 3174.190: VIOLATIONS SUBJECT TO AN IMMEDIATE ASSESSMENT
Assessment
amount per
violation:
Violation:
1.
2.
3.
4.
Missing or nonfunctioning FMP LACT system components, as required by § 3174.100 ...............................................................
Missing or nonfunctioning FMP CMS components, as required by § 3174.130 .............................................................................
Failure to meet the proving frequency requirements for an FMP, detailed in § 3174.153 .............................................................
Failure to obtain a written approval, as required by § 3174.170, before using any oil measurement method other than tank
gauging, LACT system, or CMS at a FMP ......................................................................................................................................
5. Revise subpart 3175 to read as
follows:
■
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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).
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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.
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$1,000
1,000
1,000
1,000
Appendix A to Subpart 3175—Table of
Atmospheric Pressures
Appendix B to Subpart 3175— Maximum
Time Between Required Actions
§ 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:
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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 differentialpressure 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 (differentialpressure bellows, static-pressure
element, and temperature element) of a
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mechanical recorder is designed to
measure.
Gas storage agreement measurement
point (GSAMP) means a point where the
gas injected and withdrawn from a gasstorage 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 °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:
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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
°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.
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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 volumemeasurement 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.
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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 °F).
Reynolds number means the ratio of
the inertial forces to the viscous forces
of the fluid flow, and is defined as:
Where:
Re = the Reynolds number
V = velocity
r = fluid density
D = inside meter tube diameter
m = 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
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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.
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without isolating and depressurizing the
meter tube.
Standard cubic foot (scf) means a
cubic foot of gas at 14.73 psia and 60 °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:
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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
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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.
§ 3175.20
General requirements.
(a) Measurement of all gas at an FMP
must comply with the standards
prescribed in §§ 3175.10 through
3175.126; § 3175.140, if applicable; and
§ 3175.150, except as otherwise
approved under § 3170.40 of this part.
(b) Measurement of all gas at a
GSAMP must comply with the
standards prescribed in § 3175.130,
except as otherwise approved under
§ 3170.40 of this part.
§ 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 fedreg.legal@nara.gov 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
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Related Hydrocarbon Fluids; Second
Edition, September, 1985 (‘‘AGA Report
No. 3 (1985)’’), IBR approved for
§§ 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
§ 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 §§ 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 §§ 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 https://
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 §§ 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 §§ 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 §§ 3175.50(b),
3175.80(b), (e) through (i), (l) through
(o), Table 1 to § 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
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Applications; Fourth Edition, November
2013 (‘‘API 14.3.3 (2013)’’),’’ IBR
approved for §§ 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 § 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
§§ 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
§ 3175.100, §§ 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 §§ 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
(c) Bias. For low-volume, highvolume, 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
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2261–19’’),’’ IBR approved for
§ 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 § 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 § 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; https://
infostore.saiglobal.com/store/.
§ 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.
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,
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(3) There is no uncertainty
requirement for low- and very-lowvolume 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 § 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
§ 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:
rate, and heating value based on source
records and field observations.
§ 3175.40 Measurement equipment
requiring BLM approval.
Except as allowed under § 3175.50(a),
all makes, models, sizes, and software
versions of the devices listed in this
section that are used at FMPs must be
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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 § 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 highand 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.
§ 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 § 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 § 3175.90;
(c) GCs that meet the standards in
§§ 3175.117 and 3175.118 for
determining heating value and relative
density;
(d) Transducers, when used at lowand very-low volume FMPs, must meet
the requirements of § 3175.102; and
(e) Flow-computer software, when
used at low- and very-low volume
FMPs, must meet the requirements of
§ 3175.101.
