Onshore Oil and Gas Operations; Federal and Indian Oil and Gas Leases; Measurement of Oil, 81462-81513 [2016-25405]
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Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
II. Overview of Final Rule, Section-bySection Analysis, and Response to
Comments on the Proposed Rule
III. Overview of Public Involvement and
Consistency With GAO
Recommendations
IV. Procedural Matters
DEPARTMENT OF THE INTERIOR
Bureau of Land Management
43 CFR Parts 3160 and 3170
[17X.LLWO310000.L13100000.PP0000]
RIN 1004–AE16
Onshore Oil and Gas Operations;
Federal and Indian Oil and Gas Leases;
Measurement of Oil
Bureau of Land Management,
Interior.
ACTION: Final rule.
AGENCY:
This final rule updates and
replaces Onshore Oil and Gas Order
Number 4, Measurement of Oil (Order 4)
with new regulations codified in the
Code of Federal Regulations (CFR). It
establishes minimum standards for the
measurement of oil produced from
Federal and Indian (except Osage Tribe)
leases to ensure that production is
accurately measured and properly
accounted for.
DATES: The final rule is effective on
January 17, 2017. The incorporation by
reference (IBR) of certain publications
listed in the rule is approved by the
Director of the Federal Register as of
January 17, 2017.
ADDRESSES: Mail: U.S. Department of
the Interior, Director (630), Bureau of
Land Management, Mail Stop 2134 LM,
1849 C St. NW., Washington, DC 20240,
Attention: 1004–AE16.
Personal or messenger delivery: 20 M
Street SE., Room 2134LM, Washington,
DC 20003.
FOR FURTHER INFORMATION CONTACT:
Mike McLaren, Petroleum Engineer,
BLM Wyoming, Pinedale Field Office,
1625 West Pine St., P.O. Box 768,
Pinedale, WY 82941, or by telephone at
307–367–5389, for information about
the requirements of this final rule; or
Steven Wells, Division Chief, Fluid
Minerals Division, 202–912–7143, for
information regarding the Bureau of
Land Management’s (BLM’s) Fluid
Minerals Program. For questions related
to regulatory process issues, please
contact Faith Bremner at 202–912–7441.
Persons who use a telecommunications
device for the deaf (TDD) may call the
Federal Relay Service at 800–877–8339
to contact the above individuals during
normal business hours. The Service is
available 24 hours a day, 7 days a week
to leave a message or question with the
above individuals. You will receive a
reply during normal business hours.
SUPPLEMENTARY INFORMATION:
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SUMMARY:
I. Overview and Background
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I. Overview and Background
The BLM developed this rule based
on the proposed rule published in the
Federal Register on September 30, 2015
(80 FR 58952), and the BLM’s
consideration of tribal and public
comments received on the proposed
rule. This final rule strengthens the
BLM’s policies governing production
accountability by updating its minimum
standards for oil measurement to reflect
the considerable changes in technology
and industry practices that have
occurred in the 25 years since Order 4
was issued. It also responds to
recommendations the United States
Government Accountability Office
(GAO), the Department of the Interior’s
(Interior’s or Department’s) Office of the
Inspector General (OIG), and the
Secretary of the Interior’s (Secretary’s)
Royalty Policy Committee (RPC),
Subcommittee on Royalty Management
(Subcommittee) made with respect to
the BLM’s production verification
efforts. As explained in this preamble,
the overall volume uncertainty and
performance goals established by this
rule are designed to ensure that the oil
volume reported on an Oil and Gas
Operations Report (OGOR) submitted to
the Office of Natural Resources Revenue
(ONRR) is sufficiently accurate to
ensure that the royalties due are paid.
Like the proposed rule, the final rule
addresses the use of new oil meter
technology, proper measurement
documentation, and recordkeeping;
establishes performance standards for
oil measurement systems; and includes
a mechanism for the BLM to review, and
approve for use, new oil measurement
technology and systems. The final rule
expands the acts of noncompliance that
would result in an immediate
assessment. Finally, it sets forth a
process for the BLM to consider
variances from these requirements.
Key changes incorporated into the
final rule include provisions that allow
operators to use Coriolis measurement
systems (CMSs) and automatic tank
gauging (ATG) systems without having
to obtain variances from the BLM.
This final rule, as well as the final
rules to update and replace Onshore Oil
and Gas Orders Numbers 3 (Order 3)
and 5 (Order 5) related to site security
and the measurement of gas,
respectively, enhance the BLM’s overall
production verification and
accountability program.
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The Secretary has the authority under
various Federal and Indian mineral
leasing laws to manage oil and gas
operations on Federal and Indian
(except Osage Tribe) lands. Governing
laws include, but are not limited to, the
Mineral Leasing Act (MLA), 30 U.S.C.
181 et seq.; the Mineral Leasing Act for
Acquired Lands, 30 U.S.C. 351 et seq.;
the Federal Oil and Gas Royalty
Management Act (FOGRMA), 30 U.S.C.
1701 et seq.; the Indian Mineral Leasing
Act, 25 U.S.C. 396a et seq.; the Act of
March 3, 1909, 25 U.S.C. 396; the Indian
Mineral Development Act, 25 U.S.C.
2101 et seq.; and the Federal Land
Policy and Management Act (FLPMA),
43 U.S.C. 1701, et seq.1
The BLM’s onshore oil and gas
program is one of the most significant
mineral-leasing programs in the Federal
Government. In the fiscal year (FY) 2015
sales year, onshore Federal oil and gas
lease holders sold 180 million barrels of
oil,2 2.5 trillion cubic feet of natural
gas,3 and 2.6 billion gallons of natural
gas liquids, with a market value of more
than $17.7 billion, and generating
royalties of almost $2 billion. Nearly
half of these revenues were distributed
to the States in which the leases are
located. Lease holders on tribal and
Indian lands sold 59 million barrels of
oil, 239 billion cubic feet of natural gas,
and 182 million gallons of natural gas
liquids, with a market value of over $3.6
billion, and generating royalties of over
$0.6 billion that were all distributed to
the applicable tribes and individual
allotment owners. Under applicable
laws, royalties are owed on all
production removed or sold from
Federal and Indian oil and gas leases.
1 Each of the statutes cited above expressly
authorizes the Secretary of the Interior to
promulgate necessary and appropriate rules and
regulations governing those leases. See e.g., 30
U.S.C. 189; 30 U.S.C. 359; 30 U.S.C. 1751; 25 U.S.C.
396d; 25 U.S.C. 396; 25 U.S.C. 2107; and 43 U.S.C
1740. The Secretary has delegated this authority to
the BLM. Specifically, under Secretarial Order
Number 3087, dated December 3, 1982, as amended
on February 7, 1983 (48 FR 8983), and the
Departmental Manual (235 DM 1.1), the Secretary
has delegated regulatory authority over onshore oil
and gas development on Federal and Indian (except
Osage Tribe) lands to the BLM. For Indian leases,
the delegation of authority to the BLM is reflected
in 25 CFR parts 211, 212, 213, 225, and 227. In
addition, as authorized by 43 U.S.C. 1731(a), the
Secretary has delegated to the BLM regulatory
responsibility for oil and gas operations in Indian
lands. 235 DM 1.1.K.
2 This figure includes 168 million barrels of
regularly classified oil, plus additional sales of
condensate, sweet and sour crude, black wax crude,
other liquid hydrocarbons, inlet scrubber and drip
or scrubber condensate, and oil losses, all of which
are considered to be part of oil sales for accounting
purposes.
3 This figure includes all processed and
unprocessed volumes recovered on-lease, nitrogen,
fuel gas, coal bed methane, and any volumes of gas
lost due to venting or flaring.
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The basis for those royalty payments is
the measured production from those
leases.
As explained in the preamble for the
proposed rule, given the magnitude of
oil production on Federal and Indian
lands, and the BLM’s statutory and
management obligations, it is critically
important that the BLM ensure that
operators accurately measure, properly
report, and account for that production.
However, the BLM’s rules governing
how that oil is measured and accounted
for are more than 25 years old and need
to be updated and strengthened. Federal
laws, technology, and industry
standards have all changed significantly
in that time. The final rule addresses the
outdated nature of existing requirements
and helps achieve the BLM’s objective
of ensuring accurate measurement by
updating and replacing Order 4’s
requirements with regulations codified
in the CFR, at a new 43 CFR subpart
3174. These new regulations reflect
changes in oil measurement practices
and technology since Order 4 was first
promulgated in 1989.4
These updated requirements are the
result of the BLM’s evaluation of its
existing requirements, based on its
experience in the field, and based on the
conclusion of multiple reports and
evaluations of the BLM’s oil and gas
program—one by the Subcommittee,
issued in 2007; one by the OIG, issued
in 2009; and two reports prepared by
the GAO, issued in 2010 and 2015. Each
of these is described further below.
In 2007, the Secretary appointed an
independent panel—the
Subcommittee—to review the
Department’s procedures and processes
related to the management of mineral
revenues and to provide advice to the
Department based on that review.5 In a
report dated December 17, 2007, the
Subcommittee determined that the
BLM’s production accountability
methods are ‘‘unconsolidated, outdated,
and sometimes insufficient.’’ The report
observed that:
• BLM policy and guidance have not
been consolidated into a single
document or publication, resulting in
the BLM’s 31 oil and gas field offices
using varying policies and guidance (see
page 31);
4 Order 4, which was published in the Federal
Register on February 24, 1989 (54 FR 8056), has
been in effect since August 23, 1989.
5 The Subcommittee was commissioned to report
to the RPC, which was chartered under the Federal
Advisory Committee Act to provide advice to the
Secretary and other Departmental officials
responsible for managing mineral leasing activities
and to provide a forum for the public to voice
concerns about mineral leasing activities.
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• Some BLM policy and guidance are
outdated and some policy memoranda
have expired (ibid.); and
• Some BLM State Offices have
issued their own ‘‘Notices to Lessees
and Operators’’ (NTLs) for oil and gas
operations. While such NTLs may have
a positive effect on local oil and gas
field operations, they nevertheless lack
a national perspective and may
introduce inconsistencies among the
States (ibid.).
The Subcommittee specifically
recommended that the BLM evaluate
Order 4 to determine whether it
includes sufficient guidance for
ensuring that accurate royalties are paid
on Federal oil production. As explained
in the preamble to the proposed rule,
the Interior Department formed a Fluid
Minerals Team, comprising
Departmental oil and gas experts. The
team determined that Order 4 should be
updated in light of changes in
technology, the BLM, and industry
practices.
As noted, in addition to the
Subcommittee report, findings and
recommendation addressing similar
issues have been issued by the GAO
(Report to Congressional Requesters, Oil
and Gas Management, Interior’s Oil and
Gas Production Verification Efforts Do
Not Provide Reasonable Assurance of
Accurate Measurement of Production
Volumes, GAO–10–313 (GAO 2010
Report), and Report to Congressional
Requesters, Oil and Gas Resources,
Interior’s Production Verification
Efforts: Data Have Improved but Further
Actions Needed, GAO 15–39 (GAO 2015
Report)) and the OIG (Bureau of Land
Management’s Oil and Gas Inspection
and Enforcement Program, CR–EV–
0001–2009 (OIG Report)).
In its 2010 report, the GAO found that
the Department’s measurement
regulations and policies do not provide
reasonable assurances that oil and gas
are accurately measured because, among
other things, the Department’s policies
for tracking where and how oil and gas
are measured are not consistent and
effective (GAO 2010 Report, p. 20). The
report also found that the BLM’s
regulations do not reflect current
industry-adopted measurement
technologies and standards designed to
improve oil and gas measurement
(ibid.). The GAO recommended that
Interior provide Department-wide
guidance on measurement technologies
not addressed in current regulations and
approve variances for measurement
technologies in instances when the
technologies are not addressed in
current regulations or Department-wide
guidance (see ibid., p. 80). The OIG
report made a similar recommendation
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that the BLM, ‘‘Ensure that oil and gas
regulations are current by updating and
issuing onshore orders. . . .’’ (see p.
11). In its 2015 report, the GAO
reiterated that ‘‘Interior’s measurement
regulations do not reflect current
measurement technologies and
standards,’’ and that this ‘‘hampers the
agency’s ability to have reasonable
assurance that oil and gas production is
being measured accurately and verified
. . .’’ (GAO 2015 Report, p. 16). Among
its recommendations were that the
Secretary direct the BLM to ‘‘meet its
established time frame for issuing final
regulations for oil measurement’’ (ibid.,
p. 32). The OIG made similar
recommendations based on the
Subcommittee’s report observing that
the BLM should, ‘‘(e)nsure that oil . . .
regulations are current by updating and
issuing onshore orders . . .’’ (OIG
Report, p. 11).
The GAO’s recommendations related
to the adequacy of the BLM’s oil
measurement rules are also significant
because they form one of the bases for
the GAO’s inclusion of the BLM’s oil
and gas program on the GAO’s High
Risk List in 2011 (Report to
Congressional Committees, High Risk
Series, An Update, GAO–11–278).
Specifically, the GAO concluded in
2011 ‘‘that Interior’s verification of the
volume of oil . . . produced from
Federal leases––on which royalties are
due the Federal government––does not
provide reasonable assurance that
operators are accurately measuring and
reporting these volumes’’ (GAO–11–278,
p. 15). Because the GAO’s
recommendations have not yet been
fully implemented, the onshore oil and
gas program has remained on the High
Risk List in subsequent updates in 2013
(Report to Congressional Committees,
High Risk Series, An Update, GAO–13–
283) and 2015 (Report to Congressional
Committees, High Risk Series, An
Update, GAO–15–290).
Up-to-date measurement requirements
are critically important because they
help ensure that oil and gas produced
from Federal and Indian leases are
properly accounted for, thus ensuring
that operators pay the proper royalties
due.
As explained in more detail below,
the final rule makes a number of
changes that modernize and strengthen
the existing requirements in Order 4. In
general, this final rule will give industry
more choices and flexibility for
measuring oil produced from Federal
and Indian leases and will also make it
easier for operators in the future to
adopt new technologies and processes
as the industry continues to advance.
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In addition to updating requirements
with respect to existing technologies,
the final rule also specifically
recognizes advances in measurement
technology by affirmatively allowing
operators to use a CMS 6 or an ATG/
hybrid tank measurement system
without first receiving a variance from
the BLM, as is currently required.7 In
response to GAO and RPC concerns that
BLM field offices put out various
policies and guidance, the final rule
establishes nationwide requirements
and standards for this measurement
equipment, including a nationwide
process for reviewing and approving
new technology as it is developed. This
change is significant because CMSs have
proven to be reliable and accurate in
field and laboratory testing and, when
the time comes to replace their older
systems, more and more operators are
opting to use CMSs.
Similarly, operators in newer well
fields have been using ATG systems for
internal inventory purposes for over 10
years and only recently have they
started using them to measure oil for
sales and royalty-determination
purposes. The BLM reviewed
proprietary ATG test data that operators
submitted to the BLM—both as public
comment on the proposed rule and in
support of variance requests to have
ATG systems replace manual tank
gauging. Based on that review, the BLM
believes that ATG/hybrid systems can
meet or exceed this rule’s tank-gauging
standards and as a result they should be
expressly allowed. Affirmatively
allowing ATG and hybrid systems will
also increase worker safety because
eliminating the need for workers to
climb on top of tanks, open hatches, and
manually measure or sample oil reduces
their exposure to the fumes coming out
of the tanks.8 The final rule’s
incorporation of ATG/hybrid systems as
a permissible measurement method
6 A CMS is a metering system that uses a Coriolis
flow meter in conjunction with a tertiary device,
pressure transducer, and temperature transducer in
order to derive and report gross standard oil
volume. A Coriolis flow meter is based on the
principle that fluid mass flow through a tube results
in a measurable twisting or distortion and
consequent oscillation of the tube. Sensors measure
that oscillation and allow for a determination of
various variables, including volume.
7 As explained in the proposed rule, since this
equipment was not included in Order 4, the BLM
did not have uniform national performance
standards for these systems, which has led BLM
state and field offices, while approving variances,
to specify their own. The state-by-state approach
results in inconsistencies among offices with
respect to the requirements imposed on operators.
8 The Durango Herald, New hazard with oilfield
work, March 7, 2016; https://
www.durangoherald.com/article/20160307/
NEWS01/160309666/New-hazard-with-oilfieldwork.
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gives operators an additional tool to
address growing safety concerns.9
In recognition that new measurement
technologies and processes, like CMSs
and ATG systems, will continue to be
developed and evolve, the final rule
puts in place a process and criteria that
will allow for a new Production
Measurement Team (PMT) to review,
and for the BLM to approve for use
nationwide, new measurement
technologies that are demonstrated to be
reliable and accurate.10 Under this new
system, operators would have to prove
to the BLM that new technologies meet
or exceed this rule’s new uncertainty
performance standards, which for the
first time give the BLM a set of objective
criteria that can be applied to evaluate
and approve any new meters, electronic
components, computers, software, and
procedures not specifically addressed in
these regulations. Unlike the current
variance system where operators must
make such a showing each and every
time they wish to deploy a new
technology, under the PMT approach,
once a technology has been approved by
the BLM based on the PMT’s review,
that technology can be employed at
additional facilities or by additional
operators without a subsequent BLM
approval, so long as those facilities and
operators follow all conditions of
approval (COAs) established by the
PMT.
Recognizing the newness of the PMT
process, the final rule includes a 2-year
phase-in for that system. Over the next
2 years, the BLM will develop and post
on its Web site an uncertainty calculator
that will help the BLM and industry
determine if a particular measurement
system or a new device meets the rule’s
uncertainty requirements. As an
operator designs a new system, the
operator can plug its components into
the calculator and know before
installing the system whether that
system meets the requirements, and
could be approved by the PMT. Once
the BLM approves a new technology for
use, it will post the make, model, size,
or software version on its Web site as
9 In recent months this safety issue has been
highlighted by news reports of the deaths of oil
workers who died after manually opening oil tank
hatches and being exposed to toxic fumes.
10 The PMT is distinct from the Interior’s Gas and
Oil Measurement Team (DOI GOMT), which
consists of members with gas or oil measurement
expertise from the BLM, the ONRR, and the Bureau
of Safety and Environmental Enforcement (BSEE).
BSEE handles production accountability for Federal
offshore leases. The DOI GOMT is a coordinating
body that enables the BLM and BSEE to consider
measurement issues and track developments of
common concern to both agencies. The BLM
expects that the members of the BLM PMT would
participate as part of the DOI GOMT.
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approved for use for all operators
nationwide.
With respect to the PMT, it should be
noted that while the final rule provides
that the PMT will review requests and
make recommendations to the BLM for
approval, it is the BLM’s intent that
such approvals will be issued by a BLM
AO with authority over the oil and gas
program nationally (e.g., the Director, a
Deputy Director, or an Assistant
Director), as opposed to that authority
being delegated to a local level. This is
consistent with recommendations from
the RPC, GAO, and OIG that decisions
on variances be granted at the national
level to ensure they are consistent and
have the appropriate perspective, as
opposed to more local levels, which can
result in inconsistencies among BLM
field offices.
In another important departure from
Order 4, this final rule avoids, where
possible, cookbook-style lists of
requirements for operators to follow
when determining oil quantity and
quality. Instead, in many instances, the
rule simply requires operators to follow
the applicable industry standards,
which were developed through a
consensus process by professional
industry groups, with input from
Federal oil and gas experts. In each
instance, the BLM carefully reviewed
the applicable standards and
determined they are technically
sufficient to meet the BLM’s production
verification needs and are structured in
such a way that they can be enforced by
BLM personnel in the field. The
incorporation of industry standards into
the final rule gives operators more
flexibility to comply with the
requirements of these regulations. For
example, Order 4 had one specific way
for operators to measure oil
temperature—by inserting a
thermometer in the approximate vertical
center of the fluid column, not less than
12 inches from the tank shell for 5
minutes. The final rule still allows
operators to measure oil temperature
using this method, but they can now
also follow American Petroleum
Institute (API) Chapter 7 standards,
which provide for operators to use builtin tank thermometers or to take
measurements from the flow lines that
lead to the haulers’ trucks.
The rule also adopts a number of
smaller changes which, taken together,
will increase measurement accuracy,
increase verifiability, and reduce waste.
First, it would prohibit the use of
automatic temperature/gravity
compensators on lease automatic
custody transfer (LACT) systems, which
are required equipment under Order 4.
These compensators automatically
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adjust LACT totalizer readings to
account for temperature effects and, in
some cases, oil gravity effects on
volume. However, because these
automatic compensators do not
maintain the raw data the BLM needs to
verify that the compensators are
functioning correctly or that the
totalizer readings are correct, this rule
requires operators to use temperature
averaging devices instead, which record
and average the temperatures of the
fluids flowing through the LACT. This
requirement ensures that the necessary
audit trail is maintained. Such a system
strikes the right balance because it gives
operators the data they need to
manually correct the volumes from the
totalizer for the effects of temperature
and oil gravity, while ensuring that the
BLM has the raw data needed to verify
the results and confirm system
functionality.
Finally, the rule requires all oil
storage tanks, hatches, connections, and
other access points to be installed and
maintained in accordance with
manufacturers’ specifications. This
requirement, in effect, requires
operators to maintain the pressurevacuum integrity that manufacturers
designed and built into their equipment.
This in turn will minimize hydrocarbon
gas lost to the atmosphere.
II. Overview of Final Rule, Section-bySection Analysis and Response to
Comments on the Proposed Rule
A. General Overview of the Final Rule
As discussed in the background
section of this preamble, the BLM’s
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rules concerning oil measurement found
in Order 4 have not kept pace with
industry standards and practices,
statutory requirements, or applicable
measurement technology and practices.
The final rule enhances the BLM’s
overall production accountability efforts
by addressing these concerns and
ensuring that the oil produced from
Federal and Indian (except Osage Tribe)
leases is adequately accounted for,
ultimately ensuring that all royalties
due are paid.
The following table provides an
overview of the changes between the
proposed rule and this final rule. A
similar chart explaining the differences
between the proposed rule and Order 4
appears in the proposed rule at 80 FR
58955–58956.
Final rule
Substantive changes
43 CFR 3174.1—Definitions and
Acronyms.
43 CFR 3174.1—Definitions and
Acronyms.
43 CFR 3174.2—General Requirements.
43 CFR 3174.2—General Requirements.
43 CFR 3174.3—Specific Measurement Performance Requirements.
43 CFR 3174.3—Incorporation by
Reference.
43 CFR 3174.4—Incorporation by
Reference.
43 CFR 3174.4—Specific Measurement Performance Requirements.
43 CFR 3174.5 and 3174.6—Oil
Measurement by Manual Tank
Gauging.
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Proposed rule
43 CFR 3174.5 and 3174.6—Oil
Measurement by Tank Gauging.
The final rule removes definitions for ‘‘registered volume,’’ ‘‘resistance
thermal device,’’ and ‘‘turbulent flow.’’ It changes the definitions for
‘‘base pressure’’ and ‘‘Coriolis meter.’’ It adds new definitions for
‘‘indicated volume’’ and ‘‘transducer.’’
The final rule gives operators a phase-in period of 1 to 4 years after
the rule’s effective date to bring existing facility measurement point
(FMP) equipment into compliance. This timeframe is based on the
operators’ production volumes and it coincides with their schedule
for applying for their FMP numbers. A new paragraph (g) in this
section delays for 2 years a requirement that operators begin using
approved equipment listed on the BLM website (www.blm.gov).
The final rule adopts the latest versions of certain API standards and
incorporates them by reference into the BLM’s oil and gas regulations. It incorporates by reference many API standards that did not
appear in the proposed rule and removes two industry standards
developed by the American Society for Testing and Materials
(ASTM).
The final rule establishes two thresholds for overall oil measurement
uncertainty levels. For FMPs measuring greater than or equal to
30,000 barrels (bbl)/month, the maximum uncertainty is ±0.50 percent. For FMPs measuring less than 30,000 bbl/month, the maximum uncertainty level is ±1.50 percent. Paragraph (d) is revised to
clarify that the PMT, following the process outlined in § 3174.13,
will make a determination whether proposed alternative equipment
or measurement procedures meet or exceed the objectives and intent of this section.
The final rule requires operators to submit sales tank calibration
charts (tank tables) to the authorized officer (AO) within 45 days
after calibrating or recalibrating. It allows operators to use ATG
systems and, by replacing prescriptive language with additional industry standards, it gives operators more options for tank gauging,
sampling, calibrating sales tanks, and determining temperature, oil
gravity, and sediment and water (S&W) content. The final rule
specifies manual gauging accuracy to the nearest 1⁄4 inch for tanks
of 1,000 bbl or less and gauging accuracy to the nearest 1⁄8 inch
for tanks greater than 1,000 bbl. All oil storage tanks must be
clearly identified with an operator-generated unique number.
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Final rule
Substantive changes
43 CFR 3174.7 and 3174.8—LACT
Systems.
43 CFR 3174.7 and 3174.8—
LACT Systems.
43 CFR 3174.9—Coriolis Measurement System—General Requirements and Components.
43 CFR 3174.9—Coriolis Measurement System—General Requirements and Components.
43 CFR 3174.10—Coriolis Measurement System—Operating Requirements.
43 CFR 3174.10—Coriolis meter
for LACT and CMS Measurement Applications.
43 CFR 3174.11—Meter-Proving
Requirements.
43 CFR 3174.11—Meter-Proving
Requirements.
43 CFR 3174.12—Measurement
Tickets.
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Proposed rule
43 CFR 3174.12—Measurement
Tickets.
43 CFR 3174.13—Oil Measurement
by Other Methods.
43 CFR 3174.13—Oil Measurement by Other Methods.
The final rule requires operators to notify the AO of any LACT system
failures or equipment malfunctions, or other failures that could adversely affect oil measurement within 72 hours upon discovery.
The requirement in proposed § 3174.7(b) that operators generate
an additional run ticket before proving a LACT system has been
modified. A related change in § 3174.12(b)(1) makes it clear that
LACT systems that use flow computers are exempt from the requirement that operators close a run ticket before proving a LACT
system. The table in proposed § 3174.7(c) entitled, ‘‘Standards to
Measure Oil by a LACT System,’’ has been removed and in its
place the final rule requires operators to complete measurement
tickets as required under § 3174.12(b). Industry standards have
been added to replace prescriptive language in the proposed rule.
This gives operators more choices for collecting, mixing, and analyzing samples. The final rule clarifies that LACT systems may
have either a Coriolis meter or a positive displacement (PD) meter.
The final rule is revised to clarify that operators can use CMSs as a
standalone unit, independent of a LACT system. The table in paragraph (d) entitled, ‘‘Standards Applicable to CMS Use,’’ has been
removed and in its place the final rule requires operators to complete measurement tickets, as required under § 3174.12(b). Prescriptive language in proposed paragraph (e) that dictated which
CMS components should be used during set up and installation of
a CMS, for the most part, has been removed and replaced with industry standards, which give operators more flexibility. The requirement for a back pressure valve has been removed and operators
may use any means to apply sufficient back pressure to ensure
single-phase flow so long as it meets industry standard API 5.6. Industry standards have been added to give operators more options
for automatic sampling and for mixing and handling samples. A
new paragraph (g) has been added that requires operators to follow API 12.2.1 and API 12.2.2 for calculating net standard volume.
A similar, more prescriptive requirement for calculating net standard volume appeared in proposed § 3174.10(g), which has been removed from the final rule.
Requirement for straight piping upstream and downstream of a meter
has been removed from the final rule. The requirement for verifying
the meter zero value is revised to be less prescriptive and instead
requires operators to follow manufacturers’ specifications and procedures. The requirement that operators keep the log containing
the meter factor, zero verification, and zero adjustments on site
has been changed to require them to make it available to the AO
upon request.
The final rule requires proving every 3 months (quarterly) after last
proving, or after every 75,000 bbl of volume flows through the
meter, whichever comes first, but no more frequently than monthly.
The rule includes verification requirements for pressure, temperature, and density measurement devices with each proving. The
table in proposed paragraph (b) entitled, ‘‘Minimum Standards for
Proving FMP Meters,’’ has been removed because it is not needed. The proposed requirement for master meter repeatability of
0.0002 (0.02 percent) has been changed to 0.0005 (0.05 percent).
The frequency for proving master meters is no less than once
every 12 months. The final rule replaces prescriptive language that
dictated the sizes and proving frequencies of displacement provers
with requirements that operators follow industry standards. Paragraph (c)(4) adds the requirement that operators follow industry
standards when calculating the average meter factor. Paragraph
(c)(6) contains new language on how to utilize multiple meter factors. Meter-proving reports may be submitted to the AO in either
hard-copy or electronic format.
The final rule requires that oil measurement tickets for LACT systems
and CMS be closed at the end of each month and before proving
unless utilizing flow computers. The rule allows the use of electronic measurement tickets. The final rule no longer requires the
operator’s representative to certify that the measurement on a
completed run ticket is correct. The final rule has also removed the
requirement that operators must notify the AO within 7 days if they
disagree with a tank gauger’s measurement.
None.
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Proposed rule
Final rule
43 CFR 3174.14—Determination of
Oil Volumes by Methods Other
Than Measurement.
43 CFR 3174.15—Immediate Assessments.
43 CFR 3174.14—Determination
of Oil Volumes by Methods
Other Than Measurement.
43 CFR 3174.15—Immediate Assessments.
B. Section-by-Section Analysis of the
Final Rule and Response to Comments
on Specific Provisions of the Proposed
Rule
This final rule is codified primarily in
a new 43 CFR subpart 3174 within a
new part 3170. In addition to this rule,
the BLM has also prepared separate
rules to update and replace Onshore Oil
and Gas Order Number 3 (Order 3) (site
security), which will be codified at a
new 43 CFR subpart 3173; and Onshore
Oil and Gas Order Number 5 (Order 5)
(gas measurement), which will be
codified at a new 43 CFR subpart 3175.
The rules to replace Orders 3 and 5 are
being published concurrently with this
rule. In addition to establishing a new
43 CFR subpart 3173, the rule to replace
Order 3 establishes 43 CFR part 3170
and subpart 3170. Subpart 3170
contains definitions of certain terms
common to more than one of these
rules, as well as other provisions
common to all of the rules, such as
provisions prohibiting bypass of and
tampering with meters; procedures for
obtaining variances from the
requirements of a particular rule;
requirements for recordkeeping, records
retention, and submission; and
administrative appeal procedures. All of
the definitions and substantive
provisions of subpart 3170 also apply to
this new subpart 3174.
Certain provisions of this final rule
will result in amendments to related
provisions in the onshore oil and gas
operations rules in 43 CFR part 3160.
The amendments to those provisions are
also discussed below.
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Subpart 3174 and Related Provisions
Section 3174.1 Definitions and
Acronyms
Section 3174.1 defines terms and
acronyms used in subpart 3174.
Defining these terms and acronyms is
necessary to ensure consistent
interpretation and implementation of
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Substantive changes
None.
The final rule removes one of the six violations listed in the proposed
rule: Failure to notify the AO within 7 days of any changes to any
CMS internal calibration factors (proposed violation #4). Of the five
remaining violations listed, the final rule changes the timeframe
from ‘‘within 24 hours’’ to ‘‘within 72 hours’’ that operators must notify the AO of any LACT system failure or equipment malfunction
resulting in use of an unapproved alternative method of measurement (violation #2 in the final rule). The final rule also removes the
word ‘‘variance’’ from the violation of failure to obtain a written approval before using any oil measurement method other than tank
gauging, LACT system, or CMS at an FMP (violation #5 in the final
rule).
this rule. The BLM received a number
of comments on this section. Except as
noted in this section, the terms and
acronyms in § 3174.1 did not change
between the draft and final rule. A
summary of the definitions and
acronyms that were not changed in the
final rule may be found in the proposed
rule.
Several commenters recommended
that base pressure should be defined as
14.696 pounds per square inch, absolute
(psia), as opposed to defining it, as in
the proposed rule, as the atmospheric
pressure or the vapor pressure of the
liquid at 60 °F, whichever is higher.
Subsequent research has shown that
base pressure should be defined as a
fixed amount and therefore the BLM
agrees with these comments. As a result,
the definition of base pressure has been
changed to 14.696 psia in the final rule.
Several commenters had concerns
about the definition of Coriolis meter
and Coriolis metering system (CMS).
They suggested we replace the word
‘‘measures’’ in the definition of Coriolis
meter with the word ‘‘infers.’’ The BLM
agrees with this comment because the
Coriolis meter does not actually
measure volume directly as a positive
displacement (PD) meter does, by
isolating the flowing liquid into
segments of known volume, but instead
analyzes the interaction between the
flowing fluid and the oscillation of the
tubes. As a result, the definition of
Coriolis has been changed to say that a
Coriolis meter infers a mass flow rate.
Another commenter said the definition
of CMS should be changed to say the
CMS reports ‘‘net standard oil volume’’
instead of ‘‘net oil volume,’’ while
another commenter noted that the
Coriolis meter displays ‘‘gross,’’ not
‘‘net’’ standard volumes. The BLM
agrees with these suggestions because
the Coriolis meter is capable of
correcting to gross standard volume, but
not capable of deducting the S&W
content to derive net standard volumes.
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The definition has been changed in the
final rule to ‘‘gross standard volume’’ as
a result of this comment.
Another commenter requested that we
include a definition in the rule for
‘‘vapor tight.’’ The proposed rule at
§ 3174.5(b)(3) required all oil storage
tanks, hatches, connections, and other
access points to be vapor tight. The BLM
agrees that the term ‘‘vapor tight’’
should be defined and has defined the
term to mean capable of holding
pressure differential only slightly higher
than that of installed pressure-relieving
or vapor recovery devices.
A few commenters suggested that all
of the definitions in the rule should
come from the API standards, rather
than be the BLM’s own customized
definitions. After comparing the API
definitions against the BLM’s
definitions in the rule, the BLM does
not agree with this suggestion. Not all
API definitions fit the terms used in the
rule. For example, one commenter said
the BLM should use the API definition
for LACT systems, which defines
turbine meters as an example of a meter
that can be part of a LACT system. The
BLM disagrees with this comment
because the rule does not allow turbine
meters to be used at a FMP. The BLM
has used many API definitions in the
rule, but not all of them are suitable for
this rule, therefore, this rule was not
changed as a result of these comments.
Three commenters suggested that we
include definitions for the acronyms
‘‘AO,’’ authorized officer; ‘‘PA,’’
participating area; and ‘‘CA,’’
communitization agreement. The
definitions for the acronyms AO, PA,
and CA are included in the definitions
section of 43 CFR subpart 3170, which
is in a related rulemaking previously
discussed. As a result, no change was
made to this rule as a result of these
comments.
One commenter suggested that we not
use the term ‘‘registered volume,’’ but
rather the term ‘‘indicated volume.’’ The
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BLM agrees that the term ‘‘indicated
volume’’ is a more appropriate term for
the definition and aligns with common
industry language, and as a result has
changed the definition in the rule to
reflect the definition for indicated
volume.
One commenter said the term
‘‘resistance thermal device’’ is not a
common industry term and suggested
we change it to ‘‘resistance thermal
detector.’’ As a result of this comment
and a review of comments and changes
to other sections, the term and
definition for ‘‘resistance thermal
device’’ has been removed and replaced
by the term ‘‘transducer.’’ Transducer
has been defined to be an electronic
device that converts a physical
property—such as pressure,
temperature, or electrical resistance—
into an electrical output signal that
varies proportionally with the
magnitude of the physical property.
This defines a broader spectrum of
devices and can include a resistance
thermal detector. This use of the term
‘‘transducer’’ aligns with common
industry practice and better suits the
BLM’s objective of ensuring that there is
sufficient flexibility built into the rule.
One commenter suggested that we
change our definition of ‘‘turbulent
flow’’ to include a reference to the
common measure for determining the
flow, which is by Reynolds number.
Since the final rule does not contain the
turbulent-flow requirements that
appeared in the proposed rule at
§ 3174.8(b)(1), the BLM has removed
this term from the definitions section.
Based on changes to other sections
resulting in new terms being
introduced, a definition for ‘‘dynamic
meter factor’’ has been included as
meaning a kinetic meter factor derived
by linear interpolation or polynomial fit,
used for conditions where a series of
meter factors have been determined over
a range of normal operating conditions.
In the revised non-prescriptive structure
of the final rule, the term ‘‘opaque oil’’
is no longer used, as such the definition
has been removed.
Section 3174.2 General Requirements
Paragraphs (a) through (d) of § 3174.2
refer the reader to other sections in this
rule and to 43 CFR subpart 3173, which
is addressed in the rulemaking to
replace Order 3. That rulemaking
contains the requirements for oil storage
tanks, on-lease oil measurement,
commingling, and FMP numbers,
respectively. All comments received on
these paragraphs are addressed in the
corresponding section discussions later
in this preamble and in the preamble for
43 CFR subpart 3173.
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Section 3174.2(e) specifies that all
equipment used to measure the volume
of oil for royalty purposes at an FMP
installed after the effective date of this
subpart must comply with the
requirements of this subpart. The BLM
received no comments on this
requirement.
Section 3174.2(f) requires that
measuring procedures and equipment
used to measure oil for royalty purposes
that are in use on the effective date of
this rule, must comply with the
requirements of this subpart on or
before the date the operator is required
to apply for an FMP number under
3173.12(e) of this part. Prior to that date,
measuring procedures and equipment
used to measure oil for royalty
purposes, that is in use on the effective
date of this rule, must continue to
comply with the requirements of
Onshore Oil and Gas Order No. 4,
Measurement of oil, 54 FR 8086 (Feb 24,
1989), and any COAs and written orders
applicable to that equipment.
The proposed rule would have
required operators to bring existing
equipment used at FMPs into
compliance within 180 days after the
effective date of the final rule. Many
commenters said 180 days is not enough
time to plan for and bring existing
equipment into compliance. The BLM
agrees, and in response, this final rule
provides a phase-in period of 1 to 4
years after the rule’s effective date to
bring existing equipment into
compliance.
The 1- to 4-year phase-in period is
based on the time-frames established for
operators to apply for their FMP
numbers, which is provided for in 43
CFR 3173.12 and is addressed in a
related rulemaking that is updating and
replacing Order 3. This modified
implementation timeframe in the final
rule links compliance with the oil
measurement requirement to an
operator’s production volumes, with
lower-volume producers having more
time to comply. Under this new
approach, the highest 25 percent of the
producing leases, CAs, or unit PAs are
required to be in compliance the
earliest—within 12 months of the
effective date of this rule. All remaining
leases, CAs, or unit PAs, based on
volume thresholds, are staged out over
the following 3 years.
Commenters’ greatest concern with
the 180-day deadline was that it was not
enough time to generate new oil-storagetank calibration tables that would have
allowed them to measure volumes in 1⁄8inch increments, as required in § 3174.6
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of the proposed rule.11 That is no longer
a concern, however, because the final
rule does not require that volumes be
measured in 1⁄8-inch increments.
In the proposed rule, the BLM
proposed switching to the 1⁄8-inch
gauging accuracy for all tanks in order
to meet one objective of the rule—to
bring the oil measurement regulations
up to current industry standards.
However, API has two contradictory
standards for manual gauging
measurement accuracy on oil storage
tanks—API 3.1A calls for 1⁄8-inch
gauging accuracy for all tanks, while
API 18.1 calls for a 1⁄4-inch gauging
accuracy for tanks of 1,000 bbl or less.
Based on this change in industry
standards and its own experience, the
BLM assumed that new calibration
tables could be generated from existing
tank strapping measurements.
Commenters disagreed, saying operators
would have to hire engineering
companies to reanalyze some 40,000
sales tanks across the nation. They said
numerous tanks would have to be
physically re-measured, or re-strapped.
Some commenters said that, due to
budgeting, equipment, and weather
constraints, it could take them a year to
re-strap their tanks. Others said it could
take months to do the job.
As discussed later in § 3174.6, the
BLM has decided to retain the 1⁄4-inch
gauging accuracy requirement for oil
tanks with a capacity of 1,000 bbl or
less, which is the current requirement,
eliminating the need for operators to restrap their tanks. To implement these
standards, the BLM plans to develop a
liquids uncertainty calculator that will
allow its inspectors to enforce oil tank
measurement uncertainty requirements
for operators who elect to use automatic
and hybrid tank gauging systems. It will
take the BLM about 2 years to develop
the uncertainty calculator and verify
that automated equipment meets the
uncertainty standards. During this time,
operators who use automatic and hybrid
tank gauging systems will still have to
meet the measurement performance
requirements.
Some commenters argued that
existing equipment used at FMPs
should not have to meet any deadline
for coming into compliance with this
rule’s requirement and should instead
be exempted from complying entirely
(that is, grandfathered).
For example, one commenter said the
BLM should grandfather all existing
11 Order 4 requires 1⁄4-inch gauging accuracy for
tanks with a capacity of 1,000 bbl or less and
requires strapping tables at 1⁄4-inch increments. For
tanks with a capacity greater than 1,000 bbl, Order
4 requires a 1⁄8-inch gauging accuracy and strapping
tables at 1⁄8-inch increments.
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equipment, but require all new
installations or installations that
undergo repairs costing more than 50
percent of the cost of new equipment to
meet the new standards. The BLM does
not agree with this proposed change for
several reasons. The rule’s only
equipment retrofit requirement is that
all automatic temperature/gravity
compensators be replaced with
temperature averagers. Temperature
averagers are relatively inexpensive,
costing around $6,500 per device, and
automatic temperature/gravity
compensators are not used on very
many LACT systems. The BLM
estimates that over 80 percent of all
LACTs on Federal and Indian leases
already have temperature averagers
installed. A second issue the BLM has
with this proposed change is that it
would require the BLM to monitor all
maintenance activity and estimate costs
of repairs on ‘‘grandfathered’’
equipment. Finally, the commenter did
not explain or provide justification for
how this proposed change would be
preferable to the proposed rule.
Another commenter said, as an
alternative to grandfathering, equipment
serving low-volume and marginal FMPs
should be exempted from the
requirements. The BLM does not see a
need for this exemption because lowvolume or marginal wells will, in most
cases, be measured by manual tank
gauging. Since the tank-gauging
requirements in this final rule have not
changed relative to the requirements in
Order 4, this change was unnecessary.
Another commenter disagreed with
the proposed rule’s prohibition of
automatic temperature/gravity
compensators. These compensators
should be grandfathered, the commenter
said, as long as an audit trail exists
whereby the raw data is available and
the final results from the compensators
can be recreated from this data. The
commenter further stated that systems
that cannot provide such data should be
grandfathered in the final rule. The BLM
disagrees. The fact remains that
automatic compensator systems alter the
raw data before any audit trail is
created. They automatically change a
meter’s totalizer readings, erasing the
raw data that the BLM and the operator
need to verify that the compensators are
functioning correctly and that the
totalizer reading is correct.
Another commenter said that if
existing equipment is not grandfathered,
operators may need to install new LACT
units in order to comply, which in turn
would require operators to re-pipe their
wells. According to this commenter, this
would result in undue surface
disturbance, excessive expenses, strain
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on the labor force, and wells that are
currently in secondary recovery or that
do not produce large amounts of oil
being plugged prematurely, leaving
behind undeveloped and valuable
resources. The BLM disagrees with this
interpretation of the rule’s requirements.
The only equipment that would have to
be replaced at an FMP under both the
proposed and final rules is the
automatic temperature/gravity
compensator, which is only one
component of a PD meter of a LACT
unit. Operators must replace these
devices with temperature averagers,
which allow operators to collect and
retain the raw data the BLM needs to
verify results and confirm and preserve
system functionality. Based on the
BLM’s experience, this replacement can
occur without replacing the entire LACT
system. Additionally, as explained
elsewhere in this preamble, most
existing LACT systems do not use
automatic temperature/gravity
compensators.
One commenter said the midstream
sector (the pipeline companies and
processing plants at or downstream of
the meters) would suffer if the rule does
not grandfather existing equipment. The
commenter did not explain or specify
any negative impacts on the midstream
sector from the requirement that
operators replace automatic
temperature/gravity compensators on
LACTs. The BLM is not aware of any
negative impacts this would have on the
midstream sector and the commenter
did not provide any information on how
the midstream sector will suffer from
accurate, verifiable measurement on a
lease, PA, or CA. As a result, the BLM
does not agree with the commenter and
no change has been made to the rule
based on this comment.
Several commenters said properly
operating equipment should be
grandfathered, and, if it must be
replaced, operators should be allowed to
negotiate installation timeframes with
local BLM field offices. The BLM
believes that this recommendation
would perpetuate the problem of
program requirements being
inconsistently applied from state to state
or field office to field office and
therefore did not change the rule as a
result of these comments. One of the
primary goals of this final rule is to
provide some nationwide consistency as
to the application of these requirements.
Another commenter said that existing
facilities and equipment should be
grandfathered because operators could
not afford an ‘‘investment of this
magnitude’’ to retrofit equipment to
meet the new standards. The commenter
did not provide any details regarding
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what is meant by an ‘‘investment of this
magnitude.’’ The BLM disagrees with
the implication that replacing automatic
temperature/gravity compensators on a
LACT is a significant investment. The
cost to replace automatic temperature/
gravity compensators on LACT systems
with temperature averagers is relatively
minor—approximately $6,500 per
system. No change resulted from this
comment.
The BLM does not believe that
existing equipment should be
grandfathered. For years, the GAO and
industry have voiced concerns that the
BLM’s measurement regulations are
outdated and make it harder for the
BLM to have reasonable assurance that
production is being accurately measured
and verified. This rule aims to address
these concerns at both new and existing
facilities.
Section 3174.2(g) exempts meters that
are used for allocation measurement as
part of commingling approvals from
complying with the requirements of this
subpart. Commingling approvals will be
governed under new requirements in 43
CFR 3173.14, which are addressed in
the rulemaking that is updating and
replacing Order 3. One commenter said
that meters used for allocating
production from wells in approved
commingling arrangements or that are in
the same unit, PA, or CA should be
required to meet API standards for
allocation measurement. The
commenter did not state a reason for
this suggestion. Since the BLM does not
want to impose blanket allocation
measurement requirements that may not
be relevant to every situation, it did not
adopt this suggestion. Instead, the final
rule retains the AO’s discretion to
include those requirements as a
condition of approval on a case-by-case
basis.
Section 3174.3 Incorporation by
Reference (IBR)
This section previously appeared as
§ 3174.4 in the proposed rule, but based
on edits made to the final rule, this
section and proposed § 3174.3 have
been switched. All comments discussed
below were submitted for the previously
proposed § 3174.4.
This rule incorporates a number of
industry standards and recommended
practices, either in whole or in part,
without republishing the standards in
their entirety in the CFR, a practice
known as IBR. These standards have
been developed through a consensus
process, facilitated by the API, with
input from the oil and gas industry and
Federal agencies with oil and gas
operational oversight responsibilities.
The BLM has reviewed these standards
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and determined that they will achieve
the intent of 43 CFR 3174.4 through
3174.13 of this rule. The legal effect of
IBR is that the incorporated standards
become regulatory requirements. With
the approval of the Director of the
Federal Register, this rule incorporates
the current versions of the standards
listed.
Some of the standards referenced in
this section have been incorporated in
their entirety. For other standards, the
BLM incorporates only those sections
that are relevant to the rule, meet the
intent of § 3174.3 of the rule, and do not
need further clarification.
The incorporation of industry
standards follows the requirements
found in 1 CFR part 51. The industry
standards in this final rule are eligible
for incorporation under 1 CFR 51.7
because, among other things, they will
substantially reduce the volume of
material published in the Federal
Register; the standards are published,
bound, numbered, and organized; and
the standards incorporated are readily
available to the general public through
purchase from the standards
organization or through inspection at
any BLM office with oil and gas
administrative responsibilities (1 CFR
51.7(a)(3) and (a)(4)). The language of
incorporation in § 3174.3 meets the
requirements of 1 CFR 51.9. Where
appropriate, the BLM has incorporated
by reference an industry standard
governing a particular process and then
imposed requirements that add to or
modify the requirements imposed by
that standard (e.g., the BLM sets a
specific value for a variable where the
industry standard proposed a range of
values or options).
All of the API materials that the BLM
is incorporating by reference are
available for inspection at the BLM,
Division of Fluid Minerals; 20 M Street
SE; Washington, DC 20003; 202–912–
7162; and at all BLM offices with
jurisdiction over oil and gas activities.
The API materials are available for
inspection and purchase at the API,
1220 L Street NW., Washington, DC
20005; telephone 202–682–8000; API
also offers free, read-only access to some
of the material at https://
publications.api.org.
The following describes the API
standards that the BLM has
incorporated by reference into this rule:
API Manual of Petroleum
Measurement Standards (MPMS)
Chapter 2—Tank Calibration, Section
2A, Measurement and Calibration of
Upright Cylindrical Tanks by the
Manual Tank Strapping Method; First
Edition, February 1995; Reaffirmed
February 2012 (‘‘API 2.2A’’). This
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standard describes the procedures for
calibrating upright cylindrical tanks
used for storing oil.
API MPMS Chapter 2—Tank
Calibration, Section 2.2B, Calibration of
Upright Cylindrical Tanks Using the
Optical Reference Line Method; First
Edition, March 1989; Reaffirmed
January 2013 (‘‘API 2.2B’’). This
standard describes measurement and
calibration procedures for determining
the diameters of upright welded
cylindrical tanks, or vertical cylindrical
tanks with a smooth surface and either
floating or fixed roofs.
API MPMS Chapter 2—Tank
Calibration, Section 2C, Calibration of
Upright Cylindrical Tanks Using the
Optical-triangulation Method; First
Edition, January 2002; Reaffirmed May
2008 (‘‘API 2.2C’’). This standard
describes a calibration procedure for
applications to tanks above 26 feet in
diameter with cylindrical courses that
are substantially vertical.
API MPMS Chapter 3, Section 1A,
Standard Practice for the Manual
Gauging of Petroleum and Petroleum
Products; Third Edition, August 2013
(‘‘API 3.1A’’). This standard describes
the following: (a) The procedures for
manually gauging the liquid level of
petroleum and petroleum products in
non-pressure fixed roof tanks; (b)
Procedures for manually gauging the
level of free water that may be found
with the petroleum or petroleum
products; (c) Methods used to verify the
length of gauge tapes under field
conditions and the influence of bob
weights and temperature on the gauge
tape length; and (d) Influences that may
affect the position of gauging reference
point (either the datum plate or the
reference gauge point).
API MPMS Chapter 3—Tank Gauging,
Section 1B, Standard Practice for Level
Measurement of Liquid Hydrocarbons in
Stationary Tanks by Automatic Tank
Gauging; Second Edition, June 2001;
Reaffirmed August 2011 (‘‘API 3.1B’’).
This standard describes the level
measurement of liquid hydrocarbons in
stationary, above ground, atmospheric
storage tanks using automatic tank
gauges (ATG). This standard discusses
automatic tank gauging in general,
accuracy, installation, commissioning,
calibration, and verification of ATG that
measure either innage or ullage.
API MPMS Chapter 3—Tank Gauging,
Section 6, Measurement of Liquid
Hydrocarbons by Hybrid Tank
Measurement Systems; First Edition,
February 2001; Errata September 2005;
Reaffirmed October 2011 (‘‘API 3.6’’).
This standard describes the selection,
installation, commissioning, calibration,
and verification of Hybrid Tank
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Measurement Systems. This standard
also provides a method of uncertainty
analysis to enable users to select the
correct components and configurations
to address for the intended application.
API MPMS Chapter 4—Proving
Systems, Section 1, Introduction; Third
Edition, February 2005; Reaffirmed June
2014 (‘‘API 4.1’’). Section 1 is a general
introduction to the subject of proving
meters.
API MPMS Chapter 4—Proving
Systems, Section 2, Displacement
Provers; Third Edition, September 2003;
Reaffirmed March 2011 (‘‘API 4.2’’).
This standard outlines the essential
elements of meter provers that do, and
also do not, accumulate a minimum of
10,000 whole meter pulses between
detector switches, and provides design
and installation details for the types of
displacement provers that are currently
in use. The provers discussed in this
chapter are designed for proving
measurement devices under dynamic
operating conditions with single-phase
liquid hydrocarbons.
API MPMS Chapter 4, Section 5,
Master-Meter Provers; Fourth Edition,
June 2016 (‘‘API 4.5’’). This standard
covers the use of displacement and
Coriolis meters as master meters. The
requirements in this standard are for
single-phase liquid hydrocarbons.
API MPMS Chapter 4—Proving
Systems, Section 6, Pulse Interpolation;
Second Edition, May 1999; Errata April
2007; Reaffirmed October 2013 (‘‘API
4.6’’). This standard describes how the
double-chronometry method of pulse
interpolation, including system
operating requirements and equipment
testing, is applied to meter proving.
API MPMS Chapter 4, Section 8,
Operation of Proving Systems; Second
Edition September 2013 (‘‘API 4.8’’).
This standard provides information for
operating meter provers on single-phase
liquid hydrocarbons.
API MPMS Chapter 4—Proving
Systems, Section 9, Methods of
Calibration for Displacement and
Volumetric Tank Provers, Part 2,
Determination of the Volume of
Displacement and Tank Provers by the
Waterdraw Method of Calibration; First
Edition, December 2005; Reaffirmed
July 2015 (‘‘API 4.9.2’’). This standard
covers all of the procedures required to
determine the field data necessary to
calculate a Base Prover Volume of
Displacement Provers by the Waterdraw
Method of Calibration.
API MPMS Chapter 5—Metering,
Section 6, Measurement of Liquid
Hydrocarbons by Coriolis Meters; First
Edition, October 2002; Reaffirmed
November 2013 (‘‘API 5.6’’). This
standard is applicable to custody-
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transfer applications for liquid
hydrocarbons. Topics covered are API
standards used in the operation of
Coriolis meters, proving and verification
using volume-based methods,
installation, operation, and
maintenance.
API MPMS Chapter 6—Metering
Assemblies, Section 1, Lease Automatic
Custody Transfer (LACT) Systems;
Second Edition, May 1991; Reaffirmed
May 2012 (‘‘API 6.1’’). This standard
describes the design, installation,
calibration, and operation of a LACT
system.
API MPMS Chapter 7, Temperature
Determination; First Edition, June 2001;
Reaffirmed February 2012 (‘‘API 7’’).
This standard describes the methods,
equipment, and procedures for
determining the temperature of
petroleum and petroleum products
under both static and dynamic
conditions.
API MPMS Chapter 7.3, Temperature
Determination—Fixed Automatic Tank
Temperature Systems, Second Edition,
October 2011 (‘‘API 7.3’’). This standard
describes the methods, equipment, and
procedures for determining the
temperature of petroleum and
petroleum products under static
conditions using automatic methods.
API MPMS Chapter 8, Section 1,
Standard Practice for Manual Sampling
of Petroleum and Petroleum Products;
Fourth Edition, October 2013 (‘‘API
8.1’’). This standard covers procedures
and equipment for manually obtaining
samples of liquid petroleum and
petroleum products from the sample
point into the primary containers.
API MPMS Chapter 8, Section 2,
Standard Practice for Automatic
Sampling of Petroleum and Petroleum
Products; Third Edition, October 2015
(‘‘API 8.2’’). This standard describes
general procedures and equipment for
automatically obtaining samples of
liquid petroleum, petroleum products,
and crude oils from a sample point into
a primary container.
API MPMS Chapter 8—Sampling,
Section 3, Standard Practice for Mixing
and Handling of Liquid Samples of
Petroleum and Petroleum Products;
First Edition, October 1995; Errata
March 1996; Reaffirmed, March 2010
(‘‘API 8.3’’). This standard covers the
handling, mixing, and conditioning
procedures required to ensure that a
particular representative sample of the
liquid petroleum or petroleum product
is delivered from the primary sample
container/receiver into the analytical
test apparatus or into intermediate
containers.
API MPMS Chapter 9, Section 1,
Standard Test Method for Density,
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Relative Density, or API Gravity of
Crude Petroleum and Liquid Petroleum
Products by Hydrometer Method; Third
Edition, December 2012 (‘‘API 9.1’’).
This standard covers the determination,
using a glass hydrometer in conjunction
with a series of calculations, of the
density, relative density, or API gravity
of crude petroleum, petroleum products,
or mixtures of petroleum and
nonpetroleum products normally
handled as liquids and having a Reid
vapor pressure of 101.325 kPa (14.696
psi) or less.
API MPMS Chapter 9, Section 2,
Standard Test Method for Density or
Relative Density of Light Hydrocarbons
by Pressure Hydrometer; Third Edition,
December 2012 (‘‘API 9.2’’), This
standard covers the determination of the
density or relative density of light
hydrocarbons including liquefied
petroleum gases having a Reid vapor
pressure exceeding 101.325 kPa (14.696
psi).
API MPMS Chapter 9, Section 3,
Standard Test Method for Density,
Relative Density, and API Gravity of
Crude Petroleum and Liquid Petroleum
Products by Thermohydrometer
Method; Third Edition, December 2012
(‘‘API 9.3’’). This standard covers the
determination, using a glass
thermohydrometer in conjunction with
a series of calculations, of the density,
relative density, or API gravity of crude
petroleum, petroleum products, or
mixtures of petroleum and
nonpetroleum products normally
handled as liquids and having a Reid
vapor pressure of 101.325 kPa (14.696
psi) or less.
API MPMS Chapter 10 Section 4,
Determination of Water and/or
Sediment in Crude Oil by the Centrifuge
Method (Field Procedure); Fourth
Edition, October 2013; Errata March
2015 (‘‘API 10.4’’). This standard
describes the field centrifuge method for
determining both water and sediment,
or sediment only, in crude oil.
API MPMS Chapter 11—Physical
Properties Data, Section 1, Temperature
and Pressure Volume Correction Factors
for Generalized Crude Oils, Refined
Products and Lubricating Oils; May
2004; Addendum 1, September 2007;
Reaffirmed August 2013 (‘‘API 11.1’’).
This standard provides the algorithm
and implementation procedure for the
correction of temperature and pressure
effects on density and volume of liquid
hydrocarbons that fall within the
categories of crude oil.
API MPMS Chapter 12—Calculation
of Petroleum Quantities, Section 2,
Calculation of Petroleum Quantities
Using Dynamic Measurement Methods
and Volumetric Correction Factors, Part
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1, Introduction; Second Edition, May
1995; Reaffirmed March 2014 (‘‘API
12.2.1’’). This standard provides
standardized calculation methods for
the quantification of liquids and the
determination of base prover volumes
under defined conditions. The standard
specifies the equations for computing
correction factors, rules for rounding,
calculational sequences, and
discrimination levels to be employed in
the calculations.
API MPMS Chapter 12—Calculation
of Petroleum Quantities, Section 2,
Calculation of Petroleum Quantities
Using Dynamic Measurement Methods
and Volumetric Correction Factors, Part
2, Measurement Tickets; Third Edition,
June 2003; Reaffirmed September 2010
(‘‘API 12.2.2’’). This standard provides
standardized calculation methods for
the quantification of liquids and
specifies the equations for computing
correction factors, rules for rounding,
calculation sequences, and
discrimination levels to be employed in
the calculations.
API MPMS Chapter 12—Calculation
of Petroleum Quantities, Section 2,
Calculation of Petroleum Quantities
Using Dynamic Measurement Methods
and Volumetric Correction Factors, Part
3, Proving Report; First Edition, October
1998; Reaffirmed March 2009 (‘‘API
12.2.3’’). This standard provides
standardized calculation methods for
the determination of meter factors under
defined conditions. The criteria
contained here will allow different
entities using various computer
languages on different computer
hardware (or by manual calculations) to
arrive at identical results using the same
standardized input data. This document
also specifies the equations for
computing correction factors, including
the calculation sequence, discrimination
levels, and rules for rounding to be
employed in the calculations.
API MPMS Chapter 12—Calculation
of Petroleum Quantities, Section 2,
Calculation of Petroleum Quantities
Using Dynamic Measurement Methods
and Volumetric Correction Factors, Part
4, Calculation of Base Prover Volumes
by the Waterdraw Method; First Edition,
December, 1997; Reaffirmed March
2009; Errata July 2009 (‘‘API 12.2.4’’).
This standard provides standardized
calculation methods for the
quantification of liquids and the
determination of base prover volumes
under defined conditions. The criteria
contained in this document allow
different individuals, using various
computer languages on different
computer hardware (or manual
calculations), to arrive at identical
results using the same standardized
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input data. This standard specifies the
equations for computing correction
factors, rules for rounding, the sequence
of the calculations, and the
discrimination levels of all numbers to
be used in these calculations.
API MPMS Chapter 13—Statistical
Aspects of Measuring and Sampling,
Section 1, Statistical Concepts and
Procedures in Measurements; First
Edition, June 1985; Reaffirmed February
2011, Errata July 2013 (‘‘API 13.1’’).
This standard covers the basic concepts
involved in estimating errors by
statistical techniques and ensuring that
results are quoted in the most
meaningful way. This standard also
discusses the statistical procedures that
should be followed in estimating a true
quantity from one or more
measurements and in deriving the range
of uncertainty of the results.
API MPMS Chapter 13, Section 3,
Measurement Uncertainty; First Edition,
May 2016 (‘‘API 13.3’’). This standard
establishes a methodology for
developing an uncertainty analysis.
API MPMS Chapter 14, Section 3/
American Gas Association Report No. 3,
Orifice Metering of Natural Gas and
Other Related Hydrocarbon Fluids—
Concentric, Square-edged Orifice
Meters, Part 1, Section 12, General
Equations and Uncertainty Guidelines;
Fourth Edition, September 2012; Errata
July 2013 (‘‘API 14.3’’). This standard
provides reference for engineering
equations and uncertainty estimations.
API MPMS Chapter 18—Custody
Transfer, Section 1, Measurement
Procedures for Crude Oil Gathered From
Small Tanks by Truck; Second Edition,
April 1997; Reaffirmed February 2012
(‘‘API 18.1’’). This standard describes
the procedures, organized into a
recommended sequence of steps, for
manually determining the quantity and
quality of crude oil being transferred
under field conditions.
API MPMS Chapter 18, Section 2,
Custody Transfer of Crude Oil from
Lease tanks Using Alternative
Measurement Methods, First Edition,
July 2016 (‘‘API 18.2’’). This standard
defines the minimum equipment and
methods used to determine the quantity
and quality of oil being loaded from a
lease tank to a truck trailer without
requiring direct access to a lease tank
gauge hatch.
API MPMS Chapter 21—Flow
Measurement Using Electronic Metering
Systems, Section 2, Electronic Liquid
Volume Measurement Using Positive
Displacement and Turbine Meters; First
Edition, June 1998; Reaffirmed August
2011 (‘‘API 21.2’’). This standard
provides for the effective utilization of
electronic liquid measurement systems
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for custody-transfer measurement of
liquid hydrocarbons.
API Recommended Practice (RP)
12R1, Setting, Maintenance, Inspection,
Operation and Repair of Tanks in
Production Service; Fifth Edition,
August 1997; Reaffirmed April 2008
(‘‘API RP 12R1’’). This recommended
practice is a guide on new tank
installations and maintenance of
existing tanks. Specific provisions of
this recommended practice are
identified as requirements in this final
rule.
API RP 2556, Correction Gauge Tables
for Incrustation; Second Edition, August
1993; Reaffirmed November 2013 (‘‘API
RP 2556’’). This recommended practice
provides for correcting gauge tables for
incrustation applied to tank capacity
tables. The tables given in this
recommended practice show the percent
of error of measurement caused by
varying thicknesses of uniform
incrustation in tanks of various sizes.
The BLM received numerous
comments addressing the incorporation
by reference documents. Several
commenters were concerned that the
BLM was not incorporating the most
recent versions of API standards. The
API standards are dynamic standards
that are constantly being reviewed and
updated. The commenters referred to
standards that were updated and
published either after the proposed rule
published or during the BLM’s final
internal review process before
publishing the proposed rule. The BLM
generally agrees with the commenters
that the latest editions of industry
standards should be incorporated and
has made the change here after
reviewing the latest version of the
standards to confirm they will satisfy
the applicable requirements.
Several commenters said that some of
the incorporated materials in the
proposed rule were in conflict. For
example, ASTM D1250–1980 version
tables 5A and 6A for temperature and
gravity correction factors and API 11.1
for the correction of temperature effects
on density and volume provide differing
correction factors that may result in
different corrected oil volumes. The
BLM agrees with these comments and
has removed ASTM D1250–1980 tables
5A and 6A from the list of incorporated
materials. The final rule now refers to
API 11.1 for calculations of temperature
and pressure effects on density and
volume.
Several commenters expressed
concern that the BLM will not be
updating the incorporated industry
standards as new versions are
published. The BLM is aware of the
need to continuously monitor the
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industry standards as they are revised
and updated, and intends to draft
guidance to ensure that the BLM’s rules
and the incorporated standards they
reference are kept up-to-date as
technology and practices change. Under
the applicable IBR rules, however, the
BLM cannot automatically incorporate
updated versions of standards into BLM
regulations. The rules require that BLM
reference the specific version of any
particular standard being incorporated.
Recognizing that these standards are
continually being updated, the BLM
intends to undertake periodic
rulemakings to make corresponding
updates to the relevant regulations. In
the interim, an operator could submit a
request to the PMT for a variance to
comply with a newer version of a
standard in lieu of compliance with the
version listed above.
Many commenters said the BLM
should rewrite the rule to be less
prescriptive, to primarily reference
industry standards, and to include
additional API standards that would
expand industry options for achieving
accurate measurement. They argued that
a highly prescriptive rule would
discourage industry from adopting new
technology as it becomes available.
Upon careful consideration of these
comments, the BLM has decided to take
a less prescriptive approach that will
achieve the ultimate goal of accurate
measurement, while still maintaining
our requirements for an audit trail and
production accountability, and that will
provide reasonable versatility for
operators. The rule has been modified to
be less prescriptive than the proposed
rule and includes more industry
standards that operators may choose
from to comply with the requirements of
the final rule. For example, the tank
gauging section at § 3174.6 has been
rewritten to refer more to industry
standards and less to step-by-step
instructions and requirements. Proposed
§ 3174.6(b)(3) had a list of requirements
for taking oil samples prior to the
opening gauge and was geared towards
manual tank gauging. Section
3174.6(b)(3) of the final rule instead
requires operators to follow one of two
industry standards for taking oil
samples prior to the opening gauge—
API 8.1 for manual sampling or API 8.2
for sampling by automatic sampling
systems. This paves the way for
operators to use hybrid tank
measurement systems and any other
new technology that may come along in
the coming years. Where necessary, the
rule enhances or modifies an industry
standard to ensure that the BLM’s audit
trail and production accountability
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requirements relate to lease activity and
are met. For example, the rule modifies
the industry standard for the tolerance
on the verification for ATG systems,
from ±3⁄16 inch to ±1⁄4 inch, in response
to field test data that showed properly
calibrated equipment has difficulty
meeting the ±3⁄16 inch tolerance
specified in industry standards. Also
industry standards call for monthly
ATG systems verification. This rule
instead requires that ATG systems be
verified monthly or before sales,
whichever is later. This change will
help smaller producers that may have
sales only once every 2 or 3 months.
Several commenters had the opposite
view and said the BLM should not
incorporate industry standards, but
rather make its regulations
predominantly prescriptive, explicitly
stating what is allowed and required.
Their reasoning for this approach was
that API RPs are optional for industry to
consider following, while industry must
follow BLM regulations. The BLM
disagrees with the commenter’s
description of how these rules will be
applied. Under the final rule, operators
are required to comply with industry
standards or practices that are
incorporated by reference. As discussed
earlier, the BLM has decided to take a
less prescriptive approach and, where
possible, incorporate multiple industry
standards to give operators a choice for
achieving a particular measurement
standard.
Several commenters said the BLM
should incorporate forthcoming
industry standards that have not yet
been finalized into the rule. The BLM
cannot incorporate a standard that an
industry trade association has not yet
published. An unpublished standard is
subject to change. It is possible the trade
association creating the standard could
completely rewrite the draft standard
after the BLM incorporated it into this
rule, in ways that would compromise
the BLM’s ability to enforce audit-trail
or production-accountability
requirements. The BLM disagrees with
these comments and has not
incorporated any unpublished standards
into the rule.
One commenter suggested the BLM
not incorporate industry standards but
rather copy industry standard language
directly into the rule. Copyright
restrictions prevent the BLM from
taking this course of action. Also this
approach makes it harder for the BLM
to update these requirements in the
future. The final rule was not revised as
a result of this comment.
Another commenter said the BLM is
statutorily prohibited from cherrypicking industry standards for inclusion
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in the rule—picking and choosing
which standards to apply and which to
ignore. The BLM disagrees with this
comment. Some industry standards do
not meet the rule’s goals and objectives
and have not been incorporated. For
example, there are industry standards
for turbine meters, but the BLM does not
allow these meters to be used at an FMP
because, in some situations, they do not
meet the BLM’s accuracy requirements.
Several commenters said that
incorporating industry standards puts
an unreasonable financial burden on
industry because it forces industry to
purchase the published standards from
the trade groups that create them. The
BLM agrees that the cost of purchasing
a complete set of industry standards is
not insignificant. However, the API
provides the public free, read-only
access to most of the standards
incorporated in this final rule. In
addition, all incorporated material is
available for inspection at the BLM’s
Division of Fluid Minerals, 20 M Street
SE., Washington, DC 20003, and at all
BLM offices with jurisdiction over oil
and gas activities. It is also available for
inspection at the National Archives and
Records Administration (NARA).
Several commenters stated that the BLM
has not made a good effort to provide
these newly required standards for
public review. The BLM disagrees with
this comment. As stated earlier, all
industry standards incorporated by
reference are available for inspection at
the BLM, Division of Fluid Minerals,
and at all BLM offices with jurisdiction
over oil and gas activities.
The commenter also said the
documents are not available in the
BLM’s Washington Office or in any
particular field office. The BLM
disagrees. The documents are available
for review in the BLM’s Washington
Office and in all local offices that have
jurisdiction over oil and gas activities. It
has come to the BLM’s attention that
some local office personnel may not be
aware of how to access the incorporated
standards and, as part of the
implementation process for the final
rule, the BLM plans to carry out a
training program to ensure that field
office staff can readily access the
standards as needed.
Several commenters expressed
concern about who is responsible for
complying with the incorporated
standards—operators or their
contractors. The incorporated standards
are regulatory requirements, and
operators are responsible for ensuring
that third parties that do not have a
contractual relationship with the BLM
comply with the incorporated industry
standards. Existing BLM regulations at
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43 CFR 3162.3 state that a contractor on
a leasehold will be considered the agent
of the operator for such operations with
full responsibility for acting on behalf of
the operator for purposes of complying
with applicable laws, regulations, the
lease terms, NTLs, Onshore Oil and Gas
Orders, and other orders and
instructions of the AO.
Several commenters said the industry
standards as written are not enforceable
by the BLM. The BLM disagrees. Many
of the industry standards employ the
terms ‘‘shall’’ and ‘‘should,’’ with
‘‘shall’’ denoting a minimum
requirement necessary to conform to the
specification, and ‘‘should’’ denoting a
recommendation or that which is
advised, though is not required, in order
to conform to the specification.
However, once the standards are
incorporated into BLM regulations,
operators must comply with them
whether the standard uses the word
‘‘shall’’ or ‘‘should.’’ One commenter
inquired whether operators will be
required to follow a standard, and if any
deviation from a standard is a violation.
As stated previously, operators must
comply with all incorporated standards
and material, and any deviation without
an approved variance is a violation.
Section 3174.4 Specific Measurement
Performance Requirements
This section was previously
published as § 3174.3. Based on edits
made to the final rule, this section and
previously published § 3174.4 have
been switched. All discussion of
comments here were submitted under
the previous proposed § 3174.3.
Section 3174.4(a)(1) sets volumebased overall performance standards for
measuring oil produced from Federal
and Indian leases, regardless of the type
of meters or measurement method used.
The overall volume uncertainty
performance goals apply to volumes
reported on the OGOR Part B
(Production Disposition), commonly
referred to as an OGOR B. FMPs
measuring greater than or equal to
30,000 bbl per month must achieve an
overall measurement uncertainty within
±0.50 percent. FMPs measuring less
than 30,000 bbl per month must achieve
an overall measurement uncertainty
within ±1.50 percent. Existing Order 4
has no explicit statement of
performance standards. The BLM will
apply the performance standards in this
final rule to FMPs as part of the
compliance process. The performance
goals could result in operating
limitations (such as a minimum flow
rate through the meter); however, they
could also allow flexibility for various
operational functions (for example, the
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range of error between the meter in the
field and the meter prover between
successive runs during a proving). To
facilitate this process, the BLM is
developing an oil uncertainty calculator
similar to the BLM’s gas uncertainty
calculator currently in use. The
uncertainty calculator will be an
internal tool for BLM employees to use
to verify uncertainty. Once it is
developed, the uncertainty calculator
will be available for the public to review
and use. The methods for calculating
uncertainty have been clarified in the
final rule to be in accordance with
statistical concepts described in API
13.1, the methodologies in API 13.3, the
quadrature sum (square root of the sum
of the squares) method described in API
14.3.1; Subsection 12.3, and other
methods approved by the AO.
Uncertainty indicates the risk of
measurement error. The performance
standards provide specific objective
criteria against which the BLM could
analyze operator requests to use new
metering technology, measurement
systems, and procedures not specifically
addressed in the rule. The two-tiered
uncertainty thresholds established in
§ 3174.4(a)(1) set the maximum
allowable volume measurement
uncertainty. The BLM believes that the
measurement uncertainties established
are reasonable, based on equipment
capabilities, industry standard practices
and procedures, and BLM field
experience.
As noted, for FMPs measuring greater
than or equal to 30,000 bbl per month,
the maximum overall volume
measurement uncertainty allowed is
±0.50 percent. The BLM has established
the ±0.50 percent uncertainty limit
based on uncertainty calculations and
public comments received on the
proposed rule, discussed below. The
overall uncertainty calculation includes
the effects of the meter accuracy;
maximum allowable meter-factor drift
between meter provings; the minimum
standard for repeatability during a
proving; the accuracy of the pressure
and temperature transducers used to
determine the correction for pressure on
liquids (CPL) factors, and the correction
for temperature on liquids (CTL) factors;
and the uncertainty of the CPL and CTL
calculations. The BLM chose the
volume threshold of 30,000 bbl per
month for this uncertainty level after
determining that at this monthly
volume, a one-percentage-point
decrease in the expected over- or
underpayment of royalties—from ±1.5
percent to ±0.5 percent—evaluated over
a 5-year time frame, equals $150,000.
This $150,000 amount reflects the cost
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to purchase a LACT system, based on
price quotes from several distributors. In
other words, requiring a LACT system,
in terms of increased accuracy, will
generate benefits that equal or exceed
the cost of the new system. In making
this calculation, the BLM assumed a 5year crude oil price average of $67.58
per bbl,12 and a royalty rate of 12.5
percent. FMPs with production volumes
less than 30,000-bbl-per-month
production volume do not generate
sufficient volumes that the potential
royalty risk justifies installing a LACT
system with an expected 5-year lifespan.
As a result, the maximum proposed
overall measurement uncertainty for
these FMPs is ±1.5 percent. The BLM
believes based on available data and its
experience that a ±1.5 percent threshold
is reasonable and readily achievable by
manual tank gauging. Based on the
BLM’s analysis and review of comments
received, the BLM determined that the
overall uncertainty of manual tank
gauging ranges from ±0.6 percent to
±2.50 percent depending on the volume
of oil removed from the tank at the time
of sale. A ±0.6 percent uncertainty
results from potential measurement
error applied to large volumes, while a
±2.50 percent uncertainty results from
the same potential measurement error
applied to smaller volumes removed
during one load-out. The ±1.5 percent
uncertainty in the final rule reflects the
high average calculated uncertainty for
a typical truck load-out by tank gauging,
which BLM believe is representative of
onshore operations more generally, and
therefore is an appropriate threshold to
use in this rule.
The two-tiered uncertainty
performance requirements in the final
rule reflect modifications from the
proposed rule, based on comments
received. First, one commenter noted
that the proposed rule did not give
guidance on how the uncertainty was to
be calculated. The BLM agrees with this
comment and the final rule makes it
clear that the uncertainty is to be
calculated using API 13.1, Statistical
Concepts and Procedures; API 13.3, the
uncertainty methodologies; the
quadrature sum method as described in
API 14.3.1, Subsection 12.3, General
Equations and Uncertainty Guidelines;
or other methods approved by the AO.
Another commenter agreed that it is
appropriate to permit a certain amount
of measurement uncertainty and to
utilize a tiered approach for uncertainty
based on volume. However, the
12 Based on the projected nominal West Texas
Intermediate crude oil spot price published in the
U.S. Energy Information Administration’s 2016
Annual Energy Outlook Reference case scenario.
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commenter disagreed with the proposed
rule’s three-tiered uncertainty
requirement: ± 0.35 percent for FMPs
measuring more than 10,000 bbl per
month; ± 1 percent for FMPs measuring
more than 100 bbl per month and less
than or equal to 10,000 bbl per month;
and ± 2.5 percent for FMPs measuring
less than 100 bbl per month. The
commenter said the proposed ± 2.5
percent uncertainty level for FMPs
measuring volumes less than 100 bbl/
month is both unnecessary and
counterproductive. This commenter
noted that there are a large number of
older, low-volume wells operating on
BLM and tribal leases, and argued that
the ± 2.5 percent uncertainty for those
operations could cause some lowvolume operators to shut in their wells,
resulting in a significant cumulative loss
of Federal revenue from royalties.
Commenters instead recommended that
the BLM eliminate the lowest-volume
category of the three uncertainty levels
under proposed § 3174.3(a)(1). They
further recommended that all FMPs
with monthly volumes averaged over
the previous 12 months that are less
than 10,000 bbl/month should be
subject to an uncertainty level of ± 1.0
percent. The commenters also said that
this gives the BLM more discretion over
when a less stringent uncertainty level
for low-volume operators is appropriate
based on site-specific factors.
The BLM partially agrees with these
comments. After reanalyzing the
uncertainty data and volume thresholds,
the BLM has eliminated the lowest tier
of uncertainty. However, this rule uses
a 30,000 bbl per month volume as the
dividing volume between the two tiers,
and sets the uncertainty level for the
highest-producing tier at ±0.50 percent
and the uncertainty level for the lowestproducing tier at ±1.5 percent, which
will be high enough for most tankgauging operations while still ensuring
the rules achieve accurate measurement.
