Onshore Oil and Gas Operations; Federal and Indian Oil and Gas Leases; Measurement of Gas, 81516-81636 [2016-25410]

Agencies

• DEPARTMENT OF THE INTERIOR
• Bureau of Land Management

[Federal Register Volume 81, Number 222 (Thursday, November 17, 2016)]
[Rules and Regulations]
[Pages 81516-81636]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2016-25410]



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Vol. 81

Thursday,

No. 222

November 17, 2016

Part VII





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 Gas; Final Rule

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

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DEPARTMENT OF THE INTERIOR

Bureau of Land Management

43 CFR Parts 3160 and 3170

[17X.LLWO310000.L13100000.PP0000]
RIN 1004-AE17


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

AGENCY: Bureau of Land Management, Interior.

ACTION: Final rule.

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SUMMARY: This final rule updates and replaces Onshore Oil and Gas Order 
No. 5 (Order 5) with a new regulation codified in the Code of Federal 
Regulations (CFR). Like Order 5, this rule establishes minimum 
standards for accurate measurement and proper reporting of all gas 
removed or sold from Federal and Indian (except the Osage Tribe) 
leases, units, unit participating areas (PAs), and areas subject to 
communitization agreements (CAs). It provides a system for production 
accountability by operators, lessees, purchasers, and transporters. 
This rule establishes overall gas measurement performance standards and 
includes, among other things, requirements for the hardware and 
software related to gas metering equipment and reporting and 
recordkeeping. This rule also identifies certain specific acts of 
noncompliance that may result in an immediate assessment and provides a 
process for the Bureau of Land Management (BLM) to consider variances 
from the requirements of this rule.

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

FOR FURTHER INFORMATION CONTACT: Richard Estabrook, Petroleum Engineer, 
Division of Fluid Minerals, 707-468-4052, or Steven Wells, Division 
Chief, Division of Fluid Minerals, 202-912-7143, for information 
regarding the BLM's Fluid Minerals Program. For questions relating to 
regulatory process issues, please contact Faith Bremner at 202-912-
7441. Persons who use a telecommunications device for the deaf (TDD) 
may call the Federal Relay Service at 1-800-877-8339 to contact the 
above individual 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 individual. You will receive a reply during normal business 
hours.

SUPPLEMENTARY INFORMATION:

I. Background and Overview
II. Discussion of Final Rule and Comments on the Proposed Rule
III. Overview of Public Involvement and Consistency With GAO 
Recommendations
IV. Procedural Matters

I. Background and Overview

    Under applicable laws, royalties are owed on all production removed 
or sold from Federal and Indian oil and gas leases. The basis for those 
royalty payments is the measured volume and quality of the production 
from those leases. In fiscal year (FY) 2015, onshore Federal oil and 
gas lease holders sold 180 million barrels of oil,\1\ 2.5 trillion 
cubic feet of natural gas,\2\ 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, generating 
royalties of over $0.6 billion that were all distributed to the 
applicable tribes and individual allottment owners.
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    \1\ 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.
    \2\ This figure includes all processed and unprocessed volumes 
recovered on-lease, nitrogen, fuel gas, coalbed methane, and any 
volumes of gas lost due to venting or flaring.
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    As explained in the preamble for the proposed rule, given the 
magnitude of this production and the BLM's statutory and management 
obligations, it is critically important that the BLM ensure that 
operators accurately measure, report, and account for that production. 
The final rule helps achieve that objective by updating and replacing 
Order 5's requirements with respect to the measurement of gas with 
regulations codified in the CFR that reflect changes in applicable 
laws, metering technology, and industry standards since Order 5 was 
first promulgated in 1989.\3\
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    \3\ Order 5 has been in effect since March 27, 1989 (see 54 
Federal Register (FR) 8100).
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    The basis for this rule is the Secretary of the Interior's 
authority under various Federal and Indian mineral leasing laws to 
manage oil and gas operations, which authority has been delegated to 
the BLM. In implementing that authority, the BLM issued onshore oil and 
gas operating regulations that are codified at 43 CFR part 3160. The 
regulations at 43 CFR part 3160, Onshore Oil and Gas Operations, in 
Sec.  3164.1, provide for the issuance of Onshore Oil and Gas Orders to 
``implement and supplement'' the regulations in part 3160.\4\ The table 
in Sec.  3164.1(b) lists the existing Orders. This final rule updates 
and replaces Order 5 and will be codified in the CFR, primarily in new 
subpart 3175. Like Order 5, this final rule sets the requirements for 
the measurement of gas produced or sold from a lease; it does not 
address other circumstances in which the BLM requires royalty payment, 
such as for avoidably lost gas (see Notice to Lessees and Operators of 
Onshore Federal and Indian Oil and Gas Leases (NTL-4A), Royalty or 
Compensation for Oil and Gas Lost, 44 FR 76600 (Dec. 27, 1979); see 
also 81 FR 6616 (February 8, 2016)).
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    \4\ Over the years, the BLM has issued seven Onshore Oil and Gas 
Orders that have dealt with different aspects of oil and gas 
production. These Orders were published in the FR, both for public 
comment and in final form, but they do not appear in the CFR. 
Although they are not codified in the CFR, all Onshore Orders have 
been issued consistent with Administrative Procedure Act (APA) 
notice and comment rulemaking procedures, and therefore have the 
effect of regulations and apply nationwide to all Federal and Indian 
(except the Osage Tribe) onshore oil and gas leases.
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    Consistent with updating and replacing Order 5, this rule also 
supersedes various statewide NTLs that have been issued from time-to-
time to provide additional guidance regarding compliance with the 
requirements of Order 5, including:
     NM NTL 92-5, January 1, 1992;
     WY NTL 2004-1, April 23, 2004;
     CA NTL 2007-1, April 16, 2007;
     MT NTL 2007-1, May 4, 2007;
     UT NTL 2007-1, August 24, 2007;
     CO NTL 2007-1, December 21, 2007;
     NM NTL 2008-1, January 29, 2008;
     ES NTL 2008-1, September 17, 2008;
     AK NTL 2009-1, July 29, 2009; and
     CO NTL 2014-01, May 19, 2014.
    Although this rule supersedes Order 5 and various statewide NTLs, 
the existing requirements of Order 5 and those NTLs remain in effect 
during the phase-in periods--specified in Sec.  3175.60(b)--for the 
rule's new requirements.
    The requirements in this rule help ensure that the Department of 
the Interior (DOI or the Department) meets it responsibility to collect 
royalties on gas extracted from Federal onshore and Indian (except the 
Osage Tribe) leases. The proper measurement of gas is essential to 
ensure that the American

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public, as well as Indian tribes and individual allottees, receive the 
royalties to which they are entitled on oil and gas produced from 
Federal and Indian leases, respectively.
    As explained in the preamble to the proposed rule, these changes 
were prompted by internal and external concerns about the adequacy of 
the BLM's existing gas measurement rules. Notably, these concerns were 
highlighted in several external reviews of the BLM's measurement 
program by three independent outside entities--the Secretary of the 
Interior's (Secretary's) Subcommittee on Royalty Management (the 
Subcommittee) in 2007, the DOI's Office of the Inspector General (OIG) 
in 2009, and the Government Accountability Office (GAO) in 2010, 2011, 
2013, and 2015--all of which have repeatedly recommended that the BLM 
evaluate its gas measurement guidance and regulations to ensure that 
operators are properly accounting for production from Federal and 
Indian leases and are paying the proper royalties. Specifically, these 
groups found with respect to gas measurement that the DOI needed to 
provide Department-wide guidance on measurement technologies and 
processes not addressed in current regulations, including guidance on 
the process for approving variances in instances when new technologies 
or processes are developed that are not yet addressed by existing 
rules. As explained in the Section-by-Section analysis, the provisions 
of this final rule respond to these recommendations.
    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 guidance regarding 
production accountability and measurement is ``unconsolidated, 
outdated, and sometimes insufficient'' (Subcommittee report, p. 30). 
The Subcommittee report found that this results in inconsistent and 
outmoded approaches to production accountability and measurement tasks 
and, ultimately, potential inaccuracies in royalty collections. The 
final rule in part results from the recommendations contained in the 
Subcommittee's report, which was issued on December 17, 2007.
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    \5\ The Subcommittee was commissioned to report to the Royalty 
Policy Committee, which was chartered under the Federal Advisory 
Committee Act (FACA) 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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    Specifically, the Subcommittee report expressed concern that the 
applicable ``BLM policy and guidance is outdated'' and ``some policy 
memoranda have expired'' (Subcommittee report, p. 31). It also noted 
that ``BLM policy and guidance have not been consolidated in a single 
document or publication,'' which has led to the ``BLM's 31 oil and gas 
field offices using varying policy and guidance'' (id.). For example, 
``some BLM State Offices have issued their own `Notices to Lessees' for 
oil and gas operations'' (id.). While the Subcommittee recognized that 
such NTLs may have a positive effect on some oil and gas field 
operations, it also observed that they necessarily ``lack a national 
perspective and may introduce inconsistencies among State (Offices)'' 
(id.). Of the 110 recommendations made in the 2007 Subcommittee report, 
12 recommendations relate directly to improving the measurement and 
reporting of natural gas volume and heating value. For example, the 
Subcommittee paid particular attention to the measurement and reporting 
of heating value because it has a direct impact on royalties ultimately 
collected as heating value establishes the energy content of a 
particular volume of gas, a key component of its market value. Heating 
value is as important to calculating royalties due as measured volume. 
Currently, Order 5 requires only yearly measurement of natural gas 
heating value and there are no BLM standards for how operators should 
measure heating value, where they should measure it, how they should 
analyze it, or on what basis they should report it. The requirements in 
subpart 3175 of this final rule establish these standards.
    This rule also addresses findings and recommendations made in two 
GAO reports and one OIG report: (1) 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 Report 10-313); (2) 
GAO Report to Congressional Requesters, Oil and Gas Resources, 
Interior's Production Verification Efforts and Royalty Data Have 
Improved, But Further Actions Needed, GAO-15-39 (GAO Report 15-39); and 
(3) OIG Report, Bureau of Land Management's Oil and Gas Inspection and 
Enforcement Program (CR-EV-0001-2009) (OIG Report).
    Consistent with the Subcommittee's findings, the GAO found that the 
Department's measurement regulations and policies do not provide 
reasonable assurances that oil and gas are accurately measured because, 
among other things, its policies for tracking where and how oil and gas 
are measured are not consistent and effective (GAO Report 10-313, 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 the DOI 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 OIG Report, 
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 Report 15-39, p. 16). Among its 
recommendations were that the Secretary direct the BLM to ``meet its 
established timeframe for issuing final regulations for gas 
measurement'' (ibid., p. 32).
    In total, the GAO made 19 recommendations to improve the BLM's 
ability to ensure that oil and gas produced from Federal and Indian 
lands are accurately measured and properly reported (GAO Report 10-
313), a number of which relate to gas measurement. For example, the 
report recommends that the BLM establish goals that would allow it to 
witness gas sample collections; however, it recognized that the BLM 
must first establish gas sampling standards as a basis for inspection 
and enforcement actions. This final rule establishes those standards. 
Similarly, the 2015 GAO report recommends, among other things, that the 
BLM issue new regulations pertaining to gas measurement, which this 
rule accomplishes.
    It should also be noted that the GAO's recommendations regarding 
gas measurement are also one of the bases for the GAO's inclusion of 
the Department's oil and gas program on the GAO's High Risk List in 
2011 (GAO-11-278) and for its continuing to keep the program on the 
list in the 2013 and 2015 updates (GAO-13-283 (2013) and GAO-

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15-290 (2015)). Specifically, the GAO concluded with respect to the 
High Risk List that inclusion of the BLM's oil and gas program is 
justified because, among other things, the program's existing policies 
and regulations do not provide ``reasonable assurance that . . . gas 
produced from federal leases is accurately measured and that the public 
is getting an appropriate share of oil and gas revenues'' (GAO-11-278, 
p. 38).
    In addition to these external reports and assessments, the 
provisions of this rule are also based on the BLM's own internal 
assessment of the adequacy of the existing requirements of Order 5. For 
example, because many improvements in technology and industry standards 
have occurred since Order 5 was issued, the BLM has had to develop a 
number of statewide NTLs and/or approve a number of site-specific 
variances. This final rule addresses these issues and supersedes the 
statewide NTLs.
    The following summarizes and briefly explains the most significant 
provisions in this final rule. Each of these is discussed more fully in 
the Section-by-Section analysis below. For that reason, references to 
specific section and paragraph numbers are omitted in the body of this 
summary discussion.

1. Determining and Reporting Heating Value and Relative Density 
(Sec. Sec.  3175.110 Through 3175.126)

    The most significant requirements of the final rule are related to 
determining and reporting the heating value and relative density of all 
gas produced. Royalties on gas are calculated by multiplying the volume 
of the gas removed or sold from the lease (generally expressed in 
thousands of standard cubic feet (Mcf)) by the heating value of the gas 
in British thermal units (Btu) per unit volume, the value of the gas 
(expressed in dollars per million Btu (MMBtu)), and the fixed royalty 
rate. Therefore, a 10 percent error in the reported heating value would 
result in the same error in royalty as a 10 percent error in volume 
measurement. Relative density, which is a measure of the average mass 
of the molecules flowing through the meter, is used in the calculation 
of flow rate and volume. Because the flow equation uses the square root 
of relative density, a 10 percent error in relative density would only 
result in a 5 percent error in the volume calculation. Both heating 
value and relative density are determined from the same gas sample.
    Currently, Order 5 requires a determination of heating value only 
once per year. Federal and Indian onshore gas producers can then use 
that value in the royalty calculations for an entire year. There are 
currently no requirements in Order 5 for determining relative density. 
Existing regulations do not have standards for how gas samples used in 
determining heating value and relative density should be taken and 
analyzed to avoid biasing the results. In addition, existing 
regulations do not prescribe when and how operators should report the 
results to the BLM.
    In response to a Subcommittee recommendation that the BLM determine 
the potential heating-value variability of produced natural gas and 
estimate its implications for royalty payments, the BLM conducted a 
study of 180 gas facility measurement points (FMPs) that found 
significant sample-to-sample variability in heating value and relative 
density. The ``BLM Gas Variability Study Final Report,'' dated May 21, 
2010, used 1,895 gas analyses gathered from 65 formations. In one 
example, the study found that heating values measured from samples 
taken at a gas meter in the Anderson Coal formation in the Powder River 
Basin varied 31.41 percent, while relative density varied 
19.98 percent. In multiple samples collected at another gas 
meter in the same formation, heating values varied by only 2.58 percent, while relative density varied by 3.53 
percent (p. 25). Overall, the uncertainty (statistical range of error 
that indicates the risk of measurement error) in heating value and 
relative density in this study was 5.09 percent, which, 
across the board, could amount to $127 million in royalties 
based on 2008 total onshore Federal and Indian royalty payments of 
about $2.5 billion (p. 16).
    The study concluded that heating value variability is unique to 
each gas meter and is not related to reservoir type, production type, 
age of the well, richness of the gas, flowing temperature, flow rate, 
or several other factors that were included in the study (p. 17). The 
study also concluded that more frequent sampling increases the accuracy 
of average annual heating value determinations (p. 11).
    This rule strengthens the BLM's regulations on measuring heating 
value and relative density by requiring operators to sample all meters 
more frequently than required under Order 5, except very-low-volume 
meters (measuring 35 Mcf/day or less), for which annual sampling 
remains sufficient. Low-volume FMPs (measuring more than 35 Mcf/day, 
but less than or equal to 200 Mcf/day) must be sampled every 6 months; 
high-volume FMPs (measuring more than 200 Mcf/day, but less than or 
equal to 1,000 Mcf/day) must initially be sampled every 3 months; very-
high-volume FMPs (measuring more than 1,000 Mcf/day) must initially be 
sampled every month. In developing this rule, the BLM realized that a 
fixed sampling frequency may not achieve a consistent level of 
uncertainty in heating value for high-volume and very-high-volume 
meters. For example, a 3-month sampling frequency may not adequately 
reduce average annual heating value uncertainty in a meter which has 
exhibited a high degree of variability in the past. On the other hand, 
a 3-month sampling frequency may be excessive for a meter that has very 
consistent heating values from one sample to the next. If a high- or 
very-high-volume FMP did not meet these heating-value uncertainty 
limits, the BLM will adjust the sampling frequency at that FMP until 
the heating value meets the uncertainty standards. If a very-high-
volume FMP continues to exceed the uncertainty standards, the final 
rule includes a provision that allows the BLM to require the 
installation of composite samplers or on-line gas chromatographs (GCs), 
which automatically sample gas at frequent intervals.
    The rule also sets new average annual heating value uncertainty 
standards of 2 percent for high-volume FMPs and 1 percent for very-high-volume FMPs. The BLM established these 
uncertainty thresholds by determining the uncertainty at which the cost 
of compliance equals the risk of royalty underpayment or overpayment.
    In addition to prescribing uncertainty standards and more frequent 
sampling, this rule also improves measurement and reporting of heating 
values and relative density by setting standards for gas sampling and 
analysis. These standards specify sampling locations and methods, 
analysis methods, and the minimum number of components that must be 
analyzed. The standards also set requirements for how and when 
operators report the results to the BLM and the Office of Natural 
Resources Revenue (ONRR), and define the effective date of the heating 
value and relative density that is determined from the sample.

2. Meter Inspections (Sec.  3175.80)

    This rule requires operators to periodically inspect the insides of 
meter tubes for pitting, scaling, and the buildup of foreign 
substances, which could bias measurement. Existing regulations do not 
address this issue. Under this rule, basic meter tube inspections are 
required once every 5 years at low-volume FMPs, once every 2 years at 
high-volume FMPs, and

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yearly at very-high-volume FMPs. The BLM has the ability to increase 
this frequency if a basic inspection identifies any issues or if the 
meter tube operates in adverse conditions, such as with corrosive or 
erosive gas flow. If the basic inspection indicates the presence of 
pitting, obstructions, or a buildup of foreign substances, at low-
volume FMPs the operator must clean the meter tube of obstructions and 
foreign substances; at high- and very-high-volume FMPs, the operator 
must conduct a detailed meter tube inspection. A detailed meter-tube 
inspection involves removing or disassembling the meter run. Operators 
must repair or replace meter tubes that no longer meet the requirements 
in this rule.

3. Meter Verification or Calibration (Sec. Sec.  3175.92 and 3175.102)

    The rule changes routine meter verification or calibration 
requirements from current requirements under Order 5. Verification 
frequency is decreased at all very-low-volume FMPs and low-volume FMPs 
using electronic gas measurement (EGM) systems. Verification frequency 
is unchanged from current regulations for low-volume FMPs using 
mechanical recorders and high- and very-high-volume FMPs. Currently, 
under Order 5, all meters are required to undergo routine verification 
every 3 months, regardless of the throughput volume.
    The rule restricts the use of mechanical chart recorders to low- 
and very-low-volume FMPs because the accuracy and performance of 
mechanical chart recorders is not defined well enough for the BLM to 
quantify the overall measurement uncertainty. Between 80 and 90 percent 
of gas meters at Federal onshore and Indian FMPs use EGM systems.

4. Requirements for EGM Systems (Sec. Sec.  3175.31, 3175.100 Through 
3175.104 and Sec. Sec.  3175.130 Through 3175.144)

    Although industry has used EGM systems for about 30 years, Order 5 
does not currently address them. Instead, the BLM has regulated their 
use through statewide NTLs, which do not address many aspects unique to 
EGMs, such as volume calculation and data-gathering and retention 
requirements. This rule includes many of the existing NTL requirements 
for EGM systems and adds some new requirements relating to onsite 
information, gauge lines, verification, test equipment, calculations, 
and information generated and retained by the EGM systems. The rule 
includes a significant change in those requirements by revising the 
maximum flow-rate uncertainty that is currently allowed under existing 
statewide NTLs. Under the NTLs, flow-rate equipment at FMPs that 
measure more than 100 Mcf/day is required to meet a 3 
percent uncertainty level. The rule maintains that level of uncertainty 
for high-volume FMPs although the threshold is raised to 200 Mcf/day. 
Under this rule, equipment at very-high-volume FMPs must comply with a 
new 2 percent uncertainty requirement. Flow-rate equipment 
at FMPs that measure less than 200 Mcf/day is exempt from these 
uncertainty requirements. The BLM is maintaining this exemption because 
it believes that compliance costs for these FMPs could cause some 
operators to shut in their wells instead of making improvements. The 
BLM believes the royalties lost by such shut-ins would exceed any 
royalties that might be gained through upgrades at such facilities.
    One area that this rule addresses, which is not addressed by 
existing NTLs, is the accuracy of transducers and flow-computer 
software used in EGM systems. Transducers send electronic data to flow 
computers, which use that data, along with other data that are 
programmed into the flow computers, to calculate volumes and flow 
rates. Currently, the BLM must accept transducer manufacturers' claimed 
performance specifications when calculating uncertainty. Neither the 
American Petroleum Institute (API) nor the Gas Processors Association 
(GPA) has standards for determining these performance specifications. 
For this reason, the rule requires operators or manufacturers to ``type 
test'' transducers at a qualified testing facility using a standard 
testing protocol defined in this rule or, for transducers that are 
already in use at FMPs, submit existing test data to the BLM for 
review. The purpose of this review is to quantify the uncertainty of 
the transducers using actual test data, rather than relying on the 
manufacturer's performance specifications. The BLM will then 
incorporate the test results into the calculation of overall 
measurement uncertainty based on each transducer tested. The rule also 
requires operators or manufacturers to test flow computers and flow-
computer software at qualified testing facilities, using a standard 
testing protocol defined in this rule, to assess the ability of those 
flow-computers and software versions to accurately calculate flow rate, 
volume, and other values that are used in the BLM's verification 
process. Only those flow computers and flow computer software versions 
that demonstrate the ability to perform these calculations within the 
tolerances established by the BLM will be allowed for use on Federal 
and Indian leases.
    An integral part of the BLM's evaluation process is the Production 
Measurement Team (PMT), made up of measurement experts designated by 
the BLM.\6\ The rule requires that the PMT review the results of type 
testing done on transducers and flow-computer software and make 
recommendations to the BLM. If approved, the BLM will post the make, 
model, and range of the transducer or software version on the BLM 
website as being appropriate for use. The BLM will also use the PMT to 
evaluate and make recommendations on the use of other new types of 
equipment, such as flow conditioners and primary devices, new 
measurement sampling, or analysis methods.
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    \6\ The PMT will be distinguished from the DOI's Gas and Oil 
Measurement Team (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 will not use a dual-agency approval process for 
the use of new measurement technologies for onshore leases. The BLM 
anticipates that members of the BLM PMT will participate as a part 
of the DOI GOMT.
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II. Discussion of Final Rule and Comments on the Proposed Rule

A. General Overview of Final Rule

    As discussed in the Background and Overview section of this 
preamble, the provisions of Order 5 have not kept pace with industry 
standards and practices, statutory requirements, or applicable 
measurement technology and practices. This final rule updates and 
replaces those requirements by establishing the minimum standards for 
accurate measurement and proper reporting of all gas sold from Federal 
and Indian (except the Osage Tribe) leases, units, unit PAs, and areas 
subject to CAs, by providing a system for production accountability by 
operators, lessees, purchasers, and transporters. 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 5 appears in the proposed rule at 80 FR 61650 
(October 13, 2015).

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B. General Overview of Comments Received

    This section presents and responds to general comments on the 
proposed rule received by the BLM. Comments on specific provisions of 
the proposed rule are addressed in the Section-by-Section analysis as 
part of the explanation of the provisions included in this final rule.
Administrative Delay
    The BLM received numerous comments stating the new rule will cause 
additional delays and backlogs for both the BLM and industry because of 
all the additional paperwork and inspections required by the new rule. 
The BLM has analyzed and disclosed the burdens for industry in the 
Economic and Threshold Analysis prepared as part of this rulemaking 
process and in the Paperwork Reduction Act portion of this preamble. 
Some of the burdens are usual and customary, since they are required by 
gas sales contracts and/or industry standards. The BLM has determined 
that the remaining burdens are necessary in order to ensure accurate 
measurement and reporting.
    The BLM also acknowledges that implementation of the rule will 
require additional BLM staff time. The BLM has analyzed and disclosed 
the Federal burdens that will result from this rule. The BLM is taking 
steps to address the issue of streamlining administrative processes, 
including strategic investments in technology and repeatedly requesting 
additional resources during the appropriations process. The BLM will 
continue to pay attention to this issue during the implementation 
period. The BLM did not make any changes to the rule in response to 
these comments.
Inspection and Enforcement Handbook
    As was stated in the preamble of the proposed rule, this final rule 
removes the enforcement, corrective action, and abatement period 
provisions of Order 5. 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 Authorized Officer (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 explained in the 
proposed rule, this change allows the BLM to make a case-by-case 
determination of the severity of a particular violation, based on 
applicable definitions in the regulations.
    Several comments objected, saying that this course of action was 
inconsistent with the APA. One such commenter stated its objection as 
follows:

    BLM's proposal would completely eliminate the enforcement 
infrastructure prescribed in Onshore Order No. 5, including major 
and minor violations, corrective actions, and abatement periods. . . 
. Removing the enforcement provisions from the realm of transparent, 
publicly reviewable regulations that were promulgated with notice 
and comment, and concealing them in non-public policy documents that 
can be altered in the absence of public input, is inconsistent with 
the requirements of the APA. BLM-2015-0005-0058 (December 15, 2015).

    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. Moreover, 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 Enforcement Handbook, that will 
provide the legal basis for the BLM's enforcement actions. Put another 
way, BLM's enforcement actions must be consistent with these 
regulations irrespective of what may be contained in its Inspection and 
Enforcement Handbook. It should also be noted, it is this rule and 
other duly promulgated regulations that establish these standards to 
which an operator will be held consistent with Administrative Procedure 
Act (APA) requirements.
    As to the concern about public notice and comment processes, it 
should be noted that internal guidance documents that direct agency 
personnel on how to implement existing agency policies are not required 
to follow the public notice and comment process. No change to the rule 
resulted from these comments.
    One commenter suggested that the BLM should retain discretionary 
case-by-case enforcement of requirements as is currently done under 
Order 5. Although the BLM disagrees with the premise of the comment 
regarding the existing requirements of Order 5, the intent of the 
Inspection and Enforcement Handbook is to provide guidance to BLM 
inspectors on how to apply the provisions of its oil and gas rules in a 
consistent manner. As noted above, it will not establish new 
requirements or obligations. It also will not alter the BLM's case-by-
case discretion with respect to any particular enforcement action. The 
BLM did not make any changes to the rule based on this comment.
    Several commenters suggested that the BLM should post the 
Inspection and Enforcement Handbook on the website. The BLM agrees with 
this comment and will post the enforcement handbook upon its 
completion, and will otherwise make it available to the public at any 
BLM office.
    One commenter suggested that the BLM should develop the Inspection 
and Enforcement Handbook with input from industry. The BLM disagrees 
with this comment since the handbook is

[[Page 81529]]

intended to provide internal guidance to BLM inspectors. However, as 
the Handbook is developed, the BLM will determine the appropriate 
process to use, including consideration of appropriate opportunities to 
obtain input from stakeholders. The BLM did not make any changes to the 
rule as a result of this comment.
    One commenter asked if the BLM will publish the Inspection and 
Enforcement Handbook at the same time as the final rule. For the 
preceding reasons, the BLM has determined that it is not necessary to 
release the handbook with this final rule. However, the BLM intends to 
develop the Handbook within 1 year of the effective date of the 
proposed rule, which is the earliest date by which the provisions of 
this rule will go into effect. The BLM did not make any changes to the 
rule as a result of this comment.
    One commenter asked that the BLM provide the economic analysis of 
developing an Inspection and Enforcement Handbook instead of including 
enforcement actions in the rule and for moving away from the more 
discretionary enforcement approach to more immediate assessments. The 
BLM does not agree with the characterization of Order 5 and the current 
approach. Also, there have always been immediate assessments, and the 
BLM has simply expanded the list of actions potentially subject to an 
immediate assessment. With respect to the requested economic analysis, 
the BLM does not believe that there is any economic impact in removing 
enforcement guidance from the rule and placing it in an enforcement 
handbook. Additionally, because the BLM assumes compliance for purposes 
of assessing the impact of a rule, the BLM does not believe that it is 
appropriate to analyze the economic impacts of immediate assessments. 
The BLM did not make any changes to the rule as a result of this 
comment.
National Technology Transfer and Advancement Act of 1995
    One commenter stated that, per the National Technology Transfer and 
Advancement Act (NTTAA), codified as a note to 15 U.S.C. 272, the BLM 
must adopt API standards in whole or justify to the Office of 
Management and Budget (OMB) why this does not meet the agency mission. 
The NTTAA directs agencies to utilize technical standards that are 
developed by voluntary consensus standards bodies. Some commenters 
argued that the NTTAA obligates the BLM to adopt all gas measurement 
standards developed by voluntary consensus standards bodies.
    The commenters' assertion 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 OMB's guidance for implementing the NTTAA defines ``impractical'' 
to include circumstances in which 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, p. 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, p. 25). The 
BLM has studied the available voluntary consensus standards for gas 
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, less feasible, or less useful. In 
addition, the commenters' reading of the NTTAA would, contrary to OMB 
guidance, inappropriately preempt the BLM's statutory authority to 
promulgate rules and regulations that it deems ``necessary'' to 
accomplish the purposes of the applicable statutory directives, 
including the Mineral Leasing Act (MLA) and the Federal Oil and Gas 
Royalty Management Act (FOGRMA).
Retroactivity
    Several commenters argued that the rule is impermissibly 
``retroactive.'' These comments argued that the rule is retroactive 
because it will apply to existing measurement systems that predate the 
rule's effective date. 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 final rule does not attach any new legal consequence to the use of 
existing measurements systems prior to the rule's effective date. 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 business 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. Chemical Waste Mgmt., Inc. v. EPA, 
869 F.2d 1526, 1536 (D.C. Cir. 1989).

    This rule does not impose liability for nor require changes to 
measurements made prior to the rule's enactment; rather the rule 
requires measurements taken as required by the rule after the effective 
date of the rule (that is, going forward) at both new and existing 
facilities to satisfy the performance standards established by the 
final rule. Thus, despite the fact that this rule may require operators 
to update or modify their existing measurement systems, the rule is 
prospective--not retroactive--in nature.
Availability of Material Incorporated by Reference
    The BLM received comments arguing that the incorporated API and GPA 
standards were not adequately available to the public during the 
comment period. The BLM's obligation to make the incorporated standards 
available to the public derives from the Freedom of Information Act 
(FOIA), which requires agencies to publish ``substantive rules of 
general applicability adopted as authorized by law'' in the Federal 
Register (5 U.S.C. 552(a)(1)(D)). Under FOIA, ``matter reasonably 
available to the class of persons affected thereby is deemed published 
in the Federal Register when incorporated by reference therein with the 
approval of the Director of the Federal Register'' (id. section 
552(a)(1)). For the following reasons, the industry standards 
incorporated by reference in the final rule are--and have been--
``reasonably available'' to the public as required by FOIA. As 
discussed in the notice of proposed rulemaking, all of the API and GPA 
standards incorporated by reference in the rule have been available for 
inspection at the BLM's Washington, DC office and at all BLM offices 
with jurisdiction over oil and gas activities

[[Page 81530]]

(80 FR 61646, 61655). All of the incorporated API standards have also 
been available for inspection at API's Washington, DC office; API has 
also provided free, read-only access to some of the incorporated 
standards online (id.). All of the incorporated GPA standards have also 
been available for inspection at GPA's Tulsa, Oklahoma office (id.). 
Finally, all of the incorporated API and GPA standards have been, and 
continue to be, available for purchase from API and GPA.
    Some commenters stated that local BLM offices were unable to 
provide them with access to the incorporated standards. These 
occurrences resulted from the fact that, although all the local BLM 
offices have electronic access to the incorporated standards, not all 
local office personnel were aware of how to access the incorporated 
standards. The BLM plans to carry out a training program to ensure that 
personnel at local BLM offices can readily access the incorporated 
standards and provide them to interested members of the public when 
requested. Given the multiple avenues available for accessing the 
incorporated standards, we do not believe that the handful of reported 
occurrences in which staff were unable to access the standards 
prevented stakeholders from accessing and reviewing the documents as 
part of their review of the proposed rule. Therefore the BLM has met 
its obligations under FOIA and the APA with respect to those standards.
    It should be noted that the BLM received numerous comments 
regarding the adoption of specific API and GPA standards in the 
proposed rule. Most of these comments are addressed in connection with 
the relevant sections of the rule (Sec. Sec.  3175.30, 3175.40, 
3175.110, 3175.130, and 3175.140; see section II. C of this preamble 
below).
Duplication of State Rules
    The BLM received one comment stating that this rule is duplicative 
of State rules. During the development of this rule, the BLM researched 
existing State rules related to gas measurement and crafted the rule to 
avoid conflicts with applicable State standards. The commenter did not 
identify any inconsistencies.
    Moreover, the BLM is issuing this rule in fulfillment of its 
fiduciary obligation to assure that Federal and Indian gas is properly 
measured and that all royalties due under Federal law are paid. The 
fact that some States may have similar requirements does not render 
this rule duplicative, as the BLM has an independent responsibility to 
meet its fiduciary obligations for the resources it manages.
Definitions Hard To Find
    One commenter stated that separately publishing the proposed rules 
to update and replace Order 3 (site security), Order 4 (oil 
measurement), and Order 5 made the definitions hard to find. The BLM 
does not agree with this comment. The proposed rule to replace Order 3 
also established a new part 3170 that will contain all three rules to 
replace Orders 3, 4, and 5, including a definitions section containing 
provisions common to all three rules. The proposed rules, in most 
instances, contained all of the key definitions unique to each subpart. 
For example, definitions specific to gas measurement are found in the 
definitions section of this rule. Definitions that are used in two or 
more subparts are found in the definitions section of subpart 3170 in 
order to reduce redundancy and ensure consistency. Additionally, the 
BLM extended the comment periods for all three proposed rules to ensure 
that they were all open and available for comments at the same time.
    Moreover, since all three final rules to replace Orders 3, 4, and 5 
will appear in the CFR in a new part 3170, this will ensure that the 
definitions will be easy to find during implementation. The BLM did not 
make any changes to the rule in response to this comment.
Not Enough Information
    The BLM received several comments stating the proposed rule did not 
contain a description of all the calculations, assumptions, and 
enforcement actions, nor an explanation of why certain industry 
standards were or were not incorporated by reference. The BLM believes 
that a thorough description of the assumptions and rationale for the 
proposed changes was provided in the preamble to the proposed rule. The 
BLM also published heating value variability and uncertainty 
calculations in the BLM Gas Variability Study, which was referenced 
numerous times in the preamble and posted as a supporting document on 
the www.regulations.gov Web site, along with the proposed rule. The BLM 
has been enforcing flow-rate uncertainty standards since 2009 and the 
calculations that the BLM uses to determine uncertainty have been 
publicly available since that time. Additionally, all of the economic 
assumptions used in the proposed rule were also posted on the 
www.regulations.gov Web site in a supporting document, along with the 
proposed rule (``Proposed 3175 Economic Analysis'').
    With respect to incorporated industry standards, the BLM 
incorporated the standards that are relevant and appropriate to the 
proposed rules. These include standards that directly relate to the 
measurement of volume and heating value typical of the technologies 
currently used at BLM points of royalty measurement (now called FMPs). 
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, or standards 
that cover equipment and processes that are very rarely used for gas 
measurement at the lease level, such as those covering Coriolis meters, 
turbine meters, or ultrasonic meters. That said, the PMT may, on a 
case-by-case basis, consider recommending for approval the use of such 
standards in lieu of compliance with the identified standards if and 
when it is asked to review such requests for approval to employ such 
standards in the field in the future. The commenters' questions 
regarding enforcement were addressed previously. The BLM did not make 
any changes to the rule based on these comments.
Only Use Performance Goals
    Numerous comments objected to the equipment standards in the 
proposed rule and suggested that the BLM only rely on performance goals 
because the equipment standards will become obsolete as technology 
progresses. The BLM agrees that some of the equipment standards may 
become obsolete as technology progresses. As a result, the BLM included 
performance standards in Sec.  3175.31 of the final rule (Sec.  3175.30 
in the proposed rule), along with a process for the BLM--through the 
PMT--to assess and approve new technologies over time. The BLM also 
agrees that, with appropriate oversight, performance goals should be 
sufficient without the explicit equipment standards. The BLM fully 
supports the concept of allowing industry to determine the best and 
most cost-effective way to meet performance goals. As a result, this 
rule allows the BLM to approve technologies and processes that are 
different from the specific equipment standards in the rule as long as 
they meet or exceed the stated performance goals in Sec.  3175.31. It 
should be noted that unlike the existing variance process, which 
requires local field office approval on a case-by-case basis, the PMT 
process outlined in the proposed and final rules is structured such 
that the PMT needs to review and approve technology only once on a