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§ 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 § 3175.80(e));
(2) Documentation of routine orificeplate inspection (see § 3175.80(e));
(3) Documentation of basic meter-tube
inspection (see § 3175.80(j)(6));
(4) Documentation of detailed metertube inspection (see § 3175.80(l));
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(5) Documentation of mechanical
recorder verification after repair or
installation (see § 3175.92(d));
(6) Documentation of routine
mechanical recorder verification (see
§ 3175.92(d));
(7) Documentation of EGM system
verification after repair or installation
(see § 3175.102(e));
(8) Documentation of routine EGM
system verification (see § 3175.102(e));
(9) EGM audit trail data including
QTR, configuration log, event log, and
alarm log (see § 3175.104);
(10) MDS audit trail data including
QTR, configuration log, event log, and
alarm log (see § 3175.104(e));
(11) GC verification report (see
§ 3175.118(d)); and
(12) Gas analysis report (see
§ 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 § 3175.80(k)(3));
(2) Seventy-two (72) hours prior to
performing a basic meter-tube
inspection (see § 3175.80(j)(4)); and
(3) Seventy-two (72) hours prior to
taking a gas sample (see § 3175.113(b)).
§ 3175.50
Grandfathering.
(a) Exemption. Equipment listed in
§ 3175.40(a) through (f) that was
installed at a very-low, low-, or highvolume FMP prior to [EFFECTIVE
DATE OF FINAL RULE] is exempt from
the approval requirement in § 3175.40.
Any of the equipment listed in
§ 3175.40(a) through (i) that was
installed after [EFFECTIVE DATE OF
FINAL RULE] must meet the approval
requirement in § 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 § 3175.30) and
§ 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 § 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
§ 3175.30), and § 3175.80(h) and (m).
Meter tubes grandfathered under this
section must still meet the following
requirements:
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(i) Orifice plate eccentricity must
comply with AGA Report No. 3 (1985),
Section 4.2.4 (incorporated by reference,
see § 3175.30);
(ii) Meter tube construction and
condition must comply with AGA
Report No. 3 (1985), Section 4.3.4
(incorporated by reference, see
§ 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 § 3175.30).
(B) If the upstream meter tube
contains a 19-tube bundle flow
straightener or isolating flow
conditioner, the installation must
comply with § 3175.80(i);
(2) For meter tubes installed at verylow-, 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 § 3175.30), in lieu of
the reference inside diameter of the
meter tube for the requirements of
§§ 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 §§ 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 § 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 § 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
§ 3175.30).
(2) EGM software installed at lowvolume FMPs before January 17, 2017,
is exempt from:
(i) The requirements at
§ 3175.103(a)(1)(i), if the differentialpressure 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
§ 3175.30). However, flow-rate
calculations must still be calculated in
accordance with API 14.3.3 (1992)
(incorporated by reference, see
§ 3175.30); and
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(ii) The requirements at
§ 3175.103(a)(1)(ii). However,
compressibility must still be calculated
in accordance with AGA Report No. 8
(1992) (incorporated by reference, see
§ 3175.30).
§ 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
§ 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 § 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
§ 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 § 3175.101(b)(4) after [DATE
TWO YEARS AFTER EFFECTIVE DATE
OF FINAL RULE].
§ 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.
khammond on DSKJM1Z7X2PROD with PROPOSALS2
§ 3175.80 Flange-tapped orifice plate
(primary device).
Except as provided in § 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
§ 3175.30).
(b) Orifice plate eccentricity must
comply with API 14.3.2, Subsection
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6.2.1 (incorporated by reference, see
§ 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 refractured (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 § 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
§ 3175.80 of this section.
(2) The time between any two orificeplate 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 § 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 § 3175.92(d) for
mechanical recorders, or § 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
§ 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
§ 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 § 3175.30).
(i) If flow conditioners are used, they
must be either isolating-flow
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conditioners approved by the BLM and
installed under BLM requirements (see
§ 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
§ 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 erosiveflow (e.g., high hydrogen sulfide (H2S)
or carbon dioxide (CO2) content) or
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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
§ 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 veryhigh-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 § 3175.30), or the
requirements under § 3175.50(b), if the
meter tube is grandfathered under
§ 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 § 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 metertube inspections, demonstrating that the
meter tube complies with API 14.3.2,
Subsections 5.1 through 5.4
(incorporated by reference, see
§ 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
§ 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
§ 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
§ 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 (b) falls
between the values in Tables 7, 8a, or
8b of API 14.3.2, Subsection 6.3
(incorporated by reference, see
§ 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-tubebundle 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 § 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 § 3175.30).