The BLM chose the 30,000 bbl per
month volume as the dividing line
between the two tiers, and their
respective uncertainty performance
standards, based on what it would cost
an operator to install and operate a
LACT system, relative to the risk that
the operator would under- or overpay
royalties if measuring by tank gauging.
The calculation for this assumes: A
LACT system costs $150,000 and has a
5-year expected equipment lifespan,
tank gauging results in a ±1.5 percent
uncertainty, the 5-year oil price averages
$67.58 per bbl, and the royalty rate is
12.5 percent. The following equation
shows the calculation used to arrive at
the 30,000 bbl per month volume
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dividing line between the two tiers of
uncertainty performance requirements:
Monthly volume = $150,000/
((Uncertainty × Oil price × Royalty
rate) × 60 months)
One commenter suggested that the
performance standards for uncertainty
should not be less than ±1.0 percent. A
performance standard of less than ±1.0
percent is excessively onerous, the
commenter said, and does not provide
a substantial benefit compared to a ±1.0
percent standard. This commenter did
not justify why a ±1.0 percent
uncertainty standard is reasonable or
how anything less is onerous. The BLM
disagrees with this comment. The root
square sum method of calculating the
uncertainty of a LACT system with a PD
meter configured and operated under
the requirements of Order 4 calculates
an overall uncertainty of ±0.32 percent.
The final rule makes only minor
changes to the Order 4 LACT
requirements, so a calculated overall
uncertainty rate under this rule will be
similar to the existing requirements of
Order 4. A LACT system with either a
PD meter or a Coriolis meter is very
capable of achieving the ±0.50 percent
uncertainty when constructed and
operated according to the requirements
of this rule and corresponding API
standards; no change was made as a
result of this comment.
One commenter said BLM regulations
do not need to specify equipment
models that are acceptable for use in
custody transfer measurement when
uniform uncertainty metrics are
utilized. The commenter stated that if
any equipment meets the established
uncertainty-performance standards for a
measurement system, and that
uncertainty can be validated and
maintained, such equipment should
then be allowed to be used for oil
measurement. The BLM partly agrees
with this comment, which is why this
final rule establishes a procedure
whereby the PMT can review and
approve the use of new equipment and
measurement methods, so long as the
new equipment and methods meet the
performance uncertainty and
verifiability standards of the rule. The
BLM believes that once this equipment
has been proven to be capable of
meeting the uncertainty performance
and verifiability standards of this rule,
then that equipment can be approved
for use.
The second part of this comment
suggests that the volume uncertainty
limit of ±0.35 percent in the proposed
rule for high-volume producers is
excessively small (strict) for
measurement installations that measure
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in excess of 10,000 bbl/month. The
commenter further stated that the BLM
failed to provide any basis for the
proposed allowable volume uncertainty
calculations. The proposed rule did not
offer any detail as to how the
uncertainty limit of ±0.35 percent
includes any effects of maximum
allowable meter-factor drift between
meter proving, the minimum standard
for repeatability during proving the
accuracy of pressure and temperature
transducers for volumetric correction,
and the uncertainty in the volumecorrection factor correction. The
commenter also said the BLM did not
disclose the data that it utilized to
determine the ±1.0 percent uncertainty
limit for FMPs in the 100 to 10,000 bbl/
month range.
The BLM conducted an overall
uncertainty calculation for a LACT
utilizing a PD meter operated and
proven under the requirements of Order
4. The results of this calculation
provided an overall uncertainty of ±0.32
percent, which was what the BLM used
to establish the higher standard in the
proposed rule. The commenter did not
provide a more appropriate uncertainty
calculation to justify their claim that
±0.35 percent is excessively small for
installations that measure in excess of
10,000 bbl per month. As a result no
specific changes were made in response
to this comment; however, as noted
elsewhere in this section, the BLM has
modified the uncertainty thresholds for
larger-volume FMPs.
In order to identify appropriate
thresholds, the BLM reviewed a
proprietary third-party uncertainty
calculation for tank gauging using Order
4 requirements for a 400 bbl tank. The
results indicate that the overall
uncertainty varies depending upon the
volume removed from the tank. The
overall uncertainty in the calculation
varied from ±0.6 percent for large
volumes removed to uncertainties of
±2.50 percent for very small volumes
removed. The BLM reviewed overall
uncertainty calculations in order to
determine reasonable uncertainty
requirement in the rule.
Several commenters said the BLM
should re-evaluate its proposed
measurement uncertainty (±0.35
percent), claiming the methodology
appears to be flawed. They further
stated the proposed oil measurement
rule demands a level of accuracy that
would not apply to heavy oil regimes
and that would increase operating costs
beyond what is necessary or of value.
They suggest that operators with heavy
oil operations may receive unwarranted
and costly penalties at a greater rate
than the rest of the petroleum industry,
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and that heavy oil producers would be
disproportionately impacted by the
proposed standard. These commenters
did not submit justification for their
claims, and when the BLM contacted
them to clarify this comment, they still
failed to justify or explain how heavy oil
regimes would be disproportionately
impacted by the rule. No change to the
rule resulted from these comments.
One commenter requested that the
±0.35 percent performance uncertainty
be adjusted to ±1.0 percent for meters
measuring 10,000 barrels per day. The
commenter agreed with comments that
the API submitted to the BLM on the
proposed rule and requests that the
BLM use the Order 4 proving and
uncertainty performance requirements
for LACT systems. The BLM has reanalyzed the uncertainty performance
requirements and volume thresholds,
and, based on the re-evaluation and
other comments received showing a
different uncertainty calculation
resulting in a slightly higher uncertainty
than proposed, has changed the rule’s
uncertainty performance standards to
encompass reasonable flexibility in
evaluating alternative measurement
equipment and methods and adjusted
the volume thresholds to match
volumes where the risk to royalty would
equal the expense of installing a LACT
or CMS to require a more accurate
measurement.
Another commenter said the overall
volume uncertainty limit of ±0.35
percent for measurement installations
with throughputs greater than 10,000
bbl/month is unreasonably and
excessively strict, given the potential
number of sources of measurement
error. The error should be calculated to
include the uncertainty from all sources
of error in the oil volumetric calculation
chain. The BLM agrees in part with the
comment that a ±0.35 percent
uncertainty may be somewhat strict in
some applications. The ±0.35 percent
has been calculated to include all
sources of error in the LACT
measurement calculation chain, based
on other comments providing similar
calculations. The BLM has chosen to
use a slightly higher uncertainty level in
the final rule to give some leeway when
considering approvals for future
measurement technology and
procedures for use on Federal and
Indian leases. This commenter also
suggested that systems installed at FMPs
that measure less than 100 bbl/month
should have the option to pay royalties
as if they were producing at the rate of
100 bbl/month and avoid the cost of
installing measurement equipment that
could make their operations
economically infeasible. The BLM
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disagrees with the concept of paying
royalties based on a fixed volume rather
than royalties based on actual
measurements. In addition, if the
uncertainty standards would render a
lease uneconomic, the operator can seek
an exemption from the requirements
under § 3174.4(a)(2). No change to the
rule resulted from this comment.
One commenter said they were unable
to verify the uncertainty levels proposed
without the ‘‘calculator’’ that the BLM is
developing. This commenter created its
own uncertainty calculation using the
following assumptions: A maximum
allowable deviation for temperature of
0.25 °F and pressure of 0.25 psi. The
uncertainty was calculated to be ±0.46
percent in this one instance.
The BLM appreciates receiving this
comment as it provides useful input and
actual calculation results to support the
commenter’s position. As a result of this
comment and further analysis, the BLM
agrees that this uncertainty calculation
could reflect one possible application
and has adjusted the rule’s lower overall
uncertainty performance requirements
for the highest-producing tier to ±0.50
percent.
One commenter expressed concern
that the cost of complying with this
provision will increase as uncertainty
standards are updated. However, there
is nothing in this provision that
provides for the updating of the
uncertainty threshold standards.
Under § 3174.4(a)(2), only a BLM
State Director, with the written
concurrence of the PMT, prepared in
coordination with the Deputy Director,
can grant an exception to the prescribed
uncertainty levels. Granting an
exception requires a showing that
meeting the required uncertainly levels
would involve extraordinary cost or
unacceptable adverse environmental
effects. By having the State Directors
make these decisions, with concurrence
of the PMT (prepared in coordination
with the Deputy Director), the BLM
hopes to ensure that there is consistent
application of the performance
standards across the Bureau and that
approvals for exceptions from the
performance standards are granted in
limited circumstances. In the proposed
rule, the BLM had proposed to require
concurrence from the Director; however,
upon further review, the BLM modified
the written concurrence requirement to
require written concurrence from the
PMT that has been prepared in
coordination with the Deputy Director.
The BLM feels this approach would be
more appropriate given that the PMT
will have the necessary technical
expertise, while requiring coordination
with the Deputy Director ensures such
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changes have the necessary national
policy perspective.
The BLM received several comments
on its approach to exceptions to the
proposed rule’s uncertainty limits. A
few commenters requested that the BLM
clarify and limit the criteria a BLM State
Director can use to grant exceptions.
The BLM does not believe additional
clarification is necessary and the rule’s
description of potential extraordinary
circumstance(s) that could result in an
exception to the uncertainty levels is
sufficient. The BLM cannot identify
every situation or event that could
warrant an exception. The intent of the
rule is that an exception is not a normal
occurrence, and to allow exceptions
only in limited, special circumstances.
No change to the rule resulted from this
comment.
Similarly, another commenter urged
the BLM to clarify the manner in which
exceptions may be granted and to
clearly define the term ‘‘extraordinary
cost.’’ According to this commenter, a
lack of clear guidance on these
exceptions will result in unrealistic
expectations from operators and
inconsistent application by the BLM.
Again, there could be numerous
circumstances under which an
exception could be warranted, and the
BLM cannot accurately anticipate and
address all of these in the rule. It will
be up to the individual or entity
applying for the exception to make the
case to justify an exception. The process
for granting exceptions is more likely to
be consistent if decisions are left to
State Directors, with written
concurrence from the PMT (prepared in
coordination with the Deputy Director).
No change to the rule resulted from this
comment.
One commenter questioned why, on
the one hand, the proposed rule would
have authorized BLM State Directors to
grant exceptions to uncertainty
standards for equipment at FMPs (with
BLM Director concurrence) and on the
other hand, the rule at § 3174.4(d) gives
the PMT the authority to recommend
and the BLM to decide whether
proposed alternative equipment or
measurement procedures meets or
exceeds the uncertainty standards. The
commenter questioned a process that
will rely on the availability of the PMT
and State Directors to review and
evaluate requests for exceptions. The
commenter said BLM technical experts
are often overworked, and therefore the
PMT approval process is likely to take
a considerable amount of time and
hinder operators’ ability to effectively
develop Federal oil and gas resources.
The BLM agrees that its technical
experts have a significant workload and
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face a number of competing demands.
However, one reason for creating a
BLM-wide PMT is to relieve field offices
of having to review new technology, and
to provide a consistent BLM-wide
decision-making process. The BLM
believes that this structure should
minimize the amount of time it will take
for the BLM to process requests for
evaluation of new equipment, and to
evaluate requests for exemptions from
the uncertainty requirements. No
change to the rule resulted from this
comment.
Section 3174.4(b) establishes the
degree of allowable bias in a
measurement. Bias differs from
uncertainty in that bias results in
systematic measurement error, whereas
uncertainty only indicates a risk of
measurement error. While the BLM
acknowledges that it is virtually
impossible to remove all bias in
measurement, the final rule requires
that there be no statistically significant
bias at any FMPs. When a measurement
device is tested against a laboratory
device or prover, there is often slight
disagreement, or apparent bias, between
the two. However, both the
measurement device being tested and
the laboratory device or prover have
some inherent level of uncertainty. If
the disagreement between the
measurement device being tested and
the laboratory device or prover is less
than the uncertainty of the two devices
combined, then it is not possible to
distinguish apparent bias in the
measurement device being tested from
inherent uncertainty in the devices
(sometimes referred to as ‘‘noise’’ in the
data). Therefore, the BLM does not
consider apparent bias that is less than
the uncertainty of the two devices
combined to be statistically significant
for purposes of compliance with the
final rule. However, if the shift in the
mean value of a set of measurements
away from the true value of what is
being measured exceeds the
‘‘statistically combined uncertainty’’ of
the devices, then the BLM requires that
known shift to be corrected to as close
to the actual value as possible.
The BLM received several comments
concerning bias. The first commenter
stated the rule does not give any
guidance on how bias will be
determined, or what the BLM considers
to be statistically significant. In order for
the bias restriction to be applied
uniformly throughout the nation, the
commenter asserted that the term needs
to be defined in the regulation. The
BLM agrees with this comment and has
added a new definition for ‘‘bias’’ to 43
CFR subpart 3170, as part of the
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rulemaking that is updating and
replacing Order 3.
Another commenter noted that the
BLM presented no data or calculations
in the proposed rule to verify that bias
issues will not exist under field
conditions where many additional
variables impact the statistical
calculations. The commenter claimed
that the rule essentially assumes that
uncertainties that can be demonstrated
in laboratory conditions can also be
demonstrated in field conditions, which
are not practical in a production
scenario. The commenter asked that the
BLM delete paragraph (b) from the final
rule. The BLM does not agree with this
comment. If a shift in the mean value of
a set of measurements away from the
true value of what is being measured,
exceeds the statistically combined
uncertainty of the devices, occurs, then
the BLM requires that known shift to be
corrected to as close to actual value as
possible. An example of where this shift
could be discovered is during a
transducer verification that results in a
reading that is outside of the device’s
stated uncertainty. This is different from
uncertainty, where a potential for
measurement error exists. No change to
the rule resulted from this comment.
A third commenter recommended that
the BLM clarify language in the
preamble that discusses statistically
significant bias. As noted above, the
preamble quantifies statistically
significant bias as being a number that
is greater than the combined
uncertainties of the laboratory device, or
prover, and the measured device, or the
‘‘statistically combined uncertainty.’’
The BLM recognizes that there will
always be some apparent bias resulting
from the uncertainty of all devices. Bias
is only considered significant when it
exceeds the combined uncertainties of
the devices involved. The BLM believes
that the final rule accurately explains
bias in terms of it being outside of the
‘‘statistically combined uncertainty’’ of
the devices being used. No change to the
rule resulted from this comment.
Section 3174.4(c) requires that all
measurement equipment be subject to
independent verification by the BLM
that it is performing accurately and that
all inputs, factors, and equations that
are used to determine quantity or
quality are valid. Order 4 already
requires that the BLM be able to
independently verify measurement
methods, as well as bias, so these are
not new requirements. The verifiability
requirement in this section prohibits the
use of measurement equipment that
does not allow for independent
verification. For example, if a new meter
were to be developed that did not record
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the raw data used to derive a volume,
that meter could not be used at an FMP
because without the raw data the BLM
would be unable to independently
verify the volume. Similarly, if a meter
were to be developed that used
proprietary methods that precluded the
ability to recalculate volumes, its use
would also be prohibited.
The BLM received several comments
about the verifiability requirements of
this rule. One commenter seemed to
suggest that the BLM did not take into
account the use of automation and other
measurement systems advances, such as
the use of flow computers handling
calculations. The comment further
stated that in order to retain the raw
data that the BLM needs to manually
verify equipment accuracy, operators
will be required to use computers that
are less efficient and that require more
data storage. The BLM agrees that the
rule may require operators to acquire
more data storage, but does not agree
with the commenter that saving raw
data for future verification will result in
less efficient flow computers, or that it
is unnecessary. The BLM manages
Federal oil resources on behalf of the
American taxpayer and has an
affirmative obligation to ensure that the
oil produced is accurately measured and
accounted for. In order to satisfy those
obligations it is critically important that
an audit trail exists so that the BLM can
verify the production data. As a result,
the BLM will continue to manually
verify calculations at FMPs. No change
to the rule resulted from this comment.
Another commenter suggested any
verifiability does not take into account
the difference between live calculations
at high frequencies versus averaged and
accumulated data over time. The
commenter also said that independent
calculations should only have to fall
within a statistically insignificant
window. In order for independent
calculations to be applied uniformly
throughout the nation, they should to be
defined in the regulations, the
commenter said. The BLM partly agrees
with this comment that calculations
should be live calculations at high
frequencies or calculations averaged and
accumulated over time. The Inspection
and Enforcement Handbook will
address possible methods for the BLM
to verify calculations at an FMP. No
changes to the rule were made as a
result of this comment, but the BLM
will include guidance in the Inspection
and Enforcement Handbook regarding
whether calculations should be based
on live calculations or averaged over
time. Under the final rule, all volume
calculations at an FMP must be
verifiable.
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One commenter asked whether the
requirement that new equipment
undergo independent verification will
preclude new technology. The BLM
does not intend to prevent or exclude
new technology. In fact, this rule, by
establishing performance standards,
adopting industry standards, and
standing up the PMT process, has been
designed explicitly to provide flexibility
for the BLM to adopt new technology
and practices as they are developed. No
changes were made in response to this
comment.
Another commenter said that
paragraph (c) would require the BLM to
contract with an independent laboratory
to verify equipment, which could take 6
months per device and cost upwards of
‘‘$500M’’ for each device. The BLM
disagrees with this comment because
§ 3174.4(c) merely requires operators to
have FMP equipment that can produce
the source records that provide the data
and equations the BLM needs to
independently recalculate oil
production volume and quality during
production audits. No changes were
made in response to this comment.
Section 3174.4(d) clarifies that the
operator can propose the use of
alternative equipment, provided that it
meets or exceeds the uncertainty
requirements of this section. The PMT
will make a determination under
§ 3174.13 of this subpart regarding
whether proposed alternative
equipment or measurement procedures
meets or exceeds the objectives and
intent of this section. See § 3174.13 for
discussion of comments concerning the
PMT and the PMT review process.
Section 3174.5 Oil Measurement by
Tank Gauging—General Requirements
Section 3174.5(a) specifies the general
requirements for oil measurement by
tank gauging as a means to accurately
determine the quantity and quality of oil
removed from an FMP. The BLM
received many comments on this
section of the proposed rule. Almost all
of these comments requested that the
BLM consider permitting the use of
ATG systems for custody transfer
applications. Order 4 allows only
manual tank gauging. In the proposed
rule, the BLM indicated that it was
considering including provisions in the
final rule allowing for the use of ATG
systems, and requested data regarding
whether these systems can meet the
BLM’s performance standards for
manual tank gauging with respect to
uncertainty and verifiability. The BLM
requested additional data regarding
ATG measurement systems because it
recognizes the significant safety
advantages they provide.
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The majority of the commenters
indicated that ATG systems are much
safer for workers when compared to
manual tank gauging systems, especially
when workers are measuring
hydrocarbon fluids such as those found
in the Bakken, which have higher
gravity and higher vapor pressure, and
thus emit higher volumes of toxic
fumes. The BLM agrees that safety
concerns associated with manual tank
gauging can be reduced if operators
have the option of using ATG systems
as well as the other measurement
methods addressed in this final rule.
Based on data provided in response to
the proposed rule—both as public
comment on the proposed rule and in
support of project-specific variance
requests to use ATG systems on tanks—
the BLM has determined that ATG
systems can meet or exceed the
uncertainty thresholds for tank gauging.
As a result, the rule has been changed
to allow for the use of ATG systems.
The BLM received one comment that
recommended the BLM prohibit the
practice of oil measurement by manual
tank gauging because, according to the
commenter, the practice is an
antiquated and considerably less
reliable method of measurement. The
BLM disagrees that properly conducted
manual tank gauging operations are
antiquated or less reliable than other
methods of measurement and will
continue to give operators the option of
using this widely accepted practice for
oil measurement, which is generally
used at lower-volume facilities.
However, the BLM hopes for a shift
towards ATG in areas where the nature
of the produced oil presents a safety
concern.
In the proposed rule, § 3174.5(b)
required that all oil storage tanks,
hatches, connections, and other access
points be vapor tight and that each oil
storage tank, unless connected to a
vapor recovery system, must have a
pressure-vacuum relief valve installed at
the highest point in the vent line or
connection with another tank. Pressurevacuum relief valves would provide for
normal inflow and outflow venting at an
outlet pressure that is less than the thief
hatch exhaust pressure and at an inlet
pressure that is greater than the thief
hatch vacuum setting. The intent is to
minimize hydrocarbon gas lost to the
atmosphere by ensuring that venting is
done under controlled conditions
through the pressure-vacuum relief
valve primarily in response to changes
in ambient temperature. The
requirement that all access points be
vapor tight has been expressly included
in this rule in order to eliminate
confusion over the intent of Order 4,
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which specified all the same equipment,
but did not specify the manner in which
it was supposed to be operated. The
implied intent of Order 4 was always
that the tanks be operated such that they
are vapor tight.
The BLM received numerous
comments on this section, the majority
of which said the proposed
requirements could conflict with U.S.
Environmental Protection Agency (EPA)
air quality regulations and the BLM’s
separately proposed Methane and Waste
Prevention Rule (81 FR 6616). Some of
the same commenters also complained
about the potential costs associated with
retrofitting some of the tank batteries.
The BLM disagrees with these
comments. The intent of the
requirement is to conserve the quantity
and quality of the liquid hydrocarbons
in storage by controlling the storage
conditions, not to create a potential
conflict with the EPA’s regulations for
release of harmful pollutants. The BLM
also disagrees with claims made by
some commenters that the potential
costs associated with retrofitting
existing tank batteries to make them
vapor-tight would be too high. Pressure
vacuum vent line valves and thief
hatches are already required equipment
for the existing tank battery installations
under Order 4. Paragraphs (b)(3) and (4)
of the proposed rule have been changed
and merged into a new paragraph (b)(3)
in the final rule, which now requires
that all oil storage tanks be vapor tight,
and, unless connected to a vapor
recovery or flare system, must have a
pressure-vacuum relief valve installed at
the highest point in the vent line or
connection with another tank. All
hatches, connections, and other access
points must be installed and maintained
in accordance with manufacturers’
specifications.
Several commenters recommended
that the BLM add the requirement that
oil storage tank hatches (‘‘thief hatches’’
or other access points) have pressure
indicators that provide a clear and
immediate visual indicator of tank
pressures and potential gas/vapor
release hazard should the tank need to
be accessed. One of the commenters
said pressure indicators on tank access
hatches visually display the presence of
gas/vapor pressure in a tank, allowing a
trained worker to make risk-based
decisions before accessing a tank,
including actuating a remote venting
valve, venting gas to a flare, or using
appropriate respiratory protection, such
as a self-contained breathing apparatus
or an air-line respirator. The BLM
recognizes that having such information
could potentially be useful to personnel
in the field; however, the BLM did not
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make any changes in response to this
comment because the pressure
indicators proposed by the commenter
would have no bearing on determining
measured volume, and therefore are
outside the scope of this rule. It should
also be noted that in general the
Occupational Safety and Health
Administration takes the lead on
adopting and enforcing employee safety
requirements.
Several commenters stated it is
imperative that tanks be maintained
vapor tight and that there be a
monitoring or inspection program to
ensure compliance. The BLM agrees and
the final rule has maintained the vapor
tight integrity requirement for oil
storage tanks. The BLM’s inspection and
enforcement program will continue to
ensure compliance with this and all
other oil and gas regulations. No
additional changes were made to the
final rule as a result of these comments.
One commenter stated that if the oil
is weathered or stabilized, there is no
need for hatches and other connections
to be vapor tight. The commenter did
not explain how weathered or stabilized
oil could negate the need for hatches
and other connections to be vapor tight.
The BLM disagrees that stabilized
product does not require a vapor-tight
storage condition. The vapor tight
integrity is an implied requirement of
the current Order 4 and therefore will
not require the operator to retrofit any
existing equipment. In a unique
situation where a variance could be
justified, the operator could seek a
variance through the appropriate BLM
field office following the process
outlined in § 3170.6 of this part, a
related rulemaking that is replacing
Order 3, with approval by the AO. No
additional changes were made to the
final rule. This section in the final rule
is now identified as § 3174.5(b)(3).
Section 3174.5(b)(5) of the proposed
rule specified that all oil storage tanks
must be clearly identified and have a
unique number stenciled on them,
maintained in a legible condition. Order
4 did not have a similar requirement.
The BLM received several comments
that said this section did not adequately
communicate how the numbering
system would work and how numbers
are assigned to the tanks. The BLM
agrees that this section was not clear. As
a result of these comments, the final
rule has been changed to specify that all
oil storage tanks must be clearly
identified with an operator-generated
number that is unique to the lease, unit
PA, or CA stenciled on the tank and
maintained in a legible condition. This
section now appears as § 3174.5(b)(4) in
the final rule.
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Section 3174.5(b)(6) of the proposed
rule required each oil storage tank
associated with an approved FMP by
tank gauging to be set and maintained
level. Several commenters said this
requirement is unwarranted and
unnecessary without offering any
details. The BLM disagrees, as this is
not a new requirement. Order 4 has a
similar requirement, and the BLM
believes that not requiring a tank to be
set or maintained level would be
unacceptable because it could result in
uncertainty in measurement. Industry
standards also dictate that tanks used
for gauging operations should be level.
No change resulted from these
comments. This section now appears as
§ 3174.5(b)(5) in the final rule.
Section 3174.5(b)(7) of the proposed
rule specified each oil storage tank
associated with an approved FMP that
has a tank-gauging system must be
equipped with a distinct gauging
reference point, with the height of the
reference point stamped on a fixed
bench-mark plate or stenciled on the
tank near the gauging hatch, and
maintained in a legible condition. One
commenter, without offering any
justification, said this requirement
should apply only to tanks that are
manually gauged. The BLM disagrees as
this gauging reference point is also
needed during the verification and
calibration of an ATG system, not just
for tanks that are measured by manual
gauging. No change was made to the
final rule as a result of this comment.
This section now appears as
§ 3174.5(b)(6) in the final rule.
Section 3174.5(c) in the proposed rule
required the operator to accurately
calibrate each oil storage tank associated
with an approved FMP that has a tankgauging system, under either API 2.2A
or API RP 2556. Order 4 had a similar
requirement. The BLM received a few
comments on this section. One
commenter pointed out that under the
proposed rule, sales tank calibrations
apparently can only be made using API
MPMS Chapter 2.2A—Tank Strapping
by Manual Method, when in fact other
methodologies in Chapter 2 are
available. The BLM agrees that industry
standards provide additional methods
for calibrating sales tanks. As a result of
this comment, the BLM changed the
final rule to incorporate industry
standards API 2.2A, API 2.2B, or API
2.2C; and API RP 2556. One commenter
stated the proposed rule did not clarify
when or how often a sales tank
calibration is required. The BLM
disagrees. Section 3174.5(c)(2) clearly
states when a sales tank calibration is
required—if the tank is relocated,
repaired, or the capacity is changed as
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a result of denting, damage, installation,
removal of interior components or other
alterations. No changes were made to
the final rule as a result of this
comment.
One commenter said operators should
be allowed to use formulas for
estimating tank volumes. The formula of
1.67 bbl/inch is a tool operators use to
estimate the volume stored in the tank.
When the oil is sold, the commenter
said, a more accurate measurement will
be taken, ensuring that the operator is
properly paid for the oil being sold,
which will in turn result in the correct
royalty payment to the government.
This rule seeks to ensure accurate oil
measurement, not volume estimates.
This comment is not relevant to sales
tank calibration. The final rule was not
changed as a result of this comment.
Section 3174.5(c)(1)(i) of the proposed
rule specified the strapping table unit
volume must be in barrels. The BLM
received no comments and made no
changes to this paragraph.
Section 3174.5(c)(1)(ii) of the
proposed rule specified the incremental
height measurement on all tanks must
be in 1⁄8-inch increments. This was a
change from the incremental height
measurement in Order 4 of 1⁄4-inch
gauging accuracy for tanks of 1,000 bbl
or less in capacity. The BLM received
many comments on this section. The
commenters consistently addressed the
following two main points: (1) The
benefits from the increase in accuracy
would be minimal in comparison to the
time and costs it would take to achieve
the increased accuracy; and (2) The
change would require operators to restrap their tanks and generate new tank
tables, and, in many cases, make major
changes to their software programs, all
at substantial costs. The BLM agrees that
the costs of a change to 1⁄8-inch
increments for tank gauging on tanks
that are 1,000 bbl or less in capacity is
unnecessary because the additional cost
burdens outweigh any potential
accuracy gains. As a result of these
comments, the rule has been changed to
say that the incremental height
measurement must match the gauging
increments specified in
§ 3174.6(b)(5)(i)(C), which requires 1⁄4inch increments for tanks 1,000 bbl or
less in capacity, and 1⁄8-inch increments
for tanks greater than 1,000 bbl in
capacity. This is the same accuracy
standard that has been in effect under
Order 4. The BLM would like to note
that API industry standards relative to
manual tank gauging have conflicting
tank-gauging increments. The BLM has
chosen to retain the current Order 4
gauging increments requirement by
following API 18.1 tank gauging
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increments for tanks that are 1,000 bbl
and less and API 3.1A tank gauging
increments for tanks greater than 1,000
bbl.
Section 3174.5(c)(2) requires
operators to recalibrate a sales tank if it
is relocated or repaired, or the capacity
is changed as a result of denting,
damage, installation, removal of interior
components, or other alterations. Order
4 had a nearly identical requirement.
The BLM received a few comments on
this section, all of which said there is no
definition of how large the dent or
alteration would need to be to trigger
this requirement. The commenters also
stated that the BLM must clarify the
amount of volume displacement that
would require action on the part of the
operator. The final point that the
commenters made also suggested that
the BLM should offer a range of options
that operators could take in response to
denting, including tank inspection, and
provide them an opportunity to avoid
being in violation. For example, an
insulated tank may be dented on the
outside but the dent would have no
impact on the inside due to several
inches of insulation. Upon review of
these comments, the BLM has made no
change to the rule for the following
reasons. The volume displacement from
tank denting cannot be known until the
dent has been measured and the impacts
analyzed. To measure the impacts, this
section requires re-strapping of the tank.
The BLM has chosen not to allow an
operator to ‘‘estimate’’ the impact of
denting on a tank used for tank gauging
as there would be no enforceable
requirement to properly determine the
resulting volume impacts. Denting of
the insulation on a tank may or may not
result in denting of the sales tank. If
denting is observed on the insulation of
a tank, it is the operator’s responsibility
to verify that no internal tank denting
has occurred under the insulation.
Section 3174.5(c)(3) requires
operators to submit sales tank
calibration charts (tank tables) to the AO
within 30 days after calibration. Order
4 required them to be submitted to the
AO upon request. The BLM received
several comments on this section. A few
commenters recommended extending
the 30-day time period to 45 days to
allow for more coordination time
between transporter and operator. After
considering these comments, the BLM
agrees that transporters and operators
may need more time to submit the tank
tables to the BLM. As a result of these
comments, the final rule now requires
that tank tables must be submitted to the
AO within 45 days after calibration.
Tank tables may be in paper or
electronic format. A couple of
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commenters said this requirement is
another example of the BLM getting into
the day-to-day operations of industry.
They said there is absolutely no reason
for the BLM to have these charts, argued
that they serve no purpose, suggested
that this requirement is excessively
prescriptive, and asked the BLM to
justify the need for the charts. Oil tanks
are constructed to API standards and
have a common, industry-wide standard
strapping chart, the commenters said,
and these tanks are not proven once
installed. The BLM disagrees with these
comments, as the tank calibration charts
(tank tables) are in fact unique for each
tank, and therefore there should not be
a common, industry-wide standard
strapping chart in use where tank
gauging is the method of measurement
at an FMP. The BLM has a long history
of using the tank tables on a daily basis
for production verification efforts, such
as during production inspections and
records-analysis audits. No changes
were made to the final rule as a result
of these comments.
The BLM has an affirmative obligation
to maintain an audit trail supporting
Federal and tribal oil production. A
couple of commenters requested that the
BLM continue to use the Order 4
requirement that operators submit their
latest tank calibration charts when the
AO requests them, in order to avoid
confusion and give operators notice that
an inspection is imminent. The BLM
disagrees because the new requirement
will serve as verification that the
operator has had the tanks strapped as
required, and enables the BLM to
perform the required inspection
activities. Additionally, the BLM has no
obligation to provide operators notice
that an inspection is imminent.
One commenter said marginal
producing leases should be exempt from
tank-gauging requirements. The BLM
disagrees. Marginal leases are already
subject to tank-gauging requirements.
Under this final rule, operators on
marginal-producing leases are allowed
to continue using manual tank gauging,
which imposes only modest economic
impact on these leases.
Section 3174.6 Oil Measurement by
Tank Gauging—Procedures
Section 3174.6 paragraphs (a) and (b)
require operators to take the steps in the
order prescribed in the following
paragraphs to manually determine by
tank gauging the quality and quantity of
oil measured under field conditions at
an FMP. The BLM received several
comments on this section. The
comments said the detailed tankgauging procedures in this section do
not align with the industry standard.
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The BLM partly agrees, in that industry
standards for certain activities have
several options for operators to follow
for achieving the desired outcome. The
proposed rule did not reflect all of those
options. As a result of these comments,
the final rule has been changed to
reference the appropriate industry
standards and remove any unnecessarily
prescriptive requirements to ensure
accurate measurement using tank
gauging.
Section 3174.6(b)(1) contains the
requirement in Order 4 and the
proposed rule that the tank be isolated
for at least 30 minutes to allow contents
to settle before proceeding with tank
gauging operations. The BLM received a
couple of comments on this section. The
commenters said this requirement
would be costly and is unnecessary, as
this activity will not increase the
accuracy of measurements. The BLM
disagrees. This requirement will ensure
that the tank is isolated and that the
crude oil layer is still, with no surface
foaming. In many liquid manual
sampling applications, the product to be
sampled contains a heavy component
(such as free water) that tends to
separate from the main component. In
these instances, it should be recognized
that until the heavy component
completely settles out, sampling will
likely result in varying sample qualities.
No change was made to the final rule as
a result of these comments.
Section 3174.6(b)(2) contains the
requirements for determining the
temperature of oil contained in a sales
tank that is used as an FMP. Operators
must comply with paragraphs (b)(2)(i)
through (iii) of this section and API 7
and API 7.3. The BLM received
numerous comments on this section.
Several commenters requested that the
BLM eliminate the reference to mercury
in paragraph (b)(2)(i). In the proposed
rule, that paragraph required glass
thermometers to be clean, be free of
mercury separation, and have a
minimum graduation of 1.0 °F. The
BLM agrees that the mercury reference
should be removed because the EPA has
banned mercury thermometers from use.
As a result of these comments, the final
rule has been changed to say that glass
thermometers must be ‘‘free of fluid
separation.’’
The BLM received a comment
concerning paragraphs (ii) through (iv),
which said the reported graduation and
accuracy requirements for temperature
measurement devices are different based
on the technology employed (minimum
graduation of 1.0 °F for liquid-in-glass
thermometer vs. minimum graduation of
0.1 °F for portable electronic
thermometers (PET)). The commenter
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did not elaborate, but we assume the
commenter believes PETs should be as
accurate as glass thermometers. This
comment is not consistent with the
mandate of keeping the uncertainty in
the measured quantity to within a
specified value, nor is it consistent with
existing industry standards (API MPMS
Chapter 7). The BLM disagrees in part
with this comment since the BLM used
the minimum graduations from the
industry standard, of 1.0 °F for glass and
0.1 °F from electronic thermometers. For
consistency, and as a result of this
comment, the BLM is requiring an
accuracy of ±0.5 °F for both glass and
electronic thermometers.
Several commenters questioned the
thermometer immersion times required
in the proposed rule under paragraph
(b)(2)(iii), which referenced API 7, Table
6. They also asked the BLM to allow
alternate methods for determining
opening oil temperatures, to alleviate
potential safety and economic concerns.
The BLM disagrees in part as the
immersion times are an industry
standard, but also agrees in part to allow
alternate methods under API 7. The
prescriptive requirements under
paragraph (b)(2)(iii) have been removed
because the final rule already states that
operators must comply with API 7,
which includes the Table 6
requirements. Furthermore, the BLM
changed the rule to give operators more
flexibility by allowing them to use
alternate methods for temperature
determinations under API 7 and API
7.3, as well as the option of using ATG/
hybrid tank measurement systems, in
order to address the safety concerns
identified by commenters. As a result of
these comments and changes, the final
rule eliminates paragraph (b)(2)(iii) of
the proposed rule, resulting in the
renumbering of paragraph (b)(2)(iv) in
the proposed rule to paragraph (b)(2)(iii)
in this final rule.
Section 3174.6(b)(3) of the proposed
rule specified that sampling of oil
removed from an FMP tank must yield
a representative sample of the oil and its
physical properties, and must comply
with the procedures listed in paragraphs
(i) through (iii) of this section and API
8.1. The BLM received several
comments requesting that the final rule
give operators other sampling options.
The BLM agrees that other sampling
options can still achieve the desired
measurement uncertainty. As a result of
these comments, the BLM removed the
prescriptive requirements in paragraphs
(b)(3)(i) through (iii), and added a
reference to API 8.2’s standards for
automatic sampling procedures to the
final rule.
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Section 3174.6(b)(4) of the proposed
rule specified that tests for oil gravity
must comply with paragraphs (b)(4)(i)
through (iv) of this section and API 9.3.
The BLM received a couple of
comments on this section. One
commenter said that API Chapter 9
contains additional methods for
determining gravity that can be more
appropriate to use (based on the
conditions of the oil at sample time).
Therefore, the commenter asserted that
the final rule should simply specify that
any API Chapter 9 methodology is
appropriate for determining gravity. The
commenter said the procedure outlined
in the proposed section was not
consistent with API 9.3. Another
commenter stated that proposed
paragraph (b)(4)(i), which required the
use of a thermohydrometer for API
gravity (density) measurement, would
limit the use of new, automated, more
accurate technology such as Coriolis
meters and density gauges. The
commenter said allowance should be
made for other methods that can meet
the uncertainty requirements of the
regulation. The BLM agrees that this
provision of the proposed rule was too
prescriptive and unnecessarily limited
potential compliance options. As a
result of these comments, the following
changes were made to the final rule:
• This section now incorporates by
reference API 9.1, API 9.2, or API 9.3 to
allow additional methods to measure
API gravity;
• Paragraph (b)(4)(i) is changed to
include the use of a hydrometer in
addition to a thermohydrometer;
• Proposed paragraph (b)(4)(ii) has
been removed consistent with the
BLM’s determination that the provision
was too prescriptive;
• Proposed paragraph (b)(4)(iii) is
now paragraph (b)(4)(ii) and has been
revised to require operators to allow the
temperature to stabilize for at least 5
minutes; and
• Proposed paragraph (b)(4)(iv) is
now paragraph (b)(4)(iii) and has been
revised to require operators to read and
record the observed API oil gravity to
the nearest 0.1 degree, and to read and
record the temperature reading to the
nearest 1.0 °F.
Section 3174.6(b)(5) of the proposed
rule required operators to take and
record the tank opening gauge only after
upper, middle, and outlet samples have
been taken. It further required gauging
to comply with paragraphs (b)(5)(i)
through (b)(5)(v) of this section and API
3.1A. One commenter said the opening
measurement should be taken with a
matched (bob and tape) and currently
‘‘certified’’ gauging tape. The comment
recommended that the rule specify that
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the tape and bob shall be certified
within the last year as specified in API
3.1A. The BLM agrees with this
recommendation, as it is consistent with
API standards. As a result, the BLM has
included API 3.1A in this paragraph and
has eliminated prescriptive language
that repeats API 3.1A.
Similar to the proposed rule,
§ 3174.6(b)(5)(i) of the final rule
contains the requirements for manual
gauging. But in response to commenters’
requests that the BLM allow automatic
and hybrid tank gauging, as discussed
earlier in this preamble, this section in
the final rule includes a new paragraph
(b)(5)(ii), which contains the
requirements for ATG. During the initial
years of rule implementation, the BLM
will not limit which ATG makes or
models operators can use, but starting 2
years after the effective date of this rule,
operators will only be permitted to use
the ATG makes and models that the
BLM approves for use and lists on its
Web site. To ensure that ATG
equipment in use at that time meet with
BLM approval, the BLM encourages
operators, manufacturers, or other
entities (e.g., trade associations) to
pursue equipment approval prior to use.
Paragraph (b)(5)(ii) identifies
requirements for inspecting and
verifying the accuracy of ATG systems
and for maintaining a log of field
verifications.
Section 3174.6(b)(6) of the proposed
rule required operators to determine
S&W content using the oil samples in
the centrifuge tubes collected from the
upper and outlet fluid column (see
paragraph (b)(3) of this section), and
determine the S&W content of the oil in
the sales tanks, according to paragraphs
(b)(6)(i) through (iii) of this section and
API 10.4. The BLM received a few
comments on this section. The
commenters all addressed the fact that
API 10.4 has been updated since the
BLM published the proposed rule, and
that the prescriptive requirements in
paragraphs (b)(6)(i) through (iii) were
not consistent with the revised industry
standard. The BLM agrees that the API
standard has been updated and that the
requirements in paragraphs (b)(6)(i)
through (iii) of the proposed rule are too
prescriptive and inconsistent with the
revised industry standard. Based on its
review of the revised standard and as a
result of these comments, the BLM
removed the prescriptive requirements
in paragraphs (b)(6)(i) through (iii). The
final rule requires operators to
determine S&W content by using API
10.4, which has been incorporated into
the final rule by reference.
Without saying why, one commenter
said the BLM should incorporate all
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sections of API Chapter 10 into the final
rule. The BLM disagrees. Since the oil
measurement at issue in this rule is
inherently a ‘‘field procedure,’’ in which
the S&W content is required to be
determined and documented on the run
ticket at the completion of the tank
gauging/custody transfer procedure, the
BLM determined that the only
applicable section is 10.4. This
comment did not result in a change to
the final rule.
Section 3174.6(b)(7) requires
operators, after conducting the S&W
determination, to conduct the transfer
operation and seal the effected valves
under §§ 3173.2 and 3173.5 of this part.
There were no comments to this section.
Section 3174.6(b)(8) requires
operators to determine the tank closing
temperature following procedures
discussed in paragraph (b)(2) of this
section. Any comments concerning
temperature determination have been
addressed earlier in the paragraph (b)(2)
discussion.
Section 3174.6(b)(9) requires
operators to take the closing gauge using
procedures in paragraph (b)(5) of this
section. Any comments concerning
gauging operations have been addressed
in the paragraph (b)(5) discussion.
Section 3174.6(b)(10) requires
operators to end their tank-gauging
operations by completing a
measurement ticket in accordance with
§ 3174.12. The proposed rule included
seven activities in paragraphs (b)(10)(i)
through (vii) that dictated how operators
should derive the data required for the
measurement tickets. Some commenters
said this list of activities was too
prescriptive. In an effort to be less
prescriptive, the BLM deleted
paragraphs (b)(10)(i) through (vii) in the
final rule and refers operators to the
rule’s measurement-ticket requirements.
Section 3174.7 LACT System—General
Requirements
Paragraphs (a) through (c) of this
section in both the proposed and final
rule refer operators to other sections of
this rule for construction and operation
requirements for LACT systems, proving
requirements, and measurement tickets.
The proposed rule in paragraph (a)
included a reference to API standards
and in paragraph (c) a table that listed
the requirements and components of a
LACT system, along with references to
the sections of the proposed rule
containing the minimum standards for
each of those components. The BLM
received several comments on these
paragraphs.
Several commenters said the BLM
should not be so prescriptive and
should instead require compliance with
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the appropriate API standards. In
general, the BLM agrees that following
published industry standards can result
in the desired measurement uncertainty,
and paragraph (a) of the final rule now
requires LACTs to meet the standards
prescribed in the applicable API
sections. Paragraph (b) of the final rule
requires LACTs to be proven as
prescribed in § 3174.11 of this subpart.
The proposed table of ‘‘Standards to
measure oil by a LACT system’’ from
paragraph (c) has been removed.
Although it was a handy reference that
directed readers to requirements that
were listed in other sections of the
proposed rule, the table was redundant
and unnecessary. Paragraph (c) in the
final rule now refers to the requirement
for completing measurement tickets
under § 3174.12(b).
Several commenters were uncertain
about whether the LACT requirements
only applied to new facilities, with
existing facilities grandfathered. Most of
the commenters also suggested that
bringing existing facilities into
compliance within the 180-day
implementation timeframe was either
too expensive, impossible, or both. In
response to these comments, and as
discussed previously in this preamble,
the BLM has clarified in the final rule
that all facilities are subject to the new
requirements, with operators required to
come into compliance on a staggered
schedule of between 1 and 4 years,
depending on their levels of production.
This was achieved by tying compliance
to the requirement to apply for an FMP
found in the new 43 CFR subpart 3173.
These significantly extended time
frames will give operators time to plan
and budget for expenses in advance,
while limiting the chances that there
will be local or national shortages of
equipment or technical expertise, as
might have resulted from the original
proposed, 180-day implementation
period.
Several commenters noted that in
proposed paragraph (c), the BLM
limited LACTs to those with PD meters,
and suggested that other types of meters
should be allowed. Most of those
commenters specifically requested that
Coriolis meters be allowed, but some
requested that any type of meter
permitted in API standards be allowed.
This would include PD, Coriolis, and
turbine meters. The BLM partly agrees
and has changed the rule to allow
Coriolis meters to be used with LACTs.
However, the BLM does not agree that
turbine meters should be allowed. In the
BLM’s experience, confirmed by many
industry sources, turbine flowmeters are
less accurate than PD and Coriolis
meters and are more subject to wear
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and/or damage. As a result, the BLM
will continue to disallow turbine meters
in LACTs. The change to allow Coriolis
meters in LACTs is found in
§ 3174.8(a)(1). The definition of, proving
standards for, and other specific
requirements related to the use and
operation of Coriolis meters are
addressed by other sections of the final
rule.
One commenter stated that § 3174.7(b)
would require operators to generate an
additional run ticket before proving, and
that the BLM should take into account
the additional cost associated with that
extra run ticket. The BLM did analyze
the financial impacts of increased run
tickets in its Paperwork Reduction Act
analysis, which was discussed in the
proposed rule preamble. Another
commenter pointed out that this
additional run ticket is unnecessary in
LACTs with flow computers as a flow
computer is capable of implementing a
new meter factor in the middle of a
month without the operator having to
close it. The BLM agrees and as a result
of this comment, the BLM changed
§ 3174.12(b)(1) of the rule to remove the
requirement that operators close a run
ticket prior to proving LACT systems
that utilize flow computers, which will
reduce the overall cost to operators.
One commenter said the BLM should
remove requirements in proposed
§§ 3174.7(c) and 3174.8(b)(7) for S&W
monitors at LACTs because there is no
such thing as an ‘‘S&W monitor.’’ There
are water monitors or water probes, the
commenter continued, but water
monitors are not part of any oil
measurement system. Rather, operators
use water monitors to divert the flow
back to tanks for additional processing
to remove large amounts of water from
their production stream. The BLM
agrees with this commenter’s
assessment. From a regulatory
perspective, a water monitor should not
be required equipment at a LACT
because it does not help the BLM verify
accurate measurement and net oil
volumes. In the final rule, the BLM has
incorporated LACT requirements from
API 6.1 and eliminated the table in
§ 3174.7(c), along with the S&W monitor
requirements in § 3174.8(b)(7).
Section 3174.7 paragraphs (d) and (e)
retain current requirements that all
components of a LACT system be
accessible for inspection by the AO and
that the AO be notified of all LACT
system failures that may have resulted
in measurement error. Numerous
commenters stated that the term
‘‘notify’’ in paragraph (e)(1) was
ambiguous and requested that the BLM
define what forms of notification are
acceptable and the time frame for
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notifying the AO. The BLM agrees that
this term needs to be defined and has
defined ‘‘notify’’ to mean ‘‘to contact by
any method, including but not limited
to electronically (email), in-person, by
telephone, by form 3160–5 (Sundry
Notice), letter, or Incident of
Noncompliance.’’ This definition has
been added to the definitions listed in
43 CFR 3170.3, part of the rulemaking
that is replacing Order 3.
Numerous commenters stated that the
24-hour time frame in proposed
paragraph (e)(1) regarding notifying the
BLM of LACT system failure was: (1)
Impractical, (2) Too restrictive; (3)
Potentially unnecessary if the failure
was small (less than 0.05 percent); (4)
Unlikely to significantly affect the net
oil volume; (5) Too expensive for
operators to implement because
additional monitoring equipment would
be required; and (6) Would require
speculation on the part of the operators
as to when a malfunction occurred
when no one was present at the time of
the malfunction. Most commenters
suggested requiring reporting within 7
days after discovery. The BLM partly
agrees, and paragraph (e)(1) of the final
rule now requires notification within 72
hours after discovery. This time frame
will ensure that the BLM is able to
verify that all oil volumes are properly
derived and accounted for, and verify
any alternative measurement method,
meter repairs, or meter provings within
a reasonable time frame without placing
unnecessary burdens on the operator.
Requiring notification within 72 hours
will allow operators to deal with urgent
situations while still being able to
timely notify the BLM.
Section 3174.7 paragraph (f) of the
proposed rule would have retained the
current Order 4 requirement that any
tests conducted on oil samples taken
from the LACT system samplers for
determination of temperature, oil
gravity, and S&W content meet the same
minimum standards set in the manual
tank gauging sections. However, the
section of the preamble describing
proposed § 3174.7(f) incorrectly said the
oil samples themselves had to comply
with the standards in the manual tank
gauging section, rather than the testing
procedures used to measure
temperature, gravity (density), and S&W
content. One commenter pointed out
that this section not only incorrectly
implied that temperature is somehow
calculated from the oil in the sample
pot, it also incorrectly referred to the
standard testing procedures designed for
manual tank gauging, not for testing
using automated samplers as required in
LACTs. The commenter stated that the
BLM should use the standards in API
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8.1 for static (manual) tank gauging and
the standards in API 8.2 and API 8.3 for
automatic sampler systems in LACTs,
rather than referencing incorrect
methods. The BLM agrees that the
proposed rule preamble contains an
incorrect summary of the actual
proposed regulatory requirement in
§ 3174.7(f), and that the correct
reference should be API 8.1 for
sampling in static (manual) sampling
and API 8.2 and API 8.3 for automatic
sampler systems within LACTs. With
this clarification, § 3174.7(f) in the final
rule remains unchanged, although the
recommendation to incorporate API 8.2
and API 8.3 by reference is accepted.
The reference to this requirement is in
§ 3174.8(b)(1).
Paragraph § 3174.7(g) prohibits the
use of automatic temperature/gravity
compensators on LACT systems.
Although Order 4 requires these
devices, this rule will require those
automatic compensators to be replaced
using an electronic temperature
averaging device. Automatic
temperature/gravity compensators are
designed to automatically adjust the
LACT totalizer reading to compensate
for changes in temperature and, in some
cases, for changes in oil gravity as well.
Unfortunately, the accuracy or operation
of these devices cannot be verified in
the field and there is no record of the
original, uncorrected, totalizer readings.
As a result, there is no ability to create
an audit trail for these systems. As
explained in the proposed rule, the BLM
believes that the use of these devices
inhibits its ability to verify the reported
volumes because there is no source
record generated, and the devices
degrade the accuracy of measurement.
Because there are relatively few LACT
systems that still employ automatic
temperature/gravity compensators, the
BLM does not believe this requirement
will result in significant costs to the
industry.
Several commenters objected to this
requirement, stating that temperature
averagers are expensive and not
necessarily any more accurate than
temperature compensators, and that this
change would require operators to
replace functioning equipment at
significant cost for no readily apparent
benefit. One commenter stated that
existing equipment should be
grandfathered as long as an audit trail
exists, and that the BLM should provide
scientific evidence that automatic
temperature/gravity compensators are
less accurate than temperature averaging
devices. Other commenters said that the
simultaneous demand for temperature
averaging devices would drive up the
cost of purchasing and installing these
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devices on LACT systems. Several
commenters indicated that rather than
bear such a cost, some operators would
choose to shut in wells and cease
production activities.
In response to these comments, the
BLM conducted field surveys of the
companies that made the comments and
determined that, in fact, they had very
few LACTs that are still using automatic
temperature/gravity compensators.
Indeed, one of the companies had only
one such LACT. The fact that very few
LACTs still use automatic temperature/
gravity compensators was confirmed by
a major LACT manufacturer who stated
that they sell very few automatic
temperature/gravity compensators
domestically, and that nearly all LACTs
are currently equipped with
temperature averagers. Further, this rule
now provides for a phase-in of this new
equipment over the next 1 to 4 years,
based on when operators receive their
FMP approvals, and the cost is
relatively inexpensive (roughly $6,500
per LACT for the equipment). Regarding
scientific studies or other data showing
temperature averagers are more
accurate, the BLM is not aware of any
studies that show this. The main reason
for the prohibition is that a temperature
compensator is a mechanical device that
does not have the capability for
recording an ‘‘audit trail,’’ and therefore
is inconsistent with the BLM’s
production accountability obligations.
For these reasons, no change was made
in this final rule.
Section 3174.8 LACT System—
Components and Operating
Requirements
Section 3174.8 contains LACT system
components and operating
requirements.
This section is closely related to
§ 3174.7 in that § 3174.7 contains
general requirements for LACTs and
states that LACTs must meet the
construction and operation
requirements and minimum standards
of § 3174.8. Section 3174.8 goes into
detail on what those requirements and
standards are. Consequently, many of
the comments on this section are closely
related to comments received on
§ 3174.7.
In the proposed rule, § 3174.8(a) listed
the components that each LACT must
include. Several commenters said the
BLM should not be so prescriptive and
should instead require operators to
comply with the appropriate API
standards. One commenter stated this
change would eliminate confusion and
make it clear that Coriolis meters would
be allowed as part of LACTs. In general,
the BLM agrees that the original
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81483
language was too prescriptive and may
have inadvertently disallowed the use of
Coriolis meters with LACTs. As a result
of these comments, the final rule now
simply requires LACTs to meet the
standards prescribed in the applicable
API sections. The list of all of the
components required in LACTs has now
been deleted from paragraph (a) and
replaced with a statement that each
LACT must include all equipment listed
in API 6.1, with certain listed
exceptions. The LACT components
listed in § 3174.8(a) are related to
requirements for PD and Coriolis meters
and electronic temperature averaging
devices, and allow multiple means of
applying back pressure to the LACT to
ensure single-phase flow. LACTs must
consist of meters that have been
reviewed by the PMT, approved by the
BLM, and identified and described on
the nationwide approval list at the BLM
Web site (www.blm.gov) (see
§ 3174.8(a)(1)). Initially, the BLM will
have no PD or Coriolis meter make or
models limitations, but starting 2 years
after the effective date of the rule,
operators can only use the PD or
Coriolis meter makes and models that
the BLM approves for use and lists on
its Web site. To ensure that specific PD
and Coriolis meters in use at that time
meet with BLM approval, the BLM
encourages operators, manufacturers, or
other entities (e.g., trade associations) to
pursue equipment approval prior to use.
One commenter stated that proposed
§ 3174.8 did not refer to industry
standards for automatic sampling
systems used with LACT and Coriolis
meter systems, and that failure to
provide minimal requirements could
result in samples which were not
representative, and therefore erroneous.
The commenter also stated that
proposed paragraph (b)(4), pertaining to
standards for mixing of samples, should
instead prescribe compliance with API
8.3, which contains the appropriate
standards. Another commenter stated
that proposed § 3174.8(a) did not
mention an inline mixer or any
pressure/temperature instrumentation,
and asked if these items were prohibited
or just not considered necessary. The
same commenter stated that proposed
§ 3174.8(b)(2) discussed sample probe
locations when standards for automatic
sampling had not yet been incorporated
into the rule, and requested that rather
than restating portions of the standards
in the rule, the BLM should incorporate
API MPMS Chapters 8.2 and 8.3 into the
rule.
The BLM agrees with the points
raised in these comments and so, in the
interest of eliminating uncertainty and
errors, the final rule includes industry
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Federal Register / Vol. 81, No. 222 / Thursday, November 17, 2016 / Rules and Regulations
standards for automatic sampling
systems and for mixing of samples. The
final rule now includes a requirement
that sampling and mixing of samples
must comply with the standards in API
8.2 and API 8.3, respectively.
One commenter stated that the
requirement in proposed § 3174.8(a)(10)
and (b)(13) to have a back pressure valve
and check valve downstream of the
LACT could be met by allowing
operators to use another common
industry practice of placing a pump
downstream. The BLM agrees that this
arrangement would meet the intent of
the requirement, which is to ensure
single-phase flow through the meter,
and has changed the rule accordingly.
The revised requirement is more flexible
and is found in the renumbered final
rule at § 3174.8(a)(3).
One commenter noted that in
proposed § 3174.8(a)(7), the BLM
limited LACTs to only using a PD meter,
and said that any type of meter
permitted in API standards should be
allowed. These standards include PD,
Coriolis, and turbine meters. The BLM
partly agrees and has changed the rule
to allow Coriolis meters because field
and laboratory testing have proven the
Coriolis meter to be reliable and
accurate. However, the BLM does not
agree that turbine meters should be
allowed. In the BLM’s experience,
confirmed by many industry sources,
turbine flowmeters are less accurate and
are more subject to wear or damage. As
a result, the BLM will continue to
prohibit the use of turbine meters in
LACTs. The change to allow Coriolis
meters in LACTs is reflected in
§ 3174.8(a)(1) of the final rule.
References to the definition of, proving
standards for, and other specific
requirements for Coriolis meters are
contained throughout the rule in
appropriate sections.
Section 3174.8(b) describes the
system operating requirements for
LACTs. Multiple comments were
received on this section, many of which
focused on making the requirements
less prescriptive and instead referencing
API standards more extensively.
In general, in response to numerous
comments that the proposed rule lacked
flexibility, we have removed most of the
prescriptive requirements in proposed
§ 3174.8(b). This section now requires
operators to follow the sampling-process
standards in API 8.2 and API 8.3 (the
equipment and procedures to obtain and
properly mix a representative sample);
the standards for measuring the gravity
(density) and S&W content of those
samples in API 9.1, API 9.2, API 9.3,
and API 10.4; the standards for flow
measurement using electronic meter
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systems in API 21.2; the standards for
temperature determination in API 7; and
the standards for calculating net oil
volumes for each run ticket in API
12.2.1 and API 12.2.2. All of these API
standards are incorporated by reference
and listed in § 3174.3.
One commenter objected to the BLM’s
requirement in proposed § 3174.8(b)(1)
that LACTs include an electrically
driven pump sized to ensure: (1) A
discharge pressure compatible with the
meter used; and, (2) That the flow in the
LACT main stream piping is turbulent,
such that the measurement uncertainty
levels proposed in § 3174.3 are met.
Instead, the commenter suggests that the
BLM should require LACTs to meet
uncertainty requirements without being
so prescriptive. Another commenter
stated that the BLM should be more
flexible about the types of S&W
monitors that would be allowed under
proposed § 3174.8(b)(7) because some
manufacturers do not make the types of
plastic-coated probes that this section
required. The commenter also suggested
that existing S&W monitoring
technologies should be grandfathered.
Several other commenters stated that
the requirement for a back pressure
valve in proposed § 3174.8(b)(13) was
too prescriptive and did not give
operators the flexibility to use other
methods to achieve the same result that
back pressure valves provide—
maintaining single-phase (oil-only) flow
through the LACT meter. As discussed
earlier, the BLM is keeping the
requirement that LACT systems contain
a back-pressure valve in the final rule at
§ 3174.8(a)(3), but we agree with
commenters that the requirement needs
to be more flexible, and we have added
language that gives operators the option
of using other controllable means of
applying back pressure to ensure singlephase flow. Also in response to these
comments, the BLM removed most of
the prescriptive requirements in
proposed § 3174.8(b) and replaced them
with a requirement that operators meet
the LACT system operating standards
outlined in the applicable API standard
incorporated by reference into the
proposed rule. The only requirements
that are spelled out in paragraph (b) are
those requirements that are in addition
to or different from standard API
practices or that clarify which API
standards are applicable.
Several commenters expressed
concern that retrofitting or replacing
existing equipment to meet the
requirements of § 3174.8 was
unnecessary and prohibitively
expensive, and that existing facilities
should be grandfathered, with some also
suggesting that bringing existing
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facilities into compliance within the
proposed 180-day implementation
timeframe was either too expensive,
impossible, or both. In response to these
comments, the BLM has clarified in
§ 3174.2 in the final rule that all
equipment must comply with the new
requirements, with operators required to
come into compliance on a staggered
schedule of between 1 and 4 years,
depending on when they receive their
FMP approvals, which is based on their
production levels. This significantly
extends the compliance timeframe and
gives operators time to budget and plan
for any required changes, while limiting
the chances that there will be local or
national shortages of equipment or
technical expertise, such as might have
resulted from the proposed 180-day
implementation period.
One commenter stated that proposed
§ 3174.8(b) should be revised to include
a densitometer as optional equipment in
the list of components, and that if
density is provided, recordable,
auditable, and verifiable, then the
sampler and sample pot should not be
required, which would save operators
the cost of those components and lab
analyses to determine S&W content. The
commenter further said that if the
sampler is not included in the list of
components, then S&W content must be
reported as zero percent, and the entire
volume passing through the LACT meter
would be reported as 100 percent oil.
The BLM understands that there may be
cases in which the operator would be
willing to consider the entire produced
stream as 100 percent oil, but the BLM
believes that omitting the sampler and
sample pot would create the potential
for added confusion, and it is likely that
most purchasers are going to require a
sample grind-out anyway. For these
reasons, no change was made to the rule
as a result of this comment.
One commenter pointed out that
proposed § 3174.8(b)(11)(ii), which
required a temperature averaging device
to take a temperature reading at least
once per barrel, did not accord with API
21.2, Subsection 9.2.8.1, which requires
such devices to be flow proportional
and take a reading at least once every 5
seconds. The BLM agrees and has
changed the rule accordingly. This
provision in the final rule has been
renumbered as § 3174.8(b)(6)(ii) and
now reads: ‘‘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
§ 3174.3).’’
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Sections 3174.9 and 3174.10 Coriolis
Measurement Systems
Sections 3174.9 and 3174.10 pertain
to CMS, which are not addressed in
Order 4. Order 4 allows only for the use
of PD meters with LACT systems. The
use of Coriolis meters in this rule is
based on technological advancements
that provide for measurement accuracy
that meets or exceeds the overall
performance standards in § 3174.4.
Field and laboratory testing of Coriolis
meters has proven them to be reliable
and accurate meters when installed,
configured, and operated correctly.
One commenter said the final rule
should allow operators to use truckmounted CMS and submitted
summarized data to support their view.
The summarized data indicates
significant differences between manualgauged volumes and truck-mounted
Coriolis-metered volumes. A summary
of these volume differences indicated
that the truck-mounted Coriolis meter
measured as much as 22.44 bbl less that
the manual gauge measured. Missing
from the data is the volume of the entire
load. The BLM needs this information to
understand how significant these
variations are. The data also indicates
significant differences in measured oil
temperature (as much as 23 °F) and
gravity (as much as 5 degrees) when
compared to manual methods. The
commenter did not explain these
differences or explain or justify the data
submitted. The BLM decided not to
include the use of truck-mounted
Coriolis metering in the final rule.
Operators may seek approval to use the
truck-mounted option through the PMT
approval process, which is outlined in
§ 3174.13. The rule was not changed
based on this comment.
Another commenter suggested that
the CMS could be used for gas
measurement, in addition to oil
measurement. The BLM has noted this
comment; however, this subpart is
dedicated to the measurement of oil.
The rulemaking that is replacing Order
5 is a more appropriate venue for
considering this comment, and this
comment was directed to that rule team.
The comment did not result in a change
to this rule.
Several commenters stated that the
term ‘‘CMS’’ should not be used for a
Coriolis LACT as it is simply a LACT.
The BLM agrees with this comment and
has no intention of replacing the term
‘‘LACT’’ with the term ‘‘CMS.’’ The rule
as proposed was intended to allow the
Coriolis meter to be used in a LACT as
an alternative to the PD meter, or as a
standalone meter independent of a
LACT system. The term CMS refers only
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to the latter option. To clarify this issue,
the final rule has been edited to state
that a Coriolis meter may be used in a
LACT or as a standalone CMS meter.
Section 3174.9(b) specifies that
Coriolis meters that have been reviewed
by the PMT, approved by the BLM, and
identified and described on the
nationwide approval list at the BLM
Web site (www.blm.gov) are approved
for use. Initially, the BLM will have no
Coriolis meter make or model
limitations on the approved list, but
starting 2 years after the effective date
of the rule, operators will only be able
to use the Coriolis meter makes and
models that the BLM approves for use
and lists on its Web site. To ensure that
specific Coriolis meters in use at that
time meet with BLM approval, the BLM
encourages operators, manufacturers, or
other entities (e.g., trade associations) to
pursue equipment approval outlined in
§ 3174.2(g) prior to use. Installations
meeting the requirements described in
this section and § 3174.10 do not require
additional BLM approval. CMS proving
must meet the proving requirements
described in § 3174.11 and
measurement tickets would be required,
as described in § 3174.12(b).
One commenter said requiring each
operator to have its CMS approved
would result in a large financial burden.
The BLM disagrees because the PMT
only needs to approve a particular make
or model of Coriolis meters once. Once
a meter make or model has been
reviewed, approved, and posted on the
BLM’s Web site, the meter can be
installed at any facility, subject to any
COAs imposed by the PMT for its use.
Existing installations that already meet
the requirements in §§ 3174.9 and
3174.10 do not require additional BLM
approval.13
Section 3174.9(c) requires that a CMS
be proved following the frequency
established under § 3174.11. This
proving frequency will ensure that
operators periodically prove the CMS to
provide verification that the meter is
within the allowable tolerances. There
were no comments on this section.
Section 3174.9(d) requires that
measurement (run) tickets be completed
as required by § 3174.12(b). This
establishes the measurement-ticket time
periods and minimum requirements for
information that must be included on
the tickets. There were no comments on
this section.
Section 3174.9(e) identifies the
applicable API standards for the
components that must be installed with
13 Additional comments on the PMT and the
procedure that the PMT will use to approve devices
are addressed in the discussion of § 3174.13.
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a CMS at an FMP, and includes some
additional requirements that operators
using a CMS for oil measurement must
follow. The proposed rule listed the
components in exact order from
upstream to downstream of a CMS. The
BLM has opted to be less prescriptive in
the final rule and is requiring operators
to follow API 5.6 for the setup and
installation of a CMS system.
One of the prescriptive requirements
in proposed § 3174.9(e)(7) was for
operators to install a density
measurement verification point. One
commenter asked that this term be
defined. Since the BLM has removed the
prescriptive requirements and this
particular term from the rule, a
definition is no longer needed. No
change resulted from this comment.
Another commenter said the BLM
needs to allow for a connection point for
a pycnometer. As discussed earlier, the
BLM has removed the prescriptive, stepby-step requirements in this section.
Should an operator wish to use this
density-determination option, API 5.6
does allow for a density verification
point that could be used as the point for
installing the pycnometer. There was no
change to the rule as a result of this
comment.
Section 3174.9(e)(1) and (2) sets
accuracy thresholds for temperature and
pressure measurement devices that are
part of a CMS. These devices are
required to calculate the CPL and CTL
correction factors. The uncertainties of
these devices will be used in the overall
uncertainty calculation to ensure that
the CMS meets or exceeds the
uncertainty levels required by § 3174.4.
There were no comments on this
section.
Section 3174.9(e)(3) covers the
options for handling S&W content when
determining net volume. Measurement
by LACT requires a composite sampling
system and determines net oil volume
by deducting S&W content. The CMS
does not require a composite sampling
system, but rather leaves the option to
the operator to either install a composite
sampling system to determine S&W
content for deduction in net oil
determination or to make no S&W
content deduction in net oil
determination. In practice, Coriolis
meters may be used at the outlet of a
separator. It may not be feasible to use
a composite sampling system at the
outlet of a separator due to high
separator pressure, thus effectively
precluding the ability to determine S&W
content. Without the ability to
accurately determine S&W content,
§ 3174.9(e)(3) will require operators to
report the S&W content as zero. The
BLM may consider options to use other
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methods to determine S&W content
should acceptable technology or
processes be proposed in the future.
However, the BLM will only approve an
alternate method of S&W content
determination if the resulting overall
measurement uncertainty is within the
limits of § 3174.4(a).
Several commenters stated that if the
rule does not allow corrections for S&W
content, operators will be required to
report an inaccurate volume. The BLM
agrees that failing to correct for S&W
content could result in an inaccurate
measurement of net volume of product
sold. However, this rule gives the
operator the option to determine S&W
content; if the operator chooses not to
install the necessary equipment to
determine the accurate S&W content,
then no deduction will be allowed. The
inclusion of the CMS as a method to
measure production does not make this
the sole means of measurement. It will
be at the discretion of the operator to
determine which method of
measurement is most effective for their
operation. In certain operations where a
composite sampling system cannot be
installed, and the operator determines
reporting S&W content as zero is
inappropriate for their operation, other
measurement options may be available,
though the operator will have to seek
review through the PMT. No change to
the rule resulted from these comments.
Relatedly, several commenters stated
that the BLM should allow other
methods to determine S&W content. The
BLM agrees that other methods could be
allowed, but the BLM does not currently
have the data to review those options.
As noted, under the final rule, an
operator wishing to use a different
option for determining S&W content
will have to seek approval through the
PMT process, as outlined in § 3174.13.
No change resulted from this comment.
Section 3174.9(e)(4) requires singlephase flow through the CMS by means
of applied back pressure. The proposed
rule would have required operators to
use a back pressure valve downstream
of the Coriolis meter to achieve singlephase flow. Several commenters stated
that there are other means of applying
back pressure that are just as effective as
using a back pressure valve, such as
pumps downstream of the CMS. The
BLM agrees and has changed the rule as
a result of this comment. Instead of
allowing only a back pressure valve, the
BLM will allow the operator to use any
means to apply sufficient back pressure
to ensure single phase flow, so long as
the approach meets the requirements of
API 5.6.
Section 3174.9(f) allows the API oil
gravity to be determined by using one of
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two methods: (1) From a sample taken
from a composite sample container; or
(2) Directly from the average density
measured by the Coriolis meter. This
choice accommodates situations in
which it is not feasible or an operator
chooses to not install a composite
sampling system due to economic or
operating constraints. The BLM may
consider other methods for determining
the API gravity of the fluid, such as inline densitometer devices. However, the
BLM will only approve alternative
methods if resulting overall uncertainty
is within the limits in § 3174.4.
One commenter suggested that the
BLM should incorporate by reference
the guidelines in API 8.2 and API 8.3 on
composite sampling. Because a sample
from a composite sample container is an
acceptable method for determining the
API oil gravity, the BLM agrees that the
industry standard should be included
and has incorporated API 8.2 for
automatic sampling and API 8.3 for
mixing and handling of samples into
§ 3174.8(b)(1) of the final rule.
Another commenter stated that the
use of Tables 5A and 6A is
inappropriate and that the flowing
density should be corrected in
accordance with API 11.1. The BLM
agrees that Tables 5A and 6A are
outdated and should not be used and
has removed the language that
referenced Tables 5A and 6A and
replaced it with a reference to API 11.1.
Another commenter stated that
abnormal events should be excluded
from the average density calculation.
The BLM assumes the commenter is
referring to the fact that water, sand, or
gas breakout may occur during a normal
flowing regime. Excluding these
abnormal events from the average
density is allowed under the final rule,
so long as an audit trail is maintained
showing the full-flow density, including
the period of flow that has been
removed from the average density
calculation. There is no change to the
final rule as a result of this comment.
Another commenter said that during
proving, a density correction factor
should be applied if the densitometer
within the Coriolis meter varies from a
master densitometer at the density
verification point. The BLM disagrees
with this comment. During the proving
verification of the densitometer within
the Coriolis meter, the density reading
is compared to an independent density
measurement. The difference between
the indicated density determined from
the Coriolis meter and the
independently determined density must
be within the specified density
reference accuracy specification of the
Coriolis meter. If the Coriolis
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densitometer exceeds the
manufacturer’s specification density
tolerance, then the meter must be
repaired or replaced, or an alternative
method of density determination must
be approved for use. Any alternative
method must result in an overall
uncertainty that is within the limits in
§ 3174.4.
Section 3174.9(g) requires that the net
standard volume be calculated
following API 12.2.1 and API 12.2.2.
The proposed rule listed this
requirement in § 3174.10(g) and gave
very prescriptive requirements for the
calculation. However, in order to make
the final rule less prescriptive and to
rely on industry standards wherever
possible and appropriate, the
requirement has been moved to
§ 3174.9(g), and the prescriptive
language has been removed in favor of
the guidelines listed in API 12.2.1 and
API 12.2.2.
Several commenters said that net
standard volume cannot be calculated
by current Coriolis meters or any flow
meter for that matter. The BLM agrees
with these comments and for that reason
there are no requirements in this rule
that the CMS, or any meter, calculate
and display net standard volume. No
change was made to the rule as a result
of these comments.
Another commenter stated that
operators should be allowed to apply a
shrinkage factor to the net standard
volume. The BLM disagrees because
past experience in reviewing net oil
determinations shows that applying a
calculated shrinkage factor results in
very high uncertainty for the metering
systems. The resulting overall
uncertainty would exceed the limits of
§ 3174.4. Should new methods or
technology for applying shrinkage
factors be developed and proposed for
use in the future, the PMT process
described in § 3174.13 would be used
for review and approval of those
methods or technologies. No change to
the final rule has been made as a result
of this comment.
§ 3174.10 Coriolis Meter for LACT and
CMS Measurement Applications—
Operating Requirements
Section 3174.10(a) establishes the
minimum pulse resolution (i.e., the
increment of total volume that can be
individually recognized, measured in
pulse per unit volume) of 8,400 pulses
per barrel for CMSs. Because this
resolution is standard for PD meters,
and is accepted by the BLM, the same
standard applies to CMSs. The BLM did
not receive comments on this section.
Section 3174.10(b) establishes the
minimum standards and specifications
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for specific makes, models, and sizes of
Coriolis meters. The specifications will
allow the BLM to determine the overall
measurement uncertainty of the CMS, to
ensure that it meets the requirements of
§ 3174.4, and to help insure that the
meters are properly installed.
One commenter recommended that
the BLM remove the requirement for
maintaining and submitting to the BLM
upon request the Coriolis meter
specifications found in § 3174.10(b).
The commenter said this requirement is
not necessary for uncertainty-based
measurement limits. The BLM
disagrees. In order for the BLM to
conduct a complete inspection of the
CMS, it is necessary that all information
required by this section be available to
ensure that the Coriolis meter is
operating within its design parameters,
on which the uncertainty for the meter
is based. No change in the final rule was
made as a result of this comment.
Proposed § 3174.10(b)(iv) required
that the minimum amounts of straight
piping be installed upstream and
downstream of the meter. Several
commenters said that Coriolis meters do
not require any specific amount of
straight piping. The BLM agrees that
pipe-length restrictions in Coriolis
meter installations do not affect accurate
measurement and has removed any
reference to straight-pipe requirements
for Coriolis meters from the rule.
Section 3174.10(c) requires a nonresettable totalizer for indicated volume.
This is to allow verification over
multiple run tickets of gross production
prior to any adjustments to net standard
volume. There were no comments on
this requirement.
Proposed § 3174.10(c) had a
requirement for meter orientation. One
commenter said the BLM should remove
this requirement because it is too
prescriptive and should instead require
operators to follow API standards. The
BLM agrees that the proposed language
was too prescriptive. The final rule, in
§ 3174.10(e), now requires operators to
follow API 5.6.
Section 3174.10(d) of the proposed
rule required that the operator must
notify the AO within 24 hours of any
changes to any Coriolis meter internal
calibration factors including, but not
limited to, meter factor, pulse-scaling
factor, flow-calibration factor, densitycalibration factor, or density-meter
factor. One commenter suggested that 24
hours is an unreasonably short period of
time for this requirement, especially if
the applicable changes occur on a
weekend. The commenter
recommended a period of at least 10
days, or a monthly report from the PLC
log. After consideration of this proposed
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requirement, the submitted comment,
and the proving requirements in the
final rule, the BLM has decided to
remove this notification requirement
from the rule because any changes to a
Coriolis meter internal calibration factor
will require immediate proving of the
meter as required in § 3174.11(d)(8). An
additional notification provides no
benefit to the BLM.
Section 3174.10(d) (paragraph (f) in
the proposed rule) requires verification
of the meter zero reading before proving
the meter or any time the AO requests
it. The proposed rule described the
process for verifying the meter zero
value. The BLM has changed the
wording in the final rule to be less
prescriptive and to require the operator
to follow manufacturer guidelines. This
gives the operator flexibility during the
verification procedure.
Several commenters said that
requiring flow to be stopped during
meter verification is an additional step
and may disrupt normal operations. The
BLM agrees that in order to verify that
the meter is operating within the
manufacturers’ specifications, operators
are required to verify the meter zero
with no fluid flow. However, the BLM
disagrees that meter zero verification is
a disruption to normal operations.
According to API standards and
manufacturer recommendations,
Coriolis meter zero verification is a part
of normal operations. As discussed
above, the final rule has been changed
to require operators to follow
manufacturer guidelines for meter zero
verification; however, the requirement
to verify meter zero remains in the final
rule.
Section 3174.10(e)(1) through (e)(4)
(paragraphs (i)(1) through (i)(4) in the
proposed rule) lists the information that
the Coriolis meter must display onsite.
As part of the BLM’s verification
process during field inspections, the AO
must be able to access this information
without the use of a laptop or other
special equipment. A log must be
maintained of all meter factors, zero
verifications, and zero adjustments, and
must be made available to the AO upon
request. The proposed rule would have
required operators to maintain the log
onsite.
The BLM received several comments
stating that the requirement for a log to
be maintained onsite containing the
meter factor, zero verification, and zero
adjustments is not practical. Because
this information will not need to be
readily available onsite for the AO to
complete an inspection, the BLM agrees
with the commenters and has changed
the final rule in § 3174.10(e)(4) to
require that the log containing the meter
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factor, zero verification, and zero
adjustments must be made available
upon request.