[[Page 81531]]

nation-wide basis; subsequently, facilities will be able to rely on 
those PMT reviews and approvals as long as they comply with any 
applicable conditions of approval.
    While the BLM recognizes the value of performance-based standards, 
it is nevertheless providing equipment standards for two reasons. 
First, the BLM has over 4,000 operators of Federal and Indian leases 
and the vast majority of these operators are small companies without 
measurement personnel on staff. Requiring a small operator to achieve, 
for example, an overall meter measurement uncertainty of 3 
percent, without any equipment standards, would likely require the 
operator to hire measurement specialists to determine the equipment and 
operating conditions necessary to meet the uncertainty requirement on 
their leases. The BLM equipment standards provide a ``cookbook'' for 
how to achieve the performance goals established in the rule for 
operators that do not have the expertise, resources, or interest in 
innovating new technology or processes to meet a performance goal. In 
the BLM's experience, this cookbook approach is useful to smaller 
operators and is a feature of Order 5 that was retained in the final 
rule.
    Second, it would be virtually impossible for the BLM to enforce a 
performance goal without a full understanding of the technology and 
process the operator is using to achieve that goal. In addition, this 
would require customized enforcement procedures for every meter 
installation. For the BLM to implement this approach, it would need to 
approve all new FMP installations on a case-by-case basis, which would 
include: (1) Conducting a detailed analysis on the operator's proposal 
regarding how they would achieve the performance goals in the rule; and 
(2) Developing the enforcement procedures specific to that approval. 
This would unnecessarily drive up costs for both the BLM and industry 
and could result in backlogs of new measurement applications, both of 
which the BLM (and likely industry as well) would prefer to avoid.
    Under this rule, the BLM has to approve only those technologies and 
processes that are different from the equipment standards listed in the 
rule. The BLM did not make any changes to the rule based on these 
comments.
New Rule Not Needed
    The BLM received several comments stating that Order 5 works well 
as written and a new rule is not needed. The BLM disagrees with these 
comments. Order 5 incorporates one industry standard--AGA Report No. 3 
from 1985. This standard addresses the installation requirements for 
orifice meters and the calculation of flow rate from an orifice meter. 
Installing an orifice meter using this standard can cause significant 
bias in measurement. This standard has been revised numerous times 
since 1985 based on new data and better calculation techniques. In 
addition, Order 5 does not incorporate standards for the calculation of 
volume from orifice meters, the calculation of supercompressibility 
used in flow-rate calculations, or the collection and analysis of gas 
samples. Further, Order 5 does not state overall performance goals or 
include a process to analyze and apply new technology on a national 
basis. Lastly, Order 5 does not cover EGM systems that now make up 
approximately 90 percent of all gas meters in the field. These 
deficiencies are what led the Subcommittee, the OIG, and the GAO to 
conclude that the BLM's gas measurement regulations are outdated and in 
need of an update. Management of onshore Federal oil and gas resources 
is on the GAO's High Risk List, in large part due to its outdated 
measurement regulations. The BLM did not make any changes to the rule 
as a result of these comments. Further evidence regarding the 
inadequacy of Order 5 can be found in the fact that the BLM has had to 
issue NTLs supplementing its requirements.
    One commenter stated that no third-party proof exists to 
demonstrate that the proposed changes would improve measurement. The 
BLM did not make any changes to the rule based on this comment. While 
the rulemaking process does not require third-party confirmation that 
the proposed changes would improve measurement, the BLM is confident 
that the rule will result in substantial improvements to both the 
accuracy and verifiability of measurement.
    For example, existing Order 5 has only one requirement relating to 
the determination of heating value--that it be determined once per 
year. Order 5 has no requirements as to where the sample is taken, how 
it is taken, how it is analyzed, or how it is reported. Nor does Order 
5 incorporate any industry standards relating to sampling and analysis, 
even though those have been developed. As illustrated in the Background 
Section of this preamble, inaccurate heating value determination has 
the same impact on royalty calculations as errors in volume 
determination. As explained in the preamble to the proposed rule, the 
BLM has shown that Order 5's existing requirement to sample once per 
year is inadequate. BLM's Gas Variability Study demonstrated 
significant variability in heating value for individual facilities that 
would not be captured by once per year sampling and that may be 
correlated to the lack of any BLM standards on how it is determined. 
This final rule, on the other hand, incorporates five consensus 
industry standards relating to the sampling and analysis of heating 
values and sets standards on heating value uncertainty, sample probes, 
sample cylinders, GCs, and reporting.
    One commenter stated that the new rule will not aid in consistency. 
The BLM disagrees with this comment. Order 5 included a variance 
process to address new technology and to allow the BLM to approve 
alternate methodology that accomplished the goals of the Order. 
Unfortunately, Order 5 did not state what those goals were and left the 
review and approval process at the field office level. This resulted in 
inconsistent review of variances from office to office, an issue which 
was raised by industry, the GAO, and the OIG. This final rule 
establishes a new national process for the review and approval of new 
technology and/or alternate measurement methodologies through a 
centralized team, the PMT. Once approved, the BLM will post the device 
or process on the BLM website along with any conditions for its use 
developed by the PMT. Operators can rely on those approvals without 
seeking a subsequent authorization. This centralized review will 
dramatically improve consistency over the current process. The BLM did 
not make any changes to the rule as a result of this comment.
Use Variance Process for Small Operators
    One commenter suggested a variance process for small operators who 
cannot comply with API standards. Consistent with the comment, the 
final rule includes a standard process for any operator to obtain BLM 
approval for an alternate methodology, as long as that methodology 
meets or exceeds the performance goals set out in Sec.  3175.31. 
Recognizing the economics of lower-volume properties, the final rule 
adopts changes relative to the proposed rule that will reduce the 
requirements on those properties, which will reduce compliance costs 
for operators, many of which could be smaller operators. Those specific 
changes are discussed later in the preamble, in the Section-by-Section 
analysis. The BLM did not make any changes to the rule as a result of 
this comment.

[[Page 81532]]

Transporters
    The BLM received numerous comments objecting to the provision in 
the proposed rule to require transporters to keep measurement records. 
It should be noted at the outset that this change was the result of 
statutory requirements imposed by Congress under FOGRMA and the changes 
in the proposed rule are consistent with that statutory direction. 
Commenters objected to the requirement that both the operator and the 
transporter keep duplicate records and noted that transporters will 
have to modify their computer systems to comply with BLM requirements, 
including the requirement to store the FMP number. Based on other 
comments (see the discussion of Sec. Sec.  3175.101(b)(4) and 
3175.104(a)(1) in section II.C. of this preamble), the BLM has decided 
that it will not require operators, purchasers, or transporters to 
include the FMP number as part of the flow-computer display or include 
it on audit trail records. Parties may continue to use unique meter 
station identifiers. The FMP number is now only required on the Oil and 
Gas Operations Reports (OGORs) that the operator submits to ONRR. The 
BLM realizes that this requirement could result in duplicate sets of 
records in some cases. However, when the BLM audits an FMP that is 
owned by a transporter or purchaser rather than the operator, the 
operator may not have access to the complete audit trail. In these 
cases, the records held by the transporter would not be duplicates.
    A few commenters asked for clarification of which records the 
transporter or purchaser will be responsible for maintaining. The 
transporter or purchaser is responsible for maintaining all records 
required by this subpart for FMPs that are owned by the transporter or 
purchaser for the timeframes listed in 43 CFR 3170.7. The BLM did not 
make any changes to the rule based on these comments.
    One commenter stated that there is no indication that the records 
currently maintained by the transporter or purchaser are inadequate. If 
the records owned by the transporter or purchaser are adequate, as 
implied by the comment, then this rule should not have any additional 
impact on the transporter or purchaser. The BLM did not make any 
changes to the rule based on this comment.
    One commenter stated that transporters and purchasers should not be 
subject to immediate assessments. The BLM agrees with this comment and 
has removed purchasers and transporters from the immediate assessment 
section in Sec.  3175.150 (see discussion under that section).
Will Deter Development and Reduce Royalty
    The BLM received many comments stating that the proposed rule would 
deter development on Federal and Indian oil and gas leases and result 
in lower royalty due to operators shutting in their production rather 
than complying. The commenters stated that the cost, complexity, 
delays, and new reporting requirements are primary reasons. One 
commenter stated that the rule would be especially burdensome for small 
operators. In response to comments on specific parts of the proposed 
rule, the BLM made numerous changes in the final rule that should 
provide significant economic relief to operators on Federal and Indian 
leases. These changes include:
     The threshold between very-low- and low-volume is raised 
from 15 Mcf/day to 35 Mcf/day, and the threshold between low- and high-
volume is raised from 100 Mcf/day to 200 Mcf/day;
     Existing meter tubes at low- and high-volume FMPs are 
grandfathered \7\ from the construction, length, and eccentricity 
requirements in Sec.  3175.80(f) and (k), and from API 14.3.2, 
Subsection 6.2, although they still must comply with the 1985 AGA 
Report No. 3 standards (very-low-volume FMPs are exempt from meter tube 
requirements altogether);
---------------------------------------------------------------------------

    \7\ The term ``grandfathered'' means that meters in use prior to 
the effective date of the rule do not have to comply with those 
portions of the rule.
---------------------------------------------------------------------------

     Flow-computer software at very-low-, low-, and high-volume 
FMPs are grandfathered and flow computers no longer have to display the 
FMP number;
     Accounting systems no longer have to include the FMP 
number;
     Composite sampling systems or on-line GCs are no longer 
required on high-volume FMPs, and they were never required for very-
low- and low-volume FMPs;
     Gauge lines with a \3/8\-inch nominal diameter are 
acceptable;
     Implementation of the requirement for PMT approval of 
existing equipment and gas analysis input into the Gas Analysis 
Reporting and Verification System (GARVS) is delayed for 2 years after 
the effective date of the final rule;
     Long-term stability tests for transducers is longer 
required;
     The PMT has the ability to approve existing transducers 
using existing data from manufacturers;
     Multiple analyses for laboratory GCs are no longer 
required; and
     C9+ analysis is only required periodically for high- and 
very-high-volume FMPs and only if the mole percentage for C6+ exceeds 
0.5 percent.
    Several commenters stated that the new rules could reduce royalty 
by increasing the costs of metering, which, in turn, operators could 
claim as a transportation deduction. The BLM consulted ONRR on this 
comment and ONRR confirmed that there are no circumstances in which an 
operator could claim the costs of metering as a transportation 
deduction even if the meter was owned by a transporter or purchaser. 
The BLM did not make any changes to the rule as a result of this 
comment.
Costs Underestimated
    The BLM received a number of comments stating that the Economic and 
Threshold Analysis did not adequately account for all costs associated 
with the proposed rule. Several commenters said that the estimated cost 
of the rule should include the costs to the government of reduced 
royalty payments, as well as lost tax revenues that will result from 
reduced State and local employment. However, the premise of this 
argument is based upon the commenter's assumption that operators would 
have had to shut in wells as a result of the rule. The numerous 
revisions to reduce the cost of the final rule described above will 
significantly reduce costs from the requirements of the proposed rule. 
The BLM does not believe that a significant number of shut-ins will 
occur as a result of this rule. Although the BLM made significant 
changes to the rule based on concerns over cost, the BLM did not make 
any changes based on these specific comments.
Cost-Benefit Analysis
    Several commenters stated that the BLM should have done a cost-
benefit analysis of the rule in which the estimated costs are compared 
against the resultant improvement in expected royalty revenue. There 
are several flaws in this argument. Notably, commenters are presuming 
that the only purpose of the rule is to eliminate measurement bias, and 
that FMPs are currently biased to read low. Bias is mismeasurement that 
results in a measured quantity that is either predictably higher than 
or predictably lower than the actual value of the quantity. If the BLM 
were aware that FMPs were biased to read low, then the commenter's 
assertions would be correct. In other words, if the sole intent of the 
rule were to eliminate bias to the low side and the BLM were able to 
quantify that bias, then the BLM could perform a cost-benefit analysis 
comparing the cost of the rule to the

[[Page 81533]]

increase in royalty payments resulting from the elimination of the bias 
to the low side. However, the BLM has no data to support the 
proposition that FMPs are biased exclusively to the low side (with the 
exception of Btu reporting and potentially also gas sampling 
practices). In addition, the elimination of bias, either high or low, 
is only one of the performance goals of the rule. The other performance 
goals are to establish uncertainty limits for high- and very-high-
volume FMPs and to require that all aspects of the measurement are 
independently verifiable by the BLM. Together, these performance goals 
are designed to ensure that the American public and Indian tribes and 
allottees are receiving a fair return for gas produced from their 
leases.
    Whether the rule will result in an increase in royalty, a decrease 
in royalty, or no change in royalty was not a consideration in the 
rule-making process. The rule is intended to obtain accurate 
measurement of the gas produced from Federal and Indian leases. The BLM 
did not make any changes to the rule based on these comments.
Withdraw Rule
    Two commenters recommended that the BLM withdraw the rule because 
it is incomplete and potentially devastating to the industry. The 
commenters did not elaborate as to why the rule is incomplete or why it 
would potentially be devastating to the industry. The BLM believes the 
proposed rule was complete and met all legal requirements of a proposed 
rule under the APA. The BLM also made significant changes to the 
proposed rule aimed at reducing costs, especially at low-volume 
facilities. These specific changes are discussed elsewhere. The BLM did 
not make any changes to the rule as a result of these comments.
Tone
    One commenter objected to the tone of the rule stating that the 
rule implies that operators are intentionally trying to underpay 
royalty. The commenter did not provide any specific examples. The BLM 
does not agree with this comment and did not intend to make such an 
implication. The BLM recognizes that measurement error goes in both 
directions and, as result, it might result in either over- or under-
reporting of production. The BLM did not make any changes to the 
proposed rule as a result of this comment.
Executive Order 13211
    The BLM received several comments stating that no data were 
presented to support the assertion that the rules will not affect the 
energy supply, as required by Executive Order (E.O.) 13211. The 
commenters stated that the rule will result in delays in distribution 
due to the backlog of new equipment that the BLM is requiring for 
existing FMPs. One commenter stated that the BLM needs to study the 
effects of the rule on transportation.
    E.O. 13211 requires an agency to prepare a ``Statement of Energy 
Effects'' when it undertakes a ``significant energy action.'' There are 
two ways in which an agency's action can constitute a significant 
energy action: (1) The action is a ``significant regulatory action'' 
under E.O. 12866 if it is ``likely to have a significant adverse impact 
on the supply, distribution, or use of energy''; or, (2) The action is 
designated as a significant energy action by the Office of Information 
and Regulatory Affairs (OIRA). This rule is not a significant energy 
action because it will not have a significant adverse impact on the 
supply, distribution, or use of energy, and it has not been designated 
as a significant energy action by OIRA. The BLM's conclusion that this 
rule is not a significant energy action is based on its analysis of the 
economic impact of the proposed rule.
    Additionally, in response to comments received, the BLM made 
numerous changes to the proposed rule that will reduce compliance costs 
and the potential for any approval backlogs for new equipment that may 
have resulted from the proposed rule. These changes include:
     The grandfathering of 98.7 percent of all meter tubes in 
place at FMPs as of January 17, 2017 from having to meet the 
construction and installation standards of API 14.3.2 (2000);
     The grandfathering of 88.7 percent of all flow computers 
in place at FMPs as of January 17, 2017 from having to use the latest 
flow-rate calculation methods of API 14.3.3 (2013);
     The grandfathering of 100 percent of all transducers in 
place as of January 17, 2017, from the testing protocol required in 
Sec.  3175.43, if the manufacturers submit existing test data to the 
PMT and the BLM approves the transducer based on that existing data; 
and
     Elimination of the requirement for flow computers to 
display the FMP number, which may have required some older model flow 
computers to be replaced.

C. Section-by-Section Analysis and Comment Responses

    This section describes the various regulatory changes made by this 
final rule. First, it describes the content of the specific sections of 
subpart 3175, explains any changes between the proposed and final 
rules, and responds to section-specific comments on the proposed rule 
received by the BLM during the comment period. Following that 
discussion, it describes changes and revisions being made to 43 CFR 
3162.7-3, 3163.1, and 3164.1. The proposed rule to replace Order 5 also 
proposed changes to 43 CFR 3163.2 and 3165.3. The proposed revisions 
are addressed in the final rule to replace Order 3 (being released 
concurrently with this rule) and are not discussed further here.
Sec.  3175.10--Definitions and Acronyms
    Section 3175.10 includes numerous new definitions unique to this 
rule because much of the terminology used in the rule is technical in 
nature and may not be readily understood by all readers or may have a 
specific meaning in the context of this rule. As explained in the 
preamble to the proposed rule, the BLM also added other definitions 
because their meanings, as used in the rule, may be different from what 
is commonly understood, or the definition includes a specific 
regulatory requirement.
    Definitions of terms commonly used in gas measurement or which are 
already defined in 43 CFR parts 3000, 3100, 3160, or subpart 3170 are 
not discussed in this preamble.
    The rule defines the terms ``primary device,'' ``secondary 
device,'' and ``tertiary device,'' which together measure the amount of 
natural gas flow. All differential types of gas meters consist of at 
least a primary device and a secondary device.
Primary Device
    The ``primary device'' is the equipment that creates a measureable 
and predictable pressure drop in response to the flow rate of fluid 
through the pipeline. It includes the pressure-drop device, device 
holder, pressure taps, required lengths of pipe upstream and downstream 
of the pressure-drop device, and any flow conditioners that may be used 
to establish a fully developed symmetrical flow profile.
    A flange-tapped orifice plate is the most common primary device 
found on Federal and Indian leases. It operates by accelerating the gas 
as it flows through the device, similar to placing one's thumb at the 
end of a garden hose. This acceleration creates a difference between 
the pressure upstream of the orifice and the pressure downstream of the 
orifice, which is known as differential pressure. It is the only

[[Page 81534]]

primary device that is approved in Order 5 and in this rule and would 
not require further specific approval. Other primary devices, such as 
cone-type meters, operate much like orifice plates and the BLM could 
consider them for approval under the requirements of Sec.  3175.47.
    One commenter recommended that the BLM include linear meters in the 
definition of ``primary device.'' The definition of primary device in 
the proposed rule was specific to differential-type meters. The BLM did 
not make any changes to the rule based on this comment. The rule allows 
the PMT to recommend approval of linear devices by make, model, and 
size. In its recommendation, the PMT can include requirements for a 
linear meter along with a definition of a linear-meter primary device, 
if needed. However, the performance standards in this rule are based 
around differential-type meters. As a result, there are many 
requirements pertaining specifically to the primary device of 
differential-type meters. A definition of ``primary device'' is in 
Sec.  3175.10 of the rule to avoid having to describe what a primary 
device is every time it is mentioned in the rule. Adding linear meters 
to the definition would make the requirements in the rule confusing and 
cumbersome. For example, Sec.  3175.47 requires operators or 
manufacturers to test primary devices other than orifice plates under 
API 22.2, which is specific to differential types of primary devices. 
If linear-meter primary devices were added to the definition, then the 
requirement in Sec.  3175.47 would have to specify that it applies only 
to differential types of primary devices, largely defeating the purpose 
of having the definition, especially considering there are no current 
or proposed API testing protocols for linear meters.
Secondary Device
    The ``secondary device'' measures the differential pressure along 
with static pressure and temperature. The ``secondary device'' consists 
of the differential-pressure, static-pressure, or temperature 
transducers in an EGM system or a mechanical recorder (including the 
differential pressure, static pressure, and temperature elements, and 
the clock, pens, pen linkages, and circular chart). The BLM did not 
receive any comments on this definition.
Tertiary Device
    In the case of an EGM system, there is also a ``tertiary device,'' 
namely, the flow computer and associated memory, calculation, and 
display functions, which calculates volume and flow rate based on data 
received from the transducers and other data programmed into the flow 
computer. The BLM did not receive any comments on this definition.
Self-Contained Versus Component-Type EGM Systems
    The rule adds definitions for ``component-type'' and ``self-
contained'' EGM systems. The distinction is necessary for the 
determination of overall measurement uncertainty. To determine overall 
measurement uncertainty under Sec.  3175.31(a), it is necessary to know 
the uncertainty, or risk of measurement error, of the transducers that 
are part of the EGM system. Therefore, the BLM needs to be able to 
identify the make, model, and upper range limit (URL) of each 
transducer because the uncertainty of the transducer varies among 
makes, models, and URLs.
    Some EGM systems are sold as a complete package, defined as a self-
contained EGM system, which includes the differential-pressure, static-
pressure, and temperature transducers, as well as the flow computer. 
The EGM package is identified by one make and model number. The BLM can 
access the performance specifications of all three transducers through 
the one model number, as long as the transducers have not been replaced 
by different makes or models. The BLM did not receive any comments on 
this definition.
    Other EGM systems are assembled using a variety of transducers and 
flow computers and cannot be identified by a single make and model 
number. Instead, the BLM would identify each transducer by its own make 
and model. These are defined as ``component'' EGM systems. Component 
systems include EGM systems that started out as self-contained systems, 
but one or more of whose transducers have been changed to a different 
make and model. The BLM did not receive any comments on this 
definition.
Hydrocarbon Dew Point
    The rule adds a definition for ``hydrocarbon dew point'' (HCDP). 
The HCDP is the temperature at which liquids begin to form within a gas 
mixture. Because it is not common to determine HCDPs for wellhead 
metering applications on Federal and Indian leases, the BLM established 
a default value using the gas temperature at the meter. By definition, 
the gas in a separator (if one is used) is in equilibrium with the 
natural gas liquids, which are at the HCDP. Cooler temperatures between 
the outlet of the separator and the primary device can result in 
condensation of heavy gas components, in which case the lower 
temperature at the primary device would still represent the HCDP at the 
primary device because the liquid and gas phases would again be in 
equilibrium. The AO may approve a different HCDP if data from an 
equation-of-state, chilled mirror, or other approved method are 
submitted. The BLM did not receive any comments on the definition of 
HCDP.
Upper and Lower Calibrated Limit
    The rule adopts the definitions of ``lower calibrated limit'' and 
``upper calibrated limit'' from the API Manual of Petroleum Measurement 
Standards (MPMS) 21.1. The upper and lower calibrated limits are the 
maximum and minimum values, respectively, for which the transducer was 
calibrated using certified test equipment. These terms replace the term 
``span'' as used in the statewide NTLs for EFCs. The BLM did not 
receive any comments on these definitions.
Redundancy Verification
    The term ``redundancy verification'' is added to address 
verifications done by comparing the readings from two sets of 
transducers installed on the same primary device. The BLM did not 
receive any comments on this definition.
FMP Categories
    The proposed rule defined four terms to describe categories of 
FMPs: ``Marginal volume,'' ``low volume,'' ``high volume,'' and ``very 
high volume.'' The BLM proposed these categories for purposes of 
delineating applicable requirements based on the average flow rate 
measured by an FMP. The proposed categories were as follows: A 
marginal-volume FMP would have had an average flow rate of 15 Mcf/day 
or less; a low-volume FMP would have had an average flow rate greater 
than 15 Mcf/day, but less than or equal to 100 Mcf/day; a high-volume 
FMP would have had an average flow rate greater than 100 Mcf/day, but 
less than or equal to 1,000 Mcf/day; and, a very-high-volume FMP would 
have had an average flow rate greater than 1,000 Mcf/day. Based on 
comments received on the proposed rule, changes in market conditions, 
and additional internal analysis, the BLM has modified two of the three 
thresholds separating the categories in the final rule. The revised 
definitions in the final rule are as follows: A very-low-volume FMP 
(marginal-volume FMP in the proposed rule) has an average flow rate of 
35 Mcf/

[[Page 81535]]

day or less; a low-volume FMP has an average flow rate greater than 35 
Mcf/day, but less than or equal to 200 Mcf/day; a high-volume FMP has 
an average flow rate greater than 200 Mcf/day, but less than or equal 
to 1,000 Mcf/day. Very-high-volume FMPs continue to have an average 
flow rate greater than 1,000 Mcf/day. Increasing the thresholds at 
which an FMP is considered low- or high-volume reduces the number of 
facilities that are in higher-volume categories, which reduces the 
overall cost of the rule, because the rule imposes stricter measurement 
requirements on higher-volume facilities.
    The proposed rule defined ``marginal-volume FMP'' as an FMP that 
measures a default volume of 15 Mcf/day or less. The BLM replaced the 
term ``marginal-volume FMP'' with ``very-low-volume FMP'' in the final 
rule to avoid confusion with other rules that use the term ``marginal 
well.'' As with the proposed rule, ``very-low-volume'' FMPs are exempt 
from many of the requirements in this rule.
    The proposed rule's 15 Mcf/day threshold for a very-low-volume FMP 
was derived by performing a discounted cash-flow analysis to account 
for the initial investment of equipment that may be required to comply 
with the proposed standards applicable to facilities classified as low-
volume FMPs. Assumptions in the discounted cash-flow model included:
     $12,000/year/well operating cost (not including 
measurement-related expense);
     Verification, orifice-plate inspection, meter-tube 
inspection, and gas sampling expenditures as would be required for a 
low-volume FMP in the proposed rule;
     A before-tax rate of return (ROR) of 15 percent;
     An exponential production-rate decline of 10 percent per 
year; and
     A 10-year equipment life.
    [GRAPHIC] [TIFF OMITTED] TR17NO16.036
    
    The model calculated the minimum initial flow rate needed to 
achieve a 15 percent ROR for various levels of investment in 
measurement equipment that would be required of a low-volume FMP. The 
ROR would be from the continued sale of produced gas that would 
otherwise be lost if the lease, unit PA, or CA were shut in. Figure 1 
shows the results of the modeling for assumed gas sales prices of $3/
MMBtu, $4/MMBtu, and $5/MMBtu.
    Both wellhead spot prices (Henry Hub) and New York Mercantile 
Exchange futures prices for natural gas averaged approximately $4/MMBtu 
for 2013 and 2014. At that time, the U.S. Energy Information 
Administration projected the price for natural gas to range between $5/
MMBtu and $10/MMBtu through the end of 2040, depending on the rate at 
which new natural gas discoveries are made and projected economic 
growth. Assuming a $4/MMBtu gas price from Figure 1, a 15 percent ROR 
could be achieved for meters with initial flow rates of at least 15 
Mcf/day, for an initial investment in metering equipment up to about 
$8,000. For wells with initial flow rates less than 15 Mcf/day, our 
analysis indicated that it may not have been profitable to invest in 
the necessary equipment to meet the proposed requirements for a low-
volume FMP. Instead, it would have been more economic for an operator 
to shut in the FMP. Therefore, 15 Mcf/day was proposed as the default 
threshold for a very-low-volume FMP, with the AO permitted to approve a 
higher threshold where circumstances warrant.
    The proposed rule would have defined ``low-volume FMP'' as an FMP 
flowing at more than 15 Mcf/day, up to 100 Mcf/day. Low-volume FMPs 
must meet minimum requirements to ensure that measurements are not 
biased, but they are exempt from the rule's minimum uncertainty 
requirements. It was anticipated that this classification in the 
proposed rule would have encompassed many FMPs, such as those 
associated with plunger-lift operations, where attainment of minimum 
uncertainty requirements would be difficult due to the high fluctuation 
of flow rate and other factors. The costs to retrofit these FMPs to 
achieve minimum uncertainty levels could be significant, although no 
economic modeling was performed at the time the proposed rule was 
written because costs were highly variable and speculative. The 
exemptions that would be granted for low-volume FMPs are similar to the 
exemptions granted for meters measuring 100 Mcf/day or less in Order 5 
and in the various statewide NTLs covering EFCs.
    The proposed rule would have defined ``high-volume FMP'' as an FMP 
flowing more than 100 Mcf/day, but not more than 1,000 Mcf/day. 
Requirements for high-volume FMPs will ensure that there is no 
statistically significant bias in the measurement and it will achieve 
an overall volume measurement of uncertainty of 3 percent 
or less and an annual average heating-value uncertainty of 2 percent. The BLM anticipates that the higher flow rates would 
make retrofitting to achieve minimum uncertainty levels more

[[Page 81536]]

economically feasible. The requirements for high-volume FMPs are 
similar to current BLM requirements as stated in the statewide NTLs for 
EFCs.
    Finally, the proposed rule would have defined ``very-high-volume 
FMP'' as an FMP flowing more than 1,000 Mcf/day. The BLM requires that 
very-high-volume FMPs achieve lower uncertainty than is required for 
high-volume FMPs (2 percent, compared to 3 
percent for volume; and 1 percent, compared to 2 percent for average annual heating value) and would have 
increased the frequency of primary device inspections and secondary 
device verifications. Stricter measurement accuracy requirements for 
very-high-volume facilities are appropriate due to the risk that 
mismeasurement will have a significant impact on royalty calculation. 
The BLM anticipates that FMPs in this class operate under relatively 
ideal flowing conditions where lower levels of uncertainty are 
achievable and the economics for making necessary retrofits are 
favorable.
    Many commenters questioned how the BLM determined the flow-rate 
ranges for the four categories of FMPs in the proposed rule (very-low-, 
low-, high-, and very-high-volume). Several of the commenters stated 
that the BLM used economics to determine the very-low-/low-volume 
threshold, but arbitrarily assigned the other thresholds. The BLM does 
not agree that the low-/high-volume and high-/very-high-volume 
thresholds in the proposed rule were ``arbitrary.'' The BLM did not 
have the same level of detail in its cost data to do the same level of 
detailed analysis on the thresholds for the higher-volume categories. 
The BLM nevertheless did consider existing thresholds in Order 5 and 
practical considerations for achieving lower uncertainties in setting 
those thresholds. Ultimately, though, the BLM determined that the cost 
estimates it had prepared were reasonable and formed a proper basis to 
set the thresholds used in the final rule. As explained elsewhere in 
this preamble, the thresholds were set at the point at which the cost 
of the additional requirements with respect to measurement equals the 
reduction in royalty risk achieved.
    One commenter recommended that the BLM should determine all three 
thresholds on a cost-benefit basis, setting the thresholds at the level 
at which the cost of required meter improvements is offset by reduced 
uncertainty as a result of making the improvement. The commenter also 
recommended that the BLM should use a 1.5-year ``payout'' methodology 
instead of the rate-of-return methodology that the BLM used in the 
proposed rule. The BLM partially agrees with these comments and 
developed a Threshold Analysis to support the thresholds used in the 
final rule (see the discussion on thresholds below and the BLM 
Threshold Analysis). The requirements in the rule for low-volume FMPs 
represent the most lenient requirements the BLM can reasonably accept 
while also meeting its fiduciary obligations to ensure royalty-quality 
measurement. The only rationale for exempting very-low-volume FMPs from 
those requirements is to reduce costs to the point that operators truly 
on the edge of profitability will not shut in production as a result of 
the rule. The threshold for very-low-volume FMPs, therefore, is the 
flow rate below which a prudent operator can no longer afford to comply 
with the requirements for a low-volume FMP and would shut in production 
if the rule did not include the additional, very-low-volume category. 
Put differently, the BLM established the very-low-/low-volume threshold 
based on the minimum flow rate at which a prudent operator could afford 
to meet the standards for a low-volume FMP.
    For the final rule, the BLM accepted the 1.5-year payout 
methodology suggested by the commenter in lieu of the rate-of-return 
methodology used in the proposed rule. Also, instead of using an 
assumed $8,000 investment required to meet the measurement standards 
for a low-volume FMP, the BLM re-examined the cost differences between 
the very-low-volume requirements and the low-volume requirements in the 
final rule. This cost difference was considered the ``investment'' in 
the payout methodology. The BLM does not agree that the reduction in 
uncertainty should be the basis for the ``income'' side of the payout 
method. While this may be useful for comparing uncertainty improvement 
as a function of cost, the BLM does not believe the overall premise is 
correct. First, the determination of uncertainty reduction between the 
very-low-volume and low-volume categories is highly speculative. 
Second, and perhaps more importantly, uncertainty indicates the risk of 
mismeasurement and does not denote whether that mismeasurement is high 
or low. The use of uncertainty to determine payout may be misleading to 
the reader who could incorrectly assume that uncertainty equates to 
under-measurement in all cases.
    Instead of using the reduction in uncertainty as the ``income,'' 
the BLM used the total income from the well(s) flowing through the FMP. 
The premise of the payout method for the very-low/low-volume threshold 
was to simulate the decision-making process of a prudent operator, 
faced with a choice of either investing the money required to meet the 
standards of a low-volume FMP or of shutting-in the well(s). In this 
scenario, the prudent operator would consider the income provided by 
the continuation of production if they were able to meet the 
requirements of a low-volume FMP. All of this income would be lost if 
the well(s) were shut in.
    The commenter recommended using the payout approach to set all of 
the thresholds. The BLM does not believe the payout approach is 
applicable to the low-/high-volume and high-/very-high-volume 
thresholds. Instead of using a payout method recommended by the 
commenter, the BLM used a royalty-risk methodology to determine the 
low-/high- and high-/very-high-volume thresholds. The BLM determined 
that it is fair and reasonable to set these thresholds for the higher-
volume facilities at the point at which the cost of the additional 
requirements equals the reduction in royalty risk due to the additional 
requirements. This approach is appropriate for high-volume facilities 
because the costs of installing additional measurement equipment at 
these facilities do not impact their economic viability, since they are 
producing at a high-enough rate that they generate significant 
revenues, well in excess of operating costs. For example, a required 
$30,000 upgrade for a meter flowing at 1,000 Mcf/day would have a 
payout of 7 days, after operating costs, royalties, and taxes, well 
below the payout range of 6 to 18 months given by the commenter. A 
prudent operator would not shut in production in this scenario.
    One commenter suggested that the BLM should incorporate the percent 
Federal or Indian ownership in the determination of flow-rate threshold 
categories. The BLM did not make any changes to the rule based on this 
comment because generally the accuracy of the FMP should be based on 
the flow rate it is measuring regardless of ownership. Implementing 
this suggestion would also be complex and cumbersome for both operators 
and the BLM. For example, a BLM inspector would have to multiply the 
average flow rate of the FMP by the Federal or Indian mineral interest 
in the agreement in order to determine which requirements the FMPs need 
to meet.
    One commenter raised a concern about an FMP that is operating just 
over one of the volume thresholds because the operator would still have 
to spend the money to comply with the threshold, but the FMP would only 
be making slightly more money than if it

[[Page 81537]]

were in the next lower category. The BLM did not make any changes to 
the rule based on this comment because this situation will arise no 
matter where the thresholds are established. The BLM may provide 
guidance to its inspectors in the enforcement handbook on how to handle 
situations in which an FMP is operating just over a threshold.
    The BLM received many comments suggesting alternative thresholds 
for the four categories of FMPs. The following table compares the Mcf/
day thresholds from the proposed rule with the alternative suggestions 
received in the comments:
[GRAPHIC] [TIFF OMITTED] TR17NO16.037

    Comments also included recommendations for removing the very-low-
volume category in its entirety and extending the requirements for low-
volume FMPs from zero Mcf/day to 100 Mcf/day. Another commenter 
suggested removing the very-high-volume category and extending the 
requirements for high-volume FMPs with no upper limit of flow rate. 
Based on all of the above comments, the BLM re-evaluated the economics 
of each category and developed new Mcf/day thresholds:
[GRAPHIC] [TIFF OMITTED] TR17NO16.038

    The study used to determine these thresholds is available on the 
regulations.gov Web site (BLM Threshold Analysis).
    One commenter stated that volume thresholds do not account for the 
fact that the economics of natural gas have changed with the Henry Hub 
wholesale price decreasing from $4 to $2/MMBtu, and therefore that the 
BLM's reliance on prices greater than $2/MMBtu is not reasonable. The 
BLM does not agree with this comment. First, natural gas prices are 
seasonal and $2/MMBtu gas is not permanent--for instance, the Henry Hub 
price can and does regularly exceed this level in response to cold 
weather under current market conditions. Second, it is unlikely that 
natural gas prices will remain at this $2/MMBtu level through the 3-
year timeframe that the Threshold Analysis uses to determine the 
minimum payout volume for the very-low-/low-volume threshold or the 10-
year timeframe that it uses to determine the low-/high-volume and high-
/very-high-volume thresholds. The Energy Information Administration's 
(EIA's) Annual Energy Outlook for 2016 \8\ reference case projects 
average nominal Henry Hub wholesale prices of $3.79/MMBtu from 2016 to 
2019, and $5.03/MMBtu from 2017 to 2026. Based on the foregoing, the 
BLM did not make any changes to the rule based on this comment.
---------------------------------------------------------------------------

    \8\ U.S., Energy Information Administration, Annual Energy 
Outlook 2016, available at https://www.eia.gov/forecasts/aeo/.
---------------------------------------------------------------------------