(2) For vertical meter tubes, the
sample probe must be mounted
perpendicular to the vertical meter tube.
khammond on DSKJM1Z7X2PROD with PROPOSALS2
TABLE 1 TO § 3175.80: STANDARDS FOR FLANGE-TAPPED ORIFICE PLATES
Subject
Reference
(API standards incorporated by
reference, see § 3175.30)
VL
L
H
VH
Fluid conditions .....................................................................................
Orifice plate construction and condition ...............................................
Orifice plate eccentricity and perpendicularity ** ..................................
Beta ratio range ....................................................................................
Minimum orifice size .............................................................................
New FMP orifice-plate inspection * .......................................................
Routine orifice-plate inspection frequency, in months * .......................
Documentation of orifice-plate inspection ............................................
Meter-tube construction and condition ** ..............................................
Flow conditioners including 19-tube bundles .......................................
Initial basic meter-tube inspection ........................................................
§ 3175.80(a) ..................................
API 14.3.2, Section 4 ...................
§ 3175.80(b) ..................................
§ 3175.80(c) ..................................
§ 3175.80(d) ..................................
§ 3175.80(e) ..................................
§ 3175.80(f) ...................................
§ 3175.80(g) ..................................
§ 3175.80(h) ..................................
§ 3175.80(i) ...................................
§ 3175.80(j) ...................................
n/a
x
n/a
n/a
n/a
n/a
12
x
n/a
n/a
n/a
x
x
x
x
n/a
x
6
x
x
x
n/a
x
x
x
x
x
x
3
x
x
x
x
x
x
x
x
x
x
1
x
x
x
x
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TABLE 1 TO § 3175.80: STANDARDS FOR FLANGE-TAPPED ORIFICE PLATES—Continued
Subject
Reference
(API standards incorporated by
reference, see § 3175.30)
VL
L
H
VH
Routine basic meter-tube inspection frequency, in years * ..................
Detailed meter-tube inspection * ...........................................................
Documentation of detailed meter-tube inspection ................................
Meter-tube length ** ..............................................................................
Thermometer wells ...............................................................................
Sample probe location ..........................................................................
§ 3175.80(k) ..................................
§ 3175.80(l) ...................................
§ 3175.80(m) .................................
§ 3175.80(n) ..................................
§ 3175.80(o) ..................................
§ 3175.80(p) ..................................
n/a
n/a
n/a
n/a
n/a
x
10
n/a
n/a
x
x
x
5
x
x
x
x
x
5
x
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 § 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 § 3175.50 for requirements pertaining to meter tubes installed at low- and high-volume FMPs before [EFFECTIVE DATE OF FINAL
RULE].
§ 3175.90
device).
Mechanical recorder (secondary
(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 § 3175.90: STANDARDS FOR MECHANICAL RECORDERS
Subject
Reference
VL
L
Applications for use ...................................................................................................
Manifolds and gauge/impulse lines ...........................................................................
Differential-pressure pen position ..............................................................................
Flowing temperature recording ..................................................................................
On-site data requirements .........................................................................................
Operating within the element ranges ........................................................................
Verification after installation or following repair * .......................................................
Routine verification and verification frequency, in months * ......................................
Routine verification procedures .................................................................................
Documentation of verification ....................................................................................
Notification of verification ...........................................................................................
Volume correction ......................................................................................................
Test equipment recertification ...................................................................................
Integration statement requirements ...........................................................................
Volume determination ................................................................................................
Atmospheric pressure ................................................................................................
§ 3175.90(a) .............................................
§ 3175.91(a) .............................................
§ 3175.91(b) .............................................
§ 3175.91(c) .............................................
§ 3175.91(d) .............................................
§ 3175.91(e) .............................................
§ 3175.92(a) .............................................
§ 3175.92(b) .............................................
§ 3175.92(c) .............................................