One commenter stated that the
requirement in paragraph (e)(2) for the
meter to display the instantaneous
pressure has no valid use. The BLM
disagrees with this statement as this
information is needed as part of routine
inspections conducted by the AO to
verify the flowing volume in a meter. No
changes were made as a result of this
comment. Another commenter said that
some Coriolis meters do not have the
ability to display the density in pounds
per barrel as originally required by the
proposed rule. After contacting Coriolis
system manufacturers, the BLM has
confirmed that not all Coriolis meters
have the ability to display this
particular unit of measurement.
Therefore, as a result of this comment,
the requirement to display the density
in pounds per barrel has been removed
and other units of measurement (pounds
per gallon or degrees API) have been
added in § 3174.10(e)(2)(i). One
commenter said that daily volume totals
may not be available for display. The
BLM contacted manufacturers and
confirmed that Coriolis meters are
capable of displaying daily volume
totals. As a result, there was no change
in the final rule from this comment.
Section 3174.10(f) requires that audit
trail information listed in § 3174.10(f)(1)
through (4) be retained for the time
period required in § 3170.7, which is
part of the rulemaking to replace Order
3. One commenter said that the
requirements in § 3174.10(f)(2) and (4)
may force operators to add a flow
computer to a Coriolis LACT, which
exceed the requirements of a PD LACT.
This comment does not make sense
because a Coriolis meter almost always
has a flow computer. If an operator
chooses to configure a Coriolis meter in
a LACT without utilizing a flow
computer, and display only a totalizer
reading, then the requirements of
§ 3174.10(f)(2) and (4) would not apply.
No change resulted from this comment.
Section 3174.10(g) requires that each
Coriolis meter have an operable backup
power supply or nonvolatile memory
capable of retaining all data. This is to
ensure that during a failure, all audit
trail data is preserved to maintain
compliance with these regulations.
There were no comments on this
section.
Section 3174.11 Meter-Proving
Requirements
Proposed § 3174.11(a) and (b) would
have established that a meter would not
be eligible to be used for royalty
determination unless it is proven to the
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standards detailed in the proposed rule.
The BLM received no comments on
these paragraphs. The final rule
specifies the minimum requirements for
conducting volumetric meter proving
for all FMP meters. Paragraph (a) in the
proposed rule was carried forward to
the final.
A table in proposed paragraph (b)
referred readers to the applicable
paragraphs of this proposed section that
contained the minimum standards for
proving FMP meters. The BLM received
no comments on this table.
Nevertheless, the BLM did not include
the paragraph (b) table in the final rule
because the table did not provide
substantive clarity or expedite reader
access to the relevant paragraphs. This
change resulted in the re-lettering of all
subsequent section paragraphs in the
final rule.
Paragraph (c) in proposed § 3174.11
(re-lettered to paragraph (b) in the final
rule), established the acceptable types of
meter provers that can be used to prove
an FMP LACT or CMS. The BLM
received a few comments objecting to
the meter-proving requirements in this
section of the final rule because they are
not consistent with the referenced API
specifications. These comments are
addressed in the following text.
Section 3174.11(b)(1) through (3) of
the final rule describe and detail the
requirements for acceptable meter
provers, which include the master
meters and displacement provers that
are currently allowed under Order 4.
Coriolis master meters, which were not
addressed in Order 4, have been
included in the final rule. The BLM
believes that Coriolis technology has
advanced to the point where Coriolis
meters meet the accuracy and
verifiability requirements required for
master meters. The final rule does not
allow tank provers to be used as an
acceptable device for proving a meter.
According to API standards, tank
provers are not recommended for use on
viscous liquids, which include most
crude oils. Because there are few tank
provers currently in use on Federal and
Indian leases, this requirement will not
result in a significant cost to industry.
One commenter on paragraph (b)(1)
stated that the BLM requirement for
master meter repeatability of 0.0002
(0.02 percent) is inconsistent with API
4.5, which requires a repeatability of
0.0005 (0.05 percent). The BLM agrees
with the commenter and made a change
to the final rule consistent with the
comment. The BLM believes that the
paragraph (b)(1) repeatability
requirement for master meter provers in
the proposed rule was too restrictive
and the API 4.8 (as referenced in API
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4.5) specification of 0.0005 (0.05
percent) repeatability is within the
uncertainty (±0.027 percent) of BLM
requirements.
The BLM also made a change to the
final rule based on a comment that the
calibration of the master meter prover in
the proposed rule was too frequent. The
proposed rule required master meter
provers to be calibrated no less
frequently than once every 90 days. The
BLM agrees that the 90-day frequency
for proving master meters may be too
frequent. The final rule changes the
master meter calibration frequency to no
less than once every 12 months, which
is consistent with API 4.8, Subsection
10.2, which is referenced in API 4.5.
One comment on paragraph (b)(2) of
this section said the BLM displacement
prover calibration requirements
contradict API Chapter 4.9. The BLM
disagrees with the commenter since API
4.9 addresses calibration methods for
displacement provers and not
calibration frequency for displacement
provers as specified in API 4.8. The
BLM changed paragraph (b)(2) in the
final rule by removing the prescriptive
language found in paragraphs (b)(2)(i)
and (ii) in the proposed rule, and by
incorporating calibration frequency
requirements of API 4.8, Subsection 10.
Section 3174.11(b)(3) of the final rule
(§ 3174.11(c)(3) of the proposed rule)
requires the base prover volume of a
displacement prover must be calculated
under API 12.2.4. The BLM received no
comments and made no changes to this
requirement.
Section 3174.11(b)(4) (paragraph (c)(4)
in the proposed rule) establishes
displacement prover sizing standards.
These standards ensure that fluid
velocity within the prover is within the
limits recommended by API 4.2,
Subsection 4.3.4. Displacement
velocities that are too low (prover is
oversized) can result in unacceptable
pressure and flow-rate changes and
higher uncertainty due to possible
displacement device ‘‘chatter.’’
Displacement velocities that are too
high (prover is undersized) can cause
damage to the components of the
prover. One commenter recommended
replacing the proposed prover design
language that referenced API 4.2 with
language that references operating
provers within design parameters set
forth by the manufacturer and by API
4.8 and API 4.9.2. The BLM disagrees
with the commenter that paragraph
(b)(4) should reference API 4.8 and API
4.9.2 since these standards deal with
prover operation and are not relevant to
paragraph(b)(4) design standards.
Paragraph (b)(4) is specific to
displacement prover design, which is
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covered under API 4.2. The BLM did
not change the final rule in response to
this comment.
Section 3174.11(c) (paragraph (d) in
the proposed rule) establishes the
requirements for meter proving runs
with respect to proving both the FMP
LACT and CMS and the conditions
required for proving these meter
systems. The BLM received many
comments objecting to certain
requirements in proposed § 3174.11(d)
that deal with meter proving runs. The
BLM responds to these comments as
follows.
Section 3174.11(c)(1) (paragraph
(d)(1) in the proposed rule) expands on
the current Order 4 requirement to
prove a meter under ‘‘normal’’ operating
conditions. This section defines limits
of flow rate, pressure, temperature, and
API oil gravity that must exist during
the proving to be considered ‘‘normal’’
operating condition. The BLM added
this requirement because it realized that
the meter factor can change with
changes in these parameters. For
example, a meter factor determined at
an abnormally low flow rate may not
represent the meter factor at a higher
flow rate where the meter normally
operates. This paragraph also requires a
multi-point meter proving if the LACT
or CMS is subject to highly variable
conditions. The multi-point meter
proving establishes a minimum of three
meter factors—one at the low end of the
normal operating range, one at the
midpoint, and one at the high end. An
appropriate meter factor will then be
applied according to § 3174.11(c)(6).
One commenter noted that paragraph
(c)(1) (paragraph (d)(1) in the proposed
rule) lacks specifics on what normal
operating temperature conditions mean
and another commenter said the
language should be changed to reflect
situations where normal operating
conditions vary, such as at multimetering sites, and suggested a language
change to ‘‘average for the batch
period.’’ The BLM agrees with the
commenter that normal operating
conditions, as they apply to oil
temperature, were not adequately
addressed in the proposed rule and that
in some instances it may be difficult to
identify the ‘‘normal operating
conditions’’ of flowrate, pressure,
temperature, and fluid density. The
BLM added paragraph (c)(1)(iii) to the
final rule to address normal oil
operating temperature limits, which
must be within 10 °F of the normal
operating temperature. With this
addition, paragraphs (d)(1)(iii) and
(d)(1)(iv) in the proposed rule have been
renumbered to paragraphs (c)(1)(iv) and
(c)(1)(v) in the final rule.
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The BLM made no change to the final
rule regarding normal operating
conditions to reflect variable metering
conditions since this situation may be
specific to regions and areas of the
country and can be more adequately
addressed by the specific BLM field
office through the variance request
process as outlined in § 3170.6, which
has been established as part of the
rulemaking to replace Order 3.
Section 3174.11 paragraphs (c)(2)
through (c)(5) (paragraphs (d)(2) through
(d)(5) in the proposed rule) provide the
details for minimum proving
requirements, such as requiring a
minimum proving pulse resolution of
10,000 pulses per proving run or
requiring the use of pulse interpolation,
if this cannot be met, and setting a
requirement to continue repeating
proving runs until the calculated meter
factor from five consecutive runs is
within a 0.05 percent tolerance between
the highest and lowest value. The new
meter factor will be the arithmetic
average of the five meter factors or
average pulses from the five consecutive
proving runs. This section also requires
the meter factors to be calculated
following the sequence described in API
12.2.3. We received two comments on
paragraph (c)(2) of this section. One
commenter addressed the requirement
that, during proving runs, there be a
sufficient volume to generate at least
10,000 pulses from the FMP meter that
is being proved. The commenter did not
believe that the 10,000-pulse
requirement is reasonable and said it
would disallow the use of small-volume
provers (SVPs). The BLM disagrees with
the commenter on both points. The
10,000-pulse-per-proving-run resolution
in the rule follows the API standard and
the rule specifically allows smallvolume provers as long as they meet the
additional requirements in paragraph
(c)(2). The BLM did not change the final
rule in response to this comment.
However, the BLM believes that it is
appropriate to add clarifying language to
paragraph (c)(2) in the final rule that
reminds readers of the 10,000-pulse
requirement in API 4.2, Subsection
4.3.2. Another commenter asked why
the proposed rule did not specifically
address SVPs. SVPs come under the
requirements for displacement provers
and, under paragraph (c)(2), are required
to use pulse interpolation as outlined in
API 4.6, since their volume generates
less than 10,000 meter pulses per
proving run. The BLM did not change
the final rule due to this comment.
Two commenters on paragraph (c)(3)
objected to the requirement that the five
consecutive meter-proving runs have a
repeatability of 0.0005 (0.05 percent),
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saying that three proving runs could
accomplish the same uncertainty. The
BLM disagrees with these commenters
and has decided to retain Order 4’s
requirement of a minimum of five
proving runs. The BLM believes that
this requirement achieves the desired
consistency and uncertainty levels. The
BLM made no change to the final rule
due to these comments.
One commenter on paragraph (c)(4)
recommended that the BLM adopt the
use of an average meter factor as
determined from API 12.2.3. Upon
review of this comment, the BLM agrees
with the commenter that guidance on
the calculation of the average meter
factor is appropriate. Due to this
comment, the BLM changed the final
rule to incorporate API 12.2.3,
Subsection 9 for purposes of calculating
the average meter factor.
Section 3174.11(c)(5) of the final rule
(§ 3174.11(d)(5) of the proposed rule)
requires that meter factor computations
must follow the sequence described in
API 12.2.3. The BLM received no
comments and made no changes to this
requirement.
Section 3174.11(c)(6) (paragraph
(d)(6) in the proposed rule) gives
operators two methods for determining
the multiple meter factors that are
required under § 3174.11(c)(1)(v). The
first method is to combine the meter
factors into a single arithmetic average.
The second method is to curve-fit the
meter factors and incorporate a real-time
dynamic meter factor into the flow
computer (this will apply primarily to
CMS). Neither multi-point provings nor
multi-point meter factors are discussed
in Order 4. One commenter indicated
that averaging meter factors was only
valid in regions where impacts of
nonlinearities are minimal and
recommended deleting
§ 3174.11(c)(6)(i). The BLM conducted
further research into this comment and
agrees with the commenter that
averaging meter factors is only valid
under certain conditions. Additional
language pertaining to how to use the
multiple meter factors is added to the
final rule in paragraph (c)(6). This
language will only permit the use of
averaging meter factors if all meter
factors in the range are within
approximately ±0.10 percent of the
average. It will also limit the use of the
dynamic meter factor option to prevent
any two neighboring meter factors that
differ by more than approximately 0.2
percent from being used to derive a
dynamic meter factor.
Sections 3174.11(c)(7) and (c)(8)
(paragraphs (d)(7) and (d)(8) in the
proposed rule) set the minimum and
maximum values that are allowed for a
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meter factor, both between meter
provings and for initial meter factors for
newly installed or repaired meters.
These meter-factor ranges are not
changed from Order 4. The BLM
received no comments on paragraphs
(c)(7) and (8).
Section 3174.11(c)(9) (paragraph
(d)(9) in the proposed rule) allows back
pressure valve adjustment after proving
only within the normal operating fluid
flow rate and fluid pressure as
prescribed in proposed § 3174.11(c)(1).
If the back pressure valve is adjusted
after proving, the ‘‘as left’’ fluid flow
rate and fluid pressure must be
documented on the proving report. The
BLM is requiring this documentation
based on its field observations, which
have shown this practice to affect the
meter factor in certain areas of the
country. Specifically, the BLM has
observed that a change in back pressure
outside the proving conditions can, in
some cases, result in operators reporting
incorrect volumes. Allowing back
pressure valve adjustment after proving
is not intended as a means to
circumvent the displacement prover
minimum and maximum velocity
requirements in § 3174.11(b)(4) of the
final rule. Order 4 has no specific
requirements relating to the adjustment
of the back pressure valve after proving.
The BLM received no comments on
paragraph (c)(9).
Section 3174.11(c)(10) (paragraph
(d)(10) in the proposed rule) sets
standards for the pressure used to
calculate a CPL factor for a LACT’s
composite meter factor. It also prohibits
the use of a composite meter factor for
Coriolis meters because they have the
capability to use a true average pressure
over the measurement ticket period in
the calculation of an average CPL factor.
The use of a composite meter factor is
intended to make measurement tickets
easier to complete because the CPL
factor is already included in the meter
factor. This is typically not an issue
with a Coriolis meter because of the
advanced capability of the flow
computer to which it is connected. One
commenter stated that most Coriolis
meters in the field do not have the
capability to calculate a CPL factor and
replacing them with a Coriolis meter
that could calculate a CPL factor would
be prohibitively costly. The BLM agrees
with the commenter regarding the CPL
factor capability currently available in
existing Coriolis meters. However, the
final rule does not require operators to
have a Coriolis meter with this CPL
factor feature. Therefore, the BLM made
no change to the final rule as a result of
this comment.
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Section 3174.11(d) (paragraph (e) in
the proposed rule) establishes the
minimum FMP meter-proving
frequencies, and specifies certain events
that will trigger additional meter
provings. This section contains the
meter-proving requirements that were
previously located in the LACT section
of Order 4 and consolidates in one place
all of the meter-proving requirements
for both LACTs and CMSs.
The BLM received many comments
that objected to the provision in
paragraph (d)(2) (paragraph (e)(2) of the
proposed rule) that sets a threshold for
when operators who run large volumes
of oil through their meters must conduct
additional FMP meter provings. The
proposed rule would have required
operators to prove their FMP meters
each time the registered volume flowing
through their meters increased by
50,000 bbl or quarterly, whichever
occurred first. Currently under Order 4,
an FMP meter must be proven at least
quarterly, unless total throughput
exceeds 100,000 bbl per month, in
which case the meter must be proven
monthly.
The BLM’s rationale in the proposed
rule for changing the proving threshold
to 50,000 bbl/month was that it would
have affected only about 5 percent of
existing LACT systems nationwide, yet
would have ensured that meter-factor
changes would be corrected before large
volumes of production were measured
incorrectly, which could have an
adverse impact on Federal or Indian
royalty determinations.
Many commenters objected to the
proposed meter-proving-frequency
threshold of 50,000 bbl/month. Most
commenters said this new meterproving frequency would require them
to perform excessive and costly meter
provings in locations where the meters
may not be easy to access, especially in
bad weather. The BLM agrees that the
50,000 bbl/month threshold may be
excessively costly and, after reviewing
potential economic impacts, has
decided to use a 75,000 bbl meterproving frequency threshold in the final
rule. This 75,000 bbl throughput
threshold was determined by
performing a statistical analysis to
determine the volume at which the
expected value of royalty under- or
overpayment due to meter factors equals
the $550 average cost of proving a
meter. The royalty revenue impact
depends not only on volumes but also
on oil prices. The 50,000 bbl/month
threshold in the proposed rule was
determined when the U.S. Energy
Information Administration’s (EIA) 10year West Texas Intermediate crude oil
spot price was expected to average $95/
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bbl. Since then, the EIA’s predicted 5year average crude oil price has dropped
significantly, to $67.58 per barrel. The
BLM does not find the 50,000/bbl meterproving threshold to be appropriate
under this predicted lower oil-price
environment.
The BLM also revised the maximum
and minimum proving frequencies for
meter proving on higher-volume FMPs.
Under Order 4, operators were required
to prove their meters at least quarterly
or, if total throughput exceeded 100,000
bbl/month, then they were required to
prove monthly. In this final rule,
operators must prove their meters every
3 months (quarterly), or each time the
registered volume flowing through the
meter increases by 75,000 bbl, but no
more frequently than monthly. For
example, if a meter hits the 75,000 bbl
threshold every 6 weeks, the operator
must prove it every 6 weeks. If a meter
has a 75,000 bbl throughput every 2
weeks, the operator must prove it once
a month. The final rule was changed to
include this new language.
Two commenters on paragraph (d)(2)
said meter-proving frequencies should
be increased, based on a lower volume
of throughput threshold, and another
commenter said that frequent proving
would increase accuracy. The BLM does
not agree that the final rule should
further increase the proving frequency
beyond what was presented in the
proposed rule. The comments lacked
any substantive basis and did not justify
how an increased proving frequency
would result in increased accuracy or
how the costs of those additional
provings would be justified by any
reduction in royalty risk. The BLM
believes the proving frequency in the
final rule is justified and results in the
required accuracy. The BLM did not
change the final rule in response to
these comments.
One commenter on paragraph (d)(6) of
§ 3174.11 (paragraph (e)(6) of the
proposed rule) said that requiring a
meter proving due to a change in normal
operating conditions was not practical
and not needed. The BLM disagrees
with this commenter and agrees with
another commenter who, in his
comment on paragraph (e), pointed out
that temperature extremes in places like
Alaska or North Dakota have a large
impact on meter-factor change between
different proving runs. Because a change
in the normal operating conditions
could significantly affect the meter
factor, and therefore the accurate
measurement of the oil volumes, the
BLM made no change to the final rule
due to this comment.
Paragraph (d)(7) in § 3174.11
(paragraph (e)(7) in the proposed rule)
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also expands the current Order 4
requirement that operators prove their
meters after repair. The new
requirements require proving any time
the mechanical or electrical components
of the meter have been changed,
repaired, or removed. In addition to
those circumstances, paragraph (d)(8)
requires an operator to also prove its
meter after internal calibration factors
have been changed or reprogrammed.
One commenter asked whether meters
used in flowback operations are subject
to the requirements in this section.
Flowback meters are not required to
comply with this rule’s meter-proving
requirements because flowback
operations take place prior to the
operator’s receipt of an FMP approval
under § 3173.12, and more importantly
meters used in these operations are not
FMPs. The BLM did not change the final
rule based on this comment.
One commenter said that after initial
meter installation, a period of 2 weeks
should pass before the meter is proved.
The commenter did not justify a 2-week
delay. The BLM believes that a meter
should be proved as soon as is
reasonably possible. The BLM expects
that meters will be proven immediately
after installation. The BLM did not
change the final rule based on this this
comment.
One commenter said that paragraph
(d)(7) (paragraph (e)(7) in the proposed
rule) is vague. The commenter
specifically complained about language
that required a meter proving after the
mechanical or electrical components of
the meter have been, among other
things, ‘‘opened.’’ The BLM agrees with
the commenter and changed the final
rule so that the paragraph, in its
entirety, now requires a meter proving
after ‘‘the mechanical or electrical
components of the meter have been
changed, repaired, or removed’’, and
added (d)(8) to prove after ‘‘internal
calibration factors have been changed or
reprogrammed.’’ Another commenter
questioned the need to reprove a meter
each time its secondary element
(transducer) or tertiary device is
changed. The commenter contends that
these elements have no direct effect on
the meter performance. The BLM agrees
with the commenter in part. An element
can impact the accuracy of the
measurement if it is not measuring
temperature and pressure accurately.
Changing out either of these elements
would not require the meter to be
reproved, but would require the new
element(s) (transducers) to be verified
upon their replacement as is required
under §§ 3174.11(f) and (g), and
temperature and pressure transducer
verification, respectively, during a
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meter-proving operation. The BLM
revised the final rule § 3174.11(f) and (g)
to address the commenter’s concern by
making it clear that a change out of
either one of these elements would not
require the meter to be reproved, but
would require the new element(s)
(transducers) to be verified upon their
replacement.
Section 3174.11(e) (§ 3174.11(f) in the
proposed rule) establishes what
operators must do when there is
excessive FMP meter factor deviation.
This situation occurs when a meter
factor, which is established in two
successive provings, exceeds the
allowable meter factor deviations. This
section requires operators to take steps
to bring the FMP meter back into
compliance. It also requires operators to
re-calculate the amount of production
that was measured during the time
period between these instances of
excessive meter factor deviation.
Paragraph (e) also requires operators to
show the most recent meter factor and
describe all subsequent repairs and
adjustments on the proving reports that
are required in paragraph (i) of this
section.
Section 3174.11(e) maintains the
Order 4 requirements for excess meter
factor deviation and the required actions
if proving reflects a deviation in meter
factor that exceeds ±0.0025 between two
successive meter provings.
The BLM received comments
objecting to the paragraph (e)
requirement that the FMP meter be
removed from service when found
defective or when the meter factor is
outside the proposed accuracy range.
The comments raised the issue of
temperature extremes, in places like
Alaska or North Dakota, having a large
impact on meter factor change from
proving to proving, making it
impossible for operators to meet the
meter factor deviation requirement. The
BLM agrees that changing temperatures
do affect the proving meter factors. This
situation could easily justify more
frequent provings as the temperatures
change, the commenter said. The BLM
believes this issue is field office specific
and is more appropriately addressed
through the BLM’s variance process,
which is outlined in § 3170.6, part of the
rulemaking that is replacing Order 3.
One commenter recommended
changing the meter-factor deviation
limits for meters from ±0.0025 to
±0.0050 because, the commenter said, it
is standard industry practice to consider
volume measurements as accurate if the
meter factor changes by plus or minus
0.0025 or less. It typically is not until
the differences in the meter factors are
between plus or minus 0.0025 and
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0.0050 that a correction is applied. The
BLM reviewed API 4.8 to verify the
commenter’s claims on meter-factor
deviation limits that are the industry
standard. API 4.8 states common
practice for custody transfer
applications is to accept new meter
factors within the range of 0.10 percent
and 0.50 percent of the previous meter
factor. The BLM did not accept this
recommended change for several
reasons: The commenter agrees it is
standard industry practice to consider
volume measurements as accurate if the
meter factor changes by plus or minus
0.0025 or less, ±0.0025 deviation
between meter proving runs is currently
the maximum deviation allowed under
existing Order 4, proposed deviation
falls within the acceptable deviation
range recommended in API 4.8, and it
will not increase current reporting
requirements or add costs, but will
ensure measurement accuracy. The BLM
made no changes to the final rule based
on these comments.
Section 3174.11(f) (paragraph (g) in
proposed rule) establishes standards for
the verification procedure and the test
equipment used in the temperature
transducer verification. It states the
limit threshold value required by the
verifying sources as they pertain to the
normal operating temperature of the
tested fluid. It also requires that the
temperature transducer and devices
used as part of a LACT or CMS be
verified as part of every proving.
The BLM received quite a few
comments objecting to the new
requirement that operators verify the
temperature transducers during the
meter-proving process. One commenter
said that the proposed rule’s meterproving frequencies would result in
excessive and costly transducer
verifications if the temperature
transducers had to be verified during
each meter proving, since the proposed
rule would have required operators to
prove their meters each time they
measured 50,000 bbl of oil, or quarterly,
whichever occurred first. The BLM
believes that this concern is no longer
valid. Section 3174.11(d)(2) in the final
rule has been revised and now requires
operators to prove their meters every 3
months (quarterly), or each time the
registered volume flowing through the
meter increases by 75,000 bbl, but no
more frequently than monthly. These
changes reduced the burdens associated
with the proving requirements in the
proposed rule. Therefore, the BLM did
not change the final rule in response to
this comment.
One commenter objected to the
requirement that operators use an
insulated water bath in the field to
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81491
perform the temperature transducer
verification process, stating that this
type of process belongs in a laboratorytype environment and not in a field
environment. The BLM disagrees with
this commenter since an insulated water
bath is a common, acceptable method of
verification. The rule also states the
transducer may be verified by utilizing
a test thermometer well located within
12 inches of the probe of the
temperature transducer. The BLM did
not change the final rule in response to
this comment.
One commenter said that requiring
operators to verify the temperature
transducer as part of a LACT or CMS
proving may require operators to
acquire additional equipment and incur
costs. The BLM agrees with the
commenter that verifying the transducer
will require an additional piece of
equipment and potentially an initial
cost to acquire test equipment, but
believes third-party proving contractors
already own such equipment. Moreover,
the BLM believes routine transducer
verification is vital to assure proper
performance and to obtain an accurate
liquid temperature for use in correcting
for the thermal effects on the liquid,
ensuring accurate oil measurement, and
royalty determination. As a result, the
BLM made no change to the final rule
in response to this comment.
Another commenter said the
requirement for verification of
temperature averaging devices in
§ 3174.11(f) of the proposed rule
conflicts with requirements in
§ 3174.6(b)(2) for temperature resolution
and accuracy. The commenter did not
say how this requirement conflicts. The
BLM disagrees that there is a conflict
because the temperature accuracy
required for temperature verification is
0.5 °F, which is consistent with
temperature accuracies presented in
other sections of the final rule and with
manufacturer’s recommendations. For
example, the temperature display
minimum graduation must be to the 0.1
°F, as required in § 3174.8(b)(5)(iv),
which means there is no practical
difficulty in assessing compliance with
the verification limits. The BLM made
no change to the final rule in response
to this comment.
Section 3174.11(f)(3)(i) and (ii) of the
final rule (§ 3174.11(g)(3)(i) and (ii) of
the proposed rule) requires that if the
displayed reading of instantaneous
temperature from the temperature
averager or the temperature transducer
and the reading from the test
thermometer differ by more than 0.5 °F,
the temperature averager or temperature
transducer must be either: (1) Adjusted
to match the reading of the test
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thermometer; or (2) Recalibrated,
repaired, or replaced. Section
3174.11(g)(3)(ii) of the proposed rule
only required that the difference in
temperature readings be noted on the
meter proving report and all
temperatures used until the next
proving be adjusted by the difference.
The BLM received no comments to this
section, but reconsidered the
requirement and the potential tracking
and measurement errors in adjusting
temperature readings between provings
and decided that if the temperature
averager or the temperature transducer
is unable to be adjusted to the correct
reading then it must be recalibrated,
repaired, or replaced.
Section 3174.11(g) of the final rule
(paragraph (h) in the proposed rule)
establishes the verification requirements
for the pressure transducer during the
meter-proving operations and states the
threshold limit value required by the
verifying sources as they pertain to the
normal operating pressure of the tested
fluid. It requires that the pressure
transducer and devices used as part of
a LACT or CMS be verified as part of
every FMP proving and establishes
standards for the verification procedure
and the test equipment used in the
pressure transducer verification. The
BLM received many comments objecting
to the new requirement that operators
verify the pressure transducer during
the meter-proving process. Two
commenters said that the proposed
rule’s meter-proving frequencies would
result in excessive and costly transducer
verifications if the pressure transducers
had to be verified during each meter
proving. The BLM believes that this
concern is no longer valid. As noted
elsewhere, the proving burdens under
this final rule have been reduced
relative to the proposed rule. The
proposed rule would have required
operators to prove their meters each
time they measured 50,000 bbl of oil, or
quarterly, whichever occurred first.
Section 3174.11(d)(2) of the final rule
now requires operators to prove their
meters every 3 months (quarterly), or
each time the registered volume flowing
through the meter increases by 75,000
bbl, but no more frequently than
monthly. As a result, the BLM made no
changes to the final rule in response to
these comments.
One commenter said that requiring
operators to verify the pressure
transducer as part of a LACT or CMS
meter proving may require operators to
acquire additional equipment and incur
costs. The BLM agrees that verifying the
transducer will require an additional
piece of equipment and potentially an
initial cost to acquire test equipment,
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but we believe that third-party proving
contractors already own or can acquire
such equipment. The BLM believes
routine transducer verification is vital to
accurate oil measurement and royalty
determination. The BLM made no
change to the final rule in response to
this comment.
One commenter had concerns with
the requirement in paragraph (g)(1)
(paragraph (h)(1) in the proposed rule)
that the pressure sensor must be verified
against a NIST-traceable device that is at
least twice as accurate as the reference
accuracy of the pressure sensor, saying
the operator may not have test
equipment capable of this accuracy. The
commenter suggested that the BLM
should allow equipment to be used that
does not meet this accuracy
requirement, and should provide
guidance on how lower-accuracy
equipment can be used. The BLM
realizes that this high level of accuracy
may not be achievable with test
equipment the operator currently has
and as a result has changed the rule in
§ 3174.11(g)(1) to require the testpressure device to have a stated
maximum uncertainty of no more than
one-half of the accuracy required from
the transducer being verified.
Section 3174.11(h) (paragraph (i) in
proposed rule) establishes the density
verification requirements during the
meter proving operations and states the
limit threshold values required by the
verifying sources as they pertain to the
normal operating density of the tested
fluid. For Coriolis meters, paragraph (h)
requires verification using API 5.6,
Subsection 9.1.2.1 if measured density
is used to determine API oil gravity
(instead of a hydrometer or
thermohydrometer, which is generally
required under § 3174.6(b)(4)). This
provides an independent verification
that the Coriolis meter’s density
determination function is within the
accuracy specification for that meter.
The BLM received a few comments
objecting to the new requirement for
density verification during the FMP
meter-proving process for a variety of
reasons. One commenter recommended
that the final rule refer to API 8.1, API
8.2, and API 8.3 if the compared density
samples come from a sampling system.
The BLM agrees with this
recommendation and changed the final
rule by adding references to API 8.1,
API 8.2, and API 8.3. These references
provide guidance to operators for
performing composite sampling to
verify oil density as required in the final
rule under § 3174.11(h).
One commenter said that using a CMS
meter instead of a PD meter would
impose additional costs on operators to
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verify the CMS’ density measurement.
The BLM agrees in part that using a
CMS would require additional density
verification over what would be
required on a PD meter. However, it is
up to the operator to choose which
meter type to use. The BLM did not
change the final rule as a result of this
comment.
One commenter objected to the
requirement for density verification
during the FMP meter-proving process
because, the commenter said, it would
be costly and excessive to verify the
transducer during each meter proving.
The BLM believes that this concern has
been addressed. The proposed rule
would have required operators to prove
their meters each time they measured
50,000 bbl of oil, or quarterly,
whichever occurred first. Section
3174.11(d)(2) in the final rule has been
revised and now requires operators to
prove their meters every 3 months
(quarterly), or each time the registered
volume flowing through the meter
increases by 75,000 bbl, but no more
frequently than monthly.
Section 3174.11(i) (paragraph (j) in
the proposed rule) requires operators to
report to the AO all meter-proving
operations and volume adjustments
made after any LACT system or CMS
malfunction. This section provides
additional requirements for data that
need to be included on the meterproving report beyond what is currently
required under Order 4. In one change
to Order 4 requirements, the final rule
requires operators to provide the unique
meter or station ID number on each
proving report as required under
§ 3174.11(i)(2)(i). This section includes
requirements for verification of the
temperature averager or temperature
transducer, verification of the pressure
transducer, and an addition to the final
rule for density verification
documentation, as applicable, as well as
any ‘‘as left’’ conditions if the back
pressure valve is adjusted after proving,
which operators also would have to
document on the proving report.
Many commenters asked that we
clarify aspects of paragraph (i)
(proposed paragraph (j)). One
commenter recommended that we
change § 3174.11(i)(2)(iii) and (iv) to
only require temperature and pressure
transmitter information, if verified. The
BLM disagrees with this commenter on
when to report temperature and
pressure transducer data, since this
information has to be verified as part of
each FMP meter proving. The BLM
made no change to the rule in response
to this comment. Three commenters
asked the BLM to specify the format of
the meter proving reports since
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proposed paragraph (i)(3) specified no
specific format. The proposed rule
required the operator to submit the
meter-proving report to the AO no later
than 14 days after the meter proving.
The BLM agrees with the commenters
that this information should be added
and changed the final rule to say that
the meter proving reports may be
transmitted to the AO either in hard
copy or electronically.
In addition to the comments on
specific provisions above, the BLM
received a few general comments on
§ 3174.11. One commenter said the new
regulations would impact marginalproducing wells and may force a
premature abandonment of wells and a
loss of public hydrocarbon resources.
The commenter proposed that marginal
and/or existing wells be exempt from
both subpart 3174 and subpart 3175.
The BLM disagrees that these
regulations will force operators to
abandon marginal wells. If an operator
believes these regulations will force it to
abandon a marginal well, that operator
can obtain a variance from the
regulations under § 3170.6, which is
part of the rulemaking that is replacing
Order 3. The BLM made no change to
the final rule in response to this
comment.
One commenter said the maximum
and minimum velocity for PD meter
provers was not relevant to SVPs and
royalty issues associated with their use.
The commenter recommended that the
BLM adopt language that says, ‘‘Provers
must be operated within the design
parameters of the manufacturer.’’ The
BLM disagrees with the commenter
because the prover design requirements,
including sizing by prover velocity, are
found in the API standards incorporated
in this rule. If the operator believes it
can meet or exceed these requirements
by other means, then the rule allows the
operator to use the variance process
outlined in § 3170.6. The BLM did not
change the final rule in response to this
comment.
Two comments, made by the same
commenter, voiced concerns that the
proposed rule was suited to lighter oil
regimes and did not address the
differences in measurement that
characterize heavy oil, steamflood, and
cyclic steam operations. The commenter
was concerned that the proposed rule’s
accuracy requirements would increase
operating costs for heavy-oil operators,
resulting in possible violations of the
measurement requirements. The BLM
agrees with the commenter that these
rules do not specifically address the
measurement of heavy oil. However,
these issues are field office specific and
can be appropriately addressed through
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the variance process outlined in
§ 3170.6.
Section 3174.12 Measurement Tickets
Section 3174.12 specifies the data
requirements for measurement tickets
(run tickets) based on which method of
oil measurement an operator uses, i.e.,
tank gauging, LACT system, or CMS.
These requirements were previously
found in Order 3.14 The purpose of the
information in the run tickets is to
enable the BLM to independently verify
the quantity and quality of oil removed
from the lease during production audits
so as to ensure accurate measurement
and proper reporting.
The BLM received several comments
on this section. Some comments
questioned the requirement to complete
a run ticket prior to proving a LACT or
CMS utilizing flow computers. One
commenter stated that this requirement
is unnecessary as a flow computer is
capable of implementing a new meter
factor in the middle of a run without
closing the run. The commenter asserted
that the flow computer does this by
applying the original meter factor to
deliveries that occurred from the
beginning of the month up to the point
of proving and then applying the new
meter factor after the point of proving
until the end of the month. The BLM
agrees that flow computers are capable
of utilizing two meter factors as the
commenter described, and of retaining
an audit trail capability to track this. As
a result of this comment, § 3174.12(b)(1)
of the final rule has been changed to
remove the requirement to close a run
ticket prior to proving for LACT systems
utilizing flow computers.
One commenter stated that the
proposed rule’s run-ticket requirements
for tank gauging did not specify a
frequency for when run tickets will be
required. The BLM disagrees with this
comment as the proposed rule stated
that measurement tickets must be
completed ‘‘immediately after oil is
measured by manual tank gauging.’’ The
BLM believes that this language is clear
as to how frequently a measurement
ticket needs to be completed but
modified the final rule to say, ‘‘After oil
is measured by tank gauging under
§§ 3174.5 and 3174.6. . . .’’ This change
was made because the final rule allows
the use of ATG equipment. The BLM
made no changes to the rule as a result
of this comment but did modify the
14 The information on a run ticket is considered
a source record, as defined in § 3170.3, which is
being promulgated as part of the rulemaking to
replace Order 3. The retention requirements for
such records is addressed in that rulemaking;
however, the requirements as to substance are
provided in this rule as explained above.
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81493
requirements’ language due to the
inclusion of ATG equipment. The final
rule now states ‘‘After oil is measured
by tank gauging under §§ 3174.5 and
3174.6 of this subpart, the operator,
purchaser, or transporter, as
appropriate, must complete a uniquely
numbered measurement ticket, in either
paper or electronic format.’’
We received several comments
requesting that we remove the
requirement to list on measurement
tickets the name of the operator’s
representative certifying the
measurements. It was suggested that
operators do not have enough field
personnel to witness every oil tank haul
and therefore would not be able to
‘‘certify’’ every tank sale. The
commenters argued that this
requirement could increase confusion
and expense, requiring operators to
schedule a sale only when a ‘‘company
man’’ can be present, and creating
undue financial strain on operators
having to hire staff to witness tank sales
and nothing else. Another commenter
said that the BLM needs to define the
term ‘‘certify.’’ Upon reviewing this
requirement and the comments, the
BLM agrees with the commenters, and
deleted this requirement in proposed
§ 3174.12(a)(14) from the rule. It should
be noted, however, the operators remain
responsible for the accuracy of
information found on run tickets,
irrespective of any requirement to
certify the run ticket.
Several commenters requested that
the BLM remove from the rule the
requirement that operators notify the
AO within 7 days regarding their
reasons for disagreeing with a tank
gauge measurement. The commenters
said this requirement is impractical
because, in the field, it may take up to
30 days for a transporter’s run ticket to
show up in the operator’s accounting
system. One commenter said that
operators should be able to correct
relatively minor run-ticket
discrepancies without having to report
them to the BLM. Upon reviewing these
comments, the BLM believes this
requirement may create confusion both
within the BLM and among operators as
to when exactly the AO should be
notified. For example, would a simple
calculation error warrant AO
notification? Would the operator need to
explore a potential discrepancy before
notifying the AO? The BLM believes
this requirement could lead to
significant confusion, with minimal
benefit to the BLM. Therefore, this
requirement in proposed
§ 3174.12(a)(15) was removed from the
rule. Instead, the BLM will address any
run ticket discrepancies on a case-by-
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case basis during routine production
inspections.
One commenter stated that it may not
be possible to reset temperature- and
pressure-averaging equipment and
density-determining equipment back to
zero upon closing a run ticket, as is
required by paragraph (b)(2) of this
section, which could result in some
operators having to replace equipment.
The BLM is not aware of any nonresettable averaging equipment in use
on Federal leases. This requirement is in
the rule to ensure that the temperature,
pressure, and density, which are
required to be included on each run
ticket, represent the average
temperature, average pressure, and
average density of the oil that actually
flowed through the meter during the
run-ticket period. If there is any nonresettable averaging equipment in use
on any Federal or tribal lease, operators
will be required to replace it. No change
to the rule resulted from this comment.
One commenter recommended that
the BLM require hauler signatures on
run tickets, but at the same time
admitted that anyone can write or type
someone else’s name on a run ticket and
not be the individual who is actually
performing the task. The BLM agrees
that a signature could identify a specific
individual who filled out a run ticket,
in case questions arise. But past
experience with signature requirements
resulted in BLM inspectors spending a
lot of time tracking down signatures for
no quantifiable benefit. For this reason,
the BLM decided to not include a
signature requirement. BLM regulations
at 43 CFR 3163.2(f)(1) include penalties
for any person who knowingly or
willfully prepares, maintains or submits
false, inaccurate or misleading reports,
notices, affidavits, records, data or other
written information. The BLM believes
this provision addresses any
circumstance under which someone
falsely enters another person’s name on
a run ticket. By only requiring the
name(s) of the individual(s) performing
the tank gauging, we will be acquiring
the data we need for our verification
requirements. No change was made to
the rule as a result of this comment.
Section 3174.13 Oil Measurement by
Other Methods
Section 3174.13(a) provides that using
any method of oil measurement other
than tank gauging, LACT system, or
CMS at an FMP requires prior BLM
approval. Under § 3174.13(b), the BLM
will use the PMT as a central advisory
body within the BLM to review and
recommend approval of industry
measurement technology not addressed
in these regulations. The PMT is a panel
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of BLM employees who are oil and gas
measurement experts.
The process outlined in § 3174.13(b)
for reviewing new equipment allows the
BLM to keep up with technology as it
advances and approve its use without
having to update its regulations. Under
the rule, if the PMT recommends new
equipment or measurement methods,
and the BLM approves, the BLM will
post the make, model, range or software
version, or measurement method on the
BLM Web site (www.blm.gov) as being
appropriate for use at an FMP for oil
measurement going forward.
The PMT will consider new
measurement technologies on a case-bycase basis. The BLM believes this
process will be used as other
technologies or methods are developed
and their reliability is established. For
example, the BLM considered other
meters for inclusion in this rule, such as
turbine meters and ultrasonic meters;
however, it ultimately decided not to
include them in this rule because at this
time there is insufficient testing to
validate their accuracy and reliability
under all operating conditions.
However, if in the future the data
demonstrates that these meters meet the
performance standards of the rule, the
PMT will be able to recommend that
these meters be approved for use.
If the PMT is able to make the
required determination, it will
recommend that the BLM approve the
use of the applicable equipment or
method, as is or subject to certain
conditions. Such equipment or
methods, and any applicable COAs, will
be posted to the BLM Web site and be
identified as being appropriate for use at
an FMP for oil measurement without
additional approvals from the BLM,
subject to any limitations or conditions
of use imposed by the PMT. Subsequent
users of the same technology will not
have to go through the PMT process,
provided only that they comply with the
identified conditions of use.
Section 3174.13(c) provides that the
procedures for requesting and granting a
variance under § 3170.6 cannot be used
as an avenue for approving new
technology or equipment. An operator
can obtain approval of alternative oil
measurement equipment or methods
only through review, recommendation,
and approval by the PMT under
§ 3174.13.
One commenter suggested that fieldoffice staff are often in a better position
than national office staff to collaborate
with operators on pilot projects
intended to prove alternative
measurement methods. The BLM
disagrees. Field-office staff typically do
not have the necessary time and
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measurement expertise to conduct a
complete analysis for approval of new
technology. This rule includes a process
for the BLM—through the PMT—to
assess new technology and approve it
when appropriate. Additionally, this
rule responds in part to concern on the
part of the Subcommittee, the GAO, and
the OIG that the BLM lacked uniform
national standards governing
measurement. Leaving decisions about
new equipment to field office staff
would not address that concern.
Several commenters wanted to know
what they will have to do to get
equipment approved for use through the
PMT and included on the BLM Web
site. One commenter objected to any
requirement that operators pay for thirdparty testing of equipment in order to
receive approval by the PMT. Upon
reviewing the rule and careful
consideration of this comment, the BLM
re-evaluated the approval process for
equipment and transducers that will be
listed on the BLM Web site and changed
the rule to clarify that an operator
requesting approval must submit
performance data, actual field test
results, laboratory test data, or any other
supporting data or evidence that
demonstrates that the proposed
equipment will meet or exceed this
rule’s objectives. The final rule is
revised by adding in § 3174.2(g) to
explain how operators and
manufacturers can obtain BLM approval
for ATG equipment and specific meters,
including approval of a particular make,
model, and size, by submitting test data
used to develop performance
specifications to the PMT for review.
Neither the proposed nor the final rule
requires operators to pay for third
parties to test equipment in order to
receive PMT approval. However, should
the submitted data fail to demonstrate to
the PMT that the proposed equipment
will meet or exceed this rule’s
objectives, the BLM may require
additional testing before it grants
approval.
One commenter objected to the
creation of the PMT, claiming it will
stifle innovation, not provide timely
reviews, and discourage development of
new technology by increasing ‘‘red
tape.’’ The BLM disagrees and in fact
believes the PMT will increase the
utilization of new technology and
expedite new approvals. The BLM
believes that once the PMT is fully
staffed, reviews could take 30 to 60
days, assuming that operators and
manufacturers have performed the
proper testing and that all pertinent data
is submitted to the PMT. Once the PMT
reviews the data and makes a
recommendation, and the BLM
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approves a piece of equipment, it is
approved for use across the country on
all Federal and Indian onshore leases
and no further approvals are required.
This is not the case for the current
variance process, which requires
approval by each field office for each
instance such equipment is proposed for
use, resulting in a duplicative approval
process with inconsistent results.
This commenter also said the BLM,
the public, and industry would benefit
from allowing companies to determine
how they will meet the requirements of
the regulation once it is in place,
without the agency determining what
equipment it will allow to fulfill the
requirements of its regulation. The BLM
agrees that a company should have the
flexibility to determine how to best
satisfy the performance requirements of
the rule, but disagrees that the BLM
should not be evaluating and approving
equipment. The BLM has an affirmative
obligation to determine that
measurements on Federal oil and gas
leases are meeting the applicable
performance and verifiability standards.
The final rule provides flexibility by
including provisions that allow for
variances for alternatives that meet or
exceed the minimum requirements of
the regulations and by including the
PMT approval process in the rules to
evaluate and approve new technology
and measurement methods. The BLM
believes that the final rule has already
addressed the intent of this comment—
to allow flexibility in measurement
approaches. No change to the rule
resulted from this comment.
One commenter suggested that the
BLM should list approved technology
and not specific makes and models of
equipment. The BLM partly agrees with
the commenter, in that the PMT will be
evaluating new technology and the list
will include new technology as it is
approved, but it will be approved and
listed by make and model of the specific
equipment based on the performance
data. The BLM believes that there will
always be manufacturing control and
software differences that affect
individual meter performance between
competing manufacturers and these
differences need to be captured in the
uncertainty calculator. No changes to
the rule resulted from these comments.
Section 3174.14 Determination of Oil
Volumes by Methods Other Than
Measurement
Section 3174.14 does not change
Order 4’s existing requirements for
determining volumes of oil that cannot
be measured as a result of spillage or
leakage. This section includes, but is not
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limited to, oil that is classified as slop
or waste oil.
The BLM received two comments on
this section. The first commenter said
the section requires the operator to
confirm ‘‘slop oil’’ is not recoverable,
and cannot be treated and sold, and
provide documentation to this effect.
According to the commenter: (1) The
proposed rule did not define a process
for the operator to follow; (2) This
requirement could impact water
disposal when bottoms are pulled from
a tank; and (3) The language is very
open ended. The BLM disagrees that the
rule does not define a process. The
language found in this section is simply
a codification of existing requirements
and practices. Additionally, the
proposed and final rules state that the
first determination the operator must
make is the amount of production that
cannot be measured due to spillage or
leakage. The second determination the
operator must make is whether the
production is waste oil or slop oil. And
the third step that an operator must
take, depending on whether it is waste
or slop oil, is to either demonstrate to
the AO that it is not economically
feasible to put the product into
marketable condition or get AO
approval to sell or dispose of the slop
oil.
Regarding the second issue, the BLM
notes that this is not a new requirement
and it should not surprise operators that
the requirements of this section could
impact water disposal when bottoms are
pulled from tanks should the contents
meet the definition of waste oil or slop
oil.
As for the third issue, the BLM agrees
that the language is somewhat openended because it is intended to address
all potential situations that might occur
in the field. No change has been made
to the rule as a result of this comment.
The second commenter said the rule
should be changed to better define slop
oil. The definition of slop oil is found
in the definitions section of § 3170.3,
part of the rulemaking that is replacing
Order 3. This issue was addressed as
part of that rulemaking; however, it
should be noted that the BLM does not
believe this definition is insufficient. No
change has been made to the final rule
as a result of this comment.
Section 3174.15 Immediate
Assessments
Section 3174.15 identifies certain acts
of noncompliance that are subject to
immediate assessments. This section
includes violations that are not subject
to immediate assessment under existing
regulations at 43 CFR 3163.1(b). These
assessments are not civil penalties and
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81495
are separate from the civil penalties
authorized in Section 109 of FOGRMA,
30 U.S.C. 1719.
Order 4 does not provide for
immediate assessments beyond those
specified in 43 CFR 3163.1(b). However,
the BLM continues to incur costs
associated with correcting the violations
identified in § 3174.15. Accordingly,
this rule adds five new violations that
are subject to immediate assessments.
As is explained in the proposed rule,
the authority for the BLM to impose
these assessments was explained in the
preamble to the 1987 final rule in which
43 CFR 3163.1 was originally
promulgated:
The provisions providing assessments have
been promulgated under the Secretary of the
Interior’s general authority, which is set out
in Section 32 of the Mineral Leasing Act of
1920, as amended and supplemented (30
U.S.C. 189), and under the various other
mineral leasing laws. Specific authority for
the assessments is found in Section 31(a) of
the Mineral Leasing Act (30 U.S.C. 188(a),
which states, in part ‘‘. . . the lease may
provide for resort to [sic] appropriate
methods for the settlement of disputes or for
remedies for breach of specified conditions
thereof.’’ All Federal onshore and Indian oil
and gas lessees must, by the specific terms
of their leases which incorporate the
regulations by reference, comply with all
applicable laws and regulations. Failure of
the lessee to comply with the law and
applicable regulations is a breach of the
lease, and such failure may also be a breach
of other specific lease terms and conditions.
Under Section 31(a) of the Act and the terms
of its leases, the BLM may go to court to seek
cancellation of the lease in these
circumstances. However, since at least 1942,
the BLM (and formerly the Conservation
Division, U.S. Geological Survey), has
recognized that lease cancellation is too
drastic a remedy, except in extreme cases.
Therefore, a system of liquidated damages
was established to set lesser remedies in lieu
of lease cancellation . . .
The BLM recognizes that liquidated
damages cannot be punitive, but are a
reasonable effort to compensate as fully as
possible the offended party, in this case the
lessor, for the damage resulting from a breach
where a precise financial loss would be
difficult to establish. This situation occurs
when a lessee fails to comply with the
operating and reporting requirements. The
rules, therefore, establish uniform estimates
for the damages sustained, depending on the
nature of the breach (53 FR 5384, 5387, Feb.
20, 1987).
All of the immediate assessments
under this rule are set at $1,000 per
violation. The BLM chose the $1,000
figure because it generally approximates
what it would cost the agency to
identify and document each of the
violations in question and verify
remedial action and compliance.
Some commenters argued that the
immediate assessments in § 3174.15 are
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inconsistent with due process because
there is no opportunity for an operator
to correct its violations before an
assessment is imposed. To the contrary,
the use of immediate assessments for
breaches of the BLM’s oil and gas
regulations is well established and is
consistent with the notice requirements
of due process. Operators obligate
themselves to fulfill the terms and
conditions of the Federal or Indian oil
and gas leases under which they
operate, and these leases incorporate
applicable regulations by reference.
Thus, the immediate assessments
contained in the regulations act as
‘‘liquidated damages’’ owed by
operators that have breached their leases
by breaching the regulations (see, e.g.,
M. John Kennedy, 102 IBLA 396, 400
(1988)). Operators are expected to know
the obligations and requirements of the
Federal or Indian oil and gas lease
under which they operate; additional
notice is not required.
A number of commenters said the
$1,000 assessment amounts are
‘‘excessive.’’ One commenter said the
BLM should adjust the assessment
amounts on a case-by-case basis. The
BLM does not agree. The $1,000
assessments are in line with the
amounts needed for the BLM to recover
costs for staff and processing time
associated with the inspection process.
A fixed schedule of assessments also
ensures their impartiality and
uniformity. No changes to the rule
resulted from these comments.
Enforcement
As explained in the proposed rule, the
final rule removes the enforcement,
corrective action, and abatement period
provisions of Order 3. In their place, the
BLM will develop an Internal Inspection
and Enforcement Handbook that will
provide direction to BLM inspectors on
how to classify a violation—as either
major or minor—what the corrective
action should be, and what the
timeframes for correction should be.
The AO will use the Inspection and
Enforcement Handbook in conjunction
with 43 CFR subpart 3163, which
provides for assessments and civil
penalties when lessees and operators
fail to remedy their violations in a
timely fashion, and for immediate
assessments for certain violations.
As previously discussed in the
proposed rule, the final rule allows the
BLM to make a case-by-case
determination of the severity of a
violation, based on applicable
definitions in the regulations. In
deciding how severe a violation is, BLM
inspectors must take into account
whether a violation could result in
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‘‘immediate, substantial, and adverse
impacts on public health and safety, the
environment, production accountability,
or royalty income.’’ (Definition of
‘‘major violation,’’ 43 CFR 3160.0–5.)
Under the existing definition of ‘‘major
violation,’’ which is not being revised as
part of this rulemaking, the same
violation could be major or minor,
depending on the context.
Several commenters objected to this
approach for a number of reasons. One
concern was that if the BLM publishes
an internal guidance document ‘‘after
the fact,’’ meaning after the rule is final,
industry will be precluded from
commenting on or assessing the impact
of such a document on their operations.
Another concern was that a guidance
document will create inconsistency
between field offices and operators.
However, the commenter provided no
explanation as to how an internal
guidance document will create
inconsistency between field offices and
operators, or what confusion industry
will have concerning how the BLM
enforces the regulations. In general,
these comments misunderstand the
nature of the Internal Inspection and
Enforcement Handbook that the BLM
will develop. The new Handbook will
not establish new obligations to be
imposed on the regulated community.
Those obligations are spelled out in
applicable regulations, orders, and
permits, as well as the terms and
conditions of leases and other
agreements.
Other commenters questioned why
the Inspection and Enforcement
Handbook was not part of the public
notice and comment process. Internal
guidance documents that direct agency
personnel how to implement existing
agency policies are not required to
follow the public notice and comment
process. No change to the rule resulted
from this comment.
Additional comments suggested that
the BLM may not promulgate new
binding regulations in internal
‘‘guidance’’ documents. The BLM agrees
with this comment and will not be
promulgating any binding regulations
within the internal guidance document.
The overarching enforcement
infrastructure of 43 CFR subpart 3163
remains in effect, and the definitions of
‘‘major violation’’ and ‘‘minor violation’’
in § 3160.0–5 remain unchanged. It is
these duly promulgated regulations
(among other authorities), and not the
Inspection and Enforcement Handbook,
that will provide the legal basis for the
BLM’s enforcement actions; BLM’s
enforcement actions must be consistent
with these regulations irrespective of
what may be contained in its Inspection
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and Enforcement Handbook. As noted
above, it is this rule and other duly
promulgated regulations that establish
the standards to which an operator will
be held.
Several commenters asserted that
removing internal enforcement
provisions from the regulations that
were promulgated with public notice
and comment, and ‘‘concealing’’ them
in non-public policy documents that
can be altered without notice and in the
absence of public input, is inconsistent
with the requirements of the
Administrative Procedures Act (APA).
The BLM does not agree with these
comments as they misunderstand the
nature of the new Handbook. The
operative requirements to which
operators are subject are spelled out in
duly promulgated regulations,
consistent with APA requirements.
Internal agency guidance documents on
how to implement those requirements
are not subject to the APA’s notice and
comment requirements. No change to
the rule resulted from these comments.
A few other commenters said industry
has a right to know by what standards
they are being judged and penalized.
The BLM agrees and believes this rule
very clearly describes the standards
industry must meet in the oil
measurement context. As stated above,
in deciding how severe a violation is,
BLM inspectors will take into account
whether a violation could result in
‘‘immediate, substantial, and adverse
impacts on production accountability,
or royalty income’’ (definition of ‘‘major
violation’’, 43 CFR 3160.0–5.) One
commenter suggested that the BLM
provide internal standards to industry at
the earliest opportunity. The BLM
agrees and will make the internal
Inspection and Enforcement Handbook
available to the public once it is
completed.
Several commenters expressed
concern that industry has not seen any
proposed violations that may result in
enforcement actions prior to the BLM’s
adoption of the Inspection and
Enforcement Handbook. The BLM
wishes to further clarify what a
violation is. Any deviation from the
rules and regulations, without an
approved variance from the AO, is a
violation, and any violation will result
in enforcement action. The Handbook
will not alter that fundamental structure
in any way.
Additional commenters said the
BLM’s process for developing violations
and corrective actions is not
transparent. Again, these comments
misunderstand the nature of the
forthcoming internal guidance.
Operators are obligated to follow the
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rules and regulations applicable to their
operations, including the requirements
of this final rule, or they are in violation
and subject to potential enforcement
actions by the BLM. The Inspection and
Enforcement Handbook will simply
guide BLM staff on how to identify
violations and provide guidance on
which enforcement actions should be
taken, it does not answer the underlying
question of what is or is not a violation.
No changes to the rule resulted from
these comments.
Miscellaneous Changes to Other BLM
Regulations in 43 CFR Part 3160
Because this rule replaces Order 4, the
BLM is making two related changes to
provisions in 43 CFR part 3160.
1. Section 3162.7–2, Measurement of
oil, has been rewritten to be consistent
with this rule.
2. Section 3164.1, Onshore Oil and
Gas Orders, the table has been revised
to remove the reference to Order 4.
The BLM received no comments on
these sections and they remain as
proposed.
C. General Comments on the Proposed
Rule
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Regulatory Burden
The BLM received numerous
comments that said the cumulative
economic impact of this and other rules
that the BLM has adopted or plans to
finalize in the coming months will
result in unnecessary and restrictive
regulations, increased burdens and costs
to both industry and the BLM without
any documented financial benefits to
taxpayers, and job loss in the oil and gas
industry. The commenters noted that in
addition to this rulemaking, the BLM is
finalizing rules that will update and
replace Orders 3 and 5. In addition, on
February 8, 2016, the BLM published in
the Federal Register a proposed rule
entitled Waste Prevention, Production
Subject to Royalties, and Resource
Conservation (81 FR 6616), which seeks
to curtail the wasteful venting and
flaring of Federal and Indian gas.
Commenters also flagged the BLM’s new
regulations on hydraulic fracturing that
were to go into effect on June 24, 2015
(The rule is currently vacated by order
of the District Court of Wyoming, that
Order is on appeal to the U.S. Court of
Appeals for the Tenth Circuit.) The BLM
does not agree with these comments for
two primary reasons. First, this rule
codifies existing requirements found in
Order 4, adopts industry standards and
practices that are already in use, and has
built in compliance flexibility that
increases opportunities for operators to
deploy new technologies, potentially
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reducing costs. Notably, this rule
expands compliance opportunities
because, for the first time, it establishes
measurement performance standards
that can be used by operators to identify
and evaluate alternative measurement
methods and equipment. Second,
improved accuracy also has the
potential to benefit operators, because
measurement uncertainty has an equal
chance of favoring the government or
the lessee.
Other commenters said that the costs
to retrofit many of the facilities to bring
them into compliance with this rule and
the BLM’s proposed rules on gas
measurement and site security would
outweigh any foreseeable economic
benefits to operators and government
entities. The commenters contend that
the proposed rule would impose
significant and harmful burdens on
operators and the industry as a whole
causing operators to shut in, plug, and
abandon producing wells, possibly
leading to a loss of royalty and tax
revenue for the Federal Government, as
well as tribal, State, and local
governments. Several commenters
recommended that the BLM withdraw
the proposed rule at this time due to its
negative economic impacts, and argued
that the BLM could accomplish much of
what it seeks to do through this
proposed rule by simply updating the
content of Orders 4 and 5 to reflect
current voluntary consensus standards
developed by professional industry
groups. The BLM disagrees with the
suggestion that these rules are
unnecessary and will result in plugged
wells, or lost jobs. First, the current
economic conditions in the oil and gas
sector identified by the commenters are
a direct result of the significant drop in
oil prices over the last year and a half,
which has been accounted for in the
threshold analyses performed by the
BLM. For example, the recent drop in
oil prices led the BLM to change the
various thresholds between draft and
final rule, as explained in this preamble.
Second, with respect to the suggestion
that BLM should have simply updated
Orders 4 and 5 with references to the
relevant industry standards, it must be
noted that such an approach was not
available to the BLM. Order 4 was
promulgated using the APA’s Notice
and Comment procedures; therefore any
updates to it required BLM to undertake
Notice and Comment rulemaking. Under
those procedures, the BLM is forbidden
from incorporating industry standards,
unless it is incorporating them into
codified regulations, which is the
primary reason this rule is being
codified.
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With respect to the concerns about
cost, the BLM believes that this rule will
increase opportunities for operators to
reduce costs thanks to the rule’s builtin flexibility. As noted, this rule
includes specific performance standards
that will enable operators to identify
and evaluate alternative methods and
equipment for oil measurement. In
addition, the rule includes provisions
expressly authorizing ATG systems and
the use of Coriolis meters (either as a
component of a LACT system or as a
standalone metering system). Finally, as
explained elsewhere, the rule
incorporates the latest industry
standards and establishes a PMT to
evaluate new equipment and
methodologies, so that the BLM can
review and approve such equipment
and methodologies as they are
developed. This flexibility is not
available in the current Order 4, which
requires operators to obtain case-by-case
variances before they may use new
equipment or methods.
Retroactivity
A number of commenters argued that
the rule is impermissibly ‘‘retroactive.’’
These comments argued that the rule is
retroactive because it will apply to
measurement systems whose existence
pre-dates the rule’s effective date. While
the BLM agrees that truly retroactive
regulations raise legal concerns, those
concerns are not implicated here
because this rule is not retroactive. The
comments misunderstand the nature of
the ‘‘retroactive’’ regulations that the
law disfavors. ‘‘A law does not operate
‘retrospectively’ merely because it is
applied in a case arising from conduct
antedating the statute’s enactment or
upsets expectations based in prior law’’
(Landgraf v. USI Film Prods., 511 U.S.
244, 269 (1994) (internal citations
omitted)). Rather, the test for
retroactivity is whether the new
regulation ‘‘attaches new legal
consequences to events completed
before its enactment.’’ Id. at 270. The
rule at hand does not attach any new
legal consequence to the past use of
existing measurements systems. As the
U.S. Court of Appeals for the District of
Columbia Circuit has explained, the fact
that a change in the law adversely
affects pre-existing arrangements does
not render that law ‘‘retroactive:’’
It is often the case that a business will
undertake a certain course of conduct based
on the current law, and will then find its
expectations frustrated when the law
changes. This has never been thought to
constitute retroactive lawmaking, and indeed
most economic regulation would be
unworkable if all laws disrupting prior
expectations were deemed suspect.
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Chemical Waste Mgmt., Inc. v. EPA, 869
F.2d 1526, 1536 (D.C. Cir. 1989). Thus,
despite the fact that this rule may
require companies to update or modify
their existing measurement systems, the
rule is nonetheless prospective—not
retroactive—in nature. The obligation to
accurately measure and account for oil
produced from both new and existing
facilities is ongoing and track the
productions each day it occurs.
National Technology Transfer and
Advancement Act of 1995
The National Technology Transfer
and Advancement Act of 1995
(NTTAA), codified as a note to 15 U.S.C.
272, directs agencies to utilize technical
standards that are developed by
voluntary consensus standards bodies.
In this rule, the BLM is adopting certain
oil measurement standards developed
by the API. Some commenters argued
that the NTTAA obligates the BLM to
adopt all oil measurement standards
developed by voluntary consensus
standards bodies. This position
overstates the requirements of the
NTTAA. The NTTAA does not require
an agency to adopt voluntary consensus
standards where it would be
‘‘impractical.’’ NTTAA Section 12(d)(3).
The Office of Management and Budget’s
(OMB) guidance for implementing the
NTTAA defines ‘‘impractical’’ to
include circumstances in which the use
of certain standards ‘‘would fail to serve
the agency’s regulatory, procurement, or
program needs; be infeasible; be
inadequate, ineffectual, inefficient, . . .
or impose more burdens, or be less
useful, than those of another standard’’
(OMB Circular A–119, pg. 20.)
Furthermore, the OMB has explained
that the NTTAA ‘‘does not preempt or
restrict agencies’ authorities and
responsibilities to make regulatory
decisions authorized by statute . . .
[including] determining the level of
acceptable risk and risk-management,
and due care; setting the level of
protection; and balancing risk, cost, and
availability of alternative approaches in
establishing regulatory requirements’’
(OMB Circular A–119, pg. 25.) The BLM
has studied the available voluntary
consensus standards for oil
measurement and has chosen to adopt a
workable suite of these standards that
will meet the BLM’s regulatory needs in
an effective and feasible manner. To
adopt all available voluntary consensus
standards would be ‘‘impractical’’ in
that it would involve the adoption of
standards the BLM has judged to be less
effective, feasible, or useful. In addition,
the commenters reading of the NTTAA
would, contrary to OMB guidance,
preempt the BLM’s statutory authority
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to promulgate rules and regulations that
it deems necessary to accomplish the
purposes of the MLA and FOGRMA.
III. Overview of Public Involvement and
Consistency With GAO
Recommendations
Public Outreach
The BLM conducted extensive public
and tribal outreach on this rule both
prior to its publication as a proposed
rule and during the public comment
period on the proposed rule. Prior to the
publication of the proposed rule, the
BLM held both tribal and public forums
to discussion potential changes to the
rule. In 2011, the BLM held three tribal
meetings in Tulsa, Oklahoma (July 11,
2011); Farmington, New Mexico (July
13, 2011); and Billings, Montana
(August 24, 2011). On April 24 and 25,
2013, the BLM held a series of public
meetings to discuss draft proposed
revisions to Orders 3, 4, and 5. The
meetings were webcast so tribal
members, industry, and the public
across the country could participate and
ask questions either in person or over
the Internet. Following those meetings,
the BLM opened a 36-day informal
comment period, during which 13
comment letters were submitted. The
comments received during that
comment period were summarized in
the preamble for the proposed rule (80
FR 58952).
The proposed rule was made available
for public comment from September 30,
2015 through December 14, 2015.
During that period, the BLM held tribal
and public meetings on December 1
(Durango, Colorado), December 3
(Oklahoma City, Oklahoma), and
December 8 (Dickinson, North Dakota).
The BLM also held a tribal webinar on
November 19, 2015. In total, the BLM
received 106 comment letters on the
proposed rule, the substance of which
are addressed in the Section-by-Section
analysis of this preamble.
Consistency With GAO
Recommendations
As explained in the background
section of this preamble, three outside
independent entities—the
Subcommittee, the OIG, and the GAO—
have repeatedly found that the BLM’s
oil measurement rules do not provide
sufficient assurance that operators pay
the royalties due. Specifically, these
groups found that the BLM needed
updated guidance on oil measurement
technologies, to address existing
technological advances, as well as
technologies that might be developed in
the future. These groups have all found
that the BLM’s existing guidance is
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‘‘unconsolidated, outdated, and
sometimes insufficient,’’ and more
specifically, that:
• BLM policy and guidance have not
been consolidated into a single
document or publication, resulting in
the BLM’s 31 oil and gas field offices
using varying policy and guidance;
• Some BLM policy and guidance is
outdated and some policy memoranda
have expired; and
• Some BLM State offices have issued
their own NTLs for oil and gas
operations, which lack a national
perspective and may introduce
inconsistencies among the States with
respect to the same types of operations.
The final rule addresses these
recommendations by establishing
nationwide performance requirements
for oil measurement that addresses
uncertainty factors, bias, and the
verifiability of measurement. The rule
specifically addresses technological
advances in oil metering technology
since Order 4 was promulgated. It
affirmatively allows the use of those
technologies that have been shown to be
sufficiently reliable and accurate. It also
updates the BLM’s requirements related
to proper measurement, documentation,
and recordkeeping. Going forward the
final rules establishes a process for the
BLM to review, and approve for use,
new oil measurement technology and
systems.
IV. Procedural Matters
Executive Orders 12866 and 13563,
Regulatory Planning and Review
Executive Order (E.O.) 12866 provides
that the Office of Information and
Regulatory Affairs (OIRA) will review
all significant rules. OIRA has
determined that this rule is not
significant.
E.O. 13563 reaffirms the principles of
E.O. 12866 while calling for
improvements in the nation’s regulatory
system to promote predictability, to
reduce uncertainty, and to use the best,
most innovative, and least burdensome
tools for achieving regulatory ends. The
executive order directs agencies to
consider regulatory approaches that
reduce burdens and maintain flexibility
and freedom of choice for the public
where these approaches are relevant,
feasible, and consistent with regulatory
objectives. E.O. 13563 emphasizes
further that regulations must be based
on the best available science and that
the rulemaking process must allow for
public participation and an open
exchange of ideas. The BLM has
developed this rule in a manner
consistent with these requirements.
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Regulatory Flexibility Act
The BLM certifies that this final rule
will not have a significant economic
effect on a substantial number of small
entities as defined under the Regulatory
Flexibility Act (5 U.S.C. 601 et seq.).
The Small Business Administration
(SBA) has developed size standards to
carry out the purposes of the Small
Business Act and those size standards
can be found at 13 CFR 121.201. The
Small Business Act applies to oil and
gas extraction firms with fewer than
1,250 employees, oil and gas drilling
firms with fewer than 1,000 employees,
and firms providing oil and gas support
activities with annual receipts of no
more than $38.5 million. These small
entities must be considered as being at
‘‘arm’s length’’ from the control of any
parent companies.
Of the 6,460 domestic firms involved
in onshore oil and gas extraction in
2013, U.S. Census data show that 99
percent (or 6,370) had fewer than 500
employees, which means that nearly all
U.S. firms involved in oil and gas
extraction in 2013 fell within the SBA’s
size standard of fewer than 1,250
employees. Of the 2,097 firms
participating in oil and gas drilling
activities in 2013, U.S. Census data
show that 2,044 had fewer than 500
employees, which means that nearly all
U.S. firms involved in oil and gas
support activities in 2013 fell within the
SBA’s size standard of fewer than 1,000
employees. There were another 8,877
firms involved in drilling and other
support functions in 2012. Of the firms
providing support functions, 96 percent
(8,561) had annual net receipts of no
more than $35 million, with a greater
number below the SBA’s $38.5 million
threshold.
Based on this national data, the
preponderance of firms involved in
developing oil and gas resources are
small entities as defined by the SBA. As
such, it appears a number of small
entities potentially could be affected by
this rule. Using the best available data,
the BLM estimates there are
approximately 3,700 lessees/operators
conducting oil operations on Federal
and Indian lands that could be affected
by this rule.
On an ongoing basis, we estimate the
changes to the LACT meter proving
frequency requirements based on
volume throughput will increase the
regulated community’s total annual
costs by $67,650. This amount
corresponds to the cost of an estimated
123 additional annual provings per year
at 28 LACT systems on 19 leases, CAs,
or PAs flowing between 31,250 bbl/
month/meter and 100,000 bbl/month/
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meter. This includes 75 additional
provings ($41,250 in cost) for 22 LACT
systems on 15 leases, CAs, or PAs
flowing at least 31,250 bbl/month/meter
and below 75,000 bbl/month/meter, and
48 additional provings ($26,400 in cost)
for six LACT systems on four leases, CA,
or PA’s flowing at least 75,000 bbl/
month/meter and below 100,000 bbl/
month/meter. Currently, LACT systems
for both of these groups of systems
would be proven monthly for LACTs
measuring 100,000 bbl/month or greater,
or once every 3 months (four times per
year). Under the new rule, meters at the
first group of LACT systems (31,250 bbl/
month/meter up to 75,000 bbl/month/
meter) would be proven every 75,000
bbl, or from 5 to 11 times per year,
while meters in the second group of
LACT systems (75,000 bbl/month/meter
up to 100,000 bbl/month/meter) would
be proven monthly, or 12 times each
year. There would be no change in
proving frequency for properties
producing at or above 100,000 bbl/
month/meter (one proving per month, or
12 per year) or below 31,250 bbl/month/
meter (one proving per quarter, or four
per year).
In addition, there will be a one-time
cost to retrofit an estimated 20 percent
of existing LACT systems of about $1.9
million, or a one-time average cost of
about $6,500 for each of an estimated
approximately 296 existing LACT
systems. This amounts to an average
one-time cost of $519 for each of the
approximately 3,700 lessees/operators
conducting oil production operations on
Federal or Indian leases. The
requirement for operators to conduct
tank strappings to submit revised
calibration tables to the BLM will have
an annual cost to operators of $4.0
million per year (approximately $1,080
per entity), plus an additional $0.2
million in industry paperwork costs for
submitting these tables, and $0.2
million in additional costs to the BLM
to process these paperwork
submissions. When adding the
additional cost of hourly recordkeeping
and non-hourly provisions in the final
rule, the BLM estimates that the rule
will have a total impact of $3.3 million
in one-time costs and $4.6 million in
annual costs. When the one-time costs
are annualized for the first 3 years
following the enactment of the final
rule, and combined with annual costs
for these years, the BLM estimates a
total annualized cost of $5.7 million per
year, or $1,540 per entity per year, for
years 1–3 after the final rule’s effective
date. After year three, costs will equal
the estimated annual cost of $4.6
million, or $1,240 per entity per year.
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81499
All of the provisions apply to entities
regardless of size. However, entities
with the greatest activity likely will
experience the greatest increase in
compliance costs.
Based on the available information,
we conclude that the final rule will not
have a significant impact on a
substantial number of small entities.
The final rule will cost each entity an
average of less than $2,000 per year,
which will impact expected annual
operator net income by less than 0.01
percent, as described in the Regulatory
Impact Analysis for this rule. Therefore,
a final Regulatory Flexibility Analysis is
not required, and a Small Entity
Compliance Guide is not required.
Small Business Regulatory Enforcement
Fairness Act
This final rule is not a major rule
under 5 U.S.C. 804(2), the Small
Business Regulatory Enforcement
Fairness Act. This rule will not have an
annual effect on the economy of $100
million or more. As explained under the
preamble discussion concerning E.O.
12866, Regulatory Planning and Review,
changes to oil measurement under this
final rule relative to the existing
requirements of Order 4 will increase
the cost associated with the
development and production of crude
oil resources under Federal and Indian
oil and gas leases by about $4.8 million
annually. Of this amount, about $3.9
million/year will be borne by industry,
and $0.9 million/year by the BLM.
There will also be a one-time cost of
about $1.9 million to retrofit an
estimated 20 percent of existing LACT
systems, borne entirely by industry.
Based on the cost figures above, the
estimated annual increased cost to the
estimated 3,700 lessees/operators
conducting oil production operations on
Federal or Indian leases for
implementing these changes is about
$1,055 per year, and a one-time average
cost of about $520 per entity.
This final rule:
• Will not cause a major increase in
costs or prices for consumers,
individual industries, Federal, State,
tribal, or local government agencies, or
geographic regions; and
• Will not have significant adverse
effects on competition, employment,
investment, productivity, innovation, or
the ability of U.S.-based enterprises to
compete with foreign-based enterprises.
Unfunded Mandates Reform Act
In accordance with the Unfunded
Mandates Reform Act (2 U.S.C. 1501 et
seq.), the BLM finds that:
• This final rule will not
‘‘significantly or uniquely’’ affect small
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governments. A Small Government
Agency Plan is unnecessary.
• This final rule will not produce a
Federal mandate of $100 million or
greater in any single year.
The final rule is not a ‘‘significant
regulatory action’’ as it will not require
anything of any non-Federal
governmental entity.
Executive Order 12630, Governmental
Actions and Interference With
Constitutionally Protected Property
Rights (Takings)
Under E.O. 12630, the final rule
would not have significant takings
implications. A takings implication
assessment is not required. This final
rule will establish the minimum
standards for accurate measurement and
proper reporting of oil produced from
Federal and Indian leases, unit PAs, and
CAs, by providing a system for
production accountability by operators
and lessees. All such actions are subject
to lease terms that expressly require that
subsequent lease activities be conducted
in compliance with applicable Federal
laws and regulations. The final rule
conforms to the terms of those Federal
leases and applicable statutes, and as
such the final rule is not a governmental
action capable of interfering with
constitutionally protected property
rights. Therefore, the final rule will not
cause a taking of private property and
does not require further discussion of
takings implications under this E.O.
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Executive Order 13132, Federalism
In accordance with E.O. 13132, the
BLM finds that the final rule will not
have significant Federalism effects. A
Federalism assessment is not required.
This final rule will not change the role
of or shift responsibilities among
Federal, State, and local governmental
entities. It does not relate to the
structure and role of the States and will
not have direct, substantive, or
significant effects on States.
Executive Order 13175, Consultation
and Coordination With Indian Tribal
Governments
Under Executive order 13175, the
President’s memorandum of April 29,
1994, ‘‘Government-to-Government
Relations with Native American Tribal
Governments’’ (59 FR 22951), and 512
Departmental Manual 2, the BLM
evaluated possible effects of the final
rule on federally recognized Indian
tribes. The BLM approves proposed
operations on all Indian (except Osage
Tribe) onshore oil and gas leases.
Therefore, the final rule has the
potential to affect Indian tribes. In
conformance with the Secretary’s policy
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on tribal consultation, the BLM held
tribal consultation meetings to which
more than 175 tribal entities were
invited, both before the rule was
proposed and during the public
comment period on the proposed rule.
The consultations were held in:
Pre-Publication Meetings
• Tulsa, Oklahoma on July 11, 2011;
• Farmington, New Mexico on July
13, 2011; and
• Billings, Montana on August 24,
2011.
• Tribal workshop and webcast in
Washington, DC on April 24, 2013.
Post-Publication Meetings
• The BLM hosted a webinar to
discuss the requirements of the
proposed rule and solicit feedback from
affected tribes on November 19, 2015;
and
• In-person meetings were held in:
Æ Durango Colorado, on December 1,
2015;
Æ Oklahoma City, Oklahoma, on
December 3, 2015; and
Æ Dickinson, North Dakota, on
December 8, 2015.