Determining the FMP Flow Rate Category
    In the proposed rule, the BLM would have determined the FMP 
category by averaging the flow rate of that FMP over the previous 12 
months or the life of the FMP, whichever was shorter. The BLM received 
several comments expressing concern about the proposed 12-month 
averaging period for FMPs that measure the flow rate from wells having 
high production-decline rates. Several of the commenters stated that as 
a result of the proposed 12-month averaging period, the operator would 
have to invest a lot of money to achieve the requirements for a high or 
very-high-volume FMP, only to have the volume drop to low- or even 
very-low-volume in a short period of time. One commenter recommended 
that the BLM should not include the first month of production in the 
average flow rate calculation.
    The BLM agrees with the concept presented by the commenters and 
developed a definition for ``averaging period'' that applies to the 
category definitions in this rule and the uncertainty thresholds in the 
oil measurement rule (43 CFR subpart 3174). The definition, which 
appears in the subpart 3170 definitions section, retains a 12-month 
averaging period, but excludes any production from newly drilled wells 
prior to the second full month of production from the average 
calculation. In other words, if an FMP is installed to measure the 
production from a newly drilled well, and the well is put into 
production on May 10, the production reported in May and June would not 
be used in the calculation of average flow rate when determining the 
FMP's flow-rate category. In this example, May is not a full month of 
production; therefore, June is the first full month of production and 
July is the second full month of production. The 12-month averaging 
period starts with the July production figures.
    The BLM received numerous comments asking for clarification on how 
an operator would determine the flow-rate category of an FMP. Some of 
the comments expressed confusion over the time period that the BLM 
would use to determine the average flow rate; whether this would be a 
12-month average, a 6-month average, a daily rate, or based on 
previous-day flow rate available on the display of an EGM system. One 
commenter requested clarification on how an operator would determine 
the category if there were less than 12 months of data. The category 
definitions in the proposed rule and the new definition of ``averaging 
period'' in the final rule both specify that the average is taken over 
12 months or the life of the FMP, whichever is shorter. The BLM did not 
make any further changes to the rule based on these comments. The BLM 
believes that the requirement for how the BLM will

[[Page 81538]]

determine average flow rate is sufficiently clear under the definition 
of ``averaging period'' in subpart 3170.
Bias
    The proposed rule defined ``bias'' as a shift in the mean value of 
a set of measurements away from the true value of what is being 
measured. In the final rule the BLM changed the word ``shift'' to 
``systematic shift'' to better match other statistical definitions. The 
word ``systematic'' was also added to stress that bias is present if a 
shift in mean value occurs even after averaging repeated measurements 
of the value across the entire measurement system.
    One commenter stated that the term ``bias'' as used in the proposed 
rule implies that the operator is intentionally causing a meter to read 
high or low. The BLM did not make any changes to the rule based on this 
comment because neither the definition nor the use of the word ``bias'' 
in the rule implies that any bias is intentional. ``Bias'' is a term of 
art in the measurement context and does not refer to underlying intent.
Uncertainty
    The proposed rule did not define the term ``uncertainty'' and used 
both the terms ``certainty'' and ``uncertainty'' interchangeably. One 
commenter stated that there is no definition of ``certainty'' or 
``uncertainty'' in proposed Sec.  3175.10. Based on this comment the 
BLM used only the term ``uncertainty'' in the final rule, and included 
a definition for that term. The BLM made this change because 
``uncertainty,'' unlike the term ``certainty,'' is a term that is 
commonly used and understood within the oil and gas measurement 
context. ``Uncertainty'' is defined to mean the range of error that 
could occur between a measured value and the true value being measured, 
calculated at a 95 percent confidence level. The BLM selected a 95 
percent confidence level because it is commonly used in oil and gas 
measurement. A 95 percent confidence level means that the calculated 
uncertainty indicates the maximum amount of error that is expected to 
occur between the measured value and the true value being measured 95 
percent of the time. There is a 5 percent chance that the risk of 
mismeasurement is greater than the calculated uncertainty.
Significant Digit
    The proposed rule defined ``significant digit'' as any digit of a 
number that is known with certainty. The definition was included in the 
proposed rule to support Sec.  3175.104(a)(2), which required certain 
data in the QTR to be reported to five significant digits. Based on 
comments received, the requirement in the final rule was changed from 
five significant digits to a specified number of decimal places. 
Therefore, the definition of ``significant digit'' is no longer 
necessary and is deleted in the final rule.
Statistically Significant and Threshold of Significance
    Section 3175.10 of the proposed rule included definitions for 
``statistically significant'' and ``threshold of significance.'' 
Because the final oil measurement rule (43 CFR subpart 3174) also uses 
these terms, the BLM moved the definitions to subpart 3170. The BLM did 
not make any changes to the definitions.
Heating Value Variability
    The BLM added a definition of ``heating value variability'' to the 
final rule in response to numerous comments expressing confusion over 
what this term means and how the BLM would determine it. These comments 
are discussed under Sec.  3175.31(b).
Other Definitions
    The BLM added a definition for ``AGA Report No. (followed by a 
number)'' to the final rule to be consistent with the definitions for 
GPA and API that pertain to standards incorporated by reference (see 
Sec.  3175.30). The proposed rule did not incorporate any AGA (American 
Gas Association) standards; however, the final rule incorporates two 
AGA standards (AGA Report No. 3 (1985) and AGA Report No. 8 (1992)). As 
explained elsewhere in the preamble, the BLM incorporated standards 
from AGA Report No. 3 because the final rule includes grandfathering 
provisions (see Sec.  3175.61) relating to meter tube construction that 
allow operators of grandfathered meters to meet the older standards in 
lieu of the latest API standards. AGA Report No. 8 was adopted because 
the BLM determined it was the more appropriate reference for the 
calculation of supercompressibility. In the proposed rule, the 
incorporation by reference was for API 14.2; both standards are 
identical in content.
    There are numerous other terms that were defined in both the 
proposed rule and the final rule. These include, ``as-found,'' ``as-
left,'' ``atmospheric pressure,'' ``Beta ratio,'' ``British thermal 
unit,'' ``configuration log,'' ``discharge coefficient,'' ``effective 
date of a spot or composite sample,'' ``electronic gas measurement,'' 
``element range,'' ``event log,'' ``heating value,'' ``integration,'' 
``live input variable,'' ``mean,'' ``mole percent,'' ``normal flowing 
point,'' ``quantity transaction record,'' ``Reynolds number,'' ``senior 
fitting,'' ``standard cubic foot (scf),'' ``standard deviation,'' 
``transducer,'' ``turndown,'' ``type test,'' ``upper range limit 
(URL),'' and ``verification.'' The BLM did not receive any comments on 
these definitions and did not change any of these definitions from the 
proposed rule. One commenter stated that there is no definition of 
``AO,'' ``FMP,'' ``PA,'' ``PMT,'' or ``uncertainty'' in proposed Sec.  
3175.10. The terms ``AO,'' ``FMP,'' ``PA,'' and ``PMT'' are defined 
under subpart 3170 because they apply to all the rules published under 
that part including subparts 3173, 3174, and 3175. Therefore, those 
definitions were not added to subpart 3175 in the final rule
Sec.  3175.20--General Requirements
    Proposed Sec.  3175.20 would have required measurement of all gas 
removed or sold from Federal or Indian leases and unit PAs or CAs that 
include one or more Federal or Indian leases to comply with the 
standards of the proposed rule (unless the BLM grants a variance under 
proposed Sec.  3170.6). The BLM received a comment suggesting the 
requirements of Sec.  3175 should only apply to those units or 
agreements above a set percentage of Federal interest. The BLM 
disagrees for the reasons discussed under the definition of the flow-
rate categories and did not make any changes to this section based on 
this comment.
    The BLM received another comment objecting to the proposed 
requirement to measure all gas on leases, pointing out that many times 
leases are part of units or CAs, and may have combined measurement 
points for multiple leases within these agreements. The BLM believes 
the commenter has misinterpreted the requirement. The final rule 
requires all gas removed or sold from Federal and Indian leases, unit 
PAs, or CAs to comply with 43 CFR subpart 3175. If a lease is part of a 
unit PA or CA, the measurement requirements in subpart 3175 apply only 
to the FMP where gas is removed or sold from the unit PA or CA. This is 
because the BLM considers unit PAs and CAs to be individual cases--
comparable to large ``leases''--with regards to measurement. As a 
result, operators do not have to measure the gas produced from 
individual leases within a CA or unit PA. Internal measurement points, 
such as those flagged by the commenter, that combine production from 
individual leases or wells within a CA or unit PA are not subject to 
this subpart, assuming they are not used to measure gas that is removed 
or sold

[[Page 81539]]

from the unit PA or CA for purposes of royalty determinations. The BLM 
did not make any changes to the final rule based on this comment.
    The BLM did make a change to this section based on an internal 
review of the wording in the proposed rule. The proposed rule stated 
that ``Measurement of all gas removed or sold from Federal and Indian 
leases and unit PAs or CAs that include one or more Federal or Indian 
leases, must comply with the standards prescribed in this subpart, 
except as otherwise approved under Sec.  3170.6 of this subpart.'' The 
BLM realized that this language does not account for situations where 
the BLM has granted commingling and allocation approval (CAA) under 43 
CFR part 3173. Where the BLM has granted a CAA, the allocation meters 
are not considered FMPs and, therefore, do not have to comply with the 
requirements of this rule (see the definition of FMP under subpart 
3173). As a result, gas will be removed or sold from the lease, unit 
PA, or CA without being measured in accordance with the standards in 
this rule, which is contrary to the language of the proposed rule. To 
address this, the BLM changed the wording of this sentence to 
``Measurement of all gas at an FMP must comply with the standards of 
this subpart . . . . '' It should be noted that if a gas allocation 
meter were to become an FMP in the future, it would have to comply with 
the applicable requirements of this rule.
Sec.  3175.30--Incorporation by Reference
    This section previously appeared as Sec.  3175.31 in the proposed 
rule, but based on edits made to the final rule, this section and final 
Sec.  3175.30 have swapped places.
    This final rule incorporates a number of industry standards, either 
in whole or in part, without republishing the standards in their 
entirety in the CFR, a practice known as incorporation by reference. 
These standards were developed through a consensus process, facilitated 
by the American Petroleum Institute (API), the American Gas Association 
(AGA), the Gas Processors Association (GPA), and the Pipeline Research 
Council International (PRCI) with input from the oil and gas industry 
and Federal agencies with oil and gas operational oversight 
responsibilities.
    The BLM has reviewed these standards and determined that they will 
achieve the intent of Sec. Sec.  3175.31 through 3175.125 of this rule. 
The legal effect of incorporation by reference is that the incorporated 
standards become regulatory requirements. With the approval of the 
Director of the Federal Register, this rule generally incorporates the 
current versions of the standards listed below. However, the BLM is 
also incorporating older versions of several standards due to the 
``grandfathering'' of some existing equipment in the final rule
    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.  3175.31 of the rule, or 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 (4)). The language of 
incorporation in 43 CFR 3175.30 meets the requirements of 1 CFR 51.9. 
Where appropriate, the BLM has incorporated industry standards 
governing a particular process by reference and then imposes 
requirements that are in addition 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, AGA, GPA, and PRCI 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 also 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 GPA materials are 
available for inspection at the GPA, 6526 E. 60th Street, Tulsa, OK 
74145; telephone 918-493-3872; https://gpsa.gpaglobal.org/. The AGA 
materials are available for inspection at the AGA, 400 North Capitol 
Street NW., Suite 450, Washington, DC 20001; telephone 202-824-7000. 
The PRCI material is available for inspection at the PRCI, 3141 
Fairview Park Dr., Suite 525, Falls Church, VA 22042; telephone 703-
205-1600.
    The following describes the API, GPA, APA, and PRCI standards that 
the BLM is incorporating by reference into this rule:
     API Manual of Petroleum Measurement Standards (MPMS) 
Chapter 14--Natural Gas Fluids Measurement, Section 1, Collecting and 
Handling of Natural Gas Samples for Custody Transfer; Seventh Edition, 
May, 2016 (``API 14.1''). This standard provides comprehensive 
guidelines for properly collecting, conditioning, and handling 
representative samples of natural gas that are at or above their 
hydrocarbon dew point.
     API MPMS Chapter 14, Section 3, Orifice Metering of 
Natural Gas and Other Related Hydrocarbon Fluids--Concentric, Square-
edged Orifice Meters, Part 1, General Equations and Uncertainty 
Guidelines; Fourth Edition, September 2012; Errata, July 2013 (``API 
14.3.1''). This standard provides engineering equations and uncertainty 
estimations for the calculation of flow rate through concentric, 
square-edged, flange-tapped orifice meters.
     API MPMS Chapter 14, Section 3, Orifice Metering of 
Natural Gas and Other Related Hydrocarbon Fluids--Concentric, Square-
edged Orifice Meters, Part 2, Specification and Installation 
Requirements; Fifth Edition, March 2016 (``API 14.3.2''). This standard 
provides construction and installation requirements, and standardized 
implementation recommendations for the calculation of flow rate through 
concentric, square-edged, flange-tapped orifice meters.
     API MPMS Chapter 14, Section 3, Orifice Metering of 
Natural Gas and Other Related Hydrocarbon Fluids--Concentric, Square-
edged Orifice Meters, Part 3, Natural Gas Applications; Fourth Edition, 
November 2013 (``API 14.3.3''). This standard is an application guide 
for the calculation of natural gas flow through a flange-tapped, 
concentric orifice meter.
     API MPMS Chapter 14, Natural Gas Fluids Measurement, 
Section 3, Concentric, Square-Edged Orifice Meters, Part 3, Natural Gas 
Applications, Third Edition, August 1992 (``API 14.3.3 (1992)''). This 
standard is an application guide for the calculation of natural gas 
flow through a flange-tapped, concentric orifice meter.
     API MPMS, Chapter 14, Section 5, Calculation of Gross 
Heating Value, Relative Density, Compressibility and Theoretical 
Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody 
Transfer; Third Edition, January 2009; Reaffirmed February 2014 (``API 
14.5''). This standard presents procedures for calculating, at base 
conditions from composition, the

[[Page 81540]]

following properties of natural gas mixtures: Gross heating value, 
relative density (real and ideal), compressibility factor, and 
theoretical hydrocarbon liquid content.
     API MPMS Chapter 21, Section 1, Flow Measurement Using 
Electronic Metering Systems--Electronic Gas Measurement; Second 
Edition, February 2013 (``API 21.1''). This standard describes the 
minimum specifications for electronic gas measurement systems used in 
the measurement and recording of flow parameters of gaseous phase 
hydrocarbon and other related fluids for custody transfer applications 
utilizing industry recognized primary measurement devices.
     API MPMS Chapter 22--Testing Protocol, Section 2, 
Differential Pressure Flow Measurement Devices; First Edition, August 
2005; Reaffirmed August 2012 (``API 22.2''). This standard is a testing 
protocol for any flow meter operating on the principle of a local 
change in flow velocity, caused by the meter geometry, giving a 
corresponding change of pressure between two reference locations.
     GPA Standard 2166-05, Obtaining Natural Gas Samples for 
Analysis by Gas Chromatography; Adopted as a Tentative Standard, 1966; 
Revised and Adopted as a Standard, 1968; Revised 1986, 2005 (``GPA 
2166-05''). This standard recommends procedures for obtaining samples 
from flowing natural gas streams that represent the compositions of the 
vapor phase portion of the system being analyzed.
     GPA Standard 2261-13, Analysis for Natural Gas and Similar 
Gaseous Mixtures by Gas Chromatography; Adopted as a Tentative 
Standard, 1961; Revised and Adopted as a Standard, 1964; Revised 1972, 
1986, 1989, 1990, 1995, 1999, 2000 and 2013 (``GPA 2261-13''). This 
standard establishes a method to determine the chemical composition of 
natural gas and similar gaseous mixtures within set ranges using a gas 
chromatograph (GC).
     GPA Standard 2198-03, Selection, Preparation, Validation, 
Care and Storage of Natural Gas and Natural Gas Liquids Reference 
Standard Blends; Adopted 1998; Revised 2003. (``GPA 2198-03''). This 
standard establishes procedures for selecting the proper natural gas 
and natural gas liquids reference standards, preparing the standards 
for use, verifying the accuracy of composition as reported by the 
manufacturer, and the proper care and storage of those standards to 
ensure their integrity as long as they are in use.
     GPA Standard 2286-14, Method for the Extended Analysis of 
Natural Gas and Similar Gaseous Mixtures by Temperature Program Gas 
Chromatography; Adopted as a Standard 1995; Revised 2014 (``GPA 2286-
14''). This method is intended for the compositional analysis of 
natural gas and similar gaseous mixtures where precise physical 
property data of the hexanes and heavier fractions are required. The 
procedure is applicable for mixtures which may contain components of 
nitrogen, carbon dioxide, and/or hydrocarbon compounds C1-C14.
     AGA Report No. 3, Orifice Metering of Natural Gas and 
Other Related Hydrocarbon Fluids Second Edition, September 1985 (``AGA 
Report No. 3 (1985)''). This standard provides construction and 
installation requirements, and standardized implementation 
recommendations for the calculation of flow rate through concentric, 
square-edged, flange-tapped orifice meters.
     AGA Report No. 8, Compressibility Factors of Natural Gas 
and Other Related Hydrocarbon Gases; Second Edition, November 1992 
(``AGA Report No. 8''). This standard presents detailed information for 
precise computations of compressibility factors and densities of 
natural gas and other hydrocarbon gases, calculation uncertainty 
estimations, and FORTRAN computer program listings.
     PRCI NX 19, Manual for the Determination of 
Supercompressibility Factors for Natural Gas; December 1962 (``PRCI NX 
19''). This standard presents detailed information for computations of 
compressibility factors and densities of natural gas and other 
hydrocarbon gases.
    Several commenters suggested that the BLM should adopt API and GPA 
standards in their entirety rather than incorporating only parts of 
them. Some of the commenters stated that the BLM should incorporate all 
of API MPMS Chapter 1 (Terms and Definitions), all of Chapter 14 
(Natural Gas Fluids Measurement), all of Chapter 21 (Flow Measurement 
Using Electronic Metering Systems), and all of Chapter 22 (Testing 
Protocols).
    The BLM did not make any changes as a result of these comments. The 
rule incorporates five industry standards in whole and seven industry 
standards in part. API and GPA standards are written for industry to 
use as guidelines in designing and operating measurement facilities, 
generally for custody-transfer applications, were not designed for the 
regulatory environment, and present potential enforcement challenges 
and limitations. As such, these standards are often difficult to adopt 
without modification as regulations. The BLM can only enforce 
requirements that are objective, clearly defined, and relevant to the 
BLM's goal of ensuring accurate and verifiable measurement. Many of the 
API and GPA standards referenced by the commenters do not meet this 
threshold. For example, API 21.1, Section 6, sets standards for data 
availability. API 21.1, Subsection 6.2, requires, among other things, 
that onsite data include at least 7 days of hourly QTRs. While this may 
be a useful requirement for industry, the BLM is not concerned in this 
rule with how long data are maintained onsite. The FOGRMA of 1982 (as 
amended by the Royalty Simplification and Fairness Act of 1996) 
requires all records for Federal leases to be maintained for a period 
of 7 years from the date they are generated. Whether they are 
maintained onsite or offsite is irrelevant to the BLM's goals. In 
addition, it would be very difficult for BLM inspectors to enforce such 
a provision and it would serve no purpose for them to do so.
    The following table lists the API standards that the commenters 
suggested the BLM should adopt and our response.

[[Page 81541]]

[GRAPHIC] [TIFF OMITTED] TR17NO16.039


[[Page 81542]]


[GRAPHIC] [TIFF OMITTED] TR17NO16.040

    Of the 22 standards in Chapters 1, 14, 21, and 22 that the 
commenters recommended for incorporation, the BLM is incorporating 
eight standards. Two of the remaining standards have not yet been 
published by API, four apply only to liquid measurement, and two are 
for informational uses only. The BLM did not incorporate the remaining 
six recommended standards because they are not relevant to royalty 
measurement, were not published in time to include in the final rule, 
or the BLM determined that they either had the potential to conflict 
with BLM requirements or did not help achieve the purposes of the rule 
or the underlying legal requirements.
    One commenter stated that API 14.1 and GPA 2166 are clear and 
enforceable as written and should be incorporated in whole. The rule 
incorporates portions of these two standards. While there are portions 
of API 14.1 and GPA 2166 that are clear and enforceable as written, 
many parts of these standards are not. For example, API Chapter 14.1, 
Subsection 6.3.2.1 states: ``Sample distortion due to chemical and 
physical adsorption can be minimized by prudent selection of sampling 
system materials. In general, materials and coatings that are 
chemically inert and of minimum porosity are the best choices.'' While 
this statement has important educational value, it would be virtually 
impossible for a BLM inspector to ascertain whether a sampling system 
material is in accordance with the standard or to take an enforcement 
action against an operator for not making a ``best choice.'' The BLM 
did not make any changes to the rule based on this comment.
    Several commenters suggested that the BLM should automatically 
incorporate the latest version of a standard rather than specifying a 
year and edition of the standard. The BLM did not make any changes to 
the rule based on these comments. To promulgate a rule, all Federal 
agencies must follow the APA, which establishes specific requirements 
for Federal agencies to follow. In general, the agency must provide 
notice to the

[[Page 81543]]

public that a new rule is under consideration, publish a draft of the 
rule in the Federal Register, and provide the public an opportunity to 
comment on the proposed rule (see 5 U.S.C. 553). When the BLM 
incorporates a standard by reference, the standard becomes part of the 
rule in which it is incorporated.
    If the rule were structured to incorporate ``the latest version'' 
of a particular standard, the requirements of the rule would 
automatically change whenever a particular standard is updated in the 
future. Changing a substantive rule in this manner, without the 
opportunity for public input, would be inconsistent with the notice-
and-comment requirements of the APA, and therefore would not be legally 
permissible. The BLM will, however, evaluate new standards as they are 
issued by API, GPA, and others, and will determine if it is appropriate 
to initiate a rulemaking process to update the reference in subpart 
3175 to incorporate the then-current version of those standards. In the 
interim, an operator could request a variance to follow the more recent 
version of a particular standard in lieu of the one incorporated by 
reference in this rule. Such requests would be evaluated by the PMT as 
outlined in this rule.
    Several commenters suggested incorporating the latest version of 
GPA 2261-13, instead of GPA 2261-00. The BLM agrees with this comment 
and has changed the incorporation by reference to refer to the latest 
version of this standard. See the portion of the preamble that 
describes Sec.  3175.118 for further discussion of these comments.
    Several commenters suggested incorporating GPA 2286-14, relating to 
taking extended analyses. The BLM agrees with this comment and 
incorporated this standard by reference because Sec.  3175.119(b) 
requires operators to do extended analyses in some instances. See the 
portion of the preamble that discusses Sec.  3175.117 for further 
discussion of these comments.
    As discussed in connection with Sec.  3175.10, the BLM did 
incorporate two AGA standards in the final rule: AGA Report No. 3 
(1985) and AGA Report No. 8. The BLM incorporated AGA Report No. 3 
because the final rule includes meter tube construction standards for 
certain grandfathered facilities (see Sec.  3175.61) in lieu of the 
latest standards in API 14.3.2. The BLM also changed the incorporation 
by reference for the calculation of supercompressibility. In the 
proposed rule the incorporation by reference was for API 14.2; however, 
this was changed to AGA Report No. 8 in the final rule because the BLM 
determined this was a more appropriate reference. Both standards are 
identical in content.
Sec.  3175.31--Specific Performance Requirements
    Note that the performance requirements appeared under Sec.  3175.30 
in the proposed rule. In the final rule, the BLM switched the 
provisions in Sec. Sec.  3175.30 and 3175.31 for formatting purposes.
    Section 3175.31 sets overall performance standards for measuring 
gas produced from Federal and Indian leases, regardless of the type of 
technology used. The performance standards provide specific objective 
criteria that the BLM can use to analyze meter systems not specifically 
allowed under the final rule. The performance standards also form the 
basis of determining the individual equipment standards that apply to 
each flow-rate class of meter (i.e., very-low, low, high, and very-high 
volume).
    Section 3175.31(a) establishes limits on the maximum allowable 
flow-rate measurement uncertainty. Uncertainty indicates the risk of 
measurement error. For high-volume FMPs (flow rate greater than 200 
Mcf/day, but less than or equal to 1,000 Mcf/day), the maximum allowed 
overall flow-rate measurement uncertainty is 3 percent. For 
very-high-volume FMPs (flow rate of more than 1,000 Mcf/day), the 
maximum allowable flow-rate uncertainty is reduced to 2 
percent, because uncertainty in higher-volume meters presents greater 
royalty risks than in lower-volume meters. In addition, upgrades 
necessary to achieve an uncertainty of 2 percent for very-
high-volume FMPs will be more economical given these FMPs' higher 
overall production levels. Not only do the higher flow rates make these 
necessary upgrades more economical, many of the measurement uncertainty 
problems associated with lower-volume FMPs, such as intermittent flow, 
are not as prevalent with higher-volume FMPs.
    The 3 percent uncertainty requirement for high-volume 
FMPs is the same as what is currently required in all of the statewide 
NTLs for EFCs. However, the 3 percent uncertainty 
requirement in the statewide NTLs applies to all FMPs measuring more 
than 100 Mcf/day. Section 3175.31(a), by contrast, applies only to 
high- (3 percent) and very-high- (2 percent) 
volume FMPs. Under the new rule, therefore, meters measuring between 
100 Mcf/day and 200 Mcf/day are no longer required to meet an 
uncertainty standard. Consistent with the existing requirements of the 
statewide NTLs, meters measuring less than 100 Mcf/day are not subject 
to uncertainty requirements.
    Section 3175.31(a)(3) specifies the conditions under which flow-
rate uncertainty must be calculated. Flow-rate uncertainty is a 
function of the uncertainty of each variable used to determine flow 
rate. The uncertainty of variables such as differential pressure, 
static pressure, and temperature is dynamic and depends on the 
magnitude of the variables at a point in time. This section lists two 
sources of data to use for uncertainty determinations. The best data 
source for average flowing conditions at the FMP would be the monthly 
averages typically available from a daily QTR. However, daily QTRs are 
not usually readily available to the AO at the time of inspection 
because they must usually be requested by the BLM and provided by the 
operator ahead of time. If the daily QTR is not available to the AO, 
the next best source for uncertainty determinations would be the 
average flowing parameters from the previous day, which will be 
required under Sec.  3175.101(b)(4)(i) through (iii) of this final rule 
(Sec.  3175.101(b)(4)(i) through (iv) of the proposed rule).
    The BLM received numerous comments on this section. One commenter 
stated that the new performance requirements would cause wells to be 
shut in, although no support for that claim was included in the 
comment. The BLM conducted a detailed economic analysis to support the 
new flow category thresholds discussed under proposed Sec.  3175.10, 
which included the costs of any upgrades necessary to meet the new 
uncertainty requirements (see the BLM Threshold Analysis). The flow-
rate uncertainty of 3 percent for high-volume FMPs is 
actually less restrictive than the current uncertainty requirement in 
the statewide NTLs for EFCs. The NTLs require an overall uncertainty of 
3 percent or better for all meters measuring more than 100 
Mcf/day. The final rule expands that limit to 200 Mcf/day. Therefore, 
FMPs measuring between 100 Mcf/day and 200 Mcf/day, which would have 
been subject to the 3 percent uncertainty limit under the 
statewide NTLs, are now exempt from any uncertainty requirement. The 
new uncertainty limit of 2 percent for very-high-volume 
FMPs is only required for FMPs measuring more than 1,000 Mcf/day, which 
applies to just over 1 percent of all FMPs, according to data 
maintained by the BLM about current production. The BLM believes that a 
2 percent uncertainty will not be difficult to achieve on 
very-high-volume FMPs because the flow tends to be more stable

[[Page 81544]]

and contain fewer liquids for wells producing at those levels. 
Additionally, for very-high-volume FMPs, any costs associated with 
achieving a 2 percent uncertainty versus a 3 
percent uncertainty, such as the purchase of a new transducer, should 
not be significant given the overall magnitude of production. The BLM 
did not make any changes to the rule as a result of these comments.
    Several commenters expressed a concern that reduced uncertainty 
will not necessarily increase revenue or royalty. Uncertainty is the 
risk of mismeasurement, and the goal of reducing uncertainty is to 
reduce that risk regardless of whether the end result is greater 
royalty, less royalty, or no change in royalty. Reducing the risk of 
mismeasurement ensures that the measurement is more accurate, which is 
one of the primary goals of this rule. As reflected in other provisions 
of this rule, the BLM has developed measurement standards that impose 
uncertainty requirements commensurate with the royalty risk posed by a 
particular facility. For these reasons, no changes to the rule were 
made.
    One commenter stated that any increase in transportation costs, 
such as meter upgrades, would increase transportation allowances under 
the ONRR valuation regulations, thereby reducing royalty. The BLM has 
confirmed with ONRR that there are no circumstances under which an 
operator can claim expenses relating to measurement as a transportation 
allowance. The BLM did not make any changes to the rule based on this 
comment.
    The BLM received several comments objecting to what they said is a 
lack of justification for the uncertainty limits in the proposed rule. 
The BLM does not agree with these comments. The preamble to the 
proposed rule provided a detailed explanation of how the BLM developed 
the uncertainty limits and why they were developed. The BLM did not 
make any changes to the final rule based on these comments.
    The BLM will enforce flow-rate measurement uncertainty using 
standard calculations such as those found in API 14.3.1, which are 
incorporated into the BLM uncertainty calculator (www.wy.blm.gov), or 
other methods approved by the AO. BLM employees use the uncertainty 
calculator to determine the uncertainty of meters that are used in the 
field. However, existing and previous versions of the uncertainty 
calculator do not account for the effects of relative density 
uncertainty because these effects have not been quantified. The gas 
analysis data required in Sec.  3175.120(e) and (f) of the final rule 
allow the BLM to quantify the relative density uncertainty by 
performing a statistical analysis of historical relative density 
variability and including it in the determination of overall 
measurement uncertainty, making these uncertainty calculations more 
robust.
    The BLM received numerous comments stating that the BLM has not 
published the calculations used in the BLM uncertainty calculator, 
making it difficult to comment on the uncertainty calculation. The BLM 
disagrees with this comment. A user's manual and detailed description 
of every calculation used in the uncertainty calculator has been posted 
on both the BLM Web site (www.blm.gov/wy) and the Colorado Engineering 
and Experiment Station, Inc. Web site since December 2009. These are 
the only Web sites from which the BLM uncertainty calculator can be 
downloaded, and the link to download the documentation is immediately 
adjacent to the link to download the calculator. One commenter stated 
that these calculations must be published before mandating the use of 
the calculator. Neither the proposed rule nor the final rule mandates 
the use of the BLM uncertainty calculator. As discussed in the 
preamble, the BLM uncertainty calculator is a method by which BLM 
inspectors could enforce the uncertainty requirements; however, the 
calculator is not referred to anywhere in the regulation itself. The 
BLM did not make any changes to the rule in response to these comments.
    The BLM received several comments stating that the BLM should have 
published the uncertainty calculations in the proposed rule and asked 
for clarification of what those calculations would be. The BLM agrees 
with this comment and incorporated by reference API 14.3.1, Section 12, 
which includes the uncertainty calculations that the BLM accepts and 
uses in the BLM uncertainty calculator. Section 3175.31(a)(4) was added 
to the final rule to reference the uncertainty calculations in API 
14.3.1, Section 12.
    Section 3175.31(b) establishes an uncertainty requirement for the 
measurement of heating value. This was included because both heating 
value and volume directly affect royalty calculation if gas is sold at 
arm's length on the basis of a per-MMBtu price. Virtually all of the 
gas sold domestically in the United States is priced on a $/MMBtu 
basis. The royalty is computed by the following equation:

R = V x HV x P x Rr,

Where:

R = royalty owed, $;
V = volume of gas removed or sold from a lease, Mcf;
HV = heating value, MMBtu/Mcf;
P = gas value, $/MMBtu; and
Rr = royalty rate.

    Thus, a 5 percent error in heating value would result in the same 
error in royalty as a 5 percent error in volume measurement.
    The BLM recognizes that the heating value determined from a spot 
sample only represents a snapshot in time, and the actual heating value 
at any point after the sample was taken may be different. The probable 
difference is a function of the degree of variability in heating values 
determined from previous samples. If, for example, the previous heating 
values for a meter are very consistent, then the BLM would expect that 
the difference between the heating value based on a spot sample and the 
actual heating value at any given time after the spot sample was taken 
would be relatively small. The opposite would be true if the previous 
heating values had a wide range of variability. Therefore, the 
uncertainty of the heating value calculated from spot sampling will be 
determined by performing a statistical analysis of the historical 
variability of heating values over the past year for high- and very-
high-volume FMPs. If an operator installs a composite sampling system 
or an on-line GC, the BLM will consider that device as having met the 
heating-value uncertainty requirements of this section.
    The uncertainty limits for heating value are based on the 
annualized cost of spot sampling and analysis as compared to the 
royalty risk from the resulting heating-value uncertainty. The BLM used 
the data collected for the Gas Variability Study (see the discussion of 
Sec.  3175.115 below) as the basis of this analysis. For high-volume 
FMPs, the BLM determined that the cost to industry of achieving an 
average annual heating-value uncertainty of 2 percent by 
using spot sampling methods would approximately equal the royalty risk 
resulting from the same 2 percent uncertainty in the 
heating value. For very-high-volume FMPs, an average annual heating-
value uncertainty of 1 percent would result in a cost to 
industry that is approximately equal to the royalty risk of the 
uncertainty. The rule therefore prescribes these respective levels as 
the allowed average annual heating-value uncertainty for high- and 
very-high-volume FMPs.
    The BLM received numerous comments on this section stating that the 
new performance requirements

[[Page 81545]]

would cause wells to be shut in, although no support for that claim was 
included in the comments. As with the volume uncertainties, the 
required heating-value uncertainties will only apply to FMPs measuring 
more than 200 Mcf/day. The BLM did not receive any data supporting the 
argument that meeting an average annual heating-value uncertainty of 
2 percent (high volume) or 1 percent (very-high 
volume) would be so costly that an operator would shut in the well(s) 
flowing through the meter rather than complying with this requirement. 
Under the worst-case scenario for high-volume FMPs, where the heating 
value from the FMP is highly erratic from sample to sample, the maximum 
cost to the operator would be to take spot samples every 2 weeks, which 
represents a relaxation of requirements in the proposed rule that would 
have required weekly samples. The BLM Threshold Analysis included the 
cost of bi-weekly sampling in the determination of an appropriate 
threshold for the low-/high-volume categories. For very-high-volume 
FMPs, the worst-case scenario would require an operator to install a 
composite sampling system. The proposed rule would have also required 
on-line GCs or composite samplers for high-volume FMPs. The BLM 
Threshold Analysis includes this cost to determine the high-/very-high-
volume threshold. The costs to comply with the heating-value 
uncertainties are not significant enough that a prudent operator would 
opt to shut in the well(s) flowing through FMPs producing at that 
level. Also, the operator has other means to reduce the heating-value 
variability from sample to sample, such as employing quality control 
measures in sampling and analysis.
    Several commenters stated that there is no reason the heating-value 
uncertainty limits should be more restrictive than the flow-rate 
uncertainty limits. For flow rate, an uncertainty of 3 
percent for high-volume FMPs and 2 percent for very-high-
volume FMPs is required. For heating value, an average annual 
uncertainty of 2 percent uncertainty for high-volume FMPs 
and 1 percent uncertainty for very-high-volume FMPs is 
required. As described in the preamble and in the BLM Threshold 
Analysis, the BLM determined the uncertainties for volume and heating 
value separately based on cost of compliance versus royalty risk 
resulting from the uncertainty requirement. For example, the flow-rate 
uncertainty and costs associated with achieving that uncertainty are 
dependent on the size, quality, configuration, and operation of the 
primary, secondary, and tertiary devices. For heating value, the 
uncertainty and costs associated with achieving that uncertainty are a 
function of the heating-value variability and sampling frequency or 
sampling method (i.e., composite versus spot). Because the determinants 
of flow-rate uncertainty and heating-value uncertainty are independent, 
the costs of achieving specified uncertainty levels are also 
independent. As a result, the uncertainty limits for volume and heating 
value were set independently based on the results of the BLM Threshold 
Analysis. Generally, flow-rate uncertainty targets are more difficult 
and expensive to achieve than uncertainty targets for average annual 
heating value. For example, an average annual heating-value uncertainty 
of 1 percent is achievable in most cases by simply 
increasing the sample frequency, which typically costs a few hundred 
dollars per year. By contrast, achieving a volume uncertainty of 1 percent would, in most cases, require operators to purchase the 
most expensive transducers available and install separation and other 
equipment that would maintain a very consistent flow rate. This could 
cost tens of thousands of dollars or more. The BLM did not make any 
changes to the final rule based on these comments.
    The BLM received several comments suggesting other uncertainty 
limits from those listed in the proposed rule. One commenter suggested 
that both the flow rate and heating-value uncertainties should be 
reduced to 1 percent for high- and very-high-volume FMPs 
and an uncertainty requirement of 5 percent should be added 
for very-low and low-volume FMPs. Another commenter suggested that the 
heating-value uncertainty should be 7.5 percent when the 
heating value is above 1,200 Btu/scf and 5 percent when the 
heating value is below 1,200 Btu/scf. Another commenter suggested that 
the BLM establish uncertainty levels for heating values by working with 
trade groups. Commenters submitted little rationale to support any of 
these suggested uncertainty levels. The BLM believes that the 
uncertainty levels given in the proposed rule are fair, reasonable, and 
achievable based on its experience in the field. They were established 
by determining the point at which the cost of compliance equals the 
risk to royalty. The BLM did not make any changes to the proposed rule 
based on these comments.
    Several commenters stated that the BLM is confusing variability 
with uncertainty when establishing an uncertainty limit for average 
annual heating value. The BLM disagrees with these comments. The 
commenters appear to be assuming that the BLM used the term 
``uncertainty'' interchangeably with ``variability.'' This is not the 
case, as described in detail in the BLM Gas Variability Study and as 
used in this rule. With respect to heating value, the term 
``variability'' refers to the statistical variation from the mean 
heating value based on a certain number of previous gas analyses. For 
example, the heating values from five previous gas samples are shown in 
the table below, and the mean value of those five heating values is 
1,256 Btu/scf. The variability of these five samples is the standard 
deviation of the five heating values (14.3 Btu/scf) 
multiplied by the ``student-t'' function that yields a 95 percent 
confidence. For the five samples, the student-t function is 2.78, and 
the variability of this FMP is 40 Btu/scf (14.3 
Btu/scf x 2.78), or 3.2 percent of the average heating 
value. The BLM considers the variability a quasi-static property of the 
meter. The cause of the variability could be actual changes in gas 
composition over the time period analyzed, sampling technique, analysis 
technique, or other factors such as temperature at the time of 
sampling. Whatever the cause, this particular FMP has a variability of 
3.2 percent and will most likely continue to have a 
variability of approximately 3.2 percent, unless something 
significant changes, such as the gas sampling or analysis technique or, 
for example, a new well is connected to the meter. When the BLM refers 
to heating-value uncertainty, it is specific to the average annual 
heating value uncertainty, not the uncertainty of an individual sample. 
The average annual heating value uncertainty is how close the average 
heating value from an FMP, as determined from gas samples taken over a 
1-year time span, will be to the true average heating value of that FMP 
over the same time span. The true average annual heating value is a 
hypothetical value assuming the heating value was measured continuously 
over that year by an instrument with no uncertainty.