§ 3175.92(d) .............................................
§ 3175.92(e) .............................................
§ 3175.92(f) ..............................................
§ 3175.92(g) .............................................
§ 3175.93 .................................................
§ 3175.94(a) .............................................
§ 3175.94(b) .............................................
x
n/a
n/a
n/a
x
x
x
6
x
x
x
n/a
x
x
x
x
x
x
x
x
x
x
x
3
x
x
x
x
x
x
x
x
VL=Very-low-volume FMP; L=Low-volume FMP.
* = Immediate assessment for non-compliance under § 3175.150.
khammond on DSKJM1Z7X2PROD with PROPOSALS2
§ 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 3⁄8inch;
(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
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differential-pressure bellows and staticpressure element.
(b) The differential-pressure pen must
record at a minimum reading of 10
percent of the differential-pressurebellows 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
§ 3175.94(a)(1).
(d) The following information must be
maintained at the FMP in a legible
condition, in compliance with
§ 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;
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(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 primarydevice 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
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lower- and upper-calibrated limits of the
respective elements.
TABLE 1 TO PARAGRAPH (a)(6):
MECHANICAL RECORDER TOLERANCES
khammond on DSKJM1Z7X2PROD with PROPOSALS2
§ 3175.92 Verification and calibration of
mechanical recorders.
Element
(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 staticpressure 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 °F below the
lowest expected flowing temperature;
(ii) Approximately 10 °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.
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Differential Pressure .....
Static Pressure .............
Temperature .................
Allowable error
±0.5%
±1.0%
±2 °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 § 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 asfound 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
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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 staticpressure 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 asleft 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
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§ 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 asfound 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
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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.
§ 3175.93
§ 3175.94
Volume determination.
(a) The volume for each chart
integrated must be determined as
follows:
V = IMV × 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 flangetapped orifice plate, a single IMV must
be calculated for each chart or chart
interval using the following equation:
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
§ 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
§ 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);
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(5) Average temperature (°F);
(6) Integrator counts or extension;
(7) Hours of flow; and
(8) Volume (Mcf).
Frm 00128
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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 § 3175.30)
b = 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.
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§ 3175.100 Electronic gas measurement
(secondary and tertiary device).
Except as provided in § 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 § 3175.100—STANDARDS FOR ELECTRONIC GAS MEASUREMENT SYSTEMS
Subject
Reference
(API standards
incorporated by
reference, see § 3175.30)
VL
L
H
VH
EGM system commissioning ................................................................
Access and data security .....................................................................
No-flow cutoff ........................................................................................
Manifolds and gauge lines ...................................................................
Display requirements ............................................................................
On-site information ...............................................................................
Operating within the calibrated limits ...................................................
Flowing-temperature measurement ......................................................
Verification after installation or following repair * .................................
Routine verification frequency, in months * ..........................................
Routine verification procedures ............................................................
Redundancy verification .......................................................................
Documentation of verification ...............................................................
Notification of verification .....................................................................
Volume correction .................................................................................
Test-equipment requirements ...............................................................
Flow-rate calculation ** .........................................................................
Atmospheric pressure ...........................................................................
Volume calculation ...............................................................................
QTR requirements ................................................................................
Configuration log requirements ............................................................
Event log ...............................................................................................
Alarm log ..............................................................................................
Accounting systems ..............................................................................
API 21.1, Subsection 7.3 ..............
API 21.1, Section 9 ......................
API 21.1, Subsection 4.4.5 ...........
§ 3175.101(a) ................................
§ 3175.101(b) ................................
§ 3175.101(c) ................................
§ 3175.101(d) ................................
§ 3175.101(e) ................................
§ 3175.102(a) ................................
§ 3175.102(b) ................................
§ 3175.102(c) ................................
§ 3175.102(d) ................................
§ 3175.102(e) ................................
§ 3175.102(f) .................................
§ 3175.102(g) ................................
§ 3175.102(h) ................................
§ 3175.103(a) ................................
§ 3175.103(b) ................................
§ 3175.103(c) ................................