The BLM also met with interested
tribes on a one-on-one basis, if
requested to address questions on the
proposed rule prior to the publication of
the final rule. In each instance, the
purpose of these meetings was to solicit
feedback and comments from the tribes.
The primary concerns expressed by
tribes related to the subordination of
tribal laws, rules, and regulations by the
proposed rule; tribal representation on
the Department’s Gas and Oil
Measurement Team; and the BLM’s
Inspection and Enforcement program’s
ability to enforce the terms of this rule.
In general, the tribes, as royalty
recipients, expressed support for the
goals of the rulemaking, namely
accurate measurement. With respect to
tribal representation on the
Department’s Gas and Oil Measurement
Team, it should be noted that the team
is internal to BLM. That said, the BLM
will continue to consult with tribes on
measurement issues that impact them
and their resources. None of the tribal
comments received were directed
specifically at this rule’s oil
measurement requirements, and
therefore no changes were made as a
result of these comments. While the
BLM will continue to address these
concerns, none of the concerns affect
the substance of the proposed rule.
Executive Order 12988, Civil Justice
Reform
Under E.O. 12988, the Office of the
Solicitor has determined that the final
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rule will not unduly burden the judicial
system and meets the requirements of
Sections 3(a) and 3(b)(2) of the E.O. The
Office of the Solicitor has reviewed the
final rule to eliminate drafting errors
and ambiguity. It has been written to
minimize litigation, provide clear legal
standards for affected conduct rather
than general standards, and promote
simplification and burden reduction.
Executive Order 13352, Facilitation of
Cooperative Conservation
Under E.O. 13352, the BLM has
determined that this final rule will not
impede cooperative conservation and
will take appropriate account of and
consider the interests of persons with
ownership or other legally recognized
interests in land or other natural
resources. This rulemaking process
involved Federal, tribal, State, and local
governments, private for-profit and
nonprofit institutions, other
nongovernmental entities and
individuals in the decision-making via
the public comment process. That
process provides that the programs,
projects, and activities are consistent
with protecting public health and safety.
Paperwork Reduction Act
The Paperwork Reduction Act (PRA)
(44 U.S.C. 3501–3521) provides that an
agency may not conduct or sponsor, and
a person is not required to respond to,
a collection of information, unless it
displays a currently valid OMB control
number. Collections of information
include requests and requirements that
an individual, partnership, or
corporation obtain information, and
report it to a Federal agency. See 44
U.S.C. 3502(3); 5 CFR 1320.3(c) and (k).
This rule contains information
collection activities that require
approval by the OMB under the
Paperwork Reduction Act. The BLM
included an information collection
request in the proposed rule. OMB has
approved the information collection for
the final rule under control number
1004–0209.
The information collection activities
in this rule are described below along
with estimates of the annual burdens.
Included in the burden estimates are the
time for reviewing instruction,
searching existing data sources,
gathering and maintaining the data
needed, and completing and reviewing
each component of the proposed
information collection.
Summary of Information Collection
Activities
Title: Measurement of Oil (43 CFR
parts 3160 and 3170).
Forms: None.
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OMB Control Number: 1004–0209.
Description of Respondents: Oil and
gas operators.
Abstract: This final rule replaces
Onshore Oil and Gas Order Number 4,
Measurement of Oil (Order 4) with new
regulations that will be codified at 43
CFR parts 3160 and 3170. This rule
establishes minimum standards for the
measurement of oil produced from
Federal and Indian (except Osage Tribe)
leases to ensure accurate measurement
and accounting. It also updates the
minimum standards for oil
measurement to reflect the considerable
changes in technology and industry
practices that have occurred since 1989,
when Order 4 was issued.
Frequency of Collection: On occasion.
Obligation to Respond: Required to
obtain or retain benefits.
Estimated Annual Responses: 11,707.
Estimated One-Time Responses: 35.
Estimated Annual Reporting and
Recordkeeping ‘‘Hour’’ Burden: 3,284.
Estimated One-Time Reporting and
Recordkeeping ‘‘Hour’’ Burden: 2,600.
Discussion of Information Collection
Activities
The information collection activities
in the final rule are discussed below.
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Request for Exception to Uncertainty
Requirements (43 CFR 3174.4(a)(2))
The final rule, at 43 CFR 3174.4(a),
requires each FMP to achieve certain
overall uncertainty levels. An operator
may seek an exception to the prescribed
uncertainty levels by submitting a
request to a BLM State Director. The
operator must show that meeting the
required uncertainly level would
involve extraordinary cost or
unacceptable adverse environmental
effects. The State Director may grant
such a request only with written
concurrence from the PMT (prepared in
coordination with the Deputy Director).
This provision enables the BLM to
determine whether or not it is
reasonable to grant an exception to
uncertainty requirements.
Tank Calibration Tables (43 CFR
3174.5(c)(3))
Section 3174.5(c)(3) requires
submission of tank calibration tables to
the BLM within 30 days after
calibration. This provision ensures that
BLM personnel will have the latest
charts when conducting inspections or
audits.
Approval of Automatic Tank Gauging
(ATG) Equipment (43 CFR
3174.6(b)(5)(ii)(A)); and Log of ATG
Verification (43 CFR 3174.6(b)(5)(ii)(C))
The procedures for oil measurement
by tank gauging must comply with the
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requirements outlined in 43 CFR 3174.6.
Beginning on January 17, 2019, only the
specific makes and models of ATG that
are identified and described at the BLM
Web site (www.blm.gov) are approved
for use.
If an operator chooses to use a
particular make or model of ATG
equipment, the operator (or the
manufacturer of the ATG equipment)
must seek and obtain BLM approval of
the particular make and model of that
equipment by submitting a request to
the PMT, consisting of a panel of BLM
employees who are oil and gas
measurement experts. The submission
must describe the test data used to
develop performance specifications.
After reviewing the test data, the PMT
will recommend whether or not to
approve the ATG equipment. This
information collection activity enables
the BLM to consider approving new
technologies not yet addressed in its
regulations.
The operator must inspect its ATG
equipment and verify its accuracy at
least once a month, or prior to sales,
whichever is later. In addition, the BLM
may request inspection and verification
at any time.
If the operator finds ATG equipment
to be out of tolerance, the operator must
calibrate the equipment prior to sales,
and must maintain a log of field
verifications. That operator must make
the log available to the BLM upon
request. The log must include the
following information:
• The date of verification;
• The as-found manual gauge
readings;
• The as-found ATG readings; and
• Whether the ATG equipment was
field-calibrated.
If the ATG equipment was fieldcalibrated, the as-left manual gauge
readings and as-left ATG readings must
be recorded. This information collection
activity enables the BLM to ensure the
accuracy of tank gauging by ATG
systems.
Notification of LACT System Failure (43
CFR 3174.7(e)(1))
Section 3174.7(e)(1) requires the
operator to notify the BLM within 72
hours of any LACT system failures or
equipment malfunctions which may
have resulted in measurement error. As
defined at proposed § 3174.1, a LACT
system consists of components designed
to provide for the unattended custody
transfer of oil produced from a lease,
unit PA, or Communitized Area (CA) to
the transporting carrier while providing
a proper and accurate means for
determining the net standard volume
and quality, and fail-safe and tamper-
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proof operations. This information
collection requirement enables the BLM
to verify that operators account for all
oil volumes.
Approval of a Positive Displacement
(PD) Meter (43 CFR 3174.8(a)(1)); and
Approval of a Coriolis Meter (43 CFR
3174.9(b))
Section 3174.8(a)(1) requires each
custody transfer meter to be a PD meter
or a Coriolis meter. A PD meter
measures liquid by constantly and
mechanically isolating flowing liquid
into segments of known volume. A
Coriolis meter measures liquid via the
interaction between a flowing fluid and
oscillation of tubes. Beginning on
January 17, 2019, only the specific
make, models, and sizes of PD meters
and Coriolis meters and associated
software that are identified and
described at www.blm.gov are approved
for use.
If an operator chooses to use a
particular make or model of PD meter or
Coriolis meter, the operator (or the
manufacturer of the meter) must seek
and obtain BLM approval of that
particular make and model by
submitting a request to the PMT. The
submission must describe the test data
used to develop performance
specifications. After reviewing the test
data, the PMT will recommend whether
or not to approve the meter. This
information collection activity enables
the BLM to consider approving new
technologies not yet addressed in its
regulations.
Coriolis Meter Specification and Zero
Verification Procedure (43 CFR
3174.10(b)(2) and (d)); Zero Verification
Log (43 CFR 3174.10(b)(2) and (e)(4));
and Audit Trail Requirements for
Coriolis Measurement System (CMS) (43
CFR 3174.10(b)(2) and (f))
Section 3174.10(b)(2) requires the
operator to submit Coriolis meter
specifications to the BLM upon request.
The meter specification of a Coriolis
meter must clearly identify the make
and model of the Coriolis meter to
which they apply and must include the
following:
• The reference accuracy for both
mass flow rate and density, stated in
either percent of reading, percent of full
scale, or units of measure;
• The effect of changes in
temperature and pressure on both mass
flow and fluid density readings;
• The effect of flow rate on density
readings;
• The stability of the zero reading for
volumetric flow rate;
• Design limits for flow rate and
pressure; and
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• Pressure drop through the meter as
a function of flow rate and fluid
viscosity.
Section 3174.10(d) requires the
operator to provide the BLM with a
copy of the zero value verification
procedure upon request.
Section 3174.10(e)(4) requires the
operator to maintain a log of all meter
factors, zero verifications, and zero
adjustments. For zero adjustments, the
log must include the zero value before
adjustment and the zero value after
adjustment. The log must be made
available to the BLM upon request.
Section 3174.10(f) requires the
operator to record and retain, and
submit to the BLM upon request, the
following information:
• Quantity transaction record (QTR)
in accordance with the requirements for
a measurement ticket (at 43 CFR
3174.12(b));
• Configuration log that contains and
identifies all constant flow parameters
used in generating the QTR;
• Event log of sufficient capacity to
record all events such that the operator
can retain the information under the
recordkeeping requirements of 43 CFR
3170.7; and
• Alarm log that records the type and
duration of any of the following alarm
conditions:
Æ Density deviations from acceptable
parameters; and
Æ Instances in which the flow rate
exceeded the manufacturer’s maximum
recommended flow rate or were below
the manufacturer’s minimum
recommended flow rate.
These information collection activities
will assist the BLM in ensuring realtime, on-line measurement of oil.
Meter Proving and Volume Adjustments
Notification (43 CFR 3174.11(i)(1)); and
Meter Proving Reports (43 CFR
3174.11(i)(3))
Section 3174.11 specifies the
minimum requirements for conducting
volumetric meter proving for all FMP
meters. Meter proving verifies the
accuracy of a meter.
Under 43 CFR 3174.11(i)(1), an
operator must report to the BLM all
meter-proving and volume adjustments
after any LACT system or CMS
malfunction. The operator must use the
appropriate form in API 12.2.3 or API
5.6 (both incorporated by reference at 43
CFR 3174.3), or use a similar format
showing the same information as the
API form, provided that the calculation
of meter factors maintains the proper
calculation sequence and rounding.
In addition, a meter-proving report
must show the:
• Unique meter ID number;
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• Lease number, CA number, or unit
PA number;
• The temperature from the test
thermometer and the temperature from
the temperature averager or temperature
transducer;
• For pressure transducers, the
pressure applied by the pressure test
device and the pressure reading from
the pressure transducer at the three
points required under paragraph (g)(3)
of this section;
• For density verification (if
applicable), the instantaneous flowing
density (as determined by Coriolis
meter), and the independent density
measurement, as compared under 43
CFR 3174.(h); and
• The ‘‘as left’’ fluid flow rate and
fluid pressure, if the back pressure valve
is adjusted after proving as described in
43 CFR 3174.11(c)(9).
Under § 3174.11(i)(3), the operator
must submit the meter-proving report to
the BLM no later than 14 days after the
meter proving. The proving report may
be either in a hard copy or electronic
format.
These information collection
activities will assist in ensuring the
accuracy of meters.
Tank Gauging Run Tickets (43 CFR
3174.12(a)); and LACT or CMS Run
Tickets (43 CFR 3174.12(b))
A run ticket is the evidence of receipt
or delivery of oil issued by a pipeline,
other carrier, or purchaser. The amount
of oil transferred from storage is
recorded on a run ticket. The amount of
payment for oil is based upon
information contained in the run ticket.
Tank gauging (43 CFR 3174.12(a))—
After oil is measured by tank gauging,
the operator, purchaser, or transporter,
as appropriate, must complete a
uniquely numbered measurement ticket,
in either paper or electronic format,
with the following information:
• Lease, unit, or CA number;
• Unique tank number and nominal
tank capacity;
• Opening and closing dates and
times;
• Opening and closing gauges and
observed temperatures in °F;
• Observed volume for opening and
closing gauge;
• Total gross standard volume
removed from the tank;
• Observed API oil gravity and
temperature in °F;
• API oil gravity at 60 °F;
• S&W percent;
• Unique number of each seal
removed and installed;
• Name of the individual performing
the manual tank gauging; and
• Name of the operator.
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LACT or CMS (43 CFR 3174.12(b))—
The operator, purchaser, or transporter,
as appropriate, must complete a
uniquely numbered measurement ticket,
in either paper or electronic format, at
the beginning of every month, and
(unless a flow computer is being used in
accordance with 43 CFR 3174.10) before
conducting proving operations on a
LACT system. The following
information is required:
• Lease, unit, or CA number;
• Unique meter ID number;
• Opening and closing dates;
• Opening and closing totalizer
readings of the indicated volume;
• Meter factor, indicating if it is a
composite meter factor;
• Total gross standard volume
removed through the LACT system or
CMS;
• API oil gravity;
• The average temperature in °F;
• The average flowing pressure in
psig;
• S&W percent;
• Unique number of each seal
removed and installed;
• Name of the purchaser’s
representative; and
• Name of the operator.
Request To Use Alternate Oil
Measurement System (43 CFR 3174.13)
Section 3174.13 requires prior BLM
approval for any method of oil
measurement other than manual tank
gauging, LACT system, or CMS at an
FMP. Any operator requesting approval
to use alternate oil measurement
equipment must submit to the BLM:
• Performance data;
• Actual field test results;
• Laboratory test data; or
• Any other supporting data or
evidence that demonstrates that the
proposed alternate oil measurement
equipment would meet or exceed the
objectives of the applicable minimum
requirements at 43 CFR subpart 3174
and would not affect royalty income or
production accountability.
The PMT will review and make
recommendations in response to
requests to use alternate oilmeasurement equipment. This
information collection activity enables
the BLM to consider approving new
technologies not yet addressed in its
regulations.
Approval for Slop or Waste Oil (43 CFR
3174.14)
When production cannot be measured
due to spillage or leakage, the amount
of production must be determined by
using any method the BLM approves or
prescribes. This category of production
includes, but is not limited to, oil that
is classified as slop oil or waste oil.
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No oil may be classified or disposed
of as waste oil unless the operator can
demonstrate to the satisfaction of the
BLM that it is not economically feasible
to put the oil into marketable condition.
The operator may not sell or
otherwise dispose of slop oil without
prior written approval from the BLM.
Following the sale or disposal of slop
oil, the operator must notify the BLM in
81503
writing of the volume sold or disposed
of and the method used to compute the
volume.
The following table itemizes the
estimated hour burdens for this rule:
ESTIMATED HOUR BURDENS
Type of response
Number of
responses
Hours per
response
Total hours
A.
B.
C.
D.
5
2
10,000
40
40
.25
200
80
2,500
5
80
400
1
18
100
80
0.1
0.25
80
1.8
25
10
80
800
1
10
1
100
100
80
80
80
0.1
0.1
80
800
80
10
10
500
500
150
60
123
5
1
50
0.25
0.1
0.5
0.1
0.25
80
80
1
125
50
75
6
31
400
80
50
Total Annual Costs ...............................................................................................................
11,707
........................
3,284
Total One-Time Costs ..........................................................................................................
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Request for Exception to Uncertainty Requirements—43 CFR 3174.4(a)(2)—One-Time .........
Request for Exception to Uncertainty Requirements—43 CFR 3174.4(a)(2)—Annual ..............
Documentation of Tank Calibration Table Strapping—43 CFR 3174.5(c)(3)—Annual ..............
Documentation of Testing for Approval of Automatic Tank Gauging (ATG) Equipment—43
CFR 3174.6(b)(5)(ii)(A)—One-Time .........................................................................................
Documentation of Testing for Approval of Automatic Tank Gauging (ATG) Equipment—43
CFR 3174.6(b)(5)(ii)(A)—Annual .............................................................................................
Log of ATG Verification—43 CFR 3174.6(b)(5)(ii)(C)—Annual ..................................................
Notification of LACT System Failure—43 CFR 3174.7(e)(1)—Annual .......................................
Documentation of Testing for Approval of a Positive Displacement (PD) Meter—43 CFR
3174.8(a)(1)—One-Time ..........................................................................................................
Documentation of Testing for Approval of a Positive Displacement (PD) Meter—43 CFR
3174.8(a)(1)—Annual ...............................................................................................................
Documentation of Testing for Approval of a Coriolis Meter 43 CFR 3174.9(b)—One Time ......
Documentation of Testing for Approval of a Coriolis Meter 43 CFR 3174.9(b)—Annual ...........
Documentation of Zero Verification Procedure—43 CFR 3174.10(b)(2) and (d)—Annual ........
Zero Verification Log—43 CFR 3174.10(b)(2) and (e)(4)—Annual ............................................
Audit Trail Requirements for Coriolis Measurement System (CMS)—43 CFR 3174.10(b)(2)
and (f)—Annual ........................................................................................................................
Onsite Data Display Requirements—43 CFR 3174.10(e)—Annual ............................................
Meter Prover Calibration Documentation—43 CFR 3174.11(b)—Annual ...................................
Meter Proving and Volume Adjustments Notification—43 CFR 3174.11(i)(1)—Annual .............
Meter Proving Reports—43 CFR 3174.11(i)(3)—Annual ............................................................
Request to Use Alternate Oil Measurement System—43 CFR 3174.13—One Time ................
Request to Use Alternate Oil Measurement System—43 CFR 3174.13—Annual .....................
Approval for Slop or Waste Oil—43 CFR 3174.14—Annual ......................................................
35
........................
2,600
National Environmental Policy Act
(NEPA)
The BLM prepared an environmental
assessment (EA), a Finding of No
Significant Impact (FONSI), and a
Decision Record (DR) that conclude that
the final rule would not constitute a
major Federal action significantly
affecting the quality of the human
environment under NEPA, 42 U.S.C.
4332(2)(C). Therefore, a detailed
environmental impact statement (EIS)
under NEPA is not required. A copy of
the EA, FONSI, and DR are available for
review and on file in the BLM
Administrative Record at the location
specified in the ADDRESSES section.
As explained in the EA, FONSI, and
DR, the final rule would not have a
significant effect on the human
environment because, for the most part,
its requirements involve changes that
are of an administrative, technical, or
procedural nature that apply to the
BLM’s and the lessee’s or operator’s
administrative processes. For example,
the rule allows operators to use a CMS
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or an ATG/hybrid tank measurement
system without receiving a variance
from the BLM as they must do now. The
final rule also adopts a process and
criteria that will allow for the PMT to
review any new measurement system or
method approval requests submitted to
the BLM.
Overall these changes will enhance
the agency’s ability to account for the oil
and gas produced from Federal and
Indian lands, but should have minimal
to no impact on the environment. Some
of these standards, such as the
requirement that operators replace their
automatic temperature/gravity
compensators with temperature
averaging devices, may result in
increased human presence and traffic on
existing disturbed surfaces, but these
activities are expected to have a
negligible impact on the quality of the
human environment, as discussed in the
final EA.
A draft of the EA was shared with the
public during the public comment
period on the proposed rule. As part of
PO 00000
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Fmt 4701
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that process, the BLM received
comments on the EA. Commenters
questioned the BLM’s level of NEPA
documentation, whether or not the BLM
had met the ‘‘hard look’’ test of
describing the environmental
consequences of the proposed action,
and the BLM’s ability to reach a FONSI
based on the level of analysis. One
commenter requested a complete NEPA
revision with formal scoping of the EA
and a meaningful socioeconomic
analysis. Many commenters questioned
the use of three separate EAs to disclose
impacts of Order 3, Order 4, and Order
5, stating that the Council on
Environmental Quality (CEQ)
regulations require connected actions to
be evaluated in a single document.
These commenters suggested a single
EIS to address all three rules.
CEQ’s NEPA regulations at 40 CFR
1508.18 identify new or revised agency
rules and regulations as an example of
a Federal action. Drafting new agency
regulations that ‘‘are of an
administrative . . . technical, or
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procedural nature’’ is categorically
excluded from NEPA review pursuant to
43 CFR 46.210(i). The BLM nevertheless
chose to complete a more robust level of
NEPA documentation in the form of an
EA. By preparing a separate EA for new
subpart 3173, 3174, and 3175
regulations, the BLM was able to
disclose the potential environmental
effects of the Federal agency decisions
on each of the regulations. Clearly, the
BLM’s level of analysis was more
thorough than the categorical exclusion
documentation required by NEPA.
Additionally, a thorough socioeconomic
analysis was completed in the BLM’s
regulatory impact analysis of the
proposed rule, which was referenced in
the EA.
Other commenters stated the BLM did
not adequately address potential surface
impacts to private land, minimized
environmental surface impacts, did not
address a reasonable range of
alternatives, and did not adequately
describe the Affected Environment. The
BLM anticipates that in the majority of
cases, operators will use existing surface
disturbances such as existing well pad
locations in connection with activities
undertaken in compliance with the final
rule, which will minimize new surface
construction and surface impacts. Any
new facilities will likely be constructed
on a lease, relocated to an existing
facility, or retrofitted to an existing
facility. Similarly, the codification of
BLM regulations does not hinder or
prevent development of private
minerals. The likelihood of impacts to
private surface is low. In the rare
instance that new pipelines or other
facilities must be developed on private
surface to comply with this rule, BLM
authorization for activities on split
estate would include site-specific NEPA
documentation, with appropriate
project-level mitigation. The BLM’s
obligation under NEPA is to analyze
alternatives that would meet the
Bureau’s purpose and need and allow
for a reasoned choice to be made. As
described in the EA, a number of
alternatives were considered, but
eliminated from detailed study because
they did not meet the purpose and need.
Discussion of the affected environment
should only contain data and analysis
commensurate in detail with the
importance of the impacts, which the
BLM anticipates to be minimal.
The EA, FONSI, and DR were updated
to address these comments, but the
updates did not change the BLM’s
overall analysis of the potential
environmental impacts of the rule.
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Executive Order 13211, Actions
Concerning Regulations That
Significantly Affect Energy Supply,
Distribution, or Use
Although this rule amends the BLM’s
oil production regulations, it will not
have a substantial direct effect on the
nation’s energy supply, distribution, or
use, including a shortfall in supply or
price increases. Changes in this rule
strengthen the BLM’s production
accountability requirements for
operators holding Federal and Indian oil
leases. As discussed previously, among
other things, this rule establishes
objective measurement performance
standards, updates recordkeeping
requirements, and establishes uniform
national requirements for operators who
wish to use CMSs or ATG systems. As
explained in detail in the BLM’s
regulatory impact analysis, all of these
changes will increase the regulated
community’s annual costs by about $3.9
million, or about $1,055 per entity per
year.
The BLM expects that the rule will
not result in a net change in the quantity
of oil that is produced from Federal and
Indian leases.
Authors
The principal authors of this final rule
are Mike McLaren, Petroleum Engineer,
BLM Pinedale Field Office; Tom
Zelenka, Petroleum Engineer, BLM New
Mexico State Office; Chris DeVault, I&E
Coordinator, BLM Montana State Office;
Jeff Prude, Petroleum Engineer, BLM
Bakersfield Field Office; and Frank
Sanders, Petroleum Engineer, BLM
Worland Field Office. The team was
assisted by Faith Bremner, Jean
Sonneman and Ian Senio, Office of
Regulatory Affairs, BLM Washington
Office; Michael Ford, Economist, BLM
Washington Office; Barbara Sterling,
Natural Resource Specialist, BLM
Colorado State Office; Bryce Barlan,
Senior Policy Analyst, BLM,
Washington Office; Michael Wade, BLM
Washington Office; Rich Estabrook,
BLM Washington Office; Dylan Fuge,
Counselor to the Director, BLM
Washington Office; Christopher
Rhymes, Attorney Advisor, Office of the
Solicitor, Department of the Interior;
and Geoffrey Heath (now retired).
Fmt 4701
Sfmt 4700
Administrative practice and
procedure, Government contracts,
Indians-lands, Mineral royalties, Oil and
gas exploration, Penalties, Public
lands—mineral resources, Reporting
and recordkeeping requirements.
43 CFR Part 3170
Administrative practice and
procedure, Immediate assessments,
Incorporation by reference, Indianslands, Mineral royalties, Oil and gas
measurement, Public lands—mineral
resources.
Dated: October 6, 2016.
Janice M. Schneider,
Assistant Secretary, Land and Minerals
Management.
43 CFR Chapter II
For the reasons set out in the
preamble, the Bureau of Land
Management is amending 43 CFR parts
3160 and 3170 as follows:
PART 3160—ONSHORE OIL AND GAS
OPERATIONS
1. The authority citation for part 3160
continues to read as follows:
In developing this rule, the BLM did
not conduct or use a study, experiment,
or survey requiring peer review under
the Information Quality Act (Pub. L.
106–554, Appendix C Title IV, 515, 114
Stat. 2763A–153).
Frm 00044
43 CFR Part 3160
■
Information Quality Act
PO 00000
List of Subjects
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 § 3162.7–2 to read as
follows:
■
§ 3162.7–2
Measurement of oil.
All oil removed or sold from a lease,
communitized area, or unit participating
area must be measured under subpart
3174 of this title. All measurement must
be on the lease, communitized area, or
unit from which the oil originated and
must not be commingled with oil
originating from other sources, unless
approved by the authorized officer
under the provisions of subpart 3173 of
this title.
§ 3164.1
[Amended]
3. Amend § 3164.1(b) by removing the
fourth entry in the table, Order No. 4,
Measurement of Oil.
■
PART 3170—ONSHORE OIL AND GAS
PRODUCTION
4. The authority citation for part 3170
continues to read as follows:
■
Authority: 25 U.S.C. 396d and 2107; 30
U.S.C. 189, 306, 359, and 1751; and 43 U.S.C.
1732(b), 1733, and 1740.
5. Add subpart 3174 to part 3170, to
read as follows:
■
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Subpart 3174—Measurement of Oil
Sec.
3174.1 Definitions and acronyms.
3174.2 General requirements.
3174.3 Incorporation by reference (IBR).
3174.4 Specific measurement performance
requirements.
3174.5 Oil measurement by tank gauging—
general requirements.
3174.6 Oil measurement by tank gauging—
procedures.
3174.7 LACT systems—general
requirements.
3174.8 LACT systems—components and
operating requirements.
3174.9 Coriolis measurement systems
(CMS)—general requirements and
components.
3174.10 Coriolis meter for LACT and CMS
measurement applications—operating
requirements.
3174.11 Meter-proving requirements.
3174.12 Measurement tickets.
3174.13 Oil measurement by other
methods.
3174.14 Determination of oil volumes by
methods other than measurement.
3174.15 Immediate assessments.
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§ 3174.1
Definitions and acronyms.
(a) As used in this subpart, the term:
Barrel (bbl) means 42 standard United
States gallons.
Base pressure means 14.696 pounds
per square inch, absolute (psia).
Base temperature means 60 °F.
Certificate of calibration means a
document stating the base prover
volume and other physical data required
for the calibration of flow meters.
Composite meter factor means a meter
factor corrected from normal operating
pressure to base pressure. The
composite meter factor is determined by
proving operations where the pressure
is considered constant during the
measurement period between provings.
Configuration log means the list of
constant flow parameters, calculation
methods, alarm set points, and other
values that are programmed into the
flow computer in a CMS.
Coriolis meter means a device which
by means of the interaction between a
flowing fluid and oscillation of tube(s)
infers a mass flow rate. The meter also
infers the density by measuring the
natural frequency of the oscillating
tubes. The Coriolis meter consists of
sensors and a transmitter, which convert
the output from the sensors to signals
representing volume and density.
Coriolis measurement system (CMS)
means a metering system using a
Coriolis meter in conjunction with a
tertiary device, pressure transducer, and
temperature transducer in order to
derive and report gross standard oil
volume. A CMS system provides realtime, on-line measurement of oil.
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Displacement prover means a prover
consisting of a pipe or pipes with
known capacities, a displacement
device, and detector switches, which
sense when the displacement device has
reached the beginning and ending
points of the calibrated section of pipe.
Displacement provers can be portable or
fixed.
Dynamic meter factor means a kinetic
meter factor derived by linear
interpolation or polynomial fit, used for
conditions where a series of meter
factors have been determined over a
range of normal operating conditions.
Event log means an electronic record
of all exceptions and changes to the
flow parameters contained within the
configuration log that occur and have an
impact on a quantity transaction record.
Gross standard volume means a
volume of oil corrected to base pressure
and temperature.
Indicated volume means the
uncorrected volume indicated by the
meter in a lease automatic custody
transfer system or the Coriolis meter in
a CMS. For a positive displacement
meter, the indicated volume is
represented by the non-resettable
totalizer on the meter head. For Coriolis
meters, the indicated volume is the
uncorrected (without the meter factor)
mass of liquid divided by the density.
Innage gauging means the level of a
liquid in a tank measured from the
datum plate or tank bottom to the
surface of the liquid.
Lease automatic custody transfer
(LACT) system means a system of
components designed to provide for the
unattended custody transfer of oil
produced from a lease(s), unit PA(s), or
CA(s) to the transporting carrier while
providing a proper and accurate means
for determining the net standard volume
and quality, and fail-safe and tamperproof operations.
Master meter prover means a positive
displacement meter or Coriolis meter
that is selected, maintained, and
operated to serve as the reference device
for the proving of another meter. A
comparison of the master meter to the
Facility Measurement Point (FMP) line
meter output is the basis of the mastermeter method.
Meter factor means a ratio obtained by
dividing the measured volume of liquid
that passed through a prover or master
meter during the proving by the
measured volume of liquid that passed
through the line meter during the
proving, corrected to base pressure and
temperature.
Net standard volume means the gross
standard volume corrected for quantities
of non-merchantable substances such as
sediment and water.
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81505
Outage gauging means the distance
from the surface of the liquid in a tank
to the reference gauge point of the tank.
Positive displacement meter means a
meter that registers the volume passing
through the meter using a system which
constantly and mechanically isolates the
flowing liquid into segments of known
volume.
Quantity transaction record (QTR)
means a report generated by CMS
equipment that summarizes the daily
and hourly gross standard volume
calculated by the flow computer and the
average or totals of the dynamic data
that is used in the calculation of gross
standard volume.
Tertiary device means, for a CMS, the
flow computer and associated memory,
calculation, and display functions.
Transducer means an electronic
device that converts a physical property,
such as pressure, temperature, or
electrical resistance, into an electrical
output signal that varies proportionally
with the magnitude of the physical
property. Typical output signals are in
the form of electrical potential (volts),
current (milliamps), or digital pressure
or temperature readings. The term
transducer includes devices commonly
referred to as transmitters.
Vapor tight means capable of holding
pressure differential only slightly higher
than that of installed pressure-relieving
or vapor recovery devices.
(b) As used in this subpart, the
following acronyms carry the meaning
prescribed:
API means American Petroleum
Institute.
CA has the meaning set forth in
§ 3170.3 of this part.
COA has the meaning set forth in
§ 3170.3 of this part.
CPL means correction for the effect of
pressure on a liquid.
CTL means correction for the effect of
temperature on a liquid.
NIST means National Institute of
Standards and Technology.
PA has the meaning set forth in
§ 3170.3 of this part.
PMT means Production Measurement
Team.
PSIA means pounds per square inch,
absolute.
S&W means sediment and water.
§ 3174.2
General requirements.
(a) Oil may be stored only in tanks
that meet the requirements of
§ 3174.5(b) of this subpart.
(b) Oil must be measured on the lease,
unit PA, or CA, unless approval for offlease measurement is obtained under
§§ 3173.22 and 3173.23 of this part.
(c) Oil produced from a lease, unit
PA, or CA may not be commingled with
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production from other leases, unit PAs,
or CAs or non-Federal properties before
the point of royalty measurement,
unless prior approval is obtained under
§§ 3173.14 and 3173.15 of this part.
(d) An operator must obtain a BLMapproved FMP number under
§§ 3173.12 and 3173.13 of this part for
each oil measurement facility where the
measurement affects the calculation of
the volume or quality of production on
which royalty is owed (i.e., oil tank used
for tank gauging, LACT system, CMS, or
other approved metering device), except
as provided in paragraph (h) of this
section.
(e) Except as provided in paragraph
(h) of this section, all equipment used
to measure the volume of oil for royalty
purposes installed after January 17,
2017 must comply with the
requirements of this subpart.
(f) Except as provided in paragraph
(h) of this section, measuring
procedures and equipment used to
measure oil for royalty purposes, that is
in use on January 17, 2017, must
comply with the requirements of this
subpart on or before the date the
operator is required to apply for an FMP
number under 3173.12(e) of this part.
Prior to that date, measuring procedures
and equipment used to measure oil for
royalty purposes, that is in use on
January 17, 2017 must continue to
comply with the requirements of
Onshore Oil and Gas Order No. 4,
Measurement of oil, § 3164.1(b) as
contained in 43 CFR part 3160, (revised
October 1, 2016), and any COAs and
written orders applicable to that
equipment.
(g) The requirement to follow the
approved equipment lists identified in
§§ 3174.6(b)(5)(ii)(A), 3174.6(b)(5)(iii),
3174.8(a)(1), and 3174.9(a) does not
apply until January 17, 2019. The
operator or manufacturer must obtain
approval of a particular make, model,
and size by submitting the test data used
to develop performance specifications to
the PMT to review.
(h) Meters used for allocation under a
commingling and allocation approval
under § 3173.14 are not required to meet
the requirements of this subpart.
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§ 3174.3
Incorporation by reference (IBR).
(a) Certain material specified in this
section is incorporated by reference into
this part with the approval of the
Director of the Federal Register under 5
U.S.C. 552(a) and 1 CFR part 51.
Operators must comply with all
incorporated standards and material, as
they are listed in this section. To
enforce any edition other than that
specified in this section, the BLM must
publish a rule in the Federal Register,
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and the material must be reasonably
available to the public. All approved
material is available for inspection at
the Bureau of Land Management,
Division of Fluid Minerals, 20 M Street
SE., Washington, DC 20003, 202–912–
7162; at all BLM offices with
jurisdiction over oil and gas activities;
and is available from the sources listed
below. It is also available for inspection
at the National Archives and Records
Administration (NARA). For
information on the availability of this
material at NARA, call 202–741–6030 or
go to https://www.archives.gov/federal_
register/code_of_federal_regulations/
ibr_locations.html.
(b) American Petroleum Institute
(API), 1220 L Street NW., Washington,
DC 20005; telephone 202–682–8000;
API also offers free, read-only access to
some of the material at 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 (‘‘API 2.2A’’), IBR
approved for § 3174.5(c).
(2) API MPMS Chapter 2—Tank
Calibration, Section 2.2B, Calibration of
Upright Cylindrical Tanks Using the
Optical Reference Line Method; First
Edition, March 1989, Reaffirmed
January 2013 (‘‘API 2.2B’’), IBR
approved for § 3174.5(c).
(3) API MPMS Chapter 2—Tank
Calibration, Section 2C, Calibration of
Upright Cylindrical Tanks Using the
Optical-triangulation Method; First
Edition, January 2002; Reaffirmed May
2008 (‘‘API 2.2C’’), IBR approved for
§ 3174.5(c).
(4) API MPMS Chapter 3, Section 1A,
Standard Practice for the Manual
Gauging of Petroleum and Petroleum
Products; Third Edition, August 2013
(‘‘API 3.1A’’), IBR approved for
§§ 3174.5(b), 3174.6(b).
(5) API MPMS Chapter 3—Tank
Gauging, Section 1B, Standard Practice
for Level Measurement of Liquid
Hydrocarbons in Stationary Tanks by
Automatic Tank Gauging; Second
Edition, June 2001; Reaffirmed August
2011 (‘‘API 3.1B’’), IBR approved for
§ 3174.6(b).
(6) API MPMS Chapter 3—Tank
Gauging, Section 6, Measurement of
Liquid Hydrocarbons by Hybrid Tank
Measurement Systems; First Edition,
February 2001; Errata September 2005;
Reaffirmed October 2011 (‘‘API 3.6’’),
IBR approved for § 3174.6(b).
(7) API MPMS Chapter 4—Proving
Systems, Section 1, Introduction; Third
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Edition, February 2005; Reaffirmed June
2014 (‘‘API 4.1’’), IBR approved for
§ 3174.11(c).
(8) API MPMS Chapter 4—Proving
Systems, Section 2, Displacement
Provers; Third Edition, September 2003;
Reaffirmed March 2011, Addendum
February 2015 (‘‘API 4.2’’), IBR
approved for §§ 3174.11(b) and (c).
(9) API MPMS Chapter 4, Section 5,
Master-Meter Provers; Fourth Edition,
June 2016, (‘‘API 4.5’’), IBR approved for
§ 3174.11(b).
(10) API MPMS Chapter 4—Proving
Systems, Section 6, Pulse Interpolation;
Second Edition, May 1999; Errata April
2007; Reaffirmed October 2013 (‘‘API
4.6’’), IBR approved for § 3174.11(c).
(11) API MPMS Chapter 4, Section 8,
Operation of Proving Systems; Second
Edition, September 2013 (‘‘API 4.8’’),
IBR approved for § 3174.11(b).
(12) API MPMS Chapter 4—Proving
Systems, Section 9, Methods of
Calibration for Displacement and
Volumetric Tank Provers, Part 2,
Determination of the Volume of
Displacement and Tank Provers by the
Waterdraw Method of Calibration; First
Edition, December 2005; Reaffirmed
July 2015 (‘‘API 4.9.2’’), IBR approved
for § 3174.11(b).
(13) API MPMS Chapter 5—Metering,
Section 6, Measurement of Liquid
Hydrocarbons by Coriolis Meters; First
Edition, October 2002; Reaffirmed
November 2013 (‘‘API 5.6’’), IBR
approved for §§ 3174.9(e), 3174.11(h)
and (i).
(14) API MPMS Chapter 6—Metering
Assemblies, Section 1, Lease Automatic
Custody Transfer (LACT) Systems;
Second Edition, May 1991; Reaffirmed
May 2012 (‘‘API 6.1’’), IBR approved for
§ 3174.8(a) and (b).
(15) API MPMS Chapter 7,
Temperature Determination; First
Edition, June 2001, Reaffirmed February
2012 (‘‘API 7’’), IBR approved for
§§ 3174.6(b), 3174.8(b).
(16) API MPMS Chapter 7.3,
Temperature Determination—Fixed
Automatic Tank Temperature Systems;
Second Edition, October 2011 (‘‘API
7.3’’), IBR approved for § 3174.6(b).
(17) API MPMS Chapter 8, Section 1,
Standard Practice for Manual Sampling
of Petroleum and Petroleum Products;
Fourth Edition, October 2013 (‘‘API
8.1’’), IBR approved for §§ 3174.6(b),
3174.11(h).
(18) API MPMS Chapter 8, Section 2,
Standard Practice for Automatic
Sampling of Petroleum and Petroleum
Products; Third Edition, October 2015
(‘‘API 8.2’’), IBR approved for
§§ 3174.6(b), 3174.8(b), 3174.11(h).
(19) API MPMS Chapter 8—Sampling,
Section 3, Standard Practice for Mixing
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and Handling of Liquid Samples of
Petroleum and Petroleum Products;
First Edition, October 1995; Errata
March 1996; Reaffirmed, March 2010
(‘‘API 8.3’’), IBR approved for
§§ 3174.8(b), 3174.11(h).
(20) API MPMS Chapter 9, Section 1,
Standard Test Method for Density,
Relative Density, or API Gravity of
Crude Petroleum and Liquid Petroleum
Products by Hydrometer Method; Third
Edition, December 2012 (‘‘API 9.1’’), IBR
approved for §§ 3174.6(b), 3174.8(b).
(21) API MPMS Chapter 9, Section 2,
Standard Test Method for Density or
Relative Density of Light Hydrocarbons
by Pressure Hydrometer; Third Edition,
December 2012 (‘‘API 9.2’’), IBR
approved for §§ 3174.6(b), 3174.8(b).
(22) API MPMS Chapter 9, Section 3,
Standard Test Method for Density,
Relative Density, and API Gravity of
Crude Petroleum and Liquid Petroleum
Products by Thermohydrometer
Method; Third Edition, December 2012
(‘‘API 9.3’’), IBR approved for
§§ 3174.6(b), 3174.8(b).
(23) API MPMS Chapter 10, Section 4,
Determination of Water and/or
Sediment in Crude Oil by the Centrifuge
Method (Field Procedure); Fourth
Edition, October 2013; Errata March
2015 (‘‘API 10.4’’), IBR approved for
§§ 3174.6(b), 3174.8(b).
(24) API MPMS Chapter 11—Physical
Properties Data, Section 1, Temperature
and Pressure Volume Correction Factors
for Generalized Crude Oils, Refined
Products and Lubricating Oils; May
2004, Addendum 1 September 2007;
Reaffirmed August 2012 (‘‘API 11.1’’),
IBR approved for §§ 3174.9(f),
3174.12(a).
(25) API MPMS Chapter 12—
Calculation of Petroleum Quantities,
Section 2, Calculation of Petroleum
Quantities Using Dynamic Measurement
Methods and Volumetric Correction
Factors, Part 1, Introduction; Second
Edition, May 1995; Reaffirmed March
2014 (‘‘API 12.2.1’’), IBR approved for
§§ 3174.8(b), 3174.9(g).
(26) API MPMS Chapter 12—
Calculation of Petroleum Quantities,
Section 2, Calculation of Petroleum
Quantities Using Dynamic Measurement
Methods and Volumetric Correction
Factors, Part 2, Measurement Tickets;
Third Edition, June 2003; Reaffirmed
September 2010 (‘‘API 12.2.2’’), IBR
approved for §§ 3174.8(b), 3174.9(g).
(27) API MPMS Chapter 12—
Calculation of Petroleum Quantities,
Section 2, Calculation of Petroleum
Quantities Using Dynamic Measurement
Methods and Volumetric Correction
Factors, Part 3, Proving Report; First
Edition, October 1998; Reaffirmed
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March 2009 (‘‘API 12.2.3’’), IBR
approved for § 3174.11(c) and (i).
(28) API MPMS Chapter 12—
Calculation of Petroleum Quantities,
Section 2, Calculation of Petroleum
Quantities Using Dynamic Measurement
Methods and Volumetric Correction
Factors, Part 4, Calculation of Base
Prover Volumes by the Waterdraw
Method; First Edition, December 1997;
Reaffirmed March 2009; Errata July 2009
(‘‘API 12.2.4’’), IBR approved for
§ 3174.11(b).
(29) API MPMS Chapter 13—
Statistical Aspects of Measuring and
Sampling, Section 1, Statistical
Concepts and Procedures in
Measurements; First Edition, June 1985
Reaffirmed February 2011; Errata July
2013 (‘‘API 13.1’’), IBR approved for
§ 3174.4(a).
(30) API MPMS Chapter 13, Section 3,
Measurement Uncertainty; First Edition,
May, 2016 (‘‘API 13.3’’), IBR approved
for § 3174.4(a).
(31) API MPMS Chapter 14, Section 3,
Orifice Metering of Natural Gas and
Other Related Hydrocarbon Fluids—
Concentric, Square-edged Orifice
Meters, Part 1, General Equations and
Uncertainty Guidelines; Fourth Edition,
September 2012; Errata July 2013 (‘‘API
14.3.1’’), IBR approved for § 3174.4(a).
(32) API MPMS Chapter 18—Custody
Transfer, Section 1, Measurement
Procedures for Crude Oil Gathered From
Small Tanks by Truck; Second Edition,
April 1997; Reaffirmed February 2012
(‘‘API 18.1’’), IBR approved for
§ 3174.6(b).
(33) API MPMS Chapter 18, Section 2,
Custody Transfer of Crude Oil from
Lease Tanks Using Alternative
Measurement Methods, First Edition,
July 2016 (‘‘API 18.2’’), IBR approved
for § 3174.6(b).
(34) API MPMS Chapter 21—Flow
Measurement Using Electronic Metering
Systems, Section 2, Electronic Liquid
Volume Measurement Using Positive
Displacement and Turbine Meters; First
Edition, June 1998; Reaffirmed August
2011 (‘‘API 21.2’’), IBR approved for
§§ 3174.8(b), 3174.9(f), 3174.10(f).
(35) API Recommended Practice (RP)
12R1, Setting, Maintenance, Inspection,
Operation and Repair of Tanks in
Production Service; Fifth Edition,
August 1997; Reaffirmed April 2008
(‘‘API RP 12R1’’), IBR approved for
§ 3174.5(b).
(36) API RP 2556, Correction Gauge
Tables For Incrustation; Second Edition,
August 1993; Reaffirmed November
2013 (‘‘API RP 2556’’), IBR approved for
§ 3174.5(c).
Note 1 to § 3174.3(b): You may also be able
to purchase these standards from the
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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/.
§ 3174.4 Specific measurement
performance requirements.
(a) Volume measurement uncertainty
levels. (1) The FMP must achieve the
following overall uncertainty levels as
calculated in accordance with statistical
concepts described in API 13.1, the
methodologies in API 13.3, and the
quadrature sum (square root of the sum
of the squares) method described in API
14.3.1, Subsection 12.3 (all incorporated
by reference, see § 3174.3) or other
methods approved under paragraph (d):
TABLE 1 TO § 3174.4—VOLUME
MEASUREMENT UNCERTAINTY LEVELS
If the averaging period
volume (see definition
43 CFR 3170.3) is:
1. Greater than or equal to
30,000 bbl/month.
2. Less than 30,000 bbl/
month.
The overall
volume
measurement
uncertainty
must be within:
±0.50 percent.
±1.50 percent.
(2) Only a BLM State Director may
grant an exception to the uncertainty
levels prescribed in paragraph (a)(1) of
this section, and only upon:
(i) A showing that meeting the
required uncertainly level would
involve extraordinary cost or
unacceptable adverse environmental
effects; and
(ii) Written concurrence of the PMT,
prepared in coordination with the
Deputy Director.
(b) Bias. The measuring equipment
used for volume determinations must
achieve measurement without
statistically significant bias.
(c) Verifiability. All FMP equipment
must be susceptible to independent
verification by the BLM of the accuracy
and validity of all inputs, factors, and
equations that are used to determine
quantity or quality. Verifiability
includes the ability to independently
recalculate volume and quality based on
source records.
(d) Alternative equipment. The PMT
will make a determination under
§ 3174.13 of this subpart regarding
whether proposed alternative
equipment or measurement procedures
meet or exceed the objectives and intent
of this section.
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§ 3174.5 Oil measurement by tank
gauging—general requirements.
(a) Measurement objective. Oil
measurement by tank gauging must
accurately compute the total net
standard volume of oil withdrawn from
a properly calibrated sales tank by
following the activities prescribed in
§ 3174.6 and the requirements of
§ 3174.4 of this subpart to determine the
quantity and quality of oil being
removed.
(b) Oil tank equipment. (1) Each tank
used for oil storage must comply with
the recommended practices listed in
API RP 12R1 (incorporated by reference,
see § 3174.3).
(2) Each oil storage tank must be
connected, maintained, and operated in
compliance with §§ 3173.2, 3173.6, and
3173.7 of this part.
(3) All oil storage tanks, hatches,
connections, and other access points
must be vapor tight. Unless connected
to a vapor recovery or flare system, all
tanks must have a pressure-vacuum
relief valve installed at the highest point
in the vent line or connection with
another tank. All hatches, connections,
and other access points must be
installed and maintained in accordance
with manufacturers’ specifications.
(4) All oil storage tanks must be
clearly identified and have an operatorgenerated number unique to the lease,
unit PA, or CA, stenciled on the tank
and maintained in a legible condition.
(5) Each oil storage tank associated
with an approved FMP that has a tankgauging system must be set and
maintained level.
(6) Each oil storage tank associated
with an approved FMP that has a tankgauging system must be equipped with
a distinct gauging reference point,
consistent with API 3.1A (incorporated
by reference, see § 3174.3). The height of
the reference point must be stamped on
a fixed bench-mark plate or stenciled on
the tank near the gauging hatch, and be
maintained in a legible condition.
(c) Sales tank calibrations. The
operator must accurately calibrate each
oil storage tank associated with an
approved FMP that has a tank-gauging
system using either API 2.2A, API 2.2B,
or API 2.2C; and API RP 2556 (all
incorporated by reference, see § 3174.3).
The operator must:
(1) Determine sales tank capacities by
tank calibration using actual tank
measurements;
(i) The unit volume must be in barrels
(bbl); and
(ii) The incremental height
measurement must match gauging
increments specified in
§ 3174.6(b)(5)(i)(C);
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(2) Recalibrate a sales tank if it is
relocated or repaired, or the capacity is
changed as a result of denting, damage,
installation, removal of interior
components, or other alterations; and
(3) Submit sales tank calibration
charts (tank tables) to the AO within 45
days after calibration. Tank tables may
be in paper or electronic format.
§ 3174.6 Oil measurement by tank
gauging—procedures.
(a) The procedures for oil
measurement by tank gauging must
comply with the requirements outlined
in this section.
(b) The operator must follow the
procedures identified in API 18.1 or API
18.2 (both incorporated by reference, see
§ 3174.3) as further specified in this
paragraph to determine the quality and
quantity of oil measured under field
conditions at an FMP.
(1) Isolate tank. Isolate the tank for at
least 30 minutes to allow contents to
settle before proceeding with tank
gauging operations. The tank isolating
valves must be closed and sealed under
§ 3173.2 of this part.
(2) Determine opening oil
temperature. Determination of the
temperature of oil contained in a sales
tank must comply with paragraphs
(b)(2)(i) through (iii) of this section, API
7, and API 7.3 (both incorporated by
reference, see § 3174.3). Opening
temperature may be determined before,
during, or after sampling.
(i) Glass thermometers must be clean,
be free of fluid separation, have a
minimum graduation of 1.0 °F, and have
an accuracy of ±0.5 °F.
(ii) Electronic thermometers must
have a minimum graduation of 0.1 °F
and have an accuracy of ±0.5 °F.
(iii) Record the temperature to the
nearest 1.0 °F for glass thermometers or
0.1 °F for portable electronic
thermometers.
(3) Take oil samples. Sampling
operations must be conducted prior to
taking the opening gauge unless
automatic sampling methods are being
used. Sampling of oil removed from an
FMP tank must yield a representative
sample of the oil and its physical
properties and must comply with API
8.1 or API 8.2 (both incorporated by
reference, see § 3174.3).
(4) Determine observed oil gravity.
Tests for oil gravity must comply with
paragraphs (b)(4)(i) through (iii) of this
section and API 9.1, API 9.2, or API 9.3
(all incorporated by reference, see
§ 3174.3).
(i) The hydrometer or
thermohydrometer (as applicable) must
be calibrated for an oil gravity range that
includes the observed gravity of the oil
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sample being tested and must be clean,
with a clearly legible oil gravity scale
and with no loose shot weights.
(ii) Allow the temperature to stabilize
for at least 5 minutes prior to reading
the thermometer.
(iii) Read and record the observed API
oil gravity to the nearest 0.1 degree.
Read and record the temperature
reading to the nearest 1.0 °F.
(5) Measure the opening tank fluid
level. Take and record the opening
gauge only after samples have been
taken, unless automatic sampling
methods are being used. Gauging must
comply with either paragraph (b)(5)(i) of
this section, API 3.1A, and API 18.1
(both incorporated by reference, see
§ 3174.3); or paragraph (b)(5)(ii) of this
section, API 3.1B, API 3.6, and API 18.2
(all incorporated by reference, see
§ 3174.3); or paragraph (b)(5)(iii) of this
section for dynamic volume
determination.
(i) For manual gauging, comply with
the requirements of API 3.1A and API
18.1 (both incorporated by reference, see
§ 3174.3) and the following:
(A) The proper bob must be used for
the particular measurement method, i.e.,
either innage gauging or outage gauging;
(B) A gauging tape must be used. The
gauging tape must be made of steel or
corrosion-resistant material with
graduation clearly legible, and must not
be kinked or spliced;
(C) Either obtain two consecutive
identical gauging measurements for any
tank regardless of size, or:
(1) For tanks of 1,000 bbl or less in
capacity, three consecutive
measurements that are within 1/4-inch
of each other and average these three
measurements to the nearest 1⁄4 inch; or
(2) For tanks greater than 1,000 bbl in
capacity, three consecutive
measurements within 1⁄8 inch of each
other, averaging these three
measurements to the nearest 1⁄8 inch.
(D) A suitable product-indicating
paste may be used on the tape to
facilitate the reading. The use of chalk
or talcum powder is prohibited; and
(E) The same tape and bob must be
used for both opening and closing
gauges.
(ii) For automatic tank gauging (ATG),
comply with the requirements of API
3.1B, API 3.6, and API 18.2 (all
incorporated by reference, see § 3174.3)
and the following:
(A) The specific makes and models of
ATG that are identified and described at
www.blm.gov are approved for use;
(B) The ATG must be inspected and
its accuracy verified to within ±1⁄4 inch
in accordance with API 3.1B,
Subsection 9 (incorporated by reference,
see § 3174.3) at least once a month or
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prior to sales, whichever is latest, or any
time at the request of the AO. If the ATG
is found to be out of tolerance, the ATG
must be calibrated prior to sales; and
(C) A log of field verifications must be
maintained and available upon request.
The log must include the following
information: The date of verification;
the as-found manual gauge readings; the
as-found ATG readings; and whether the
ATG was field calibrated. If the ATG
was field calibrated, the as-left manual
gauge readings and as-left ATG readings
must be recorded.
(iii) For dynamic volume
determination under API 18.2,
Subsection 10.1.1, (incorporated by
reference, see § 3174.3), the specific
makes and models of in-line meters that
are identified and described at
www.blm.gov are approved for use.
(6) Determine S&W content. Using the
oil samples obtained pursuant to
paragraph (b)(3) of this section,
determine the S&W content of the oil in
the sales tanks, according to API 10.4
(incorporated by reference, see
§ 3174.3).
(7) Transfer oil. Break the tank load
line valve seal and transfer oil to the
tanker truck. After transfer is complete,
close the tank valve and seal the valve
under §§ 3173.2 and 3173.5 of this part.
(8) Determine closing oil temperature.
Determine the closing oil temperature
using the procedures in paragraph (b)(2)
of this section.
(9) Take closing gauge. Take the
closing tank gauge using the procedures
in paragraph (b)(5) of this section.
(10) Complete measurement ticket.
Following procedures in § 3174.12.
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§ 3174.7 LACT system—general
requirements.
(a) A LACT system must meet the
construction and operation
requirements and minimum standards
of this section, § 3174.8, and § 3174.4.
(b) A LACT system must be proven as
prescribed in § 3174.11 of this subpart.
(c) Measurement tickets must be
completed under § 3174.12(b) of this
subpart.
(d) All components of a LACT system
must be accessible for inspection by the
AO.
(e)(1) The operator must notify the
AO, within 72 hours after discovery, of
any LACT system failures or equipment
malfunctions that may have resulted in
measurement error.
(2) Such system failures or equipment
malfunctions include, but are not
limited to, electrical, meter, and other
failures that affect oil measurement.
(f) Any tests conducted on oil samples
extracted from LACT system samplers
for determination of temperature, oil
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gravity, and S&W content must meet the
requirements and minimum standards
in § 3174.6(b)(2), (4), and (6) of this
subpart.
(g) Automatic temperature
compensators and automatic
temperature and gravity compensators
are prohibited.
§ 3174.8 LACT system—components and
operating requirements.
(a) LACT system components. Each
LACT system must include all of the
equipment listed in API 6.1
(incorporated by reference, see
§ 3174.3), with the following exceptions:
(1) The custody transfer meter must
be a positive displacement meter or a
Coriolis meter. The specific make,
models, and sizes of positive
displacement or Coriolis meter and
associated software that are identified
and described at www.blm.gov are
approved for use.
(2) An electronic temperature
averaging device must be installed.
(3) Meter back pressure must be
applied by a back pressure valve or
other controllable means of applying
back pressure to ensure single-phase
flow.
(b) LACT system operating
requirements. Operation of all LACT
system components must meet the
requirements of API 6.1 (incorporated
by reference, see § 3174.3) and the
following:
(1) Sampling must be conducted
according to API 8.2 and API 8.3 (both
incorporated by reference, see § 3174.3)
and the following:
(i) The sample extractor probe must
be inserted within the center half of the
flowing stream;
(ii) The extractor probe must be
horizontally oriented; and
(iii) The external body of the extractor
probe must be marked with the
direction of the flow.
(2) Any tests conducted on oil
samples extracted from LACT system
samplers for determination of oil gravity
and S&W content must meet the
requirements of either API 9.1, API 9.2,
or API 9.3, and API 10.4 (all
incorporated by reference, see § 3174.3).
(3) The composite sample container
must be emptied and cleaned upon
completion of sample withdrawal.
(4) The positive displacement or
Coriolis meter (see § 3174.10) must be
equipped with a non-resettable totalizer.
The meter must include or allow for the
attachment of a device that generates at
least 8,400 pulses per barrel of
registered volume.
(5) The system must have a pressureindicating device downstream of the
meter, but upstream of meter-proving
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connections. The pressure-indicating
device must be capable of providing
pressure data to calculate the CPL
correction factor.
(6) An electronic temperature
averaging device must be installed,
operated, and maintained as follows:
(i) The temperature sensor must be
placed in compliance with API 7
(incorporated by reference, see
§ 3174.3);
(ii) 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
§ 3174.3);
(iii) The average temperature for the
measurement ticket must be calculated
by the volumetric averaging method
using API 21.2, Subsection 9.2.13.2a
(incorporated by reference, see
§ 3174.3);
(iv) The temperature averaging device
must have a reference accuracy of
±0.5 °F or better, and have a minimum
graduation of 0.1 °F; and
(v) The temperature averaging device
must include a display of instantaneous
temperature and the average
temperature calculated since the
measurement ticket was opened.
(vi) The average temperature
calculated since the measurement ticket
was opened must be used to calculate
the CTL correction factor.
(7) Determination of net standard
volume: Calculate the net standard
volume at the close of each
measurement ticket following the
guidelines in API 12.2.1 and API 12.2.2
(both incorporated by reference, see
§ 3174.3).
§ 3174.9 Coriolis measurement systems
(CMS)—general requirements and
components.
The following Coriolis measurement
systems section is intended for Coriolis
measurement applications independent
of LACT measurement systems.
(a) A CMS must meet the
requirements and minimum standards
of this section, § 3174.4, and § 3174.10.
(b) The specific makes, models, and
sizes of Coriolis meters and associated
software that have been reviewed by the
PMT, as provided in § 3174.13,
approved by the BLM, and identified
and described at www.blm.gov are
approved for use.
(c) A CMS system must be proven at
the frequency and under the
requirements of § 3174.11 of this
subpart.
(d) Measurement tickets must be
completed under § 3174.12(b) of this
subpart.
(e) A CMS at an FMP must be
installed with the components listed in
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API 5.6 (incorporated by reference, see
§ 3174.3). Additional requirements are
as follows:
(1) The pressure transducer must meet
the requirements of § 3174.8(b)(5) of this
subpart.
(2) Temperature determination must
meet the requirements of § 3174.8(b)(6)
of this subpart.
(3) If nonzero S&W content is to be
used in determining net oil volume, the
sampling system must meet the
requirements of § 3174.8(b)(1) through
(3) of this subpart. If no sampling
system is used, or the sampling system
does not meet the requirements of
§ 3174.8(b)(1) through (3) of this
subpart, the S&W content must be
reported as zero;
(4) Sufficient back pressure must be
applied to ensure single phase flow
through the meter.
(f) Determination of API oil gravity.
The API oil gravity reported for the
measurement ticket period must be
determined by one of the following
methods:
(1) Determined from a composite
sample taken pursuant to § 3174.8(b)(1)
through (3) of this subpart; or
(2) Calculated from the average
density as measured by the CMS over
the measurement ticket period under
API 21.2, Subsection 9.2.13.2a
(incorporated by reference, see
§ 3174.3). Density must be corrected to
base temperature and pressure using
API 11.1 (incorporated by reference, see
§ 3174.3).
(g) Determination of net standard
volume. Calculate the net standard
volume at the close of each
measurement ticket following the
guidelines in API 12.2.1 and API 12.2.2
(both incorporated by reference, see
§ 3174.3).
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§ 3174.10 Coriolis meter for LACT and
CMS measurement applications—operating
requirements.
(a) Minimum electronic pulse level.
The Coriolis meter must register the
volume of oil passing through the meter
as determined by a system that
constantly emits electronic pulse signals
representing the indicated volume
measured. The pulse per unit volume
must be set at a minimum of 8,400
pulses per barrel.
(b) Meter specifications. (1) The
Coriolis meter specifications must
identify the make and model of the
Coriolis meter to which they apply and
must include the following:
(i) The reference accuracy for both
mass flow rate and density, stated in
either percent of reading, percent of full
scale, or units of measure;
(ii) The effect of changes in
temperature and pressure on both mass
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flow and fluid density readings, and the
effect of flow rate on density readings.
These specifications must be stated in
percent of reading, percent of full scale,
or units of measure over a stated amount
of change in temperature, pressure, or
flow rate (e.g., ‘‘±0.1 percent of reading
per 20 psi’’);
(iii) The stability of the zero reading
for volumetric flow rate. The
specifications must be stated in percent
of reading, percent of full scale, or units
of measure;
(iv) Design limits for flow rate and
pressure; and
(v) Pressure drop through the meter as
a function of flow rate and fluid
viscosity.
(2) Submission of meter
specifications: The operator must
submit Coriolis meter specifications to
the BLM upon request.
(c) Non-resettable totalizer. The
Coriolis meter must have a nonresettable internal totalizer for indicated
volume.
(d) Verification of meter zero value
using the manufacturer’s specifications.
If the indicated flow rate is within the
manufacturer’s specifications for zero
stability, no adjustments are required. If
the indicated flow rate is outside the
manufacturer’s specification for zero
stability, the meter’s zero reading must
be adjusted. After the meter’s zero has
been adjusted, the meter must be proven
required by § 3174.11. A copy of the
zero value verification procedure must
be made available to the AO upon
request.
(e) Required on-site information. (1)
The Coriolis meter display must be
readable without using data collection
units, laptop computers, or any special
equipment, and must be on-site and
accessible to the AO.
(2) For each Coriolis meter, the
following values and corresponding
units of measurement must be
displayed:
(i) The instantaneous density of liquid
(pounds/bbl, pounds/gal, or degrees
API);
(ii) The instantaneous indicated
volumetric flow rate through the meter
(bbl/day);
(iii) The meter factor;
(iv) The instantaneous pressure (psi);
(v) The instantaneous temperature
(°F);
(vi) The cumulative gross standard
volume through the meter (nonresettable totalizer) (bbl); and
(vii) The previous day’s gross
standard volume through the meter
(bbl).
(3) The following information must be
correct, be maintained in a legible
condition, and be accessible to the AO
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at the FMP without the use of data
collection equipment, laptop computers,
or any special equipment:
(i) The make, model, and size of each
sensor; and
(ii) The make, range, calibrated span,
and model of the pressure and
temperature transducer used to
determine gross standard volume.
(4) A log must be maintained of all
meter factors, zero verifications, and
zero adjustments. For zero adjustments,
the log must include the zero value
before adjustment and the zero value
after adjustment. The log must be made
available upon request.
(f) Audit trail requirements. The
information specified in paragraphs
(f)(1) through (4) of this section must be
recorded and retained under the
recordkeeping requirements of § 3170.7
of this part. Audit trail requirements
must follow API 21.2, Subsection 10
(incorporated by reference, see
§ 3174.3). All data must be available and
submitted to the BLM upon request.
(1) Quantity transaction record (QTR).
Follow the requirements for a
measurement ticket in § 3174.12(b) of
this subpart.
(2) Configuration log. The
configuration log must comply with the
requirements of API 21.2, Subsection
10.2 (incorporated by reference, see
§ 3174.3). The configuration log must
contain and identify all constant flow
parameters used in generating the QTR.
(3) Event log. The event log must
comply with the requirements of API
21.2, Subsection 10.6 (incorporated by
reference, see § 3174.3). In addition, the
event log must be of sufficient capacity
to record all events such that the
operator can retain the information
under the recordkeeping requirements
of § 3170.7 of this part.
(4) Alarm log The type and duration
of any of the following alarm conditions
must be recorded:
(i) Density deviations from acceptable
parameters; and
(ii) Instances in which the flow rate
exceeded the manufacturer’s maximum
recommended flow rate or was below
the manufacturer’s minimum
recommended flow rate.
(g) Data protection. Each Coriolis
meter must have installed and
maintained in an operable condition a
backup power supply or a nonvolatile
memory capable of retaining all data in
the unit’s memory to ensure that the
audit trail information required under
paragraph (f) of this section is protected.
§ 3174.11
Meter-proving requirements.
(a) Applicability. This section
specifies the minimum requirements for
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conducting volumetric meter proving
for all FMP meters.
(b) Meter prover. Acceptable provers
are positive displacement master
meters, Coriolis master meters, and
displacement provers. The operator
must ensure that the meter prover used
to determine the meter factor has a valid
certificate of calibration on site and
available for review by the AO. The
certificate must show that the prover,
identified by serial number assigned to
and inscribed on the prover, was
calibrated as follows:
(1) Master meters must have a meter
factor within 0.9900 to 1.0100
determined by a minimum of five
consecutive prover runs within 0.0005
(0.05 percent repeatability) as described
in API 4.5, Subsection 6.5 (incorporated
by reference, see § 3174.3). The master
meter must not be mechanically
compensated for oil gravity or
temperature; its readout must indicate
units of volume without corrections.
The meter factor must be documented
on the calibration certificate and must
be calibrated at least once every 12
months. New master meters must be
calibrated immediately and recalibrated
in three months. Master meters that
have undergone mechanical repairs,
alterations, or changes that affect the
calibration must be calibrated
immediately upon completion of this
work and calibrated again 3 months
after this date under API 4.5, API 4.8,
Subsection 10.2, and API 4.8, Annex B
(all incorporated by reference, see
§ 3174.3).
(2) Displacement provers must meet
the requirements of API 4.2
(incorporated by reference, see § 3174.3)
and be calibrated using the water-draw
method under API 4.9.2 (incorporated
by reference, see § 3174.3), at the
calibration frequencies specified in API
4.8, Subsection 10.1(b) (incorporated by
reference, see § 3174.3).
(3) The base prover volume of a
displacement prover must be calculated
under API 12.2.4 (incorporated by
reference, see § 3174.3).
(4) Displacement provers must be
sized to obtain a displacer velocity
through the prover that is within the
appropriate range during proving under
API 4.2, Subsection 4.3.4.2, Minimum
Displacer Velocities and API 4.2,
Subsection 4.3.4.1, Maximum Displacer
Velocities (incorporated by reference,
see § 3174.3).
(5) Fluid velocity is calculated using
API 4.2, Subsection 4.3.4.3, Equation 12
(incorporated by reference, see
§ 3174.3).
(c) Meter proving runs. Meter proving
must follow the applicable section(s) of
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API 4.1, Proving Systems (incorporated
by reference, see § 3174.3).
(1) Meter proving must be performed
under normal operating fluid pressure,
fluid temperature, and fluid type and
composition, as follows:
(i) The oil flow rate through the LACT
or CMS during proving must be within
10 percent of the normal flow rate;
(ii) The absolute pressure as measured
by the LACT or CMS during proving
must be within 10 percent of the normal
operating absolute pressure;
(iii) The temperature as measured by
the LACT or CMS during the proving
must be within 10 °F of the normal
operating temperature; and
(iv) The gravity of the oil during
proving must be within 5° API of the
normal oil gravity.
(v) If the normal flow rate, pressure,
temperature, or oil gravity vary by more
than the limits defined in paragraphs
(c)(i) through (c)(iv) of this section,
meter provings must be conducted, at a
minimum, under the three following
conditions: At the lower limit of normal
operating conditions, at the upper limit
of normal operation conditions, and at
the midpoint of normal operating
conditions.
(2) If each proving run is not of
sufficient volume to generate at least
10,000 pulses, as specified by API 4.2,
Subsection 4.3.2 (incorporated by
reference, see § 3174.3), from the
positive displacement meter or the
Coriolis meter, then pulse interpolation
must be used in accordance with API
4.6 (incorporated by reference, see
§ 3174.3).
(3) Proving runs must be made until
the calculated meter factor or meter
generated pulses from five consecutive
runs match within a tolerance of 0.0005
(0.05 percent) between the highest and
the lowest value in accordance with API
12.2.3, Subsection 9 (incorporated by
reference, see § 3174.3).
(4) The new meter factor is the
arithmetic average of the meter
generated pulses or intermediate meter
factors calculated from the five
consecutive runs in accordance with
API 12.2.3, Subsection 9 (incorporated
by reference, see § 3174.3).
(5) Meter factor computations must
follow the sequence described in API
12.2.3 (incorporated by reference, see
§ 3174.3).
(6) If multiple meters factors are
determined over a range of normal
operating conditions, then:
(i) If all the meter factors determined
over a range of conditions fall within
0.0020 of each other, then a single meter
factor may be calculated for that range
as the arithmetic average of all the meter
factors within that range. The full range
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of normal operating conditions may be
divided into segments such that all the
meter factors within each segment fall
within a range of 0.0020. In this case, a
single meter factor for each segment
may be calculated as the arithmetic
average of the meter factors within that
segment; or
(ii) The metering system may apply a
dynamic meter factor derived (using,
e.g., linear interpolation, polynomial fit,
etc.) from the series of meter factors
determined over the range of normal
operating conditions, so long as no two
neighboring meter factors differ by more
than 0.0020.
(7) The meter factor must be at least
0.9900 and no more than 1.0100.
(8) The initial meter factor for a new
or repaired meter must be at least 0.9950
and no more than 1.0050.
(9) For positive displacement meters,
the back pressure valve may be adjusted
after proving only within the normal
operating fluid flow rate and fluid
pressure as described in paragraph (c)(1)
of this section. If the back pressure valve
is adjusted after proving, the operator
must document the as left fluid flow
rate and fluid pressure on the proving
report.
(10) If a composite meter factor is
calculated, the CPL value must be
calculated from the pressure setting of
the back pressure valve or the normal
operating pressure at the meter.
Composite meter factors must not be
used with a Coriolis meter.
(d) Minimum proving frequency. The
operator must prove any FMP meter
before removal or sales of production
after any of the following events:
(1) Initial meter installation;
(2) Every 3 months (quarterly) after
the last proving, or each time the
registered volume flowing through the
meter, as measured on the nonresettable totalizer from the last proving,
increases by 75,000 bbl, whichever
comes first, but no more frequently than
monthly;
(3) Meter zeroing (Coriolis meter);
(4) Modification of mounting
conditions;
(5) A change in fluid temperature that
exceeds the transducer’s calibrated
span;
(6) A change in pressure, density, or
flow rate that exceeds the operating
proving limits;
(7) The mechanical or electrical
components of the meter have been
changed, repaired, or removed;
(8) Internal calibration factors have
been changed or reprogrammed; or
(9) At the request of the AO.
(e) Excessive meter factor deviation.
(1) If the difference between meter
factors established in two successive
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provings exceeds ±0.0025, the meter
must be immediately removed from
service, checked for damage or wear,
adjusted or repaired, and reproved
before returning the meter to service.
(2) The arithmetic average of the two
successive meter factors must be
applied to the production measured
through the meter between the date of
the previous meter proving and the date
of the most recent meter proving.
(3) The proving report submitted
under paragraph (i) of this section must
clearly show the most recent meter
factor and describe all subsequent
repairs and adjustments.
(f) Verification of the temperature
transducer. As part of each required
meter proving and upon replacement,
the temperature averager for a LACT
system and the temperature transducer
used in conjunction with a CMS must
be verified against a known standard
according to the following:
(1) The temperature averager or
temperature transducer must be
compared with a test thermometer
traceable to NIST and with a stated
accuracy of ±0.25 °F or better.
(2) The temperature reading displayed
on the temperature averager or
temperature transducer must be
compared with the reading of the test
thermometer using one of the following
methods:
(i) The test thermometer must be
placed in a test thermometer well
located not more than 12″ from the
probe of the temperature averager or
temperature transducer; or
(ii) Both the test thermometer and
probe of the temperature averager or
temperature transducer must be placed
in an insulated water bath. The water
bath temperature must be within 20 °F
of the normal flowing temperature of the
oil.
(3) The displayed reading of
instantaneous temperature from the
temperature averager or the temperature
transducer must be compared with the
reading from the test thermometer. If
they differ by more than 0.5 °F, then the
difference in temperatures must be
noted on the meter proving report and:
(i) The temperature averager or
temperature transducer must be
adjusted to match the reading of the test
thermometer; or
(ii) The temperature averager or
temperature transducer must be
recalibrated, repaired, or replaced.
(g) Verification of the pressure
transducer (if applicable). (1) As part of
each required meter proving and upon
replacement, the pressure transducer
must be compared with a test pressure
device (dead weight or pressure gauge)
traceable to NIST and with a stated
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maximum uncertainty of no more than
one-half of the accuracy required from
the transducer being verified.
(2) The pressure reading displayed on
the pressure transducer must be
compared with the reading of the test
pressure device.
(3) The pressure transducer must be
tested at the following three points:
(i) Zero (atmospheric pressure);
(ii) 100 percent of the calibrated span
of the pressure transducer; and
(iii) A point that represents the
normal flowing pressure through the
Coriolis meter.
(4) If the pressure applied by the test
pressure device and the pressure
displayed on the pressure transducer
vary by more than the required accuracy
of the pressure transducer, the pressure
transducer must be adjusted to read
within the stated accuracy of the test
pressure device.
(h) Density verification (if applicable).
As part of each required meter proving,
if the API gravity of oil is determined
from the average density measured by
the Coriolis meter (rather than from a
composite sample), then during each
proving of the Coriolis meter, the
instantaneous flowing density
determined by the Coriolis meter must
be verified by comparing it with an
independent density measurement as
specified under API 5.6, Subsection
9.1.2.1 (incorporated by reference, see
§ 3174.3). The difference between the
indicated density determined from the
Coriolis meter and the independently
determined density must be within the
specified density reference accuracy
specification of the Coriolis meter.
Sampling must be performed in
accordance with API 8.1, API 8.2, or API
8.3 (incorporated by reference, see
§ 3174.3), as appropriate.
(i) Meter proving reporting
requirements. (1) The operator must
report to the AO all meter-proving and
volume adjustments after any LACT
system or CMS malfunction, including
excessive meter-factor deviation, using
the appropriate form in either API
12.2.3 or API 5.6 (both incorporated by
reference, see § 3174.3), or any similar
format showing the same information as
the API form, provided that the
calculation of meter factors maintains
the proper calculation sequence and
rounding.
(2) In addition to the information
required under paragraph (i)(1) of this
section, each meter-proving report must
also show the:
(i) Unique meter ID number;
(ii) Lease number, CA number, or unit
PA number;
(iii) The temperature from the test
thermometer and the temperature from
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the temperature averager or temperature
transducer;
(iv) For pressure transducers, the
pressure applied by the pressure test
device and the pressure reading from
the pressure transducer at the three
points required under paragraph (g)(3)
of this section;
(v) For density verification (if
applicable), the instantaneous flowing
density (as determined by Coriolis
meter), and the independent density
measurement, as compared under
paragraph (h) of this section; and
(vi) The ‘‘as left’’ fluid flow rate and
fluid pressure, if the back pressure valve
is adjusted after proving as described in
paragraph (c)(9) of this section.
(3) The operator must submit the
meter-proving report to the AO no later
than 14 days after the meter proving.
The proving report may be either in a
hard copy or electronic format.
§ 3174.12
Measurement tickets.
(a) Tank gauging. After oil is
measured by tank gauging under
§§ 3174.5 and 3174.6 of this subpart, the
operator, purchaser, or transporter, as
appropriate, must complete a uniquely
numbered measurement ticket, in either
paper or electronic format, with the
following information:
(1) Lease, unit PA, or CA number;
(2) Unique tank number and nominal
tank capacity;
(3) Opening and closing dates and
times;
(4) Opening and closing gauges and
observed temperatures in °F;
(5) Observed volume for opening and
closing gauge, using tank specific
calibration charts (see § 3174.5(c));
(6) Total gross standard volume
removed from the tank following API
11.1 (incorporated by reference, see
§ 3174.3);
(7) Observed API oil gravity and
temperature in °F;
(8) API oil gravity at 60 °F, following
API 11.1 (incorporated by reference, see
§ 3174.3);
(9) S&W content percent;
(10) Unique number of each seal
removed and installed;
(11) Name of the individual
performing the tank gauging; and
(12) Name of the operator.
(b) LACT system and CMS. (1) At the
beginning of every month, and, unless
the operator is using a flow computer
under § 3174.10, before conducting
proving operations on a LACT system,
the operator, purchaser, or transporter,
as appropriate, must complete a
uniquely numbered measurement ticket,
in either paper or electronic format,
with the following information:
(i) Lease, unit PA, or CA number;
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(ii) Unique meter ID number;
(iii) Opening and closing dates;
(iv) Opening and closing totalizer
readings of the indicated volume;
(v) Meter factor, indicating if it is a
composite meter factor;
(vi) Total gross standard volume
removed through the LACT system or
CMS;
(vii) API oil gravity. For API oil
gravity determined from a composite
sample, the observed API oil gravity and
temperature must be indicated in °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;
(viii) The average temperature in °F;
(ix) The average flowing pressure in
psig;
(x) S&W content percent;
(xi) Unique number of each seal
removed and installed;
(xii) Name of the purchaser’s
representative; and
(xiii) Name of the operator.
(2) Any accumulators used in the
determination of average pressure,
average temperature, and average
density must be reset to zero whenever
a new measurement ticket is opened.