[[Page 81546]]

[GRAPHIC] [TIFF OMITTED] TR17NO16.041

    In the BLM Gas Variability Study, the BLM determined the 
relationship between variability and uncertainty in the average annual 
heating value. The relationship is defined by the following equation:
[GRAPHIC] [TIFF OMITTED] TR17NO16.042

    Although the variability of this FMP is 3.2 percent, 
the average annual heating-value uncertainty is reduced by taking more 
samples over the year. In this example, the samples were taken twice 
per year, or roughly once every 180 days. Using the equation directly 
above, the uncertainty of the average annual heating value at this 
sampling frequency is reduced to 2.1 percent. Sampling four 
times per year (every 90 days) would reduce the average annual heating-
value uncertainty to 1.5 percent. In summary, the average 
annual heating-value uncertainty requirement in the final rule governs 
uncertainty not variability. While variability is a factor in 
determining uncertainty, uncertainty can be reduced for a given level 
of variability by taking more frequent samples. The BLM added Sec.  
3175.31(b)(3) to the final rule as a result of these comments, in order 
to clarify and define the relationship between average annual heating-
value uncertainty and variability. The equations presented in Sec.  
3175.31(b)(3) are the same equations that were presented in the heating 
value variability study repeatedly referenced in the preamble to the 
proposed rule. The study was also included in the supporting 
documentation posted on www.regulations.gov concurrently with the 
release of the proposed rule. In addition, Sec.  3175.31(b)(3) allows 
the BLM to approve other methods of calculating average annual heating 
value uncertainty that operators or industry groups may develop.
    One commenter asked that the BLM exempt central delivery point 
(CDP) meters from the heating-value uncertainty limits because 
achieving these limits would be difficult due to the constantly 
changing gas composition as different wells produce through the meter. 
The commenter provided an example of where a CDP meter, which would 
qualify as a very-high-volume FMP under the proposed rule, has a 
heating-value variability of 3.5 percent. Assuming that the 
commenter determined the variability in the same manner as the BLM 
does, and took monthly samples at a very-high volume as required in the 
rule for the initial 1-year timeframe, the average annual heating-value 
uncertainty would be 0.87 percent, based on the equation 
directly above, which is well within the uncertainty of 1 
percent required for very-high-volume FMPs. The BLM did not make any 
changes to the rule based on this comment.
    Several commenters requested that the BLM provide the calculation 
methodology for average annual heating-value uncertainty. The BLM 
agrees with this comment and included the methodology in the final 
rule, under Sec.  3175.31(b)(3). The methodology was also included in 
the BLM Gas Variability Study, which was posted as a supporting 
document on www.regulations.gov, along with the proposed rule.
    One commenter stated that the cost of compliance for existing FMPs 
outweighs any measurable benefit. However, the volume cutoff points 
between low- and high-volume and between high- and very-high-volume 
FMPs in the final rule were established to represent the point at which 
the cost of compliance is equal to or less than the resulting reduction 
in royalty risk resulting from the improvements required by the rule. 
Royalty risk is the measurement uncertainty expressed in royalty 
dollars. The BLM did not make any changes to the rule based on this 
comment.
    One commenter stated that the data used in the BLM Gas Variability 
study were not vetted or scrubbed to control for the conditions under 
which the samples were taken. The implication of the comment is that 
the BLM study is not statistically valid. While the BLM acknowledges 
that that the data were not controlled for the conditions under which 
they were taken, the data

[[Page 81547]]

represent samples taken under real-life conditions and, in every case, 
the heating values used in the study were used as the basis for royalty 
payment. The BLM also believes that reliance on the study is 
appropriate without controlling for conditions because field sampling 
is typically not controlled to ensure that samples are taken at, for 
example, the same time of year or at the same ambient temperature--
i.e., the study as used by the BLM for purposes of this rule is an 
accurate reflection of sampling results that occur in the field. The 
fact that the data showed no correlation existed between heating-value 
variability and pressure, temperature, or any of the other attributes 
analyzed demonstrates that other factors--perhaps poor sampling 
practices--are masking any correlation that theoretically should exist. 
Again, the BLM does not believe that scrubbing the data was necessary 
because the BLM does not intend to require the same conditions every 
time a sample is taken. In the field, it is impossible to control 
conditions, such as temperature, pressure, flow rate, separator 
efficiency, and other factors. The final rule establishes a uniform 
uncertainty value that reflects actual field practice. Based on the 
foregoing, the BLM did not make any changes to the rule based on this 
comment.
    One commenter stated that the BLM Gas Variability Study does not 
reflect the accuracy of custody-transfer meters because most of the 
measurement points from which the BLM obtained the analyses were on-
lease meters. The BLM believes that the commenter misunderstands the 
purpose of the study, which was to assess the variability of meters on 
which Federal and Indian royalty is based. These meters are often on-
lease meters rather than custody-transfer meters on which the operator 
is paid. The BLM is not concerned with sales or custody-transfer meters 
that are not used in the determination of royalty. Therefore, the data 
used in the study are directly applicable to meters used for royalty 
determination, which are generally the on-lease meters. The BLM did not 
make any changes to the rule based on this comment.
    Several commenters stated that composite samplers and on-line GCs 
are not economical on location because they do not work well with rich 
gas. The commenters did not supply any data to support this claim. 
Based on this comment and on the BLM Threshold Analysis, the BLM 
eliminated the provision in the proposed rule that would have required 
composite samplers or on-line GCs on high-volume FMPs, if the required 
2 percent average annual heating-value uncertainty could 
not be achieved by spot sampling. The BLM made this change for economic 
reasons, not because it accepts that these devices do not work well 
with rich gas. The BLM did not remove the provision in the rule that 
requires composite samplers on very-high-volume FMPs when the required 
1 percent average annual heating-value uncertainty cannot 
be achieved through spot sampling.
    One commenter suggested that the determination of heating-value 
uncertainty should be on a field-wide basis rather than on a well or 
FMP basis. The commenter did not provide any data to substantiate this 
suggestion. The BLM does not agree with this comment. While the 
determination of heating-value uncertainty on a regional or formation-
wide basis may seem like a reasonable approach, the data analyzed by 
the BLM (BLM Gas Variability Study) showed that heating-value 
variability is not correlated by region or formation. One possible 
reason for this is that the heating-value variability is not only 
dependent on the formation, but also on human factors, such as gas 
sampling and analysis techniques. The BLM did not make any changes to 
the rule in response to this comment.
    Section 3175.31(c) establishes the degree of allowable bias in a 
measurement. Bias, unlike uncertainty, results in systematic 
measurement error; uncertainty only indicates the risk of measurement 
error. For all FMPs, except very-low-volume FMPs, no statistically 
significant bias is allowed. The BLM acknowledges that it is virtually 
impossible to completely remove all bias in measurement. When a 
measurement device is tested against a laboratory device, there is 
often slight disagreement, or apparent bias, between the two. However, 
both the measurement device being tested and the laboratory device have 
some inherent level of uncertainty. If the disagreement between the 
measurement device being tested and the laboratory device 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, apparent bias that is less than the 
uncertainty of the two devices combined is not considered to be 
statistically significant. This approach is consistent with existing 
BLM policy. Although bias is not specifically addressed in Order 5 or 
the statewide NTLs, the intent of those standards is to reduce bias.
    The bias requirement does not apply to very-low-volume FMPs because 
very-low-volume FMPs are measuring such low volumes that any bias, even 
if it is statistically significant, results in little impact to 
royalty. The small amount of royalty loss (or gain) resulting from bias 
would be much less than the royalty lost if production were to cease 
altogether--a possible outcome if the operator were to decide that it 
is uneconomic to upgrade a meter to eliminate bias. Therefore, the BLM 
has determined that it is in the public interest to accept some risk of 
measurement bias in very-low-volume FMPs in order to maintain gas 
production. The BLM did not receive any comments on this section.
    Section 3175.31(d) requires that all measurement equipment must 
allow for independent verification by the BLM. For example, if a new 
meter were 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 developed that used proprietary methods that 
precluded the ability to recalculate volumes or heating values, or made 
it impossible for the BLM to verify its accuracy, its use would also be 
prohibited. As explained in the preamble to the proposed rule, this is 
not a change from existing policy. Order 5 and the statewide NTLs for 
EFCs only allow meters that can be independently verified by the BLM.
    One commenter stated that the performance goal of verifiability 
will restrict new technology. As an example, the commenter suggested 
that a verifiability requirement could have prevented the development 
of EGM systems. The BLM disagrees with this comment and did not make 
any changes to the rule as result. Contrary to the suggestion by the 
commenter, the BLM believes that verifiability is essential to making 
EGM systems universally accepted by both industry and regulators. For 
example, over 20 percent of the main body of API 21.1 is devoted to the 
audit trail, reporting, and data integrity required of EGM systems, all 
of which encompass verifiability.
    One commenter expressed concern that the provisions of the proposed 
rule would cause the BLM to continually re-evaluate the quantity, rate, 
or heating value uncertainty of particular equipment. The BLM does not 
agree with this comment and did not make any changes to the rule as a 
result. The rule is designed to minimize required testing. The PMT will 
establish the uncertainty of each new piece of equipment one time, and 
operators can

[[Page 81548]]

then rely on that determination in making the uncertainty calculations.
Sec.  3175.40--Measurement Equipment Approved by Standard or Make and 
Model
    Section 3175.40 establishes the types, makes, and models of 
equipment and software versions that can be used at FMPs. All makes of 
flange-tapped orifice plates (Sec.  3175.41), all makes and models of 
mechanical recorders (Sec.  3175.42), and all makes and models of GCs 
(Sec.  3175.45) are automatically approved under this rule without any 
additional BLM review. This section also explains that for specific 
makes, models, and sizes of other types of equipment including 
transducers (Sec.  3175.43), flow-computer software (Sec.  3175.44), 
flow conditioners (Sec.  3175.46), differential primary devices other 
than flange-tapped orifice plates (Sec.  3175.47), linear measurement 
devices (Sec.  3175.48), and accounting systems (Sec.  3175.49) are 
approved for use at FMPs under the conditions and circumstances stated 
in those sections.
    For the specified types of equipment requiring BLM approval, as 
explained in the section-specific discussions of this preamble, this 
rule requires that equipment must be reviewed by the PMT and approved 
by the BLM. The PMT, which consists of a team of measurement experts, 
will base its review of such equipment on data submitted by individual 
operators, companies, or equipment manufacturers. Unlike the variance 
process under Order 5, which limits approvals to specific facilities, 
and requires that operators submit separate requests to use the same 
equipment at different facilities, this final rule provides that once 
the PMT reviews and the BLM approves a piece of equipment or 
measurement process, that approval will be posted to the BLM website 
(www.blm.gov), and any operator may rely on that approval at any 
facility, provided the operator follows any attached conditions of use. 
The PMT process provides a way for the BLM to approve new technology 
without having to update its regulations, issue other forms of guidance 
(such as NTLs) or grant approvals on a case-by-case basis.
    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.
    The BLM received many comments that expressed concerns over the 
role, authority, staffing, process, and approval timeframes relating to 
the PMT. Several comments stated that the PMT should include industry 
members, academia, tribal members, and State Government 
representatives. Comments also stated that the PMT should be chartered 
under the Federal Advisory Committee Act (FACA) and that all meetings 
should be open to the public. The BLM finds formalizing the PMT and 
requiring a FACA-chartered committee to be inconsistent with expediting 
the approval of new and existing technology. As described in the final 
rule, the PMT will consist of measurement experts within the BLM whose 
primary job function is to review test data for new and existing 
technology and recommend approval or denial of that technology to the 
BLM. While the team has not yet been assembled, the BLM believes that 
once the PMT is fully staffed, reviews will take 30 to 60 days, 
assuming that the proper testing has been done and all pertinent data 
have been submitted to the PMT.
    Under a FACA charter, as favored by some commenters, reviews would 
take much longer, possibly even years. A FACA charter first requires 
all members to be vetted and approved by the Secretary. The BLM would 
then have to publish a notice in the Federal Register of all meetings 
at least 30 days in advance. The BLM does not believe that this is an 
appropriate forum to review large amounts of test data and perform 
specialized analysis to determine if a device can meet the performance 
goals of the rule.
    Substantively, the PMT's role in reviewing specific makes and 
models of equipment and making recommendations to the BLM for approval 
of particular equipment under this rule is similar to the authority for 
a BLM field office to issue variances under the existing Onshore 
Orders. The only difference between the existing variance process and 
the PMT is that under the existing variance process reviews are 
performed at the field-office level on a case-by-case basis; under this 
final rule these reviews will be performed once by a single entity at 
the Washington-Office level. Ultimately, the PMT makes recommendations 
for approval, and the BLM retains full discretion to concur with or 
reject such recommendations. In the final rule to update and replace 
Order 3, Sec.  3170.8 has been revised to add a new paragraph (b) that 
addresses the appeals procedure for PMT recommendations that are 
approved by the BLM. The BLM did not make any changes to the rule based 
on these comments.
    Other commenters stated that the rule should provide for 
administrative review of all recommendations made by the PMT. The BLM 
agrees with this comment and has added an administrative review to the 
PMT process as part of the final rule updating and replacing Order 3 
(see 43 CFR 3170.8(b)). Under this process, any approval or denial made 
by the BLM based on a PMT recommendation can be administratively 
appealed to the Assistant Secretary for Lands and Minerals, or their 
designee. Using the analogy of the existing field office variance 
review process discussed earlier, the approval or denial of a variance 
for new technology under the current process could be appealed by 
anyone adversely affected by that approval or denial. Likewise, any 
decision made by the BLM regarding technology reviewed by the PMT is 
also subject to appeal by anyone adversely affected by that decision.
    Several commenters said that the PMT would favor large companies 
that could afford elaborate ``Cadillac'' proposals. The BLM disagrees 
with this comment and did not make any changes as a result. The reviews 
performed by the PMT are not exclusive. In other words, if a large 
operator submitted a ``Cadillac'' proposal to the PMT and a small 
operator submitted a ``Chevy'' proposal (simple and inexpensive) to the 
PMT, the PMT would review both proposals on their merits. If the PMT 
and then, ultimately, the BLM determined that both proposals met the 
performance goals in this rule, then both proposals would be approved 
and posted on the BLM website. Once posted, any operator could use 
either the ``Cadillac'' or ``Chevy'' technology without any further 
approval needed.
    One commenter stated that the PMT should develop testing manuals 
that the industry could follow. While the BLM did not make any changes 
to the rule based on this comment, the BLM agrees that manuals could 
provide useful guidance. Once formed, the PMT will consider developing 
nonbinding testing manuals, as suggested by the commenter.
    One commenter stated that the PMT role should include the review of 
new gas sampling technology. The BLM agrees with this comment, but does 
not

[[Page 81549]]

believe a change to the regulations is necessary. While this is not a 
specific function of the PMT listed under Sec.  3175.40, the BLM 
believes that the PMT could consider reviewing new gas sampling 
techniques under the PMT's general authority to review new measurement 
equipment and methods.
    Several commenters objected to the lack of information in the 
proposed rule regarding the PMT review and approval process and also 
objected to the absence of a list of approved equipment published in 
the proposed rule. The BLM did not make any changes to the rule based 
on these comments. As a procedural matter, the BLM does not believe 
that it is necessary or appropriate to set forth prescriptive 
procedures for the PMT to follow in either the proposed rule or the 
final rule in order to preserve the BLM's discretion in setting up this 
new entity. That said, the BLM notes that the rule is not silent on the 
PMT's review procedures. To the contrary, the rule establishes specific 
performance standards and requirements that equipment and methods used 
for gas measurement must meet. This information was clearly identified 
in the proposed rule, and, for the most part, has been carried forward 
into the final rule.
    The BLM did not publish a specific list of approved equipment 
because no such list exists. However, the rule does provide for the 
automatic acceptance of certain types of equipment, such as flange-
tapped orifice plates, gas chromatographs, and mechanical recorders at 
low- and very low-volume FMPs. The PMT will develop the list of other 
types of approved equipment, such as flow conditioners and 
differential-pressure meters, based on a review of the data that the 
PMT receives and a determination by the PMT that the equipment complies 
with the performance standards established in this rule. The need for 
these reviews is the reason why the final rule establishes a 2-year 
phase-in period for equipment approved by the PMT in order to give the 
PMT time to complete this work.
    One commenter questioned why the BLM is entering the free market by 
limiting the types of devices that operators can use. The BLM is not 
limiting the types of devices. To the contrary, an operator can use a 
variety of devices as long as those devices meet the applicable 
performance standards specified in the rule. The BLM believes that the 
only way to ensure that volume and quality measurement meets the 
specified uncertainty performance goals is to ensure that the 
components that contribute to volume and quality uncertainty have been 
tested in a consistent and transparent manner. The BLM did not make any 
changes to the rule based on this comment.
    One commenter asked for clarification if the BLM is approving 
equipment by performance or uncertainty. Although the BLM is unclear as 
to what the commenter means by ``performance'' and ``uncertainty'' 
(uncertainty is a performance goal in this rule), the answer is case-
specific as indicated below:
     Transducers (Sec.  3175.43): Approval for transducers 
installed at FMPs after the effective date of the rule is granted if 
the transducer undergoes the tests required in the testing protocol 
(see Sec.  3175.130). Alternatively, for existing transducers, the BLM 
will grant approval if the manufacturer supplies the BLM with a 
sufficient amount of existing data. In either case, the BLM will 
ascertain the uncertainty of the transducer and how outside conditions, 
such as ambient temperature, affect the device.
     Flow-computer software (Sec.  3175.44): Approval is 
granted if the flow-computer software agrees with the reference 
software within a specified tolerance.
     Isolating flow conditioners (Sec.  3175.46): Approval is 
granted if the device is tested under API 14.3.2, Annex D, which 
includes a pass-fail criterion.
     Differential primary devices other than flange-tapped 
orifice plates (Sec.  3175.47): Approval is granted if the device is 
tested in accordance with API 22.2. The BLM will ascertain the 
uncertainty of the device and how factors such as installation 
configurations, Reynolds number, and differential-pressure-to-static-
pressure-ratio, affect the device.
     Linear meters (Sec.  3175.48): Approval is granted if the 
BLM determines that the meter can meet or exceed the performance goals 
of Sec.  3175.31(a), (c), and (d).
     Accounting systems (Sec.  3175.49): Approval is granted if 
the BLM determines that the system can meet the performance goals of 
Sec.  3175.31(d).
    The BLM did not make any changes to the rule based on this comment.
Sec. 3175.41--Flange-Tapped Orifice Plates
    Flange-tapped orifice plates have been rigorously tested and have 
proven capable of meeting the performance standards of Sec.  
3175.31(a), (c), and (d). As such, FMPs using flange-tapped orifice 
plates that are installed, operated, and maintained as the primary 
device in accordance with the standards in Sec.  3175.80 are 
automatically accepted under the final rule with no additional review 
or approvals needed. The BLM did not receive any comments on this 
section.
Sec. 3175.42--Chart Recorders
    Mechanical recorders have been in use on gas meters for more than 
90 years in custody-transfer applications and their ability to meet the 
performance standards of Sec.  3175.31(c) and (d) is well established. 
Because mechanical recorders are limited to very-low-volume and low-
volume FMPs under the rule, they do not have to meet the uncertainty 
requirements of Sec.  3175.31(a). As such, low- and very-low-volume 
FMPs using mechanical recorders that are installed, operated, and 
maintained in accordance with the standards in Sec.  3175.90 are 
automatically accepted under the final rule with no additional review 
or approvals needed. The BLM did not receive any comments on this 
section.
Sec. 3175.43--Transducers
    While EGM systems are widely accepted for use in custody-transfer 
applications, there are currently no standardized protocols by which 
transducers, a critical component of an EGM system, are tested to 
document their performance capabilities and limitations. Proposed Sec.  
3175.43 would have required transducers to be tested under the 
protocols in Sec.  3175.130 in order to be used at high- or very-high-
volume FMPs. Transducers used at very-low and low-volume FMPs are not 
subject to these requirements. The primary purpose of the testing 
protocol is to determine the uncertainty of the transducer under a 
variety of operating conditions. Because very-low and low-volume FMPs 
are not subject to the uncertainty requirements under Sec.  3175.31(a), 
testing the performance of the transducers used at these FMPs is 
unnecessary.
    Several commenters requested that the BLM accept transducers 
currently in use or approve these transducers if the manufacturer can 
provide test data consistent with industry practice. The BLM agrees 
with these comments and added the option of using the test data the 
manufacturers used to derive their published performance 
specifications. However, if the data submitted by the manufacturer are 
incomplete, or insufficient to justify the published performance 
specifications, the BLM may use performance specifications derived by 
the PMT from the data, or limit the use of the transducer to specific 
ranges of pressure, temperature, or operating conditions.

[[Page 81550]]

    The BLM received numerous comments suggesting that the BLM should 
accept published API-type testing standards for transducers in lieu of 
the protocols in the proposed rule. However, there are no API standards 
in place for testing transducers. The BLM is aware that the API is 
developing testing protocols for transducers, but these standards have 
not been published. The BLM did not make any changes to the rule based 
on these comments.
    Numerous commenters suggested that the BLM should grandfather 
existing transducers from the type testing requirements in this 
section. The reasons given in the comments include the inability to 
type test older equipment that is no longer manufactured or supported 
by the manufacturer, the opinion that there is no need to test 
equipment that is properly working, the lack of laboratories equipped 
to do the testing, and timeframes for the PMT to review and approve 
existing equipment to avoid shutting in production. The proposed rule 
would have required type testing of all transducers used on high- and 
very-high-volume FMPs. The BLM recognizes these concerns and has made 
two changes in this section as a result. First, the requirement to use 
type-tested equipment will not take effect until 2 years after the 
effective date of the rule as provided in Sec.  3175.60(a)(4) and 
(b)(2). This should be adequate time for the formation of the PMT, 
testing of existing equipment, and review of that equipment by the PMT. 
Second, for existing transducers, the BLM will allow operators or 
manufacturers to submit the data on which the manufacturer's published 
performance specifications are based, in lieu of using the testing 
protocols specified in Sec.  3175.130 of the rule. This will allow the 
PMT to review, and the BLM to approve if appropriate, existing 
transducers without the need for additional testing. Additional changes 
based on these comments are addressed in the Sec.  3175.130 discussion 
in this preamble.
    Several commenters expressed a concern about the cost of replacing 
existing transducers as a result of this requirement. The BLM does not 
believe that this requirement would require operators to replace 
existing transducers. In addition to the 2-year implementation of this 
requirement and the provision to allow operators and manufacturers to 
submit existing data instead of generating new data, the transducer 
testing protocol in Sec.  3175.130 is not a pass-fail requirement. The 
purpose of the testing protocol is to independently define the 
performance of a transducer and then use that performance to determine 
compliance with the overall uncertainty requirements in Sec.  
3175.31(a). The BLM did not make any changes to the rule based on these 
comments.
    One commenter suggested that instead of approving transducers by 
make and model using the testing protocol, the BLM should just specify 
performance goals. The BLM has, in fact, specified performance goals 
for both volume (Sec.  3175.31(a)) and heating value (Sec.  3175.31(b)) 
based on overall measurement uncertainty. However, in order to enforce 
an uncertainty standard, BLM inspectors must be able to calculate the 
overall uncertainty to determine if the FMP meets the requirements. 
Transducer performance is often the largest contributor to overall 
volume measurement uncertainty, especially in situations where the 
transducer is operated at the low end of its upper calibrated limit. 
Currently, the BLM uncertainty calculator uses the manufacturer's 
published performance specifications in the calculation of uncertainty; 
however, there is no standard method that manufacturers use to develop 
those specifications. In addition, most manufacturers consider their 
testing process and data as proprietary, making it impossible for the 
BLM to verify. The BLM believes that to enforce an uncertainty 
performance goal, the components that go into the uncertainty 
calculation must be determined in a transparent and consistent manner. 
Therefore, the BLM did not make any changes to the rule based on this 
comment.
    Two commenters also suggested that the BLM could use field 
calibration data to validate existing equipment. While the BLM believes 
that field calibration could be used to validate existing equipment, it 
would be difficult to extract individual installation effects from the 
data such as ambient temperature effects, vibration effects, and static 
pressure effects. In addition, it would be difficult to filter the data 
to eliminate human error in the calibration data. The BLM did not make 
any changes to the proposed rule as a result of these comments.
    One commenter stated that operators have no economic incentive to 
replace existing transducers. The BLM did not make any changes to the 
rule based on this comment for two reasons. First, as explained 
previously, the testing protocols for transducers and flow computers 
would not generally require replacing existing equipment. Second, we 
agree that operators often do not have an economic incentive to replace 
existing transducers (in other words, the investment in a new 
transducer would not necessarily result in increased revenue). If they 
had an economic incentive, this provision in the rule would probably 
not be necessary. The intent of the provision is to improve accuracy 
and verifiability to ensure that the public and Indian tribes and 
allottees receive their fair share of the value of oil and gas 
resources extracted from their land. The BLM did not make any changes 
to the rule based on this comment.
Sec. 3175.44--Flow-Computer Software
    As with transducers, there are currently no standardized protocols 
by which flow-computer software is tested to document its capability to 
perform all calculations within acceptable tolerances and record and 
store other supporting information. Proposed Sec.  3175.44 would have 
required flow-computer software at all FMPs to be tested under Sec.  
3175.140 in order to be used at an FMP.
    Numerous commenters suggested that the BLM should grandfather 
existing flow-computer software versions from the type-testing 
requirements of this section. The commenters stated that it would be 
difficult to test software versions on older computers that are no 
longer supported by the manufacturer. Other commenters stated that the 
time required for the PMT to review and approve software versions could 
lead to production shut-ins.
    The BLM recognizes these concerns and has made two changes in the 
final rule as a result. First, the requirement to use type-tested 
software does not take effect until 2 years after the effective date of 
the rule, as provided for in Sec.  3175.60(a)(4) and (b)(2). This 
should be adequate time for the formation of the PMT, testing of 
existing software versions, review of that software by the PMT, and 
approval of the software by the BLM. Second, under the final rule, all 
software versions used at very-low- and low-volume FMPs are approved 
for use without testing, unless otherwise required by the BLM (Sec.  
3175.44(c)). While this is not the complete grandfathering requested by 
the commenters, the BLM believes that there are very few older, 
unsupported flow computers in use at high- or very-high-volume FMPs.
    The BLM received numerous comments suggesting that the BLM should 
accept published API type-testing standards for flow-computer software 
in lieu of the protocols in the rule. However, there are no API 
standards in place for flow-computer software. The BLM is aware that 
the API is developing testing protocols for flow-

[[Page 81551]]

computer software, but these standards have not been published. The BLM 
did not make any changes to the rule based on these comments.
    Several commenters expressed a concern about the cost of replacing 
existing flow computers as a result of this requirement. The BLM does 
not believe that this requirement requires operators to replace 
existing flow computers. The testing protocol defined in Sec.  3175.140 
applies to the software in the flow computer, not the flow computer 
itself (although the software testing is specific to individual makes 
and models of flow computers). The flow-computer testing protocol is a 
pass-fail requirement. However, if the BLM discovers a software version 
that did not pass, the remedy would be to update the software and 
install it in the flow computer.
Sec. 3175.45--Gas Chromatographs
    GCs have been rigorously tested and used in industry for custody-
transfer applications, and their ability to meet the requirements of 
Sec.  3175.31 has been demonstrated. Therefore, the rule allows all 
makes and models of GCs in determining heating value and relative 
density as long as they meet the requirements of Sec. Sec.  3175.117 
and 3175.118. The BLM did not receive any comments on this section.
Sec. 3175.46--Isolating Flow Conditioners
    Section 3175.46 requires all makes and models of flow conditioners 
used in conjunction with flange-tapped orifice plates at FMPs to be 
tested under established API test protocols, reviewed by the PMT, and 
approved by the BLM.
    The final rule references API 14.3.2, Annex D, which provides a 
testing protocol for flow conditioners. In the proposed rule, based on 
the BLM's experience with other testing protocols, the BLM proposed 
using additional testing beyond what Annex D requires to meet the 
intent of the uncertainty limits in Sec.  3175.31(a). Additional 
testing protocols would have been posted on the BLM's Web site at 
www.blm.gov. Numerous commenters expressed concern over the PMT's 
ability to include additions to the API 14.3.2 Annex D testing protocol 
for flow conditioners. The BLM agrees with these comments as they 
relate to flow conditioners and deleted the provision that would have 
allowed the PMT to add additional testing for flow conditioners.
    One commenter asked if data for existing flow conditioners that 
have already been tested under Annex D will have to be resubmitted to 
the PMT to get approval. The PMT will require the data in order to 
review the flow conditioner in question. No changes to the rule were 
made as a result of this comment.
    One commenter suggested that in lieu of establishing a new process 
for the PMT to follow for the approval of flow conditioners, the BLM 
should incorporate and use API Chapter 12.1. The commenter also stated 
that unless the PMT meets regularly, it will slow down the adoption of 
new technology. API 12.1 deals with the calculation of static petroleum 
liquids in upright cylindrical tanks and rail cars, which does not seem 
relevant here. The BLM's intent is to establish the PMT as a permanent 
full-time team dedicated to reviewing test data and performing other 
centralized measurement functions. The BLM did not make any changes to 
the rule based on this comment.
Sec. 3175.47--Differential Primary Devices Other Than Flange-Tapped 
Orifice Plates
    Section 3175.47 requires all makes and models of differential 
primary devices other than flange-tapped orifice plates to be tested 
under established API test protocols, reviewed by the PMT, and approved 
by the BLM in order to be used at FMPs.
    This section references API 22.2 (2005), which establishes a 
testing protocol for differential devices. The proposed rule would have 
allowed the BLM to include additional testing requirements beyond those 
in the current version of API 22.2 to help ensure that tests are 
conducted and applied in a manner that meets the intent of Sec.  
3175.31 of this rule. The BLM would have posted any additional testing 
protocols on its Web site at www.blm.gov.
    Numerous comments expressed concern over the PMT's ability to 
include additions to the API 22.2 testing protocol for differential 
primary devices. The BLM agrees and modified this provision 
accordingly.
    Several commenters asked that the burden of testing new devices be 
on the manufacturer and not the operator. The BLM is not concerned with 
who does the testing. However, this section of the proposed rule 
specified that the operator must test these devices. The BLM agrees 
that the both the testing and the submittal of data to the PMT can be 
done by either the operator or the manufacturer; the BLM changed the 
reference to ``operator'' in this section to ``operator or 
manufacturer'' as a result of this comment.
Sec. 3175.48--Linear Measurement Devices
    Proposed Sec.  3175.48 would have allowed the BLM to approve linear 
measurement devices reviewed by the PMT on a case-by-case basis to be 
used at FMPs. Linear measurement devices include ultrasonic meters, 
Coriolis meters, and turbine meters.
    The BLM received numerous comments stating that linear meters 
should be approved on a type-testing basis, and not just on a case-by-
case basis as stated in the proposed rule. The comments indicated that 
industry widely accepts linear meters and case-by-case approval could 
inhibit technological development. In addition, the commenters stated 
that there are existing industry standards for linear meters such as 
ultrasonic meters, turbine meters, and Coriolis meters. The BLM agrees 
with these comments and changed the wording of Sec.  3175.48 from a 
``case-by-case basis'' to a ``type-testing basis,'' similar to the 
requirements for other devices under Sec.  3175.40. When the PMT 
receives a request to use a linear meter, it will review any applicable 
standards for that meter as part of the approval process. The PMT will 
then recommend approval or denial of that device to the BLM. If the BLM 
approves the device, it will be posted at www.blm.gov.
    One commenter expressed concern with the language in the proposed 
rule stating that the BLM ``may,'' but does not have to, approve the 
make and model of a linear measurement device. The commenter indicated 
that this could present a regulatory hurdle that could delay the use of 
more technologically advanced devices like ultrasonic meters. Although 
the language of this section was changed based on other comments and 
the word ``may'' no longer appears, the BLM retains the discretion of 
approving or not approving certain makes and models of linear 
measurement devices based on the review of the PMT. The BLM does not 
agree that this will present a regulatory hurdle for the implementation 
of new technology. Instead, the BLM believes that having a consistent 
and thorough review process that ensures that the new technology can 
meet the uncertainty, bias, and verifiability goals of the rule will 
encourage acceptance of new technology that can meet these goals. The 
BLM did not make any changes to the rule based on this comment.
Sec. 3175.49--Accounting Systems
    Accounting systems were not included in the proposed rule; however,