§ 3175.104(a) ................................
§ 3175.104(b) ................................
§ 3175.104(c) ................................
§ 3175.104(d) ................................
§ 3175.104(e) ................................
n/a
x
x
n/a
x
x
n/a
n/a
x
12
x
x
x
x
n/a
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
6
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
6
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
6
x
x
x
x
x
x
x
x
x
x
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 § 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 § 3175.50 for requirements pertaining to FMPs installed at low- and very-low-volume FMPs before EFFECTIVE DATE OF
FINAL RULE].
khammond on DSKJM1Z7X2PROD with PROPOSALS2
§ 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 3⁄8inch;
(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 staticpressure transducers may be connected.
(b) Each FMP must include a display,
which must:
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(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 (°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 § 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);
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(ii) Previous-period average static
pressure with units (psia or psig); and
(iii) Previous-period average flowing
temperature (°F);
(c) The following information must be
maintained at the FMP in a legible
condition, in compliance with
§ 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;
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(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 BLMapproved 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 differentialpressure 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 § 3175.30).
khammond on DSKJM1Z7X2PROD with PROPOSALS2
§ 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 § 3175.92(a)(1).
(2) The operator must verify the
points listed in API 21.1, Subsection
7.3.3 (incorporated by reference, see
§ 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
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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
§ 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
§ 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
§ 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
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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 °F of the normal
operating point for temperature.
(3) If a transducer is calibrated, the asleft 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 § 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 § 3175.30). The verification
tolerance for temperature is equivalent
to the uncertainty of the temperature
transmitter or 0.5 °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 § 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:
Where:
Ap is the reference accuracy of the primary
transducer and
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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 § 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
§ 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;
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(i) The information required in
§ 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 § 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 asfound 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
§ 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:
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(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.
§ 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
§ 3175.30); and
(ii) AGA Report No. 8 Part 1 or Part
2 (both incorporated by reference, see
§ 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
§ 3175.104 must be determined under
API 21.1, Section 4 and Annex B
(incorporated by reference, see
§ 3175.30).
§ 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
§ 3175.30), with the following additions
and clarifications:
(1) The information required in
§ 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 § 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
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original, unaltered, unprocessed, and
unedited configuration log, which must
contain the information specified in API
21.1, Subsection 5.4 (including the flowcomputer snapshot report in Subsection
5.4.2), and Annex G (incorporated by
reference, see § 3175.30), with the
following additions and clarifications:
(1) The information required in
§ 3170.50(g) of this part;
(2) Software/firmware identifiers
under API 21.1, Subsection 5.3
(incorporated by reference, see
§ 3175.30);
(3) For very-low-volume FMPs only,
the fixed temperature, if not
continuously measured (°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
§ 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 § 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
§ 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 § 3175.41).
§ 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 § 3175.110: GAS SAMPLING AND ANALYSIS
Subject
Reference
Methods of sampling ............................................................................
Heating requirements ...........................................................................
Samples taken from probes .................................................................
Location of sample probe .....................................................................
Sample probe design and type ............................................................
Sample tubing .......................................................................................
Spot sample while flowing ....................................................................
Notification of spot samples .................................................................
Sample cylinder requirements ..............................................................
Spot sampling using portable GCs ......................................................
Allowable methods of spot sampling ....................................................
Low pressure sampling ........................................................................
Spot sampling frequency, low- and very-low-volume FMPs (in
months) *.
Initial spot sampling frequency, high- and very-high-volume FMPs (in
months) *.
Adjustment of spot sampling frequencies, high- and very-high-volume FMPs.
Maximum time between samples .........................................................
Installation of composite sampler or on-line GC ..................................
Removal of composite sampler or on-line GC .....................................
Composite sampling methods ..............................................................
On-line gas chromatographs ................................................................
Gas chromatograph requirements ........................................................
Minimum components to analyze .........................................................
C9+ analysis .........................................................................................
Gas analysis report requirements ........................................................
Effective date of spot and composite samples ....................................
VL
L
H
VH
................................
................................
................................
................................