§ 3174.13 Oil measurement by other
methods.
(a) Any method of oil measurement
other than tank gauging, LACT system,
or CMS at an FMP requires prior BLM
approval.
(b)(1) Any operator requesting
approval to use alternate oil
measurement equipment or
measurement method must submit to
the BLM performance data, actual field
test results, laboratory test data, or any
other supporting data or evidence that
demonstrates that the proposed
alternate oil equipment or method
would meet or exceed the objectives of
the applicable minimum requirements
of this subpart and would not affect
royalty income or production
accountability.
(2) The PMT will review the
submitted data to ensure that the
alternate oil measurement equipment or
method meets the requirements of this
subpart and will make a
recommendation to the BLM to approve
use of the equipment or method,
disapprove use of the equipment or
method, or approve use of the
equipment or method with conditions
for its use. If the PMT recommends, and
the BLM approves new equipment or
methods, the BLM will post the make,
model, range or software version (as
applicable), or method on the BLM Web
site www.blm.gov as being appropriate
for use at an FMP for oil measurement
without further approval by the BLM,
subject to any conditions of approval
identified by the PMT and approved by
the BLM.
(c) The procedures for requesting and
granting a variance under § 3170.6 of
this part may not be used as an avenue
for approving new technology, methods,
81513
or equipment. Approval of alternative
oil measurement equipment or methods
may be obtained only under this
section.
§ 3174.14 Determination of oil volumes by
methods other than measurement.
(a) Under 43 CFR 3162.7–2, when
production cannot be measured due to
spillage or leakage, the amount of
production must be determined by
using any method the AO approves or
prescribes. This category of production
includes, but is not limited to, oil that
is classified as slop oil or waste oil.
(b) No oil may be classified or
disposed of as waste oil unless the
operator can demonstrate to the
satisfaction of the AO that it is not
economically feasible to put the oil into
marketable condition.
(c) The operator may not sell or
otherwise dispose of slop oil without
prior written approval from the AO.
Following the sale or disposal of slop
oil, the operator must notify the AO in
writing of the volume sold or disposed
of and the method used to compute the
volume.
§ 3174.15
Immediate assessments.
Certain instances of noncompliance
warrant the imposition of immediate
assessments upon the BLM’s discovery
of the violation, as prescribed in the
following table. Imposition of any of
these assessments does not preclude
other appropriate enforcement actions.
TABLE 1 TO § 3174.15—VIOLATIONS SUBJECT TO AN IMMEDIATE ASSESSMENT
Violations subject to an immediate assessment
Assessment
amount per
violation:
Violation:
1. Missing or nonfunctioning FMP LACT system components as required by § 3174.8 of this subpart ............................................
2. Failure to notify the AO within 72 hours, as required by § 3174.7(e) of this subpart, of any FMP LACT system failure or
equipment malfunction resulting in use of an unapproved alternate method of measurement ......................................................
3. Missing or nonfunctioning FMP CMS components as required by § 3174.9 of this subpart .........................................................
4. Failure to meet the proving frequency requirements for an FMP, detailed in § 3174.11 of this subpart .......................................
5. Failure to obtain a written approval, as required by § 3174.13 of this subpart, before using any oil measurement method other
than tank gauging, LACT system, or CMS at a FMP ......................................................................................................................
[FR Doc. 2016–25405 Filed 11–16–16; 8:45 am]
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]]>Agencies
[Federal Register Volume 81, Number 222 (Thursday, November 17, 2016)]
[Rules and Regulations]
[Pages 81462-81513]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2016-25405]
[[Page 81461]]
Vol. 81
Thursday,
No. 222
November 17, 2016
Part VI
Department of the Interior
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Bureau of Land Management
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43 CFR Parts 3160 and 3170
Onshore Oil and Gas Operations; Federal and Indian Oil and Gas Leases;
Measurement of Oil; Final Rule
Federal Register / Vol. 81 , No. 222 / Thursday, November 17, 2016 /
Rules and Regulations
[[Page 81462]]
-----------------------------------------------------------------------
DEPARTMENT OF THE INTERIOR
Bureau of Land Management
43 CFR Parts 3160 and 3170
[17X.LLWO310000.L13100000.PP0000]
RIN 1004-AE16
Onshore Oil and Gas Operations; Federal and Indian Oil and Gas
Leases; Measurement of Oil
AGENCY: Bureau of Land Management, Interior.
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: This final rule updates and replaces Onshore Oil and Gas Order
Number 4, Measurement of Oil (Order 4) with new regulations codified in
the Code of Federal Regulations (CFR). It establishes minimum standards
for the measurement of oil produced from Federal and Indian (except
Osage Tribe) leases to ensure that production is accurately measured
and properly accounted for.
DATES: The final rule is effective on January 17, 2017. The
incorporation by reference (IBR) of certain publications listed in the
rule is approved by the Director of the Federal Register as of January
17, 2017.
ADDRESSES: Mail: U.S. Department of the Interior, Director (630),
Bureau of Land Management, Mail Stop 2134 LM, 1849 C St. NW.,
Washington, DC 20240, Attention: 1004-AE16.
Personal or messenger delivery: 20 M Street SE., Room 2134LM,
Washington, DC 20003.
FOR FURTHER INFORMATION CONTACT: Mike McLaren, Petroleum Engineer, BLM
Wyoming, Pinedale Field Office, 1625 West Pine St., P.O. Box 768,
Pinedale, WY 82941, or by telephone at 307-367-5389, for information
about the requirements of this final rule; or Steven Wells, Division
Chief, Fluid Minerals Division, 202-912-7143, for information regarding
the Bureau of Land Management's (BLM's) Fluid Minerals Program. For
questions related to regulatory process issues, please contact Faith
Bremner at 202-912-7441. Persons who use a telecommunications device
for the deaf (TDD) may call the Federal Relay Service at 800-877-8339
to contact the above individuals during normal business hours. The
Service is available 24 hours a day, 7 days a week to leave a message
or question with the above individuals. You will receive a reply during
normal business hours.
SUPPLEMENTARY INFORMATION:
I. Overview and Background
II. Overview of Final Rule, Section-by-Section Analysis, and
Response to Comments on the Proposed Rule
III. Overview of Public Involvement and Consistency With GAO
Recommendations
IV. Procedural Matters
I. Overview and Background
The BLM developed this rule based on the proposed rule published in
the Federal Register on September 30, 2015 (80 FR 58952), and the BLM's
consideration of tribal and public comments received on the proposed
rule. This final rule strengthens the BLM's policies governing
production accountability by updating its minimum standards for oil
measurement to reflect the considerable changes in technology and
industry practices that have occurred in the 25 years since Order 4 was
issued. It also responds to recommendations the United States
Government Accountability Office (GAO), the Department of the
Interior's (Interior's or Department's) Office of the Inspector General
(OIG), and the Secretary of the Interior's (Secretary's) Royalty Policy
Committee (RPC), Subcommittee on Royalty Management (Subcommittee) made
with respect to the BLM's production verification efforts. As explained
in this preamble, the overall volume uncertainty and performance goals
established by this rule are designed to ensure that the oil volume
reported on an Oil and Gas Operations Report (OGOR) submitted to the
Office of Natural Resources Revenue (ONRR) is sufficiently accurate to
ensure that the royalties due are paid.
Like the proposed rule, the final rule addresses the use of new oil
meter technology, proper measurement documentation, and recordkeeping;
establishes performance standards for oil measurement systems; and
includes a mechanism for the BLM to review, and approve for use, new
oil measurement technology and systems. The final rule expands the acts
of noncompliance that would result in an immediate assessment. Finally,
it sets forth a process for the BLM to consider variances from these
requirements.
Key changes incorporated into the final rule include provisions
that allow operators to use Coriolis measurement systems (CMSs) and
automatic tank gauging (ATG) systems without having to obtain variances
from the BLM.
This final rule, as well as the final rules to update and replace
Onshore Oil and Gas Orders Numbers 3 (Order 3) and 5 (Order 5) related
to site security and the measurement of gas, respectively, enhance the
BLM's overall production verification and accountability program.
The Secretary has the authority under various Federal and Indian
mineral leasing laws to manage oil and gas operations on Federal and
Indian (except Osage Tribe) lands. Governing laws include, but are not
limited to, the Mineral Leasing Act (MLA), 30 U.S.C. 181 et seq.; the
Mineral Leasing Act for Acquired Lands, 30 U.S.C. 351 et seq.; the
Federal Oil and Gas Royalty Management Act (FOGRMA), 30 U.S.C. 1701 et
seq.; the Indian Mineral Leasing Act, 25 U.S.C. 396a et seq.; the Act
of March 3, 1909, 25 U.S.C. 396; the Indian Mineral Development Act, 25
U.S.C. 2101 et seq.; and the Federal Land Policy and Management Act
(FLPMA), 43 U.S.C. 1701, et seq.\1\
---------------------------------------------------------------------------
\1\ Each of the statutes cited above expressly authorizes the
Secretary of the Interior to promulgate necessary and appropriate
rules and regulations governing those leases. See e.g., 30 U.S.C.
189; 30 U.S.C. 359; 30 U.S.C. 1751; 25 U.S.C. 396d; 25 U.S.C. 396;
25 U.S.C. 2107; and 43 U.S.C 1740. The Secretary has delegated this
authority to the BLM. Specifically, under Secretarial Order Number
3087, dated December 3, 1982, as amended on February 7, 1983 (48 FR
8983), and the Departmental Manual (235 DM 1.1), the Secretary has
delegated regulatory authority over onshore oil and gas development
on Federal and Indian (except Osage Tribe) lands to the BLM. For
Indian leases, the delegation of authority to the BLM is reflected
in 25 CFR parts 211, 212, 213, 225, and 227. In addition, as
authorized by 43 U.S.C. 1731(a), the Secretary has delegated to the
BLM regulatory responsibility for oil and gas operations in Indian
lands. 235 DM 1.1.K.
---------------------------------------------------------------------------
The BLM's onshore oil and gas program is one of the most
significant mineral-leasing programs in the Federal Government. In the
fiscal year (FY) 2015 sales year, onshore Federal oil and gas lease
holders sold 180 million barrels of oil,\2\ 2.5 trillion cubic feet of
natural gas,\3\ and 2.6 billion gallons of natural gas liquids, with a
market value of more than $17.7 billion, and generating royalties of
almost $2 billion. Nearly half of these revenues were distributed to
the States in which the leases are located. Lease holders on tribal and
Indian lands sold 59 million barrels of oil, 239 billion cubic feet of
natural gas, and 182 million gallons of natural gas liquids, with a
market value of over $3.6 billion, and generating royalties of over
$0.6 billion that were all distributed to the applicable tribes and
individual allotment owners. Under applicable laws, royalties are owed
on all production removed or sold from Federal and Indian oil and gas
leases.
[[Page 81463]]
The basis for those royalty payments is the measured production from
those leases.
---------------------------------------------------------------------------
\2\ This figure includes 168 million barrels of regularly
classified oil, plus additional sales of condensate, sweet and sour
crude, black wax crude, other liquid hydrocarbons, inlet scrubber
and drip or scrubber condensate, and oil losses, all of which are
considered to be part of oil sales for accounting purposes.
\3\ This figure includes all processed and unprocessed volumes
recovered on-lease, nitrogen, fuel gas, coal bed methane, and any
volumes of gas lost due to venting or flaring.
---------------------------------------------------------------------------
As explained in the preamble for the proposed rule, given the
magnitude of oil production on Federal and Indian lands, and the BLM's
statutory and management obligations, it is critically important that
the BLM ensure that operators accurately measure, properly report, and
account for that production. However, the BLM's rules governing how
that oil is measured and accounted for are more than 25 years old and
need to be updated and strengthened. Federal laws, technology, and
industry standards have all changed significantly in that time. The
final rule addresses the outdated nature of existing requirements and
helps achieve the BLM's objective of ensuring accurate measurement by
updating and replacing Order 4's requirements with regulations codified
in the CFR, at a new 43 CFR subpart 3174. These new regulations reflect
changes in oil measurement practices and technology since Order 4 was
first promulgated in 1989.\4\
---------------------------------------------------------------------------
\4\ Order 4, which was published in the Federal Register on
February 24, 1989 (54 FR 8056), has been in effect since August 23,
1989.
---------------------------------------------------------------------------
These updated requirements are the result of the BLM's evaluation
of its existing requirements, based on its experience in the field, and
based on the conclusion of multiple reports and evaluations of the
BLM's oil and gas program--one by the Subcommittee, issued in 2007; one
by the OIG, issued in 2009; and two reports prepared by the GAO, issued
in 2010 and 2015. Each of these is described further below.
In 2007, the Secretary appointed an independent panel--the
Subcommittee--to review the Department's procedures and processes
related to the management of mineral revenues and to provide advice to
the Department based on that review.\5\ In a report dated December 17,
2007, the Subcommittee determined that the BLM's production
accountability methods are ``unconsolidated, outdated, and sometimes
insufficient.'' The report observed that:
---------------------------------------------------------------------------
\5\ The Subcommittee was commissioned to report to the RPC,
which was chartered under the Federal Advisory Committee Act to
provide advice to the Secretary and other Departmental officials
responsible for managing mineral leasing activities and to provide a
forum for the public to voice concerns about mineral leasing
activities.
---------------------------------------------------------------------------
BLM policy and guidance have not been consolidated into a
single document or publication, resulting in the BLM's 31 oil and gas
field offices using varying policies and guidance (see page 31);
Some BLM policy and guidance are outdated and some policy
memoranda have expired (ibid.); and
Some BLM State Offices have issued their own ``Notices to
Lessees and Operators'' (NTLs) for oil and gas operations. While such
NTLs may have a positive effect on local oil and gas field operations,
they nevertheless lack a national perspective and may introduce
inconsistencies among the States (ibid.).
The Subcommittee specifically recommended that the BLM evaluate
Order 4 to determine whether it includes sufficient guidance for
ensuring that accurate royalties are paid on Federal oil production. As
explained in the preamble to the proposed rule, the Interior Department
formed a Fluid Minerals Team, comprising Departmental oil and gas
experts. The team determined that Order 4 should be updated in light of
changes in technology, the BLM, and industry practices.
As noted, in addition to the Subcommittee report, findings and
recommendation addressing similar issues have been issued by the GAO
(Report to Congressional Requesters, Oil and Gas Management, Interior's
Oil and Gas Production Verification Efforts Do Not Provide Reasonable
Assurance of Accurate Measurement of Production Volumes, GAO-10-313
(GAO 2010 Report), and Report to Congressional Requesters, Oil and Gas
Resources, Interior's Production Verification Efforts: Data Have
Improved but Further Actions Needed, GAO 15-39 (GAO 2015 Report)) and
the OIG (Bureau of Land Management's Oil and Gas Inspection and
Enforcement Program, CR-EV-0001-2009 (OIG Report)).
In its 2010 report, the GAO found that the Department's measurement
regulations and policies do not provide reasonable assurances that oil
and gas are accurately measured because, among other things, the
Department's policies for tracking where and how oil and gas are
measured are not consistent and effective (GAO 2010 Report, p. 20). The
report also found that the BLM's regulations do not reflect current
industry-adopted measurement technologies and standards designed to
improve oil and gas measurement (ibid.). The GAO recommended that
Interior provide Department-wide guidance on measurement technologies
not addressed in current regulations and approve variances for
measurement technologies in instances when the technologies are not
addressed in current regulations or Department-wide guidance (see
ibid., p. 80). The OIG report made a similar recommendation that the
BLM, ``Ensure that oil and gas regulations are current by updating and
issuing onshore orders. . . .'' (see p. 11). In its 2015 report, the
GAO reiterated that ``Interior's measurement regulations do not reflect
current measurement technologies and standards,'' and that this
``hampers the agency's ability to have reasonable assurance that oil
and gas production is being measured accurately and verified . . .''
(GAO 2015 Report, p. 16). Among its recommendations were that the
Secretary direct the BLM to ``meet its established time frame for
issuing final regulations for oil measurement'' (ibid., p. 32). The OIG
made similar recommendations based on the Subcommittee's report
observing that the BLM should, ``(e)nsure that oil . . . regulations
are current by updating and issuing onshore orders . . .'' (OIG Report,
p. 11).
The GAO's recommendations related to the adequacy of the BLM's oil
measurement rules are also significant because they form one of the
bases for the GAO's inclusion of the BLM's oil and gas program on the
GAO's High Risk List in 2011 (Report to Congressional Committees, High
Risk Series, An Update, GAO-11-278). Specifically, the GAO concluded in
2011 ``that Interior's verification of the volume of oil . . . produced
from Federal leases--on which royalties are due the Federal government-
-does not provide reasonable assurance that operators are accurately
measuring and reporting these volumes'' (GAO-11-278, p. 15). Because
the GAO's recommendations have not yet been fully implemented, the
onshore oil and gas program has remained on the High Risk List in
subsequent updates in 2013 (Report to Congressional Committees, High
Risk Series, An Update, GAO-13-283) and 2015 (Report to Congressional
Committees, High Risk Series, An Update, GAO-15-290).
Up-to-date measurement requirements are critically important
because they help ensure that oil and gas produced from Federal and
Indian leases are properly accounted for, thus ensuring that operators
pay the proper royalties due.
As explained in more detail below, the final rule makes a number of
changes that modernize and strengthen the existing requirements in
Order 4. In general, this final rule will give industry more choices
and flexibility for measuring oil produced from Federal and Indian
leases and will also make it easier for operators in the future to
adopt new technologies and processes as the industry continues to
advance.
[[Page 81464]]
In addition to updating requirements with respect to existing
technologies, the final rule also specifically recognizes advances in
measurement technology by affirmatively allowing operators to use a CMS
\6\ or an ATG/hybrid tank measurement system without first receiving a
variance from the BLM, as is currently required.\7\ In response to GAO
and RPC concerns that BLM field offices put out various policies and
guidance, the final rule establishes nationwide requirements and
standards for this measurement equipment, including a nationwide
process for reviewing and approving new technology as it is developed.
This change is significant because CMSs have proven to be reliable and
accurate in field and laboratory testing and, when the time comes to
replace their older systems, more and more operators are opting to use
CMSs.
---------------------------------------------------------------------------
\6\ A CMS is a metering system that uses a Coriolis flow meter
in conjunction with a tertiary device, pressure transducer, and
temperature transducer in order to derive and report gross standard
oil volume. A Coriolis flow meter is based on the principle that
fluid mass flow through a tube results in a measurable twisting or
distortion and consequent oscillation of the tube. Sensors measure
that oscillation and allow for a determination of various variables,
including volume.
\7\ As explained in the proposed rule, since this equipment was
not included in Order 4, the BLM did not have uniform national
performance standards for these systems, which has led BLM state and
field offices, while approving variances, to specify their own. The
state-by-state approach results in inconsistencies among offices
with respect to the requirements imposed on operators.
---------------------------------------------------------------------------
Similarly, operators in newer well fields have been using ATG
systems for internal inventory purposes for over 10 years and only
recently have they started using them to measure oil for sales and
royalty-determination purposes. The BLM reviewed proprietary ATG test
data that operators submitted to the BLM--both as public comment on the
proposed rule and in support of variance requests to have ATG systems
replace manual tank gauging. Based on that review, the BLM believes
that ATG/hybrid systems can meet or exceed this rule's tank-gauging
standards and as a result they should be expressly allowed.
Affirmatively allowing ATG and hybrid systems will also increase worker
safety because eliminating the need for workers to climb on top of
tanks, open hatches, and manually measure or sample oil reduces their
exposure to the fumes coming out of the tanks.\8\ The final rule's
incorporation of ATG/hybrid systems as a permissible measurement method
gives operators an additional tool to address growing safety
concerns.\9\
---------------------------------------------------------------------------
\8\ The Durango Herald, New hazard with oilfield work, March 7,
2016; https://www.durangoherald.com/article/20160307/NEWS01/160309666/New-hazard-with-oilfield-work.
\9\ In recent months this safety issue has been highlighted by
news reports of the deaths of oil workers who died after manually
opening oil tank hatches and being exposed to toxic fumes.
---------------------------------------------------------------------------
In recognition that new measurement technologies and processes,
like CMSs and ATG systems, will continue to be developed and evolve,
the final rule puts in place a process and criteria that will allow for
a new Production Measurement Team (PMT) to review, and for the BLM to
approve for use nationwide, new measurement technologies that are
demonstrated to be reliable and accurate.\10\ Under this new system,
operators would have to prove to the BLM that new technologies meet or
exceed this rule's new uncertainty performance standards, which for the
first time give the BLM a set of objective criteria that can be applied
to evaluate and approve any new meters, electronic components,
computers, software, and procedures not specifically addressed in these
regulations. Unlike the current variance system where operators must
make such a showing each and every time they wish to deploy a new
technology, under the PMT approach, once a technology has been approved
by the BLM based on the PMT's review, that technology can be employed
at additional facilities or by additional operators without a
subsequent BLM approval, so long as those facilities and operators
follow all conditions of approval (COAs) established by the PMT.
---------------------------------------------------------------------------
\10\ The PMT is distinct from the Interior's Gas and Oil
Measurement Team (DOI GOMT), which consists of members with gas or
oil measurement expertise from the BLM, the ONRR, and the Bureau of
Safety and Environmental Enforcement (BSEE). BSEE handles production
accountability for Federal offshore leases. The DOI GOMT is a
coordinating body that enables the BLM and BSEE to consider
measurement issues and track developments of common concern to both
agencies. The BLM expects that the members of the BLM PMT would
participate as part of the DOI GOMT.
---------------------------------------------------------------------------
Recognizing the newness of the PMT process, the final rule includes
a 2-year phase-in for that system. Over the next 2 years, the BLM will
develop and post on its Web site an uncertainty calculator that will
help the BLM and industry determine if a particular measurement system
or a new device meets the rule's uncertainty requirements. As an
operator designs a new system, the operator can plug its components
into the calculator and know before installing the system whether that
system meets the requirements, and could be approved by the PMT. Once
the BLM approves a new technology for use, it will post the make,
model, size, or software version on its Web site as approved for use
for all operators nationwide.
With respect to the PMT, it should be noted that while the final
rule provides that the PMT will review requests and make
recommendations to the BLM for approval, it is the BLM's intent that
such approvals will be issued by a BLM AO with authority over the oil
and gas program nationally (e.g., the Director, a Deputy Director, or
an Assistant Director), as opposed to that authority being delegated to
a local level. This is consistent with recommendations from the RPC,
GAO, and OIG that decisions on variances be granted at the national
level to ensure they are consistent and have the appropriate
perspective, as opposed to more local levels, which can result in
inconsistencies among BLM field offices.
In another important departure from Order 4, this final rule
avoids, where possible, cookbook-style lists of requirements for
operators to follow when determining oil quantity and quality. Instead,
in many instances, the rule simply requires operators to follow the
applicable industry standards, which were developed through a consensus
process by professional industry groups, with input from Federal oil
and gas experts. In each instance, the BLM carefully reviewed the
applicable standards and determined they are technically sufficient to
meet the BLM's production verification needs and are structured in such
a way that they can be enforced by BLM personnel in the field. The
incorporation of industry standards into the final rule gives operators
more flexibility to comply with the requirements of these regulations.
For example, Order 4 had one specific way for operators to measure oil
temperature--by inserting a thermometer in the approximate vertical
center of the fluid column, not less than 12 inches from the tank shell
for 5 minutes. The final rule still allows operators to measure oil
temperature using this method, but they can now also follow American
Petroleum Institute (API) Chapter 7 standards, which provide for
operators to use built-in tank thermometers or to take measurements
from the flow lines that lead to the haulers' trucks.
The rule also adopts a number of smaller changes which, taken
together, will increase measurement accuracy, increase verifiability,
and reduce waste. First, it would prohibit the use of automatic
temperature/gravity compensators on lease automatic custody transfer
(LACT) systems, which are required equipment under Order 4. These
compensators automatically
[[Page 81465]]
adjust LACT totalizer readings to account for temperature effects and,
in some cases, oil gravity effects on volume. However, because these
automatic compensators do not maintain the raw data the BLM needs to
verify that the compensators are functioning correctly or that the
totalizer readings are correct, this rule requires operators to use
temperature averaging devices instead, which record and average the
temperatures of the fluids flowing through the LACT. This requirement
ensures that the necessary audit trail is maintained. Such a system
strikes the right balance because it gives operators the data they need
to manually correct the volumes from the totalizer for the effects of
temperature and oil gravity, while ensuring that the BLM has the raw
data needed to verify the results and confirm system functionality.
Finally, the rule requires all oil storage tanks, hatches,
connections, and other access points to be installed and maintained in
accordance with manufacturers' specifications. This requirement, in
effect, requires operators to maintain the pressure-vacuum integrity
that manufacturers designed and built into their equipment. This in
turn will minimize hydrocarbon gas lost to the atmosphere.
II. Overview of Final Rule, Section-by-Section Analysis and Response to
Comments on the Proposed Rule
A. General Overview of the Final Rule
As discussed in the background section of this preamble, the BLM's
rules concerning oil measurement found in Order 4 have not kept pace
with industry standards and practices, statutory requirements, or
applicable measurement technology and practices. The final rule
enhances the BLM's overall production accountability efforts by
addressing these concerns and ensuring that the oil produced from
Federal and Indian (except Osage Tribe) leases is adequately accounted
for, ultimately ensuring that all royalties due are paid.
The following table provides an overview of the changes between the
proposed rule and this final rule. A similar chart explaining the
differences between the proposed rule and Order 4 appears in the
proposed rule at 80 FR 58955-58956.
------------------------------------------------------------------------
Proposed rule Final rule Substantive changes
------------------------------------------------------------------------
43 CFR 3174.1--Definitions and 43 CFR 3174.1-- The final rule
Acronyms. Definitions and removes definitions
Acronyms. for ``registered
volume,''
``resistance thermal
device,'' and
``turbulent flow.''
It changes the
definitions for
``base pressure''
and ``Coriolis
meter.'' It adds new
definitions for
``indicated volume''
and ``transducer.''
43 CFR 3174.2--General 43 CFR 3174.2-- The final rule gives
Requirements. General operators a phase-in
Requirements. period of 1 to 4
years after the
rule's effective
date to bring
existing facility
measurement point
(FMP) equipment into
compliance. This
timeframe is based
on the operators'
production volumes
and it coincides
with their schedule
for applying for
their FMP numbers. A
new paragraph (g) in
this section delays
for 2 years a
requirement that
operators begin
using approved
equipment listed on
the BLM website
(www.blm.gov).
43 CFR 3174.3--Specific 43 CFR 3174.3-- The final rule adopts
Measurement Performance Incorporation by the latest versions
Requirements. Reference. of certain API
standards and
incorporates them by
reference into the
BLM's oil and gas
regulations. It
incorporates by
reference many API
standards that did
not appear in the
proposed rule and
removes two industry
standards developed
by the American
Society for Testing
and Materials
(ASTM).
43 CFR 3174.4--Incorporation 43 CFR 3174.4-- The final rule
by Reference. Specific establishes two
Measurement thresholds for
Performance overall oil
Requirements. measurement
uncertainty levels.
For FMPs measuring
greater than or
equal to 30,000
barrels (bbl)/month,
the maximum
uncertainty is 0.50 percent.
For FMPs measuring
less than 30,000 bbl/
month, the maximum
uncertainty level is
1.50
percent. Paragraph
(d) is revised to
clarify that the
PMT, following the
process outlined in
Sec. 3174.13, will
make a determination
whether proposed
alternative
equipment or
measurement
procedures meet or
exceed the
objectives and
intent of this
section.
43 CFR 3174.5 and 3174.6--Oil 43 CFR 3174.5 and The final rule
Measurement by Manual Tank 3174.6--Oil requires operators
Gauging. Measurement by to submit sales tank
Tank Gauging. calibration charts
(tank tables) to the
authorized officer
(AO) within 45 days
after calibrating or
recalibrating. It
allows operators to
use ATG systems and,
by replacing
prescriptive
language with
additional industry
standards, it gives
operators more
options for tank
gauging, sampling,
calibrating sales
tanks, and
determining
temperature, oil
gravity, and
sediment and water
(S&W) content. The
final rule specifies
manual gauging
accuracy to the
nearest \1/4\ inch
for tanks of 1,000
bbl or less and
gauging accuracy to
the nearest \1/8\
inch for tanks
greater than 1,000
bbl. All oil storage
tanks must be
clearly identified
with an operator-
generated unique
number.
[[Page 81466]]
43 CFR 3174.7 and 3174.8--LACT 43 CFR 3174.7 and The final rule
Systems. 3174.8--LACT requires operators
Systems. to notify the AO of
any LACT system
failures or
equipment
malfunctions, or
other failures that
could adversely
affect oil
measurement within
72 hours upon
discovery. The
requirement in
proposed Sec.
3174.7(b) that
operators generate
an additional run
ticket before
proving a LACT
system has been
modified. A related
change in Sec.
3174.12(b)(1) makes
it clear that LACT
systems that use
flow computers are
exempt from the
requirement that
operators close a
run ticket before
proving a LACT
system. The table in
proposed Sec.
3174.7(c) entitled,
``Standards to
Measure Oil by a
LACT System,'' has
been removed and in
its place the final
rule requires
operators to
complete measurement
tickets as required
under Sec.
3174.12(b). Industry
standards have been
added to replace
prescriptive
language in the
proposed rule. This
gives operators more
choices for
collecting, mixing,
and analyzing
samples. The final
rule clarifies that
LACT systems may
have either a
Coriolis meter or a
positive
displacement (PD)
meter.
43 CFR 3174.9--Coriolis 43 CFR 3174.9-- The final rule is
Measurement System--General Coriolis revised to clarify
Requirements and Components. Measurement that operators can
System--General use CMSs as a
Requirements and standalone unit,
Components. independent of a
LACT system. The
table in paragraph
(d) entitled,
``Standards
Applicable to CMS
Use,'' has been
removed and in its
place the final rule
requires operators
to complete
measurement tickets,
as required under
Sec. 3174.12(b).
Prescriptive
language in proposed
paragraph (e) that
dictated which CMS
components should be
used during set up
and installation of
a CMS, for the most
part, has been
removed and replaced
with industry
standards, which
give operators more
flexibility. The
requirement for a
back pressure valve
has been removed and
operators may use
any means to apply
sufficient back
pressure to ensure
single-phase flow so
long as it meets
industry standard
API 5.6. Industry
standards have been
added to give
operators more
options for
automatic sampling
and for mixing and
handling samples. A
new paragraph (g)
has been added that
requires operators
to follow API 12.2.1
and API 12.2.2 for
calculating net
standard volume. A
similar, more
prescriptive
requirement for
calculating net
standard volume
appeared in proposed
Sec. 3174.10(g),
which has been
removed from the
final rule.
43 CFR 3174.10--Coriolis 43 CFR 3174.10-- Requirement for
Measurement System--Operating Coriolis meter straight piping
Requirements. for LACT and CMS upstream and
Measurement downstream of a
Applications. meter has been
removed from the
final rule. The
requirement for
verifying the meter
zero value is
revised to be less
prescriptive and
instead requires
operators to follow
manufacturers'
specifications and
procedures. The
requirement that
operators keep the
log containing the
meter factor, zero
verification, and
zero adjustments on
site has been
changed to require
them to make it
available to the AO
upon request.
43 CFR 3174.11--Meter-Proving 43 CFR 3174.11-- The final rule
Requirements. Meter-Proving requires proving
Requirements. every 3 months
(quarterly) after
last proving, or
after every 75,000
bbl of volume flows
through the meter,
whichever comes
first, but no more
frequently than
monthly. The rule
includes
verification
requirements for
pressure,
temperature, and
density measurement
devices with each
proving. The table
in proposed
paragraph (b)
entitled, ``Minimum
Standards for
Proving FMP
Meters,'' has been
removed because it
is not needed. The
proposed requirement
for master meter
repeatability of
0.0002 (0.02
percent) has been
changed to 0.0005
(0.05 percent). The
frequency for
proving master
meters is no less
than once every 12
months. The final
rule replaces
prescriptive
language that
dictated the sizes
and proving
frequencies of
displacement provers
with requirements
that operators
follow industry
standards. Paragraph
(c)(4) adds the
requirement that
operators follow
industry standards
when calculating the
average meter
factor. Paragraph
(c)(6) contains new
language on how to
utilize multiple
meter factors. Meter-
proving reports may
be submitted to the
AO in either hard-
copy or electronic
format.
43 CFR 3174.12--Measurement 43 CFR 3174.12-- The final rule
Tickets. Measurement requires that oil
Tickets. measurement tickets
for LACT systems and
CMS be closed at the
end of each month
and before proving
unless utilizing
flow computers. The
rule allows the use
of electronic
measurement tickets.
The final rule no
longer requires the
operator's
representative to
certify that the
measurement on a
completed run ticket
is correct. The
final rule has also
removed the
requirement that
operators must
notify the AO within
7 days if they
disagree with a tank
gauger's
measurement.
43 CFR 3174.13--Oil 43 CFR 3174.13-- None.
Measurement by Other Methods. Oil Measurement
by Other Methods.
[[Page 81467]]
43 CFR 3174.14--Determination 43 CFR 3174.14-- None.
of Oil Volumes by Methods Determination of
Other Than Measurement. Oil Volumes by
Methods Other
Than Measurement.
43 CFR 3174.15--Immediate 43 CFR 3174.15-- The final rule
Assessments. Immediate removes one of the
Assessments. six violations
listed in the
proposed rule:
Failure to notify
the AO within 7 days
of any changes to
any CMS internal
calibration factors
(proposed violation
#4). Of the five
remaining violations
listed, the final
rule changes the
timeframe from
``within 24 hours''
to ``within 72
hours'' that
operators must
notify the AO of any
LACT system failure
or equipment
malfunction
resulting in use of
an unapproved
alternative method
of measurement
(violation #2 in the
final rule). The
final rule also
removes the word
``variance'' from
the violation of
failure to obtain a
written approval
before using any oil
measurement method
other than tank
gauging, LACT
system, or CMS at an
FMP (violation #5 in
the final rule).
------------------------------------------------------------------------
B. Section-by-Section Analysis of the Final Rule and Response to
Comments on Specific Provisions of the Proposed Rule
This final rule is codified primarily in a new 43 CFR subpart 3174
within a new part 3170. In addition to this rule, the BLM has also
prepared separate rules to update and replace Onshore Oil and Gas Order
Number 3 (Order 3) (site security), which will be codified at a new 43
CFR subpart 3173; and Onshore Oil and Gas Order Number 5 (Order 5) (gas
measurement), which will be codified at a new 43 CFR subpart 3175. The
rules to replace Orders 3 and 5 are being published concurrently with
this rule. In addition to establishing a new 43 CFR subpart 3173, the
rule to replace Order 3 establishes 43 CFR part 3170 and subpart 3170.
Subpart 3170 contains definitions of certain terms common to more than
one of these rules, as well as other provisions common to all of the
rules, such as provisions prohibiting bypass of and tampering with
meters; procedures for obtaining variances from the requirements of a
particular rule; requirements for recordkeeping, records retention, and
submission; and administrative appeal procedures. All of the
definitions and substantive provisions of subpart 3170 also apply to
this new subpart 3174.
Certain provisions of this final rule will result in amendments to
related provisions in the onshore oil and gas operations rules in 43
CFR part 3160. The amendments to those provisions are also discussed
below.
Subpart 3174 and Related Provisions
Section 3174.1 Definitions and Acronyms
Section 3174.1 defines terms and acronyms used in subpart 3174.
Defining these terms and acronyms is necessary to ensure consistent
interpretation and implementation of this rule. The BLM received a
number of comments on this section. Except as noted in this section,
the terms and acronyms in Sec. 3174.1 did not change between the draft
and final rule. A summary of the definitions and acronyms that were not
changed in the final rule may be found in the proposed rule.
Several commenters recommended that base pressure should be defined
as 14.696 pounds per square inch, absolute (psia), as opposed to
defining it, as in the proposed rule, as the atmospheric pressure or
the vapor pressure of the liquid at 60[emsp14][deg]F, whichever is
higher. Subsequent research has shown that base pressure should be
defined as a fixed amount and therefore the BLM agrees with these
comments. As a result, the definition of base pressure has been changed
to 14.696 psia in the final rule.
Several commenters had concerns about the definition of Coriolis
meter and Coriolis metering system (CMS). They suggested we replace the
word ``measures'' in the definition of Coriolis meter with the word
``infers.'' The BLM agrees with this comment because the Coriolis meter
does not actually measure volume directly as a positive displacement
(PD) meter does, by isolating the flowing liquid into segments of known
volume, but instead analyzes the interaction between the flowing fluid
and the oscillation of the tubes. As a result, the definition of
Coriolis has been changed to say that a Coriolis meter infers a mass
flow rate. Another commenter said the definition of CMS should be
changed to say the CMS reports ``net standard oil volume'' instead of
``net oil volume,'' while another commenter noted that the Coriolis
meter displays ``gross,'' not ``net'' standard volumes. The BLM agrees
with these suggestions because the Coriolis meter is capable of
correcting to gross standard volume, but not capable of deducting the
S&W content to derive net standard volumes. The definition has been
changed in the final rule to ``gross standard volume'' as a result of
this comment.
Another commenter requested that we include a definition in the
rule for ``vapor tight.'' The proposed rule at Sec. 3174.5(b)(3)
required all oil storage tanks, hatches, connections, and other access
points to be vapor tight. The BLM agrees that the term ``vapor tight''
should be defined and has defined the term to mean capable of holding
pressure differential only slightly higher than that of installed
pressure-relieving or vapor recovery devices.
A few commenters suggested that all of the definitions in the rule
should come from the API standards, rather than be the BLM's own
customized definitions. After comparing the API definitions against the
BLM's definitions in the rule, the BLM does not agree with this
suggestion. Not all API definitions fit the terms used in the rule. For
example, one commenter said the BLM should use the API definition for
LACT systems, which defines turbine meters as an example of a meter
that can be part of a LACT system. The BLM disagrees with this comment
because the rule does not allow turbine meters to be used at a FMP. The
BLM has used many API definitions in the rule, but not all of them are
suitable for this rule, therefore, this rule was not changed as a
result of these comments.
Three commenters suggested that we include definitions for the
acronyms ``AO,'' authorized officer; ``PA,'' participating area; and
``CA,'' communitization agreement. The definitions for the acronyms AO,
PA, and CA are included in the definitions section of 43 CFR subpart
3170, which is in a related rulemaking previously discussed. As a
result, no change was made to this rule as a result of these comments.
One commenter suggested that we not use the term ``registered
volume,'' but rather the term ``indicated volume.'' The
[[Page 81468]]
BLM agrees that the term ``indicated volume'' is a more appropriate
term for the definition and aligns with common industry language, and
as a result has changed the definition in the rule to reflect the
definition for indicated volume.
One commenter said the term ``resistance thermal device'' is not a
common industry term and suggested we change it to ``resistance thermal
detector.'' As a result of this comment and a review of comments and
changes to other sections, the term and definition for ``resistance
thermal device'' has been removed and replaced by the term
``transducer.'' Transducer has been defined to be an electronic device
that converts a physical property--such as pressure, temperature, or
electrical resistance--into an electrical output signal that varies
proportionally with the magnitude of the physical property. This
defines a broader spectrum of devices and can include a resistance
thermal detector. This use of the term ``transducer'' aligns with
common industry practice and better suits the BLM's objective of
ensuring that there is sufficient flexibility built into the rule.
One commenter suggested that we change our definition of
``turbulent flow'' to include a reference to the common measure for
determining the flow, which is by Reynolds number. Since the final rule
does not contain the turbulent-flow requirements that appeared in the
proposed rule at Sec. 3174.8(b)(1), the BLM has removed this term from
the definitions section.
Based on changes to other sections resulting in new terms being
introduced, a definition for ``dynamic meter factor'' has been included
as meaning a kinetic meter factor derived by linear interpolation or
polynomial fit, used for conditions where a series of meter factors
have been determined over a range of normal operating conditions. In
the revised non-prescriptive structure of the final rule, the term
``opaque oil'' is no longer used, as such the definition has been
removed.
Section 3174.2 General Requirements
Paragraphs (a) through (d) of Sec. 3174.2 refer the reader to
other sections in this rule and to 43 CFR subpart 3173, which is
addressed in the rulemaking to replace Order 3. That rulemaking
contains the requirements for oil storage tanks, on-lease oil
measurement, commingling, and FMP numbers, respectively. All comments
received on these paragraphs are addressed in the corresponding section
discussions later in this preamble and in the preamble for 43 CFR
subpart 3173.
Section 3174.2(e) specifies that all equipment used to measure the
volume of oil for royalty purposes at an FMP installed after the
effective date of this subpart must comply with the requirements of
this subpart. The BLM received no comments on this requirement.
Section 3174.2(f) requires that measuring procedures and equipment
used to measure oil for royalty purposes that are in use on the
effective date of this rule, must comply with the requirements of this
subpart on or before the date the operator is required to apply for an
FMP number under 3173.12(e) of this part. Prior to that date, measuring
procedures and equipment used to measure oil for royalty purposes, that
is in use on the effective date of this rule, must continue to comply
with the requirements of Onshore Oil and Gas Order No. 4, Measurement
of oil, 54 FR 8086 (Feb 24, 1989), and any COAs and written orders
applicable to that equipment.
The proposed rule would have required operators to bring existing
equipment used at FMPs into compliance within 180 days after the
effective date of the final rule. Many commenters said 180 days is not
enough time to plan for and bring existing equipment into compliance.
The BLM agrees, and in response, this final rule provides a phase-in
period of 1 to 4 years after the rule's effective date to bring
existing equipment into compliance.
The 1- to 4-year phase-in period is based on the time-frames
established for operators to apply for their FMP numbers, which is
provided for in 43 CFR 3173.12 and is addressed in a related rulemaking
that is updating and replacing Order 3. This modified implementation
timeframe in the final rule links compliance with the oil measurement
requirement to an operator's production volumes, with lower-volume
producers having more time to comply. Under this new approach, the
highest 25 percent of the producing leases, CAs, or unit PAs are
required to be in compliance the earliest--within 12 months of the
effective date of this rule. All remaining leases, CAs, or unit PAs,
based on volume thresholds, are staged out over the following 3 years.
Commenters' greatest concern with the 180-day deadline was that it
was not enough time to generate new oil-storage-tank calibration tables
that would have allowed them to measure volumes in \1/8\-inch
increments, as required in Sec. 3174.6 of the proposed rule.\11\ That
is no longer a concern, however, because the final rule does not
require that volumes be measured in \1/8\-inch increments.
---------------------------------------------------------------------------
\11\ Order 4 requires \1/4\-inch gauging accuracy for tanks with
a capacity of 1,000 bbl or less and requires strapping tables at \1/
4\-inch increments. For tanks with a capacity greater than 1,000
bbl, Order 4 requires a \1/8\-inch gauging accuracy and strapping
tables at \1/8\-inch increments.
---------------------------------------------------------------------------
In the proposed rule, the BLM proposed switching to the \1/8\-inch
gauging accuracy for all tanks in order to meet one objective of the
rule--to bring the oil measurement regulations up to current industry
standards. However, API has two contradictory standards for manual
gauging measurement accuracy on oil storage tanks--API 3.1A calls for
\1/8\-inch gauging accuracy for all tanks, while API 18.1 calls for a
\1/4\-inch gauging accuracy for tanks of 1,000 bbl or less. Based on
this change in industry standards and its own experience, the BLM
assumed that new calibration tables could be generated from existing
tank strapping measurements. Commenters disagreed, saying operators
would have to hire engineering companies to reanalyze some 40,000 sales
tanks across the nation. They said numerous tanks would have to be
physically re-measured, or re-strapped. Some commenters said that, due
to budgeting, equipment, and weather constraints, it could take them a
year to re-strap their tanks. Others said it could take months to do
the job.
As discussed later in Sec. 3174.6, the BLM has decided to retain
the \1/4\-inch gauging accuracy requirement for oil tanks with a
capacity of 1,000 bbl or less, which is the current requirement,
eliminating the need for operators to re-strap their tanks. To
implement these standards, the BLM plans to develop a liquids
uncertainty calculator that will allow its inspectors to enforce oil
tank measurement uncertainty requirements for operators who elect to
use automatic and hybrid tank gauging systems. It will take the BLM
about 2 years to develop the uncertainty calculator and verify that
automated equipment meets the uncertainty standards. During this time,
operators who use automatic and hybrid tank gauging systems will still
have to meet the measurement performance requirements.
Some commenters argued that existing equipment used at FMPs should
not have to meet any deadline for coming into compliance with this
rule's requirement and should instead be exempted from complying
entirely (that is, grandfathered).
For example, one commenter said the BLM should grandfather all
existing
[[Page 81469]]
equipment, but require all new installations or installations that
undergo repairs costing more than 50 percent of the cost of new
equipment to meet the new standards. The BLM does not agree with this
proposed change for several reasons. The rule's only equipment retrofit
requirement is that all automatic temperature/gravity compensators be
replaced with temperature averagers. Temperature averagers are
relatively inexpensive, costing around $6,500 per device, and automatic
temperature/gravity compensators are not used on very many LACT
systems. The BLM estimates that over 80 percent of all LACTs on Federal
and Indian leases already have temperature averagers installed. A
second issue the BLM has with this proposed change is that it would
require the BLM to monitor all maintenance activity and estimate costs
of repairs on ``grandfathered'' equipment. Finally, the commenter did
not explain or provide justification for how this proposed change would
be preferable to the proposed rule.
Another commenter said, as an alternative to grandfathering,
equipment serving low-volume and marginal FMPs should be exempted from
the requirements. The BLM does not see a need for this exemption
because low-volume or marginal wells will, in most cases, be measured
by manual tank gauging. Since the tank-gauging requirements in this
final rule have not changed relative to the requirements in Order 4,
this change was unnecessary.
Another commenter disagreed with the proposed rule's prohibition of
automatic temperature/gravity compensators. These compensators should
be grandfathered, the commenter said, as long as an audit trail exists
whereby the raw data is available and the final results from the
compensators can be recreated from this data. The commenter further
stated that systems that cannot provide such data should be
grandfathered in the final rule. The BLM disagrees. The fact remains
that automatic compensator systems alter the raw data before any audit
trail is created. They automatically change a meter's totalizer
readings, erasing the raw data that the BLM and the operator need to
verify that the compensators are functioning correctly and that the
totalizer reading is correct.
Another commenter said that if existing equipment is not
grandfathered, operators may need to install new LACT units in order to
comply, which in turn would require operators to re-pipe their wells.
According to this commenter, this would result in undue surface
disturbance, excessive expenses, strain on the labor force, and wells
that are currently in secondary recovery or that do not produce large
amounts of oil being plugged prematurely, leaving behind undeveloped
and valuable resources. The BLM disagrees with this interpretation of
the rule's requirements. The only equipment that would have to be
replaced at an FMP under both the proposed and final rules is the
automatic temperature/gravity compensator, which is only one component
of a PD meter of a LACT unit. Operators must replace these devices with
temperature averagers, which allow operators to collect and retain the
raw data the BLM needs to verify results and confirm and preserve
system functionality. Based on the BLM's experience, this replacement
can occur without replacing the entire LACT system. Additionally, as
explained elsewhere in this preamble, most existing LACT systems do not
use automatic temperature/gravity compensators.
One commenter said the midstream sector (the pipeline companies and
processing plants at or downstream of the meters) would suffer if the
rule does not grandfather existing equipment. The commenter did not
explain or specify any negative impacts on the midstream sector from
the requirement that operators replace automatic temperature/gravity
compensators on LACTs. The BLM is not aware of any negative impacts
this would have on the midstream sector and the commenter did not
provide any information on how the midstream sector will suffer from
accurate, verifiable measurement on a lease, PA, or CA. As a result,
the BLM does not agree with the commenter and no change has been made
to the rule based on this comment.
Several commenters said properly operating equipment should be
grandfathered, and, if it must be replaced, operators should be allowed
to negotiate installation timeframes with local BLM field offices. The
BLM believes that this recommendation would perpetuate the problem of
program requirements being inconsistently applied from state to state
or field office to field office and therefore did not change the rule
as a result of these comments. One of the primary goals of this final
rule is to provide some nationwide consistency as to the application of
these requirements.
Another commenter said that existing facilities and equipment
should be grandfathered because operators could not afford an
``investment of this magnitude'' to retrofit equipment to meet the new
standards. The commenter did not provide any details regarding what is
meant by an ``investment of this magnitude.'' The BLM disagrees with
the implication that replacing automatic temperature/gravity
compensators on a LACT is a significant investment. The cost to replace
automatic temperature/gravity compensators on LACT systems with
temperature averagers is relatively minor--approximately $6,500 per
system. No change resulted from this comment.
The BLM does not believe that existing equipment should be
grandfathered. For years, the GAO and industry have voiced concerns
that the BLM's measurement regulations are outdated and make it harder
for the BLM to have reasonable assurance that production is being
accurately measured and verified. This rule aims to address these
concerns at both new and existing facilities.
Section 3174.2(g) exempts meters that are used for allocation
measurement as part of commingling approvals from complying with the
requirements of this subpart. Commingling approvals will be governed
under new requirements in 43 CFR 3173.14, which are addressed in the
rulemaking that is updating and replacing Order 3. One commenter said
that meters used for allocating production from wells in approved
commingling arrangements or that are in the same unit, PA, or CA should
be required to meet API standards for allocation measurement. The
commenter did not state a reason for this suggestion. Since the BLM
does not want to impose blanket allocation measurement requirements
that may not be relevant to every situation, it did not adopt this
suggestion. Instead, the final rule retains the AO's discretion to
include those requirements as a condition of approval on a case-by-case
basis.
Section 3174.3 Incorporation by Reference (IBR)
This section previously appeared as Sec. 3174.4 in the proposed
rule, but based on edits made to the final rule, this section and
proposed Sec. 3174.3 have been switched. All comments discussed below
were submitted for the previously proposed Sec. 3174.4.
This rule incorporates a number of industry standards and
recommended practices, either in whole or in part, without republishing
the standards in their entirety in the CFR, a practice known as IBR.
These standards have been developed through a consensus process,
facilitated by the API, with input from the oil and gas industry and
Federal agencies with oil and gas operational oversight
responsibilities. The BLM has reviewed these standards
[[Page 81470]]
and determined that they will achieve the intent of 43 CFR 3174.4
through 3174.13 of this rule. The legal effect of IBR is that the
incorporated standards become regulatory requirements. With the
approval of the Director of the Federal Register, this rule
incorporates the current versions of the standards listed.
Some of the standards referenced in this section have been
incorporated in their entirety. For other standards, the BLM
incorporates only those sections that are relevant to the rule, meet
the intent of Sec. 3174.3 of the rule, and do not need further
clarification.
The incorporation of industry standards follows the requirements
found in 1 CFR part 51. The industry standards in this final rule are
eligible for incorporation under 1 CFR 51.7 because, among other
things, they will substantially reduce the volume of material published
in the Federal Register; the standards are published, bound, numbered,
and organized; and the standards incorporated are readily available to
the general public through purchase from the standards organization or
through inspection at any BLM office with oil and gas administrative
responsibilities (1 CFR 51.7(a)(3) and (a)(4)). The language of
incorporation in Sec. 3174.3 meets the requirements of 1 CFR 51.9.
Where appropriate, the BLM has incorporated by reference an industry
standard governing a particular process and then imposed requirements
that add to or modify the requirements imposed by that standard (e.g.,
the BLM sets a specific value for a variable where the industry
standard proposed a range of values or options).
All of the API materials that the BLM is incorporating by reference
are available for inspection at the BLM, Division of Fluid Minerals; 20
M Street SE; Washington, DC 20003; 202-912-7162; and at all BLM offices
with jurisdiction over oil and gas activities. The API materials are
available for inspection and purchase at the API, 1220 L Street NW.,
Washington, DC 20005; telephone 202-682-8000; API also offers free,
read-only access to some of the material at https://publications.api.org.
The following describes the API standards that the BLM has
incorporated by reference into this rule:
API Manual of Petroleum Measurement Standards (MPMS) Chapter 2--
Tank Calibration, Section 2A, Measurement and Calibration of Upright
Cylindrical Tanks by the Manual Tank Strapping Method; First Edition,
February 1995; Reaffirmed February 2012 (``API 2.2A''). This standard
describes the procedures for calibrating upright cylindrical tanks used
for storing oil.
API MPMS Chapter 2--Tank Calibration, Section 2.2B, Calibration of
Upright Cylindrical Tanks Using the Optical Reference Line Method;
First Edition, March 1989; Reaffirmed January 2013 (``API 2.2B''). This
standard describes measurement and calibration procedures for
determining the diameters of upright welded cylindrical tanks, or
vertical cylindrical tanks with a smooth surface and either floating or
fixed roofs.
API MPMS Chapter 2--Tank Calibration, Section 2C, Calibration of
Upright Cylindrical Tanks Using the Optical-triangulation Method; First
Edition, January 2002; Reaffirmed May 2008 (``API 2.2C''). This
standard describes a calibration procedure for applications to tanks
above 26 feet in diameter with cylindrical courses that are
substantially vertical.
API MPMS Chapter 3, Section 1A, Standard Practice for the Manual
Gauging of Petroleum and Petroleum Products; Third Edition, August 2013
(``API 3.1A''). This standard describes the following: (a) The
procedures for manually gauging the liquid level of petroleum and
petroleum products in non-pressure fixed roof tanks; (b) Procedures for
manually gauging the level of free water that may be found with the
petroleum or petroleum products; (c) Methods used to verify the length
of gauge tapes under field conditions and the influence of bob weights
and temperature on the gauge tape length; and (d) Influences that may
affect the position of gauging reference point (either the datum plate
or the reference gauge point).
API MPMS Chapter 3--Tank Gauging, Section 1B, Standard Practice for
Level Measurement of Liquid Hydrocarbons in Stationary Tanks by
Automatic Tank Gauging; Second Edition, June 2001; Reaffirmed August
2011 (``API 3.1B''). This standard describes the level measurement of
liquid hydrocarbons in stationary, above ground, atmospheric storage
tanks using automatic tank gauges (ATG). This standard discusses
automatic tank gauging in general, accuracy, installation,
commissioning, calibration, and verification of ATG that measure either
innage or ullage.
API MPMS Chapter 3--Tank Gauging, Section 6, Measurement of Liquid
Hydrocarbons by Hybrid Tank Measurement Systems; First Edition,
February 2001; Errata September 2005; Reaffirmed October 2011 (``API
3.6''). This standard describes the selection, installation,
commissioning, calibration, and verification of Hybrid Tank Measurement
Systems. This standard also provides a method of uncertainty analysis
to enable users to select the correct components and configurations to
address for the intended application.
API MPMS Chapter 4--Proving Systems, Section 1, Introduction; Third
Edition, February 2005; Reaffirmed June 2014 (``API 4.1''). Section 1
is a general introduction to the subject of proving meters.
API MPMS Chapter 4--Proving Systems, Section 2, Displacement
Provers; Third Edition, September 2003; Reaffirmed March 2011 (``API
4.2''). This standard outlines the essential elements of meter provers
that do, and also do not, accumulate a minimum of 10,000 whole meter
pulses between detector switches, and provides design and installation
details for the types of displacement provers that are currently in
use. The provers discussed in this chapter are designed for proving
measurement devices under dynamic operating conditions with single-
phase liquid hydrocarbons.
API MPMS Chapter 4, Section 5, Master-Meter Provers; Fourth
Edition, June 2016 (``API 4.5''). This standard covers the use of
displacement and Coriolis meters as master meters. The requirements in
this standard are for single-phase liquid hydrocarbons.
API MPMS Chapter 4--Proving Systems, Section 6, Pulse
Interpolation; Second Edition, May 1999; Errata April 2007; Reaffirmed
October 2013 (``API 4.6''). This standard describes how the double-
chronometry method of pulse interpolation, including system operating
requirements and equipment testing, is applied to meter proving.
API MPMS Chapter 4, Section 8, Operation of Proving Systems; Second
Edition September 2013 (``API 4.8''). This standard provides
information for operating meter provers on single-phase liquid
hydrocarbons.
API MPMS Chapter 4--Proving Systems, Section 9, Methods of
Calibration for Displacement and Volumetric Tank Provers, Part 2,
Determination of the Volume of Displacement and Tank Provers by the
Waterdraw Method of Calibration; First Edition, December 2005;
Reaffirmed July 2015 (``API 4.9.2''). This standard covers all of the
procedures required to determine the field data necessary to calculate
a Base Prover Volume of Displacement Provers by the Waterdraw Method of
Calibration.
API MPMS Chapter 5--Metering, Section 6, Measurement of Liquid
Hydrocarbons by Coriolis Meters; First Edition, October 2002;
Reaffirmed November 2013 (``API 5.6''). This standard is applicable to
custody-
[[Page 81471]]
transfer applications for liquid hydrocarbons. Topics covered are API
standards used in the operation of Coriolis meters, proving and
verification using volume-based methods, installation, operation, and
maintenance.
API MPMS Chapter 6--Metering Assemblies, Section 1, Lease Automatic
Custody Transfer (LACT) Systems; Second Edition, May 1991; Reaffirmed
May 2012 (``API 6.1''). This standard describes the design,
installation, calibration, and operation of a LACT system.
API MPMS Chapter 7, Temperature Determination; First Edition, June
2001; Reaffirmed February 2012 (``API 7''). This standard describes the
methods, equipment, and procedures for determining the temperature of
petroleum and petroleum products under both static and dynamic
conditions.
API MPMS Chapter 7.3, Temperature Determination--Fixed Automatic
Tank Temperature Systems, Second Edition, October 2011 (``API 7.3'').
This standard describes the methods, equipment, and procedures for
determining the temperature of petroleum and petroleum products under
static conditions using automatic methods.
API MPMS Chapter 8, Section 1, Standard Practice for Manual
Sampling of Petroleum and Petroleum Products; Fourth Edition, October
2013 (``API 8.1''). This standard covers procedures and equipment for
manually obtaining samples of liquid petroleum and petroleum products
from the sample point into the primary containers.
API MPMS Chapter 8, Section 2, Standard Practice for Automatic
Sampling of Petroleum and Petroleum Products; Third Edition, October
2015 (``API 8.2''). This standard describes general procedures and
equipment for automatically obtaining samples of liquid petroleum,
petroleum products, and crude oils from a sample point into a primary
container.
API MPMS Chapter 8--Sampling, Section 3, Standard Practice for
Mixing and Handling of Liquid Samples of Petroleum and Petroleum
Products; First Edition, October 1995; Errata March 1996; Reaffirmed,
March 2010 (``API 8.3''). This standard covers the handling, mixing,
and conditioning procedures required to ensure that a particular
representative sample of the liquid petroleum or petroleum product is
delivered from the primary sample container/receiver into the
analytical test apparatus or into intermediate containers.
API MPMS Chapter 9, Section 1, Standard Test Method for Density,
Relative Density, or API Gravity of Crude Petroleum and Liquid
Petroleum Products by Hydrometer Method; Third Edition, December 2012
(``API 9.1''). This standard covers the determination, using a glass
hydrometer in conjunction with a series of calculations, of the
density, relative density, or API gravity of crude petroleum, petroleum
products, or mixtures of petroleum and nonpetroleum products normally
handled as liquids and having a Reid vapor pressure of 101.325 kPa
(14.696 psi) or less.
API MPMS Chapter 9, Section 2, Standard Test Method for Density or
Relative Density of Light Hydrocarbons by Pressure Hydrometer; Third
Edition, December 2012 (``API 9.2''), This standard covers the
determination of the density or relative density of light hydrocarbons
including liquefied petroleum gases having a Reid vapor pressure
exceeding 101.325 kPa (14.696 psi).
API MPMS Chapter 9, Section 3, Standard Test Method for Density,
Relative Density, and API Gravity of Crude Petroleum and Liquid
Petroleum Products by Thermohydrometer Method; Third Edition, December
2012 (``API 9.3''). This standard covers the determination, using a
glass thermohydrometer in conjunction with a series of calculations, of
the density, relative density, or API gravity of crude petroleum,
petroleum products, or mixtures of petroleum and nonpetroleum products
normally handled as liquids and having a Reid vapor pressure of 101.325
kPa (14.696 psi) or less.
API MPMS Chapter 10 Section 4, Determination of Water and/or
Sediment in Crude Oil by the Centrifuge Method (Field Procedure);
Fourth Edition, October 2013; Errata March 2015 (``API 10.4''). This
standard describes the field centrifuge method for determining both
water and sediment, or sediment only, in crude oil.
API MPMS Chapter 11--Physical Properties Data, Section 1,
Temperature and Pressure Volume Correction Factors for Generalized
Crude Oils, Refined Products and Lubricating Oils; May 2004; Addendum
1, September 2007; Reaffirmed August 2013 (``API 11.1''). This standard
provides the algorithm and implementation procedure for the correction
of temperature and pressure effects on density and volume of liquid
hydrocarbons that fall within the categories of crude oil.
API MPMS Chapter 12--Calculation of Petroleum Quantities, Section
2, Calculation of Petroleum Quantities Using Dynamic Measurement
Methods and Volumetric Correction Factors, Part 1, Introduction; Second
Edition, May 1995; Reaffirmed March 2014 (``API 12.2.1''). This
standard provides standardized calculation methods for the
quantification of liquids and the determination of base prover volumes
under defined conditions. The standard specifies the equations for
computing correction factors, rules for rounding, calculational
sequences, and discrimination levels to be employed in the
calculations.
API MPMS Chapter 12--Calculation of Petroleum Quantities, Section
2, Calculation of Petroleum Quantities Using Dynamic Measurement
Methods and Volumetric Correction Factors, Part 2, Measurement Tickets;
Third Edition, June 2003; Reaffirmed September 2010 (``API 12.2.2'').
This standard provides standardized calculation methods for the
quantification of liquids and specifies the equations for computing
correction factors, rules for rounding, calculation sequences, and
discrimination levels to be employed in the calculations.
API MPMS Chapter 12--Calculation of Petroleum Quantities, Section
2, Calculation of Petroleum Quantities Using Dynamic Measurement
Methods and Volumetric Correction Factors, Part 3, Proving Report;
First Edition, October 1998; Reaffirmed March 2009 (``API 12.2.3'').
This standard provides standardized calculation methods for the
determination of meter factors under defined conditions. The criteria
contained here will allow different entities using various computer
languages on different computer hardware (or by manual calculations) to
arrive at identical results using the same standardized input data.
This document also specifies the equations for computing correction
factors, including the calculation sequence, discrimination levels, and
rules for rounding to be employed in the calculations.
API MPMS Chapter 12--Calculation of Petroleum Quantities, Section
2, Calculation of Petroleum Quantities Using Dynamic Measurement
Methods and Volumetric Correction Factors, Part 4, Calculation of Base
Prover Volumes by the Waterdraw Method; First Edition, December, 1997;
Reaffirmed March 2009; Errata July 2009 (``API 12.2.4''). This standard
provides standardized calculation methods for the quantification of
liquids and the determination of base prover volumes under defined
conditions. The criteria contained in this document allow different
individuals, using various computer languages on different computer
hardware (or manual calculations), to arrive at identical results using
the same standardized
[[Page 81472]]
input data. This standard specifies the equations for computing
correction factors, rules for rounding, the sequence of the
calculations, and the discrimination levels of all numbers to be used
in these calculations.
API MPMS Chapter 13--Statistical Aspects of Measuring and Sampling,
Section 1, Statistical Concepts and Procedures in Measurements; First
Edition, June 1985; Reaffirmed February 2011, Errata July 2013 (``API
13.1''). This standard covers the basic concepts involved in estimating
errors by statistical techniques and ensuring that results are quoted
in the most meaningful way. This standard also discusses the
statistical procedures that should be followed in estimating a true
quantity from one or more measurements and in deriving the range of
uncertainty of the results.
API MPMS Chapter 13, Section 3, Measurement Uncertainty; First
Edition, May 2016 (``API 13.3''). This standard establishes a
methodology for developing an uncertainty analysis.
API MPMS Chapter 14, Section 3/American Gas Association Report No.
3, Orifice Metering of Natural Gas and Other Related Hydrocarbon
Fluids--Concentric, Square-edged Orifice Meters, Part 1, Section 12,
General Equations and Uncertainty Guidelines; Fourth Edition, September
2012; Errata July 2013 (``API 14.3''). This standard provides reference
for engineering equations and uncertainty estimations.
API MPMS Chapter 18--Custody Transfer, Section 1, Measurement
Procedures for Crude Oil Gathered From Small Tanks by Truck; Second
Edition, April 1997; Reaffirmed February 2012 (``API 18.1''). This
standard describes the procedures, organized into a recommended
sequence of steps, for manually determining the quantity and quality of
crude oil being transferred under field conditions.
API MPMS Chapter 18, Section 2, Custody Transfer of Crude Oil from
Lease tanks Using Alternative Measurement Methods, First Edition, July
2016 (``API 18.2''). This standard defines the minimum equipment and
methods used to determine the quantity and quality of oil being loaded
from a lease tank to a truck trailer without requiring direct access to
a lease tank gauge hatch.
API MPMS Chapter 21--Flow Measurement Using Electronic Metering
Systems, Section 2, Electronic Liquid Volume Measurement Using Positive
Displacement and Turbine Meters; First Edition, June 1998; Reaffirmed
August 2011 (``API 21.2''). This standard provides for the effective
utilization of electronic liquid measurement systems for custody-
transfer measurement of liquid hydrocarbons.
API Recommended Practice (RP) 12R1, Setting, Maintenance,
Inspection, Operation and Repair of Tanks in Production Service; Fifth
Edition, August 1997; Reaffirmed April 2008 (``API RP 12R1''). This
recommended practice is a guide on new tank installations and
maintenance of existing tanks. Specific provisions of this recommended
practice are identified as requirements in this final rule.
API RP 2556, Correction Gauge Tables for Incrustation; Second
Edition, August 1993; Reaffirmed November 2013 (``API RP 2556''). This
recommended practice provides for correcting gauge tables for
incrustation applied to tank capacity tables. The tables given in this
recommended practice show the percent of error of measurement caused by
varying thicknesses of uniform incrustation in tanks of various sizes.
The BLM received numerous comments addressing the incorporation by
reference documents. Several commenters were concerned that the BLM was
not incorporating the most recent versions of API standards. The API
standards are dynamic standards that are constantly being reviewed and
updated. The commenters referred to standards that were updated and
published either after the proposed rule published or during the BLM's
final internal review process before publishing the proposed rule. The
BLM generally agrees with the commenters that the latest editions of
industry standards should be incorporated and has made the change here
after reviewing the latest version of the standards to confirm they
will satisfy the applicable requirements.
Several commenters said that some of the incorporated materials in
the proposed rule were in conflict. For example, ASTM D1250-1980
version tables 5A and 6A for temperature and gravity correction factors
and API 11.1 for the correction of temperature effects on density and
volume provide differing correction factors that may result in
different corrected oil volumes. The BLM agrees with these comments and
has removed ASTM D1250-1980 tables 5A and 6A from the list of
incorporated materials. The final rule now refers to API 11.1 for
calculations of temperature and pressure effects on density and volume.
Several commenters expressed concern that the BLM will not be
updating the incorporated industry standards as new versions are
published. The BLM is aware of the need to continuously monitor the
industry standards as they are revised and updated, and intends to
draft guidance to ensure that the BLM's rules and the incorporated
standards they reference are kept up-to-date as technology and
practices change. Under the applicable IBR rules, however, the BLM
cannot automatically incorporate updated versions of standards into BLM
regulations. The rules require that BLM reference the specific version
of any particular standard being incorporated. Recognizing that these
standards are continually being updated, the BLM intends to undertake
periodic rulemakings to make corresponding updates to the relevant
regulations. In the interim, an operator could submit a request to the
PMT for a variance to comply with a newer version of a standard in lieu
of compliance with the version listed above.
Many commenters said the BLM should rewrite the rule to be less
prescriptive, to primarily reference industry standards, and to include
additional API standards that would expand industry options for
achieving accurate measurement. They argued that a highly prescriptive
rule would discourage industry from adopting new technology as it
becomes available. Upon careful consideration of these comments, the
BLM has decided to take a less prescriptive approach that will achieve
the ultimate goal of accurate measurement, while still maintaining our
requirements for an audit trail and production accountability, and that
will provide reasonable versatility for operators. The rule has been
modified to be less prescriptive than the proposed rule and includes
more industry standards that operators may choose from to comply with
the requirements of the final rule. For example, the tank gauging
section at Sec. 3174.6 has been rewritten to refer more to industry
standards and less to step-by-step instructions and requirements.
Proposed Sec. 3174.6(b)(3) had a list of requirements for taking oil
samples prior to the opening gauge and was geared towards manual tank
gauging. Section 3174.6(b)(3) of the final rule instead requires
operators to follow one of two industry standards for taking oil
samples prior to the opening gauge--API 8.1 for manual sampling or API
8.2 for sampling by automatic sampling systems. This paves the way for
operators to use hybrid tank measurement systems and any other new
technology that may come along in the coming years. Where necessary,
the rule enhances or modifies an industry standard to ensure that the
BLM's audit trail and production accountability
[[Page 81473]]
requirements relate to lease activity and are met. For example, the
rule modifies the industry standard for the tolerance on the
verification for ATG systems, from \3/16\ inch to \1/4\ inch, in response to field test data that showed properly
calibrated equipment has difficulty meeting the \3/16\ inch
tolerance specified in industry standards. Also industry standards call
for monthly ATG systems verification. This rule instead requires that
ATG systems be verified monthly or before sales, whichever is later.
This change will help smaller producers that may have sales only once
every 2 or 3 months.
Several commenters had the opposite view and said the BLM should
not incorporate industry standards, but rather make its regulations
predominantly prescriptive, explicitly stating what is allowed and
required. Their reasoning for this approach was that API RPs are
optional for industry to consider following, while industry must follow
BLM regulations. The BLM disagrees with the commenter's description of
how these rules will be applied. Under the final rule, operators are
required to comply with industry standards or practices that are
incorporated by reference. As discussed earlier, the BLM has decided to
take a less prescriptive approach and, where possible, incorporate
multiple industry standards to give operators a choice for achieving a
particular measurement standard.
Several commenters said the BLM should incorporate forthcoming
industry standards that have not yet been finalized into the rule. The
BLM cannot incorporate a standard that an industry trade association
has not yet published. An unpublished standard is subject to change. It
is possible the trade association creating the standard could
completely rewrite the draft standard after the BLM incorporated it
into this rule, in ways that would compromise the BLM's ability to
enforce audit-trail or production-accountability requirements. The BLM
disagrees with these comments and has not incorporated any unpublished
standards into the rule.
One commenter suggested the BLM not incorporate industry standards
but rather copy industry standard language directly into the rule.
Copyright restrictions prevent the BLM from taking this course of
action. Also this approach makes it harder for the BLM to update these
requirements in the future. The final rule was not revised as a result
of this comment.
Another commenter said the BLM is statutorily prohibited from
cherry-picking industry standards for inclusion in the rule--picking
and choosing which standards to apply and which to ignore. The BLM
disagrees with this comment. Some industry standards do not meet the
rule's goals and objectives and have not been incorporated. For
example, there are industry standards for turbine meters, but the BLM
does not allow these meters to be used at an FMP because, in some
situations, they do not meet the BLM's accuracy requirements.
Several commenters said that incorporating industry standards puts
an unreasonable financial burden on industry because it forces industry
to purchase the published standards from the trade groups that create
them. The BLM agrees that the cost of purchasing a complete set of
industry standards is not insignificant. However, the API provides the
public free, read-only access to most of the standards incorporated in
this final rule. In addition, all incorporated material is available
for inspection at the BLM's Division of Fluid Minerals, 20 M Street
SE., Washington, DC 20003, and at all BLM offices with jurisdiction
over oil and gas activities. It is also available for inspection at the
National Archives and Records Administration (NARA). Several commenters
stated that the BLM has not made a good effort to provide these newly
required standards for public review. The BLM disagrees with this
comment. As stated earlier, all industry standards incorporated by
reference are available for inspection at the BLM, Division of Fluid
Minerals, and at all BLM offices with jurisdiction over oil and gas
activities.
The commenter also said the documents are not available in the
BLM's Washington Office or in any particular field office. The BLM
disagrees. The documents are available for review in the BLM's
Washington Office and in all local offices that have jurisdiction over
oil and gas activities. It has come to the BLM's attention that some
local office personnel may not be aware of how to access the
incorporated standards and, as part of the implementation process for
the final rule, the BLM plans to carry out a training program to ensure
that field office staff can readily access the standards as needed.
Several commenters expressed concern about who is responsible for
complying with the incorporated standards--operators or their
contractors. The incorporated standards are regulatory requirements,
and operators are responsible for ensuring that third parties that do
not have a contractual relationship with the BLM comply with the
incorporated industry standards. Existing BLM regulations at 43 CFR
3162.3 state that a contractor on a leasehold will be considered the
agent of the operator for such operations with full responsibility for
acting on behalf of the operator for purposes of complying with
applicable laws, regulations, the lease terms, NTLs, Onshore Oil and
Gas Orders, and other orders and instructions of the AO.
Several commenters said the industry standards as written are not
enforceable by the BLM. The BLM disagrees. Many of the industry
standards employ the terms ``shall'' and ``should,'' with ``shall''
denoting a minimum requirement necessary to conform to the
specification, and ``should'' denoting a recommendation or that which
is advised, though is not required, in order to conform to the
specification. However, once the standards are incorporated into BLM
regulations, operators must comply with them whether the standard uses
the word ``shall'' or ``should.'' One commenter inquired whether
operators will be required to follow a standard, and if any deviation
from a standard is a violation. As stated previously, operators must
comply with all incorporated standards and material, and any deviation
without an approved variance is a violation.
Section 3174.4 Specific Measurement Performance Requirements
This section was previously published as Sec. 3174.3. Based on
edits made to the final rule, this section and previously published
Sec. 3174.4 have been switched. All discussion of comments here were
submitted under the previous proposed Sec. 3174.3.
Section 3174.4(a)(1) sets volume-based overall performance
standards for measuring oil produced from Federal and Indian leases,
regardless of the type of meters or measurement method used. The
overall volume uncertainty performance goals apply to volumes reported
on the OGOR Part B (Production Disposition), commonly referred to as an
OGOR B. FMPs measuring greater than or equal to 30,000 bbl per month
must achieve an overall measurement uncertainty within 0.50
percent. FMPs measuring less than 30,000 bbl per month must achieve an
overall measurement uncertainty within 1.50 percent.
Existing Order 4 has no explicit statement of performance standards.
The BLM will apply the performance standards in this final rule to FMPs
as part of the compliance process. The performance goals could result
in operating limitations (such as a minimum flow rate through the
meter); however, they could also allow flexibility for various
operational functions (for example, the
[[Page 81474]]
range of error between the meter in the field and the meter prover
between successive runs during a proving). To facilitate this process,
the BLM is developing an oil uncertainty calculator similar to the
BLM's gas uncertainty calculator currently in use. The uncertainty
calculator will be an internal tool for BLM employees to use to verify
uncertainty. Once it is developed, the uncertainty calculator will be
available for the public to review and use. The methods for calculating
uncertainty have been clarified in the final rule to be in accordance
with statistical concepts described in API 13.1, the methodologies in
API 13.3, the quadrature sum (square root of the sum of the squares)
method described in API 14.3.1; Subsection 12.3, and other methods
approved by the AO. Uncertainty indicates the risk of measurement
error. The performance standards provide specific objective criteria
against which the BLM could analyze operator requests to use new
metering technology, measurement systems, and procedures not
specifically addressed in the rule. The two-tiered uncertainty
thresholds established in Sec. 3174.4(a)(1) set the maximum allowable
volume measurement uncertainty. The BLM believes that the measurement
uncertainties established are reasonable, based on equipment
capabilities, industry standard practices and procedures, and BLM field
experience.
As noted, for FMPs measuring greater than or equal to 30,000 bbl
per month, the maximum overall volume measurement uncertainty allowed
is 0.50 percent. The BLM has established the 0.50 percent uncertainty limit based on uncertainty calculations
and public comments received on the proposed rule, discussed below. The
overall uncertainty calculation includes the effects of the meter
accuracy; maximum allowable meter-factor drift between meter provings;
the minimum standard for repeatability during a proving; the accuracy
of the pressure and temperature transducers used to determine the
correction for pressure on liquids (CPL) factors, and the correction
for temperature on liquids (CTL) factors; and the uncertainty of the
CPL and CTL calculations. The BLM chose the volume threshold of 30,000
bbl per month for this uncertainty level after determining that at this
monthly volume, a one-percentage-point decrease in the expected over-
or underpayment of royalties--from 1.5 percent to 0.5 percent--evaluated over a 5-year time frame, equals $150,000.
This $150,000 amount reflects the cost to purchase a LACT system, based
on price quotes from several distributors. In other words, requiring a
LACT system, in terms of increased accuracy, will generate benefits
that equal or exceed the cost of the new system. In making this
calculation, the BLM assumed a 5-year crude oil price average of $67.58
per bbl,\12\ and a royalty rate of 12.5 percent. FMPs with production
volumes less than 30,000-bbl-per-month production volume do not
generate sufficient volumes that the potential royalty risk justifies
installing a LACT system with an expected 5-year lifespan. As a result,
the maximum proposed overall measurement uncertainty for these FMPs is
1.5 percent. The BLM believes based on available data and
its experience that a 1.5 percent threshold is reasonable
and readily achievable by manual tank gauging. Based on the BLM's
analysis and review of comments received, the BLM determined that the
overall uncertainty of manual tank gauging ranges from 0.6
percent to 2.50 percent depending on the volume of oil
removed from the tank at the time of sale. A 0.6 percent
uncertainty results from potential measurement error applied to large
volumes, while a 2.50 percent uncertainty results from the
same potential measurement error applied to smaller volumes removed
during one load-out. The 1.5 percent uncertainty in the
final rule reflects the high average calculated uncertainty for a
typical truck load-out by tank gauging, which BLM believe is
representative of onshore operations more generally, and therefore is
an appropriate threshold to use in this rule.
---------------------------------------------------------------------------
\12\ Based on the projected nominal West Texas Intermediate
crude oil spot price published in the U.S. Energy Information
Administration's 2016 Annual Energy Outlook Reference case scenario.