[[Page 81552]]

the BLM received several comments on Sec.  3175.104(a), (b), and (c) 
recommending that the BLM include the PMT review of accounting systems 
in the final rule. Paragraphs (a), (b), and (c) of Sec.  3175.104 
require operators to retain and submit to the BLM upon request 
original, unaltered, unprocessed, and unedited QTRs, configuration 
logs, and event logs. The BLM agrees with the comments and believes 
that the PMT should approve accounting systems by software version 
through a type-testing protocol. As a result, the final rule contains a 
protocol by which the PMT can assess whether an accounting system 
produces original, unaltered, unprocessed, and unedited records that 
can be submitted to the BLM.
    When performing a production review, the BLM typically starts by 
sending a written order to the operator requiring the operator to 
submit data supporting the reported production quality and quantity 
over a specified time period and for a specified lease, CA, or unit PA. 
These data typically include QTRs, configuration logs, event logs, and 
alarm logs. As discussed in the preamble to the proposed rule, it is 
common practice for operators to submit these data to the BLM using 
third party software that automatically compiles data from the flow 
computers and uses it to generate a standard report. However, the BLM 
has found in numerous cases that the data submitted from the third-
party software is not the same as the data generated directly by the 
flow computer. In addition, the BLM consistently has problems verifying 
the volumes reported through reports generated by third-party software.
    As a result, the BLM has developed the testing protocol required in 
this section that compares raw data retrieved directly from flow 
computers to both edited and unedited data obtained from the third 
party software under test. The BLM will only approve software packages 
where the protocol demonstrates that the original, unaltered, 
unprocessed, and unedited data from the flow computer is provided by 
the software, and that edited data is clearly marked as such.
Sec. 3175.60--Timeframes for Compliance
    Section 3175.60 provides a timeframe for when all measuring 
procedures and equipment installed at any FMP must comply with the 
requirements of this subpart. Proposed Sec.  3175.60(a) would have 
required all meters installed after the effective date of the final 
rule to meet the requirements of the rule. The BLM received several 
comments stating that the requirement to enter all gas analyses into 
the GARVS (see Sec.  3175.120(f)) should be delayed because GARVS does 
not exist yet and the BLM did not provide enough information about 
GARVS in the proposed rule for operators to develop reporting formats. 
GARVS is a new database that the BLM is developing as part of the 
implementation of this rule that will have the ability to receive gas 
analysis reports from operators. One commenter stated that the BLM 
should delay this requirement up to 7 years, to give operators enough 
time to obtain GC models that are capable of meeting the proposed GC 
requirements of Sec.  3175.118. Several other commenters suggested a 
delay of 2 years. The BLM agrees with the latter comments and included 
a 2-year phase-in period for reporting into GARVS in the final rule 
(Sec.  3175.60(a)(2)). The 2-year phase-in period is to allow the BLM 
time to develop the GARVS software. Based on changes in the final rule 
relating to GCs, the BLM believes that virtually all existing GCs will 
meet the standards of this rule and that no additional delay to develop 
new GCs is necessary. The final rule (Sec.  3175.60(a)(3)) also delays 
the implementation of variable sampling frequencies in Sec.  
3175.115(b) for 2 years. In order to implement this requirement, GARVS 
must be fully functioning.
    Numerous comments suggested that the BLM should grandfather 
existing equipment from having to get approval from the PMT. The 
commenters expressed concern over having to shut in wells while the PMT 
reviews and approves existing equipment. The proposed rule would have 
required type testing of transducers used on high- and very-high-volume 
FMPs and type testing of flow-computer software, flow measurement 
devices, and flow conditioners at all FMPs. The BLM understands these 
concerns and has made two changes in the rule as a result. First, the 
requirement to use equipment reviewed by the PMT and approved by the 
BLM will not take effect until 2 years after the effective date of the 
rule (Sec.  3175.60(a)(4)). This should be adequate time for the 
formation of the PMT, testing of existing equipment, and review and 
approval of that equipment by the PMT. Second, for existing 
transducers, the BLM will allow operators or manufacturers to submit 
the data on which their published performance specifications are based 
in lieu of using the testing protocols specified in Sec.  3175.130 of 
the rule. This will allow the PMT to approve existing transducers 
without the need for additional testing.
    Section 3175.60(b) sets timeframes for compliance with the 
provisions of this rule for measuring procedures and equipment existing 
on the effective date of the final rule. The timeframes for compliance 
generally depend on the average flow rate at the FMP. Under the 
proposed rule, very-high-volume FMPs would have had 6 months from the 
effective date of the rule, high-volume FMPs would have had 1 year from 
the effective date of the rule, low-volume FMPs would have had 2 years 
from the effective date of the rule, and very-low-volume FMPs would 
have had 3 years from the effective date of the rule. Higher-volume 
FMPs would have had shorter timeframes for compliance under the 
proposed rule because they present a greater risk to royalty inaccuracy 
than lower-volume FMPs and the costs to comply could be recovered in a 
shorter period of time.
    Numerous comments stated that the compliance timeframes in the 
proposed rule were too short for several reasons, including the time it 
takes to revise accounting systems to handle the 11-digit FMP number; 
the time for budgeting, engineering, purchasing, and installing new 
equipment; the fact that GARVS is not yet up and running; and the time 
it will take for the PMT to approve existing equipment. In addition, 
several commenters stated that the proposed rule would have created a 
high demand for items such as flow computers and meter tubes that would 
comply with the new requirements, and that demand would delay the 
availability of the equipment. One commenter stated that the proposed 
timeframes also needed to consider delays caused by weather and 
seasonal restrictions in some areas. Commenters' suggestions ranged 
from a 1-year to a 3-year phase-in period or tying the phase-in period 
to when the FMP is approved by the BLM. One commenter suggested tying 
the phase-in period to the availability of GCs capable of meeting the 
new requirements in the proposed rule, although it is not clear to what 
new requirements the commenter was referring. The BLM generally agrees 
with these comments and changed the compliance timeframe for very-high-
volume FMPs from 6 months to 1 year to coincide with the timeframe for 
high-volume FMPs. The compliance timeframe for very-low and low-volume 
FMPs remains at 3 years and 2 years, respectively. This change, in 
conjunction with other changes to the rule listed below, should 
alleviate the concerns raised by the commenters:
     Elimination of the need to display the 11-digit FMP 
number, or include this number in accounting systems (Sec. Sec.  
3175.101(b)(4)(i) and 3175.104(a)(1) in the proposed rule). Removing 
the

[[Page 81553]]

requirement for FMPs to display the FMP number or run the latest API 
calculations should significantly reduce the number of FMPs that would 
potentially have been replaced under the proposed rule. Removing the 
requirement that accounting systems have to include the FMP number 
should reduce the amount of time required to modify accounting systems.
     Grandfathering of existing meter tubes at low- and high-
volume FMPs (Sec.  3175.61(a)). Under the final rule, operators of 
existing very-low-volume, low-volume, and high-volume FMPs will not 
have to upgrade the meter tubes to API 14.3.2 standards. The BLM 
believes that meter tubes at very-high-volume FMPs constructed after 
API 14.3.2 was issued in 2000 meet those standards and will not have to 
be retrofitted. As with the flow computers, therefore, only those very-
high-volume FMPs that were constructed prior to 2000 will require meter 
tube upgrades. The BLM believes that most meter tubes at very-high-
volume FMPs were constructed to the latest API standards and will not 
have to be retrofitted as a result.
     Allowing existing data to approve transducers at high- and 
very-high-volume FMPs (Sec.  3175.43(b)). Under the final rule, 
operators can submit existing test data to the PMT in lieu of 
performing the testing under Sec.  3175.130, for transducers that are 
in use at FMPs prior to the effective date of the rule. This will 
dramatically reduce the time and cost that could have been associated 
with the required testing for all transducers under the proposed rule.
     Modifying GC requirements (Sec. Sec.  3175.113 and 
3175.118). The BLM made numerous changes to Sec. Sec.  3175.113 and 
3175.118 relating to GCs, and believes that these changes address the 
concerns of the commenter who suggested that the BLM tie the timeframes 
to the availability of GCs capable of meeting the new BLM requirements. 
For example, the requirement under Sec.  3175.118(b) of the proposed 
rule would have required samples to be analyzed until 3 consecutive 
runs are within the repeatability standards listed in GPA 2261-00, 
Section 9. It would have been very difficult for existing GCs to meet 
this proposed standard and, as a result of comments received, the BLM 
eliminated this requirement in the final rule.
     Lengthening to 2 years the phase-in period for the 
implementation of GARVS (Sec.  3175.60(a)(2) and (b)(2)(ii)).
     Lengthening to 2 years the timeframe for getting PMT 
approval of existing equipment (Sec.  3175.60(a)(4) and (b)(2)(iii)). 
Allowing the PMT to approve transducers currently in use with existing 
data from the manufacturers will greatly reduce the approval timeframe 
and, in conjunction with the new, 2-year timeframe for PMT approvals, 
should ease operators' compliance with the new requirements.
    Several commenters expressed a concern about being penalized if 
they cannot meet the deadlines due to delays within BLM, such as the 
PMT failing to issue approvals in a timely manner. In deciding how to 
target its enforcement actions, the BLM will take into account any 
evidence that BLM delays contributed to an operators' noncompliance. No 
changes to the rule were made based on these comments.
    One commenter recommended that the BLM implement a series of 
training programs for operators during the phase-in periods. The BLM 
will consider outreach programs; however, no changes to the rule were 
made as a result of this comment.
    Proposed Sec.  3175.60(b)(1)(ii) and (b)(2)(ii) would have included 
some exceptions to the compliance timelines for high-volume and very-
high-volume FMPs. To implement the gas-sampling frequency requirements 
in proposed Sec.  3175.115, the gas-analysis submittal requirements in 
proposed Sec.  3175.120(f) would have gone into effect immediately for 
high-volume and very-high-volume FMPs on the effective date of the 
final rule. This would have allowed the BLM to immediately start 
developing a history of heating values and relative densities at FMPs 
to determine the variability and uncertainty of these values. As 
discussed above, however, the BLM decided to allow for a 2-year window 
from the effective date of the rule for the implementation of GARVS, 
including for FMPs existing before the effective date of the rule 
(Sec.  3175.60(b)(1)(iii)).
    Although this rule will supersede Order 5 and any NTLs, variance 
approvals, and written orders relating to gas measurement, paragraph 
(c) specifies that their requirements will remain in effect through the 
timeframes specified in paragraph (b). Paragraph (d) establishes the 
dates on which the applicable NTLs, variance approvals, and written 
orders relating to gas measurement will be rescinded. These dates 
correspond to the phase-in timeframes given in paragraph (b). The BLM 
did not receive any comments on this paragraph.
    The BLM received a few comments regarding the proposed requirement 
in Sec.  3175.60(b)(2) on timeframes to retrofit chart recorders used 
on low- and very-low volume FMPs. The BLM did not make any changes 
based on these comments. The rule allows 2 years for low-volume FMPs to 
come into compliance with the new rule and 3 years for very-low-volume 
FMPs. The BLM believes that this provides enough time for operators to 
make the relatively few changes required for mechanical recorders in 
the rule. Based on other comments, the BLM raised the very-low-/low-
volume threshold from 15 Mcf/day to 35 Mcf/day, which significantly 
decreases the number of mechanical recorders that fall into the low-
volume FMP category.
    Several commenters stated that the timeline to implement the 
required changes was unreasonable due to workforce constraints, and the 
end result would not increase accuracy or royalties. Based on these and 
other comments, the BLM extended the timeframe for very-high-volume 
FMPs to comply with these requirements from 6 months to 1 year. The 
compliance timeframes for high-, low-, and very-low-volume FMPs remain 
at 1 year, 2 years, and 3 years, respectively. As stated above, the 1-
year compliance timeframe only applies to high- and very-high-volume 
FMPs, which only make up 11 percent of all FMPs nationwide under the 
new flow-rate category definitions.
    The BLM disagrees with the statement that these rules will not 
increase accuracy. For one thing, the accuracy, or uncertainty, for 
very-high-volume FMPs must improve from the 3 percent 
allowed in the statewide NTLs to 2 percent under this rule. 
Similarly, the requirement to eliminate statistically significant bias 
in the final rule will ensure that the calculation of uncertainty only 
involves random error, representing a risk of mismeasurement, and not 
systemic error, which would result in actual mismeasurement. The BLM 
also notes that many of the changes in this rule are aimed at improving 
the verifiability of measurement, not the accuracy.
    As for whether the rule will increase royalties, the BLM notes that 
the goal of the rule is to reduce uncertainty (improve accuracy), 
remove bias, and increase verifiability to ensure that the public and 
tribes receive their fair share of royalty on the gas removed and sold 
from their leases. The goal was not necessarily to increase royalty 
payments, but rather to ensure that all royalties due are paid. Royalty 
payments may increase as a result of this rule, but the BLM cannot 
predict whether net payments will increase in every instance as a 
result of this rule. The BLM did not make any changes to the rule based 
on these comments.

[[Page 81554]]

Sec. 3175.61--Grandfathering
    This section was added to the final rule based on numerous comments 
regarding the cost of some of the requirements in the proposed rule, 
and based on the BLM's Threshold Analysis, which re-examined some of 
the economic impacts based on information received during the comment 
period.
    In the proposed rule, the BLM did not propose to ``grandfather'' 
existing equipment. Operators would have been required to upgrade 
measurement equipment at FMPs to meet the new standards, except at 
those FMPs that were specifically exempted in the rule. The BLM 
received many comments, however, expressing that existing equipment 
should be grandfathered to avoid changing out or upgrading equipment 
that is working.
    In general, commenters expressed the concern that without 
grandfathering, they would be forced to plug and abandon wells--
particularly low producing wells--due to the high cost of retrofitting 
existing facilities. Other commenters stated that equipment should be 
grandfathered if the operator can demonstrate it meets the performance 
goals under this rule or unless and until the BLM determines the 
equipment is inaccurate. Several commenters stated that existing 
equipment should be grandfathered because the BLM implicitly accepts 
this equipment as being accurate under Order 5. One commenter suggested 
that the BLM should grandfather existing equipment when the repair cost 
exceeds 50 percent of a new installation. One commenter stated that 
retroactive requirements should only apply to high- and very-high-
volume FMPs. The BLM also received numerous comments requesting 
specifically that the BLM grandfather existing meter tubes at FMPs 
because meter tubes installed before the standards of API 14.3.2 came 
out in 2000 would not comply with some of the requirements in Sec.  
3175.80.
    In addition to these general comments, the commenters also 
expressed concern about four specific requirements in proposed Sec.  
3175.80 pertaining to meter tubes:
     The orifice plate perpendicularity and eccentricity at all 
FMPs would have to meet the standards of API 14.3.2, Subsection 6.2 
(Table 1 to Sec.  3175.80). The term ``perpendicularity'' refers to the 
orifice plate being perpendicular to the direction of flow. The term 
``eccentricity'' refers to the centering of the orifice plate in the 
meter tube. These standards require less eccentricity than the previous 
1985 version of AGA Report No. 3.
     The meter tube construction and condition at low-, high-, 
and very-high-volume FMPs would have to meet the standards in Sec.  
3175.80(f). These standards refer to the requirements in API 14.3.2, 
Subsections 5.1 through 5.4 and require higher tolerances for meter 
tube roundness than the previous 1985 version of AGA Report No. 3 
required.
     The design of tube bundles at low-, high-, and very-high-
volume FMPs would have to meet the requirements in Sec.  3175.80(g). 
These requirements refer to the tube-bundle construction requirements 
in API 14.3.2, Subsections 5.5.2 through 5.5.4. The previous 1985 
version of AGA Report No. 3 did not specify the number of tubes that 
the tube-bundle straightening vane could have, whereas the API 14.3.2 
standards incorporated by reference in this rule only allow 19 tubes.
     The meter tube length and tube-bundle placement for low-, 
high-, and very-high-volume FMPs would have to meet the requirements in 
Sec.  3175.80(k). These requirements refer to API 14.3.2, Subsection 
6.3. The meter tube length requirements in API standards incorporated 
by reference in the proposed rule were generally the same, or very 
close to, the meter tube length requirements in the previous 1985 
version of AGA Report No. 3, especially at Beta ratios below 0.5. 
However, there are some specific situations where the lengths under the 
new API standard are much longer than those required in the 1985 
standard. In addition, for Beta ratios of 0.5 or greater, the tube-
bundle placement standards are much different in the new API than in 
the previous 1985 version.
    The commenters cited multiple reasons for exempting existing meter 
tubes from these requirements. The commenters stated that meter tubes 
installed before the standards of API 14.3.2 came out in 2000 do not 
comply with some of the requirements in Sec.  3175.80, and noted the 
high cost of replacing the large number of meter tubes installed under 
the 1985 standard (or under previous standards), the likely 
manufacturing delays that would result when operators simultaneously 
ordered a high number of replacement meter tubes, and the negligible 
revenue benefit that would result from replacing meter tubes. One 
commenter also recommended that the eccentricity requirements only 
apply to high- and very-high-volume FMPs.
    The BLM partially agrees with these comments, and therefore decided 
to modify the final rule to provide for limited grandfathering of meter 
tubes and flow-computer software at certain FMPs. Specifically, the BLM 
changed Table 1 to Sec.  3175.80 so that neither the eccentricity nor 
the pendicularity requirement applies to very-low-volume FMPs. Further, 
the BLM added a grandfathering clause (Sec.  3175.61(a)) that exempts 
meter tubes at low- and high-volume FMPs installed before January 17, 
2017 from the perpendicularity and eccentricity requirements in Table 1 
to Sec.  3175.80; the construction and condition requirements in Sec.  
3175.80(f); and the meter tube length requirement in Sec.  3175.80(k). 
However, these meter tubes have to meet the 1985 AGA Report No. 3 
standards for eccentricity (see Sec.  3175.61(a)(1)), construction and 
condition (see Sec.  3175.61(a)(2)), and meter tube length (see Sec.  
3175.61(a)(3)). The rule does not grandfather the design and location 
of flow conditioners, including tube bundles, for reasons outlined in 
the discussion under Sec.  3175.80(g) regarding tube-bundle design and 
Sec.  3175.80(k) regarding tube-bundle placement.
    In addition, the BLM added a clause for grandfathered meter tubes 
used at high-volume FMPs, which allows the BLM to add 0.25 percent to 
the discharge coefficient uncertainty when determining overall 
measurement uncertainty under Sec.  3175.31(a)(1). The discharge 
coefficient uncertainty used in the BLM uncertainty calculator is based 
on data presented in API 14.3.1, which assumes the meter tube meets all 
the standards under API 14.3.2. The looser tolerances in AGA Report No. 
3 (1985) likely result in higher levels of discharge coefficient 
uncertainty than those resulting from the tighter tolerances in API 
14.3.2, although the BLM does not know specifically how much higher. 
Based on its experience with meter testing, the BLM believes that an 
increase in discharge coefficient uncertainty of 0.25 percent is 
reasonable to account for the looser tolerances under AGA Report No. 3 
(1895). If operators submit test data to the PMT showing that meter 
tubes constructed under the 1985 standard result in an increase in the 
discharge coefficient uncertainty of less than 0.25 percent, or no 
increase at all, the BLM may approve a lower percentage. The 0.25 
percent increase in discharge coefficient uncertainty does not apply to 
low-volume FMPs because low-volume FMPs are not subject to the 
uncertainty requirements under Sec.  3175.31(a).
    Several commenters asked that the BLM grandfather flow computers 
that are currently in use without requiring operators to go through the 
testing protocol. The BLM agrees with this comment, at least for very-
low and low-volume FMPs. Accordingly, the BLM changed Sec.  3175.44 so 
that the testing of

[[Page 81555]]

flow-computer software is no longer required for very-low and low-
volume FMPs (see the discussion under Sec.  3175.44). Because flow-
computer software used at existing very-low and low-volume FMPs is 
grandfathered from having to perform the calculations in the latest API 
standards, there is no benefit in requiring this software to be tested 
under Sec.  3175.44. The testing protocol in Sec.  3175.140 compares 
the calculations from the flow-computer software with the calculations 
from reference software using the latest API equations. Therefore, 
there would be no benefit in comparing grandfathered flow computers, 
using older calculation methodologies to reference software using the 
latest API methodologies. The results would most likely not match, not 
due to errant flow computer software, but due to the different 
methodologies used.
    One commenter stated that the BLM should grandfather the 
calculation methodologies at existing flow computers and allow them to 
calculate supercompressibility under AGA Report No. 8, (1992), which is 
already programmed into the commenter's flow computers. The BLM did not 
make any changes to the rule based on this comment because AGA Report 
No. 8 (1992) is the most current method of calculating 
supercompressibility and is incorporated by reference (see Sec.  
3175.30). Any flow computer that is programmed with the AGA Report No. 
8 software will be in compliance with the rule.
    Another commenter suggested that the BLM should grandfather 
existing flow computers from having to comply with Sec.  3175.103(a)(1) 
which requires flow rate calculations to be done in accordance with API 
14.3.3 (2013) and supercompressibility calculations to be done in 
accordance with AGA Report No. 8 (1992). The commenter stated that 
older flow computers may not have the latest calculation software, and 
it may be difficult or impossible to upgrade the flow computers, 
especially if they are no longer supported by the manufacturer. In 
these cases, according to the commenter, operators would choose to 
prematurely plug and abandon wells rather than incur the cost of a new 
flow computer. The BLM agrees with these comments as they relate to 
very-low and some low-volume FMPs, and added Sec.  3175.61(b) to the 
final rule to address flow computers installed at these FMPs before the 
effective date of the rule. A summary of the calculation methodologies 
of the older API and AGA standards and the response to the commenter's 
suggestion are addressed below.
     API 14.3.3 (1992): The primary difference between the API 
14.3.3 (2013) calculation and the API 14.3.3 (1992) calculation 
involves the gas expansion factor. The 2013 edition of API 14.3.3 uses 
a different equation for the gas expansion factor which is based on a 
more thoroughly vetted dataset than the 1992 edition. Use of the 
equation from the 1992 standard results in a statistically significant 
bias of greater than 0.25 percent when the ratio of differential 
pressure to static pressure exceeds the values listed in Table G.1 of 
API 14.3.3 (2013), Annex G. When the differential pressure to static 
pressure ratio is below these values, the bias is less than 0.25 
percent, which the BLM does not consider to be statistically 
significant.
     AGA Report No. 3 (1985): This standard, which was the 
predecessor to the API 14.3.3 standards, not only uses the older 
version of the gas expansion factor equation, it uses a different and 
less accurate version of the calculation used to determine the 
discharge coefficient. In addition, the 1985 calculation uses a non-
iterative calculation approach that further contributes to reduced 
accuracy. Both the 1992 and 2013 API 14.3.3 calculations use an 
iterative process and a more accurate equation for the discharge 
coefficient, resulting in a more accurate calculation of flow rate. The 
1992 and 2013 API standards also quantify the uncertainty of the 
discharge coefficient calculation in greater detail than in AGA Report 
No. 8 (1985).
     PRCI NX-19: This standard, which was the predecessor of 
AGA Report No. 8, defines a calculation method for supercompressibility 
that is less accurate and more limited in its application than the AGA 
Report No. 8 calculation. The BLM does not know if the PRCI NX-19 
calculation results in statistically significant bias compared to the 
AGA Report No. 8 calculation, however.
    Because high- and very-high-volume FMPs must meet uncertainty, 
bias, and verifiability requirements of Sec.  3175.31(a), (c), and (d), 
respectively, the BLM believes it is appropriate to require the use of 
the latest calculation methodologies in API 14.3.3 (2013) and AGA 
Report No. 8 (1992) at these FMPs, whether they are new or existed as 
of January 17, 2017. Therefore, the BLM did not grandfather the 
calculation requirements of Sec.  3175.103(a)(1) for high- and very-
high-volume FMPs.
    Low-volume FMPs do not have to meet the uncertainty requirements of 
Sec.  3175.31(a), but they must still meet the bias and verifiability 
requirements of Sec.  3175.31(c) and (d), respectively. Therefore, the 
BLM believes that allowing the use of the API 14.3.3 (1992) 
calculations at existing low-volume FMPs, where the differential 
pressure to static pressure ratio is less than those values in Table 
G.1, of API 14.3.3 (2013), Annex G, is acceptable. As stated 
previously, the use of the gas expansion equation in API 14.3.3 (1992) 
does not result in statistically significant bias when the differential 
pressure to static pressure ratio is less than those values in Table 
G.1.
    Based on the foregoing, the BLM added Sec.  3175.61(b)(2) which 
grandfathers existing low-volume FMPs from having to use the 
calculations in API 14.3.3 (2013) (required under Sec.  
3175.13(a)(1)(i)) when the differential pressure to static pressure 
ratio is less than those values specified in Table G.1 of API 14.3.3 
(2013), Annex G. However, these FMPs must still use the calculations in 
API 14.3.3 (1992). If the differential pressure to static pressure 
ratio at an FMP, calculated using the monthly average values of 
differential pressure and static pressure, ever exceeds the values 
listed in Table G.1 of Annex G, the operator will have to upgrade the 
flow computer to use the latest calculation methodology in API 14.3.3 
(2013). The BLM does not believe this restriction will result in 
significant cost to operators. The easiest and cheapest remedy for a 
high differential pressure to static pressure ratio is to install a 
larger orifice plate which will reduce the differential pressure and 
reduce the differential pressure to static pressure ratio below the 
limits in Table G.1.
    The BLM did not grandfather the supercompressibility calculations 
for low-volume FMPs that use the older PRCI NX-19 equation because the 
BLM does not know whether the use of that equation results in 
statistically significant bias. In addition, the latest AGA Report No. 
8 calculation has been available since 1992 and it is highly unlikely 
that any new or existing flow computer at a low-volume FMP would still 
be running the PRCI NX-19 calculations.
    Very-low-volume FMPs only need to meet the verifiability 
requirements under Sec.  3175.31(c). While the older calculation 
methodologies described above can result in higher uncertainty and 
statistically significant bias, the calculations are verifiable. 
Therefore, the BLM added Sec.  3175.61(b)(1), which grandfathers 
existing very-low-volume FMPs from having to having to meet the 
calculation standards of Sec.  3175.103(a)(1). However, existing very-
low-volume FMPs must still run the calculations methodologies listed

[[Page 81556]]

previously. As with low-volume FMPs, the BLM did not see any rationale 
to exempt all very-low-volume FMPs (new and existing) from the 
calculation requirements of Sec.  3175.103(a)(1) because virtually all 
flow computers installed at new FMPs will comply with Sec.  
3175.103(a)(1).
    One commenter suggested that if the BLM agreed to grandfather 
existing facilities, the operator could add 0.1 percent to the volume 
measured by the FMP to ensure the Federal Government or Indian tribes 
did not get shortchanged as a result of any inaccuracies in the 
existing equipment. The BLM disagrees with this comment. The BLM's goal 
in promulgating this rule is to ensure that the Federal Government and 
Indian tribes receive their fair share of royalty on the gas removed 
from their leases, based on accurate measurement, not to increase 
royalty payments. There is no reason to think that the royalty 
measurement problems this rule aims to address--inaccuracy, non-
verifiability, and bias--result in a systematic 0.1 percent 
underestimate of volumes produced; \9\ adding 0.1 percent to volume 
measurements would therefore do little to ensure receipt of fair 
royalties. On the contrary, this approach would merely add another 
source of inaccuracy. The BLM did not make any changes to the rule 
based on this comment.
---------------------------------------------------------------------------

    \9\ The BLM notes that this rule eliminates two sources of 
potential bias: (1) Reporting heating values as ``wet;'' and (2) 
Failing to account for the liquids that exist in the gas sample. The 
bias caused by reporting heating value as ``wet'' can be as high as 
1.74 percent, far greater than the 0.1 percent suggested by the 
commenter. The BLM has no data to ascertain the potential bias 
caused by the elimination of liquids in a gas sample, but believes 
it could be significant.
---------------------------------------------------------------------------

    Some commenters stated that all very-low-volume wells should be 
automatically grandfathered. While the BLM does not provide a blanket 
grandfathering for all existing very-low-volume FMPs, the provisions of 
the final rule provide the same outcome. EGM software at very-low-
volume FMPs is specifically grandfathered. In addition, all very-low-
volume FMPs, existing and new, are exempt from many of the requirements 
of the rule, including those relating to uncertainty and bias, fluid 
conditions, Beta ratio limits, orifice plate inspections for newly 
drilled or re-fractured wells, flow conditioners, meter tube 
construction and condition, differential pen position (mechanical 
recorders), volume corrections, temperature measurement, sample probes 
and sample tubing, gauge lines and manifolds, EGM commissioning, and 
extended analysis. In addition, the BLM raised the very-low/low-volume 
threshold from 15 Mcf/day in the proposed rule to 35 Mcf/day in the 
final rule, which increased the number of FMPs falling within the very-
low-volume category from approximately 21,500 FMPs to 35,700 FMPs. 
Thus, the BLM believes the final rule adequately addresses the 
commenters' concern about costs of compliance at very-low-volume wells.
Sec. 3175.70--Measurement Location
    Section 3175.70 requires prior approval for commingling of 
production with production from other leases, unit PAs, or CAs or non-
Federal properties before the point of royalty measurement and for 
measurement off the lease, unit, or CA (referred to as ``off-lease 
measurement''). The process for obtaining approval is explained in 
subpart 3173. The BLM did not receive any comments on this section.
Sec. 3175.80--Flange-Tapped Orifice Plates (Primary Devices)
General
    Section 3175.80 prescribes standards for the installation, 
operation, and inspection of flange-tapped orifice plate primary 
devices. The standards include requirements described in the rule as 
well as requirements described in API standards that are incorporated 
by reference. Table 1 to Sec.  3175.80 is included to clarify and 
provide easy reference to which requirements would apply to different 
aspects of the primary device and to adopt specific API standards as 
necessary. The first column of Table 1 to Sec.  3175.80 lists the 
subject area for which a standard exists. The second column of Table 1 
to Sec.  3175.80 contains a reference to the standard that applies to 
the subject area described in the first column. For subject areas where 
the BLM adopts an API standard verbatim, the specific API reference is 
shown. For subject areas where there is no API standard or the API 
standard requires additional clarification, the reference in Table 1 to 
Sec.  3175.80 cites the paragraph in the section that addresses the 
subject area.
    The final four columns of Table 1 to Sec.  3175.80 indicate the 
categories of FMPs to which the standard applies. The FMPs are 
categorized by the amount of flow they measure on a monthly basis as 
follows: ``VL'' is very-low volume, ``L'' is low volume, ``H'' is high 
volume, and ``VH'' is very-high volume. Definitions for these various 
classifications are included in the definitions section in Sec.  
3175.10. An ``x'' in a column indicates that the standard listed 
applies to that category of FMP. A number in a column indicates a 
numeric value for that category, such as the maximum number of months 
or years between inspections, and is explained in the body of the 
standard. The requirements of Sec.  3175.80 vary depending on the 
average monthly flow rate being measured. In general, the higher the 
flow rate, the greater the risk of mismeasurement, and the stricter the 
requirements are.
    Section 3175.80 adopts API 14.3.1, Subsection 4.1, which sets out 
requirements for the fluid and flowing conditions that must exist at 
the FMP (i.e., single phase, steady state, Newtonian, and Reynolds 
number greater than 4,000). The term ``single-phase'' means that the 
fluid flowing through the meter consists only of gas. Any liquids in 
the flowing stream will cause measurement error. The requirement for 
single-phase fluid is the same as the requirement for fluid of a 
homogenous state in AGA Report No. 3 (1985), paragraph 14.3.5.1. The 
term ``steady-state'' means that the flow rate is not changing rapidly 
with time. Pulsating flow that may exist downstream of a piston 
compressor is an example of non-steady-state flow because the flow rate 
is changing rapidly with time. Pulsating or non-steady-state flow will 
also cause measurement error. The requirement for steady-state flow in 
the rule is essentially the same as the requirement to suppress 
pulsation in the AGA Report No. 3 (1985), paragraph 14.3.4.10.3. The 
term ``Newtonian fluid'' refers to a fluid whose viscosity does not 
change with flow rate. The requirement for Newtonian fluids in the rule 
is not specifically stated in the AGA Report No. 3 (1985); however, all 
gases are generally considered Newtonian fluids.
    The Reynolds number is a measure of how turbulent the flow is. 
Rather than expressed in units of measurement, the Reynolds number is 
the ratio of inertial forces (flow rate, relative density, and pipe 
size) to viscous forces. The higher the flow rate, relative density, or 
pipe size, the higher the Reynolds number. High viscosity, on the other 
hand, acts to lower the Reynolds number. At a Reynolds number below 
2,000, fluid movement is controlled by viscosity and the fluid 
molecules tend to flow in straight lines parallel to the direction of 
flow (generally referred to as laminar flow). At a Reynolds number 
above 4,000, fluid movement is controlled by inertial forces, with 
molecules moving chaotically as they collide with other molecules and 
with the walls of the pipe (generally referred to as turbulent flow). 
Fluid behavior between a Reynolds number of 2,000 and 4,000 is 
difficult to predict. For most meters

[[Page 81557]]

using the principle of differential pressure, including orifice meters, 
the flow equation is based on an assumption of turbulent flow with a 
Reynolds number greater than 4,000.
    Using a typical gas viscosity of 0.0103 centipoise and 0.7 relative 
density, a Reynolds number of 4,000 is achieved at a flow rate of 5.8 
Mcf/day in a 2-inch diameter pipe, 8.7 Mcf/day in a 3-inch diameter 
pipe, and 11.6 Mcf/day in a 4-inch diameter pipe. The majority of pipe 
sizes currently used at FMPs are between 2 and 4 inches in diameter. 
Because low-, high-, and very-high-volume FMPs all exceed 35 Mcf/day by 
definition, all FMPs within these categories and with line sizes of 4 
inches or less, would operate at Reynolds numbers well above 4,000. 
Very-low-volume FMPs would be exempt from this requirement. Therefore, 
the requirement to maintain a Reynolds number greater than 4,000 does 
not represent a significant change from existing conditions. The 
requirement for maintaining a Reynolds number greater than 4,000 for 
low-, high-, and very-high-volume FMPs will help ensure the accuracy of 
measurement in rare situations where the pipe size is greater than 4 
inches or flowing conditions are significantly different from the 
conditions used in the examples above.
    Very-low-volume FMPs could fall below this limit, but are exempt 
from the Reynolds number requirement. While the BLM recognizes that 
measurement error could occur at FMPs with Reynolds numbers below 
4,000, it would be uneconomic to require a different type of meter to 
be installed at very-low-volume FMPs. The BLM recognizes that not 
maintaining the fluid and flowing conditions recommended by API can 
cause significant measurement error. However, the measurement error at 
such low flow rates will not significantly affect royalty, and the 
potential error in royalty is small compared to the potential loss of 
royalty if production were shut in. The BLM did not receive any 
comments on the adoption of API 14.3.1, Subsection 4.1, regarding 
required fluid and flowing conditions.
    Section 3175.80 adopts API 14.3.2, Section 4, which establishes 
requirements for orifice plate construction and condition. Orifice 
plate standards in API 14.3.2, Section 4 are virtually the same as they 
are in the AGA Report No. 3 (1985). There are no exemptions to this 
requirement, since the cost of obtaining compliant orifice plates for 
most sizes used at FMPs (2-inch, 3-inch, and 4-inch) is minimal and 
orifice plates not complying with the API standards can cause 
significant bias in measurement. The BLM did not receive any comments 
on the adoption of API 14.3.2, Section 4 regarding orifice plate 
construction and condition.
    Proposed Sec.  3175.80 would have adopted API 14.3.2, Subsection 
6.2, regarding orifice plate eccentricity for all categories of FMPs. 
As noted earlier in this preamble, the term ``eccentricity'' refers to 
the centering of the orifice plate in the meter tube. Eccentricity can 
affect the flow profile of the gas through the orifice and larger Beta 
ratio meters (i.e., meters with larger-diameter orifice bores relative 
to the diameter of the meter tube) are more sensitive to flow profile 
than smaller Beta ratio meters. For that reason, larger Beta ratio 
meters have a smaller eccentricity tolerance. In the proposed rule, the 
BLM specifically asked for data on the cost of this retrofit and on the 
number of meters that it may affect. The BLM received one comment 
objecting to the application of orifice plate eccentricity requirements 
to low- and very-low-volume FMPs. The commenter suggested that low- and 
very-low-volume FMPs should be exempt from this requirement because the 
only way to achieve this for older meter runs built to the 1985 API 
standards would be to replace the meter tube. The commenter stated that 
this would provide little benefit and would be cost prohibitive for 
these lower-volume meters. The BLM agrees with this comment and made 
several changes to the rule as a result. For very-low-volume FMPs, the 
BLM changed Table 1 to Sec.  3175.80 to reflect that these FMPs are 
exempt from the eccentricity and perpendicularity requirements of API 
14.3.2, Section 6.2. For low-volume FMPs, the rule grandfathers meter 
tubes existing at FMPs as of January 17, 2017 from meeting the 
eccentricity requirements of API 14.3.2, Subsection 6.2. However, the 
meter tube would still have to meet the eccentricity requirements of 
AGA Report No. 3 (1985) (see discussion of grandfathering under Sec.  
3175.61). The grandfathering also includes high-volume FMPs. Although 
this was not addressed in the comments, the BLM Threshold Analysis 
determined that it may be uneconomic to require operators to replace 
existing meter tubes at high-volume FMPs. All meter tubes at very-high-
volume FMPs must meet the API 14.3.2, Subsection 6.2 standards for 
eccentricity.
    Table 1 also requires the orifice plate to be installed 
perpendicularly to the meter tube axis as required in API 14.3.2, 
Subsection 6.2. Virtually all orifice plate holders, new and existing, 
maintain perpendicularity between the orifice plate and the meter-tube 
axis. The BLM did not receive any comments regarding the 
perpendicularity requirement.
Sec. 3175.80(a)
    Section 3175.80(a) defines the allowable Beta ratio range for 
flange-tapped orifice meters to be between 0.10 and 0.75, as 
recommended by API 14.3.2. The previous industry standard for orifice 
meters (AGA Report No. 3 (1985)) established a Beta ratio range between 
0.15 and 0.70. In the early 1990s, additional testing was done on 
orifice meters, which resulted in an increased Beta ratio range and a 
more robust characterization of the uncertainty of orifice meters over 
this range. The testing also showed that a meter with a Beta ratio less 
than 0.10 could result in higher uncertainty due to the increased 
sensitivity of upstream edge sharpness. Meters with Beta ratios greater 
than 0.75 exhibited increased uncertainty due to flow profile 
sensitivity.
    This section also applies the Beta ratio limits to low-volume FMPs. 
The elimination of statistically significant bias is one of the 
performance goals that applies to low-volume FMPs, and we know of no 
data showing that bias is not significant for Beta ratios less than 
0.10. Generally, if edge sharpness cannot be maintained, it results in 
a measurement that is biased to the low side. The low limit for the 
Beta ratio in API 14.3.2 is based on the inability to maintain edge 
sharpness in Beta ratios below 0.10. Therefore, if the BLM were to 
allow Beta ratios lower than 0.10 at low-volume FMPs, there would be 
the potential for bias.
    While the increased sensitivity to flow profile due to Beta ratios 
greater than 0.75 does not generally result in bias (only an increase 
in uncertainty), this section also maintains the upper Beta ratio limit 
in API 14.3.2 for low-volume FMPs. It is very rare for an operator to 
install a large Beta ratio orifice plate on low-volume meters.
    Very-low-volume FMPs are exempt from any Beta ratio restrictions in 
the rule, as indicated in Table 1 to Sec.  3175.80, because at very-low 
flow rates, it can be difficult to obtain a measureable amount of 
differential pressure with a Beta ratio of 0.10 or greater. The 
increased uncertainty and potential for bias associated with allowing a 
Beta ratio less than 0.10 on very-low-volume FMPs is offset by the 
ability to accurately measure a differential pressure and record flow.
    The BLM received a few comments that stated that the Beta ratio 
range should be more restrictive, and recommended a range of 0.20 to 
0.60 in