................................
................................
................................
................................
................................
................................
................................
................................
................................
x
x
n/a
n/a
n/a
n/a
x
x
x
x
x
x
12
x
x
x
x
x
x
x
x
x
x
x
x
6
x
x
x
x
x
x
x
x
x
x
x
x
n/a
x
x
x
x
x
x
x
x
x
x
x
x
n/a
§ 3175.115(a) ................................
n/a
n/a
3
1
§ 3175.115(b) ................................
n/a
n/a
x
x
§ 3175.115(c) ................................
§ 3175.115(d) ................................
§ 3175.115(e) ................................
§ 3175.116 ....................................
§ 3175.117 ....................................
§ 3175.118 ....................................
§ 3175.119(a) ................................
§ 3175.119(b) and (c) ...................
§ 3175.120 ....................................
§ 3175.121 ....................................
x
x
x
x
x
x
x
n/a
x
x
x
x
x
x
x
x
x
n/a
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
§ 3175.111(a)
§ 3175.111(b)
§ 3175.112(a)
§ 3175.112(b)
§ 3175.112(c)
§ 3175.112(d)
§ 3175.113(a)
§ 3175.113(b)
§ 3175.113(c)
§ 3175.113(d)
§ 3175.114(a)
§ 3175.114(b)
§ 3175.115(a)
VL=Very-low-volume FMP; L=Low-volume FMP; H=High-volume FMP.
VH=Very-high-volume FMP.
* = Immediate assessment for non-compliance under § 3175.150.
khammond on DSKJM1Z7X2PROD with PROPOSALS2
§ 3175.111 General sampling
requirements.
(a) Samples must be taken by one of
the following methods:
(1) Spot sampling under §§ 3175.113
to 3175.115;
(2) Flow-proportional composite
sampling under § 3175.116; or
(3) On-line gas chromatograph under
§ 3175.117.
(b) At all times during the sampling
process, the minimum temperature of
all gas sampling components must be
the lesser of:
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(1) The flowing temperature of the gas
measured at the time of sampling; or
(2) 30 °F above the calculated
hydrocarbon dew point of the gas.
§ 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 § 3175.80(p).
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(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
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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 °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
§ 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.
khammond on DSKJM1Z7X2PROD with PROPOSALS2
§ 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 § 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
§ 3175.30);
(2) Have a minimum capacity of 300
cubic centimeters; and
(3) Be cleaned before sampling in
accordance with GPA 2166–17,
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Appendix A (incorporated by reference,
see § 3175.30), or an equivalent method.
The operator must maintain
documentation of cleaning (see
§ 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
§ 3175.118.
(4) The documentation of verification
or calibration required in § 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 °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.
§ 3175.114
methods.
Spot samples—allowable
(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
§ 3175.30);
(2) Helium ‘‘pop’’ method. Samples
taken using this method must comply
with GPA 2166–17, Section 9.5
(incorporated by reference, see
§ 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 § 3175.30). The operator must
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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 § 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 vacuumgathering system. Samples taken using a
vacuum-gathering system must comply
with API 14.1, Subsection 11.10
(incorporated by reference, see
§ 3175.30), and the samples must be
obtained from the discharge of the
vacuum pump.
§ 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 § 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 veryhigh-volume FMPs if the BLM
determines that the sampling frequency
required in Table 1 in § 3175.110 is not
sufficient to achieve the heating value
uncertainty levels required in
§ 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 § 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
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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
§ 3175.116 or § 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.
§ 3175.116
Composite sampling methods.
(a) Composite samplers must be flowproportional.
(b) Samples must be collected using a
positive-displacement pump.
(c) Sample cylinders must comply
with § 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 °F
above the HCDP at all times.
§ 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
§ 3175.30), and the manufacturer’s
specifications, instructions, and
recommendations.
(b) The GC must comply with the
verification and calibration
requirements of § 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.
khammond on DSKJM1Z7X2PROD with PROPOSALS2
§ 3175.118 Gas chromatograph
requirements.