---------------------------------------------------------------------------
The two-tiered uncertainty performance requirements in the final
rule reflect modifications from the proposed rule, based on comments
received. First, one commenter noted that the proposed rule did not
give guidance on how the uncertainty was to be calculated. The BLM
agrees with this comment and the final rule makes it clear that the
uncertainty is to be calculated using API 13.1, Statistical Concepts
and Procedures; API 13.3, the uncertainty methodologies; the quadrature
sum method as described in API 14.3.1, Subsection 12.3, General
Equations and Uncertainty Guidelines; or other methods approved by the
AO.
Another commenter agreed that it is appropriate to permit a certain
amount of measurement uncertainty and to utilize a tiered approach for
uncertainty based on volume. However, the commenter disagreed with the
proposed rule's three-tiered uncertainty requirement: 0.35
percent for FMPs measuring more than 10,000 bbl per month;
1 percent for FMPs measuring more than 100 bbl per month and less than
or equal to 10,000 bbl per month; and 2.5 percent for FMPs
measuring less than 100 bbl per month. The commenter said the proposed
2.5 percent uncertainty level for FMPs measuring volumes
less than 100 bbl/month is both unnecessary and counterproductive. This
commenter noted that there are a large number of older, low-volume
wells operating on BLM and tribal leases, and argued that the 2.5 percent uncertainty for those operations could cause some
low-volume operators to shut in their wells, resulting in a significant
cumulative loss of Federal revenue from royalties. Commenters instead
recommended that the BLM eliminate the lowest-volume category of the
three uncertainty levels under proposed Sec. 3174.3(a)(1). They
further recommended that all FMPs with monthly volumes averaged over
the previous 12 months that are less than 10,000 bbl/month should be
subject to an uncertainty level of 1.0 percent. The
commenters also said that this gives the BLM more discretion over when
a less stringent uncertainty level for low-volume operators is
appropriate based on site-specific factors.
The BLM partially agrees with these comments. After reanalyzing the
uncertainty data and volume thresholds, the BLM has eliminated the
lowest tier of uncertainty. However, this rule uses a 30,000 bbl per
month volume as the dividing volume between the two tiers, and sets the
uncertainty level for the highest-producing tier at 0.50
percent and the uncertainty level for the lowest-producing tier at
1.5 percent, which will be high enough for most tank-
gauging operations while still ensuring the rules achieve accurate
measurement.
The BLM chose the 30,000 bbl per month volume as the dividing line
between the two tiers, and their respective uncertainty performance
standards, based on what it would cost an operator to install and
operate a LACT system, relative to the risk that the operator would
under- or overpay royalties if measuring by tank gauging. The
calculation for this assumes: A LACT system costs $150,000 and has a 5-
year expected equipment lifespan, tank gauging results in a 1.5 percent uncertainty, the 5-year oil price averages $67.58 per
bbl, and the royalty rate is 12.5 percent. The following equation shows
the calculation used to arrive at the 30,000 bbl per month volume
[[Page 81475]]
dividing line between the two tiers of uncertainty performance
requirements:
Monthly volume = $150,000/((Uncertainty x Oil price x Royalty rate) x
60 months)
One commenter suggested that the performance standards for
uncertainty should not be less than 1.0 percent. A
performance standard of less than 1.0 percent is
excessively onerous, the commenter said, and does not provide a
substantial benefit compared to a 1.0 percent standard.
This commenter did not justify why a 1.0 percent
uncertainty standard is reasonable or how anything less is onerous. The
BLM disagrees with this comment. The root square sum method of
calculating the uncertainty of a LACT system with a PD meter configured
and operated under the requirements of Order 4 calculates an overall
uncertainty of 0.32 percent. The final rule makes only
minor changes to the Order 4 LACT requirements, so a calculated overall
uncertainty rate under this rule will be similar to the existing
requirements of Order 4. A LACT system with either a PD meter or a
Coriolis meter is very capable of achieving the 0.50
percent uncertainty when constructed and operated according to the
requirements of this rule and corresponding API standards; no change
was made as a result of this comment.
One commenter said BLM regulations do not need to specify equipment
models that are acceptable for use in custody transfer measurement when
uniform uncertainty metrics are utilized. The commenter stated that if
any equipment meets the established uncertainty-performance standards
for a measurement system, and that uncertainty can be validated and
maintained, such equipment should then be allowed to be used for oil
measurement. The BLM partly agrees with this comment, which is why this
final rule establishes a procedure whereby the PMT can review and
approve the use of new equipment and measurement methods, so long as
the new equipment and methods meet the performance uncertainty and
verifiability standards of the rule. The BLM believes that once this
equipment has been proven to be capable of meeting the uncertainty
performance and verifiability standards of this rule, then that
equipment can be approved for use.
The second part of this comment suggests that the volume
uncertainty limit of 0.35 percent in the proposed rule for
high-volume producers is excessively small (strict) for measurement
installations that measure in excess of 10,000 bbl/month. The commenter
further stated that the BLM failed to provide any basis for the
proposed allowable volume uncertainty calculations. The proposed rule
did not offer any detail as to how the uncertainty limit of 0.35 percent includes any effects of maximum allowable meter-
factor drift between meter proving, the minimum standard for
repeatability during proving the accuracy of pressure and temperature
transducers for volumetric correction, and the uncertainty in the
volume-correction factor correction. The commenter also said the BLM
did not disclose the data that it utilized to determine the 1.0 percent uncertainty limit for FMPs in the 100 to 10,000 bbl/
month range.
The BLM conducted an overall uncertainty calculation for a LACT
utilizing a PD meter operated and proven under the requirements of
Order 4. The results of this calculation provided an overall
uncertainty of 0.32 percent, which was what the BLM used to
establish the higher standard in the proposed rule. The commenter did
not provide a more appropriate uncertainty calculation to justify their
claim that 0.35 percent is excessively small for
installations that measure in excess of 10,000 bbl per month. As a
result no specific changes were made in response to this comment;
however, as noted elsewhere in this section, the BLM has modified the
uncertainty thresholds for larger-volume FMPs.
In order to identify appropriate thresholds, the BLM reviewed a
proprietary third-party uncertainty calculation for tank gauging using
Order 4 requirements for a 400 bbl tank. The results indicate that the
overall uncertainty varies depending upon the volume removed from the
tank. The overall uncertainty in the calculation varied from 0.6 percent for large volumes removed to uncertainties of 2.50 percent for very small volumes removed. The BLM reviewed
overall uncertainty calculations in order to determine reasonable
uncertainty requirement in the rule.
Several commenters said the BLM should re-evaluate its proposed
measurement uncertainty (0.35 percent), claiming the
methodology appears to be flawed. They further stated the proposed oil
measurement rule demands a level of accuracy that would not apply to
heavy oil regimes and that would increase operating costs beyond what
is necessary or of value. They suggest that operators with heavy oil
operations may receive unwarranted and costly penalties at a greater
rate than the rest of the petroleum industry, and that heavy oil
producers would be disproportionately impacted by the proposed
standard. These commenters did not submit justification for their
claims, and when the BLM contacted them to clarify this comment, they
still failed to justify or explain how heavy oil regimes would be
disproportionately impacted by the rule. No change to the rule resulted
from these comments.
One commenter requested that the 0.35 percent
performance uncertainty be adjusted to 1.0 percent for
meters measuring 10,000 barrels per day. The commenter agreed with
comments that the API submitted to the BLM on the proposed rule and
requests that the BLM use the Order 4 proving and uncertainty
performance requirements for LACT systems. The BLM has re-analyzed the
uncertainty performance requirements and volume thresholds, and, based
on the re-evaluation and other comments received showing a different
uncertainty calculation resulting in a slightly higher uncertainty than
proposed, has changed the rule's uncertainty performance standards to
encompass reasonable flexibility in evaluating alternative measurement
equipment and methods and adjusted the volume thresholds to match
volumes where the risk to royalty would equal the expense of installing
a LACT or CMS to require a more accurate measurement.
Another commenter said the overall volume uncertainty limit of
0.35 percent for measurement installations with throughputs
greater than 10,000 bbl/month is unreasonably and excessively strict,
given the potential number of sources of measurement error. The error
should be calculated to include the uncertainty from all sources of
error in the oil volumetric calculation chain. The BLM agrees in part
with the comment that a 0.35 percent uncertainty may be
somewhat strict in some applications. The 0.35 percent has
been calculated to include all sources of error in the LACT measurement
calculation chain, based on other comments providing similar
calculations. The BLM has chosen to use a slightly higher uncertainty
level in the final rule to give some leeway when considering approvals
for future measurement technology and procedures for use on Federal and
Indian leases. This commenter also suggested that systems installed at
FMPs that measure less than 100 bbl/month should have the option to pay
royalties as if they were producing at the rate of 100 bbl/month and
avoid the cost of installing measurement equipment that could make
their operations economically infeasible. The BLM
[[Page 81476]]
disagrees with the concept of paying royalties based on a fixed volume
rather than royalties based on actual measurements. In addition, if the
uncertainty standards would render a lease uneconomic, the operator can
seek an exemption from the requirements under Sec. 3174.4(a)(2). No
change to the rule resulted from this comment.
One commenter said they were unable to verify the uncertainty
levels proposed without the ``calculator'' that the BLM is developing.
This commenter created its own uncertainty calculation using the
following assumptions: A maximum allowable deviation for temperature of
0.25[emsp14][deg]F and pressure of 0.25 psi. The uncertainty was
calculated to be 0.46 percent in this one instance.
The BLM appreciates receiving this comment as it provides useful
input and actual calculation results to support the commenter's
position. As a result of this comment and further analysis, the BLM
agrees that this uncertainty calculation could reflect one possible
application and has adjusted the rule's lower overall uncertainty
performance requirements for the highest-producing tier to 0.50 percent.
One commenter expressed concern that the cost of complying with
this provision will increase as uncertainty standards are updated.
However, there is nothing in this provision that provides for the
updating of the uncertainty threshold standards.
Under Sec. 3174.4(a)(2), only a BLM State Director, with the
written concurrence of the PMT, prepared in coordination with the
Deputy Director, can grant an exception to the prescribed uncertainty
levels. Granting an exception requires a showing that meeting the
required uncertainly levels would involve extraordinary cost or
unacceptable adverse environmental effects. By having the State
Directors make these decisions, with concurrence of the PMT (prepared
in coordination with the Deputy Director), the BLM hopes to ensure that
there is consistent application of the performance standards across the
Bureau and that approvals for exceptions from the performance standards
are granted in limited circumstances. In the proposed rule, the BLM had
proposed to require concurrence from the Director; however, upon
further review, the BLM modified the written concurrence requirement to
require written concurrence from the PMT that has been prepared in
coordination with the Deputy Director. The BLM feels this approach
would be more appropriate given that the PMT will have the necessary
technical expertise, while requiring coordination with the Deputy
Director ensures such changes have the necessary national policy
perspective.
The BLM received several comments on its approach to exceptions to
the proposed rule's uncertainty limits. A few commenters requested that
the BLM clarify and limit the criteria a BLM State Director can use to
grant exceptions. The BLM does not believe additional clarification is
necessary and the rule's description of potential extraordinary
circumstance(s) that could result in an exception to the uncertainty
levels is sufficient. The BLM cannot identify every situation or event
that could warrant an exception. The intent of the rule is that an
exception is not a normal occurrence, and to allow exceptions only in
limited, special circumstances. No change to the rule resulted from
this comment.
Similarly, another commenter urged the BLM to clarify the manner in
which exceptions may be granted and to clearly define the term
``extraordinary cost.'' According to this commenter, a lack of clear
guidance on these exceptions will result in unrealistic expectations
from operators and inconsistent application by the BLM. Again, there
could be numerous circumstances under which an exception could be
warranted, and the BLM cannot accurately anticipate and address all of
these in the rule. It will be up to the individual or entity applying
for the exception to make the case to justify an exception. The process
for granting exceptions is more likely to be consistent if decisions
are left to State Directors, with written concurrence from the PMT
(prepared in coordination with the Deputy Director). No change to the
rule resulted from this comment.
One commenter questioned why, on the one hand, the proposed rule
would have authorized BLM State Directors to grant exceptions to
uncertainty standards for equipment at FMPs (with BLM Director
concurrence) and on the other hand, the rule at Sec. 3174.4(d) gives
the PMT the authority to recommend and the BLM to decide whether
proposed alternative equipment or measurement procedures meets or
exceeds the uncertainty standards. The commenter questioned a process
that will rely on the availability of the PMT and State Directors to
review and evaluate requests for exceptions. The commenter said BLM
technical experts are often overworked, and therefore the PMT approval
process is likely to take a considerable amount of time and hinder
operators' ability to effectively develop Federal oil and gas
resources. The BLM agrees that its technical experts have a significant
workload and face a number of competing demands. However, one reason
for creating a BLM-wide PMT is to relieve field offices of having to
review new technology, and to provide a consistent BLM-wide decision-
making process. The BLM believes that this structure should minimize
the amount of time it will take for the BLM to process requests for
evaluation of new equipment, and to evaluate requests for exemptions
from the uncertainty requirements. No change to the rule resulted from
this comment.
Section 3174.4(b) establishes the degree of allowable bias in a
measurement. Bias differs from uncertainty in that bias results in
systematic measurement error, whereas uncertainty only indicates a risk
of measurement error. While the BLM acknowledges that it is virtually
impossible to remove all bias in measurement, the final rule requires
that there be no statistically significant bias at any FMPs. When a
measurement device is tested against a laboratory device or prover,
there is often slight disagreement, or apparent bias, between the two.
However, both the measurement device being tested and the laboratory
device or prover have some inherent level of uncertainty. If the
disagreement between the measurement device being tested and the
laboratory device or prover is less than the uncertainty of the two
devices combined, then it is not possible to distinguish apparent bias
in the measurement device being tested from inherent uncertainty in the
devices (sometimes referred to as ``noise'' in the data). Therefore,
the BLM does not consider apparent bias that is less than the
uncertainty of the two devices combined to be statistically significant
for purposes of compliance with the final rule. However, if the shift
in the mean value of a set of measurements away from the true value of
what is being measured exceeds the ``statistically combined
uncertainty'' of the devices, then the BLM requires that known shift to
be corrected to as close to the actual value as possible.
The BLM received several comments concerning bias. The first
commenter stated the rule does not give any guidance on how bias will
be determined, or what the BLM considers to be statistically
significant. In order for the bias restriction to be applied uniformly
throughout the nation, the commenter asserted that the term needs to be
defined in the regulation. The BLM agrees with this comment and has
added a new definition for ``bias'' to 43 CFR subpart 3170, as part of
the
[[Page 81477]]
rulemaking that is updating and replacing Order 3.
Another commenter noted that the BLM presented no data or
calculations in the proposed rule to verify that bias issues will not
exist under field conditions where many additional variables impact the
statistical calculations. The commenter claimed that the rule
essentially assumes that uncertainties that can be demonstrated in
laboratory conditions can also be demonstrated in field conditions,
which are not practical in a production scenario. The commenter asked
that the BLM delete paragraph (b) from the final rule. The BLM does not
agree with this comment. If a shift in the mean value of a set of
measurements away from the true value of what is being measured,
exceeds the statistically combined uncertainty of the devices, occurs,
then the BLM requires that known shift to be corrected to as close to
actual value as possible. An example of where this shift could be
discovered is during a transducer verification that results in a
reading that is outside of the device's stated uncertainty. This is
different from uncertainty, where a potential for measurement error
exists. No change to the rule resulted from this comment.
A third commenter recommended that the BLM clarify language in the
preamble that discusses statistically significant bias. As noted above,
the preamble quantifies statistically significant bias as being a
number that is greater than the combined uncertainties of the
laboratory device, or prover, and the measured device, or the
``statistically combined uncertainty.'' The BLM recognizes that there
will always be some apparent bias resulting from the uncertainty of all
devices. Bias is only considered significant when it exceeds the
combined uncertainties of the devices involved. The BLM believes that
the final rule accurately explains bias in terms of it being outside of
the ``statistically combined uncertainty'' of the devices being used.
No change to the rule resulted from this comment.
Section 3174.4(c) requires that all measurement equipment be
subject to independent verification by the BLM that it is performing
accurately and that all inputs, factors, and equations that are used to
determine quantity or quality are valid. Order 4 already requires that
the BLM be able to independently verify measurement methods, as well as
bias, so these are not new requirements. The verifiability requirement
in this section prohibits the use of measurement equipment that does
not allow for independent verification. For example, if a new meter
were to be developed that did not record the raw data used to derive a
volume, that meter could not be used at an FMP because without the raw
data the BLM would be unable to independently verify the volume.
Similarly, if a meter were to be developed that used proprietary
methods that precluded the ability to recalculate volumes, its use
would also be prohibited.
The BLM received several comments about the verifiability
requirements of this rule. One commenter seemed to suggest that the BLM
did not take into account the use of automation and other measurement
systems advances, such as the use of flow computers handling
calculations. The comment further stated that in order to retain the
raw data that the BLM needs to manually verify equipment accuracy,
operators will be required to use computers that are less efficient and
that require more data storage. The BLM agrees that the rule may
require operators to acquire more data storage, but does not agree with
the commenter that saving raw data for future verification will result
in less efficient flow computers, or that it is unnecessary. The BLM
manages Federal oil resources on behalf of the American taxpayer and
has an affirmative obligation to ensure that the oil produced is
accurately measured and accounted for. In order to satisfy those
obligations it is critically important that an audit trail exists so
that the BLM can verify the production data. As a result, the BLM will
continue to manually verify calculations at FMPs. No change to the rule
resulted from this comment.
Another commenter suggested any verifiability does not take into
account the difference between live calculations at high frequencies
versus averaged and accumulated data over time. The commenter also said
that independent calculations should only have to fall within a
statistically insignificant window. In order for independent
calculations to be applied uniformly throughout the nation, they should
to be defined in the regulations, the commenter said. The BLM partly
agrees with this comment that calculations should be live calculations
at high frequencies or calculations averaged and accumulated over time.
The Inspection and Enforcement Handbook will address possible methods
for the BLM to verify calculations at an FMP. No changes to the rule
were made as a result of this comment, but the BLM will include
guidance in the Inspection and Enforcement Handbook regarding whether
calculations should be based on live calculations or averaged over
time. Under the final rule, all volume calculations at an FMP must be
verifiable.
One commenter asked whether the requirement that new equipment
undergo independent verification will preclude new technology. The BLM
does not intend to prevent or exclude new technology. In fact, this
rule, by establishing performance standards, adopting industry
standards, and standing up the PMT process, has been designed
explicitly to provide flexibility for the BLM to adopt new technology
and practices as they are developed. No changes were made in response
to this comment.
Another commenter said that paragraph (c) would require the BLM to
contract with an independent laboratory to verify equipment, which
could take 6 months per device and cost upwards of ``$500M'' for each
device. The BLM disagrees with this comment because Sec. 3174.4(c)
merely requires operators to have FMP equipment that can produce the
source records that provide the data and equations the BLM needs to
independently recalculate oil production volume and quality during
production audits. No changes were made in response to this comment.
Section 3174.4(d) clarifies that the operator can propose the use
of alternative equipment, provided that it meets or exceeds the
uncertainty requirements of this section. The PMT will make a
determination under Sec. 3174.13 of this subpart regarding whether
proposed alternative equipment or measurement procedures meets or
exceeds the objectives and intent of this section. See Sec. 3174.13
for discussion of comments concerning the PMT and the PMT review
process.
Section 3174.5 Oil Measurement by Tank Gauging--General Requirements
Section 3174.5(a) specifies the general requirements for oil
measurement by tank gauging as a means to accurately determine the
quantity and quality of oil removed from an FMP. The BLM received many
comments on this section of the proposed rule. Almost all of these
comments requested that the BLM consider permitting the use of ATG
systems for custody transfer applications. Order 4 allows only manual
tank gauging. In the proposed rule, the BLM indicated that it was
considering including provisions in the final rule allowing for the use
of ATG systems, and requested data regarding whether these systems can
meet the BLM's performance standards for manual tank gauging with
respect to uncertainty and verifiability. The BLM requested additional
data regarding ATG measurement systems because it recognizes the
significant safety advantages they provide.
[[Page 81478]]
The majority of the commenters indicated that ATG systems are much
safer for workers when compared to manual tank gauging systems,
especially when workers are measuring hydrocarbon fluids such as those
found in the Bakken, which have higher gravity and higher vapor
pressure, and thus emit higher volumes of toxic fumes. The BLM agrees
that safety concerns associated with manual tank gauging can be reduced
if operators have the option of using ATG systems as well as the other
measurement methods addressed in this final rule. Based on data
provided in response to the proposed rule--both as public comment on
the proposed rule and in support of project-specific variance requests
to use ATG systems on tanks--the BLM has determined that ATG systems
can meet or exceed the uncertainty thresholds for tank gauging. As a
result, the rule has been changed to allow for the use of ATG systems.
The BLM received one comment that recommended the BLM prohibit the
practice of oil measurement by manual tank gauging because, according
to the commenter, the practice is an antiquated and considerably less
reliable method of measurement. The BLM disagrees that properly
conducted manual tank gauging operations are antiquated or less
reliable than other methods of measurement and will continue to give
operators the option of using this widely accepted practice for oil
measurement, which is generally used at lower-volume facilities.
However, the BLM hopes for a shift towards ATG in areas where the
nature of the produced oil presents a safety concern.
In the proposed rule, Sec. 3174.5(b) required that all oil storage
tanks, hatches, connections, and other access points be vapor tight and
that each oil storage tank, unless connected to a vapor recovery
system, must have a pressure-vacuum relief valve installed at the
highest point in the vent line or connection with another tank.
Pressure-vacuum relief valves would provide for normal inflow and
outflow venting at an outlet pressure that is less than the thief hatch
exhaust pressure and at an inlet pressure that is greater than the
thief hatch vacuum setting. The intent is to minimize hydrocarbon gas
lost to the atmosphere by ensuring that venting is done under
controlled conditions through the pressure-vacuum relief valve
primarily in response to changes in ambient temperature. The
requirement that all access points be vapor tight has been expressly
included in this rule in order to eliminate confusion over the intent
of Order 4, which specified all the same equipment, but did not specify
the manner in which it was supposed to be operated. The implied intent
of Order 4 was always that the tanks be operated such that they are
vapor tight.
The BLM received numerous comments on this section, the majority of
which said the proposed requirements could conflict with U.S.
Environmental Protection Agency (EPA) air quality regulations and the
BLM's separately proposed Methane and Waste Prevention Rule (81 FR
6616). Some of the same commenters also complained about the potential
costs associated with retrofitting some of the tank batteries. The BLM
disagrees with these comments. The intent of the requirement is to
conserve the quantity and quality of the liquid hydrocarbons in storage
by controlling the storage conditions, not to create a potential
conflict with the EPA's regulations for release of harmful pollutants.
The BLM also disagrees with claims made by some commenters that the
potential costs associated with retrofitting existing tank batteries to
make them vapor-tight would be too high. Pressure vacuum vent line
valves and thief hatches are already required equipment for the
existing tank battery installations under Order 4. Paragraphs (b)(3)
and (4) of the proposed rule have been changed and merged into a new
paragraph (b)(3) in the final rule, which now requires that all oil
storage tanks be vapor tight, and, unless connected to a vapor recovery
or flare system, must have a pressure-vacuum relief valve installed at
the highest point in the vent line or connection with another tank. All
hatches, connections, and other access points must be installed and
maintained in accordance with manufacturers' specifications.
Several commenters recommended that the BLM add the requirement
that oil storage tank hatches (``thief hatches'' or other access
points) have pressure indicators that provide a clear and immediate
visual indicator of tank pressures and potential gas/vapor release
hazard should the tank need to be accessed. One of the commenters said
pressure indicators on tank access hatches visually display the
presence of gas/vapor pressure in a tank, allowing a trained worker to
make risk-based decisions before accessing a tank, including actuating
a remote venting valve, venting gas to a flare, or using appropriate
respiratory protection, such as a self-contained breathing apparatus or
an air-line respirator. The BLM recognizes that having such information
could potentially be useful to personnel in the field; however, the BLM
did not make any changes in response to this comment because the
pressure indicators proposed by the commenter would have no bearing on
determining measured volume, and therefore are outside the scope of
this rule. It should also be noted that in general the Occupational
Safety and Health Administration takes the lead on adopting and
enforcing employee safety requirements.
Several commenters stated it is imperative that tanks be maintained
vapor tight and that there be a monitoring or inspection program to
ensure compliance. The BLM agrees and the final rule has maintained the
vapor tight integrity requirement for oil storage tanks. The BLM's
inspection and enforcement program will continue to ensure compliance
with this and all other oil and gas regulations. No additional changes
were made to the final rule as a result of these comments.
One commenter stated that if the oil is weathered or stabilized,
there is no need for hatches and other connections to be vapor tight.
The commenter did not explain how weathered or stabilized oil could
negate the need for hatches and other connections to be vapor tight.
The BLM disagrees that stabilized product does not require a vapor-
tight storage condition. The vapor tight integrity is an implied
requirement of the current Order 4 and therefore will not require the
operator to retrofit any existing equipment. In a unique situation
where a variance could be justified, the operator could seek a variance
through the appropriate BLM field office following the process outlined
in Sec. 3170.6 of this part, a related rulemaking that is replacing
Order 3, with approval by the AO. No additional changes were made to
the final rule. This section in the final rule is now identified as
Sec. 3174.5(b)(3).
Section 3174.5(b)(5) of the proposed rule specified that all oil
storage tanks must be clearly identified and have a unique number
stenciled on them, maintained in a legible condition. Order 4 did not
have a similar requirement. The BLM received several comments that said
this section did not adequately communicate how the numbering system
would work and how numbers are assigned to the tanks. The BLM agrees
that this section was not clear. As a result of these comments, the
final rule has been changed to specify that all oil storage tanks must
be clearly identified with an operator-generated number that is unique
to the lease, unit PA, or CA stenciled on the tank and maintained in a
legible condition. This section now appears as Sec. 3174.5(b)(4) in
the final rule.
[[Page 81479]]
Section 3174.5(b)(6) of the proposed rule required each oil storage
tank associated with an approved FMP by tank gauging to be set and
maintained level. Several commenters said this requirement is
unwarranted and unnecessary without offering any details. The BLM
disagrees, as this is not a new requirement. Order 4 has a similar
requirement, and the BLM believes that not requiring a tank to be set
or maintained level would be unacceptable because it could result in
uncertainty in measurement. Industry standards also dictate that tanks
used for gauging operations should be level. No change resulted from
these comments. This section now appears as Sec. 3174.5(b)(5) in the
final rule.
Section 3174.5(b)(7) of the proposed rule specified each oil
storage tank associated with an approved FMP that has a tank-gauging
system must be equipped with a distinct gauging reference point, with
the height of the reference point stamped on a fixed bench-mark plate
or stenciled on the tank near the gauging hatch, and maintained in a
legible condition. One commenter, without offering any justification,
said this requirement should apply only to tanks that are manually
gauged. The BLM disagrees as this gauging reference point is also
needed during the verification and calibration of an ATG system, not
just for tanks that are measured by manual gauging. No change was made
to the final rule as a result of this comment. This section now appears
as Sec. 3174.5(b)(6) in the final rule.
Section 3174.5(c) in the proposed rule required the operator to
accurately calibrate each oil storage tank associated with an approved
FMP that has a tank-gauging system, under either API 2.2A or API RP
2556. Order 4 had a similar requirement. The BLM received a few
comments on this section. One commenter pointed out that under the
proposed rule, sales tank calibrations apparently can only be made
using API MPMS Chapter 2.2A--Tank Strapping by Manual Method, when in
fact other methodologies in Chapter 2 are available. The BLM agrees
that industry standards provide additional methods for calibrating
sales tanks. As a result of this comment, the BLM changed the final
rule to incorporate industry standards API 2.2A, API 2.2B, or API 2.2C;
and API RP 2556. One commenter stated the proposed rule did not clarify
when or how often a sales tank calibration is required. The BLM
disagrees. Section 3174.5(c)(2) clearly states when a sales tank
calibration is required--if the tank is relocated, repaired, or the
capacity is changed as a result of denting, damage, installation,
removal of interior components or other alterations. No changes were
made to the final rule as a result of this comment.
One commenter said operators should be allowed to use formulas for
estimating tank volumes. The formula of 1.67 bbl/inch is a tool
operators use to estimate the volume stored in the tank. When the oil
is sold, the commenter said, a more accurate measurement will be taken,
ensuring that the operator is properly paid for the oil being sold,
which will in turn result in the correct royalty payment to the
government. This rule seeks to ensure accurate oil measurement, not
volume estimates. This comment is not relevant to sales tank
calibration. The final rule was not changed as a result of this
comment.
Section 3174.5(c)(1)(i) of the proposed rule specified the
strapping table unit volume must be in barrels. The BLM received no
comments and made no changes to this paragraph.
Section 3174.5(c)(1)(ii) of the proposed rule specified the
incremental height measurement on all tanks must be in \1/8\-inch
increments. This was a change from the incremental height measurement
in Order 4 of \1/4\-inch gauging accuracy for tanks of 1,000 bbl or
less in capacity. The BLM received many comments on this section. The
commenters consistently addressed the following two main points: (1)
The benefits from the increase in accuracy would be minimal in
comparison to the time and costs it would take to achieve the increased
accuracy; and (2) The change would require operators to re-strap their
tanks and generate new tank tables, and, in many cases, make major
changes to their software programs, all at substantial costs. The BLM
agrees that the costs of a change to \1/8\-inch increments for tank
gauging on tanks that are 1,000 bbl or less in capacity is unnecessary
because the additional cost burdens outweigh any potential accuracy
gains. As a result of these comments, the rule has been changed to say
that the incremental height measurement must match the gauging
increments specified in Sec. 3174.6(b)(5)(i)(C), which requires \1/4\-
inch increments for tanks 1,000 bbl or less in capacity, and \1/8\-inch
increments for tanks greater than 1,000 bbl in capacity. This is the
same accuracy standard that has been in effect under Order 4. The BLM
would like to note that API industry standards relative to manual tank
gauging have conflicting tank-gauging increments. The BLM has chosen to
retain the current Order 4 gauging increments requirement by following
API 18.1 tank gauging increments for tanks that are 1,000 bbl and less
and API 3.1A tank gauging increments for tanks greater than 1,000 bbl.
Section 3174.5(c)(2) requires operators to recalibrate a sales tank
if it is relocated or repaired, or the capacity is changed as a result
of denting, damage, installation, removal of interior components, or
other alterations. Order 4 had a nearly identical requirement. The BLM
received a few comments on this section, all of which said there is no
definition of how large the dent or alteration would need to be to
trigger this requirement. The commenters also stated that the BLM must
clarify the amount of volume displacement that would require action on
the part of the operator. The final point that the commenters made also
suggested that the BLM should offer a range of options that operators
could take in response to denting, including tank inspection, and
provide them an opportunity to avoid being in violation. For example,
an insulated tank may be dented on the outside but the dent would have
no impact on the inside due to several inches of insulation. Upon
review of these comments, the BLM has made no change to the rule for
the following reasons. The volume displacement from tank denting cannot
be known until the dent has been measured and the impacts analyzed. To
measure the impacts, this section requires re-strapping of the tank.
The BLM has chosen not to allow an operator to ``estimate'' the impact
of denting on a tank used for tank gauging as there would be no
enforceable requirement to properly determine the resulting volume
impacts. Denting of the insulation on a tank may or may not result in
denting of the sales tank. If denting is observed on the insulation of
a tank, it is the operator's responsibility to verify that no internal
tank denting has occurred under the insulation.
Section 3174.5(c)(3) requires operators to submit sales tank
calibration charts (tank tables) to the AO within 30 days after
calibration. Order 4 required them to be submitted to the AO upon
request. The BLM received several comments on this section. A few
commenters recommended extending the 30-day time period to 45 days to
allow for more coordination time between transporter and operator.
After considering these comments, the BLM agrees that transporters and
operators may need more time to submit the tank tables to the BLM. As a
result of these comments, the final rule now requires that tank tables
must be submitted to the AO within 45 days after calibration. Tank
tables may be in paper or electronic format. A couple of
[[Page 81480]]
commenters said this requirement is another example of the BLM getting
into the day-to-day operations of industry. They said there is
absolutely no reason for the BLM to have these charts, argued that they
serve no purpose, suggested that this requirement is excessively
prescriptive, and asked the BLM to justify the need for the charts. Oil
tanks are constructed to API standards and have a common, industry-wide
standard strapping chart, the commenters said, and these tanks are not
proven once installed. The BLM disagrees with these comments, as the
tank calibration charts (tank tables) are in fact unique for each tank,
and therefore there should not be a common, industry-wide standard
strapping chart in use where tank gauging is the method of measurement
at an FMP. The BLM has a long history of using the tank tables on a
daily basis for production verification efforts, such as during
production inspections and records-analysis audits. No changes were
made to the final rule as a result of these comments.
The BLM has an affirmative obligation to maintain an audit trail
supporting Federal and tribal oil production. A couple of commenters
requested that the BLM continue to use the Order 4 requirement that
operators submit their latest tank calibration charts when the AO
requests them, in order to avoid confusion and give operators notice
that an inspection is imminent. The BLM disagrees because the new
requirement will serve as verification that the operator has had the
tanks strapped as required, and enables the BLM to perform the required
inspection activities. Additionally, the BLM has no obligation to
provide operators notice that an inspection is imminent.
One commenter said marginal producing leases should be exempt from
tank-gauging requirements. The BLM disagrees. Marginal leases are
already subject to tank-gauging requirements. Under this final rule,
operators on marginal-producing leases are allowed to continue using
manual tank gauging, which imposes only modest economic impact on these
leases.
Section 3174.6 Oil Measurement by Tank Gauging--Procedures
Section 3174.6 paragraphs (a) and (b) require operators to take the
steps in the order prescribed in the following paragraphs to manually
determine by tank gauging the quality and quantity of oil measured
under field conditions at an FMP. The BLM received several comments on
this section. The comments said the detailed tank-gauging procedures in
this section do not align with the industry standard. The BLM partly
agrees, in that industry standards for certain activities have several
options for operators to follow for achieving the desired outcome. The
proposed rule did not reflect all of those options. As a result of
these comments, the final rule has been changed to reference the
appropriate industry standards and remove any unnecessarily
prescriptive requirements to ensure accurate measurement using tank
gauging.
Section 3174.6(b)(1) contains the requirement in Order 4 and the
proposed rule that the tank be isolated for at least 30 minutes to
allow contents to settle before proceeding with tank gauging
operations. The BLM received a couple of comments on this section. The
commenters said this requirement would be costly and is unnecessary, as
this activity will not increase the accuracy of measurements. The BLM
disagrees. This requirement will ensure that the tank is isolated and
that the crude oil layer is still, with no surface foaming. In many
liquid manual sampling applications, the product to be sampled contains
a heavy component (such as free water) that tends to separate from the
main component. In these instances, it should be recognized that until
the heavy component completely settles out, sampling will likely result
in varying sample qualities. No change was made to the final rule as a
result of these comments.
Section 3174.6(b)(2) contains the requirements for determining the
temperature of oil contained in a sales tank that is used as an FMP.
Operators must comply with paragraphs (b)(2)(i) through (iii) of this
section and API 7 and API 7.3. The BLM received numerous comments on
this section. Several commenters requested that the BLM eliminate the
reference to mercury in paragraph (b)(2)(i). In the proposed rule, that
paragraph required glass thermometers to be clean, be free of mercury
separation, and have a minimum graduation of 1.0[emsp14][deg]F. The BLM
agrees that the mercury reference should be removed because the EPA has
banned mercury thermometers from use. As a result of these comments,
the final rule has been changed to say that glass thermometers must be
``free of fluid separation.''
The BLM received a comment concerning paragraphs (ii) through (iv),
which said the reported graduation and accuracy requirements for
temperature measurement devices are different based on the technology
employed (minimum graduation of 1.0 [deg]F for liquid-in-glass
thermometer vs. minimum graduation of 0.1 [deg]F for portable
electronic thermometers (PET)). The commenter did not elaborate, but we
assume the commenter believes PETs should be as accurate as glass
thermometers. This comment is not consistent with the mandate of
keeping the uncertainty in the measured quantity to within a specified
value, nor is it consistent with existing industry standards (API MPMS
Chapter 7). The BLM disagrees in part with this comment since the BLM
used the minimum graduations from the industry standard, of 1.0 [deg]F
for glass and 0.1 [deg]F from electronic thermometers. For consistency,
and as a result of this comment, the BLM is requiring an accuracy of
0.5 [deg]F for both glass and electronic thermometers.
Several commenters questioned the thermometer immersion times
required in the proposed rule under paragraph (b)(2)(iii), which
referenced API 7, Table 6. They also asked the BLM to allow alternate
methods for determining opening oil temperatures, to alleviate
potential safety and economic concerns. The BLM disagrees in part as
the immersion times are an industry standard, but also agrees in part
to allow alternate methods under API 7. The prescriptive requirements
under paragraph (b)(2)(iii) have been removed because the final rule
already states that operators must comply with API 7, which includes
the Table 6 requirements. Furthermore, the BLM changed the rule to give
operators more flexibility by allowing them to use alternate methods
for temperature determinations under API 7 and API 7.3, as well as the
option of using ATG/hybrid tank measurement systems, in order to
address the safety concerns identified by commenters. As a result of
these comments and changes, the final rule eliminates paragraph
(b)(2)(iii) of the proposed rule, resulting in the renumbering of
paragraph (b)(2)(iv) in the proposed rule to paragraph (b)(2)(iii) in
this final rule.
Section 3174.6(b)(3) of the proposed rule specified that sampling
of oil removed from an FMP tank must yield a representative sample of
the oil and its physical properties, and must comply with the
procedures listed in paragraphs (i) through (iii) of this section and
API 8.1. The BLM received several comments requesting that the final
rule give operators other sampling options. The BLM agrees that other
sampling options can still achieve the desired measurement uncertainty.
As a result of these comments, the BLM removed the prescriptive
requirements in paragraphs (b)(3)(i) through (iii), and added a
reference to API 8.2's standards for automatic sampling procedures to
the final rule.
[[Page 81481]]
Section 3174.6(b)(4) of the proposed rule specified that tests for
oil gravity must comply with paragraphs (b)(4)(i) through (iv) of this
section and API 9.3. The BLM received a couple of comments on this
section. One commenter said that API Chapter 9 contains additional
methods for determining gravity that can be more appropriate to use
(based on the conditions of the oil at sample time). Therefore, the
commenter asserted that the final rule should simply specify that any
API Chapter 9 methodology is appropriate for determining gravity. The
commenter said the procedure outlined in the proposed section was not
consistent with API 9.3. Another commenter stated that proposed
paragraph (b)(4)(i), which required the use of a thermohydrometer for
API gravity (density) measurement, would limit the use of new,
automated, more accurate technology such as Coriolis meters and density
gauges. The commenter said allowance should be made for other methods
that can meet the uncertainty requirements of the regulation. The BLM
agrees that this provision of the proposed rule was too prescriptive
and unnecessarily limited potential compliance options. As a result of
these comments, the following changes were made to the final rule:
This section now incorporates by reference API 9.1, API
9.2, or API 9.3 to allow additional methods to measure API gravity;
Paragraph (b)(4)(i) is changed to include the use of a
hydrometer in addition to a thermohydrometer;
Proposed paragraph (b)(4)(ii) has been removed consistent
with the BLM's determination that the provision was too prescriptive;
Proposed paragraph (b)(4)(iii) is now paragraph (b)(4)(ii)
and has been revised to require operators to allow the temperature to
stabilize for at least 5 minutes; and
Proposed paragraph (b)(4)(iv) is now paragraph (b)(4)(iii)
and has been revised to require operators to read and record the
observed API oil gravity to the nearest 0.1 degree, and to read and
record the temperature reading to the nearest 1.0 [deg]F.
Section 3174.6(b)(5) of the proposed rule required operators to
take and record the tank opening gauge only after upper, middle, and
outlet samples have been taken. It further required gauging to comply
with paragraphs (b)(5)(i) through (b)(5)(v) of this section and API
3.1A. One commenter said the opening measurement should be taken with a
matched (bob and tape) and currently ``certified'' gauging tape. The
comment recommended that the rule specify that the tape and bob shall
be certified within the last year as specified in API 3.1A. The BLM
agrees with this recommendation, as it is consistent with API
standards. As a result, the BLM has included API 3.1A in this paragraph
and has eliminated prescriptive language that repeats API 3.1A.
Similar to the proposed rule, Sec. 3174.6(b)(5)(i) of the final
rule contains the requirements for manual gauging. But in response to
commenters' requests that the BLM allow automatic and hybrid tank
gauging, as discussed earlier in this preamble, this section in the
final rule includes a new paragraph (b)(5)(ii), which contains the
requirements for ATG. During the initial years of rule implementation,
the BLM will not limit which ATG makes or models operators can use, but
starting 2 years after the effective date of this rule, operators will
only be permitted to use the ATG makes and models that the BLM approves
for use and lists on its Web site. To ensure that ATG equipment in use
at that time meet with BLM approval, the BLM encourages operators,
manufacturers, or other entities (e.g., trade associations) to pursue
equipment approval prior to use. Paragraph (b)(5)(ii) identifies
requirements for inspecting and verifying the accuracy of ATG systems
and for maintaining a log of field verifications.
Section 3174.6(b)(6) of the proposed rule required operators to
determine S&W content using the oil samples in the centrifuge tubes
collected from the upper and outlet fluid column (see paragraph (b)(3)
of this section), and determine the S&W content of the oil in the sales
tanks, according to paragraphs (b)(6)(i) through (iii) of this section
and API 10.4. The BLM received a few comments on this section. The
commenters all addressed the fact that API 10.4 has been updated since
the BLM published the proposed rule, and that the prescriptive
requirements in paragraphs (b)(6)(i) through (iii) were not consistent
with the revised industry standard. The BLM agrees that the API
standard has been updated and that the requirements in paragraphs
(b)(6)(i) through (iii) of the proposed rule are too prescriptive and
inconsistent with the revised industry standard. Based on its review of
the revised standard and as a result of these comments, the BLM removed
the prescriptive requirements in paragraphs (b)(6)(i) through (iii).
The final rule requires operators to determine S&W content by using API
10.4, which has been incorporated into the final rule by reference.
Without saying why, one commenter said the BLM should incorporate
all sections of API Chapter 10 into the final rule. The BLM disagrees.
Since the oil measurement at issue in this rule is inherently a ``field
procedure,'' in which the S&W content is required to be determined and
documented on the run ticket at the completion of the tank gauging/
custody transfer procedure, the BLM determined that the only applicable
section is 10.4. This comment did not result in a change to the final
rule.
Section 3174.6(b)(7) requires operators, after conducting the S&W
determination, to conduct the transfer operation and seal the effected
valves under Sec. Sec. 3173.2 and 3173.5 of this part. There were no
comments to this section.
Section 3174.6(b)(8) requires operators to determine the tank
closing temperature following procedures discussed in paragraph (b)(2)
of this section. Any comments concerning temperature determination have
been addressed earlier in the paragraph (b)(2) discussion.
Section 3174.6(b)(9) requires operators to take the closing gauge
using procedures in paragraph (b)(5) of this section. Any comments
concerning gauging operations have been addressed in the paragraph
(b)(5) discussion.
Section 3174.6(b)(10) requires operators to end their tank-gauging
operations by completing a measurement ticket in accordance with Sec.
3174.12. The proposed rule included seven activities in paragraphs
(b)(10)(i) through (vii) that dictated how operators should derive the
data required for the measurement tickets. Some commenters said this
list of activities was too prescriptive. In an effort to be less
prescriptive, the BLM deleted paragraphs (b)(10)(i) through (vii) in
the final rule and refers operators to the rule's measurement-ticket
requirements.
Section 3174.7 LACT System--General Requirements
Paragraphs (a) through (c) of this section in both the proposed and
final rule refer operators to other sections of this rule for
construction and operation requirements for LACT systems, proving
requirements, and measurement tickets. The proposed rule in paragraph
(a) included a reference to API standards and in paragraph (c) a table
that listed the requirements and components of a LACT system, along
with references to the sections of the proposed rule containing the
minimum standards for each of those components. The BLM received
several comments on these paragraphs.
Several commenters said the BLM should not be so prescriptive and
should instead require compliance with
[[Page 81482]]
the appropriate API standards. In general, the BLM agrees that
following published industry standards can result in the desired
measurement uncertainty, and paragraph (a) of the final rule now
requires LACTs to meet the standards prescribed in the applicable API
sections. Paragraph (b) of the final rule requires LACTs to be proven
as prescribed in Sec. 3174.11 of this subpart. The proposed table of
``Standards to measure oil by a LACT system'' from paragraph (c) has
been removed. Although it was a handy reference that directed readers
to requirements that were listed in other sections of the proposed
rule, the table was redundant and unnecessary. Paragraph (c) in the
final rule now refers to the requirement for completing measurement
tickets under Sec. 3174.12(b).
Several commenters were uncertain about whether the LACT
requirements only applied to new facilities, with existing facilities
grandfathered. Most of the commenters also suggested that bringing
existing facilities into compliance within the 180-day implementation
timeframe was either too expensive, impossible, or both. In response to
these comments, and as discussed previously in this preamble, the BLM
has clarified in the final rule that all facilities are subject to the
new requirements, with operators required to come into compliance on a
staggered schedule of between 1 and 4 years, depending on their levels
of production. This was achieved by tying compliance to the requirement
to apply for an FMP found in the new 43 CFR subpart 3173. These
significantly extended time frames will give operators time to plan and
budget for expenses in advance, while limiting the chances that there
will be local or national shortages of equipment or technical
expertise, as might have resulted from the original proposed, 180-day
implementation period.
Several commenters noted that in proposed paragraph (c), the BLM
limited LACTs to those with PD meters, and suggested that other types
of meters should be allowed. Most of those commenters specifically
requested that Coriolis meters be allowed, but some requested that any
type of meter permitted in API standards be allowed. This would include
PD, Coriolis, and turbine meters. The BLM partly agrees and has changed
the rule to allow Coriolis meters to be used with LACTs. However, the
BLM does not agree that turbine meters should be allowed. In the BLM's
experience, confirmed by many industry sources, turbine flowmeters are
less accurate than PD and Coriolis meters and are more subject to wear
and/or damage. As a result, the BLM will continue to disallow turbine
meters in LACTs. The change to allow Coriolis meters in LACTs is found
in Sec. 3174.8(a)(1). The definition of, proving standards for, and
other specific requirements related to the use and operation of
Coriolis meters are addressed by other sections of the final rule.
One commenter stated that Sec. 3174.7(b) would require operators
to generate an additional run ticket before proving, and that the BLM
should take into account the additional cost associated with that extra
run ticket. The BLM did analyze the financial impacts of increased run
tickets in its Paperwork Reduction Act analysis, which was discussed in
the proposed rule preamble. Another commenter pointed out that this
additional run ticket is unnecessary in LACTs with flow computers as a
flow computer is capable of implementing a new meter factor in the
middle of a month without the operator having to close it. The BLM
agrees and as a result of this comment, the BLM changed Sec.
3174.12(b)(1) of the rule to remove the requirement that operators
close a run ticket prior to proving LACT systems that utilize flow
computers, which will reduce the overall cost to operators.
One commenter said the BLM should remove requirements in proposed
Sec. Sec. 3174.7(c) and 3174.8(b)(7) for S&W monitors at LACTs because
there is no such thing as an ``S&W monitor.'' There are water monitors
or water probes, the commenter continued, but water monitors are not
part of any oil measurement system. Rather, operators use water
monitors to divert the flow back to tanks for additional processing to
remove large amounts of water from their production stream. The BLM
agrees with this commenter's assessment. From a regulatory perspective,
a water monitor should not be required equipment at a LACT because it
does not help the BLM verify accurate measurement and net oil volumes.
In the final rule, the BLM has incorporated LACT requirements from API
6.1 and eliminated the table in Sec. 3174.7(c), along with the S&W
monitor requirements in Sec. 3174.8(b)(7).
Section 3174.7 paragraphs (d) and (e) retain current requirements
that all components of a LACT system be accessible for inspection by
the AO and that the AO be notified of all LACT system failures that may
have resulted in measurement error. Numerous commenters stated that the
term ``notify'' in paragraph (e)(1) was ambiguous and requested that
the BLM define what forms of notification are acceptable and the time
frame for notifying the AO. The BLM agrees that this term needs to be
defined and has defined ``notify'' to mean ``to contact by any method,
including but not limited to electronically (email), in-person, by
telephone, by form 3160-5 (Sundry Notice), letter, or Incident of
Noncompliance.'' This definition has been added to the definitions
listed in 43 CFR 3170.3, part of the rulemaking that is replacing Order
3.
Numerous commenters stated that the 24-hour time frame in proposed
paragraph (e)(1) regarding notifying the BLM of LACT system failure
was: (1) Impractical, (2) Too restrictive; (3) Potentially unnecessary
if the failure was small (less than 0.05 percent); (4) Unlikely to
significantly affect the net oil volume; (5) Too expensive for
operators to implement because additional monitoring equipment would be
required; and (6) Would require speculation on the part of the
operators as to when a malfunction occurred when no one was present at
the time of the malfunction. Most commenters suggested requiring
reporting within 7 days after discovery. The BLM partly agrees, and
paragraph (e)(1) of the final rule now requires notification within 72
hours after discovery. This time frame will ensure that the BLM is able
to verify that all oil volumes are properly derived and accounted for,
and verify any alternative measurement method, meter repairs, or meter
provings within a reasonable time frame without placing unnecessary
burdens on the operator. Requiring notification within 72 hours will
allow operators to deal with urgent situations while still being able
to timely notify the BLM.
Section 3174.7 paragraph (f) of the proposed rule would have
retained the current Order 4 requirement that any tests conducted on
oil samples taken from the LACT system samplers for determination of
temperature, oil gravity, and S&W content meet the same minimum
standards set in the manual tank gauging sections. However, the section
of the preamble describing proposed Sec. 3174.7(f) incorrectly said
the oil samples themselves had to comply with the standards in the
manual tank gauging section, rather than the testing procedures used to
measure temperature, gravity (density), and S&W content. One commenter
pointed out that this section not only incorrectly implied that
temperature is somehow calculated from the oil in the sample pot, it
also incorrectly referred to the standard testing procedures designed
for manual tank gauging, not for testing using automated samplers as
required in LACTs. The commenter stated that the BLM should use the
standards in API
[[Page 81483]]
8.1 for static (manual) tank gauging and the standards in API 8.2 and
API 8.3 for automatic sampler systems in LACTs, rather than referencing
incorrect methods. The BLM agrees that the proposed rule preamble
contains an incorrect summary of the actual proposed regulatory
requirement in Sec. 3174.7(f), and that the correct reference should
be API 8.1 for sampling in static (manual) sampling and API 8.2 and API
8.3 for automatic sampler systems within LACTs. With this
clarification, Sec. 3174.7(f) in the final rule remains unchanged,
although the recommendation to incorporate API 8.2 and API 8.3 by
reference is accepted. The reference to this requirement is in Sec.
3174.8(b)(1).
Paragraph Sec. 3174.7(g) prohibits the use of automatic
temperature/gravity compensators on LACT systems. Although Order 4
requires these devices, this rule will require those automatic
compensators to be replaced using an electronic temperature averaging
device. Automatic temperature/gravity compensators are designed to
automatically adjust the LACT totalizer reading to compensate for
changes in temperature and, in some cases, for changes in oil gravity
as well. Unfortunately, the accuracy or operation of these devices
cannot be verified in the field and there is no record of the original,
uncorrected, totalizer readings. As a result, there is no ability to
create an audit trail for these systems. As explained in the proposed
rule, the BLM believes that the use of these devices inhibits its
ability to verify the reported volumes because there is no source
record generated, and the devices degrade the accuracy of measurement.
Because there are relatively few LACT systems that still employ
automatic temperature/gravity compensators, the BLM does not believe
this requirement will result in significant costs to the industry.
Several commenters objected to this requirement, stating that
temperature averagers are expensive and not necessarily any more
accurate than temperature compensators, and that this change would
require operators to replace functioning equipment at significant cost
for no readily apparent benefit. One commenter stated that existing
equipment should be grandfathered as long as an audit trail exists, and
that the BLM should provide scientific evidence that automatic
temperature/gravity compensators are less accurate than temperature
averaging devices. Other commenters said that the simultaneous demand
for temperature averaging devices would drive up the cost of purchasing
and installing these devices on LACT systems. Several commenters
indicated that rather than bear such a cost, some operators would
choose to shut in wells and cease production activities.
In response to these comments, the BLM conducted field surveys of
the companies that made the comments and determined that, in fact, they
had very few LACTs that are still using automatic temperature/gravity
compensators. Indeed, one of the companies had only one such LACT. The
fact that very few LACTs still use automatic temperature/gravity
compensators was confirmed by a major LACT manufacturer who stated that
they sell very few automatic temperature/gravity compensators
domestically, and that nearly all LACTs are currently equipped with
temperature averagers. Further, this rule now provides for a phase-in
of this new equipment over the next 1 to 4 years, based on when
operators receive their FMP approvals, and the cost is relatively
inexpensive (roughly $6,500 per LACT for the equipment). Regarding
scientific studies or other data showing temperature averagers are more
accurate, the BLM is not aware of any studies that show this. The main
reason for the prohibition is that a temperature compensator is a
mechanical device that does not have the capability for recording an
``audit trail,'' and therefore is inconsistent with the BLM's
production accountability obligations. For these reasons, no change was
made in this final rule.
Section 3174.8 LACT System--Components and Operating Requirements
Section 3174.8 contains LACT system components and operating
requirements.
This section is closely related to Sec. 3174.7 in that Sec.
3174.7 contains general requirements for LACTs and states that LACTs
must meet the construction and operation requirements and minimum
standards of Sec. 3174.8. Section 3174.8 goes into detail on what
those requirements and standards are. Consequently, many of the
comments on this section are closely related to comments received on
Sec. 3174.7.
In the proposed rule, Sec. 3174.8(a) listed the components that
each LACT must include. Several commenters said the BLM should not be
so prescriptive and should instead require operators to comply with the
appropriate API standards. One commenter stated this change would
eliminate confusion and make it clear that Coriolis meters would be
allowed as part of LACTs. In general, the BLM agrees that the original
language was too prescriptive and may have inadvertently disallowed the
use of Coriolis meters with LACTs. As a result of these comments, the
final rule now simply requires LACTs to meet the standards prescribed
in the applicable API sections. The list of all of the components
required in LACTs has now been deleted from paragraph (a) and replaced
with a statement that each LACT must include all equipment listed in
API 6.1, with certain listed exceptions. The LACT components listed in
Sec. 3174.8(a) are related to requirements for PD and Coriolis meters
and electronic temperature averaging devices, and allow multiple means
of applying back pressure to the LACT to ensure single-phase flow.
LACTs must consist of meters that have been reviewed by the PMT,
approved by the BLM, and identified and described on the nationwide
approval list at the BLM Web site (www.blm.gov) (see Sec.
3174.8(a)(1)). Initially, the BLM will have no PD or Coriolis meter
make or models limitations, but starting 2 years after the effective
date of the rule, operators can only use the PD or Coriolis meter makes
and models that the BLM approves for use and lists on its Web site. To
ensure that specific PD and Coriolis meters in use at that time meet
with BLM approval, the BLM encourages operators, manufacturers, or
other entities (e.g., trade associations) to pursue equipment approval
prior to use.
One commenter stated that proposed Sec. 3174.8 did not refer to
industry standards for automatic sampling systems used with LACT and
Coriolis meter systems, and that failure to provide minimal
requirements could result in samples which were not representative, and
therefore erroneous. The commenter also stated that proposed paragraph
(b)(4), pertaining to standards for mixing of samples, should instead
prescribe compliance with API 8.3, which contains the appropriate
standards. Another commenter stated that proposed Sec. 3174.8(a) did
not mention an inline mixer or any pressure/temperature
instrumentation, and asked if these items were prohibited or just not
considered necessary. The same commenter stated that proposed Sec.
3174.8(b)(2) discussed sample probe locations when standards for
automatic sampling had not yet been incorporated into the rule, and
requested that rather than restating portions of the standards in the
rule, the BLM should incorporate API MPMS Chapters 8.2 and 8.3 into the
rule.
The BLM agrees with the points raised in these comments and so, in
the interest of eliminating uncertainty and errors, the final rule
includes industry
[[Page 81484]]
standards for automatic sampling systems and for mixing of samples. The
final rule now includes a requirement that sampling and mixing of
samples must comply with the standards in API 8.2 and API 8.3,
respectively.
One commenter stated that the requirement in proposed Sec.
3174.8(a)(10) and (b)(13) to have a back pressure valve and check valve
downstream of the LACT could be met by allowing operators to use
another common industry practice of placing a pump downstream. The BLM
agrees that this arrangement would meet the intent of the requirement,
which is to ensure single-phase flow through the meter, and has changed
the rule accordingly. The revised requirement is more flexible and is
found in the renumbered final rule at Sec. 3174.8(a)(3).
One commenter noted that in proposed Sec. 3174.8(a)(7), the BLM
limited LACTs to only using a PD meter, and said that any type of meter
permitted in API standards should be allowed. These standards include
PD, Coriolis, and turbine meters. The BLM partly agrees and has changed
the rule to allow Coriolis meters because field and laboratory testing
have proven the Coriolis meter to be reliable and accurate. However,
the BLM does not agree that turbine meters should be allowed. In the
BLM's experience, confirmed by many industry sources, turbine
flowmeters are less accurate and are more subject to wear or damage. As
a result, the BLM will continue to prohibit the use of turbine meters
in LACTs. The change to allow Coriolis meters in LACTs is reflected in
Sec. 3174.8(a)(1) of the final rule. References to the definition of,
proving standards for, and other specific requirements for Coriolis
meters are contained throughout the rule in appropriate sections.
Section 3174.8(b) describes the system operating requirements for
LACTs. Multiple comments were received on this section, many of which
focused on making the requirements less prescriptive and instead
referencing API standards more extensively.
In general, in response to numerous comments that the proposed rule
lacked flexibility, we have removed most of the prescriptive
requirements in proposed Sec. 3174.8(b). This section now requires
operators to follow the sampling-process standards in API 8.2 and API
8.3 (the equipment and procedures to obtain and properly mix a
representative sample); the standards for measuring the gravity
(density) and S&W content of those samples in API 9.1, API 9.2, API
9.3, and API 10.4; the standards for flow measurement using electronic
meter systems in API 21.2; the standards for temperature determination
in API 7; and the standards for calculating net oil volumes for each
run ticket in API 12.2.1 and API 12.2.2. All of these API standards are
incorporated by reference and listed in Sec. 3174.3.
One commenter objected to the BLM's requirement in proposed Sec.
3174.8(b)(1) that LACTs include an electrically driven pump sized to
ensure: (1) A discharge pressure compatible with the meter used; and,
(2) That the flow in the LACT main stream piping is turbulent, such
that the measurement uncertainty levels proposed in Sec. 3174.3 are
met. Instead, the commenter suggests that the BLM should require LACTs
to meet uncertainty requirements without being so prescriptive. Another
commenter stated that the BLM should be more flexible about the types
of S&W monitors that would be allowed under proposed Sec. 3174.8(b)(7)
because some manufacturers do not make the types of plastic-coated
probes that this section required. The commenter also suggested that
existing S&W monitoring technologies should be grandfathered. Several
other commenters stated that the requirement for a back pressure valve
in proposed Sec. 3174.8(b)(13) was too prescriptive and did not give
operators the flexibility to use other methods to achieve the same
result that back pressure valves provide--maintaining single-phase
(oil-only) flow through the LACT meter. As discussed earlier, the BLM
is keeping the requirement that LACT systems contain a back-pressure
valve in the final rule at Sec. 3174.8(a)(3), but we agree with
commenters that the requirement needs to be more flexible, and we have
added language that gives operators the option of using other
controllable means of applying back pressure to ensure single-phase
flow. Also in response to these comments, the BLM removed most of the
prescriptive requirements in proposed Sec. 3174.8(b) and replaced them
with a requirement that operators meet the LACT system operating
standards outlined in the applicable API standard incorporated by
reference into the proposed rule. The only requirements that are
spelled out in paragraph (b) are those requirements that are in
addition to or different from standard API practices or that clarify
which API standards are applicable.
Several commenters expressed concern that retrofitting or replacing
existing equipment to meet the requirements of Sec. 3174.8 was
unnecessary and prohibitively expensive, and that existing facilities
should be grandfathered, with some also suggesting that bringing
existing facilities into compliance within the proposed 180-day
implementation timeframe was either too expensive, impossible, or both.
In response to these comments, the BLM has clarified in Sec. 3174.2 in
the final rule that all equipment must comply with the new
requirements, with operators required to come into compliance on a
staggered schedule of between 1 and 4 years, depending on when they
receive their FMP approvals, which is based on their production levels.
This significantly extends the compliance timeframe and gives operators
time to budget and plan for any required changes, while limiting the
chances that there will be local or national shortages of equipment or
technical expertise, such as might have resulted from the proposed 180-
day implementation period.
One commenter stated that proposed Sec. 3174.8(b) should be
revised to include a densitometer as optional equipment in the list of
components, and that if density is provided, recordable, auditable, and
verifiable, then the sampler and sample pot should not be required,
which would save operators the cost of those components and lab
analyses to determine S&W content. The commenter further said that if
the sampler is not included in the list of components, then S&W content
must be reported as zero percent, and the entire volume passing through
the LACT meter would be reported as 100 percent oil. The BLM
understands that there may be cases in which the operator would be
willing to consider the entire produced stream as 100 percent oil, but
the BLM believes that omitting the sampler and sample pot would create
the potential for added confusion, and it is likely that most
purchasers are going to require a sample grind-out anyway. For these
reasons, no change was made to the rule as a result of this comment.
One commenter pointed out that proposed Sec. 3174.8(b)(11)(ii),
which required a temperature averaging device to take a temperature
reading at least once per barrel, did not accord with API 21.2,
Subsection 9.2.8.1, which requires such devices to be flow proportional
and take a reading at least once every 5 seconds. The BLM agrees and
has changed the rule accordingly. This provision in the final rule has
been renumbered as Sec. 3174.8(b)(6)(ii) and now reads: ``The
electronic temperature averaging device must be volume-weighted and
take a temperature reading following API 21.2, Subsection 9.2.8
(incorporated by reference, see Sec. 3174.3).''
[[Page 81485]]
Sections 3174.9 and 3174.10 Coriolis Measurement Systems
Sections 3174.9 and 3174.10 pertain to CMS, which are not addressed
in Order 4. Order 4 allows only for the use of PD meters with LACT
systems. The use of Coriolis meters in this rule is based on
technological advancements that provide for measurement accuracy that
meets or exceeds the overall performance standards in Sec. 3174.4.
Field and laboratory testing of Coriolis meters has proven them to be
reliable and accurate meters when installed, configured, and operated
correctly.
One commenter said the final rule should allow operators to use
truck-mounted CMS and submitted summarized data to support their view.
The summarized data indicates significant differences between manual-
gauged volumes and truck-mounted Coriolis-metered volumes. A summary of
these volume differences indicated that the truck-mounted Coriolis
meter measured as much as 22.44 bbl less that the manual gauge
measured. Missing from the data is the volume of the entire load. The
BLM needs this information to understand how significant these
variations are. The data also indicates significant differences in
measured oil temperature (as much as 23 [deg]F) and gravity (as much as
5 degrees) when compared to manual methods. The commenter did not
explain these differences or explain or justify the data submitted. The
BLM decided not to include the use of truck-mounted Coriolis metering
in the final rule. Operators may seek approval to use the truck-mounted
option through the PMT approval process, which is outlined in Sec.
3174.13. The rule was not changed based on this comment.
Another commenter suggested that the CMS could be used for gas
measurement, in addition to oil measurement. The BLM has noted this
comment; however, this subpart is dedicated to the measurement of oil.
The rulemaking that is replacing Order 5 is a more appropriate venue
for considering this comment, and this comment was directed to that
rule team. The comment did not result in a change to this rule.
Several commenters stated that the term ``CMS'' should not be used
for a Coriolis LACT as it is simply a LACT. The BLM agrees with this
comment and has no intention of replacing the term ``LACT'' with the
term ``CMS.'' The rule as proposed was intended to allow the Coriolis
meter to be used in a LACT as an alternative to the PD meter, or as a
standalone meter independent of a LACT system. The term CMS refers only
to the latter option. To clarify this issue, the final rule has been
edited to state that a Coriolis meter may be used in a LACT or as a
standalone CMS meter.
Section 3174.9(b) specifies that Coriolis meters that have been
reviewed by the PMT, approved by the BLM, and identified and described
on the nationwide approval list at the BLM Web site (www.blm.gov) are
approved for use. Initially, the BLM will have no Coriolis meter make
or model limitations on the approved list, but starting 2 years after
the effective date of the rule, operators will only be able to use the
Coriolis meter makes and models that the BLM approves for use and lists
on its Web site. To ensure that specific Coriolis meters in use at that
time meet with BLM approval, the BLM encourages operators,
manufacturers, or other entities (e.g., trade associations) to pursue
equipment approval outlined in Sec. 3174.2(g) prior to use.
Installations meeting the requirements described in this section and
Sec. 3174.10 do not require additional BLM approval. CMS proving must
meet the proving requirements described in Sec. 3174.11 and
measurement tickets would be required, as described in Sec.
3174.12(b).
One commenter said requiring each operator to have its CMS approved
would result in a large financial burden. The BLM disagrees because the
PMT only needs to approve a particular make or model of Coriolis meters
once. Once a meter make or model has been reviewed, approved, and
posted on the BLM's Web site, the meter can be installed at any
facility, subject to any COAs imposed by the PMT for its use. Existing
installations that already meet the requirements in Sec. Sec. 3174.9
and 3174.10 do not require additional BLM approval.\13\
---------------------------------------------------------------------------
\13\ Additional comments on the PMT and the procedure that the
PMT will use to approve devices are addressed in the discussion of
Sec. 3174.13.
---------------------------------------------------------------------------
Section 3174.9(c) requires that a CMS be proved following the
frequency established under Sec. 3174.11. This proving frequency will
ensure that operators periodically prove the CMS to provide
verification that the meter is within the allowable tolerances. There
were no comments on this section.
Section 3174.9(d) requires that measurement (run) tickets be
completed as required by Sec. 3174.12(b). This establishes the
measurement-ticket time periods and minimum requirements for
information that must be included on the tickets. There were no
comments on this section.
Section 3174.9(e) identifies the applicable API standards for the
components that must be installed with a CMS at an FMP, and includes
some additional requirements that operators using a CMS for oil
measurement must follow. The proposed rule listed the components in
exact order from upstream to downstream of a CMS. The BLM has opted to
be less prescriptive in the final rule and is requiring operators to
follow API 5.6 for the setup and installation of a CMS system.
One of the prescriptive requirements in proposed Sec. 3174.9(e)(7)
was for operators to install a density measurement verification point.
One commenter asked that this term be defined. Since the BLM has
removed the prescriptive requirements and this particular term from the
rule, a definition is no longer needed. No change resulted from this
comment.
Another commenter said the BLM needs to allow for a connection
point for a pycnometer. As discussed earlier, the BLM has removed the
prescriptive, step-by-step requirements in this section. Should an
operator wish to use this density-determination option, API 5.6 does
allow for a density verification point that could be used as the point
for installing the pycnometer. There was no change to the rule as a
result of this comment.
Section 3174.9(e)(1) and (2) sets accuracy thresholds for
temperature and pressure measurement devices that are part of a CMS.
These devices are required to calculate the CPL and CTL correction
factors. The uncertainties of these devices will be used in the overall
uncertainty calculation to ensure that the CMS meets or exceeds the
uncertainty levels required by Sec. 3174.4. There were no comments on
this section.
Section 3174.9(e)(3) covers the options for handling S&W content
when determining net volume. Measurement by LACT requires a composite
sampling system and determines net oil volume by deducting S&W content.
The CMS does not require a composite sampling system, but rather leaves
the option to the operator to either install a composite sampling
system to determine S&W content for deduction in net oil determination
or to make no S&W content deduction in net oil determination. In
practice, Coriolis meters may be used at the outlet of a separator. It
may not be feasible to use a composite sampling system at the outlet of
a separator due to high separator pressure, thus effectively precluding
the ability to determine S&W content. Without the ability to accurately
determine S&W content, Sec. 3174.9(e)(3) will require operators to
report the S&W content as zero. The BLM may consider options to use
other
[[Page 81486]]
methods to determine S&W content should acceptable technology or
processes be proposed in the future. However, the BLM will only approve
an alternate method of S&W content determination if the resulting
overall measurement uncertainty is within the limits of Sec.
3174.4(a).
Several commenters stated that if the rule does not allow
corrections for S&W content, operators will be required to report an
inaccurate volume. The BLM agrees that failing to correct for S&W
content could result in an inaccurate measurement of net volume of
product sold. However, this rule gives the operator the option to
determine S&W content; if the operator chooses not to install the
necessary equipment to determine the accurate S&W content, then no
deduction will be allowed. The inclusion of the CMS as a method to
measure production does not make this the sole means of measurement. It
will be at the discretion of the operator to determine which method of
measurement is most effective for their operation. In certain
operations where a composite sampling system cannot be installed, and
the operator determines reporting S&W content as zero is inappropriate
for their operation, other measurement options may be available, though
the operator will have to seek review through the PMT. No change to the
rule resulted from these comments.
Relatedly, several commenters stated that the BLM should allow
other methods to determine S&W content. The BLM agrees that other
methods could be allowed, but the BLM does not currently have the data
to review those options. As noted, under the final rule, an operator
wishing to use a different option for determining S&W content will have
to seek approval through the PMT process, as outlined in Sec. 3174.13.
No change resulted from this comment.
Section 3174.9(e)(4) requires single-phase flow through the CMS by
means of applied back pressure. The proposed rule would have required
operators to use a back pressure valve downstream of the Coriolis meter
to achieve single-phase flow. Several commenters stated that there are
other means of applying back pressure that are just as effective as
using a back pressure valve, such as pumps downstream of the CMS. The
BLM agrees and has changed the rule as a result of this comment.
Instead of allowing only a back pressure valve, the BLM will allow the
operator to use any means to apply sufficient back pressure to ensure
single phase flow, so long as the approach meets the requirements of
API 5.6.
Section 3174.9(f) allows the API oil gravity to be determined by
using one of two methods: (1) From a sample taken from a composite
sample container; or (2) Directly from the average density measured by
the Coriolis meter. This choice accommodates situations in which it is
not feasible or an operator chooses to not install a composite sampling
system due to economic or operating constraints. The BLM may consider
other methods for determining the API gravity of the fluid, such as in-
line densitometer devices. However, the BLM will only approve
alternative methods if resulting overall uncertainty is within the
limits in Sec. 3174.4.
One commenter suggested that the BLM should incorporate by
reference the guidelines in API 8.2 and API 8.3 on composite sampling.
Because a sample from a composite sample container is an acceptable
method for determining the API oil gravity, the BLM agrees that the
industry standard should be included and has incorporated API 8.2 for
automatic sampling and API 8.3 for mixing and handling of samples into
Sec. 3174.8(b)(1) of the final rule.
Another commenter stated that the use of Tables 5A and 6A is
inappropriate and that the flowing density should be corrected in
accordance with API 11.1. The BLM agrees that Tables 5A and 6A are
outdated and should not be used and has removed the language that
referenced Tables 5A and 6A and replaced it with a reference to API
11.1.
Another commenter stated that abnormal events should be excluded
from the average density calculation. The BLM assumes the commenter is
referring to the fact that water, sand, or gas breakout may occur
during a normal flowing regime. Excluding these abnormal events from
the average density is allowed under the final rule, so long as an
audit trail is maintained showing the full-flow density, including the
period of flow that has been removed from the average density
calculation. There is no change to the final rule as a result of this
comment.
Another commenter said that during proving, a density correction
factor should be applied if the densitometer within the Coriolis meter
varies from a master densitometer at the density verification point.
The BLM disagrees with this comment. During the proving verification of
the densitometer within the Coriolis meter, the density reading is
compared to an independent density measurement. The difference between
the indicated density determined from the Coriolis meter and the
independently determined density must be within the specified density
reference accuracy specification of the Coriolis meter. If the Coriolis
densitometer exceeds the manufacturer's specification density
tolerance, then the meter must be repaired or replaced, or an
alternative method of density determination must be approved for use.
Any alternative method must result in an overall uncertainty that is
within the limits in Sec. 3174.4.
Section 3174.9(g) requires that the net standard volume be
calculated following API 12.2.1 and API 12.2.2. The proposed rule
listed this requirement in Sec. 3174.10(g) and gave very prescriptive
requirements for the calculation. However, in order to make the final
rule less prescriptive and to rely on industry standards wherever
possible and appropriate, the requirement has been moved to Sec.
3174.9(g), and the prescriptive language has been removed in favor of
the guidelines listed in API 12.2.1 and API 12.2.2.
Several commenters said that net standard volume cannot be
calculated by current Coriolis meters or any flow meter for that
matter. The BLM agrees with these comments and for that reason there
are no requirements in this rule that the CMS, or any meter, calculate
and display net standard volume. No change was made to the rule as a
result of these comments.
Another commenter stated that operators should be allowed to apply
a shrinkage factor to the net standard volume. The BLM disagrees
because past experience in reviewing net oil determinations shows that
applying a calculated shrinkage factor results in very high uncertainty
for the metering systems. The resulting overall uncertainty would
exceed the limits of Sec. 3174.4. Should new methods or technology for
applying shrinkage factors be developed and proposed for use in the
future, the PMT process described in Sec. 3174.13 would be used for
review and approval of those methods or technologies. No change to the
final rule has been made as a result of this comment.
Sec. 3174.10 Coriolis Meter for LACT and CMS Measurement
Applications--Operating Requirements
Section 3174.10(a) establishes the minimum pulse resolution (i.e.,
the increment of total volume that can be individually recognized,
measured in pulse per unit volume) of 8,400 pulses per barrel for CMSs.
Because this resolution is standard for PD meters, and is accepted by
the BLM, the same standard applies to CMSs. The BLM did not receive
comments on this section.
Section 3174.10(b) establishes the minimum standards and
specifications
[[Page 81487]]
for specific makes, models, and sizes of Coriolis meters. The
specifications will allow the BLM to determine the overall measurement
uncertainty of the CMS, to ensure that it meets the requirements of
Sec. 3174.4, and to help insure that the meters are properly
installed.
One commenter recommended that the BLM remove the requirement for
maintaining and submitting to the BLM upon request the Coriolis meter
specifications found in Sec. 3174.10(b). The commenter said this
requirement is not necessary for uncertainty-based measurement limits.
The BLM disagrees. In order for the BLM to conduct a complete
inspection of the CMS, it is necessary that all information required by
this section be available to ensure that the Coriolis meter is
operating within its design parameters, on which the uncertainty for
the meter is based. No change in the final rule was made as a result of
this comment.
Proposed Sec. 3174.10(b)(iv) required that the minimum amounts of
straight piping be installed upstream and downstream of the meter.
Several commenters said that Coriolis meters do not require any
specific amount of straight piping. The BLM agrees that pipe-length
restrictions in Coriolis meter installations do not affect accurate
measurement and has removed any reference to straight-pipe requirements
for Coriolis meters from the rule.
Section 3174.10(c) requires a non-resettable totalizer for
indicated volume. This is to allow verification over multiple run
tickets of gross production prior to any adjustments to net standard
volume. There were no comments on this requirement.
Proposed Sec. 3174.10(c) had a requirement for meter orientation.
One commenter said the BLM should remove this requirement because it is
too prescriptive and should instead require operators to follow API
standards. The BLM agrees that the proposed language was too
prescriptive. The final rule, in Sec. 3174.10(e), now requires
operators to follow API 5.6.
Section 3174.10(d) of the proposed rule required that the operator
must notify the AO within 24 hours of any changes to any Coriolis meter
internal calibration factors including, but not limited to, meter
factor, pulse-scaling factor, flow-calibration factor, density-
calibration factor, or density-meter factor. One commenter suggested
that 24 hours is an unreasonably short period of time for this
requirement, especially if the applicable changes occur on a weekend.
The commenter recommended a period of at least 10 days, or a monthly
report from the PLC log. After consideration of this proposed
requirement, the submitted comment, and the proving requirements in the
final rule, the BLM has decided to remove this notification requirement
from the rule because any changes to a Coriolis meter internal
calibration factor will require immediate proving of the meter as
required in Sec. 3174.11(d)(8). An additional notification provides no
benefit to the BLM.
Section 3174.10(d) (paragraph (f) in the proposed rule) requires
verification of the meter zero reading before proving the meter or any
time the AO requests it. The proposed rule described the process for
verifying the meter zero value. The BLM has changed the wording in the
final rule to be less prescriptive and to require the operator to
follow manufacturer guidelines. This gives the operator flexibility
during the verification procedure.
Several commenters said that requiring flow to be stopped during
meter verification is an additional step and may disrupt normal
operations. The BLM agrees that in order to verify that the meter is
operating within the manufacturers' specifications, operators are
required to verify the meter zero with no fluid flow. However, the BLM
disagrees that meter zero verification is a disruption to normal
operations. According to API standards and manufacturer
recommendations, Coriolis meter zero verification is a part of normal
operations. As discussed above, the final rule has been changed to
require operators to follow manufacturer guidelines for meter zero
verification; however, the requirement to verify meter zero remains in
the final rule.
Section 3174.10(e)(1) through (e)(4) (paragraphs (i)(1) through
(i)(4) in the proposed rule) lists the information that the Coriolis
meter must display onsite. As part of the BLM's verification process
during field inspections, the AO must be able to access this
information without the use of a laptop or other special equipment. A
log must be maintained of all meter factors, zero verifications, and
zero adjustments, and must be made available to the AO upon request.
The proposed rule would have required operators to maintain the log
onsite.
The BLM received several comments stating that the requirement for
a log to be maintained onsite containing the meter factor, zero
verification, and zero adjustments is not practical. Because this
information will not need to be readily available onsite for the AO to
complete an inspection, the BLM agrees with the commenters and has
changed the final rule in Sec. 3174.10(e)(4) to require that the log
containing the meter factor, zero verification, and zero adjustments
must be made available upon request.