[[Page 81558]]

order to minimize uncertainty. One commenter stated that Beta ratios 
over 0.60 can cause the meter to over-register, although the commenter 
did not supply any data to substantiate this claim. The BLM did not 
make any changes to the rule based on this comment. The BLM is not 
aware of any data that suggest that Beta ratios over 0.60 will cause a 
meter to over-register. The BLM is aware that the uncertainty of a 
flange-tapped orifice plate increases if the Beta ratio is below 0.2 or 
is greater than 0.6. The uncertainty of a flange-tapped orifice plate 
as a function of both Beta ratio and Reynolds number is well understood 
and well documented. The final rule sets an overall uncertainty 
performance standard that the BLM enforces using the BLM uncertainty 
calculator. The performance standard allows an operator to offset the 
higher uncertainties at low or high Beta ratios by reducing the 
uncertainty of other components of the metering system such as the 
differential and static-pressure transducers. This allows operators 
more flexibility. The BLM does not believe that setting uncertainty 
standards for individual components of the metering system is workable 
or desirable. The BLM also notes that the minimum orifice plate size of 
0.45 inches, as required in Sec.  3175.80(b), effectively raises the 
minimum Beta ratio allowed under this rule for high- and very-high-
volume FMPs. For 2-inch meter tubes, the effective minimum Beta ratio 
is 0.22; for 3-inch meter tubes, the effective minimum Beta ratio is 
0.15; and for 4-inch meter tubes, the effective minimum Beta ratio is 
0.11.\10\
---------------------------------------------------------------------------

    \10\ These values were derived by dividing the minimum allowable 
orifice bore diameter of 0.45 inches by typical internal diameters 
of 2-inch, 3-inch, and 4-inch meter tubes (2.067 inches, 3.068 
inches, and 4.026 inches, respectively).
---------------------------------------------------------------------------

Sec. 3175.80(b)
    Section 3175.80(b) establishes a minimum orifice bore diameter of 
0.45 inches for high-volume and very-high-volume FMPs. API 14.3.1, 
Subsection 12.4.1 states: ``Orifice plates with bore diameters less 
than 0.45 inches . . . may have coefficient of discharge uncertainties 
as great as 3.0 percent. This large uncertainty is due to problems with 
edge sharpness.'' Because the uncertainty of orifice plates less than 
0.45 inches in diameter has not been specifically determined, the BLM 
cannot mathematically account for it when calculating overall 
measurement uncertainty under proposed Sec.  3175.31(a). To ensure that 
high- and very-high-volume FMPs maintain the uncertainty required in 
Sec.  3175.31(a), the BLM is prohibiting the use of orifice plates with 
bores less than 0.45 inches in diameter. Because there is no evidence 
to suggest that the use of orifice plates smaller than 0.45 inches in 
diameter causes measurement bias in low-volume and very-low-volume 
FMPs, they are allowed for use in these FMPs.
    The BLM received several comments stating that this requirement 
should not apply to existing meters because it could force the operator 
to replace meter tubes in order to comply with Beta ratio requirements. 
The BLM does not understand why this requirement would necessitate 
replacing existing meter tubes and the commenters did not provide an 
explanation. One commenter stated that an orifice bore less than 0.45 
inches is sometimes necessary in meters operating at the low end of the 
high-volume FMP category to raise the differential pressure to provide 
better measurement accuracy. The BLM disagrees with this comment. Even 
using the minimum high-volume FMP flow rate of 100 Mcf/day in the 
proposed rule, a 0.50-inch orifice plate (orifice plates are typically 
provided in 0.125-inch increments) would generate a differential 
pressure of 23 inches of water column,\11\ which would be high enough 
in most cases to achieve an overall measurement uncertainty of 3 percent as required in Sec.  3175.31(a). Because the BLM raised 
this threshold to 200 Mcf/day in the final rule, a 0.50-inch orifice 
plate would generate 92 inches of differential pressure using the same 
assumptions. In other words, there is no reason that an operator would 
have to use an orifice plate less than 0.45 inches with a high- or 
very-high-volume FMP. The BLM did not make any changes to the final 
rule based on this comment.
---------------------------------------------------------------------------

    \11\ Assumes a relative density of 0.7 and a static pressure of 
200 psia.
---------------------------------------------------------------------------

Sec. 3175.80(c)
    Section 3175.80(c) requires orifice plate inspections upon 
installation and then every 2 weeks thereafter for FMPs measuring 
production from wells first coming into production or from existing 
wells that have been re-fractured. It is common for new wells and re-
fractured wells to produce high amounts of sand, grit, and other 
particulate matter for some initial period of time. This material can 
quickly damage an orifice plate, generally causing measurement to be 
biased low. This requirement increases the orifice plate inspection 
frequency until it can be demonstrated that the production of 
particulate matter from a new well first coming into production or a 
re-fractured well has subsided. The once-every-2-week inspection 
requirement also applies to existing FMPs already measuring production 
from one or more other wells, which measures gas from a new well first 
coming into production or from a well that has been re-fractured.
    Under this rule, once an inspection demonstrates that no detectable 
wear occurred over the previous 2 weeks, the BLM will consider the well 
production to have stabilized and the inspection frequency will revert 
to the frequency in Table 1 to Sec.  3175.80. There are no exemptions 
for this requirement because: (1) Based on the BLM's experience, 
pulling and inspecting an orifice plate generally takes less than 30 
minutes and is a low-cost operation; and (2) In most cases, the new 
requirement will not apply to very-low-volume FMPs anyway because 
rarely would a newly drilled well have only very-low-volume levels of 
gas production.
    The BLM received several comments objecting to the once-every-2-
week inspection requirement. One commenter stated that this frequency 
of inspections is not necessary unless there is evidence of plate 
degradation, while other commenters suggested the inspection frequency 
should be monthly instead of every 2 weeks. The BLM disagrees with 
these comments. The only way an operator would know if there was 
evidence of plate degradation is to pull and inspect the orifice plate. 
The BLM believes that orifice plate inspections every 2 weeks are 
important considering how much a dulled edge on an orifice plate can 
bias the measured flow rate, usually to the low side. Although the BLM 
did not make any changes to the inspection requirement, very-low-volume 
FMPs are no longer subject to this requirement because bias is not one 
of the performance criteria for the very-low-volume category.
    The BLM received one comment stating that assessing whether there 
has been wear over the previous 2 weeks in order to determine if an 
orifice plate change is still necessary is subjective and recommended 
that the BLM provide guidance and training for BLM inspectors. Although 
the BLM does not agree that assessing an orifice plate is subjective, 
the BLM does agree that guidance and training are necessary. The BLM 
will include additional guidance in the enforcement handbook. The 
comment did not suggest any changes to the rule. The BLM did not make 
any changes to the rule based on this comment.
    Several commenters objected to the proposed requirement that an 
operator must determine whether the orifice plate meets the 
eccentricity

[[Page 81559]]

requirements of API 14.3.2, Subsection 6.2, during an orifice plate 
inspection under this paragraph. The commenters stated that 
eccentricity can only be determined during a detailed meter tube 
inspection. The BLM agrees with this comment and moved the eccentricity 
requirement from this paragraph to the detailed meter tube inspection 
paragraph (see Sec.  3175.80(i)).
    The BLM added a phrase to the proposed rule, clarifying that the 
BLM considers a well that has been re-fractured to have the same impact 
on an orifice plate that a new well has, and therefore to require 
inspections every 2 weeks for re-fractured wells. Like new wells, re-
fractured wells produce tremendous amounts of sand and grit during flow 
back and this sand and grit have the potential to quickly dull an 
orifice plate in the same manner as the sand and grit produced from a 
new well.
Sec. 3175.80(d)
    Section 3175.80(d) establishes a frequency for routine orifice 
plate inspections. The term ``routine'' in Table 1 to Sec.  3175.80 is 
used to differentiate this requirement from Sec.  3175.80(c) of this 
rule, which is related to new FMPs measuring production from new and 
re-fractured wells. Under this rule, the inspection frequency depends 
on the flow rate category the FMP is in. The required inspection 
frequency, in months, is given in Table 1 to Sec.  3175.80. More than 
any other component of the metering system, orifice plate condition has 
one of the highest potentials to introduce measurement bias and create 
error in royalty calculations. The higher the flow rate being measured, 
the greater the risk to ongoing measurement accuracy. Therefore, the 
higher the flow rate, the more often orifice plate inspections are 
required. For high-volume and very-high-volume FMPs, the frequency of 
orifice plate inspections is every 3 months and every month, 
respectively. For very-low-volume FMPs, the frequency is every 12 
months; and for low-volume FMPs, the frequency is every 6 months.
    The BLM received multiple comments both criticizing and supporting 
the routine orifice plate inspection frequency required in Sec.  
3175.80(d). Those objecting to the requirement stated that the orifice 
plate inspection frequency should be based on need rather than on a 
fixed frequency, while others asserted that the proposed frequency was 
too high. Suggested frequencies include once every 1 or 2 years for all 
FMPs, annually for very-low-volume FMPs, semi-annually for low- and 
high-volume FMPs, and quarterly for very-high-volume FMPs. The BLM 
disagrees with these comments. Orifice plate condition, especially the 
condition of the upstream edge, is perhaps the most critical part of an 
orifice plate metering system. Even slight changes to the upstream edge 
of an orifice plate can cause significant bias in the measured flow 
rate, usually to the low side. The BLM believes that the frequency 
given in the proposed rule strikes a reasonable balance between the 
cost to the operator and the need for measurement accuracy. The BLM did 
not make any changes to the proposed rule based on these comments.
    Two commenters suggested that the proposed schedule would be 
acceptable if the meter was equipped with a senior fitting (a fitting 
where the orifice plate can be removed without shutting off the flow of 
gas through the meter). The BLM accepts that orifice plate inspection 
is much easier and less costly when a senior fitting is used. If an 
operator makes a determination that it is in their best economic 
interest to install a senior fitting, they are free to do so. However, 
the type of plate holder has no bearing on how quickly a plate can 
become worn or dirty or how a worn or dirty orifice plate can affect 
measurement and, ultimately, royalty. The BLM did not make any changes 
to the rule based on this comment.
    One commenter stated that orifice plate and meter tube inspection 
frequency should be left up to the operators, because the requirements 
in the proposed rule were too burdensome. Although the BLM did not make 
any changes to the rule based on this comment, changes to the rule 
based on other comments resulted in an estimated reduction in orifice 
plate and meter tube inspections costs to industry from $6.3 million 
per year in the proposed rule to $5.8 million per year in the final 
rule. The BLM does not consider either of these requirements to be 
overly burdensome.
    One commenter suggested changing the terminology from ``every 3 
months'' and ``every 6 months'' to ``quarterly'' and ``semi-annually'' 
to provide operators more flexibility. The BLM believes specifying the 
number of months between calibrations is clearer than the terminology 
suggested by the commenter. In addition, operators could imply that 
adoption of ``quarterly'' and ``semi-annually'' means an orifice plate 
inspection on a high-volume FMP could be performed at the beginning of 
one quarter and at the end of another quarter (January 1 and June 30, 
for example), which would essentially double the time between 
inspections. The BLM did not make any changes to the rule based on this 
comment.
    In response to other comments on Sec.  3175.100, the BLM changed 
the required verification frequency for high-volume FMPs from once 
every month to once every 3 months (see Table 1 to Sec.  3175.100). 
This change means that routine orifice plate inspections no longer 
correspond to verifications for high-volume FMPs. To address this 
issue, the BLM removed the requirement that routine orifice plate 
inspections have to be performed at the same time an FMP is verified 
under Sec.  3175.92 (mechanical recorders) or Sec.  3175.102 (EGM 
systems).
Sec. 3175.80(e)
    Section 3175.80(e) requires operators to retain, and provide to the 
BLM upon request, documentation about the condition of an orifice plate 
that is removed and inspected. Documentation of the plate inspection 
can be a useful part of an audit trail and can also be used to detect 
and track metering problems. Although this is a new requirement, many 
operators already record this information as part of their meter 
verifications. Thus, this requirement is not a significant change from 
prevailing industry practice. The BLM did not receive any comments on 
this paragraph.
Sec. 3175.80(f)
    Proposed Sec.  3175.80(f) would have required all meter tubes to be 
constructed in compliance with current API standards. This proposed 
requirement would not have included meter tube lengths, which are 
addressed in proposed Sec.  3175.80(k). The BLM has reviewed the API 
standards referenced and believes that they meet the intent of Sec.  
3175.31 of the rule.
    Proposed Sec.  3175.80(f)(1) and (2) would have included an 
exception allowing all low-volume FMPs to continue using the tolerances 
in the AGA Report No. 3 (1985). While the BLM recognizes this could 
result in higher uncertainty than meter tubes meeting the tolerances of 
API 14.3.2, it is not imposing uncertainty requirements for low-volume 
FMPs. In the final rule, this exception is moved to Sec.  3175.61 and 
paragraphs (1) and (2) of proposed Sec.  3175.80(f) were eliminated. 
This means that only existing low-volume FMPs are exempt from the meter 
tube construction standards of API 14.3.2, Subsections 5.1 through 5.4 
(although they must still meet the 1985 AGA Report No. 3 construction 
standards). Under the final rule, low-volume FMPs installed after the 
effective date of this rule must meet

[[Page 81560]]

the standards of API 14.3.2, Subsections 5.1 through 5.4. Very-low-
volume FMPs are exempt from meter tube standards under this paragraph.
    The BLM received numerous comments arguing that existing meter 
tubes should be grandfathered because the only way to comply with the 
new standards is to replace the meter tube, and this would be very 
costly. Some commenters questioned the benefit of replacing existing 
meter tubes. The commenters also suggested that the BLM should hold the 
operator to the meter-tube standard in place at the time the meter tube 
was installed. The BLM agrees with these comments, with respect to low- 
and high-volume FMPs, and has grandfathered existing meter tubes at 
those FMPs (see the discussion under Sec.  3175.61). To account for the 
additional uncertainty that may be present in pre-2000 meter tubes, the 
BLM will add an uncertainty of 0.25 percent to the 
discharge coefficient when determining the overall meter uncertainty, 
unless the operator provides sufficient data to show that the 
additional uncertainty in discharge coefficient when the meter tube is 
constructed to the tolerance of the 1985 standard is less than 0.25 percent (see Sec.  3175.61(a)). The BLM believes that, in 
the absence of data to the contrary, the 0.25 percent 
uncertainty is a reasonable assumption based on its experience with 
orifice plate test data.
Sec. 3175.80(g)
    Section 3175.80(g) addresses isolating flow conditioners and tube-
bundle flow straighteners. To achieve the orifice plate uncertainty 
stated in API 14.3.1, the gas flow approaching the orifice plate must 
be free of swirl and asymmetry. This can be achieved by placing a 
section of straight pipe between the orifice plate and any upstream 
flow disturbances such as elbows, tees, and valves. Swirl and asymmetry 
caused by these disturbances will eventually dissipate if the pipe 
lengths are long enough. The minimum length of pipe required to achieve 
the uncertainty stated in API 14.3.1 is discussed in Sec.  3175.80(k).
    Isolating flow conditioners and tube-bundle flow straighteners are 
designed to reduce the length of straight pipe upstream of an orifice 
meter by accelerating the dissipation of swirl and asymmetric flow 
caused by upstream disturbances. Both devices are placed inside the 
meter tube at a specified distance upstream of the orifice plate. An 
isolating flow conditioner consists of a flat plate with holes drilled 
through it in a geometric pattern designed to reduce swirl and 
asymmetry in the gas flow. A tube bundle is a collection of tubes that 
are welded together to form a bundle.
    Section 3175.80(g) allows isolating flow conditioners to be used at 
FMPs if they have been approved by the BLM pursuant to Sec.  3175.46 of 
this rule, or 19-tube-bundle flow straighteners constructed in 
compliance with API 14.3.2, Subsections 5.5.2 through 5.5.4, and 
located in compliance with API 14.3.2, Subsection 6.3. Use of 19-tube-
bundle flow straighteners constructed and installed under these API 
standards does not require BLM approval. The rule requires a tube-
bundle flow straightener, if used, to comply with API 14.3.2, 
Subsections 5.5.2 through 5.5.4 and 6.3, because data have shown that 
these installations produce almost no additional uncertainty of the 
discharge coefficient and the small amount of additional uncertainty is 
accounted for in the determination of overall uncertainty. This rule 
prohibits the use of 7-tube-bundle flow straighteners, which are used 
primarily in 2-inch meters. Additionally, 19-tube-bundle flow 
straighteners are typically not available in a 2-inch size for these 
existing meters. A significant number of the meters in use currently 
are 2-inch meters. Without the ability to use either 7- or 19-tube-
bundle flow straighteners, 2-inch meters are required to be retrofitted 
to either: (1) Use a proprietary type of isolating flow conditioner 
approved in accordance with Sec.  3175.46; or (2) Not have a flow 
conditioner, which typically requires much longer lengths of pipe 
upstream of the orifice plate. The rule's requirements with respect to 
isolating flow conditioners will increase consistency and eliminate the 
time and expense it takes to apply for and obtain a variance for each 
FMP.
    As indicated in Table 1 to Sec.  3175.80, very-low-volume FMPs are 
exempt from the requirement to retrofit because the costs involved are 
believed to outweigh the benefits based upon experience with these 
production levels.
    A few comments on the proposed rule indicated that replacing 7-tube 
bundles on 2-inch meter tubes will be costly, and suggested that the 
BLM grandfather meter tubes that comply with the API standard in place 
when the meter tube was installed. Although the BLM has grandfathered 
existing meter tubes for perpendicularity, eccentricity, construction 
and condition, and meter tube length, the BLM did not grandfather 
existing flow conditioners, including tube bundles on low-, high-, and 
very-high-volume FMPs. While the grandfathering of the other meter tube 
aspects can increase the uncertainty of an orifice plate meter, the BLM 
is not aware of any evidence that they cause bias in the measurement. 
The design of tube-bundle flow straighteners can, however, cause bias. 
Because the elimination of statistically significant bias is one of the 
performance standards in Sec.  3175.31 for low-, high-, and very-high-
volume FMPs, the BLM did not make any changes in the final rule based 
on these comments. The BLM does not believe that requiring existing 
meter tubes to comply with the new API standards for the design of tube 
bundles is cost-prohibitive. If the meter tube has a 7-tube bundle, or 
a tube bundle that does not comply with API 14.3.2, Subsections 5.5.2 
through 5.5.4, the operator can replace the tube bundle with an 
isolating flow conditioner for a few hundred dollars. If the meter tube 
has an isolating flow conditioner that has not been approved by the 
BLM, then the operator can replace that isolating flow conditioner with 
one that has been approved by the BLM. If the operator uses a 19-tube 
bundle that is located in accordance with the 1985 AGA standard, the 
BLM deems that this will also comply with the requirements of API 
14.3.2, Subsection 6.3 if the Beta ratio is less than 0.5 (see the 
discussion under Sec.  3175.80(k)).
Sec. 3175.80(h)
    Proposed Sec.  3175.80(h) would have required an internal visual 
inspection of all meter tubes at the frequency, in years, shown in 
Table 1 to Sec.  3175.80. The visual inspection would have had to be 
conducted using a borescope or similar device (which would obviate the 
need to remove or disassemble the meter run), unless the operator 
decided to disassemble the meter run to conduct a detailed inspection, 
which also would meet the requirements of this proposed paragraph. 
While an inspection using a borescope or similar device cannot ensure 
that the meter tube complies with API 14.3.2 requirements, it can 
identify issues, such as pitting, scaling, and buildup of foreign 
substances that could warrant a detailed inspection under Sec.  
3175.80(i) of the proposed rule.
    The BLM received many comments stating that borescopes are 
expensive and have potential safety hazards due to the explosive 
environment in which they operate. The BLM agrees that the use of 
borescopes could require additional safety measures and could cause 
operators to incur significant costs. As a result of these comments, 
the BLM eliminated the reference to borescopes and made the standards 
entirely performance-based. The BLM also changed the name of the 
requirement to a ``basic inspection''

[[Page 81561]]

instead of a ``visual inspection'' in the proposed rule. This 
requirement provides that the operator must conduct a ``basic 
inspection that is able to identify obstructions, pitting, and buildup 
of foreign substances (e.g., grease and scale).'' This change will 
allow the operator to use other methods to meet the performance goal. 
For example, there may be ultrasonic devices on the market that 
operators could use externally to meet the intent of this requirement, 
without incurring the safety risks associated with borescopes. The BLM 
believes that this requirement may also inspire new technology to 
accomplish the goals of this requirement safely and cost effectively.
    The BLM received several comments addressing the cost burden of 
performing basic inspections, although no cost figures were included 
with the comments. The BLM did not make any changes to the proposed 
rule based on these comments because the BLM believes that basic 
inspections can be done at relatively little cost. These costs are 
included in the BLM Threshold Analysis and in the Economic and 
Threshold Analysis.
    Several commenters suggested that the BLM should require a visual 
inspection only if an orifice plate inspection indicated problems, and 
that the BLM should train inspectors to recognize when a visual 
inspection is needed. While the BLM agrees that orifice plate 
inspections can give some indication as to meter tube problems (such as 
liquid and grease buildup), they are not reliable. For example, if 
debris plugged a flow conditioner or a tube-bundle flow straightener, 
this could have a significant effect on the accuracy of the meter and 
would not be detected by merely pulling and inspecting the orifice 
plate. The BLM did not make any changes to the proposed rule based on 
these comments.
    One commenter stated that shutting in wells to perform visual 
inspections could cause reservoir damage and lower royalty. While there 
is always some possibility of reservoir damage when shutting in a well, 
the BLM does not believe this risk is significant enough to warrant the 
elimination of this requirement. If that were the case, then wells 
could never be shut in for orifice plate inspections or other routine 
maintenance. The commenter did not provide any data or studies to 
substantiate their claim. If an operator demonstrated that this was an 
issue for a particular well, they could request a variance from the AO. 
The BLM did not make any changes based on this comment.
    Numerous comments objected to the frequency of visual inspections 
as proposed in Table 1 to Sec.  3175.80. Suggestions for inspection 
frequency ranged from every 3 years to every 10 years. The BLM did not 
make any changes to the rule based on these comments because none of 
the commenters submitted a rationale for their suggested frequencies. 
The BLM believes the frequencies presented in the proposed rule 
represent a balance between economic considerations and ensuring 
accurate measurement of Federal and Indian gas resources.
    The BLM removed paragraph (h)(5) of the proposed rule out of 
concern that operators could have misinterpreted it to mean that a 
detailed inspection would have been required to meet the standards of a 
basic inspection. Any type of inspection that can identify 
obstructions, pitting, and a build-up of foreign substances qualifies 
as a basic inspection, which includes a detailed inspection as 
described in paragraph (i) of this section. However, a detailed 
inspection is not required to meet the standards under Sec.  
3175.80(h).
Sec. 3175.80(i)
    Proposed Sec.  3175.80(i) would have required a detailed inspection 
of meter tubes on high- and very-high-volume FMPs at the frequency, in 
years, shown in Table 1 to Sec.  3175.80 (10 years for high-volume FMPs 
and 5 years for very-high-volume FMPs). Under the proposed rule, the AO 
could have increased this frequency, and could have required a detailed 
inspection of low-volume FMPs, if the visual inspection identified any 
issues regarding compliance with incorporated API standards, or if the 
meter tube operated in adverse conditions (such as corrosive or erosive 
gas flow), or had signs of physical damage. The goal of the inspection 
is to determine whether the meter is in compliance with required 
standards for meter-tube construction. Meter tube inspections would 
have been required more frequently for very-high-volume FMPs because 
there is a higher risk of volume errors and, therefore, royalty errors 
in higher-volume FMPs. Very-low-volume FMPs would have been exempt from 
the inspection requirement because they would be exempt from the 
construction standards of API 14.3.2.
    Several commenters indicated that detailed meter tube inspections 
are expensive and present safety issues. Other commenters suggested 
that the BLM should only require a detailed inspection if the visual 
inspection indicated it was warranted. Several commenters objected to a 
single visual inspection leading to a frequency change in the number of 
detailed inspections on an FMP. Several commenters suggested that the 
proposed detailed meter tube inspection frequency was inadequate. The 
BLM agrees with the comments and made several changes to this paragraph 
as a result. First, the BLM eliminated routine detailed inspections; 
under the final rule, the BLM will require a detailed inspection only 
if the findings from a basic inspection warrant a detailed inspection. 
Second, if a basic inspection reveals the presence of obstructions or 
buildup of material at a low-volume FMP, the operator will only have to 
clean the meter tube. For high-volume FMPs, the operator must ensure 
the meter tube meets all the relevant standards relating to meter tubes 
before returning the meter to service. For meter tubes installed after 
January 17, 2017, the relevant standard is API 14.3.2, Subsections 5.1 
through 5.4 and 6.2, incorporated by reference in this rule. For meter 
tubes installed before January 17, 2017, the relevant standard is AGA 
Report No. 3, which has been incorporated by reference in this rule. 
For very-high-volume FMPs, regardless of when they were installed, the 
operator must ensure the meter tube complies with the applicable 
provisions of API 14.3.2, incorporated by reference in this rule.
    One commenter objected to detailed meter tube inspections under any 
circumstance, while another commenter recommended that the BLM could 
adjust the frequency of both basic and detailed meter tube inspections 
based on the findings of previous inspections. The BLM did not make any 
changes to the rule based on these comments. The BLM believes detailed 
inspections are required to ensure accurate measurement. While the BLM 
agrees that an operator could justify a change in the frequency in 
certain instances, this should be handled through the variance process 
on a case-by-case basis.
Sec. 3175.80(j)
    Section 3175.80(j) requires operators to keep documentation of all 
detailed meter tube inspections to be made available to the BLM upon 
request. The BLM will use this documentation to establish that the 
inspections meet the requirements of the rule, for auditing purposes, 
and to track the rate of change in meter tube condition to support an 
operator's request for a change of inspection frequency. Very-low-
volume FMPs are exempt from this requirement because no meter tube 
inspections are required. The BLM did not receive any

[[Page 81562]]

comments on this requirement in the proposed rule.
Sec. 3175.80(k)
    Proposed Sec.  3175.80(k) would have incorporated the standards of 
API 14.3.2 for the length of meter tubes upstream and downstream of the 
orifice plate, and for the location of tube-bundle flow straighteners, 
if they are used (see previous discussion of swirl and asymmetry in 
Sec.  3175.80(g)). As indicated in Table 1 to Sec.  3175.80, very-low-
volume FMPs are exempt from the meter tube length requirements because 
the costs involved in retrofitting the meter tubes are believed to 
outweigh the benefits based on experience with these production levels.
    The pipe length requirements in AGA Report No. 3 (1985) 
(incorporated by reference in Order 5) were based on orifice plate 
testing done before 1985. In the early 1990s, extensive additional 
testing was done to refine the uncertainty and performance of orifice 
plate meters. This testing revealed that the recommended pipe lengths 
in the AGA Report No. 3 (1985) were generally too short to achieve the 
stated uncertainty levels, especially when the Beta ratio is 0.5 or 
greater. In addition, the testing revealed that tube bundles placed in 
accordance with the 1985 AGA Report No. 3 could bias the measured flow 
rate by several percent.
    When API 14.3.2 was published in 2000 (and later updated in 2016), 
it used the additional test data to revise the meter tube length and 
tube-bundle location requirements to achieve the stated levels of 
uncertainty and remove bias. All meter tubes installed after the 
publication of API 14.3.2 in 2000 should already comply with the more 
stringent requirements for meter tube length and tube-bundle placement.
    Because the meter tube lengths in API 14.3.2 are required to 
achieve the stated uncertainty, Sec.  3175.80(k)(1) would have adopted 
these lengths as a minimum standard for high-volume and very-high-
volume FMPs. Due to the high-production decline rates in many Federal 
and Indian wells, the BLM does not expect a significant number of 
meters that were installed before 2000, under the AGA Report No. 3 
(1985) standards, to still be measuring gas flow rates that would place 
them in the high-volume or very-high-volume categories. However, the 
BLM Threshold Analysis shows that it would be uneconomic for operators 
of high-volume FMPs to retrofit the meter tubes to comply with the 
length requirements in API 14.3.2. Therefore, the final rule 
grandfathers the meter tube length requirements for the anticipated 
handful of high-volume FMPs existing before the effective date of the 
rule (see Sec.  3175.61(a)) that continue to measure high-volume flow 
rates of gas even after 16 years of production (from 2000 to 2016). 
These grandfathered FMPs would still have to meet the meter tube length 
requirements of AGA Report No. 3 (1985). If the meter tube contains a 
19-tube bundle flow straightener or isolating flow conditioner, the 
location of that straightener or flow conditioner will not be 
grandfathered and will still have to comply with Sec.  3175.80(g). The 
meter tubes at very-high-volume FMPs were not grandfathered in the 
final rule.
    While low-volume FMPs would not be subject to the uncertainty 
requirements under Sec.  3175.31(a), they still would have to be free 
of statistically significant bias under Sec.  3175.31(c). Because 
testing has shown that placement of tube-bundle flow straighteners in 
conformance with the AGA Report No. 3 (1985) can cause bias, low-volume 
FMPs utilizing tube-bundle flow straighteners also would have been 
subject to the meter tube length requirements of API 14.3.2 under 
proposed Sec.  3175.80(k)(1).
    While this may require some retrofitting of existing meters, the 
BLM does not expect this to be a significant change for three reasons. 
First, FMPs installed after 2000 should already comply with the meter 
tube length and tube-bundle placement requirements of API 14.3.2. 
Second, based on the BLM's experience, we estimate that fewer than 25 
percent of existing meters use tube-bundle flow straighteners. Third, 
for those FMPs that would need to be retrofitted, most operators would 
opt to remove the tube-bundle-flow straightener and replace it with an 
isolating flow conditioner. Several manufacturers make a type of 
isolating flow conditioner designed to replace tube bundles without 
retrofitting the upstream piping. These flow conditioners are 
relatively inexpensive and would not create an economic burden on the 
operator for low-volume FMPs. The BLM received many comments requesting 
that the BLM grandfather existing meter tubes from the meter tube 
length requirements of this paragraph due to the high cost and 
questionable benefit of this requirement. The commenters also suggested 
that the BLM should hold the operator to the meter tube standard in 
place at the time the meter tube was installed. The BLM agrees with 
these comments and has grandfathered existing meter tubes at low- and 
high-volume FMPs (see discussion under Sec.  3175.61). To account for 
the additional uncertainty that may be present on pre-2000 meter tubes, 
the BLM will add an uncertainty of 0.25 percent to the 
discharge coefficient when determining the overall meter uncertainty, 
unless the operator provides sufficient data to show that the 
additional uncertainty in discharge coefficient when the meter tube is 
constructed to the tolerances of the 1985 standard is less than 0.25 percent. The BLM believes that, in the absence of data to 
the contrary, the 0.25 percent uncertainty is a reasonable 
assumption based on its experience with orifice plate test data.
    Proposed Sec.  3175.80(k)(2) would have allowed low-volume FMPs 
that do not have tube-bundle flow straighteners to comply with the 
less-stringent meter tube length requirements of the AGA Report No. 3 
(1985). For those meter tubes that do not include tube-bundle flow 
straighteners, the BLM is not currently aware of any data that show the 
shorter meter tube lengths required in the AGA Report No. 3 (1985) 
result in statistically significant bias.
    The BLM received numerous comments requesting that the BLM 
grandfather existing meter tubes from the tube bundle location 
requirements of this paragraph, based on API 14.3.2. Test data have 
shown that statistically significant measurement bias can occur if the 
19-tube-bundle straightening vane is placed at the location required by 
the 1985 API standard. Because low-, high-, and very-high-volume FMPs 
are subject to the performance standard in Sec.  3175.31(c), which 
prohibits statistically significant bias, the BLM did not grandfather 
flow conditioners, including the required location of 19-tube bundle 
flow straighteners. However, the BLM has determined that the tube-
bundle placement requirements in the 1985 API standards are generally 
consistent with the tube-bundle placement requirements in the 2000 API 
standards for Beta ratios less than 0.5. Therefore, the BLM has revised 
this paragraph to make it clear that the BLM considers tube bundles 
installed under the 1985 standard to be in compliance with the 2000 
standard when the Beta ratio is less than 0.5. In addition, the BLM 
moved the meter tube length requirements for existing FMPs from this 
paragraph to the grandfathering section (see Sec.  3175.61(a)).
Sec. 3175.80(l)
    Section 3175.80(l) sets standards for thermometer wells, including 
the adoption of API 14.3.2, Subsection 6.5, in Sec.  3175.80(l)(1). 
While the provisions of the API standard proposed for adoption in the 
proposed rule were the same as those in the AGA Report No. 3, several 
additional items would have