(a) All GCs must be installed,
operated, and calibrated under GPA
2261–19 (incorporated by reference, see
§ 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).
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(1) GCs must be verified under GPA
2261–19, Section 6 (incorporated by
reference, see § 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
§ 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
§ 3175.30).
(4) The gas used to calibrate a GC
must be maintained under GPA 2198–
16, Section 5 (incorporated by reference,
see § 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 § 3175.30), the GC
must be calibrated under GPA 2261–19,
Section 6 (incorporated by reference, see
§ 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 § 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;
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(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.
§ 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
§ 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.
§ 3175.120 Gas analysis report
requirements.
(a) The gas analysis report must
contain the following information:
(1) The information required in
§ 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;
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(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
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§ 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
volume-weighted average of heating
values, determined as follows:
where:
HVi = the heating value for FMPi, in Btu/scf
HVi,j = the heating value for FMPi, for partial
month j, in Btu/scf
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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].
§ 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 § 3175.30) and must be
calculated under API 14.5, Subsection
7.1 (incorporated by reference, see
§ 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 °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:
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
§§ 3175.94 (mechanical recorders) or
3175.103(c) (EGM systems).
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HVi = the heating value for FMPi, during the
reporting month (see § 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
(c) The heating value and relative
density must be calculated under API
14.5 (incorporated by reference, see
§ 3175.30).
(d) The base supercompressibility
must be calculated under AGA Report
No. 8, Part 1 or Part 2 (incorporated by
reference, see § 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 § 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 electronicsubmission 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.
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(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., spotcylinder, spot-portable GC, composite);
(16) The sampling method if spotcylinder (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.
56073
56074
§ 3175.126
volume.
Federal Register / Vol. 85, No. 176 / Thursday, September 10, 2020 / Proposed Rules
Reporting of heating value and
(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 °F;
(3) For samples analyzed under
§ 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
§ 3175.119(c); and
(4) For samples analyzed under
§ 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 § 3175.94 or
§ 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 § 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.
§ 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.
§ 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 § 3175.92(b) are not
required;
(b) Routine EGM system verification
under § 3175.102(b) are not required;
(c) Basic meter-tube inspections under
§ 3175.80(j) are not required; and
(d) Detailed meter-tube inspections
under § 3175.80(k)(1) are not required.
§ 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 § 3175.150—VIOLATIONS SUBJECT TO AN IMMEDIATE ASSESSMENT
Assessment
amount per
violation:
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Violation:
1.
2.
3.
4.
5.
6.
7.
8.
New FMP orifice-plate inspections were not conducted as required by § 3175.80(e) ...................................................................
Routine FMP orifice-plate inspections were not conducted as required by § 3175.80(f) ...............................................................
Basic meter-tube inspections were not conducted as required by § 3175.80(j) .............................................................................
Detailed meter-tube inspections were not conducted as required by § 3175.80(k) .......................................................................
An initial EGM-system verification was not conducted as required by § 3175.102(a) ...................................................................
Routine EGM-system verifications were not conducted as required by § 3175.102(b) ..................................................................
Spot samples for low-volume and very-low-volume FMPs were not taken as required by § 3175.115(a) ....................................
Spot samples for high- and very-high-volume FMPs were not taken as required by § 3175.115(a) and (b) ................................
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56077
APPENDIX B TO SUBPART 3175—MAXIMUM TIME BETWEEN REQUIRED ACTIONS
Then the maximum time
between required actions (in
days) is:
If the required frequency is once every:
2 weeks ......................................................................................................................................................................
Month .........................................................................................................................................................................
2 months ....................................................................................................................................................................
3 months ....................................................................................................................................................................
6 months ....................................................................................................................................................................
12 months ..................................................................................................................................................................
18
45
75
105
195
395
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BILLING CODE 4310–84–C
]]>Agencies
[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.
-----------------------------------------------------------------------
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.
[[Page 55941]]
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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
[[Page 55942]]
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
[[Page 55943]]
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
[[Page 55944]]
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 https://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.
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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 https://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;
https://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 https://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; https://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........................... 