One commenter stated that the requirement in paragraph (e)(2) for
the meter to display the instantaneous pressure has no valid use. The
BLM disagrees with this statement as this information is needed as part
of routine inspections conducted by the AO to verify the flowing volume
in a meter. No changes were made as a result of this comment. Another
commenter said that some Coriolis meters do not have the ability to
display the density in pounds per barrel as originally required by the
proposed rule. After contacting Coriolis system manufacturers, the BLM
has confirmed that not all Coriolis meters have the ability to display
this particular unit of measurement. Therefore, as a result of this
comment, the requirement to display the density in pounds per barrel
has been removed and other units of measurement (pounds per gallon or
degrees API) have been added in Sec. 3174.10(e)(2)(i). One commenter
said that daily volume totals may not be available for display. The BLM
contacted manufacturers and confirmed that Coriolis meters are capable
of displaying daily volume totals. As a result, there was no change in
the final rule from this comment.
Section 3174.10(f) requires that audit trail information listed in
Sec. 3174.10(f)(1) through (4) be retained for the time period
required in Sec. 3170.7, which is part of the rulemaking to replace
Order 3. One commenter said that the requirements in Sec.
3174.10(f)(2) and (4) may force operators to add a flow computer to a
Coriolis LACT, which exceed the requirements of a PD LACT. This comment
does not make sense because a Coriolis meter almost always has a flow
computer. If an operator chooses to configure a Coriolis meter in a
LACT without utilizing a flow computer, and display only a totalizer
reading, then the requirements of Sec. 3174.10(f)(2) and (4) would not
apply. No change resulted from this comment.
Section 3174.10(g) requires that each Coriolis meter have an
operable backup power supply or nonvolatile memory capable of retaining
all data. This is to ensure that during a failure, all audit trail data
is preserved to maintain compliance with these regulations. There were
no comments on this section.
Section 3174.11 Meter-Proving Requirements
Proposed Sec. 3174.11(a) and (b) would have established that a
meter would not be eligible to be used for royalty determination unless
it is proven to the
[[Page 81488]]
standards detailed in the proposed rule. The BLM received no comments
on these paragraphs. The final rule specifies the minimum requirements
for conducting volumetric meter proving for all FMP meters. Paragraph
(a) in the proposed rule was carried forward to the final.
A table in proposed paragraph (b) referred readers to the
applicable paragraphs of this proposed section that contained the
minimum standards for proving FMP meters. The BLM received no comments
on this table. Nevertheless, the BLM did not include the paragraph (b)
table in the final rule because the table did not provide substantive
clarity or expedite reader access to the relevant paragraphs. This
change resulted in the re-lettering of all subsequent section
paragraphs in the final rule.
Paragraph (c) in proposed Sec. 3174.11 (re-lettered to paragraph
(b) in the final rule), established the acceptable types of meter
provers that can be used to prove an FMP LACT or CMS. The BLM received
a few comments objecting to the meter-proving requirements in this
section of the final rule because they are not consistent with the
referenced API specifications. These comments are addressed in the
following text.
Section 3174.11(b)(1) through (3) of the final rule describe and
detail the requirements for acceptable meter provers, which include the
master meters and displacement provers that are currently allowed under
Order 4. Coriolis master meters, which were not addressed in Order 4,
have been included in the final rule. The BLM believes that Coriolis
technology has advanced to the point where Coriolis meters meet the
accuracy and verifiability requirements required for master meters. The
final rule does not allow tank provers to be used as an acceptable
device for proving a meter. According to API standards, tank provers
are not recommended for use on viscous liquids, which include most
crude oils. Because there are few tank provers currently in use on
Federal and Indian leases, this requirement will not result in a
significant cost to industry. One commenter on paragraph (b)(1) stated
that the BLM requirement for master meter repeatability of 0.0002 (0.02
percent) is inconsistent with API 4.5, which requires a repeatability
of 0.0005 (0.05 percent). The BLM agrees with the commenter and made a
change to the final rule consistent with the comment. The BLM believes
that the paragraph (b)(1) repeatability requirement for master meter
provers in the proposed rule was too restrictive and the API 4.8 (as
referenced in API 4.5) specification of 0.0005 (0.05 percent)
repeatability is within the uncertainty (0.027 percent) of
BLM requirements.
The BLM also made a change to the final rule based on a comment
that the calibration of the master meter prover in the proposed rule
was too frequent. The proposed rule required master meter provers to be
calibrated no less frequently than once every 90 days. The BLM agrees
that the 90-day frequency for proving master meters may be too
frequent. The final rule changes the master meter calibration frequency
to no less than once every 12 months, which is consistent with API 4.8,
Subsection 10.2, which is referenced in API 4.5.
One comment on paragraph (b)(2) of this section said the BLM
displacement prover calibration requirements contradict API Chapter
4.9. The BLM disagrees with the commenter since API 4.9 addresses
calibration methods for displacement provers and not calibration
frequency for displacement provers as specified in API 4.8. The BLM
changed paragraph (b)(2) in the final rule by removing the prescriptive
language found in paragraphs (b)(2)(i) and (ii) in the proposed rule,
and by incorporating calibration frequency requirements of API 4.8,
Subsection 10.
Section 3174.11(b)(3) of the final rule (Sec. 3174.11(c)(3) of the
proposed rule) requires the base prover volume of a displacement prover
must be calculated under API 12.2.4. The BLM received no comments and
made no changes to this requirement.
Section 3174.11(b)(4) (paragraph (c)(4) in the proposed rule)
establishes displacement prover sizing standards. These standards
ensure that fluid velocity within the prover is within the limits
recommended by API 4.2, Subsection 4.3.4. Displacement velocities that
are too low (prover is oversized) can result in unacceptable pressure
and flow-rate changes and higher uncertainty due to possible
displacement device ``chatter.'' Displacement velocities that are too
high (prover is undersized) can cause damage to the components of the
prover. One commenter recommended replacing the proposed prover design
language that referenced API 4.2 with language that references
operating provers within design parameters set forth by the
manufacturer and by API 4.8 and API 4.9.2. The BLM disagrees with the
commenter that paragraph (b)(4) should reference API 4.8 and API 4.9.2
since these standards deal with prover operation and are not relevant
to paragraph(b)(4) design standards. Paragraph (b)(4) is specific to
displacement prover design, which is covered under API 4.2. The BLM did
not change the final rule in response to this comment.
Section 3174.11(c) (paragraph (d) in the proposed rule) establishes
the requirements for meter proving runs with respect to proving both
the FMP LACT and CMS and the conditions required for proving these
meter systems. The BLM received many comments objecting to certain
requirements in proposed Sec. 3174.11(d) that deal with meter proving
runs. The BLM responds to these comments as follows.
Section 3174.11(c)(1) (paragraph (d)(1) in the proposed rule)
expands on the current Order 4 requirement to prove a meter under
``normal'' operating conditions. This section defines limits of flow
rate, pressure, temperature, and API oil gravity that must exist during
the proving to be considered ``normal'' operating condition. The BLM
added this requirement because it realized that the meter factor can
change with changes in these parameters. For example, a meter factor
determined at an abnormally low flow rate may not represent the meter
factor at a higher flow rate where the meter normally operates. This
paragraph also requires a multi-point meter proving if the LACT or CMS
is subject to highly variable conditions. The multi-point meter proving
establishes a minimum of three meter factors--one at the low end of the
normal operating range, one at the midpoint, and one at the high end.
An appropriate meter factor will then be applied according to Sec.
3174.11(c)(6).
One commenter noted that paragraph (c)(1) (paragraph (d)(1) in the
proposed rule) lacks specifics on what normal operating temperature
conditions mean and another commenter said the language should be
changed to reflect situations where normal operating conditions vary,
such as at multi-metering sites, and suggested a language change to
``average for the batch period.'' The BLM agrees with the commenter
that normal operating conditions, as they apply to oil temperature,
were not adequately addressed in the proposed rule and that in some
instances it may be difficult to identify the ``normal operating
conditions'' of flowrate, pressure, temperature, and fluid density. The
BLM added paragraph (c)(1)(iii) to the final rule to address normal oil
operating temperature limits, which must be within 10 [deg]F of the
normal operating temperature. With this addition, paragraphs
(d)(1)(iii) and (d)(1)(iv) in the proposed rule have been renumbered to
paragraphs (c)(1)(iv) and (c)(1)(v) in the final rule.
[[Page 81489]]
The BLM made no change to the final rule regarding normal operating
conditions to reflect variable metering conditions since this situation
may be specific to regions and areas of the country and can be more
adequately addressed by the specific BLM field office through the
variance request process as outlined in Sec. 3170.6, which has been
established as part of the rulemaking to replace Order 3.
Section 3174.11 paragraphs (c)(2) through (c)(5) (paragraphs (d)(2)
through (d)(5) in the proposed rule) provide the details for minimum
proving requirements, such as requiring a minimum proving pulse
resolution of 10,000 pulses per proving run or requiring the use of
pulse interpolation, if this cannot be met, and setting a requirement
to continue repeating proving runs until the calculated meter factor
from five consecutive runs is within a 0.05 percent tolerance between
the highest and lowest value. The new meter factor will be the
arithmetic average of the five meter factors or average pulses from the
five consecutive proving runs. This section also requires the meter
factors to be calculated following the sequence described in API
12.2.3. We received two comments on paragraph (c)(2) of this section.
One commenter addressed the requirement that, during proving runs,
there be a sufficient volume to generate at least 10,000 pulses from
the FMP meter that is being proved. The commenter did not believe that
the 10,000-pulse requirement is reasonable and said it would disallow
the use of small-volume provers (SVPs). The BLM disagrees with the
commenter on both points. The 10,000-pulse-per-proving-run resolution
in the rule follows the API standard and the rule specifically allows
small-volume provers as long as they meet the additional requirements
in paragraph (c)(2). The BLM did not change the final rule in response
to this comment. However, the BLM believes that it is appropriate to
add clarifying language to paragraph (c)(2) in the final rule that
reminds readers of the 10,000-pulse requirement in API 4.2, Subsection
4.3.2. Another commenter asked why the proposed rule did not
specifically address SVPs. SVPs come under the requirements for
displacement provers and, under paragraph (c)(2), are required to use
pulse interpolation as outlined in API 4.6, since their volume
generates less than 10,000 meter pulses per proving run. The BLM did
not change the final rule due to this comment.
Two commenters on paragraph (c)(3) objected to the requirement that
the five consecutive meter-proving runs have a repeatability of 0.0005
(0.05 percent), saying that three proving runs could accomplish the
same uncertainty. The BLM disagrees with these commenters and has
decided to retain Order 4's requirement of a minimum of five proving
runs. The BLM believes that this requirement achieves the desired
consistency and uncertainty levels. The BLM made no change to the final
rule due to these comments.
One commenter on paragraph (c)(4) recommended that the BLM adopt
the use of an average meter factor as determined from API 12.2.3. Upon
review of this comment, the BLM agrees with the commenter that guidance
on the calculation of the average meter factor is appropriate. Due to
this comment, the BLM changed the final rule to incorporate API 12.2.3,
Subsection 9 for purposes of calculating the average meter factor.
Section 3174.11(c)(5) of the final rule (Sec. 3174.11(d)(5) of the
proposed rule) requires that meter factor computations must follow the
sequence described in API 12.2.3. The BLM received no comments and made
no changes to this requirement.
Section 3174.11(c)(6) (paragraph (d)(6) in the proposed rule) gives
operators two methods for determining the multiple meter factors that
are required under Sec. 3174.11(c)(1)(v). The first method is to
combine the meter factors into a single arithmetic average. The second
method is to curve-fit the meter factors and incorporate a real-time
dynamic meter factor into the flow computer (this will apply primarily
to CMS). Neither multi-point provings nor multi-point meter factors are
discussed in Order 4. One commenter indicated that averaging meter
factors was only valid in regions where impacts of nonlinearities are
minimal and recommended deleting Sec. 3174.11(c)(6)(i). The BLM
conducted further research into this comment and agrees with the
commenter that averaging meter factors is only valid under certain
conditions. Additional language pertaining to how to use the multiple
meter factors is added to the final rule in paragraph (c)(6). This
language will only permit the use of averaging meter factors if all
meter factors in the range are within approximately 0.10
percent of the average. It will also limit the use of the dynamic meter
factor option to prevent any two neighboring meter factors that differ
by more than approximately 0.2 percent from being used to derive a
dynamic meter factor.
Sections 3174.11(c)(7) and (c)(8) (paragraphs (d)(7) and (d)(8) in
the proposed rule) set the minimum and maximum values that are allowed
for a meter factor, both between meter provings and for initial meter
factors for newly installed or repaired meters. These meter-factor
ranges are not changed from Order 4. The BLM received no comments on
paragraphs (c)(7) and (8).
Section 3174.11(c)(9) (paragraph (d)(9) in the proposed rule)
allows back pressure valve adjustment after proving only within the
normal operating fluid flow rate and fluid pressure as prescribed in
proposed Sec. 3174.11(c)(1). If the back pressure valve is adjusted
after proving, the ``as left'' fluid flow rate and fluid pressure must
be documented on the proving report. The BLM is requiring this
documentation based on its field observations, which have shown this
practice to affect the meter factor in certain areas of the country.
Specifically, the BLM has observed that a change in back pressure
outside the proving conditions can, in some cases, result in operators
reporting incorrect volumes. Allowing back pressure valve adjustment
after proving is not intended as a means to circumvent the displacement
prover minimum and maximum velocity requirements in Sec. 3174.11(b)(4)
of the final rule. Order 4 has no specific requirements relating to the
adjustment of the back pressure valve after proving. The BLM received
no comments on paragraph (c)(9).
Section 3174.11(c)(10) (paragraph (d)(10) in the proposed rule)
sets standards for the pressure used to calculate a CPL factor for a
LACT's composite meter factor. It also prohibits the use of a composite
meter factor for Coriolis meters because they have the capability to
use a true average pressure over the measurement ticket period in the
calculation of an average CPL factor. The use of a composite meter
factor is intended to make measurement tickets easier to complete
because the CPL factor is already included in the meter factor. This is
typically not an issue with a Coriolis meter because of the advanced
capability of the flow computer to which it is connected. One commenter
stated that most Coriolis meters in the field do not have the
capability to calculate a CPL factor and replacing them with a Coriolis
meter that could calculate a CPL factor would be prohibitively costly.
The BLM agrees with the commenter regarding the CPL factor capability
currently available in existing Coriolis meters. However, the final
rule does not require operators to have a Coriolis meter with this CPL
factor feature. Therefore, the BLM made no change to the final rule as
a result of this comment.
[[Page 81490]]
Section 3174.11(d) (paragraph (e) in the proposed rule) establishes
the minimum FMP meter-proving frequencies, and specifies certain events
that will trigger additional meter provings. This section contains the
meter-proving requirements that were previously located in the LACT
section of Order 4 and consolidates in one place all of the meter-
proving requirements for both LACTs and CMSs.
The BLM received many comments that objected to the provision in
paragraph (d)(2) (paragraph (e)(2) of the proposed rule) that sets a
threshold for when operators who run large volumes of oil through their
meters must conduct additional FMP meter provings. The proposed rule
would have required operators to prove their FMP meters each time the
registered volume flowing through their meters increased by 50,000 bbl
or quarterly, whichever occurred first. Currently under Order 4, an FMP
meter must be proven at least quarterly, unless total throughput
exceeds 100,000 bbl per month, in which case the meter must be proven
monthly.
The BLM's rationale in the proposed rule for changing the proving
threshold to 50,000 bbl/month was that it would have affected only
about 5 percent of existing LACT systems nationwide, yet would have
ensured that meter-factor changes would be corrected before large
volumes of production were measured incorrectly, which could have an
adverse impact on Federal or Indian royalty determinations.
Many commenters objected to the proposed meter-proving-frequency
threshold of 50,000 bbl/month. Most commenters said this new meter-
proving frequency would require them to perform excessive and costly
meter provings in locations where the meters may not be easy to access,
especially in bad weather. The BLM agrees that the 50,000 bbl/month
threshold may be excessively costly and, after reviewing potential
economic impacts, has decided to use a 75,000 bbl meter-proving
frequency threshold in the final rule. This 75,000 bbl throughput
threshold was determined by performing a statistical analysis to
determine the volume at which the expected value of royalty under- or
overpayment due to meter factors equals the $550 average cost of
proving a meter. The royalty revenue impact depends not only on volumes
but also on oil prices. The 50,000 bbl/month threshold in the proposed
rule was determined when the U.S. Energy Information Administration's
(EIA) 10-year West Texas Intermediate crude oil spot price was expected
to average $95/bbl. Since then, the EIA's predicted 5-year average
crude oil price has dropped significantly, to $67.58 per barrel. The
BLM does not find the 50,000/bbl meter-proving threshold to be
appropriate under this predicted lower oil-price environment.
The BLM also revised the maximum and minimum proving frequencies
for meter proving on higher-volume FMPs. Under Order 4, operators were
required to prove their meters at least quarterly or, if total
throughput exceeded 100,000 bbl/month, then they were required to prove
monthly. In this final rule, operators must prove their meters every 3
months (quarterly), or each time the registered volume flowing through
the meter increases by 75,000 bbl, but no more frequently than monthly.
For example, if a meter hits the 75,000 bbl threshold every 6 weeks,
the operator must prove it every 6 weeks. If a meter has a 75,000 bbl
throughput every 2 weeks, the operator must prove it once a month. The
final rule was changed to include this new language.
Two commenters on paragraph (d)(2) said meter-proving frequencies
should be increased, based on a lower volume of throughput threshold,
and another commenter said that frequent proving would increase
accuracy. The BLM does not agree that the final rule should further
increase the proving frequency beyond what was presented in the
proposed rule. The comments lacked any substantive basis and did not
justify how an increased proving frequency would result in increased
accuracy or how the costs of those additional provings would be
justified by any reduction in royalty risk. The BLM believes the
proving frequency in the final rule is justified and results in the
required accuracy. The BLM did not change the final rule in response to
these comments.
One commenter on paragraph (d)(6) of Sec. 3174.11 (paragraph
(e)(6) of the proposed rule) said that requiring a meter proving due to
a change in normal operating conditions was not practical and not
needed. The BLM disagrees with this commenter and agrees with another
commenter who, in his comment on paragraph (e), pointed out that
temperature extremes in places like Alaska or North Dakota have a large
impact on meter-factor change between different proving runs. Because a
change in the normal operating conditions could significantly affect
the meter factor, and therefore the accurate measurement of the oil
volumes, the BLM made no change to the final rule due to this comment.
Paragraph (d)(7) in Sec. 3174.11 (paragraph (e)(7) in the proposed
rule) also expands the current Order 4 requirement that operators prove
their meters after repair. The new requirements require proving any
time the mechanical or electrical components of the meter have been
changed, repaired, or removed. In addition to those circumstances,
paragraph (d)(8) requires an operator to also prove its meter after
internal calibration factors have been changed or reprogrammed. One
commenter asked whether meters used in flowback operations are subject
to the requirements in this section. Flowback meters are not required
to comply with this rule's meter-proving requirements because flowback
operations take place prior to the operator's receipt of an FMP
approval under Sec. 3173.12, and more importantly meters used in these
operations are not FMPs. The BLM did not change the final rule based on
this comment.
One commenter said that after initial meter installation, a period
of 2 weeks should pass before the meter is proved. The commenter did
not justify a 2-week delay. The BLM believes that a meter should be
proved as soon as is reasonably possible. The BLM expects that meters
will be proven immediately after installation. The BLM did not change
the final rule based on this this comment.
One commenter said that paragraph (d)(7) (paragraph (e)(7) in the
proposed rule) is vague. The commenter specifically complained about
language that required a meter proving after the mechanical or
electrical components of the meter have been, among other things,
``opened.'' The BLM agrees with the commenter and changed the final
rule so that the paragraph, in its entirety, now requires a meter
proving after ``the mechanical or electrical components of the meter
have been changed, repaired, or removed'', and added (d)(8) to prove
after ``internal calibration factors have been changed or
reprogrammed.'' Another commenter questioned the need to reprove a
meter each time its secondary element (transducer) or tertiary device
is changed. The commenter contends that these elements have no direct
effect on the meter performance. The BLM agrees with the commenter in
part. An element can impact the accuracy of the measurement if it is
not measuring temperature and pressure accurately. Changing out either
of these elements would not require the meter to be reproved, but would
require the new element(s) (transducers) to be verified upon their
replacement as is required under Sec. Sec. 3174.11(f) and (g), and
temperature and pressure transducer verification, respectively, during
a
[[Page 81491]]
meter-proving operation. The BLM revised the final rule Sec.
3174.11(f) and (g) to address the commenter's concern by making it
clear that a change out of either one of these elements would not
require the meter to be reproved, but would require the new element(s)
(transducers) to be verified upon their replacement.
Section 3174.11(e) (Sec. 3174.11(f) in the proposed rule)
establishes what operators must do when there is excessive FMP meter
factor deviation. This situation occurs when a meter factor, which is
established in two successive provings, exceeds the allowable meter
factor deviations. This section requires operators to take steps to
bring the FMP meter back into compliance. It also requires operators to
re-calculate the amount of production that was measured during the time
period between these instances of excessive meter factor deviation.
Paragraph (e) also requires operators to show the most recent meter
factor and describe all subsequent repairs and adjustments on the
proving reports that are required in paragraph (i) of this section.
Section 3174.11(e) maintains the Order 4 requirements for excess
meter factor deviation and the required actions if proving reflects a
deviation in meter factor that exceeds 0.0025 between two
successive meter provings.
The BLM received comments objecting to the paragraph (e)
requirement that the FMP meter be removed from service when found
defective or when the meter factor is outside the proposed accuracy
range. The comments raised the issue of temperature extremes, in places
like Alaska or North Dakota, having a large impact on meter factor
change from proving to proving, making it impossible for operators to
meet the meter factor deviation requirement. The BLM agrees that
changing temperatures do affect the proving meter factors. This
situation could easily justify more frequent provings as the
temperatures change, the commenter said. The BLM believes this issue is
field office specific and is more appropriately addressed through the
BLM's variance process, which is outlined in Sec. 3170.6, part of the
rulemaking that is replacing Order 3.
One commenter recommended changing the meter-factor deviation
limits for meters from 0.0025 to 0.0050
because, the commenter said, it is standard industry practice to
consider volume measurements as accurate if the meter factor changes by
plus or minus 0.0025 or less. It typically is not until the differences
in the meter factors are between plus or minus 0.0025 and 0.0050 that a
correction is applied. The BLM reviewed API 4.8 to verify the
commenter's claims on meter-factor deviation limits that are the
industry standard. API 4.8 states common practice for custody transfer
applications is to accept new meter factors within the range of 0.10
percent and 0.50 percent of the previous meter factor. The BLM did not
accept this recommended change for several reasons: The commenter
agrees it is standard industry practice to consider volume measurements
as accurate if the meter factor changes by plus or minus 0.0025 or
less, 0.0025 deviation between meter proving runs is
currently the maximum deviation allowed under existing Order 4,
proposed deviation falls within the acceptable deviation range
recommended in API 4.8, and it will not increase current reporting
requirements or add costs, but will ensure measurement accuracy. The
BLM made no changes to the final rule based on these comments.
Section 3174.11(f) (paragraph (g) in proposed rule) establishes
standards for the verification procedure and the test equipment used in
the temperature transducer verification. It states the limit threshold
value required by the verifying sources as they pertain to the normal
operating temperature of the tested fluid. It also requires that the
temperature transducer and devices used as part of a LACT or CMS be
verified as part of every proving.
The BLM received quite a few comments objecting to the new
requirement that operators verify the temperature transducers during
the meter-proving process. One commenter said that the proposed rule's
meter-proving frequencies would result in excessive and costly
transducer verifications if the temperature transducers had to be
verified during each meter proving, since the proposed rule would have
required operators to prove their meters each time they measured 50,000
bbl of oil, or quarterly, whichever occurred first. The BLM believes
that this concern is no longer valid. Section 3174.11(d)(2) in the
final rule has been revised and now requires operators to prove their
meters every 3 months (quarterly), or each time the registered volume
flowing through the meter increases by 75,000 bbl, but no more
frequently than monthly. These changes reduced the burdens associated
with the proving requirements in the proposed rule. Therefore, the BLM
did not change the final rule in response to this comment.
One commenter objected to the requirement that operators use an
insulated water bath in the field to perform the temperature transducer
verification process, stating that this type of process belongs in a
laboratory-type environment and not in a field environment. The BLM
disagrees with this commenter since an insulated water bath is a
common, acceptable method of verification. The rule also states the
transducer may be verified by utilizing a test thermometer well located
within 12 inches of the probe of the temperature transducer. The BLM
did not change the final rule in response to this comment.
One commenter said that requiring operators to verify the
temperature transducer as part of a LACT or CMS proving may require
operators to acquire additional equipment and incur costs. The BLM
agrees with the commenter that verifying the transducer will require an
additional piece of equipment and potentially an initial cost to
acquire test equipment, but believes third-party proving contractors
already own such equipment. Moreover, the BLM believes routine
transducer verification is vital to assure proper performance and to
obtain an accurate liquid temperature for use in correcting for the
thermal effects on the liquid, ensuring accurate oil measurement, and
royalty determination. As a result, the BLM made no change to the final
rule in response to this comment.
Another commenter said the requirement for verification of
temperature averaging devices in Sec. 3174.11(f) of the proposed rule
conflicts with requirements in Sec. 3174.6(b)(2) for temperature
resolution and accuracy. The commenter did not say how this requirement
conflicts. The BLM disagrees that there is a conflict because the
temperature accuracy required for temperature verification is 0.5
[deg]F, which is consistent with temperature accuracies presented in
other sections of the final rule and with manufacturer's
recommendations. For example, the temperature display minimum
graduation must be to the 0.1 [deg]F, as required in Sec.
3174.8(b)(5)(iv), which means there is no practical difficulty in
assessing compliance with the verification limits. The BLM made no
change to the final rule in response to this comment.
Section 3174.11(f)(3)(i) and (ii) of the final rule (Sec.
3174.11(g)(3)(i) and (ii) of the proposed rule) requires that if the
displayed reading of instantaneous temperature from the temperature
averager or the temperature transducer and the reading from the test
thermometer differ by more than 0.5 [deg]F, the temperature averager or
temperature transducer must be either: (1) Adjusted to match the
reading of the test
[[Page 81492]]
thermometer; or (2) Recalibrated, repaired, or replaced. Section
3174.11(g)(3)(ii) of the proposed rule only required that the
difference in temperature readings be noted on the meter proving report
and all temperatures used until the next proving be adjusted by the
difference. The BLM received no comments to this section, but
reconsidered the requirement and the potential tracking and measurement
errors in adjusting temperature readings between provings and decided
that if the temperature averager or the temperature transducer is
unable to be adjusted to the correct reading then it must be
recalibrated, repaired, or replaced.
Section 3174.11(g) of the final rule (paragraph (h) in the proposed
rule) establishes the verification requirements for the pressure
transducer during the meter-proving operations and states the threshold
limit value required by the verifying sources as they pertain to the
normal operating pressure of the tested fluid. It requires that the
pressure transducer and devices used as part of a LACT or CMS be
verified as part of every FMP proving and establishes standards for the
verification procedure and the test equipment used in the pressure
transducer verification. The BLM received many comments objecting to
the new requirement that operators verify the pressure transducer
during the meter-proving process. Two commenters said that the proposed
rule's meter-proving frequencies would result in excessive and costly
transducer verifications if the pressure transducers had to be verified
during each meter proving. The BLM believes that this concern is no
longer valid. As noted elsewhere, the proving burdens under this final
rule have been reduced relative to the proposed rule. The proposed rule
would have required operators to prove their meters each time they
measured 50,000 bbl of oil, or quarterly, whichever occurred first.
Section 3174.11(d)(2) of the final rule now requires operators to prove
their meters every 3 months (quarterly), or each time the registered
volume flowing through the meter increases by 75,000 bbl, but no more
frequently than monthly. As a result, the BLM made no changes to the
final rule in response to these comments.
One commenter said that requiring operators to verify the pressure
transducer as part of a LACT or CMS meter proving may require operators
to acquire additional equipment and incur costs. The BLM agrees that
verifying the transducer will require an additional piece of equipment
and potentially an initial cost to acquire test equipment, but we
believe that third-party proving contractors already own or can acquire
such equipment. The BLM believes routine transducer verification is
vital to accurate oil measurement and royalty determination. The BLM
made no change to the final rule in response to this comment.
One commenter had concerns with the requirement in paragraph (g)(1)
(paragraph (h)(1) in the proposed rule) that the pressure sensor must
be verified against a NIST-traceable device that is at least twice as
accurate as the reference accuracy of the pressure sensor, saying the
operator may not have test equipment capable of this accuracy. The
commenter suggested that the BLM should allow equipment to be used that
does not meet this accuracy requirement, and should provide guidance on
how lower-accuracy equipment can be used. The BLM realizes that this
high level of accuracy may not be achievable with test equipment the
operator currently has and as a result has changed the rule in Sec.
3174.11(g)(1) to require the test-pressure device to have a stated
maximum uncertainty of no more than one-half of the accuracy required
from the transducer being verified.
Section 3174.11(h) (paragraph (i) in proposed rule) establishes the
density verification requirements during the meter proving operations
and states the limit threshold values required by the verifying sources
as they pertain to the normal operating density of the tested fluid.
For Coriolis meters, paragraph (h) requires verification using API 5.6,
Subsection 9.1.2.1 if measured density is used to determine API oil
gravity (instead of a hydrometer or thermohydrometer, which is
generally required under Sec. 3174.6(b)(4)). This provides an
independent verification that the Coriolis meter's density
determination function is within the accuracy specification for that
meter.
The BLM received a few comments objecting to the new requirement
for density verification during the FMP meter-proving process for a
variety of reasons. One commenter recommended that the final rule refer
to API 8.1, API 8.2, and API 8.3 if the compared density samples come
from a sampling system. The BLM agrees with this recommendation and
changed the final rule by adding references to API 8.1, API 8.2, and
API 8.3. These references provide guidance to operators for performing
composite sampling to verify oil density as required in the final rule
under Sec. 3174.11(h).
One commenter said that using a CMS meter instead of a PD meter
would impose additional costs on operators to verify the CMS' density
measurement. The BLM agrees in part that using a CMS would require
additional density verification over what would be required on a PD
meter. However, it is up to the operator to choose which meter type to
use. The BLM did not change the final rule as a result of this comment.
One commenter objected to the requirement for density verification
during the FMP meter-proving process because, the commenter said, it
would be costly and excessive to verify the transducer during each
meter proving. The BLM believes that this concern has been addressed.
The proposed rule would have required operators to prove their meters
each time they measured 50,000 bbl of oil, or quarterly, whichever
occurred first. Section 3174.11(d)(2) in the final rule has been
revised and now requires operators to prove their meters every 3 months
(quarterly), or each time the registered volume flowing through the
meter increases by 75,000 bbl, but no more frequently than monthly.
Section 3174.11(i) (paragraph (j) in the proposed rule) requires
operators to report to the AO all meter-proving operations and volume
adjustments made after any LACT system or CMS malfunction. This section
provides additional requirements for data that need to be included on
the meter-proving report beyond what is currently required under Order
4. In one change to Order 4 requirements, the final rule requires
operators to provide the unique meter or station ID number on each
proving report as required under Sec. 3174.11(i)(2)(i). This section
includes requirements for verification of the temperature averager or
temperature transducer, verification of the pressure transducer, and an
addition to the final rule for density verification documentation, as
applicable, as well as any ``as left'' conditions if the back pressure
valve is adjusted after proving, which operators also would have to
document on the proving report.
Many commenters asked that we clarify aspects of paragraph (i)
(proposed paragraph (j)). One commenter recommended that we change
Sec. 3174.11(i)(2)(iii) and (iv) to only require temperature and
pressure transmitter information, if verified. The BLM disagrees with
this commenter on when to report temperature and pressure transducer
data, since this information has to be verified as part of each FMP
meter proving. The BLM made no change to the rule in response to this
comment. Three commenters asked the BLM to specify the format of the
meter proving reports since
[[Page 81493]]
proposed paragraph (i)(3) specified no specific format. The proposed
rule required the operator to submit the meter-proving report to the AO
no later than 14 days after the meter proving. The BLM agrees with the
commenters that this information should be added and changed the final
rule to say that the meter proving reports may be transmitted to the AO
either in hard copy or electronically.
In addition to the comments on specific provisions above, the BLM
received a few general comments on Sec. 3174.11. One commenter said
the new regulations would impact marginal-producing wells and may force
a premature abandonment of wells and a loss of public hydrocarbon
resources. The commenter proposed that marginal and/or existing wells
be exempt from both subpart 3174 and subpart 3175. The BLM disagrees
that these regulations will force operators to abandon marginal wells.
If an operator believes these regulations will force it to abandon a
marginal well, that operator can obtain a variance from the regulations
under Sec. 3170.6, which is part of the rulemaking that is replacing
Order 3. The BLM made no change to the final rule in response to this
comment.
One commenter said the maximum and minimum velocity for PD meter
provers was not relevant to SVPs and royalty issues associated with
their use. The commenter recommended that the BLM adopt language that
says, ``Provers must be operated within the design parameters of the
manufacturer.'' The BLM disagrees with the commenter because the prover
design requirements, including sizing by prover velocity, are found in
the API standards incorporated in this rule. If the operator believes
it can meet or exceed these requirements by other means, then the rule
allows the operator to use the variance process outlined in Sec.
3170.6. The BLM did not change the final rule in response to this
comment.
Two comments, made by the same commenter, voiced concerns that the
proposed rule was suited to lighter oil regimes and did not address the
differences in measurement that characterize heavy oil, steamflood, and
cyclic steam operations. The commenter was concerned that the proposed
rule's accuracy requirements would increase operating costs for heavy-
oil operators, resulting in possible violations of the measurement
requirements. The BLM agrees with the commenter that these rules do not
specifically address the measurement of heavy oil. However, these
issues are field office specific and can be appropriately addressed
through the variance process outlined in Sec. 3170.6.
Section 3174.12 Measurement Tickets
Section 3174.12 specifies the data requirements for measurement
tickets (run tickets) based on which method of oil measurement an
operator uses, i.e., tank gauging, LACT system, or CMS. These
requirements were previously found in Order 3.\14\ The purpose of the
information in the run tickets is to enable the BLM to independently
verify the quantity and quality of oil removed from the lease during
production audits so as to ensure accurate measurement and proper
reporting.
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\14\ The information on a run ticket is considered a source
record, as defined in Sec. 3170.3, which is being promulgated as
part of the rulemaking to replace Order 3. The retention
requirements for such records is addressed in that rulemaking;
however, the requirements as to substance are provided in this rule
as explained above.
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The BLM received several comments on this section. Some comments
questioned the requirement to complete a run ticket prior to proving a
LACT or CMS utilizing flow computers. One commenter stated that this
requirement is unnecessary as a flow computer is capable of
implementing a new meter factor in the middle of a run without closing
the run. The commenter asserted that the flow computer does this by
applying the original meter factor to deliveries that occurred from the
beginning of the month up to the point of proving and then applying the
new meter factor after the point of proving until the end of the month.
The BLM agrees that flow computers are capable of utilizing two meter
factors as the commenter described, and of retaining an audit trail
capability to track this. As a result of this comment, Sec.
3174.12(b)(1) of the final rule has been changed to remove the
requirement to close a run ticket prior to proving for LACT systems
utilizing flow computers.
One commenter stated that the proposed rule's run-ticket
requirements for tank gauging did not specify a frequency for when run
tickets will be required. The BLM disagrees with this comment as the
proposed rule stated that measurement tickets must be completed
``immediately after oil is measured by manual tank gauging.'' The BLM
believes that this language is clear as to how frequently a measurement
ticket needs to be completed but modified the final rule to say,
``After oil is measured by tank gauging under Sec. Sec. 3174.5 and
3174.6. . . .'' This change was made because the final rule allows the
use of ATG equipment. The BLM made no changes to the rule as a result
of this comment but did modify the requirements' language due to the
inclusion of ATG equipment. The final rule now states ``After oil is
measured by tank gauging under Sec. Sec. 3174.5 and 3174.6 of this
subpart, the operator, purchaser, or transporter, as appropriate, must
complete a uniquely numbered measurement ticket, in either paper or
electronic format.''
We received several comments requesting that we remove the
requirement to list on measurement tickets the name of the operator's
representative certifying the measurements. It was suggested that
operators do not have enough field personnel to witness every oil tank
haul and therefore would not be able to ``certify'' every tank sale.
The commenters argued that this requirement could increase confusion
and expense, requiring operators to schedule a sale only when a
``company man'' can be present, and creating undue financial strain on
operators having to hire staff to witness tank sales and nothing else.
Another commenter said that the BLM needs to define the term
``certify.'' Upon reviewing this requirement and the comments, the BLM
agrees with the commenters, and deleted this requirement in proposed
Sec. 3174.12(a)(14) from the rule. It should be noted, however, the
operators remain responsible for the accuracy of information found on
run tickets, irrespective of any requirement to certify the run ticket.
Several commenters requested that the BLM remove from the rule the
requirement that operators notify the AO within 7 days regarding their
reasons for disagreeing with a tank gauge measurement. The commenters
said this requirement is impractical because, in the field, it may take
up to 30 days for a transporter's run ticket to show up in the
operator's accounting system. One commenter said that operators should
be able to correct relatively minor run-ticket discrepancies without
having to report them to the BLM. Upon reviewing these comments, the
BLM believes this requirement may create confusion both within the BLM
and among operators as to when exactly the AO should be notified. For
example, would a simple calculation error warrant AO notification?
Would the operator need to explore a potential discrepancy before
notifying the AO? The BLM believes this requirement could lead to
significant confusion, with minimal benefit to the BLM. Therefore, this
requirement in proposed Sec. 3174.12(a)(15) was removed from the rule.
Instead, the BLM will address any run ticket discrepancies on a case-
by-
[[Page 81494]]
case basis during routine production inspections.
One commenter stated that it may not be possible to reset
temperature- and pressure-averaging equipment and density-determining
equipment back to zero upon closing a run ticket, as is required by
paragraph (b)(2) of this section, which could result in some operators
having to replace equipment. The BLM is not aware of any non-resettable
averaging equipment in use on Federal leases. This requirement is in
the rule to ensure that the temperature, pressure, and density, which
are required to be included on each run ticket, represent the average
temperature, average pressure, and average density of the oil that
actually flowed through the meter during the run-ticket period. If
there is any non-resettable averaging equipment in use on any Federal
or tribal lease, operators will be required to replace it. No change to
the rule resulted from this comment.
One commenter recommended that the BLM require hauler signatures on
run tickets, but at the same time admitted that anyone can write or
type someone else's name on a run ticket and not be the individual who
is actually performing the task. The BLM agrees that a signature could
identify a specific individual who filled out a run ticket, in case
questions arise. But past experience with signature requirements
resulted in BLM inspectors spending a lot of time tracking down
signatures for no quantifiable benefit. For this reason, the BLM
decided to not include a signature requirement. BLM regulations at 43
CFR 3163.2(f)(1) include penalties for any person who knowingly or
willfully prepares, maintains or submits false, inaccurate or
misleading reports, notices, affidavits, records, data or other written
information. The BLM believes this provision addresses any circumstance
under which someone falsely enters another person's name on a run
ticket. By only requiring the name(s) of the individual(s) performing
the tank gauging, we will be acquiring the data we need for our
verification requirements. No change was made to the rule as a result
of this comment.
Section 3174.13 Oil Measurement by Other Methods
Section 3174.13(a) provides that using any method of oil
measurement other than tank gauging, LACT system, or CMS at an FMP
requires prior BLM approval. Under Sec. 3174.13(b), the BLM will use
the PMT as a central advisory body within the BLM to review and
recommend approval of industry measurement technology not addressed in
these regulations. The PMT is a panel of BLM employees who are oil and
gas measurement experts.
The process outlined in Sec. 3174.13(b) for reviewing new
equipment allows the BLM to keep up with technology as it advances and
approve its use without having to update its regulations. Under the
rule, if the PMT recommends new equipment or measurement methods, and
the BLM approves, the BLM will post the make, model, range or software
version, or measurement method on the BLM Web site (www.blm.gov) as
being appropriate for use at an FMP for oil measurement going forward.
The PMT will consider new measurement technologies on a case-by-
case basis. The BLM believes this process will be used as other
technologies or methods are developed and their reliability is
established. For example, the BLM considered other meters for inclusion
in this rule, such as turbine meters and ultrasonic meters; however, it
ultimately decided not to include them in this rule because at this
time there is insufficient testing to validate their accuracy and
reliability under all operating conditions. However, if in the future
the data demonstrates that these meters meet the performance standards
of the rule, the PMT will be able to recommend that these meters be
approved for use.
If the PMT is able to make the required determination, it will
recommend that the BLM approve the use of the applicable equipment or
method, as is or subject to certain conditions. Such equipment or
methods, and any applicable COAs, will be posted to the BLM Web site
and be identified as being appropriate for use at an FMP for oil
measurement without additional approvals from the BLM, subject to any
limitations or conditions of use imposed by the PMT. Subsequent users
of the same technology will not have to go through the PMT process,
provided only that they comply with the identified conditions of use.
Section 3174.13(c) provides that the procedures for requesting and
granting a variance under Sec. 3170.6 cannot be used as an avenue for
approving new technology or equipment. An operator can obtain approval
of alternative oil measurement equipment or methods only through
review, recommendation, and approval by the PMT under Sec. 3174.13.
One commenter suggested that field-office staff are often in a
better position than national office staff to collaborate with
operators on pilot projects intended to prove alternative measurement
methods. The BLM disagrees. Field-office staff typically do not have
the necessary time and measurement expertise to conduct a complete
analysis for approval of new technology. This rule includes a process
for the BLM--through the PMT--to assess new technology and approve it
when appropriate. Additionally, this rule responds in part to concern
on the part of the Subcommittee, the GAO, and the OIG that the BLM
lacked uniform national standards governing measurement. Leaving
decisions about new equipment to field office staff would not address
that concern.
Several commenters wanted to know what they will have to do to get
equipment approved for use through the PMT and included on the BLM Web
site. One commenter objected to any requirement that operators pay for
third-party testing of equipment in order to receive approval by the
PMT. Upon reviewing the rule and careful consideration of this comment,
the BLM re-evaluated the approval process for equipment and transducers
that will be listed on the BLM Web site and changed the rule to clarify
that an operator requesting approval must submit performance data,
actual field test results, laboratory test data, or any other
supporting data or evidence that demonstrates that the proposed
equipment will meet or exceed this rule's objectives. The final rule is
revised by adding in Sec. 3174.2(g) to explain how operators and
manufacturers can obtain BLM approval for ATG equipment and specific
meters, including approval of a particular make, model, and size, by
submitting test data used to develop performance specifications to the
PMT for review. Neither the proposed nor the final rule requires
operators to pay for third parties to test equipment in order to
receive PMT approval. However, should the submitted data fail to
demonstrate to the PMT that the proposed equipment will meet or exceed
this rule's objectives, the BLM may require additional testing before
it grants approval.
One commenter objected to the creation of the PMT, claiming it will
stifle innovation, not provide timely reviews, and discourage
development of new technology by increasing ``red tape.'' The BLM
disagrees and in fact believes the PMT will increase the utilization of
new technology and expedite new approvals. The BLM believes that once
the PMT is fully staffed, reviews could take 30 to 60 days, assuming
that operators and manufacturers have performed the proper testing and
that all pertinent data is submitted to the PMT. Once the PMT reviews
the data and makes a recommendation, and the BLM
[[Page 81495]]
approves a piece of equipment, it is approved for use across the
country on all Federal and Indian onshore leases and no further
approvals are required. This is not the case for the current variance
process, which requires approval by each field office for each instance
such equipment is proposed for use, resulting in a duplicative approval
process with inconsistent results.
This commenter also said the BLM, the public, and industry would
benefit from allowing companies to determine how they will meet the
requirements of the regulation once it is in place, without the agency
determining what equipment it will allow to fulfill the requirements of
its regulation. The BLM agrees that a company should have the
flexibility to determine how to best satisfy the performance
requirements of the rule, but disagrees that the BLM should not be
evaluating and approving equipment. The BLM has an affirmative
obligation to determine that measurements on Federal oil and gas leases
are meeting the applicable performance and verifiability standards. The
final rule provides flexibility by including provisions that allow for
variances for alternatives that meet or exceed the minimum requirements
of the regulations and by including the PMT approval process in the
rules to evaluate and approve new technology and measurement methods.
The BLM believes that the final rule has already addressed the intent
of this comment--to allow flexibility in measurement approaches. No
change to the rule resulted from this comment.
One commenter suggested that the BLM should list approved
technology and not specific makes and models of equipment. The BLM
partly agrees with the commenter, in that the PMT will be evaluating
new technology and the list will include new technology as it is
approved, but it will be approved and listed by make and model of the
specific equipment based on the performance data. The BLM believes that
there will always be manufacturing control and software differences
that affect individual meter performance between competing
manufacturers and these differences need to be captured in the
uncertainty calculator. No changes to the rule resulted from these
comments.
Section 3174.14 Determination of Oil Volumes by Methods Other Than
Measurement
Section 3174.14 does not change Order 4's existing requirements for
determining volumes of oil that cannot be measured as a result of
spillage or leakage. This section includes, but is not limited to, oil
that is classified as slop or waste oil.
The BLM received two comments on this section. The first commenter
said the section requires the operator to confirm ``slop oil'' is not
recoverable, and cannot be treated and sold, and provide documentation
to this effect. According to the commenter: (1) The proposed rule did
not define a process for the operator to follow; (2) This requirement
could impact water disposal when bottoms are pulled from a tank; and
(3) The language is very open ended. The BLM disagrees that the rule
does not define a process. The language found in this section is simply
a codification of existing requirements and practices. Additionally,
the proposed and final rules state that the first determination the
operator must make is the amount of production that cannot be measured
due to spillage or leakage. The second determination the operator must
make is whether the production is waste oil or slop oil. And the third
step that an operator must take, depending on whether it is waste or
slop oil, is to either demonstrate to the AO that it is not
economically feasible to put the product into marketable condition or
get AO approval to sell or dispose of the slop oil.
Regarding the second issue, the BLM notes that this is not a new
requirement and it should not surprise operators that the requirements
of this section could impact water disposal when bottoms are pulled
from tanks should the contents meet the definition of waste oil or slop
oil.
As for the third issue, the BLM agrees that the language is
somewhat open-ended because it is intended to address all potential
situations that might occur in the field. No change has been made to
the rule as a result of this comment.
The second commenter said the rule should be changed to better
define slop oil. The definition of slop oil is found in the definitions
section of Sec. 3170.3, part of the rulemaking that is replacing Order
3. This issue was addressed as part of that rulemaking; however, it
should be noted that the BLM does not believe this definition is
insufficient. No change has been made to the final rule as a result of
this comment.
Section 3174.15 Immediate Assessments
Section 3174.15 identifies certain acts of noncompliance that are
subject to immediate assessments. This section includes violations that
are not subject to immediate assessment under existing regulations at
43 CFR 3163.1(b). These assessments are not civil penalties and are
separate from the civil penalties authorized in Section 109 of FOGRMA,
30 U.S.C. 1719.
Order 4 does not provide for immediate assessments beyond those
specified in 43 CFR 3163.1(b). However, the BLM continues to incur
costs associated with correcting the violations identified in Sec.
3174.15. Accordingly, this rule adds five new violations that are
subject to immediate assessments.
As is explained in the proposed rule, the authority for the BLM to
impose these assessments was explained in the preamble to the 1987
final rule in which 43 CFR 3163.1 was originally promulgated:
The provisions providing assessments have been promulgated under
the Secretary of the Interior's general authority, which is set out
in Section 32 of the Mineral Leasing Act of 1920, as amended and
supplemented (30 U.S.C. 189), and under the various other mineral
leasing laws. Specific authority for the assessments is found in
Section 31(a) of the Mineral Leasing Act (30 U.S.C. 188(a), which
states, in part ``. . . the lease may provide for resort to [sic]
appropriate methods for the settlement of disputes or for remedies
for breach of specified conditions thereof.'' All Federal onshore
and Indian oil and gas lessees must, by the specific terms of their
leases which incorporate the regulations by reference, comply with
all applicable laws and regulations. Failure of the lessee to comply
with the law and applicable regulations is a breach of the lease,
and such failure may also be a breach of other specific lease terms
and conditions. Under Section 31(a) of the Act and the terms of its
leases, the BLM may go to court to seek cancellation of the lease in
these circumstances. However, since at least 1942, the BLM (and
formerly the Conservation Division, U.S. Geological Survey), has
recognized that lease cancellation is too drastic a remedy, except
in extreme cases. Therefore, a system of liquidated damages was
established to set lesser remedies in lieu of lease cancellation . .
.
The BLM recognizes that liquidated damages cannot be punitive,
but are a reasonable effort to compensate as fully as possible the
offended party, in this case the lessor, for the damage resulting
from a breach where a precise financial loss would be difficult to
establish. This situation occurs when a lessee fails to comply with
the operating and reporting requirements. The rules, therefore,
establish uniform estimates for the damages sustained, depending on
the nature of the breach (53 FR 5384, 5387, Feb. 20, 1987).
All of the immediate assessments under this rule are set at $1,000
per violation. The BLM chose the $1,000 figure because it generally
approximates what it would cost the agency to identify and document
each of the violations in question and verify remedial action and
compliance.
Some commenters argued that the immediate assessments in Sec.
3174.15 are
[[Page 81496]]
inconsistent with due process because there is no opportunity for an
operator to correct its violations before an assessment is imposed. To
the contrary, the use of immediate assessments for breaches of the
BLM's oil and gas regulations is well established and is consistent
with the notice requirements of due process. Operators obligate
themselves to fulfill the terms and conditions of the Federal or Indian
oil and gas leases under which they operate, and these leases
incorporate applicable regulations by reference. Thus, the immediate
assessments contained in the regulations act as ``liquidated damages''
owed by operators that have breached their leases by breaching the
regulations (see, e.g., M. John Kennedy, 102 IBLA 396, 400 (1988)).
Operators are expected to know the obligations and requirements of the
Federal or Indian oil and gas lease under which they operate;
additional notice is not required.
A number of commenters said the $1,000 assessment amounts are
``excessive.'' One commenter said the BLM should adjust the assessment
amounts on a case-by-case basis. The BLM does not agree. The $1,000
assessments are in line with the amounts needed for the BLM to recover
costs for staff and processing time associated with the inspection
process. A fixed schedule of assessments also ensures their
impartiality and uniformity. No changes to the rule resulted from these
comments.
Enforcement
As explained in the proposed rule, the final rule removes the
enforcement, corrective action, and abatement period provisions of
Order 3. In their place, the BLM will develop an Internal Inspection
and Enforcement Handbook that will provide direction to BLM inspectors
on how to classify a violation--as either major or minor--what the
corrective action should be, and what the timeframes for correction
should be. The AO will use the Inspection and Enforcement Handbook in
conjunction with 43 CFR subpart 3163, which provides for assessments
and civil penalties when lessees and operators fail to remedy their
violations in a timely fashion, and for immediate assessments for
certain violations.
As previously discussed in the proposed rule, the final rule allows
the BLM to make a case-by-case determination of the severity of a
violation, based on applicable definitions in the regulations. In
deciding how severe a violation is, BLM inspectors must take into
account whether a violation could result in ``immediate, substantial,
and adverse impacts on public health and safety, the environment,
production accountability, or royalty income.'' (Definition of ``major
violation,'' 43 CFR 3160.0-5.) Under the existing definition of ``major
violation,'' which is not being revised as part of this rulemaking, the
same violation could be major or minor, depending on the context.
Several commenters objected to this approach for a number of
reasons. One concern was that if the BLM publishes an internal guidance
document ``after the fact,'' meaning after the rule is final, industry
will be precluded from commenting on or assessing the impact of such a
document on their operations. Another concern was that a guidance
document will create inconsistency between field offices and operators.
However, the commenter provided no explanation as to how an internal
guidance document will create inconsistency between field offices and
operators, or what confusion industry will have concerning how the BLM
enforces the regulations. In general, these comments misunderstand the
nature of the Internal Inspection and Enforcement Handbook that the BLM
will develop. The new Handbook will not establish new obligations to be
imposed on the regulated community. Those obligations are spelled out
in applicable regulations, orders, and permits, as well as the terms
and conditions of leases and other agreements.
Other commenters questioned why the Inspection and Enforcement
Handbook was not part of the public notice and comment process.
Internal guidance documents that direct agency personnel how to
implement existing agency policies are not required to follow the
public notice and comment process. No change to the rule resulted from
this comment.
Additional comments suggested that the BLM may not promulgate new
binding regulations in internal ``guidance'' documents. The BLM agrees
with this comment and will not be promulgating any binding regulations
within the internal guidance document. The overarching enforcement
infrastructure of 43 CFR subpart 3163 remains in effect, and the
definitions of ``major violation'' and ``minor violation'' in Sec.
3160.0-5 remain unchanged. It is these duly promulgated regulations
(among other authorities), and not the Inspection and Enforcement
Handbook, that will provide the legal basis for the BLM's enforcement
actions; BLM's enforcement actions must be consistent with these
regulations irrespective of what may be contained in its Inspection and
Enforcement Handbook. As noted above, it is this rule and other duly
promulgated regulations that establish the standards to which an
operator will be held.
Several commenters asserted that removing internal enforcement
provisions from the regulations that were promulgated with public
notice and comment, and ``concealing'' them in non-public policy
documents that can be altered without notice and in the absence of
public input, is inconsistent with the requirements of the
Administrative Procedures Act (APA). The BLM does not agree with these
comments as they misunderstand the nature of the new Handbook. The
operative requirements to which operators are subject are spelled out
in duly promulgated regulations, consistent with APA requirements.
Internal agency guidance documents on how to implement those
requirements are not subject to the APA's notice and comment
requirements. No change to the rule resulted from these comments.
A few other commenters said industry has a right to know by what
standards they are being judged and penalized. The BLM agrees and
believes this rule very clearly describes the standards industry must
meet in the oil measurement context. As stated above, in deciding how
severe a violation is, BLM inspectors will take into account whether a
violation could result in ``immediate, substantial, and adverse impacts
on production accountability, or royalty income'' (definition of
``major violation'', 43 CFR 3160.0-5.) One commenter suggested that the
BLM provide internal standards to industry at the earliest opportunity.
The BLM agrees and will make the internal Inspection and Enforcement
Handbook available to the public once it is completed.
Several commenters expressed concern that industry has not seen any
proposed violations that may result in enforcement actions prior to the
BLM's adoption of the Inspection and Enforcement Handbook. The BLM
wishes to further clarify what a violation is. Any deviation from the
rules and regulations, without an approved variance from the AO, is a
violation, and any violation will result in enforcement action. The
Handbook will not alter that fundamental structure in any way.
Additional commenters said the BLM's process for developing
violations and corrective actions is not transparent. Again, these
comments misunderstand the nature of the forthcoming internal guidance.
Operators are obligated to follow the
[[Page 81497]]
rules and regulations applicable to their operations, including the
requirements of this final rule, or they are in violation and subject
to potential enforcement actions by the BLM. The Inspection and
Enforcement Handbook will simply guide BLM staff on how to identify
violations and provide guidance on which enforcement actions should be
taken, it does not answer the underlying question of what is or is not
a violation. No changes to the rule resulted from these comments.
Miscellaneous Changes to Other BLM Regulations in 43 CFR Part 3160
Because this rule replaces Order 4, the BLM is making two related
changes to provisions in 43 CFR part 3160.
1. Section 3162.7-2, Measurement of oil, has been rewritten to be
consistent with this rule.
2. Section 3164.1, Onshore Oil and Gas Orders, the table has been
revised to remove the reference to Order 4.
The BLM received no comments on these sections and they remain as
proposed.
C. General Comments on the Proposed Rule
Regulatory Burden
The BLM received numerous comments that said the cumulative
economic impact of this and other rules that the BLM has adopted or
plans to finalize in the coming months will result in unnecessary and
restrictive regulations, increased burdens and costs to both industry
and the BLM without any documented financial benefits to taxpayers, and
job loss in the oil and gas industry. The commenters noted that in
addition to this rulemaking, the BLM is finalizing rules that will
update and replace Orders 3 and 5. In addition, on February 8, 2016,
the BLM published in the Federal Register a proposed rule entitled
Waste Prevention, Production Subject to Royalties, and Resource
Conservation (81 FR 6616), which seeks to curtail the wasteful venting
and flaring of Federal and Indian gas. Commenters also flagged the
BLM's new regulations on hydraulic fracturing that were to go into
effect on June 24, 2015 (The rule is currently vacated by order of the
District Court of Wyoming, that Order is on appeal to the U.S. Court of
Appeals for the Tenth Circuit.) The BLM does not agree with these
comments for two primary reasons. First, this rule codifies existing
requirements found in Order 4, adopts industry standards and practices
that are already in use, and has built in compliance flexibility that
increases opportunities for operators to deploy new technologies,
potentially reducing costs. Notably, this rule expands compliance
opportunities because, for the first time, it establishes measurement
performance standards that can be used by operators to identify and
evaluate alternative measurement methods and equipment. Second,
improved accuracy also has the potential to benefit operators, because
measurement uncertainty has an equal chance of favoring the government
or the lessee.
Other commenters said that the costs to retrofit many of the
facilities to bring them into compliance with this rule and the BLM's
proposed rules on gas measurement and site security would outweigh any
foreseeable economic benefits to operators and government entities. The
commenters contend that the proposed rule would impose significant and
harmful burdens on operators and the industry as a whole causing
operators to shut in, plug, and abandon producing wells, possibly
leading to a loss of royalty and tax revenue for the Federal
Government, as well as tribal, State, and local governments. Several
commenters recommended that the BLM withdraw the proposed rule at this
time due to its negative economic impacts, and argued that the BLM
could accomplish much of what it seeks to do through this proposed rule
by simply updating the content of Orders 4 and 5 to reflect current
voluntary consensus standards developed by professional industry
groups. The BLM disagrees with the suggestion that these rules are
unnecessary and will result in plugged wells, or lost jobs. First, the
current economic conditions in the oil and gas sector identified by the
commenters are a direct result of the significant drop in oil prices
over the last year and a half, which has been accounted for in the
threshold analyses performed by the BLM. For example, the recent drop
in oil prices led the BLM to change the various thresholds between
draft and final rule, as explained in this preamble. Second, with
respect to the suggestion that BLM should have simply updated Orders 4
and 5 with references to the relevant industry standards, it must be
noted that such an approach was not available to the BLM. Order 4 was
promulgated using the APA's Notice and Comment procedures; therefore
any updates to it required BLM to undertake Notice and Comment
rulemaking. Under those procedures, the BLM is forbidden from
incorporating industry standards, unless it is incorporating them into
codified regulations, which is the primary reason this rule is being
codified.
With respect to the concerns about cost, the BLM believes that this
rule will increase opportunities for operators to reduce costs thanks
to the rule's built-in flexibility. As noted, this rule includes
specific performance standards that will enable operators to identify
and evaluate alternative methods and equipment for oil measurement. In
addition, the rule includes provisions expressly authorizing ATG
systems and the use of Coriolis meters (either as a component of a LACT
system or as a standalone metering system). Finally, as explained
elsewhere, the rule incorporates the latest industry standards and
establishes a PMT to evaluate new equipment and methodologies, so that
the BLM can review and approve such equipment and methodologies as they
are developed. This flexibility is not available in the current Order
4, which requires operators to obtain case-by-case variances before
they may use new equipment or methods.
Retroactivity
A number of commenters argued that the rule is impermissibly
``retroactive.'' These comments argued that the rule is retroactive
because it will apply to measurement systems whose existence pre-dates
the rule's effective date. While the BLM agrees that truly retroactive
regulations raise legal concerns, those concerns are not implicated
here because this rule is not retroactive. The comments misunderstand
the nature of the ``retroactive'' regulations that the law disfavors.
``A law does not operate `retrospectively' merely because it is applied
in a case arising from conduct antedating the statute's enactment or
upsets expectations based in prior law'' (Landgraf v. USI Film Prods.,
511 U.S. 244, 269 (1994) (internal citations omitted)). Rather, the
test for retroactivity is whether the new regulation ``attaches new
legal consequences to events completed before its enactment.'' Id. at
270. The rule at hand does not attach any new legal consequence to the
past use of existing measurements systems. As the U.S. Court of Appeals
for the District of Columbia Circuit has explained, the fact that a
change in the law adversely affects pre-existing arrangements does not
render that law ``retroactive:''
It is often the case that a business will undertake a certain
course of conduct based on the current law, and will then find its
expectations frustrated when the law changes. This has never been
thought to constitute retroactive lawmaking, and indeed most
economic regulation would be unworkable if all laws disrupting prior
expectations were deemed suspect.
[[Page 81498]]
Chemical Waste Mgmt., Inc. v. EPA, 869 F.2d 1526, 1536 (D.C. Cir.
1989). Thus, despite the fact that this rule may require companies to
update or modify their existing measurement systems, the rule is
nonetheless prospective--not retroactive--in nature. The obligation to
accurately measure and account for oil produced from both new and
existing facilities is ongoing and track the productions each day it
occurs.
National Technology Transfer and Advancement Act of 1995
The National Technology Transfer and Advancement Act of 1995
(NTTAA), codified as a note to 15 U.S.C. 272, directs agencies to
utilize technical standards that are developed by voluntary consensus
standards bodies. In this rule, the BLM is adopting certain oil
measurement standards developed by the API. Some commenters argued that
the NTTAA obligates the BLM to adopt all oil measurement standards
developed by voluntary consensus standards bodies. This position
overstates the requirements of the NTTAA. The NTTAA does not require an
agency to adopt voluntary consensus standards where it would be
``impractical.'' NTTAA Section 12(d)(3). The Office of Management and
Budget's (OMB) guidance for implementing the NTTAA defines
``impractical'' to include circumstances in which the use of certain
standards ``would fail to serve the agency's regulatory, procurement,
or program needs; be infeasible; be inadequate, ineffectual,
inefficient, . . . or impose more burdens, or be less useful, than
those of another standard'' (OMB Circular A-119, pg. 20.) Furthermore,
the OMB has explained that the NTTAA ``does not preempt or restrict
agencies' authorities and responsibilities to make regulatory decisions
authorized by statute . . . [including] determining the level of
acceptable risk and risk-management, and due care; setting the level of
protection; and balancing risk, cost, and availability of alternative
approaches in establishing regulatory requirements'' (OMB Circular A-
119, pg. 25.) The BLM has studied the available voluntary consensus
standards for oil measurement and has chosen to adopt a workable suite
of these standards that will meet the BLM's regulatory needs in an
effective and feasible manner. To adopt all available voluntary
consensus standards would be ``impractical'' in that it would involve
the adoption of standards the BLM has judged to be less effective,
feasible, or useful. In addition, the commenters reading of the NTTAA
would, contrary to OMB guidance, preempt the BLM's statutory authority
to promulgate rules and regulations that it deems necessary to
accomplish the purposes of the MLA and FOGRMA.
III. Overview of Public Involvement and Consistency With GAO
Recommendations
Public Outreach
The BLM conducted extensive public and tribal outreach on this rule
both prior to its publication as a proposed rule and during the public
comment period on the proposed rule. Prior to the publication of the
proposed rule, the BLM held both tribal and public forums to discussion
potential changes to the rule. In 2011, the BLM held three tribal
meetings in Tulsa, Oklahoma (July 11, 2011); Farmington, New Mexico
(July 13, 2011); and Billings, Montana (August 24, 2011). On April 24
and 25, 2013, the BLM held a series of public meetings to discuss draft
proposed revisions to Orders 3, 4, and 5. The meetings were webcast so
tribal members, industry, and the public across the country could
participate and ask questions either in person or over the Internet.
Following those meetings, the BLM opened a 36-day informal comment
period, during which 13 comment letters were submitted. The comments
received during that comment period were summarized in the preamble for
the proposed rule (80 FR 58952).
The proposed rule was made available for public comment from
September 30, 2015 through December 14, 2015. During that period, the
BLM held tribal and public meetings on December 1 (Durango, Colorado),
December 3 (Oklahoma City, Oklahoma), and December 8 (Dickinson, North
Dakota). The BLM also held a tribal webinar on November 19, 2015. In
total, the BLM received 106 comment letters on the proposed rule, the
substance of which are addressed in the Section-by-Section analysis of
this preamble.
Consistency With GAO Recommendations
As explained in the background section of this preamble, three
outside independent entities--the Subcommittee, the OIG, and the GAO--
have repeatedly found that the BLM's oil measurement rules do not
provide sufficient assurance that operators pay the royalties due.
Specifically, these groups found that the BLM needed updated guidance
on oil measurement technologies, to address existing technological
advances, as well as technologies that might be developed in the
future. These groups have all found that the BLM's existing guidance is
``unconsolidated, outdated, and sometimes insufficient,'' and more
specifically, that:
BLM policy and guidance have not been consolidated into a
single document or publication, resulting in the BLM's 31 oil and gas
field offices using varying policy and guidance;
Some BLM policy and guidance is outdated and some policy
memoranda have expired; and
Some BLM State offices have issued their own NTLs for oil
and gas operations, which lack a national perspective and may introduce
inconsistencies among the States with respect to the same types of
operations.
The final rule addresses these recommendations by establishing
nationwide performance requirements for oil measurement that addresses
uncertainty factors, bias, and the verifiability of measurement. The
rule specifically addresses technological advances in oil metering
technology since Order 4 was promulgated. It affirmatively allows the
use of those technologies that have been shown to be sufficiently
reliable and accurate. It also updates the BLM's requirements related
to proper measurement, documentation, and recordkeeping. Going forward
the final rules establishes a process for the BLM to review, and
approve for use, new oil measurement technology and systems.
IV. Procedural Matters
Executive Orders 12866 and 13563, Regulatory Planning and Review
Executive Order (E.O.) 12866 provides that the Office of
Information and Regulatory Affairs (OIRA) will review all significant
rules. OIRA has determined that this rule is not significant.
E.O. 13563 reaffirms the principles of E.O. 12866 while calling for
improvements in the nation's regulatory system to promote
predictability, to reduce uncertainty, and to use the best, most
innovative, and least burdensome tools for achieving regulatory ends.
The executive order directs agencies to consider regulatory approaches
that reduce burdens and maintain flexibility and freedom of choice for
the public where these approaches are relevant, feasible, and
consistent with regulatory objectives. E.O. 13563 emphasizes further
that regulations must be based on the best available science and that
the rulemaking process must allow for public participation and an open
exchange of ideas. The BLM has developed this rule in a manner
consistent with these requirements.
[[Page 81499]]
Regulatory Flexibility Act
The BLM certifies that this final rule will not have a significant
economic effect on a substantial number of small entities as defined
under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.). The Small
Business Administration (SBA) has developed size standards to carry out
the purposes of the Small Business Act and those size standards can be
found at 13 CFR 121.201. The Small Business Act applies to oil and gas
extraction firms with fewer than 1,250 employees, oil and gas drilling
firms with fewer than 1,000 employees, and firms providing oil and gas
support activities with annual receipts of no more than $38.5 million.
These small entities must be considered as being at ``arm's length''
from the control of any parent companies.
Of the 6,460 domestic firms involved in onshore oil and gas
extraction in 2013, U.S. Census data show that 99 percent (or 6,370)
had fewer than 500 employees, which means that nearly all U.S. firms
involved in oil and gas extraction in 2013 fell within the SBA's size
standard of fewer than 1,250 employees. Of the 2,097 firms
participating in oil and gas drilling activities in 2013, U.S. Census
data show that 2,044 had fewer than 500 employees, which means that
nearly all U.S. firms involved in oil and gas support activities in
2013 fell within the SBA's size standard of fewer than 1,000 employees.
There were another 8,877 firms involved in drilling and other support
functions in 2012. Of the firms providing support functions, 96 percent
(8,561) had annual net receipts of no more than $35 million, with a
greater number below the SBA's $38.5 million threshold.
Based on this national data, the preponderance of firms involved in
developing oil and gas resources are small entities as defined by the
SBA. As such, it appears a number of small entities potentially could
be affected by this rule. Using the best available data, the BLM
estimates there are approximately 3,700 lessees/operators conducting
oil operations on Federal and Indian lands that could be affected by
this rule.
On an ongoing basis, we estimate the changes to the LACT meter
proving frequency requirements based on volume throughput will increase
the regulated community's total annual costs by $67,650. This amount
corresponds to the cost of an estimated 123 additional annual provings
per year at 28 LACT systems on 19 leases, CAs, or PAs flowing between
31,250 bbl/month/meter and 100,000 bbl/month/meter. This includes 75
additional provings ($41,250 in cost) for 22 LACT systems on 15 leases,
CAs, or PAs flowing at least 31,250 bbl/month/meter and below 75,000
bbl/month/meter, and 48 additional provings ($26,400 in cost) for six
LACT systems on four leases, CA, or PA's flowing at least 75,000 bbl/
month/meter and below 100,000 bbl/month/meter. Currently, LACT systems
for both of these groups of systems would be proven monthly for LACTs
measuring 100,000 bbl/month or greater, or once every 3 months (four
times per year). Under the new rule, meters at the first group of LACT
systems (31,250 bbl/month/meter up to 75,000 bbl/month/meter) would be
proven every 75,000 bbl, or from 5 to 11 times per year, while meters
in the second group of LACT systems (75,000 bbl/month/meter up to
100,000 bbl/month/meter) would be proven monthly, or 12 times each
year. There would be no change in proving frequency for properties
producing at or above 100,000 bbl/month/meter (one proving per month,
or 12 per year) or below 31,250 bbl/month/meter (one proving per
quarter, or four per year).
In addition, there will be a one-time cost to retrofit an estimated
20 percent of existing LACT systems of about $1.9 million, or a one-
time average cost of about $6,500 for each of an estimated
approximately 296 existing LACT systems. This amounts to an average
one-time cost of $519 for each of the approximately 3,700 lessees/
operators conducting oil production operations on Federal or Indian
leases. The requirement for operators to conduct tank strappings to
submit revised calibration tables to the BLM will have an annual cost
to operators of $4.0 million per year (approximately $1,080 per
entity), plus an additional $0.2 million in industry paperwork costs
for submitting these tables, and $0.2 million in additional costs to
the BLM to process these paperwork submissions. When adding the
additional cost of hourly recordkeeping and non-hourly provisions in
the final rule, the BLM estimates that the rule will have a total
impact of $3.3 million in one-time costs and $4.6 million in annual
costs. When the one-time costs are annualized for the first 3 years
following the enactment of the final rule, and combined with annual
costs for these years, the BLM estimates a total annualized cost of
$5.7 million per year, or $1,540 per entity per year, for years 1-3
after the final rule's effective date. After year three, costs will
equal the estimated annual cost of $4.6 million, or $1,240 per entity
per year. All of the provisions apply to entities regardless of size.
However, entities with the greatest activity likely will experience the
greatest increase in compliance costs.
Based on the available information, we conclude that the final rule
will not have a significant impact on a substantial number of small
entities. The final rule will cost each entity an average of less than
$2,000 per year, which will impact expected annual operator net income
by less than 0.01 percent, as described in the Regulatory Impact
Analysis for this rule. Therefore, a final Regulatory Flexibility
Analysis is not required, and a Small Entity Compliance Guide is not
required.
Small Business Regulatory Enforcement Fairness Act
This final rule is not a major rule under 5 U.S.C. 804(2), the
Small Business Regulatory Enforcement Fairness Act. This rule will not
have an annual effect on the economy of $100 million or more. As
explained under the preamble discussion concerning E.O. 12866,
Regulatory Planning and Review, changes to oil measurement under this
final rule relative to the existing requirements of Order 4 will
increase the cost associated with the development and production of
crude oil resources under Federal and Indian oil and gas leases by
about $4.8 million annually. Of this amount, about $3.9 million/year
will be borne by industry, and $0.9 million/year by the BLM. There will
also be a one-time cost of about $1.9 million to retrofit an estimated
20 percent of existing LACT systems, borne entirely by industry.
Based on the cost figures above, the estimated annual increased
cost to the estimated 3,700 lessees/operators conducting oil production
operations on Federal or Indian leases for implementing these changes
is about $1,055 per year, and a one-time average cost of about $520 per
entity.
This final rule:
Will not cause a major increase in costs or prices for
consumers, individual industries, Federal, State, tribal, or local
government agencies, or geographic regions; and
Will not have significant adverse effects on competition,
employment, investment, productivity, innovation, or the ability of
U.S.-based enterprises to compete with foreign-based enterprises.
Unfunded Mandates Reform Act
In accordance with the Unfunded Mandates Reform Act (2 U.S.C. 1501
et seq.), the BLM finds that:
This final rule will not ``significantly or uniquely''
affect small
[[Page 81500]]
governments. A Small Government Agency Plan is unnecessary.
This final rule will not produce a Federal mandate of $100
million or greater in any single year.
The final rule is not a ``significant regulatory action'' as it
will not require anything of any non-Federal governmental entity.
Executive Order 12630, Governmental Actions and Interference With
Constitutionally Protected Property Rights (Takings)
Under E.O. 12630, the final rule would not have significant takings
implications. A takings implication assessment is not required. This
final rule will establish the minimum standards for accurate
measurement and proper reporting of oil produced from Federal and
Indian leases, unit PAs, and CAs, by providing a system for production
accountability by operators and lessees. All such actions are subject
to lease terms that expressly require that subsequent lease activities
be conducted in compliance with applicable Federal laws and
regulations. The final rule conforms to the terms of those Federal
leases and applicable statutes, and as such the final rule is not a
governmental action capable of interfering with constitutionally
protected property rights. Therefore, the final rule will not cause a
taking of private property and does not require further discussion of
takings implications under this E.O.
Executive Order 13132, Federalism
In accordance with E.O. 13132, the BLM finds that the final rule
will not have significant Federalism effects. A Federalism assessment
is not required. This final rule will not change the role of or shift
responsibilities among Federal, State, and local governmental entities.
It does not relate to the structure and role of the States and will not
have direct, substantive, or significant effects on States.
Executive Order 13175, Consultation and Coordination With Indian Tribal
Governments
Under Executive order 13175, the President's memorandum of April
29, 1994, ``Government-to-Government Relations with Native American
Tribal Governments'' (59 FR 22951), and 512 Departmental Manual 2, the
BLM evaluated possible effects of the final rule on federally
recognized Indian tribes. The BLM approves proposed operations on all
Indian (except Osage Tribe) onshore oil and gas leases. Therefore, the
final rule has the potential to affect Indian tribes. In conformance
with the Secretary's policy on tribal consultation, the BLM held tribal
consultation meetings to which more than 175 tribal entities were
invited, both before the rule was proposed and during the public
comment period on the proposed rule. The consultations were held in:
Pre-Publication Meetings
Tulsa, Oklahoma on July 11, 2011;
Farmington, New Mexico on July 13, 2011; and
Billings, Montana on August 24, 2011.
Tribal workshop and webcast in Washington, DC on April 24,
2013.
Post-Publication Meetings
The BLM hosted a webinar to discuss the requirements of
the proposed rule and solicit feedback from affected tribes on November
19, 2015; and
In-person meetings were held in:
[cir] Durango Colorado, on December 1, 2015;
[cir] Oklahoma City, Oklahoma, on December 3, 2015; and
[cir] Dickinson, North Dakota, on December 8, 2015.
The BLM also met with interested tribes on a one-on-one basis, if
requested to address questions on the proposed rule prior to the
publication of the final rule. In each instance, the purpose of these
meetings was to solicit feedback and comments from the tribes. The
primary concerns expressed by tribes related to the subordination of
tribal laws, rules, and regulations by the proposed rule; tribal
representation on the Department's Gas and Oil Measurement Team; and
the BLM's Inspection and Enforcement program's ability to enforce the
terms of this rule. In general, the tribes, as royalty recipients,
expressed support for the goals of the rulemaking, namely accurate
measurement. With respect to tribal representation on the Department's
Gas and Oil Measurement Team, it should be noted that the team is
internal to BLM. That said, the BLM will continue to consult with
tribes on measurement issues that impact them and their resources. None
of the tribal comments received were directed specifically at this
rule's oil measurement requirements, and therefore no changes were made
as a result of these comments. While the BLM will continue to address
these concerns, none of the concerns affect the substance of the
proposed rule.
Executive Order 12988, Civil Justice Reform
Under E.O. 12988, the Office of the Solicitor has determined that
the final rule will not unduly burden the judicial system and meets the
requirements of Sections 3(a) and 3(b)(2) of the E.O. The Office of the
Solicitor has reviewed the final rule to eliminate drafting errors and
ambiguity. It has been written to minimize litigation, provide clear
legal standards for affected conduct rather than general standards, and
promote simplification and burden reduction.
Executive Order 13352, Facilitation of Cooperative Conservation
Under E.O. 13352, the BLM has determined that this final rule will
not impede cooperative conservation and will take appropriate account
of and consider the interests of persons with ownership or other
legally recognized interests in land or other natural resources. This
rulemaking process involved Federal, tribal, State, and local
governments, private for-profit and nonprofit institutions, other
nongovernmental entities and individuals in the decision-making via the
public comment process. That process provides that the programs,
projects, and activities are consistent with protecting public health
and safety.
Paperwork Reduction Act
The Paperwork Reduction Act (PRA) (44 U.S.C. 3501-3521) provides
that an agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information, unless it displays a
currently valid OMB control number. Collections of information include
requests and requirements that an individual, partnership, or
corporation obtain information, and report it to a Federal agency. See
44 U.S.C. 3502(3); 5 CFR 1320.3(c) and (k).
This rule contains information collection activities that require
approval by the OMB under the Paperwork Reduction Act. The BLM included
an information collection request in the proposed rule. OMB has
approved the information collection for the final rule under control
number 1004-0209.
The information collection activities in this rule are described
below along with estimates of the annual burdens. Included in the
burden estimates are the time for reviewing instruction, searching
existing data sources, gathering and maintaining the data needed, and
completing and reviewing each component of the proposed information
collection.