[[Page 81563]]

been required. First, proposed Sec.  3175.80(l)(2) would have required 
operators to install the thermometer well in the same ambient 
conditions as the primary device. The purpose of measuring temperature 
is to determine the density of the gas at the primary device, which is 
used in the calculation of flow rate and volume. A 10-degree error in 
the measured temperature will cause a 1 percent error in the measured 
flow rate and volume. Even if the thermometer well is located away from 
the primary device within the distances allowed by API 14.3.2, 
Subsection 6.5, significant temperature measurement error could occur 
if the ambient conditions at the thermometer well are different from 
the ambient conditions at the orifice plate. For example, if the 
orifice plate is located inside of a heated meter house and the 
thermometer well is located outside of the heated meter house, the 
measured temperature will be influenced by the ambient temperature, 
thereby biasing the calculated flow rate. In these situations, the 
proposed rule would have required the thermometer well to be relocated 
inside of the heated meter house even if the existing location is in 
compliance with API 14.3.2, Subsection 6.5.
    The BLM received several comments on this section. Two of the 
commenters stated that the difference between the actual and measured 
gas temperatures at low-, high-, and very-high-volume FMPs is not 
significant because the flow rate is high enough to distribute the 
temperature within the pipe. Another commenter stated that the thermal 
effects are only significant if the thermometer is inserted less than 6 
inches into the pipe. Neither of the commenters submitted any data to 
substantiate their claim, and the BLM was unable to obtain any studies 
on this subject. The vast majority of FMPs on Federal and Indian leases 
are 4 inches in diameter or less; therefore the comment regarding 
thermometer insertion depths of 6 inches is generally irrelevant. 
Because the BLM could not substantiate the claims by commenters, the 
BLM did not make any changes to the rule based on these comments.
    The BLM also received a few comments recommending that operators 
could meet the intent of the requirement by insulating the meter tube, 
which would eliminate the need to move a thermometer well into a heated 
meter house, for example. The BLM agrees with these comments and added 
the option of insulating the meter run and adding heat tracing to the 
meter run. This change is also consistent with API 14.3.2, Subsection 
6.6, which recommends insulating the meter tube in the case of 
temperature differences between the ambient temperature and the 
temperature of the flowing fluid. It is difficult to define with any 
uniformity what level of insulation is needed to meet the intent of 
this requirement due to regional and local variations in operating 
conditions. Therefore, the BLM did not establish specific requirements 
with respect to insulation in the final rule and, instead, opted for 
language that states that the AO may prescribe the quality of the 
insulation based on site specific factors such as ambient temperature, 
flowing temperature of the gas, composition of the gas, and location of 
the thermometer well in relation to the orifice plate (i.e., inside or 
outside of a meter house).
    Section 3175.80(l)(3) applies when multiple thermometer wells exist 
at one meter. Many meter installations include a primary thermometer 
well for continuous measurement of gas temperature and a test 
thermometer well, where a certified test thermometer is inserted to 
verify the accuracy of the primary thermometer. API does not specify 
which thermometer well should be used as the primary thermometer. To 
minimize measurement bias, the gas temperature should be taken as close 
to the orifice plate as possible. When more than one thermometer well 
exists, the thermometer well closest to the primary device will 
generally result in less measurement bias, and therefore, the rule 
specifies that this thermometer well is the one that must be used for 
the flowing temperature measurement. The BLM did not receive any 
comments on this paragraph.
    Section 3175.80(l)(4) requires the use of a thermally conductive 
fluid in a thermometer well. To ensure that the temperature sensed by 
the thermometer is representative of the gas temperature at the orifice 
plate, it is important that the thermometer is thermally connected to 
the gas. Because air is a poor heat conductor, the rule includes a new 
requirement that a thermally conductive liquid be used in the 
thermometer well because this would provide a more accurate temperature 
measurement. The BLM did not receive any comments on this paragraph.
Sec. 3175.80(m)
    Section 3175.80(m) requires operators to locate the sample probe as 
required in Sec.  3175.112(b). The reference to Sec.  3175.112(b) is in 
Sec.  3175.80(m) because the sample probe is part of the primary 
device. Please see the discussion of Sec.  3175.112(b) for an 
explanation of the requirement. The BLM did not receive any comments on 
this paragraph.
Sec. 3175.80(n)
    Proposed Sec.  3175.80(n) would have included a requirement for 
operators to notify the BLM at least 72 hours in advance of a visual or 
detailed meter-tube inspection or installation of a new meter tube. 
Because meter tubes are inspected infrequently, it is important that 
the BLM be given an opportunity to witness the inspection of existing 
meter tubes or the installation of new meter tubes. Because meter tube 
inspections would not have been required for very-low-volume FMPs under 
the proposed rule, they would have been exempt from this requirement.
    Several commenters questioned the practicality of performing a 
detailed inspection on a new pre-fabricated meter tube. The commenters 
wondered if they would have to disassemble the meter tube in order for 
the BLM to witness the inspection. Other commenters stated that the 72-
hour notice requirement to inspect new meter tubes is impractical for 
pre-fabricated meter tubes, presumably because the meter tube could be 
delivered to the FMP on very short notice.
    The BLM agrees with these comments and made numerous changes to 
this section as a result of these comments and to further clarify the 
notification requirement. First, the BLM moved the notification 
requirements of proposed Sec.  3175.80(n) into Sec.  3175.80(h) and 
(i). The notification requirement in Sec.  3175.80(h)(3) requires the 
operator to notify the BLM within 72 hours of performing a basic 
inspection or submit a monthly or quarterly schedule of basic meter 
tube inspections to the AO. The notification requirement in Sec.  
3175.80(i)(3) requires the operator to notify the BLM at least 24 hours 
before performing a detailed inspection. The requirement for 
notification of a detailed inspection is different from that of a basic 
inspection because detailed inspections are no longer routine and 
cannot be scheduled. Second, the BLM reduced the notification 
requirement from 72 hours to 24 hours for detailed inspections because 
some operators may perform a detailed inspection immediately after 
discovering problems during a basic inspection. Third, to address the 
comments directly, the BLM added language (see Sec.  3175.80(i)(2)) 
that allows operators to submit documentation showing that the meter 
tube complies with the construction requirements of this rule in lieu 
of disassembling and inspecting the meter tube. This language 
specifically applies to pre-fabricated meter tubes where the pre-
fabrication shop supplies the operator with a specification sheet

[[Page 81564]]

showing that all dimensions meet the tolerances required by this rule.
    One commenter questioned what would happen if the BLM cannot 
witness a meter tube inspection. The operator's only obligation is to 
notify the BLM of the inspection within the required timeframes. If the 
BLM does not attend, the operator may proceed with the inspection. The 
BLM did not make any changes to the rule based on this comment.
Sec. 3175.90--Mechanical Recorder (Secondary Device)
    Section 3175.90(a) limits the use of mechanical recorders, also 
known as chart recorders, to very-low- and low-volume FMPs. Mechanical 
recorders will not be allowed at high- and very-high-volume FMPs 
because they may not be able to meet the uncertainty requirements of 
Sec.  3175.31(a). Mechanical recorders are subject to many of the same 
uncertainty sources as EGM systems, such as ambient temperature 
effects, vibration effects, static pressure effects, and drift. In 
addition, mechanical recorders are vulnerable to other sources of 
uncertainty, such as paper expansion and contraction effects and 
integration uncertainty. Unlike EGM systems, however, none of these 
effects have been quantified for mechanical recorders. All of these 
factors contribute to increased uncertainty and the potential for 
inaccurate measurement.
    Because there are no data indicating that the use of mechanical 
recorders results in statistically significant bias, mechanical 
recorders are allowed at very-low- and low-volume FMPs due to the 
limited production from these facilities.
    Table 1 to Sec.  3175.90 was developed to clarify and provide easy 
reference to the requirements that apply to different aspects of 
mechanical recorders. No industry standards are cited in Table 1 to 
Sec.  3175.90 because there are no industry standards applicable to 
mechanical recorders. The first column of Table 1 to Sec.  3175.90 
lists the subject of the standard. The second column of Table 1 to 
Sec.  3175.90 identifies the section and specific paragraph in the rule 
that apply to each subject area. (The standards are prescribed in 
Sec. Sec.  3175.91 through 3175.94.)
    The final two columns of Table 1 to Sec.  3175.90 indicate the FMPs 
to which the standard applies. The FMPs are categorized by the amount 
of flow they measure on a monthly basis as follows: ``VL'' is a very-
low-volume FMP and ``L'' is a low-volume FMP. As noted previously, 
mechanical recorders are not allowed at high- and very-high-volume 
FMPs; therefore, Table 1 to Sec.  3175.90 does not include 
corresponding columns for them. Definitions for the various FMP 
categories are given in Sec.  3175.10. An ``x'' in a column indicates 
that the standard listed applies to that category of FMP. A number in a 
column indicates a numeric value for that category, such as the maximum 
number of months or years between inspections, which is explained in 
the body of the requirement.
    The BLM received a comment stating that mechanical recorders should 
be prohibited because they cannot meet the uncertainty requirements 
required in Sec.  3175.31 (Sec.  3175.30 in the proposed rule). The BLM 
did not make any changes to the rule as a result of this comment 
because the uncertainty requirements in Sec.  3175.31 do not apply to 
very-low- and low-volume FMPs, and mechanical recorders are not allowed 
on any other FMPs.
    One commenter stated that if the BLM was going to continue to allow 
mechanical recorders, the recorders at very-low-volume FMPs should meet 
the same requirements as mechanical recorders at low-volume FMPs. The 
BLM disagrees. The exemptions for very-low-volume FMPs were provided to 
reduce the risk that an operator might choose to shut in production 
instead of upgrading the meter. The BLM did not make any changes to the 
rule based on this comment.
Sec. 3175.91--Installation and Operation of Mechanical Recorders
Sec. 3175.91(a)
    Section 3175.91(a) sets requirements for gauge lines. Gauge lines 
connect the pressure taps on the primary device to the mechanical 
recorder and can contribute to bias and uncertainty if not properly 
designed and installed. For example, a leaking or improperly sloped 
gauge line could cause significant bias in the differential pressure 
and static pressure readings. Improperly installed gauge lines can also 
result in a phenomenon known as ``gauge line error,'' which tends to 
bias measured flow rate and volume. This is discussed in more detail 
below.
    The proposed requirement in Sec.  3175.91(a)(1) would have required 
a minimum gauge line internal diameter of \3/8\ inches to reduce 
frictional effects that could result from smaller diameter gauge lines. 
These frictional effects could dampen pressure changes received by the 
recorder, which could result in measurement error.
    The BLM received numerous comments regarding the proposed 
requirement of \3/8\-inch minimum inside diameter gauge lines. The 
commenters stated that most gauge lines in place have a \3/8\-inch 
nominal diameter with an internal diameter that is less than \3/8\-
inch. The commenters objected to the \3/8\-inch internal diameter 
because it would require them to replace the existing gauge lines at a 
high cost with negligible benefit to measurement accuracy. The 
commenters recommended allowing \3/8\-inch nominal diameter gauge 
lines. The BLM agrees with this comment as the original intent was a 
\3/8\-inch nominal diameter. As a result, the BLM changed the 
requirement from a \3/8\-inch internal diameter to a \3/8\-inch nominal 
diameter.
    Proposed Sec.  3175.91(a)(2) would have allowed only stainless-
steel gauge lines. Carbon steel, copper, plastic tubing, or other 
material could corrode and leak, thus presenting a safety issue as well 
as resulting in biased measurement.
    The BLM received a few comments objecting to the requirement of 
stainless steel gauge lines because many operators have carbon steel 
gauge lines that would have to be replaced, resulting in excessive cost 
and a negligible benefit to measurement accuracy. The commenters stated 
that carbon steel gauge lines should be acceptable in most situations 
and that stainless steel should only be required in corrosive 
environments. The BLM's primary concern in proposing stainless steel 
gauge lines is that the use of plastic lines could lead to loops or 
sags that could trap liquids. The BLM agrees with these comments and 
removed the requirement for gauge lines to be constructed of stainless 
steel. The BLM added language to Sec.  3175.91(a)(2) (Sec.  
3175.91(a)(3) in the proposed rule) that prohibits visible sag in the 
gauge line.
    Section 3175.91(a)(2) requires gauge lines to be sloped up and away 
from the meter tube to allow any condensed liquids to drain back into 
the meter tube. A build-up of liquids in the gauge lines could 
significantly bias the differential pressure reading. The BLM did not 
receive any comments on this section, although it added the phrase 
regarding sags as discussed above.
    Requirements in Sec.  3175.91(a)(3) through (6) are intended to 
reduce a phenomenon known as ``gauge line error,'' which is caused when 
changes in differential or static pressure due to pulsating flow are 
amplified by the gauge lines, thereby causing increased bias and 
uncertainty. API 14.3.2, Subsection 5.4.3, recommends that gauge lines 
be the same diameter along their entire length, which the BLM adopted 
as a standard in Sec.  3175.91(a)(3).

[[Page 81565]]

    Section 3175.91(a)(4) and (5) are intended to minimize the volume 
of gas contained in the gauge lines because excessive volume can 
contribute significantly to gauge-line error whenever pulsation exists. 
These paragraphs allow only the static-pressure connection in a gauge 
line and prohibit the practice of connecting multiple secondary devices 
to a single set of pressure taps, the use of drip pots, and the use of 
gauge lines as a source for pressure-regulated control valves, heaters, 
and other equipment. Section 3175.91(a)(6) limits the gauge lines to 6 
feet in length, again to minimize the gas contained in the gauge lines.
    As indicated in Table 1 to Sec.  3175.90, very-low-volume FMPs are 
exempt from the requirements of Sec.  3175.91(a) because any bias or 
uncertainty caused by improperly designed gauge lines of very-low-
volume FMPs would not have a significant royalty impact.
    The BLM received a few comments objecting to these requirements 
because they would eliminate the use of drip pots, which, according to 
the commenters, are required in some areas to prevent freezing. The BLM 
did not make any changes to the rule based on these comments because, 
if freezing is an issue, then it must be resolved by properly sloping 
gauge lines to avoid the accumulation of liquids, rather than by using 
drip pots.
Sec. 3175.91(b)
    Section 3175.91(b) requires that the differential pressure pen 
record at a minimum reading of 10 percent of the differential-pressure 
bellows range for the majority of the flowing period. The integration 
of the differential pen when it is operating very close to the chart 
hub can cause substantial bias because a small amount of differential 
pressure could be interpreted as zero, thereby biasing the volume 
represented by the chart. A reading of at least 10 percent of the chart 
range will provide adequate separation of the differential pen from the 
``zero'' line, while still allowing flexibility for plunger lift 
operations that operate over a large range. Very-low-volume FMPs are 
exempt from this requirement due to the cost associated with 
compliance.
    The BLM received a few comments stating that this should not apply 
to inverted charts since the chart inversion yields better resolution 
for integration. With an inverted chart, the differential pen is moved 
to record on the opposite side of the chart as it normally would be. In 
this configuration, when the differential pressure pen is reading zero, 
it rests on the outer line of the chart and as the differential 
pressure increases, it moves closer to the hub. By moving the zero line 
from the hub of the chart to the outer edge of the chart, the 
integrator is better able to distinguish the ``zero'' line from the 
differential pen trace. The BLM agrees with this comment and added an 
exception for inverted charts to Sec.  3175.91(b).
Sec. 3175.91(c)
    Section 3175.91(c) requires the flowing temperature to be 
continuously recorded and used in the volume calculations under Sec.  
3175.94(a)(1) for low-volume FMPs (as provided in Table 1 to Sec.  
3175.90). Flowing temperature is needed to determine flowing gas 
density, which is critical to determining flow rate and volume. 
Typically, an indicating thermometer is inserted into the thermometer 
well during a chart change. That instantaneous value of flowing 
temperature is used to calculate volume for the chart period. This 
introduces a significant potential bias into the calculations. If, for 
example, the temperature is always obtained early in the morning, then 
the flowing temperature used in the calculations will be biased low 
from the true average value due to lower morning ambient temperatures. 
A continuous temperature recorder is used to obtain the true average 
flowing temperature over the chart period with no significant bias. 
Because Sec.  3175.31(c) prohibits statistically significant bias for 
low-volume FMPs, the rule requires continuous recorders for low-volume 
FMPs, but not for very-low-volume FMPs, as specified in Table 1 to 
Sec.  3175.90.
    The BLM received a few comments objecting to the cost to retrofit 
the recording device with a third pen to continuously record 
temperature. The commenters stated that temperature could be based on a 
fixed temperature or with a separate temperature recorder. The final 
rule does not require the temperature to be recorded on the same chart 
as the differential and static pressure; therefore, recording 
temperature on a separate temperature recorder would satisfy this 
requirement. A fixed temperature would be allowed for very-low-volume 
FMPs, but is not allowed for low-volume FMPs because of the potential 
for bias. The BLM did not make any changes to the rule based on these 
comments. The BLM included the cost of adding a temperature recorder 
(assumed to cost $500) in determining the upper limit of the very-low-
volume FMP category (see the BLM Threshold Analysis for subpart 3175 
Flow Category Tiers).
Sec. 3175.91(d)
    Section 3175.91(d) requires certain information to be available 
onsite at the FMP and available to the AO at all times. This 
requirement allows the BLM to calculate the average flow rate indicated 
by the chart and to verify compliance with this rule. The information 
that is required under Sec.  3175.91(d)(2), (3), (7), and (8) typically 
is already available onsite. For example, the static pressure and 
temperature element ranges are stamped into the elements and are 
visible to BLM inspectors, and the meter-tube inside diameter is 
typically stamped into the downstream flange or is on a tag as part of 
the device holder, making it visible and available to the BLM.
    The information that the operator must retain onsite at the FMP 
under Sec.  3175.91(d)(1), (4), (5), (6), (9), (10), (11), (12), and 
(13) was not previously required and thus typically has not been 
maintained onsite as a matter of practice. The information required in 
these paragraphs include: The differential-pressure-bellows range; the 
static-pressure-element range; the temperature-element range; the 
relative density (specific gravity) of the gas; the units of measure 
for static pressure (pounds per square inch absolute (psia) or pounds 
per square inch gage (psig)); the meter elevation; the orifice bore or 
other primary-device dimensions necessary for device verification, 
Beta- or area-ratio determination and gas volume calculation; make, 
model, and location of approved isolating flow conditioner (if used); 
the location of the downstream end of 19-tube-bundle flow straighteners 
(if used); the date of the last primary-device inspection; and the date 
of the last meter verification.
    The BLM received a few comments stating that the information was 
generally on the back of the flow chart and would satisfy the 
requirement of Sec.  3175.91(d). The BLM did not make any changes to 
the rule based on these comments. The BLM inspectors are instructed not 
to manipulate measurement equipment, which includes removing flow 
charts from the recorder to access the information on the back of the 
chart, because of concerns for safety and liability.
Sec. 3175.91(e)
    Section 3175.91(e) requires the differential-pressure, static-
pressure, and temperature elements to be operated within the range of 
the respective elements. Operating any of the elements beyond the upper 
range of the element will cause the pen to record off the chart. When a 
chart is integrated

[[Page 81566]]

to determine volume, any parameters recorded off the chart will not be 
accounted for, which results in biased measurement. Operating a 
mechanical recorder within the range of the elements is common industry 
practice. The BLM did not receive any comments on this paragraph.
Sec. 3175.92--Verification and Calibration of Mechanical Recorders
Sec. 3175.92(a)
    Section 3175.92(a) sets requirements for the verification and 
calibration of mechanical recorders upon installation or after repairs, 
and defines the procedures that operators must follow. The rule 
differentiates the procedures that are specific to this type of 
verification from a routine verification that is required under Sec.  
3175.92(b). The BLM did not receive any comments on any of the 
requirements under Sec.  3175.92(a) or paragraphs (a)(1) through (7) of 
this section.
    Section 3175.92(a)(1) requires the operator to perform a successful 
leak test before starting the mechanical recorder verification. The 
rule specifies the tests that operators must perform. The BLM is 
requiring this level of specificity because it is possible to perform 
leak tests without ensuring that all valves, connections, and fittings 
are not leaking. Leak testing is necessary because a verification or 
calibration done while valves are leaking could result in significant 
meter bias. A successful leak test is required to precede a 
verification.
    Section 3175.92(a)(2) requires that the differential- and static-
pressure pens operate independently of each other, which is 
accomplished by adjusting the time lag between the pens. Examples of 
appropriate time lag are given for a 24-hour chart and an 8-day chart 
because these are the charts that are normally used as test charts for 
verification and calibration.
    Section 3175.92(a)(3) requires a test of the differential pen arc.
    Section 3175.92(a)(4) requires an ``as left'' verification to be 
done at zero percent, 50 percent, 100 percent, 80 percent, 20 percent, 
and zero percent of the differential- and static-pressure- element 
ranges. Using this set of verification points helps ensure that the 
pens have been properly calibrated to read accurately throughout the 
element ranges. This section also clarifies the verification of static 
pressure when the static pressure pen has been offset to include 
atmospheric pressure. In this case, the element range is assumed to be 
in psia instead of psig. For example, if the static-pressure-element-
range is 100 psig and the atmospheric pressure at the meter is 14 psia, 
then the calibrator would apply 86 psig to test the ``100 percent'' 
reading as required in Sec.  3175.92(a)(4)(iii). This prevents the pen 
from being pushed off the chart during verification. As-found readings 
are not required in this section because as-found readings are not 
available for a newly installed or repaired recorder.
    Section 3175.92(a)(5) requires a verification of the temperature 
element to be done at approximately 10 [deg]F below the lowest expected 
flowing temperature, approximately 10 [deg]F above the highest expected 
flowing temperature, and at the expected average flowing temperature. 
This requirement ensures that the temperature element is recording 
accurately over the range of expected flowing temperature.
    Section 3175.92(a)(6) establishes a threshold for the amount of 
error between the pen reading on the chart and the reading from the 
test equipment that is allowed in the differential-pressure element, 
static-pressure element, and temperature element being installed or 
repaired. If any of the required test points are not within the values 
shown in Table 1 to Sec.  3175.92, the element must be replaced. The 
threshold for the differential pressure element is 0.5 percent of the 
element range and 1.0 percent of the range for the static pressure 
element. These thresholds are based on the published accuracy 
specifications for a common brand of mechanical recorders used on 
Federal and Indian land (``Installation and Operation Manual, Models 
202E and 208E,'' ITT Barton Instruments, 1986, Table 1-1). The 
threshold for the temperature element assumes a typical temperature 
element range of 0-150 [deg]F with an assumed accuracy of 1.0 percent of range. This yields a tolerance of 1.5 [deg]F, 
which was rounded up to 2 [deg]F for the sake of simplicity. Our 
experience over the last three decades indicates that a zero error is 
unattainable.
    Section 3175.92(a)(7) establishes standards for when the static-
pressure pen is offset to account for atmospheric pressure. The 
equation used to determine atmospheric pressure is discussed in 
Appendix A to this rule. This rule adds the requirement to offset the 
pen before obtaining the as-left values to ensure that the pen offset 
did not affect the calibration of any of the required test points.
Sec. 3175.92(b)
    Section 3175.92(b) establishes requirements for how often a routine 
verification must be performed, with the minimum frequency, in months, 
shown in Table 1 to Sec.  3175.90. The rule requires verification every 
3 months for a low-volume FMP and every 6 months for a very-low-volume 
FMP. The required routine verification frequency for a chart recorder 
is twice as frequent as it is for an EGM system at low- and very-low-
volume FMPs because chart recorders tend to drift more than the 
transducers of an EGM system.
    The BLM received one comment regarding the proposed 6-month routine 
verification frequency for very-low-volume FMPs. The commenter stated 
that if chart recorders are permitted, routine verification should 
occur every 3 months, although no rationale was given by the commenter. 
The BLM did not make any changes to the rule based on this comment. The 
BLM believes that a 6-month routine verification frequency is adequate 
for very-low-volume FMPs because the volumes measured by very-low-
volume FMPs are low enough that errors in the mechanical recorder will 
not have a significant effect on royalty.
Sec. 3175.92(c)
    Section 3175.92(c) establishes procedures for performing a routine 
verification. These procedures vary from the procedures used for 
verification after installation or repair, which are discussed in Sec.  
3175.92(a). The BLM did not receive any comments on any of the 
requirements under Sec.  3175.92 (c).
    Section 3175.92(c)(1) requires that a successful leak test be 
performed before starting the verification. See the previous discussion 
of leak testing under Sec.  3175.92(a)(1). Section 3175.92(c)(2) 
prohibits any adjustments to the recorder until the as-found 
verifications are obtained. It is general industry practice to obtain 
the as-found readings before making adjustments. However, some 
adjustments are specifically prohibited under this rule. For example, 
some meter calibrators will zero the static pressure pen to remove the 
atmospheric-pressure offset before obtaining any as-found values. Once 
the pen has been zeroed it is no longer possible to determine how far 
off the pen was reading prior to the adjustment, thus making it 
impossible to determine whether a volume correction would be required 
under Sec.  3175.92(f). This section makes it clear that no 
adjustments, including the previous example, are allowed before 
obtaining the as-found values.
    Section 3175.92(c)(3) requires an as-found verification to be done 
at zero percent, 50 percent, 100 percent, 80 percent, 20 percent, and 
zero percent of the differential and static element ranges. The 
verification points were

[[Page 81567]]

included to identify pen error over the chart range. Mechanical 
recorders are generally more susceptible to varying degrees of 
recording error (sometimes referred to as an ``S'' curve) than EGM 
systems.
    Section 3175.92(c)(3)(i) requires that an as-found verification be 
done at a point that represents where the differential and static pens 
normally operate. This section requires verification at the points 
where the pens normally operate only if there is enough information 
onsite to determine where these points are.
    Section 3175.92(c)(3)(ii) establishes additional requirements if 
there is not sufficient information onsite to determine the normal 
operating points for the differential pressure and static pressure 
pens. The most likely example would be when the chart on the meter at 
the time of verification has just been installed and there were no 
historical pen traces from which to determine the normal operating 
values. In these cases, additional measurement points are required at 5 
and 10 percent of the element range to ensure that the flow-rate error 
can be accurately calculated once the normal operating points are 
known. The amount of flow-rate error is more sensitive to pen error at 
the lower end of the element range than at the upper end of the range. 
Therefore, more verification points are required at the lower end to 
allow the calculation of flow-rate error throughout the range of the 
differential and static pressure elements.
    Section 3175.92(c)(4) establishes standards for determining the as-
found value of the temperature pen. In a flowing well, the use of a 
test thermometer well is preferred because it more closely represents 
the flowing temperature of the gas compared to a water bath, which is 
often set at an arbitrary temperature. However, if the meter is not 
flowing, temperature differences within the pipeline may occur, which 
have the potential to introduce error between the primary-thermometer 
well and the test-thermometer well, thereby causing measurement bias. 
If the meter is not flowing, temperature verification must be done 
using a water bath.
    Section 3175.92(c)(5) establishes a threshold for the degree of 
allowable error between the pen reading on the chart and the reading 
from the test equipment for the differential, static, or temperature 
element being verified. If any of the required points to be tested, as 
defined in Sec.  3175.92(c)(3) or (4), are not within these thresholds, 
the element must be calibrated. For a discussion of the thresholds, see 
the previous discussion in Sec.  3175.92(a)(6) and (7).
    Section 3175.92(c)(6) requires that the differential- and static-
pressure pens operate independently of each other, which is 
accomplished by adjusting the time lag between the pens. Please see 
previous discussion in Sec.  3175.92(a)(3) for further explanation of 
this requirement.
    Section 3175.92(c)(7) requires a test of the differential-pen arc.
    Section 3175.92(c)(8) requires an as-left verification if an 
adjustment to any of the meter elements was made. Obtaining as-left 
readings whenever a calibration is performed is standard industry 
practice. The purpose of the as-left verification is to ensure that the 
calibration process, required in Sec.  3175.92(c)(5) through (7), was 
successful before returning the meter to service.
    Section 3175.92(c)(9) establishes a threshold for the amount of 
error allowed in the differential, static, or temperature element after 
calibration. If any of the required test points, as defined in Sec.  
3175.92(c)(3) and (4), are not within the thresholds shown in Table 1 
to Sec.  3175.92, the element must be replaced and verified under Sec.  
3175.92(c)(5) through (7).
    Section 3175.92(c)(10) establishes standards if the static-pressure 
pen is offset to account for atmospheric pressure. Please see previous 
discussion in Sec.  3175.92(a)(7) for further explanation of this 
requirement. Very-low-volume FMPs are not exempt from any of the 
verification or calibration requirements in Sec.  3175.92(c) because 
these requirements do not result in significant additional cost and are 
necessary for the BLM to verify the measurement. The BLM did not 
receive any comments on this provision, and therefore did not make any 
changes to the rule.
Sec. 3175.92(d)
    Section 3175.92(d) specifies the documentation that must be 
generated and retained by operators in connection with each 
verification. This information includes: The time and date of the 
verification and the prior verification date; primary-device data 
(meter-tube inside diameter and differential-device size and Beta or 
area ratio) if the orifice plate is pulled and inspected; the type and 
location of taps (flange or pipe, upstream or downstream static tap); 
atmospheric pressure used to offset the static-pressure pen, if 
applicable; mechanical recorder data (make, model, and differential 
pressure, static pressure, and temperature element ranges); the normal 
operating points for differential pressure, static pressure, and 
flowing temperature; verification points (as-found and applied) for 
each element; verification points (as-left and applied) for each 
element, if a calibration was performed; names, contact information, 
and affiliations of the person performing the verification and any 
witness, if applicable; and remarks, if any.
    The purpose of this documentation is to: (1) Identify the FMP that 
was verified; (2) Ensure that the operator adheres to the proper 
verification frequency; (3) Ascertain that the verification/calibration 
was performed according to the requirements established in Sec.  
3175.92(a) through (c), as applicable; (4) Determine the amount of 
error in the differential-pressure, static-pressure, and temperature 
pens; (5) Verify the proper offset of the static pen, if applicable; 
and (6) Allow the determination of flow rate error. The rule includes 
the documentation requirement for the normal operating points to allow 
the BLM to confirm that the proper points were verified and to allow 
error calculation based on the applicable verification point. The rule 
requires the primary-device documentation because the primary device is 
pulled and inspected at the same time that the operator performs a 
mechanical-recorder verification. Although the BLM did not receive any 
comments on this section, it added language that the primary device 
data are only required if the primary device is pulled and inspected 
during the verification. For very-low- and low-volume FMPs, operators 
must inspect the primary device every 12 months and every 6 months, 
respectively. However, for mechanical recorders, verifications are 
required every 6 months and every 3 months, respectively. Therefore, 
the operator is only required to pull and inspect the primary device 
every other time they perform a verification.
Sec. 3175.92(e)
    Proposed Sec.  3175.92(e) would have required the operator to 
notify the AO at least 72 hours before verification of the recording 
device. A 72-hour notice would be sufficient for the BLM to rearrange 
schedules, as necessary, to allow the AO to be present at the 
verification.
    The BLM received a few comments stating that the 72-hour 
notification would require a great deal of coordination. The BLM agrees 
with this comment and has included an alternative to submit a monthly 
or quarterly verification schedule to the AO. The submittal of monthly 
or quarterly schedules in lieu of the 72-

[[Page 81568]]

hour notice is already common practice in many field offices.
Sec. 3175.92(f)
    Proposed Sec.  3175.92(f) would have required the operator to 
correct flow-rate errors that are greater than 2 Mcf/day, if they are 
due to the chart recorder being out of calibration, by submitting 
amended reports to ONRR. The 2 Mcf/day flow-rate threshold would 
eliminate the need for operators to submit--and the BLM to review--
amended reports on low-volume meters, where a 2 percent error (as 
required under Order 5) does not constitute a sufficient volume of gas 
to justify the cost of processing amended reports. The BLM derived the 
2 Mcf/day threshold by multiplying the 2-percent threshold in Order 5 
by 100 Mcf/day, which is the maximum flow rate that would have been 
allowed to be measured with a chart recorder in the proposed rule. 
Very-low-volume FMPs are exempt from this requirement because the 
volumes are so small that even relatively large errors discovered 
during the verification process would not result in significant lost 
royalties or otherwise justify the costs involved in producing and 
reviewing amended reports. For example, if an operator were to discover 
that an FMP measuring 15 Mcf/day is off by 10 percent (a very large 
error based on the BLM's experience) while performing a verification 
under this section, that would amount to a 1.5 Mcf/day error which, 
over a month's period, would be 45 Mcf. At $4 per Mcf, that error could 
result in an under- or over-payment in royalty of $22.50. It could take 
several hours for the operator to develop and submit amended OGORs and 
it could take several hours for both the BLM and ONRR to review and 
process those reports.
    This paragraph also defines the points that are used to determine 
the flow-rate error. Calculated flow-rate error will vary depending on 
the verification points used in the calculation. The normal operating 
points must be used because these points, by definition, represent the 
flow rate normally measured by the meter.
    Although the BLM did not receive comments on this section, an 
example is added to clarify the flow-rate error correction. The BLM 
added the example because this calculation tends to cause confusion 
among both the BLM staff and industry. The BLM also changed the 2 Mcf/
day threshold to ``2 percent or 2 Mcf/day, whichever is greater.'' In 
the proposed rule, the low-/high-volume threshold was 100 Mcf/day; 
therefore, for a low-volume FMP, a flow rate error of 2 Mcf/day would 
always have been at or above 2 percent of the total flow rate. However, 
in the final rule, the low-/high-volume threshold was raised to 200 
Mcf/day. For average flow rates between 100 Mcf/day and 200 Mcf/day, 
which can now be measured with a mechanical recorder, a fixed threshold 
of 2 Mcf/day would be less than 2 percent of the flow rate. Therefore, 
the BLM added the 2 percent threshold to be consistent with the 
requirements for EGM systems (Sec.  3175.102(g)).
Sec. 3175.92(g)
    Section 3175.92(g) requires verification equipment to be certified 
at least every 2 years. The purpose of this requirement is to ensure 
that the verification or calibration equipment meets its specified 
level of accuracy and does not introduce significant bias into the 
field meter during calibration. Two-year certification of verification 
equipment is typically recommended by the verification equipment 
manufacturer, and therefore, this does not represent a major change 
from existing procedures. This paragraph also requires that proof of 
certification be available to the BLM and sets minimum standards as to 
what the documentation must include. The BLM did not receive any 
comments on this paragraph.
Sec. 3175.93--Integration Statements
    Section 3175.93 establishes minimum standards for chart integration 
statements. The purpose of requiring the information listed is to allow 
the BLM to independently verify the volumes of gas reported on the 
integration statement. Currently, the range of information available on 
integration statements varies greatly. In addition, many integration 
statements lack one or more items of critical information necessary to 
verify the reported volumes. The BLM is not aware of any industry 
standards that apply to chart integration.
    The BLM received one comment stating that the time of retention is 
not mentioned. The BLM did not make any changes to the rule based on 
this comment. Retention time is defined in 43 CFR 3170.7.
Sec. 3175.94--Volume Determination
    Section 3175.94(a) establishes the methodology for determining 
volume from the integration of a chart. The methodology includes the 
adoption of the equations published in API 14.3.3 or AGA Report No. 3 
for flange-tapped orifice plates. Under this rule, operators using 
mechanical recorders have the option to continue using the older AGA 
Report No. 3 flow equation. (Operators using EGM systems, on the other 
hand, are required to use the flow equations in API 14.3.3 (see Sec.  
3175.103.))
    There are three primary reasons for allowing mechanical recorders 
to use a less strict standard. First, chart recorders, unlike EGM 
systems, are restricted to FMPs measuring 200 Mcf/day or less. 
Therefore, any errors caused by using the older 1985 flow equation will 
not have nearly as significant an effect on measured volume or royalty 
as for a high- or very-high-volume meter. Second, the BLM estimates 
that only 10 to 15 percent of FMPs still use mechanical recorders, and 
this number is declining steadily. This fact, combined with the 200 
Mcf/day flow rate restriction, means that only a small percentage of 
gas produced from Federal and Indian leases is measured using a 
mechanical recorder, significantly lowering the risk of volume or 
royalty error as a result of using the older 1985 equation. Third, it 
may be economically burdensome for a chart integration company to 
switch over to the new API 14.3.3 flow equations because much of the 
equipment and procedures used to integrate charts was established 
before the revision of AGA Report No. 3. In the proposed rule, the BLM 
sought data on the cost for chart integration companies to switch over 
to the new API 14.3.3 flow rate. The BLM did not receive any such data.
    There are two variables in the API 14.3.3 flow equation that have 
changed since 1985. The current API equation includes a more accurate 
curve fit for determining the discharge coefficient as a function of 
Reynolds number, Beta ratio, and line size. Further, the gas expansion 
factor was changed based on a more rigorous screening of valid data 
points. The current flow equation also requires an iterative 
calculation procedure instead of an equation that can be solved 
directly by hand, providing a more accurate flow rate. The difference 
in flow rate between the two equations, given the same input 
parameters, is less than 0.5 percent in most cases.
    While API 14.3.3 provides equations for calculating instantaneous 
flow rate, it is silent on determining volume. Therefore, the 
methodology presented in API 21.1 for EGM systems is adopted in this 
section for volume determination. This methodology is generally 
consistent with existing methods for chart integration and, as such, 
should not require any significant modifications. For primary devices 
other than flange-tapped orifice plates, the BLM would approve, based 
on the PMT's recommendation, the equations that would be used for 
volume determination.