Summary of Information Collection Activities
Title: Measurement of Oil (43 CFR parts 3160 and 3170).
Forms: None.
[[Page 81501]]
OMB Control Number: 1004-0209.
Description of Respondents: Oil and gas operators.
Abstract: This final rule replaces Onshore Oil and Gas Order Number
4, Measurement of Oil (Order 4) with new regulations that will be
codified at 43 CFR parts 3160 and 3170. This rule establishes minimum
standards for the measurement of oil produced from Federal and Indian
(except Osage Tribe) leases to ensure accurate measurement and
accounting. It also updates the minimum standards for oil measurement
to reflect the considerable changes in technology and industry
practices that have occurred since 1989, when Order 4 was issued.
Frequency of Collection: On occasion.
Obligation to Respond: Required to obtain or retain benefits.
Estimated Annual Responses: 11,707.
Estimated One-Time Responses: 35.
Estimated Annual Reporting and Recordkeeping ``Hour'' Burden:
3,284.
Estimated One-Time Reporting and Recordkeeping ``Hour'' Burden:
2,600.
Discussion of Information Collection Activities
The information collection activities in the final rule are
discussed below.
Request for Exception to Uncertainty Requirements (43 CFR 3174.4(a)(2))
The final rule, at 43 CFR 3174.4(a), requires each FMP to achieve
certain overall uncertainty levels. An operator may seek an exception
to the prescribed uncertainty levels by submitting a request to a BLM
State Director. The operator must show that meeting the required
uncertainly level would involve extraordinary cost or unacceptable
adverse environmental effects. The State Director may grant such a
request only with written concurrence from the PMT (prepared in
coordination with the Deputy Director). This provision enables the BLM
to determine whether or not it is reasonable to grant an exception to
uncertainty requirements.
Tank Calibration Tables (43 CFR 3174.5(c)(3))
Section 3174.5(c)(3) requires submission of tank calibration tables
to the BLM within 30 days after calibration. This provision ensures
that BLM personnel will have the latest charts when conducting
inspections or audits.
Approval of Automatic Tank Gauging (ATG) Equipment (43 CFR
3174.6(b)(5)(ii)(A)); and Log of ATG Verification (43 CFR
3174.6(b)(5)(ii)(C))
The procedures for oil measurement by tank gauging must comply with
the requirements outlined in 43 CFR 3174.6. Beginning on January 17,
2019, only the specific makes and models of ATG that are identified and
described at the BLM Web site (www.blm.gov) are approved for use.
If an operator chooses to use a particular make or model of ATG
equipment, the operator (or the manufacturer of the ATG equipment) must
seek and obtain BLM approval of the particular make and model of that
equipment by submitting a request to the PMT, consisting of a panel of
BLM employees who are oil and gas measurement experts. The submission
must describe the test data used to develop performance specifications.
After reviewing the test data, the PMT will recommend whether or not to
approve the ATG equipment. This information collection activity enables
the BLM to consider approving new technologies not yet addressed in its
regulations.
The operator must inspect its ATG equipment and verify its accuracy
at least once a month, or prior to sales, whichever is later. In
addition, the BLM may request inspection and verification at any time.
If the operator finds ATG equipment to be out of tolerance, the
operator must calibrate the equipment prior to sales, and must maintain
a log of field verifications. That operator must make the log available
to the BLM upon request. The log must include the following
information:
The date of verification;
The as-found manual gauge readings;
The as-found ATG readings; and
Whether the ATG equipment was field-calibrated.
If the ATG equipment was field-calibrated, the as-left manual gauge
readings and as-left ATG readings must be recorded. This information
collection activity enables the BLM to ensure the accuracy of tank
gauging by ATG systems.
Notification of LACT System Failure (43 CFR 3174.7(e)(1))
Section 3174.7(e)(1) requires the operator to notify the BLM within
72 hours of any LACT system failures or equipment malfunctions which
may have resulted in measurement error. As defined at proposed Sec.
3174.1, a LACT system consists of components designed to provide for
the unattended custody transfer of oil produced from a lease, unit PA,
or Communitized Area (CA) to the transporting carrier while providing a
proper and accurate means for determining the net standard volume and
quality, and fail-safe and tamper-proof operations. This information
collection requirement enables the BLM to verify that operators account
for all oil volumes.
Approval of a Positive Displacement (PD) Meter (43 CFR 3174.8(a)(1));
and Approval of a Coriolis Meter (43 CFR 3174.9(b))
Section 3174.8(a)(1) requires each custody transfer meter to be a
PD meter or a Coriolis meter. A PD meter measures liquid by constantly
and mechanically isolating flowing liquid into segments of known
volume. A Coriolis meter measures liquid via the interaction between a
flowing fluid and oscillation of tubes. Beginning on January 17, 2019,
only the specific make, models, and sizes of PD meters and Coriolis
meters and associated software that are identified and described at
www.blm.gov are approved for use.
If an operator chooses to use a particular make or model of PD
meter or Coriolis meter, the operator (or the manufacturer of the
meter) must seek and obtain BLM approval of that particular make and
model by submitting a request to the PMT. The submission must describe
the test data used to develop performance specifications. After
reviewing the test data, the PMT will recommend whether or not to
approve the meter. This information collection activity enables the BLM
to consider approving new technologies not yet addressed in its
regulations.
Coriolis Meter Specification and Zero Verification Procedure (43 CFR
3174.10(b)(2) and (d)); Zero Verification Log (43 CFR 3174.10(b)(2) and
(e)(4)); and Audit Trail Requirements for Coriolis Measurement System
(CMS) (43 CFR 3174.10(b)(2) and (f))
Section 3174.10(b)(2) requires the operator to submit Coriolis
meter specifications to the BLM upon request. The meter specification
of a Coriolis meter must clearly identify the make and model of the
Coriolis meter to which they apply and must include the following:
The reference accuracy for both mass flow rate and
density, stated in either percent of reading, percent of full scale, or
units of measure;
The effect of changes in temperature and pressure on both
mass flow and fluid density readings;
The effect of flow rate on density readings;
The stability of the zero reading for volumetric flow
rate;
Design limits for flow rate and pressure; and
[[Page 81502]]
Pressure drop through the meter as a function of flow rate
and fluid viscosity.
Section 3174.10(d) requires the operator to provide the BLM with a
copy of the zero value verification procedure upon request.
Section 3174.10(e)(4) requires the operator to maintain a log of
all meter factors, zero verifications, and zero adjustments. For zero
adjustments, the log must include the zero value before adjustment and
the zero value after adjustment. The log must be made available to the
BLM upon request.
Section 3174.10(f) requires the operator to record and retain, and
submit to the BLM upon request, the following information:
Quantity transaction record (QTR) in accordance with the
requirements for a measurement ticket (at 43 CFR 3174.12(b));
Configuration log that contains and identifies all
constant flow parameters used in generating the QTR;
Event log of sufficient capacity to record all events such
that the operator can retain the information under the recordkeeping
requirements of 43 CFR 3170.7; and
Alarm log that records the type and duration of any of the
following alarm conditions:
[cir] Density deviations from acceptable parameters; and
[cir] Instances in which the flow rate exceeded the manufacturer's
maximum recommended flow rate or were below the manufacturer's minimum
recommended flow rate.
These information collection activities will assist the BLM in ensuring
real-time, on-line measurement of oil.
Meter Proving and Volume Adjustments Notification (43 CFR
3174.11(i)(1)); and Meter Proving Reports (43 CFR 3174.11(i)(3))
Section 3174.11 specifies the minimum requirements for conducting
volumetric meter proving for all FMP meters. Meter proving verifies the
accuracy of a meter.
Under 43 CFR 3174.11(i)(1), an operator must report to the BLM all
meter-proving and volume adjustments after any LACT system or CMS
malfunction. The operator must use the appropriate form in API 12.2.3
or API 5.6 (both incorporated by reference at 43 CFR 3174.3), or use a
similar format showing the same information as the API form, provided
that the calculation of meter factors maintains the proper calculation
sequence and rounding.
In addition, a meter-proving report must show the:
Unique meter ID number;
Lease number, CA number, or unit PA number;
The temperature from the test thermometer and the
temperature from the temperature averager or temperature transducer;
For pressure transducers, the pressure applied by the
pressure test device and the pressure reading from the pressure
transducer at the three points required under paragraph (g)(3) of this
section;
For density verification (if applicable), the
instantaneous flowing density (as determined by Coriolis meter), and
the independent density measurement, as compared under 43 CFR 3174.(h);
and
The ``as left'' fluid flow rate and fluid pressure, if the
back pressure valve is adjusted after proving as described in 43 CFR
3174.11(c)(9).
Under Sec. 3174.11(i)(3), the operator must submit the meter-
proving report to the BLM no later than 14 days after the meter
proving. The proving report may be either in a hard copy or electronic
format.
These information collection activities will assist in ensuring the
accuracy of meters.
Tank Gauging Run Tickets (43 CFR 3174.12(a)); and LACT or CMS Run
Tickets (43 CFR 3174.12(b))
A run ticket is the evidence of receipt or delivery of oil issued
by a pipeline, other carrier, or purchaser. The amount of oil
transferred from storage is recorded on a run ticket. The amount of
payment for oil is based upon information contained in the run ticket.
Tank gauging (43 CFR 3174.12(a))--After oil is measured by tank
gauging, the operator, purchaser, or transporter, as appropriate, must
complete a uniquely numbered measurement ticket, in either paper or
electronic format, with the following information:
Lease, unit, or CA number;
Unique tank number and nominal tank capacity;
Opening and closing dates and times;
Opening and closing gauges and observed temperatures in
[deg]F;
Observed volume for opening and closing gauge;
Total gross standard volume removed from the tank;
Observed API oil gravity and temperature in [deg]F;
API oil gravity at 60 [deg]F;
S&W percent;
Unique number of each seal removed and installed;
Name of the individual performing the manual tank gauging;
and
Name of the operator.
LACT or CMS (43 CFR 3174.12(b))--The operator, purchaser, or
transporter, as appropriate, must complete a uniquely numbered
measurement ticket, in either paper or electronic format, at the
beginning of every month, and (unless a flow computer is being used in
accordance with 43 CFR 3174.10) before conducting proving operations on
a LACT system. The following information is required:
Lease, unit, or CA number;
Unique meter ID number;
Opening and closing dates;
Opening and closing totalizer readings of the indicated
volume;
Meter factor, indicating if it is a composite meter
factor;
Total gross standard volume removed through the LACT
system or CMS;
API oil gravity;
The average temperature in [deg]F;
The average flowing pressure in psig;
S&W percent;
Unique number of each seal removed and installed;
Name of the purchaser's representative; and
Name of the operator.
Request To Use Alternate Oil Measurement System (43 CFR 3174.13)
Section 3174.13 requires prior BLM approval for any method of oil
measurement other than manual tank gauging, LACT system, or CMS at an
FMP. Any operator requesting approval to use alternate oil measurement
equipment must submit to the BLM:
Performance data;
Actual field test results;
Laboratory test data; or
Any other supporting data or evidence that demonstrates
that the proposed alternate oil measurement equipment would meet or
exceed the objectives of the applicable minimum requirements at 43 CFR
subpart 3174 and would not affect royalty income or production
accountability.
The PMT will review and make recommendations in response to
requests to use alternate oil-measurement equipment. This information
collection activity enables the BLM to consider approving new
technologies not yet addressed in its regulations.
Approval for Slop or Waste Oil (43 CFR 3174.14)
When production cannot be measured due to spillage or leakage, the
amount of production must be determined by using any method the BLM
approves or prescribes. This category of production includes, but is
not limited to, oil that is classified as slop oil or waste oil.
[[Page 81503]]
No oil may be classified or disposed of as waste oil unless the
operator can demonstrate to the satisfaction of the BLM that it is not
economically feasible to put the oil into marketable condition.
The operator may not sell or otherwise dispose of slop oil without
prior written approval from the BLM. Following the sale or disposal of
slop oil, the operator must notify the BLM in writing of the volume
sold or disposed of and the method used to compute the volume.
The following table itemizes the estimated hour burdens for this
rule:
Estimated Hour Burdens
----------------------------------------------------------------------------------------------------------------
Number of Hours per
Type of response responses response Total hours
A. B. C. D.
----------------------------------------------------------------------------------------------------------------
Request for Exception to Uncertainty Requirements--43 CFR 5 40 200
3174.4(a)(2)--One-Time.........................................
Request for Exception to Uncertainty Requirements--43 CFR 2 40 80
3174.4(a)(2)--Annual...........................................
Documentation of Tank Calibration Table Strapping--43 CFR 10,000 .25 2,500
3174.5(c)(3)--Annual...........................................
Documentation of Testing for Approval of Automatic Tank Gauging 5 80 400
(ATG) Equipment--43 CFR 3174.6(b)(5)(ii)(A)--One-Time..........
Documentation of Testing for Approval of Automatic Tank Gauging 1 80 80
(ATG) Equipment--43 CFR 3174.6(b)(5)(ii)(A)--Annual............
Log of ATG Verification--43 CFR 3174.6(b)(5)(ii)(C)--Annual..... 18 0.1 1.8
Notification of LACT System Failure--43 CFR 3174.7(e)(1)--Annual 100 0.25 25
Documentation of Testing for Approval of a Positive Displacement 10 80 800
(PD) Meter--43 CFR 3174.8(a)(1)--One-Time......................
Documentation of Testing for Approval of a Positive Displacement 1 80 80
(PD) Meter--43 CFR 3174.8(a)(1)--Annual........................
Documentation of Testing for Approval of a Coriolis Meter 43 CFR 10 80 800
3174.9(b)--One Time............................................
Documentation of Testing for Approval of a Coriolis Meter 43 CFR 1 80 80
3174.9(b)--Annual..............................................
Documentation of Zero Verification Procedure--43 CFR 100 0.1 10
3174.10(b)(2) and (d)--Annual..................................
Zero Verification Log--43 CFR 3174.10(b)(2) and (e)(4)--Annual.. 100 0.1 10
Audit Trail Requirements for Coriolis Measurement System (CMS)-- 500 0.25 125
43 CFR 3174.10(b)(2) and (f)--Annual...........................
Onsite Data Display Requirements--43 CFR 3174.10(e)--Annual..... 500 0.1 50
Meter Prover Calibration Documentation--43 CFR 3174.11(b)-- 150 0.5 75
Annual.........................................................
Meter Proving and Volume Adjustments Notification--43 CFR 60 0.1 6
3174.11(i)(1)--Annual..........................................
Meter Proving Reports--43 CFR 3174.11(i)(3)--Annual............. 123 0.25 31
Request to Use Alternate Oil Measurement System--43 CFR 3174.13-- 5 80 400
One Time.......................................................
Request to Use Alternate Oil Measurement System--43 CFR 3174.13-- 1 80 80
Annual.........................................................
Approval for Slop or Waste Oil--43 CFR 3174.14--Annual.......... 50 1 50
-----------------------------------------------
Total Annual Costs.......................................... 11,707 .............. 3,284
-----------------------------------------------
Total One-Time Costs........................................ 35 .............. 2,600
----------------------------------------------------------------------------------------------------------------
National Environmental Policy Act (NEPA)
The BLM prepared an environmental assessment (EA), a Finding of No
Significant Impact (FONSI), and a Decision Record (DR) that conclude
that the final rule would not constitute a major Federal action
significantly affecting the quality of the human environment under
NEPA, 42 U.S.C. 4332(2)(C). Therefore, a detailed environmental impact
statement (EIS) under NEPA is not required. A copy of the EA, FONSI,
and DR are available for review and on file in the BLM Administrative
Record at the location specified in the ADDRESSES section.
As explained in the EA, FONSI, and DR, the final rule would not
have a significant effect on the human environment because, for the
most part, its requirements involve changes that are of an
administrative, technical, or procedural nature that apply to the BLM's
and the lessee's or operator's administrative processes. For example,
the rule allows operators to use a CMS or an ATG/hybrid tank
measurement system without receiving a variance from the BLM as they
must do now. The final rule also adopts a process and criteria that
will allow for the PMT to review any new measurement system or method
approval requests submitted to the BLM.
Overall these changes will enhance the agency's ability to account
for the oil and gas produced from Federal and Indian lands, but should
have minimal to no impact on the environment. Some of these standards,
such as the requirement that operators replace their automatic
temperature/gravity compensators with temperature averaging devices,
may result in increased human presence and traffic on existing
disturbed surfaces, but these activities are expected to have a
negligible impact on the quality of the human environment, as discussed
in the final EA.
A draft of the EA was shared with the public during the public
comment period on the proposed rule. As part of that process, the BLM
received comments on the EA. Commenters questioned the BLM's level of
NEPA documentation, whether or not the BLM had met the ``hard look''
test of describing the environmental consequences of the proposed
action, and the BLM's ability to reach a FONSI based on the level of
analysis. One commenter requested a complete NEPA revision with formal
scoping of the EA and a meaningful socioeconomic analysis. Many
commenters questioned the use of three separate EAs to disclose impacts
of Order 3, Order 4, and Order 5, stating that the Council on
Environmental Quality (CEQ) regulations require connected actions to be
evaluated in a single document. These commenters suggested a single EIS
to address all three rules.
CEQ's NEPA regulations at 40 CFR 1508.18 identify new or revised
agency rules and regulations as an example of a Federal action.
Drafting new agency regulations that ``are of an administrative . . .
technical, or
[[Page 81504]]
procedural nature'' is categorically excluded from NEPA review pursuant
to 43 CFR 46.210(i). The BLM nevertheless chose to complete a more
robust level of NEPA documentation in the form of an EA. By preparing a
separate EA for new subpart 3173, 3174, and 3175 regulations, the BLM
was able to disclose the potential environmental effects of the Federal
agency decisions on each of the regulations. Clearly, the BLM's level
of analysis was more thorough than the categorical exclusion
documentation required by NEPA. Additionally, a thorough socioeconomic
analysis was completed in the BLM's regulatory impact analysis of the
proposed rule, which was referenced in the EA.
Other commenters stated the BLM did not adequately address
potential surface impacts to private land, minimized environmental
surface impacts, did not address a reasonable range of alternatives,
and did not adequately describe the Affected Environment. The BLM
anticipates that in the majority of cases, operators will use existing
surface disturbances such as existing well pad locations in connection
with activities undertaken in compliance with the final rule, which
will minimize new surface construction and surface impacts. Any new
facilities will likely be constructed on a lease, relocated to an
existing facility, or retrofitted to an existing facility. Similarly,
the codification of BLM regulations does not hinder or prevent
development of private minerals. The likelihood of impacts to private
surface is low. In the rare instance that new pipelines or other
facilities must be developed on private surface to comply with this
rule, BLM authorization for activities on split estate would include
site-specific NEPA documentation, with appropriate project-level
mitigation. The BLM's obligation under NEPA is to analyze alternatives
that would meet the Bureau's purpose and need and allow for a reasoned
choice to be made. As described in the EA, a number of alternatives
were considered, but eliminated from detailed study because they did
not meet the purpose and need. Discussion of the affected environment
should only contain data and analysis commensurate in detail with the
importance of the impacts, which the BLM anticipates to be minimal.
The EA, FONSI, and DR were updated to address these comments, but
the updates did not change the BLM's overall analysis of the potential
environmental impacts of the rule.
Executive Order 13211, Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
Although this rule amends the BLM's oil production regulations, it
will not have a substantial direct effect on the nation's energy
supply, distribution, or use, including a shortfall in supply or price
increases. Changes in this rule strengthen the BLM's production
accountability requirements for operators holding Federal and Indian
oil leases. As discussed previously, among other things, this rule
establishes objective measurement performance standards, updates
recordkeeping requirements, and establishes uniform national
requirements for operators who wish to use CMSs or ATG systems. As
explained in detail in the BLM's regulatory impact analysis, all of
these changes will increase the regulated community's annual costs by
about $3.9 million, or about $1,055 per entity per year.
The BLM expects that the rule will not result in a net change in
the quantity of oil that is produced from Federal and Indian leases.
Information Quality Act
In developing this rule, the BLM did not conduct or use a study,
experiment, or survey requiring peer review under the Information
Quality Act (Pub. L. 106-554, Appendix C Title IV, 515, 114 Stat.
2763A-153).
Authors
The principal authors of this final rule are Mike McLaren,
Petroleum Engineer, BLM Pinedale Field Office; Tom Zelenka, Petroleum
Engineer, BLM New Mexico State Office; Chris DeVault, I&E Coordinator,
BLM Montana State Office; Jeff Prude, Petroleum Engineer, BLM
Bakersfield Field Office; and Frank Sanders, Petroleum Engineer, BLM
Worland Field Office. The team was assisted by Faith Bremner, Jean
Sonneman and Ian Senio, Office of Regulatory Affairs, BLM Washington
Office; Michael Ford, Economist, BLM Washington Office; Barbara
Sterling, Natural Resource Specialist, BLM Colorado State Office; Bryce
Barlan, Senior Policy Analyst, BLM, Washington Office; Michael Wade,
BLM Washington Office; Rich Estabrook, BLM Washington Office; Dylan
Fuge, Counselor to the Director, BLM Washington Office; Christopher
Rhymes, Attorney Advisor, Office of the Solicitor, Department of the
Interior; and Geoffrey Heath (now retired).
List of Subjects
43 CFR Part 3160
Administrative practice and procedure, Government contracts,
Indians-lands, Mineral royalties, Oil and gas exploration, Penalties,
Public lands--mineral resources, Reporting and recordkeeping
requirements.
43 CFR Part 3170
Administrative practice and procedure, Immediate assessments,
Incorporation by reference, Indians-lands, Mineral royalties, Oil and
gas measurement, Public lands--mineral resources.
Dated: October 6, 2016.
Janice M. Schneider,
Assistant Secretary, Land and Minerals Management.
43 CFR Chapter II
For the reasons set out in the preamble, the Bureau of Land
Management is amending 43 CFR parts 3160 and 3170 as follows:
PART 3160--ONSHORE OIL AND GAS OPERATIONS
0
1. The authority citation for part 3160 continues to read as follows:
Authority: 25 U.S.C. 396d and 2107; 30 U.S.C. 189, 306, 359, and
1751; and 43 U.S.C. 1732(b), 1733, and 1740.
0
2. Revise Sec. 3162.7-2 to read as follows:
Sec. 3162.7-2 Measurement of oil.
All oil removed or sold from a lease, communitized area, or unit
participating area must be measured under subpart 3174 of this title.
All measurement must be on the lease, communitized area, or unit from
which the oil originated and must not be commingled with oil
originating from other sources, unless approved by the authorized
officer under the provisions of subpart 3173 of this title.
Sec. 3164.1 [Amended]
0
3. Amend Sec. 3164.1(b) by removing the fourth entry in the table,
Order No. 4, Measurement of Oil.
PART 3170--ONSHORE OIL AND GAS PRODUCTION
0
4. The authority citation for part 3170 continues to read as follows:
Authority: 25 U.S.C. 396d and 2107; 30 U.S.C. 189, 306, 359, and
1751; and 43 U.S.C. 1732(b), 1733, and 1740.
0
5. Add subpart 3174 to part 3170, to read as follows:
[[Page 81505]]
Subpart 3174--Measurement of Oil
Sec.
3174.1 Definitions and acronyms.
3174.2 General requirements.
3174.3 Incorporation by reference (IBR).
3174.4 Specific measurement performance requirements.
3174.5 Oil measurement by tank gauging--general requirements.
3174.6 Oil measurement by tank gauging--procedures.
3174.7 LACT systems--general requirements.
3174.8 LACT systems--components and operating requirements.
3174.9 Coriolis measurement systems (CMS)--general requirements and
components.
3174.10 Coriolis meter for LACT and CMS measurement applications--
operating requirements.
3174.11 Meter-proving requirements.
3174.12 Measurement tickets.
3174.13 Oil measurement by other methods.
3174.14 Determination of oil volumes by methods other than
measurement.
3174.15 Immediate assessments.
Sec. 3174.1 Definitions and acronyms.
(a) As used in this subpart, the term:
Barrel (bbl) means 42 standard United States gallons.
Base pressure means 14.696 pounds per square inch, absolute (psia).
Base temperature means 60 [deg]F.
Certificate of calibration means a document stating the base prover
volume and other physical data required for the calibration of flow
meters.
Composite meter factor means a meter factor corrected from normal
operating pressure to base pressure. The composite meter factor is
determined by proving operations where the pressure is considered
constant during the measurement period between provings.
Configuration log means the list of constant flow parameters,
calculation methods, alarm set points, and other values that are
programmed into the flow computer in a CMS.
Coriolis meter means a device which by means of the interaction
between a flowing fluid and oscillation of tube(s) infers a mass flow
rate. The meter also infers the density by measuring the natural
frequency of the oscillating tubes. The Coriolis meter consists of
sensors and a transmitter, which convert the output from the sensors to
signals representing volume and density.
Coriolis measurement system (CMS) means a metering system using a
Coriolis meter in conjunction with a tertiary device, pressure
transducer, and temperature transducer in order to derive and report
gross standard oil volume. A CMS system provides real-time, on-line
measurement of oil.
Displacement prover means a prover consisting of a pipe or pipes
with known capacities, a displacement device, and detector switches,
which sense when the displacement device has reached the beginning and
ending points of the calibrated section of pipe. Displacement provers
can be portable or fixed.
Dynamic meter factor means a kinetic meter factor derived by linear
interpolation or polynomial fit, used for conditions where a series of
meter factors have been determined over a range of normal operating
conditions.
Event log means an electronic record of all exceptions and changes
to the flow parameters contained within the configuration log that
occur and have an impact on a quantity transaction record.
Gross standard volume means a volume of oil corrected to base
pressure and temperature.
Indicated volume means the uncorrected volume indicated by the
meter in a lease automatic custody transfer system or the Coriolis
meter in a CMS. For a positive displacement meter, the indicated volume
is represented by the non-resettable totalizer on the meter head. For
Coriolis meters, the indicated volume is the uncorrected (without the
meter factor) mass of liquid divided by the density.
Innage gauging means the level of a liquid in a tank measured from
the datum plate or tank bottom to the surface of the liquid.
Lease automatic custody transfer (LACT) system means a system of
components designed to provide for the unattended custody transfer of
oil produced from a lease(s), unit PA(s), or CA(s) to the transporting
carrier while providing a proper and accurate means for determining the
net standard volume and quality, and fail-safe and tamper-proof
operations.
Master meter prover means a positive displacement meter or Coriolis
meter that is selected, maintained, and operated to serve as the
reference device for the proving of another meter. A comparison of the
master meter to the Facility Measurement Point (FMP) line meter output
is the basis of the master-meter method.
Meter factor means a ratio obtained by dividing the measured volume
of liquid that passed through a prover or master meter during the
proving by the measured volume of liquid that passed through the line
meter during the proving, corrected to base pressure and temperature.
Net standard volume means the gross standard volume corrected for
quantities of non-merchantable substances such as sediment and water.
Outage gauging means the distance from the surface of the liquid in
a tank to the reference gauge point of the tank.
Positive displacement meter means a meter that registers the volume
passing through the meter using a system which constantly and
mechanically isolates the flowing liquid into segments of known volume.
Quantity transaction record (QTR) means a report generated by CMS
equipment that summarizes the daily and hourly gross standard volume
calculated by the flow computer and the average or totals of the
dynamic data that is used in the calculation of gross standard volume.
Tertiary device means, for a CMS, the flow computer and associated
memory, calculation, and display functions.
Transducer means an electronic device that converts a physical
property, such as pressure, temperature, or electrical resistance, into
an electrical output signal that varies proportionally with the
magnitude of the physical property. Typical output signals are in the
form of electrical potential (volts), current (milliamps), or digital
pressure or temperature readings. The term transducer includes devices
commonly referred to as transmitters.
Vapor tight means capable of holding pressure differential only
slightly higher than that of installed pressure-relieving or vapor
recovery devices.
(b) As used in this subpart, the following acronyms carry the
meaning prescribed:
API means American Petroleum Institute.
CA has the meaning set forth in Sec. 3170.3 of this part.
COA has the meaning set forth in Sec. 3170.3 of this part.
CPL means correction for the effect of pressure on a liquid.
CTL means correction for the effect of temperature on a liquid.
NIST means National Institute of Standards and Technology.
PA has the meaning set forth in Sec. 3170.3 of this part.
PMT means Production Measurement Team.
PSIA means pounds per square inch, absolute.
S&W means sediment and water.
Sec. 3174.2 General requirements.
(a) Oil may be stored only in tanks that meet the requirements of
Sec. 3174.5(b) of this subpart.
(b) Oil must be measured on the lease, unit PA, or CA, unless
approval for off-lease measurement is obtained under Sec. Sec. 3173.22
and 3173.23 of this part.
(c) Oil produced from a lease, unit PA, or CA may not be commingled
with
[[Page 81506]]
production from other leases, unit PAs, or CAs or non-Federal
properties before the point of royalty measurement, unless prior
approval is obtained under Sec. Sec. 3173.14 and 3173.15 of this part.
(d) An operator must obtain a BLM-approved FMP number under
Sec. Sec. 3173.12 and 3173.13 of this part for each oil measurement
facility where the measurement affects the calculation of the volume or
quality of production on which royalty is owed (i.e., oil tank used for
tank gauging, LACT system, CMS, or other approved metering device),
except as provided in paragraph (h) of this section.
(e) Except as provided in paragraph (h) of this section, all
equipment used to measure the volume of oil for royalty purposes
installed after January 17, 2017 must comply with the requirements of
this subpart.
(f) Except as provided in paragraph (h) of this section, measuring
procedures and equipment used to measure oil for royalty purposes, that
is in use on January 17, 2017, must comply with the requirements of
this subpart on or before the date the operator is required to apply
for an FMP number under 3173.12(e) of this part. Prior to that date,
measuring procedures and equipment used to measure oil for royalty
purposes, that is in use on January 17, 2017 must continue to comply
with the requirements of Onshore Oil and Gas Order No. 4, Measurement
of oil, Sec. 3164.1(b) as contained in 43 CFR part 3160, (revised
October 1, 2016), and any COAs and written orders applicable to that
equipment.
(g) The requirement to follow the approved equipment lists
identified in Sec. Sec. 3174.6(b)(5)(ii)(A), 3174.6(b)(5)(iii),
3174.8(a)(1), and 3174.9(a) does not apply until January 17, 2019. The
operator or manufacturer must obtain approval of a particular make,
model, and size by submitting the test data used to develop performance
specifications to the PMT to review.
(h) Meters used for allocation under a commingling and allocation
approval under Sec. 3173.14 are not required to meet the requirements
of this subpart.
Sec. 3174.3 Incorporation by reference (IBR).
(a) Certain material specified in this section is incorporated by
reference into this part with the approval of the Director of the
Federal Register under 5 U.S.C. 552(a) and 1 CFR part 51. Operators
must comply with all incorporated standards and material, as they are
listed in this section. To enforce any edition other than that
specified in this section, the BLM must publish a rule in the Federal
Register, and the material must be reasonably available to the public.
All approved material is available for inspection at the Bureau of Land
Management, Division of Fluid Minerals, 20 M Street SE., Washington, DC
20003, 202-912-7162; at all BLM offices with jurisdiction over oil and
gas activities; and is available from the sources listed below. It is
also available for inspection at the National Archives and Records
Administration (NARA). For information on the availability of this
material at NARA, call 202-741-6030 or go to https://www.archives.gov/federal_register/code_of_federal_regulations/ibr_locations.html.
(b) American Petroleum Institute (API), 1220 L Street NW.,
Washington, DC 20005; telephone 202-682-8000; API also offers free,
read-only access to some of the material at 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 (``API 2.2A''), IBR approved
for Sec. 3174.5(c).
(2) API MPMS Chapter 2--Tank Calibration, Section 2.2B, Calibration
of Upright Cylindrical Tanks Using the Optical Reference Line Method;
First Edition, March 1989, Reaffirmed January 2013 (``API 2.2B''), IBR
approved for Sec. 3174.5(c).
(3) API MPMS Chapter 2--Tank Calibration, Section 2C, Calibration
of Upright Cylindrical Tanks Using the Optical-triangulation Method;
First Edition, January 2002; Reaffirmed May 2008 (``API 2.2C''), IBR
approved for Sec. 3174.5(c).
(4) API MPMS Chapter 3, Section 1A, Standard Practice for the
Manual Gauging of Petroleum and Petroleum Products; Third Edition,
August 2013 (``API 3.1A''), IBR approved for Sec. Sec. 3174.5(b),
3174.6(b).
(5) API MPMS Chapter 3--Tank Gauging, Section 1B, Standard Practice
for Level Measurement of Liquid Hydrocarbons in Stationary Tanks by
Automatic Tank Gauging; Second Edition, June 2001; Reaffirmed August
2011 (``API 3.1B''), IBR approved for Sec. 3174.6(b).
(6) API MPMS Chapter 3--Tank Gauging, Section 6, Measurement of
Liquid Hydrocarbons by Hybrid Tank Measurement Systems; First Edition,
February 2001; Errata September 2005; Reaffirmed October 2011 (``API
3.6''), IBR approved for Sec. 3174.6(b).
(7) API MPMS Chapter 4--Proving Systems, Section 1, Introduction;
Third Edition, February 2005; Reaffirmed June 2014 (``API 4.1''), IBR
approved for Sec. 3174.11(c).
(8) API MPMS Chapter 4--Proving Systems, Section 2, Displacement
Provers; Third Edition, September 2003; Reaffirmed March 2011, Addendum
February 2015 (``API 4.2''), IBR approved for Sec. Sec. 3174.11(b) and
(c).
(9) API MPMS Chapter 4, Section 5, Master-Meter Provers; Fourth
Edition, June 2016, (``API 4.5''), IBR approved for Sec. 3174.11(b).
(10) API MPMS Chapter 4--Proving Systems, Section 6, Pulse
Interpolation; Second Edition, May 1999; Errata April 2007; Reaffirmed
October 2013 (``API 4.6''), IBR approved for Sec. 3174.11(c).
(11) API MPMS Chapter 4, Section 8, Operation of Proving Systems;
Second Edition, September 2013 (``API 4.8''), IBR approved for Sec.
3174.11(b).
(12) API MPMS Chapter 4--Proving Systems, Section 9, Methods of
Calibration for Displacement and Volumetric Tank Provers, Part 2,
Determination of the Volume of Displacement and Tank Provers by the
Waterdraw Method of Calibration; First Edition, December 2005;
Reaffirmed July 2015 (``API 4.9.2''), IBR approved for Sec.
3174.11(b).
(13) API MPMS Chapter 5--Metering, Section 6, Measurement of Liquid
Hydrocarbons by Coriolis Meters; First Edition, October 2002;
Reaffirmed November 2013 (``API 5.6''), IBR approved for Sec. Sec.
3174.9(e), 3174.11(h) and (i).
(14) API MPMS Chapter 6--Metering Assemblies, Section 1, Lease
Automatic Custody Transfer (LACT) Systems; Second Edition, May 1991;
Reaffirmed May 2012 (``API 6.1''), IBR approved for Sec. 3174.8(a) and
(b).
(15) API MPMS Chapter 7, Temperature Determination; First Edition,
June 2001, Reaffirmed February 2012 (``API 7''), IBR approved for
Sec. Sec. 3174.6(b), 3174.8(b).
(16) API MPMS Chapter 7.3, Temperature Determination--Fixed
Automatic Tank Temperature Systems; Second Edition, October 2011 (``API
7.3''), IBR approved for Sec. 3174.6(b).
(17) API MPMS Chapter 8, Section 1, Standard Practice for Manual
Sampling of Petroleum and Petroleum Products; Fourth Edition, October
2013 (``API 8.1''), IBR approved for Sec. Sec. 3174.6(b), 3174.11(h).
(18) API MPMS Chapter 8, Section 2, Standard Practice for Automatic
Sampling of Petroleum and Petroleum Products; Third Edition, October
2015 (``API 8.2''), IBR approved for Sec. Sec. 3174.6(b), 3174.8(b),
3174.11(h).
(19) API MPMS Chapter 8--Sampling, Section 3, Standard Practice for
Mixing
[[Page 81507]]
and Handling of Liquid Samples of Petroleum and Petroleum Products;
First Edition, October 1995; Errata March 1996; Reaffirmed, March 2010
(``API 8.3''), IBR approved for Sec. Sec. 3174.8(b), 3174.11(h).
(20) API MPMS Chapter 9, Section 1, Standard Test Method for
Density, Relative Density, or API Gravity of Crude Petroleum and Liquid
Petroleum Products by Hydrometer Method; Third Edition, December 2012
(``API 9.1''), IBR approved for Sec. Sec. 3174.6(b), 3174.8(b).
(21) API MPMS Chapter 9, Section 2, Standard Test Method for
Density or Relative Density of Light Hydrocarbons by Pressure
Hydrometer; Third Edition, December 2012 (``API 9.2''), IBR approved
for Sec. Sec. 3174.6(b), 3174.8(b).
(22) API MPMS Chapter 9, Section 3, Standard Test Method for
Density, Relative Density, and API Gravity of Crude Petroleum and
Liquid Petroleum Products by Thermohydrometer Method; Third Edition,
December 2012 (``API 9.3''), IBR approved for Sec. Sec. 3174.6(b),
3174.8(b).
(23) API MPMS Chapter 10, Section 4, Determination of Water and/or
Sediment in Crude Oil by the Centrifuge Method (Field Procedure);
Fourth Edition, October 2013; Errata March 2015 (``API 10.4''), IBR
approved for Sec. Sec. 3174.6(b), 3174.8(b).
(24) API MPMS Chapter 11--Physical Properties Data, Section 1,
Temperature and Pressure Volume Correction Factors for Generalized
Crude Oils, Refined Products and Lubricating Oils; May 2004, Addendum 1
September 2007; Reaffirmed August 2012 (``API 11.1''), IBR approved for
Sec. Sec. 3174.9(f), 3174.12(a).
(25) API MPMS Chapter 12--Calculation of Petroleum Quantities,
Section 2, Calculation of Petroleum Quantities Using Dynamic
Measurement Methods and Volumetric Correction Factors, Part 1,
Introduction; Second Edition, May 1995; Reaffirmed March 2014 (``API
12.2.1''), IBR approved for Sec. Sec. 3174.8(b), 3174.9(g).
(26) API MPMS Chapter 12--Calculation of Petroleum Quantities,
Section 2, Calculation of Petroleum Quantities Using Dynamic
Measurement Methods and Volumetric Correction Factors, Part 2,
Measurement Tickets; Third Edition, June 2003; Reaffirmed September
2010 (``API 12.2.2''), IBR approved for Sec. Sec. 3174.8(b),
3174.9(g).
(27) API MPMS Chapter 12--Calculation of Petroleum Quantities,
Section 2, Calculation of Petroleum Quantities Using Dynamic
Measurement Methods and Volumetric Correction Factors, Part 3, Proving
Report; First Edition, October 1998; Reaffirmed March 2009 (``API
12.2.3''), IBR approved for Sec. 3174.11(c) and (i).
(28) API MPMS Chapter 12--Calculation of Petroleum Quantities,
Section 2, Calculation of Petroleum Quantities Using Dynamic
Measurement Methods and Volumetric Correction Factors, Part 4,
Calculation of Base Prover Volumes by the Waterdraw Method; First
Edition, December 1997; Reaffirmed March 2009; Errata July 2009 (``API
12.2.4''), IBR approved for Sec. 3174.11(b).
(29) API MPMS Chapter 13--Statistical Aspects of Measuring and
Sampling, Section 1, Statistical Concepts and Procedures in
Measurements; First Edition, June 1985 Reaffirmed February 2011; Errata
July 2013 (``API 13.1''), IBR approved for Sec. 3174.4(a).
(30) API MPMS Chapter 13, Section 3, Measurement Uncertainty; First
Edition, May, 2016 (``API 13.3''), IBR approved for Sec. 3174.4(a).
(31) API MPMS Chapter 14, Section 3, Orifice Metering of Natural
Gas and Other Related Hydrocarbon Fluids--Concentric, Square-edged
Orifice Meters, Part 1, General Equations and Uncertainty Guidelines;
Fourth Edition, September 2012; Errata July 2013 (``API 14.3.1''), IBR
approved for Sec. 3174.4(a).
(32) API MPMS Chapter 18--Custody Transfer, Section 1, Measurement
Procedures for Crude Oil Gathered From Small Tanks by Truck; Second
Edition, April 1997; Reaffirmed February 2012 (``API 18.1''), IBR
approved for Sec. 3174.6(b).
(33) API MPMS Chapter 18, Section 2, Custody Transfer of Crude Oil
from Lease Tanks Using Alternative Measurement Methods, First Edition,
July 2016 (``API 18.2''), IBR approved for Sec. 3174.6(b).
(34) API MPMS Chapter 21--Flow Measurement Using Electronic
Metering Systems, Section 2, Electronic Liquid Volume Measurement Using
Positive Displacement and Turbine Meters; First Edition, June 1998;
Reaffirmed August 2011 (``API 21.2''), IBR approved for Sec. Sec.
3174.8(b), 3174.9(f), 3174.10(f).
(35) API Recommended Practice (RP) 12R1, Setting, Maintenance,
Inspection, Operation and Repair of Tanks in Production Service; Fifth
Edition, August 1997; Reaffirmed April 2008 (``API RP 12R1''), IBR
approved for Sec. 3174.5(b).
(36) API RP 2556, Correction Gauge Tables For Incrustation; Second
Edition, August 1993; Reaffirmed November 2013 (``API RP 2556''), IBR
approved for Sec. 3174.5(c).
Note 1 to Sec. 3174.3(b): You may also be able to purchase
these standards from the following resellers: Techstreet, 3916
Ranchero Drive, Ann Arbor, MI 48108; telephone 734-780-8000;
www.techstreet.com/api/apigate.html; IHS Inc., 321 Inverness Drive
South, Englewood, CO 80112; 303-790-0600; www.ihs.com; SAI Global,
610 Winters Avenue, Paramus, NJ 07652; telephone 201-986-1131;
https://infostore.saiglobal.com/store/.
Sec. 3174.4 Specific measurement performance requirements.
(a) Volume measurement uncertainty levels. (1) The FMP must achieve
the following overall uncertainty levels as calculated in accordance
with statistical concepts described in API 13.1, the methodologies in
API 13.3, and the quadrature sum (square root of the sum of the
squares) method described in API 14.3.1, Subsection 12.3 (all
incorporated by reference, see Sec. 3174.3) or other methods approved
under paragraph (d):
Table 1 to Sec. 3174.4--Volume Measurement Uncertainty Levels
------------------------------------------------------------------------
The overall volume
If the averaging period volume (see measurement uncertainty must
definition 43 CFR 3170.3) is: be within:
------------------------------------------------------------------------
1. Greater than or equal to 30,000 bbl/ 0.50 percent.
month.
2. Less than 30,000 bbl/month........... 1.50 percent.
------------------------------------------------------------------------
(2) Only a BLM State Director may grant an exception to the
uncertainty levels prescribed in paragraph (a)(1) of this section, and
only upon:
(i) A showing that meeting the required uncertainly level would
involve extraordinary cost or unacceptable adverse environmental
effects; and
(ii) Written concurrence of the PMT, prepared in coordination with
the Deputy Director.
(b) Bias. The measuring equipment used for volume determinations
must achieve measurement without statistically significant bias.
(c) Verifiability. All FMP equipment must be susceptible to
independent verification by the BLM of the accuracy and validity of all
inputs, factors, and equations that are used to determine quantity or
quality. Verifiability includes the ability to independently
recalculate volume and quality based on source records.
(d) Alternative equipment. The PMT will make a determination under
Sec. 3174.13 of this subpart regarding whether proposed alternative
equipment or measurement procedures meet or exceed the objectives and
intent of this section.
[[Page 81508]]
Sec. 3174.5 Oil measurement by tank gauging--general requirements.
(a) Measurement objective. Oil measurement by tank gauging must
accurately compute the total net standard volume of oil withdrawn from
a properly calibrated sales tank by following the activities prescribed
in Sec. 3174.6 and the requirements of Sec. 3174.4 of this subpart to
determine the quantity and quality of oil being removed.
(b) Oil tank equipment. (1) Each tank used for oil storage must
comply with the recommended practices listed in API RP 12R1
(incorporated by reference, see Sec. 3174.3).
(2) Each oil storage tank must be connected, maintained, and
operated in compliance with Sec. Sec. 3173.2, 3173.6, and 3173.7 of
this part.
(3) All oil storage tanks, hatches, connections, and other access
points must be vapor tight. Unless connected to a vapor recovery or
flare system, all tanks must have a pressure-vacuum relief valve
installed at the highest point in the vent line or connection with
another tank. All hatches, connections, and other access points must be
installed and maintained in accordance with manufacturers'
specifications.
(4) All oil storage tanks must be clearly identified and have an
operator-generated number unique to the lease, unit PA, or CA,
stenciled on the tank and maintained in a legible condition.
(5) Each oil storage tank associated with an approved FMP that has
a tank-gauging system must be set and maintained level.
(6) Each oil storage tank associated with an approved FMP that has
a tank-gauging system must be equipped with a distinct gauging
reference point, consistent with API 3.1A (incorporated by reference,
see Sec. 3174.3). The height of the reference point must be stamped on
a fixed bench-mark plate or stenciled on the tank near the gauging
hatch, and be maintained in a legible condition.
(c) Sales tank calibrations. The operator must accurately calibrate
each oil storage tank associated with an approved FMP that has a tank-
gauging system using either API 2.2A, API 2.2B, or API 2.2C; and API RP
2556 (all incorporated by reference, see Sec. 3174.3). The operator
must:
(1) Determine sales tank capacities by tank calibration using
actual tank measurements;
(i) The unit volume must be in barrels (bbl); and
(ii) The incremental height measurement must match gauging
increments specified in Sec. 3174.6(b)(5)(i)(C);
(2) Recalibrate a sales tank if it is relocated or repaired, or the
capacity is changed as a result of denting, damage, installation,
removal of interior components, or other alterations; and
(3) Submit sales tank calibration charts (tank tables) to the AO
within 45 days after calibration. Tank tables may be in paper or
electronic format.
Sec. 3174.6 Oil measurement by tank gauging--procedures.
(a) The procedures for oil measurement by tank gauging must comply
with the requirements outlined in this section.
(b) The operator must follow the procedures identified in API 18.1
or API 18.2 (both incorporated by reference, see Sec. 3174.3) as
further specified in this paragraph to determine the quality and
quantity of oil measured under field conditions at an FMP.
(1) Isolate tank. Isolate the tank for at least 30 minutes to allow
contents to settle before proceeding with tank gauging operations. The
tank isolating valves must be closed and sealed under Sec. 3173.2 of
this part.
(2) Determine opening oil temperature. Determination of the
temperature of oil contained in a sales tank must comply with
paragraphs (b)(2)(i) through (iii) of this section, API 7, and API 7.3
(both incorporated by reference, see Sec. 3174.3). Opening temperature
may be determined before, during, or after sampling.
(i) Glass thermometers must be clean, be free of fluid separation,
have a minimum graduation of 1.0 [deg]F, and have an accuracy of 0.5 [deg]F.
(ii) Electronic thermometers must have a minimum graduation of 0.1
[deg]F and have an accuracy of 0.5 [deg]F.
(iii) Record the temperature to the nearest 1.0 [deg]F for glass
thermometers or 0.1 [deg]F for portable electronic thermometers.
(3) Take oil samples. Sampling operations must be conducted prior
to taking the opening gauge unless automatic sampling methods are being
used. Sampling of oil removed from an FMP tank must yield a
representative sample of the oil and its physical properties and must
comply with API 8.1 or API 8.2 (both incorporated by reference, see
Sec. 3174.3).
(4) Determine observed oil gravity. Tests for oil gravity must
comply with paragraphs (b)(4)(i) through (iii) of this section and API
9.1, API 9.2, or API 9.3 (all incorporated by reference, see Sec.
3174.3).
(i) The hydrometer or thermohydrometer (as applicable) must be
calibrated for an oil gravity range that includes the observed gravity
of the oil sample being tested and must be clean, with a clearly
legible oil gravity scale and with no loose shot weights.
(ii) Allow the temperature to stabilize for at least 5 minutes
prior to reading the thermometer.
(iii) Read and record the observed API oil gravity to the nearest
0.1 degree. Read and record the temperature reading to the nearest 1.0
[deg]F.
(5) Measure the opening tank fluid level. Take and record the
opening gauge only after samples have been taken, unless automatic
sampling methods are being used. Gauging must comply with either
paragraph (b)(5)(i) of this section, API 3.1A, and API 18.1 (both
incorporated by reference, see Sec. 3174.3); or paragraph (b)(5)(ii)
of this section, API 3.1B, API 3.6, and API 18.2 (all incorporated by
reference, see Sec. 3174.3); or paragraph (b)(5)(iii) of this section
for dynamic volume determination.
(i) For manual gauging, comply with the requirements of API 3.1A
and API 18.1 (both incorporated by reference, see Sec. 3174.3) and the
following:
(A) The proper bob must be used for the particular measurement
method, i.e., either innage gauging or outage gauging;
(B) A gauging tape must be used. The gauging tape must be made of
steel or corrosion-resistant material with graduation clearly legible,
and must not be kinked or spliced;
(C) Either obtain two consecutive identical gauging measurements
for any tank regardless of size, or:
(1) For tanks of 1,000 bbl or less in capacity, three consecutive
measurements that are within 1/4-inch of each other and average these
three measurements to the nearest \1/4\ inch; or
(2) For tanks greater than 1,000 bbl in capacity, three consecutive
measurements within \1/8\ inch of each other, averaging these three
measurements to the nearest \1/8\ inch.
(D) A suitable product-indicating paste may be used on the tape to
facilitate the reading. The use of chalk or talcum powder is
prohibited; and
(E) The same tape and bob must be used for both opening and closing
gauges.
(ii) For automatic tank gauging (ATG), comply with the requirements
of API 3.1B, API 3.6, and API 18.2 (all incorporated by reference, see
Sec. 3174.3) and the following:
(A) The specific makes and models of ATG that are identified and
described at www.blm.gov are approved for use;
(B) The ATG must be inspected and its accuracy verified to within
\1/4\ inch in accordance with API 3.1B, Subsection 9
(incorporated by reference, see Sec. 3174.3) at least once a month or
[[Page 81509]]
prior to sales, whichever is latest, or any time at the request of the
AO. If the ATG is found to be out of tolerance, the ATG must be
calibrated prior to sales; and
(C) A log of field verifications must be maintained and available
upon request. The log must include the following information: The date
of verification; the as-found manual gauge readings; the as-found ATG
readings; and whether the ATG was field calibrated. If the ATG was
field calibrated, the as-left manual gauge readings and as-left ATG
readings must be recorded.
(iii) For dynamic volume determination under API 18.2, Subsection
10.1.1, (incorporated by reference, see Sec. 3174.3), the specific
makes and models of in-line meters that are identified and described at
www.blm.gov are approved for use.
(6) Determine S&W content. Using the oil samples obtained pursuant
to paragraph (b)(3) of this section, determine the S&W content of the
oil in the sales tanks, according to API 10.4 (incorporated by
reference, see Sec. 3174.3).
(7) Transfer oil. Break the tank load line valve seal and transfer
oil to the tanker truck. After transfer is complete, close the tank
valve and seal the valve under Sec. Sec. 3173.2 and 3173.5 of this
part.
(8) Determine closing oil temperature. Determine the closing oil
temperature using the procedures in paragraph (b)(2) of this section.
(9) Take closing gauge. Take the closing tank gauge using the
procedures in paragraph (b)(5) of this section.
(10) Complete measurement ticket. Following procedures in Sec.
3174.12.
Sec. 3174.7 LACT system--general requirements.
(a) A LACT system must meet the construction and operation
requirements and minimum standards of this section, Sec. 3174.8, and
Sec. 3174.4.
(b) A LACT system must be proven as prescribed in Sec. 3174.11 of
this subpart.
(c) Measurement tickets must be completed under Sec. 3174.12(b) of
this subpart.
(d) All components of a LACT system must be accessible for
inspection by the AO.
(e)(1) The operator must notify the AO, within 72 hours after
discovery, of any LACT system failures or equipment malfunctions that
may have resulted in measurement error.
(2) Such system failures or equipment malfunctions include, but are
not limited to, electrical, meter, and other failures that affect oil
measurement.
(f) Any tests conducted on oil samples extracted from LACT system
samplers for determination of temperature, oil gravity, and S&W content
must meet the requirements and minimum standards in Sec. 3174.6(b)(2),
(4), and (6) of this subpart.
(g) Automatic temperature compensators and automatic temperature
and gravity compensators are prohibited.
Sec. 3174.8 LACT system--components and operating requirements.
(a) LACT system components. Each LACT system must include all of
the equipment listed in API 6.1 (incorporated by reference, see Sec.
3174.3), with the following exceptions:
(1) The custody transfer meter must be a positive displacement
meter or a Coriolis meter. The specific make, models, and sizes of
positive displacement or Coriolis meter and associated software that
are identified and described at www.blm.gov are approved for use.
(2) An electronic temperature averaging device must be installed.
(3) Meter back pressure must be applied by a back pressure valve or
other controllable means of applying back pressure to ensure single-
phase flow.
(b) LACT system operating requirements. Operation of all LACT
system components must meet the requirements of API 6.1 (incorporated
by reference, see Sec. 3174.3) and the following:
(1) Sampling must be conducted according to API 8.2 and API 8.3
(both incorporated by reference, see Sec. 3174.3) and the following:
(i) The sample extractor probe must be inserted within the center
half of the flowing stream;
(ii) The extractor probe must be horizontally oriented; and
(iii) The external body of the extractor probe must be marked with
the direction of the flow.
(2) Any tests conducted on oil samples extracted from LACT system
samplers for determination of oil gravity and S&W content must meet the
requirements of either API 9.1, API 9.2, or API 9.3, and API 10.4 (all
incorporated by reference, see Sec. 3174.3).
(3) The composite sample container must be emptied and cleaned upon
completion of sample withdrawal.
(4) The positive displacement or Coriolis meter (see Sec. 3174.10)
must be equipped with a non-resettable totalizer. The meter must
include or allow for the attachment of a device that generates at least
8,400 pulses per barrel of registered volume.
(5) The system must have a pressure-indicating device downstream of
the meter, but upstream of meter-proving connections. The pressure-
indicating device must be capable of providing pressure data to
calculate the CPL correction factor.
(6) An electronic temperature averaging device must be installed,
operated, and maintained as follows:
(i) The temperature sensor must be placed in compliance with API 7
(incorporated by reference, see Sec. 3174.3);
(ii) The electronic temperature averaging device must be volume-
weighted and take a temperature reading following API 21.2, Subsection
9.2.8 (incorporated by reference, see Sec. 3174.3);
(iii) The average temperature for the measurement ticket must be
calculated by the volumetric averaging method using API 21.2,
Subsection 9.2.13.2a (incorporated by reference, see Sec. 3174.3);
(iv) The temperature averaging device must have a reference
accuracy of 0.5[emsp14][deg]F or better, and have a minimum
graduation of 0.1[emsp14][deg]F; and
(v) The temperature averaging device must include a display of
instantaneous temperature and the average temperature calculated since
the measurement ticket was opened.
(vi) The average temperature calculated since the measurement
ticket was opened must be used to calculate the CTL correction factor.
(7) Determination of net standard volume: Calculate the net
standard volume at the close of each measurement ticket following the
guidelines in API 12.2.1 and API 12.2.2 (both incorporated by
reference, see Sec. 3174.3).
Sec. 3174.9 Coriolis measurement systems (CMS)--general requirements
and components.
The following Coriolis measurement systems section is intended for
Coriolis measurement applications independent of LACT measurement
systems.
(a) A CMS must meet the requirements and minimum standards of this
section, Sec. 3174.4, and Sec. 3174.10.
(b) The specific makes, models, and sizes of Coriolis meters and
associated software that have been reviewed by the PMT, as provided in
Sec. 3174.13, approved by the BLM, and identified and described at
www.blm.gov are approved for use.
(c) A CMS system must be proven at the frequency and under the
requirements of Sec. 3174.11 of this subpart.
(d) Measurement tickets must be completed under Sec. 3174.12(b) of
this subpart.
(e) A CMS at an FMP must be installed with the components listed in
[[Page 81510]]
API 5.6 (incorporated by reference, see Sec. 3174.3). Additional
requirements are as follows:
(1) The pressure transducer must meet the requirements of Sec.
3174.8(b)(5) of this subpart.
(2) Temperature determination must meet the requirements of Sec.
3174.8(b)(6) of this subpart.
(3) If nonzero S&W content is to be used in determining net oil
volume, the sampling system must meet the requirements of Sec.
3174.8(b)(1) through (3) of this subpart. If no sampling system is
used, or the sampling system does not meet the requirements of Sec.
3174.8(b)(1) through (3) of this subpart, the S&W content must be
reported as zero;
(4) Sufficient back pressure must be applied to ensure single phase
flow through the meter.
(f) Determination of API oil gravity. The API oil gravity reported
for the measurement ticket period must be determined by one of the
following methods:
(1) Determined from a composite sample taken pursuant to Sec.
3174.8(b)(1) through (3) of this subpart; or
(2) Calculated from the average density as measured by the CMS over
the measurement ticket period under API 21.2, Subsection 9.2.13.2a
(incorporated by reference, see Sec. 3174.3). Density must be
corrected to base temperature and pressure using API 11.1 (incorporated
by reference, see Sec. 3174.3).
(g) Determination of net standard volume. Calculate the net
standard volume at the close of each measurement ticket following the
guidelines in API 12.2.1 and API 12.2.2 (both incorporated by
reference, see Sec. 3174.3).
Sec. 3174.10 Coriolis meter for LACT and CMS measurement
applications--operating requirements.
(a) Minimum electronic pulse level. The Coriolis meter must
register the volume of oil passing through the meter as determined by a
system that constantly emits electronic pulse signals representing the
indicated volume measured. The pulse per unit volume must be set at a
minimum of 8,400 pulses per barrel.
(b) Meter specifications. (1) The Coriolis meter specifications
must identify the make and model of the Coriolis meter to which they
apply and must include the following:
(i) The reference accuracy for both mass flow rate and density,
stated in either percent of reading, percent of full scale, or units of
measure;
(ii) The effect of changes in temperature and pressure on both mass
flow and fluid density readings, and the effect of flow rate on density
readings. These specifications must be stated in percent of reading,
percent of full scale, or units of measure over a stated amount of
change in temperature, pressure, or flow rate (e.g., ``0.1
percent of reading per 20 psi'');
(iii) The stability of the zero reading for volumetric flow rate.
The specifications must be stated in percent of reading, percent of
full scale, or units of measure;
(iv) Design limits for flow rate and pressure; and
(v) Pressure drop through the meter as a function of flow rate and
fluid viscosity.
(2) Submission of meter specifications: The operator must submit
Coriolis meter specifications to the BLM upon request.
(c) Non-resettable totalizer. The Coriolis meter must have a non-
resettable internal totalizer for indicated volume.
(d) Verification of meter zero value using the manufacturer's
specifications. If the indicated flow rate is within the manufacturer's
specifications for zero stability, no adjustments are required. If the
indicated flow rate is outside the manufacturer's specification for
zero stability, the meter's zero reading must be adjusted. After the
meter's zero has been adjusted, the meter must be proven required by
Sec. 3174.11. A copy of the zero value verification procedure must be
made available to the AO upon request.
(e) Required on-site information. (1) The Coriolis meter display
must be readable without using data collection units, laptop computers,
or any special equipment, and must be on-site and accessible to the AO.
(2) For each Coriolis meter, the following values and corresponding
units of measurement must be displayed:
(i) The instantaneous density of liquid (pounds/bbl, pounds/gal, or
degrees API);
(ii) The instantaneous indicated volumetric flow rate through the
meter (bbl/day);
(iii) The meter factor;
(iv) The instantaneous pressure (psi);
(v) The instantaneous temperature ([deg]F);
(vi) The cumulative gross standard volume through the meter (non-
resettable totalizer) (bbl); and
(vii) The previous day's gross standard volume through the meter
(bbl).
(3) The following information must be correct, be maintained in a
legible condition, and be accessible to the AO at the FMP without the
use of data collection equipment, laptop computers, or any special
equipment:
(i) The make, model, and size of each sensor; and
(ii) The make, range, calibrated span, and model of the pressure
and temperature transducer used to determine gross standard volume.
(4) A log must be maintained of all meter factors, zero
verifications, and zero adjustments. For zero adjustments, the log must
include the zero value before adjustment and the zero value after
adjustment. The log must be made available upon request.
(f) Audit trail requirements. The information specified in
paragraphs (f)(1) through (4) of this section must be recorded and
retained under the recordkeeping requirements of Sec. 3170.7 of this
part. Audit trail requirements must follow API 21.2, Subsection 10
(incorporated by reference, see Sec. 3174.3). All data must be
available and submitted to the BLM upon request.
(1) Quantity transaction record (QTR). Follow the requirements for
a measurement ticket in Sec. 3174.12(b) of this subpart.
(2) Configuration log. The configuration log must comply with the
requirements of API 21.2, Subsection 10.2 (incorporated by reference,
see Sec. 3174.3). The configuration log must contain and identify all
constant flow parameters used in generating the QTR.
(3) Event log. The event log must comply with the requirements of
API 21.2, Subsection 10.6 (incorporated by reference, see Sec.
3174.3). In addition, the event log must be of sufficient capacity to
record all events such that the operator can retain the information
under the recordkeeping requirements of Sec. 3170.7 of this part.
(4) Alarm log The type and duration of any of the following alarm
conditions must be recorded:
(i) Density deviations from acceptable parameters; and
(ii) Instances in which the flow rate exceeded the manufacturer's
maximum recommended flow rate or was below the manufacturer's minimum
recommended flow rate.
(g) Data protection. Each Coriolis meter must have installed and
maintained in an operable condition a backup power supply or a
nonvolatile memory capable of retaining all data in the unit's memory
to ensure that the audit trail information required under paragraph (f)
of this section is protected.
Sec. 3174.11 Meter-proving requirements.
(a) Applicability. This section specifies the minimum requirements
for
[[Page 81511]]
conducting volumetric meter proving for all FMP meters.
(b) Meter prover. Acceptable provers are positive displacement
master meters, Coriolis master meters, and displacement provers. The
operator must ensure that the meter prover used to determine the meter
factor has a valid certificate of calibration on site and available for
review by the AO. The certificate must show that the prover, identified
by serial number assigned to and inscribed on the prover, was
calibrated as follows:
(1) Master meters must have a meter factor within 0.9900 to 1.0100
determined by a minimum of five consecutive prover runs within 0.0005
(0.05 percent repeatability) as described in API 4.5, Subsection 6.5
(incorporated by reference, see Sec. 3174.3). The master meter must
not be mechanically compensated for oil gravity or temperature; its
readout must indicate units of volume without corrections. The meter
factor must be documented on the calibration certificate and must be
calibrated at least once every 12 months. New master meters must be
calibrated immediately and recalibrated in three months. Master meters
that have undergone mechanical repairs, alterations, or changes that
affect the calibration must be calibrated immediately upon completion
of this work and calibrated again 3 months after this date under API
4.5, API 4.8, Subsection 10.2, and API 4.8, Annex B (all incorporated
by reference, see Sec. 3174.3).
(2) Displacement provers must meet the requirements of API 4.2
(incorporated by reference, see Sec. 3174.3) and be calibrated using
the water-draw method under API 4.9.2 (incorporated by reference, see
Sec. 3174.3), at the calibration frequencies specified in API 4.8,
Subsection 10.1(b) (incorporated by reference, see Sec. 3174.3).
(3) The base prover volume of a displacement prover must be
calculated under API 12.2.4 (incorporated by reference, see Sec.
3174.3).
(4) Displacement provers must be sized to obtain a displacer
velocity through the prover that is within the appropriate range during
proving under API 4.2, Subsection 4.3.4.2, Minimum Displacer Velocities
and API 4.2, Subsection 4.3.4.1, Maximum Displacer Velocities
(incorporated by reference, see Sec. 3174.3).
(5) Fluid velocity is calculated using API 4.2, Subsection 4.3.4.3,
Equation 12 (incorporated by reference, see Sec. 3174.3).
(c) Meter proving runs. Meter proving must follow the applicable
section(s) of API 4.1, Proving Systems (incorporated by reference, see
Sec. 3174.3).
(1) Meter proving must be performed under normal operating fluid
pressure, fluid temperature, and fluid type and composition, as
follows:
(i) The oil flow rate through the LACT or CMS during proving must
be within 10 percent of the normal flow rate;
(ii) The absolute pressure as measured by the LACT or CMS during
proving must be within 10 percent of the normal operating absolute
pressure;
(iii) The temperature as measured by the LACT or CMS during the
proving must be within 10 [deg]F of the normal operating temperature;
and
(iv) The gravity of the oil during proving must be within 5[deg]
API of the normal oil gravity.
(v) If the normal flow rate, pressure, temperature, or oil gravity
vary by more than the limits defined in paragraphs (c)(i) through
(c)(iv) of this section, meter provings must be conducted, at a
minimum, under the three following conditions: At the lower limit of
normal operating conditions, at the upper limit of normal operation
conditions, and at the midpoint of normal operating conditions.
(2) If each proving run is not of sufficient volume to generate at
least 10,000 pulses, as specified by API 4.2, Subsection 4.3.2
(incorporated by reference, see Sec. 3174.3), from the positive
displacement meter or the Coriolis meter, then pulse interpolation must
be used in accordance with API 4.6 (incorporated by reference, see
Sec. 3174.3).
(3) Proving runs must be made until the calculated meter factor or
meter generated pulses from five consecutive runs match within a
tolerance of 0.0005 (0.05 percent) between the highest and the lowest
value in accordance with API 12.2.3, Subsection 9 (incorporated by
reference, see Sec. 3174.3).
(4) The new meter factor is the arithmetic average of the meter
generated pulses or intermediate meter factors calculated from the five
consecutive runs in accordance with API 12.2.3, Subsection 9
(incorporated by reference, see Sec. 3174.3).
(5) Meter factor computations must follow the sequence described in
API 12.2.3 (incorporated by reference, see Sec. 3174.3).
(6) If multiple meters factors are determined over a range of
normal operating conditions, then:
(i) If all the meter factors determined over a range of conditions
fall within 0.0020 of each other, then a single meter factor may be
calculated for that range as the arithmetic average of all the meter
factors within that range. The full range of normal operating
conditions may be divided into segments such that all the meter factors
within each segment fall within a range of 0.0020. In this case, a
single meter factor for each segment may be calculated as the
arithmetic average of the meter factors within that segment; or
(ii) The metering system may apply a dynamic meter factor derived
(using, e.g., linear interpolation, polynomial fit, etc.) from the
series of meter factors determined over the range of normal operating
conditions, so long as no two neighboring meter factors differ by more
than 0.0020.
(7) The meter factor must be at least 0.9900 and no more than
1.0100.
(8) The initial meter factor for a new or repaired meter must be at
least 0.9950 and no more than 1.0050.
(9) For positive displacement meters, the back pressure valve may
be adjusted after proving only within the normal operating fluid flow
rate and fluid pressure as described in paragraph (c)(1) of this
section. If the back pressure valve is adjusted after proving, the
operator must document the as left fluid flow rate and fluid pressure
on the proving report.
(10) If a composite meter factor is calculated, the CPL value must
be calculated from the pressure setting of the back pressure valve or
the normal operating pressure at the meter. Composite meter factors
must not be used with a Coriolis meter.
(d) Minimum proving frequency. The operator must prove any FMP
meter before removal or sales of production after any of the following
events:
(1) Initial meter installation;
(2) Every 3 months (quarterly) after the last proving, or each time
the registered volume flowing through the meter, as measured on the
non-resettable totalizer from the last proving, increases by 75,000
bbl, whichever comes first, but no more frequently than monthly;
(3) Meter zeroing (Coriolis meter);
(4) Modification of mounting conditions;
(5) A change in fluid temperature that exceeds the transducer's
calibrated span;
(6) A change in pressure, density, or flow rate that exceeds the
operating proving limits;
(7) The mechanical or electrical components of the meter have been
changed, repaired, or removed;
(8) Internal calibration factors have been changed or reprogrammed;
or
(9) At the request of the AO.
(e) Excessive meter factor deviation. (1) If the difference between
meter factors established in two successive
[[Page 81512]]
provings exceeds 0.0025, the meter must be immediately
removed from service, checked for damage or wear, adjusted or repaired,
and reproved before returning the meter to service.
(2) The arithmetic average of the two successive meter factors must
be applied to the production measured through the meter between the
date of the previous meter proving and the date of the most recent
meter proving.
(3) The proving report submitted under paragraph (i) of this
section must clearly show the most recent meter factor and describe all
subsequent repairs and adjustments.
(f) Verification of the temperature transducer. As part of each
required meter proving and upon replacement, the temperature averager
for a LACT system and the temperature transducer used in conjunction
with a CMS must be verified against a known standard according to the
following:
(1) The temperature averager or temperature transducer must be
compared with a test thermometer traceable to NIST and with a stated
accuracy of 0.25 [deg]F or better.
(2) The temperature reading displayed on the temperature averager
or temperature transducer must be compared with the reading of the test
thermometer using one of the following methods:
(i) The test thermometer must be placed in a test thermometer well
located not more than 12 from the probe of the temperature
averager or temperature transducer; or
(ii) Both the test thermometer and probe of the temperature
averager or temperature transducer must be placed in an insulated water
bath. The water bath temperature must be within 20 [deg]F of the normal
flowing temperature of the oil.
(3) The displayed reading of instantaneous temperature from the
temperature averager or the temperature transducer must be compared
with the reading from the test thermometer. If they differ by more than
0.5 [deg]F, then the difference in temperatures must be noted on the
meter proving report and:
(i) The temperature averager or temperature transducer must be
adjusted to match the reading of the test thermometer; or
(ii) The temperature averager or temperature transducer must be
recalibrated, repaired, or replaced.
(g) Verification of the pressure transducer (if applicable). (1) As
part of each required meter proving and upon replacement, the pressure
transducer must be compared with a test pressure device (dead weight or
pressure gauge) traceable to NIST and with a stated maximum uncertainty
of no more than one-half of the accuracy required from the transducer
being verified.
(2) The pressure reading displayed on the pressure transducer must
be compared with the reading of the test pressure device.
(3) The pressure transducer must be tested at the following three
points:
(i) Zero (atmospheric pressure);
(ii) 100 percent of the calibrated span of the pressure transducer;
and
(iii) A point that represents the normal flowing pressure through
the Coriolis meter.
(4) If the pressure applied by the test pressure device and the
pressure displayed on the pressure transducer vary by more than the
required accuracy of the pressure transducer, the pressure transducer
must be adjusted to read within the stated accuracy of the test
pressure device.
(h) Density verification (if applicable). As part of each required
meter proving, if the API gravity of oil is determined from the average
density measured by the Coriolis meter (rather than from a composite
sample), then during each proving of the Coriolis meter, the
instantaneous flowing density determined by the Coriolis meter must be
verified by comparing it with an independent density measurement as
specified under API 5.6, Subsection 9.1.2.1 (incorporated by reference,
see Sec. 3174.3). The difference between the indicated density
determined from the Coriolis meter and the independently determined
density must be within the specified density reference accuracy
specification of the Coriolis meter. Sampling must be performed in
accordance with API 8.1, API 8.2, or API 8.3 (incorporated by
reference, see Sec. 3174.3), as appropriate.
(i) Meter proving reporting requirements. (1) The operator must
report to the AO all meter-proving and volume adjustments after any
LACT system or CMS malfunction, including excessive meter-factor
deviation, using the appropriate form in either API 12.2.3 or API 5.6
(both incorporated by reference, see Sec. 3174.3), or any similar
format showing the same information as the API form, provided that the
calculation of meter factors maintains the proper calculation sequence
and rounding.
(2) In addition to the information required under paragraph (i)(1)
of this section, each meter-proving report must also show the:
(i) Unique meter ID number;
(ii) Lease number, CA number, or unit PA number;
(iii) The temperature from the test thermometer and the temperature
from the temperature averager or temperature transducer;
(iv) For pressure transducers, the pressure applied by the pressure
test device and the pressure reading from the pressure transducer at
the three points required under paragraph (g)(3) of this section;
(v) For density verification (if applicable), the instantaneous
flowing density (as determined by Coriolis meter), and the independent
density measurement, as compared under paragraph (h) of this section;
and
(vi) The ``as left'' fluid flow rate and fluid pressure, if the
back pressure valve is adjusted after proving as described in paragraph
(c)(9) of this section.
(3) The operator must submit the meter-proving report to the AO no
later than 14 days after the meter proving. The proving report may be
either in a hard copy or electronic format.
Sec. 3174.12 Measurement tickets.
(a) Tank gauging. After oil is measured by tank gauging under
Sec. Sec. 3174.5 and 3174.6 of this subpart, the operator, purchaser,
or transporter, as appropriate, must complete a uniquely numbered
measurement ticket, in either paper or electronic format, with the
following information:
(1) Lease, unit PA, or CA number;
(2) Unique tank number and nominal tank capacity;
(3) Opening and closing dates and times;
(4) Opening and closing gauges and observed temperatures in [deg]F;
(5) Observed volume for opening and closing gauge, using tank
specific calibration charts (see Sec. 3174.5(c));
(6) Total gross standard volume removed from the tank following API
11.1 (incorporated by reference, see Sec. 3174.3);
(7) Observed API oil gravity and temperature in [deg]F;
(8) API oil gravity at 60 [deg]F, following API 11.1 (incorporated
by reference, see Sec. 3174.3);
(9) S&W content percent;
(10) Unique number of each seal removed and installed;
(11) Name of the individual performing the tank gauging; and
(12) Name of the operator.
(b) LACT system and CMS. (1) At the beginning of every month, and,
unless the operator is using a flow computer under Sec. 3174.10,
before conducting proving operations on a LACT system, the operator,
purchaser, or transporter, as appropriate, must complete a uniquely
numbered measurement ticket, in either paper or electronic format, with
the following information:
(i) Lease, unit PA, or CA number;
[[Page 81513]]
(ii) Unique meter ID number;
(iii) Opening and closing dates;
(iv) Opening and closing totalizer readings of the indicated
volume;
(v) Meter factor, indicating if it is a composite meter factor;
(vi) Total gross standard volume removed through the LACT system or
CMS;
(vii) API oil gravity. For API oil gravity determined from a
composite sample, the observed API oil gravity and temperature must be
indicated in [deg]F and the API oil gravity must be indicated at 60
[deg]F. For API oil gravity determined from average density (CMS only),
the average uncorrected density must be determined by the CMS;
(viii) The average temperature in [deg]F;
(ix) The average flowing pressure in psig;
(x) S&W content percent;
(xi) Unique number of each seal removed and installed;
(xii) Name of the purchaser's representative; and
(xiii) Name of the operator.
(2) Any accumulators used in the determination of average pressure,
average temperature, and average density must be reset to zero whenever
a new measurement ticket is opened.
Sec. 3174.13 Oil measurement by other methods.
(a) Any method of oil measurement other than tank gauging, LACT
system, or CMS at an FMP requires prior BLM approval.
(b)(1) Any operator requesting approval to use alternate oil
measurement equipment or measurement method must submit to the BLM
performance data, actual field test results, laboratory test data, or
any other supporting data or evidence that demonstrates that the
proposed alternate oil equipment or method would meet or exceed the
objectives of the applicable minimum requirements of this subpart and
would not affect royalty income or production accountability.
(2) The PMT will review the submitted data to ensure that the
alternate oil measurement equipment or method meets the requirements of
this subpart and will make a recommendation to the BLM to approve use
of the equipment or method, disapprove use of the equipment or method,
or approve use of the equipment or method with conditions for its use.
If the PMT recommends, and the BLM approves new equipment or methods,
the BLM will post the make, model, range or software version (as
applicable), or method on the BLM Web site www.blm.gov as being
appropriate for use at an FMP for oil measurement without further
approval by the BLM, subject to any conditions of approval identified
by the PMT and approved by the BLM.
(c) The procedures for requesting and granting a variance under
Sec. 3170.6 of this part may not be used as an avenue for approving
new technology, methods, or equipment. Approval of alternative oil
measurement equipment or methods may be obtained only under this
section.
Sec. 3174.14 Determination of oil volumes by methods other than
measurement.
(a) Under 43 CFR 3162.7-2, when production cannot be measured due
to spillage or leakage, the amount of production must be determined by
using any method the AO approves or prescribes. This category of
production includes, but is not limited to, oil that is classified as
slop oil or waste oil.
(b) No oil may be classified or disposed of as waste oil unless the
operator can demonstrate to the satisfaction of the AO that it is not
economically feasible to put the oil into marketable condition.
(c) The operator may not sell or otherwise dispose of slop oil
without prior written approval from the AO. Following the sale or
disposal of slop oil, the operator must notify the AO in writing of the
volume sold or disposed of and the method used to compute the volume.
Sec. 3174.15 Immediate assessments.
Certain instances of noncompliance warrant the imposition of
immediate assessments upon the BLM's discovery of the violation, as
prescribed in the following table. Imposition of any of these
assessments does not preclude other appropriate enforcement actions.
Table 1 to Sec. 3174.15--Violations Subject to an Immediate Assessment
------------------------------------------------------------------------
Violations subject to an immediate assessment
-------------------------------------------------------------------------
Assessment
Violation: amount per
violation:
------------------------------------------------------------------------
1. Missing or nonfunctioning FMP LACT system components $1,000
as required by Sec. 3174.8 of this subpart...........
2. Failure to notify the AO within 72 hours, as required 1,000
by Sec. 3174.7(e) of this subpart, of any FMP LACT
system failure or equipment malfunction resulting in
use of an unapproved alternate method of measurement...
3. Missing or nonfunctioning FMP CMS components as 1,000
required by Sec. 3174.9 of this subpart..............
4. Failure to meet the proving frequency requirements 1,000
for an FMP, detailed in Sec. 3174.11 of this subpart.
5. Failure to obtain a written approval, as required by 1,000
Sec. 3174.13 of this subpart, before using any oil
measurement method other than tank gauging, LACT
system, or CMS at a FMP................................
------------------------------------------------------------------------
[FR Doc. 2016-25405 Filed 11-16-16; 8:45 am]
BILLING CODE 4310-84-P