[[Page 81569]]

    The BLM received one comment that supported chart integration 
companies switching to the 1992/2013 volume calculation. The BLM did 
not make any changes to the rule based on this comment as there was no 
change requested.
    Section 3175.94(a)(3) defines the source of the data that goes into 
the flow equation. The BLM did not receive any comments on this 
requirement.
    Section 3175.94(b) establishes a standard method for determining 
atmospheric pressure used to convert pressure measured in psig to units 
of psia, which is used in the calculation of flow rate. Any error in 
the value of atmospheric pressure will cause errors in the calculation 
of flow rate, especially in meters that operate at low pressure. This 
rule eliminates the use of a contract value for atmospheric pressure 
because contract provisions are not always in the public interest and 
do not always dictate the best measurement practice. A contract value 
that is not representative of the actual atmospheric pressure at the 
meter will cause measurement bias, especially in meters where the 
static pressure is low--a condition that is common at FMPs.
    This rule also eliminates the option of operators measuring actual 
atmospheric pressure at the meter location for mechanical recorders. 
Instead, atmospheric pressure must be determined from an equation or 
table (see appendix A to this subpart) based on elevation. Atmospheric 
pressure is used in one of two ways for a mechanical recorder. First, 
the static-pressure reading from the chart in psig is converted to 
absolute pressure during the integration process by adding atmospheric 
pressure to the static pressure reading. Or, second, the static 
pressure pen can be offset from zero in an amount that represents 
atmospheric pressure. In the second case, the static-pressure line on 
the chart already has atmospheric pressure added to it and no further 
corrections are made during the integration of the charts. The static-
pressure element in a chart recorder is a gauge pressure device--in 
other words, it measures the difference between the pressure from the 
pressure tap and atmospheric pressure. Offsetting the pen does not 
convert it into an absolute pressure device; it is only a convenient 
way to convert gauge pressure to atmospheric pressure. If measured 
atmospheric pressure were allowed, the measurement could be made when, 
for example, a low-pressure weather system was over the area. The 
measured atmospheric pressure in this example would not be 
representative of the average atmospheric pressure and would bias the 
measurements to the low side. This is much more critical in meters 
operating at low pressure than in meters operating at high pressure. 
The BLM believes that operators rarely use measured atmospheric 
pressure to offset the static pressure; therefore, this requirement 
would have no significant impact on current industry practice. The 
treatment of atmospheric pressure for mechanical recorders is different 
than it is for EGM systems because many EGM systems measure absolute 
pressure, whereas all mechanical recorders are gauge-pressure devices. 
Please see the discussion of Sec.  3175.102(a)(3) for further analysis.
    The equation to determine atmospheric pressure from elevation 
(``U.S. Standard Atmosphere,'' National Aeronautics and Space 
Administration, 1976 (NASA-TM-X-74335)), prescribed in appendix A to 
this subpart, produces similar results to the equation normally used 
for atmospheric pressure for elevations less than 7,000 feet mean sea 
level (see Figure 3). The BLM did not receive any comments on the 
change in how atmospheric pressure must be calculated.
Sec. 3175.100--Electronic Gas Measurement (Secondary and Tertiary 
Device)
    Section 3175.100 adopts API 21.1, Subsection 7.3, regarding EGM 
equipment commissioning; API 21.1, Section 9, regarding access and data 
security; and API 21.1, Subsection 4.4.5, regarding the no-flow cutoff. 
The BLM has reviewed these sections and believes they are appropriate 
for use at FMPs. The existing statewide NTLs referenced similar 
sections in the previous version of API 21.1 (1993); therefore, this is 
not a significant change from existing requirements.
    The BLM received several comments objecting to the application of 
API 21.1 to low- and very-low-volume FMPs due to its complexity and the 
difficulty of implementing it for wellhead measurement. The BLM 
recognizes the recommendations of API 21.1 as industry standards for 
accurate measurement of natural gas. These consensus standards are 
developed by operators, manufacturers, purchasers, and other recognized 
experts within the oil and gas industry and approved by API voting 
members. The authors of API 21.1 did not include any limitations for 
the use of the standard based on a specific application or average flow 
rate through the meter, nor did the commenters provide any 
justification as to why API 21.1 was too complex and difficult to 
implement on low- and very-low-volume FMPs. In addition, wellhead 
measurement is not a requirement of the BLM. The BLM requirement is 
only that measurement of gas must occur prior to removal or sales from 
the lease, unit PA, or CA, unless otherwise approved by the AO. 
Therefore, if an operator believes that API 21.1 is too complex or 
difficult to use for wellhead measurement, they could combine the 
production from multiple wells within a lease, CA, or unit PA and 
measure the combined stream. Combining production from multiple wells 
within a single lease, unit PA, or communitized area is not considered 
commingling for production accounting purposes and does not require BLM 
approval (see definition of commingling in Sec.  3170.3(a)). The BLM 
did not make any changes as a result of this comment.
    The BLM received a comment indicating that the description of the 
acronyms at the bottom of Table 1 to Sec.  3175.100, Standards for 
Electronic Gas Measurement Systems, may suggest that all very-high-
volume FMP requirements will be subject to immediate assessments for 
non-compliance. The commenter suggested adding a comma and asterisk 
after the phrase ``Very-high-volume FMP'' to delineate the acronym 
definition from the note on immediate assessments. The BLM agrees with 
this comment and changed this language to indicate that only those 
requirements with a superscript number 1 (\1\) following the subject in 
the table are intended to have immediate assessment for non-compliance.
Sec. 3175.101--Installation and Operation of Electronic Gas Measurement 
Systems
Sec. 3175.101(a)
    Section 3175.101(a) sets requirements for manifolds and gauge 
lines. The requirements regarding gauge lines for EGM systems are 
identical to the requirements for gauge lines for mechanical recorders. 
The comments that the BLM received on gauge lines are also the same for 
both EGM systems and mechanical recorders. Please see the discussion of 
gauge line requirements and comments on these requirements under Sec.  
3175.91(a).
Sec. 3175.101(b) and (c)
    Section 3175.101(b) and (c) specify the minimum information that 
the operator must maintain onsite for an EGM system and make available 
to the BLM for inspection. The purpose of the data requirements in 
these sections is to allow BLM inspectors to:
    (1) Verify the flow-rate calculations being made by the flow 
computer;

[[Page 81570]]

    (2) Compare the daily volumes shown on the flow computer to the 
volumes reported to ONRR;
    (3) Determine the uncertainty of the meter;
    (4) Determine if the Beta ratio is within the required range;
    (5) Determine if the upstream and downstream piping meets minimum 
standards;
    (6) Determine if the thermometer well is properly placed;
    (7) Determine if the flow computer software version and transducer 
makes, models, and URLs have been reviewed by the PMT and approved by 
the BLM;
    (8) Verify that the primary device has been inspected at the 
required frequency; and
    (9) Verify that the transducers have been verified at the required 
frequency.
    Section 3175.101 paragraphs (b)(1) through (3) requires that each 
EGM system include a display that is accessible to the BLM, and that 
shows the units of measure for each variable.
    The BLM received a few comments to the proposed requirement in 
Sec.  3175.101(b)(1). The commenters objected to the need for a 
display. The BLM did not make any changes to the rule based on these 
comments. The BLM believes the displayed information is required in 
order to verify that the flow computer is functioning properly. The BLM 
uses the displayed information for several purposes, including to 
independently check the flow-computer calculations, to determine 
average values of differential and static pressure in order to enforce 
uncertainty requirements, to compare the displayed volume to reported 
volume, and to determine the normal operating points for verification. 
The statewide NTLs, which have been in place for at least 7 years (12 
years for Wyoming), all require a display, so this requirement is not 
new.
    The BLM received one comment regarding the requirement in Sec.  
3175.101(b)(2) that the display be onsite and in a location that is 
accessible to the AO. The commenter objected to the requirement of 
accessibility by the AO if the meter house is locked. The BLM did not 
make any changes to the rule based on this comment. The BLM must have 
immediate access to the EGM display. Although some operators have 
offered to provide BLM inspectors with keys or combinations to locks, 
the BLM has determined after years of experience that this rarely works 
well. During the course of a year, a BLM inspector has to inspect 
thousands of FMPs owned by dozens of different operators. It is 
unworkable for BLM inspectors to maintain a list of lock combinations 
and keys, both of which often change over the course of time. The BLM 
does not believe that it is unreasonable to ask for ready access to the 
EGM display. Again, this requirement is essentially the same as the 
requirement for the display to be accessible to the BLM in the 
statewide NTLs.
    The BLM received one comment regarding the proposed requirement in 
Sec.  3175.101(b)(3) to include units of measure for each required 
variable in the display. The commenter objected to this requirement and 
proposed an alternative to post the units on a placard or card. The BLM 
did not make any changes to the rule based on this comment. The BLM 
believes that the units of measure must be with the variables in the 
display because they can change when a flow computer is replaced or 
reconfigured. The units of measure are critical when verifying the 
flow-computer calculations in the field. Based on the BLM's experience, 
virtually all flow computers are capable of displaying the units of 
measure; therefore, the BLM believes this is a reasonable requirement.
    Proposed Sec.  3175.101(b)(4) would have required the display to 
contain 13 items, including the FMP number, software version, 
instantaneous flow data (differential pressure, static pressure, 
flowing temperature, and flow rate), previous day volume and flow time, 
previous day average flowing data (differential pressure, static 
pressure, and flowing temperature), relative density, and primary 
device information (e.g., orifice bore diameter).
    The BLM received several comments on this section, which stated 
that most legacy and several current models of flow computers cannot 
accommodate 13 lines due to software limitations and suggested that 
some of the required information could be posted onsite instead of 
being part of the display. The BLM agrees with these comments and has 
reduced the amount of information that must be displayed by the flow 
computer from 13 lines in the proposed rule to 6 lines of information 
in the final rule. The final rule no longer requires the FMP number 
(see discussion below), the relative density, or the primary device 
information as part of the display if this information is posted 
onsite. The BLM eliminated the requirement to display or post the 
previous day's flow time. In addition, the previous day's average 
differential pressure, average static pressure, and average flowing 
temperature do not have to be displayed if the operator posts an hourly 
or daily QTR (see Sec.  3175.104(a)) that is no more than 31 days old 
onsite and accessible to the AO. Posting the previous day's average 
values will still allow the BLM to determine the normal operating 
points of differential pressure, static pressure, and temperature, in 
order to perform an uncertainty calculation and determine the normal 
operating points for verification.
    The BLM also received numerous comments regarding the proposed 
requirement in Sec.  3175.101(b)(4)(i) to include the FMP number or, if 
an FMP number has not yet been assigned, a unique meter-identification 
number in the display. The commenters stated that most EFCs are not 
capable of handling an 11-digit FMP number in the display. The 
commenters suggested only providing the FMP number during calibration, 
at the time of audit, or making the FMP number available by posting it 
onsite. The BLM agrees with these comments and has removed the proposed 
requirement to display the FMP number on the electronic display. 
Instead, the operator may post a unique meter ID number (which could 
include the FMP number) at the FMP. The BLM also added the term 
``unique meter ID number'' to the definitions in Sec.  3170.
    Section 3175.101(c) sets requirements for information that must be 
onsite, but not necessarily on the EGM system display. The information 
in the proposed rule included the elevation, meter tube diameter, 
information regarding the flow conditioner or 19-tube-bundle flow 
straightener (if installed), information regarding the transducers and 
flow computer, static pressure tap location, and last inspection dates 
for both the primary and secondary devices.
    The BLM did not receive any comments on Sec.  3175.101(c). However, 
the BLM did add additional items to this list based on comments on 
Sec.  3175.101(b), including a unique meter ID number, the relative 
density of the gas, and primary device information.
Sec. 3175.101(d)
    Section 3175.101(d) requires the differential pressure, static 
pressure, and flowing temperature transducers to be operated within the 
lower and upper calibrated limits of the transducer. Inputs that are 
outside of these limits are subject to higher uncertainty and if the 
transducer is over-ranged, the readings may not be recorded. The term 
``over-ranged'' means that the pressure or temperature transducer is 
trying to measure a pressure or temperature that is beyond the pressure 
or temperature it was designed or calibrated to measure. In some 
transducers--typically older ones--the transducer output will not 
exceed the maximum value for which it

[[Page 81571]]

was calibrated, even when the pressure being measured exceeds that 
value. For example, if a differential-pressure transducer that has a 
URL of 250 inches of water is measuring a differential pressure of 300 
inches of water, the transducer may output only 250 inches of water. 
This results in loss of measured volume and royalty. Many newer 
transducers will continue to measure values that are over their 
calibrated range; however, because the transducer has not been 
calibrated for these values, the uncertainty may be higher than the 
transducer specification indicates. Many of these newer transducers 
will not output a value that exceeds the URL of that transducer, 
however.
    The BLM received one comment in response to Sec.  3175.101(d) that 
suggested an exception for wells using a plunger lift system. A plunger 
lift is installed on a well to suppress flow from the well until enough 
pressure builds up to lift accumulated liquids out of the wellbore. 
When the well pressure reaches this threshold, the plunger releases and 
a surge of flow--both liquids and gases--comes to the surface. This 
results in a spike in the gas flow through the meter, which causes a 
corresponding spike in the differential pressure at the meter. It is 
often difficult to size an orifice plate and differential-pressure 
transducer to accurately record both the spike in flow, which typically 
lasts only several seconds, and the lower differential pressure for the 
remainder of the plunger cycle. The commenter suggested that the BLM 
should allow the differential-pressure transducer associated with a 
plunger lift system to exceed the URL by 150 percent for 1 minute. The 
rationale for this, as stated by the commenter, is that under the 
transducer testing protocol (see Sec.  3175.133(e)), the transducer 
must be tested at 150 percent of URL for at least 1 minute; therefore, 
the BLM should accept over-range operation of the differential-pressure 
transducer for 1 minute because this condition has been tested. The 
commenter stated that the increased uncertainty of a transducer 
operating in an over-range condition could be derived from the testing 
done under Sec.  3175.133(e).
    The BLM believes that the commenter has misinterpreted the intent 
of the testing protocol. The testing protocol does require an ``over-
range effects'' test where the transducer is operated at 150 percent of 
its URL for at least 1 minute. However, the purpose of this test is to 
see if, or how much, the over-ranging affects the calibration of the 
transducer under normal operation when the reading is below the upper 
calibrated limit. In some transducers, a brief over-ranging can cause 
the calibration of the transducer to shift, which affects all of the 
transducer's readings. This testing does not determine the accuracy to 
which an over-range pressure is recorded or if the over-range pressure 
is recorded at all, it only determines how an over-range condition 
affects the accuracy of the transducer when it is operated within its 
upper calibrated limit. Also, the BLM is grandfathering transducers 
that are used at FMPs as of January 17, 2017 from going through the 
testing protocol in Sec.  3175.130. While the manufacturer must still 
submit the data from whatever testing they did in order to get BLM 
approval, this testing may not have included the over-range-effects 
test to which the commenter refers.
    The BLM agrees that plunger lifts can cause measurement issues as 
described previously and added a provision to Sec.  3175.101(d) to 
allow the differential pressure to exceed the upper calibrated limit 
for brief periods of time if approved by the BLM. The BLM does not 
believe the differential pressure should ever exceed the URL, because 
in some transducers differential pressures exceeding the URL are not 
recorded and included in the calculation of volume. Although operation 
of the differential-pressure transducer over the upper calibrated limit 
may exceed the uncertainty specification of the transducer, the BLM 
believes that this will not significantly degrade the uncertainty of 
the volume calculation if these instances are brief. The BLM did not 
make any changes regarding the commenter's suggestion to allow the 
exceedance for 1 minute. Although the 1-minute timeframe is a test 
condition in Sec.  3175.133(e)(1), this is not relevant for normal 
operation of the transducer. In addition, a specific timeframe would be 
virtually impossible for the BLM to enforce.
Sec. 3175.101(e)
    Section 3175.101(e) requires the flowing temperature of the gas to 
be continuously recorded on all FMPs except on very-low-volume FMPs. 
Flowing temperature is needed to determine flowing gas density, which 
is critical to determining flow rate and volume. Very-low-volume FMPs 
would be exempt from this requirement because the potential effect on 
royalty would be minimal and the BLM's experience suggests that the 
costs would outweigh potential royalty. For very-low-volume FMPs, any 
errors introduced by using an estimated temperature in lieu of a 
measured temperature would not have a significant impact on royalties. 
The BLM did not receive any comments on this paragraph.
Sec. 3175.102--Verification and Calibration of Electronic Gas 
Measurement Systems
Sec. 3175.102(a)
    Section 3175.102(a) includes several specific requirements for the 
verification and calibration of transducers following installation and 
repair. This differentiates the procedures that are specific to this 
type of verification from the procedures required for a routine 
verification under Sec.  3175.102(c). The primary difference between 
Sec.  3175.102(a) and (c) is that an as-found verification is not 
required if the meter is being verified following installation or 
repair.
    Section 3175.102(a)(1) requires a leak test before performing a 
verification or calibration. Please see the previous discussion 
regarding Sec.  3175.92(a)(1) for further explanation of leak testing.
    The BLM received one comment in response to this requirement 
stating support for the proposed requirement for a leak test prior to 
performing verification of equipment. No change was requested. The BLM 
did not make any changes to the rule based on this comment.
    Section 3175.102(a)(2) requires a verification to be done at the 
points required by API 21.1, Subsection 7.3.3 (zero percent, 25 
percent, 50 percent, 100 percent, 80 percent, 20 percent, and zero 
percent of the calibrated span of the differential-pressure and static-
pressure transducers, respectively). This includes more verification 
points than are required for a routine verification described in Sec.  
3175.102(c). The purpose of requiring more verification points in this 
section is: (1) For new installations, the normal operating points for 
differential and static pressure may not be known because of a lack of 
historical operating information; and (2) A more rigorous verification 
is required to ensure that new or repaired equipment is working 
properly between the lower and upper calibrated limits of the 
transducer.
    The BLM received several comments stating that the proposed rule 
implies that an operator could not recalibrate the transducer to bring 
it into compliance and that the only solution is to replace the 
transducer. The BLM does not agree with these comments. Section 
3175.102(a)(2) states: ``If any of these as-left readings vary from the 
test equipment by more than the tolerance determined by API 21.1, 
Subsection 8.2.2.2, Equation 24 (see Sec.  3175.30), then that 
transducer must be replaced

[[Page 81572]]

and retested under this paragraph.'' The term ``as-left,'' as defined 
in Sec.  3175.10, means: ``The reading of a mechanical or electronic 
transducer when compared to a certified test device, after making 
adjustments to the transducer, but prior to returning the transducer to 
service.'' An operator must perform an as-left verification prior to 
returning the meter to service if the transducer was calibrated. The 
as-left verification assumes that the operator has done whatever they 
could to achieve the tolerances of API 21.1, Subsection 8.2.2.2, 
Equation 24, including multiple calibrations or recalibrations. The BLM 
did not make any changes to the rule based on these comments.
    Other commenters stated that older meters are incapable of 
verification at six points and should be grandfathered, and that the 
additional verification at the proposed points would increase time and 
cost without improving accuracy. The BLM does not agree. There are no 
limits to the number of verification points that a flow computer can 
provide. An operator can obtain a verification point by comparing the 
reading from the test equipment with the reading from the flow 
computer. While some flow computers may have limitations on the number 
of verification points that the event log will record, the BLM does not 
require the flow computer to log verification points. The BLM did not 
make any changes to the rule based on this comment.
    Another commenter said the proposed rule did not allow for a 
working-pressure zero adjustment and, as a result, a transmitter could 
appear to be out of calibration when it is not. A working-pressure zero 
adjustment compares the differential-pressure transducer's reading, 
when line pressure is applied to both sides of the transducer, to the 
transducer's reading when atmospheric pressure is applied to both 
sides. This difference is then applied to all readings determined from 
a differential-pressure verification, which is done at atmospheric 
pressure. The BLM disagrees with this comment. Section 3175.102(a)(2) 
is specific to new FMPs or to transducers that the operator has 
replaced or repaired. Because the operator has just installed this 
transducer and it has not yet been subjected to working pressure, there 
would be no way do a working-pressure zero adjustment. Section 
3175.102(a)(4) requires the operator to re-zero the transducer prior to 
returning it to service if the difference between atmospheric-pressure 
zero and working-pressure zero is greater than the tolerance defined in 
Equation 24. The BLM did not make any changes to the rule based on this 
comment.
    Proposed Sec.  3175.102(a)(3) would have required the operator to 
calculate the value of atmospheric pressure used to calibrate an 
absolute-pressure transducer from elevation using the equation or table 
given in Appendix A to this subpart, or to be based on a barometer 
measurement made at the time of verification for absolute-pressure 
transducers in an EGM system. Under this rule, use of the value for 
atmospheric pressure defined in the buy/sell contract is not allowed 
unless it meets the requirements stated in this section. The BLM is 
eliminating the use of a contract value for atmospheric pressure 
because contract provisions are not always in the public interest, and 
they do not always dictate the best measurement practice. A contract 
value that is not representative of the actual atmospheric pressure at 
the meter will cause measurement bias, especially in meters where the 
static pressure is low. If a barometer is used to determine the 
atmospheric pressure, the barometer must be certified by the National 
Institute of Standards and Technology (NIST) and have an accuracy of 
0.05 psi, or better. This will ensure the value of 
atmospheric pressure entered into the flow computer during the 
verification process represents the true atmospheric pressure at the 
meter station.
    This requirement is different from the requirements in Sec.  
3175.94(b) for the treatment of atmospheric pressure in connection with 
mechanical recorders. The difference results from the design of the 
pressure measurement device--whether it is a gauge pressure device or 
an absolute pressure device. A gauge pressure device measures the 
difference between the applied pressure and the atmospheric pressure. 
An absolute pressure device measures the difference between the applied 
pressure and an absolute vacuum. The use of a barometer to determine 
atmospheric pressure is allowed only when calibrating an absolute 
pressure transducer. It is not allowed for gauge pressure transducers. 
Because all mechanical recorders are gauge pressure devices (even if 
the pen has been offset to account for atmospheric pressure), the use 
of a barometer to establish atmospheric pressure is not allowed.
    The BLM received several comments in response to this proposed 
requirement. One commenter stated that this does not allow for local 
changes in barometric pressure. The BLM agrees that a calculation of 
atmospheric pressure would not account for local changes in barometric 
pressure, presumably due to weather systems in the area. However, the 
additional uncertainty caused by weather systems is easy to estimate 
and include in the calculation of overall uncertainty (the BLM 
uncertainty calculator does this). Another commenter proposed using the 
barometric pressure reported by the National Weather Service if a 
barometer was not available. The BLM disagrees because a barometric 
pressure reported by the National Weather Service is generally 
corrected to mean sea level and does not represent the true atmospheric 
pressure at the FMP location. Even if the National Weather Service, or 
other weather service, were to provide a true uncorrected barometric 
pressure, it would be specific to the elevation of an airport or other 
fixed location and would most likely not represent the true atmospheric 
pressure at the FMP location. The BLM did not make any changes to the 
rule based on these suggestions.
    One commenter suggested the option of using a static pressure 
calibration device that applies absolute pressures to the static-
pressure transducer (virtually all calibration devices in use today 
apply gauge pressure to the static-pressure transducer), as long as it 
is twice as accurate as the transducer under calibration. The BLM 
agrees with this suggestion and added this option to Sec.  
3175.102(a)(3). However, the absolute pressure calibration device would 
not have to be twice as accurate as the transducer being calibrated, as 
long as it meets the requirements of a calibration device in Sec.  
3175.102(h).
    Proposed Sec.  3175.102(a)(4) would have required the operator to 
re-zero the differential-pressure transducer under working pressure 
before putting the meter into service. Differential-pressure 
transducers are verified and calibrated by applying known pressures to 
the high side of the transducer while leaving the low side vented to 
the atmosphere. When a differential-pressure transducer is placed into 
service, the transducer is subject to static (line) pressure on both 
the high side and the low side (with small differences in pressure 
between the high and low sides due to flow). The change from 
atmospheric-pressure conditions to static-pressure conditions can cause 
all the readings from the transducer to shift, usually by the same 
amount.
    Typically, the higher the static pressure is, the more shift 
occurs. Zero shift can be minimized by re-zeroing the differential-
pressure transducer when the high side and low side are equalized under 
static pressure. The re-zeroing proposed in this section would have 
been a new requirement that would eliminate measurement errors caused 
by

[[Page 81573]]

static-pressure zero-shift of the differential-pressure transducer. Re-
zeroing is recommended in API 21.1, Subsection 8.2.2.3, but not 
required. The BLM proposed to require it here. The BLM received several 
comments in response to the proposed requirement, objecting to re-
zeroing if the transducer's reading did not change more than the 
tolerance required in API 21.1, Subsection 8.2.2.2, Equation 24, when 
subjected to working pressure. The BLM generally agrees with this 
comment. The BLM added language that requires re-zeroing the transducer 
only if the absolute value of the transducer reading is greater than 
the reference accuracy of the transducer, expressed in inches of water 
column. The BLM did not reference Equation 24 because test equipment is 
not used to check the zero shift due to working pressure. If the 
accuracy of the verification equipment is removed from Equation 24, the 
equation reduces to the reference accuracy of the transducer, which is 
the language the BLM used in making this change.
Sec. 3175.102(b)
    Section 3175.102(b) establishes requirements for how often a 
routine verification must be performed where the minimum frequency, in 
months, is shown in Table 1 to Sec.  3175.100. The proposed rule would 
have required a verification every month for very-high-volume FMPs, 
every 3 months for high-volume FMPs, every 6 months for low-volume 
FMPs, and every 12 months for very-low-volume FMPs. Because there is a 
greater risk of measurement error in the volume calculation for a given 
transducer error at higher-volume FMPs, the proposed rule would have 
increased the verification frequency as the measured volume increases.
    The BLM received several comments in response to this proposed 
requirement. One commenter stated that they wanted the terminology 
changed from the number of months between verifications to the number 
of times per year the verification had to be accomplished. For example, 
instead of ``every 3 months,'' the requirement should read 
``quarterly.'' The BLM did not make any changes to the rule as a result 
of this comment because the BLM believes the frequency of required 
verifications given in Table 1 to Sec.  3175.100, is clear as written. 
In addition, a term such as ``quarterly'' could be interpreted to mean 
that a routine verification could be done at the beginning of one 
quarter and at the end of another quarter, essentially doubling the 
time between verifications that the BLM intended.
    Several commenters stated that the calibration frequency was 
excessive on very-high-volume FMPs while other commenters stated that 
the calibration frequency should be increased to every 6 months on 
very-low-volume FMPs. The BLM agrees that modern equipment does not 
drift significantly and calibration can cause more error than it solves 
due to human error during the calibration process. As a result, the BLM 
changed the required verification frequency for very-high-volume FMPs 
from once every month to once every 3 months. The BLM did not change 
the verification frequency for very-low-volume FMPs because it is based 
on an economic model that does not justify a calibration frequency 
higher than annual.
Sec. 3175.102(c)
    Section 3175.102(c) adopts the procedures in API 21.1, Subsection 
8.2, for the routine verification and calibration of transducers with 
several additions and clarifications. The primary difference between 
Sec.  3175.102(a) and (c) is that an as-found verification is required 
for routine verifications in Sec.  3175.102(c).
    Section 3175.102(c)(1) requires a leak test before performing a 
verification. A leak test is not specified in API 21.1, Subsection 8.2; 
however, the BLM believes that performing a leak test is critical to 
obtaining accurate measurement. Please see the previous discussion of 
Sec.  3175.92(a)(1) for further explanation of leak testing.
    The BLM received one comment in response to the proposed 
requirement in Sec.  3175.102(c)(1) on performing a leak test. The 
commenter stated that a leak test should not be required on non-
regulated pressure sources because leaks are readily detectable without 
having to perform a leak test. The BLM believes that the commenter is 
using the term ``regulated'' pressure source to refer to devices such 
as deadweight testers. A regulated pressure source could mask a leak 
because, if a leak were present, it would continuously add air or gas 
to the system to maintain a constant pressure. In theory, a non-
regulated pressure source would not mask a leak. However, a leak could 
still be masked with a non-regulated pressure source if, for example, 
the valve on the pressure source is not shut off completely during the 
calibration. The BLM did not make a change to the rule based on this 
comment. The BLM believes a leak test is the only definitive way to 
determine if leaks are present and it is neither onerous nor time 
consuming to perform.
    Section 3175.102(c)(2) requires that the operator perform an as-
found verification at the normal operating point of each transducer. 
This clarifies the requirements in API 21.1, Subsection 8.2.2.3, which 
requires a verification at either the normal point or 50 percent of the 
upper user-defined operating limit. This paragraph also defines how the 
normal operating point is determined because this is a common point of 
confusion for operators and the BLM.
    The BLM received one comment in response to the proposed 
requirement in Sec.  3175.102(c)(2) on the verification at the normal 
operating point of each transducer. The commenter requested 
clarification on how close they have to be to the normal point when 
verifying a transducer. For example, the commenter stated that they 
already do a 10-point verification on the differential-pressure 
transducer and wondered if that would be sufficient to comply with the 
normal point requirement. The BLM agrees with the commenter that 
clarification is needed, and added clarification in the final rule that 
for differential and static-pressure transducers, the pressure applied 
to the transducer for this verification must be within five percentage 
points of the normal operating point, while for the temperature 
transducer, the water bath or test-thermometer well must be within 20 
[deg]F of the normal operating point.
    In addition to making the changes to this section in response to 
comments, the BLM added a new Sec.  3175.102(c)(3) that requires 
operators to replace transducers when the as-found verification exceeds 
the manufacturer's specification for stability or drift, as adjusted 
for static pressure and ambient temperature, on two consecutive 
verifications. The BLM added this requirement in lieu of the long-term 
stability test that was eliminated from Sec.  3175.133(g). Because the 
BLM does not have any way to verify the long-term stability 
specification provided by the manufacturer without testing, the BLM 
will enforce the manufacturer's specifications during field 
verification. There is no reason that a properly functioning transducer 
should be outside of the stability or drift specification once 
adjustments for static pressure (on differential-pressure transducers) 
and ambient temperature are factored out. Manufacturer's specifications 
include both static pressure effects on differential-pressure 
transducers and ambient temperature effects. The BLM plans to add the 
capability of determining the maximum allowable drift to the BLM 
uncertainty calculator to make this requirement easier to enforce.

[[Page 81574]]

    Section 3175.102(c)(4) also requires that the operator perform an 
as-left verification at the normal operating point of each transducer. 
The BLM did not receive any comments on this paragraph.
    Section 3175.102(c)(5) (Sec.  3175.102(c)(4) in the proposed rule) 
requires the operator to correct the as-found values for differential 
pressure taken under atmospheric conditions to working pressure values 
based on the difference between working-pressure zero and the zero 
value obtained at atmospheric pressure. Please see the previous 
discussion of proposed Sec.  3175.102(a)(4) for further explanation of 
zero shift. API 21.1, Subsection 8.2.2.3, recommends that this 
correction be made, but does not require it. API also provides a 
methodology for the correction. The correction methodology in API 21.1, 
Annex H, is required in this section. The BLM did not receive any 
comments on this paragraph.
    Section 3175.102(c)(6) (Sec.  3175.102(c)(5) in the proposed rule) 
adopts the allowable tolerance between the test device and the device 
being tested as stated in API 21.1, Subsection 8.2.2.2. This tolerance 
is based on the reference uncertainty of the transducer and the 
uncertainty of the test equipment.
    The BLM received several comments in response to this proposed 
requirement. One commenter stated that the verification tolerances in 
API 21.1, Subsection 8.2.2.2, are complex and restrictive and that the 
BLM should not require operators to follow it. The BLM disagrees. The 
purpose of establishing a verification tolerance is to ensure that a 
calibration is only required when the transducer readings have drifted 
outside of the combined accuracy of both the transducer and the test 
equipment. The API requirement for verification tolerance is similar to 
the verification tolerance in the BLM statewide NTLs for EFCs. Because 
API 21.1 no longer requires the test equipment to be twice as accurate 
as the equipment being tested, the added uncertainty of the test 
equipment can no longer be ignored and must be included in the 
determination of verification tolerance. The BLM did not make any 
changes to the rule based on this comment.
    Another commenter suggested tying the verification tolerance of the 
temperature transmitter to the uncertainty of the temperature 
transmitter rather than establishing a set value of 0.5 [deg]F as 
required in the proposed rule. The BLM agrees that tying the 
verification tolerance to the uncertainty is consistent with the 
requirement for differential and static-pressure transducers. The BLM 
added that the verification tolerance for temperature transmitters is 
equivalent to the uncertainty of the temperature transmitter or 0.5 
[deg]F, whichever is greater.
    Section 3175.102(c)(7) (Sec.  3175.102(c)(6) in the proposed rule) 
clarifies that all required verification points must be within the 
verification tolerance before returning the meter to service. This 
requirement is implied by API 21.1, Subsection 8.2.2.2, but is not 
clearly stated. The BLM did not receive any comments on this paragraph.
    Proposed Sec.  3175.102(c)(8) (Sec.  3175.102(c)(7) in the proposed 
rule) would have required the differential-pressure transducer to be 
zeroed at working pressure before returning the meter to service. This 
is implied by API 21.1, Subsection 8.2.2.3, but not required. Refer to 
the discussion of zero shift under Sec.  3175.102(a)(4) for further 
information.
    The BLM received several comments in response to this proposed 
requirement. The commenters stated that it was an unnecessary step to 
re-zero the differential transducer if it was already reading zero. The 
BLM agrees with the commenters and changed the proposed rule to require 
operators to re-zero the differential-pressure transducer only if the 
absolute value of the transducer reading under pressure is greater than 
the reference accuracy of the transducer, expressed in inches of water 
column. See the discussion under Sec.  3175.102(a)(4).
Sec. 3175.102(d)
    Section 3175.102(d) allows for redundancy verification in lieu of a 
routine verification under Sec.  3175.102(c). Redundancy verification 
was added to the current version of API 21.1 as an acceptable method of 
ensuring the accuracy of the transducers in lieu of performing routine 
verifications. Redundancy verification is accomplished by installing 
two EGM systems on a single differential flow meter and then comparing 
the differential pressure, static pressure, and temperature readings 
from the two EGM systems. If the readings vary by more than a set 
amount, both sets of transducers would have to be calibrated and 
verified. Operators have the option of performing routine verifications 
at the frequency required under Sec.  3175.102(b) or employing 
redundancy verification under this paragraph. Operators may realize 
cost savings by adopting redundancy verification, especially on high- 
or very-high-volume FMPs. The rule adopts API 21.1, Subsection 8.2, 
procedures for redundancy verifications with several additions and 
clarifications as follows.
    Section 3175.102(d)(1) requires the operator to identify separately 
the primary set of transducers from the set of transducers that is used 
as a check. This requirement allows the BLM to know which set should be 
used for auditing the volumes reported on the OGOR.
    Section 3175.102(d)(2) requires the operator to compare the average 
differential pressure, static pressure, and temperature readings taken 
by each transducer set every calendar month. API 21.1, Subsection 8.2, 
does not specify a frequency at which this comparison should be done.
    Section 3175.102(d)(3) establishes the tolerance between the two 
sets of transducers that will trigger a verification of both sets of 
transducers under Sec.  3175.102(c). API 21.1 does not establish a set 
tolerance. This section also requires the operator to perform a 
verification within 5 days of discovering the tolerance has been 
exceeded.
    The BLM did not receive any comments on Sec.  3175.102(d).
Sec. 3175.102(e)
    Section 3175.102(e) establishes requirements for retaining 
documentation related to each verification and calibration. This 
section also establishes the information that the operator must retain 
onsite for redundancy verifications. Section 3175.102(e)(1)(i) refers 
to Sec.  3170.7 (Sec.  3170.6 in the proposed rule), which lists the 
information that operators must include on all source records.
    The BLM received a few comments in response to the proposed 
requirement in Sec.  3175.102(e). The commenters stated that the 
retention of the FMP number required in proposed Sec.  3170.6 (Sec.  
3170.7 in the final rule) would take some time to implement, and that 
the citation to Sec.  3170.6 should be changed to Sec.  3170.7. The BLM 
agrees with the commenters, corrected the citations, and, in final 
subpart 3170, changed Sec.  3170.7 to require operators to use either 
an FMP number or the lease, unit PA, or CA number, along with a unique 
meter identification number, on verification documentation. (Operators 
still have the option of using the FMP number.)
    The BLM also added a provision to the first sentence of this 
paragraph clarifying that the documentation requirements of this 
paragraph also apply to transducers that are replaced to ensure that 
operators document how much in error the broken transducers were prior 
to replacement.

[[Page 81575]]

Sec. 3175.102(f)
    Proposed Sec.  3175.102(f) would have required the operator to 
notify the BLM at least 72 hours before verification of an EGM system. 
A 72-hour notice would be sufficient for the BLM to rearrange 
schedules, as necessary, to be present at the verification.
    The BLM received a few comments in response to this proposed 
requirement. The commenters stated that the 72-hour notification before 
performing verification would require a great deal of coordination. The 
BLM agrees with these comments and has included an alternative to 
submit a monthly or quarterly verification schedule to the AO for 
routine verifications performed under Sec.  3175.102(c). The submittal 
of monthly or quarterly schedules in lieu of the 72-hour notice is 
already common practice in many field offices. For verifications 
performed after installation or following repair, however, the 72-hour 
notice requirement in the proposed rule was retained because it would 
be difficult for operators to schedule these on a monthly or quarterly 
basis.
Sec. 3175.102(g)
    Proposed Sec.  3175.102(g) would have required correction of flow-
rate errors greater than 2 percent or 2 Mcf/day, whichever is less, if 
the errors are due to the transducers being out of calibration, by 
submitting amended reports to ONRR. For lower-volume meters, a 2 
percent error may represent only a small amount of volume. Assuming the 
2 percent error resulted in an underpayment of royalty, the amount of 
royalty recovered by receiving amended reports may not cover the costs 
incurred by the BLM or ONRR of identifying and correcting the error. 
This rule adds an additional threshold of 2 Mcf/day to exempt amended 
reports on low-volume, small-error FMPs.
    The BLM received numerous comments in response to this proposed 
requirement stating that this would be an onerous requirement and that 
the term ``less'' should be changed to ``greater.'' The BLM agrees with 
the comments on changing the term ``less'' to ``greater.'' That was an 
oversight in the proposed rule. To further clarify flow rate error 
volume correction when the date on which the error occurred is unknown, 
this section refers to an example in Sec.  3175.92(f).
    One commenter suggested that volume corrections should only be 
required when the flow rate error is greater than 2 percent or 100 Mcf/
month, whichever is less. The BLM did not make any changes to the rule 
based on this comment because there was no compelling rationale for 
this change given by the commenter. The value of 100 Mcf/month is 
approximately 3 Mcf/day, which is essentially the same as the 2 Mcf/day 
threshold the BLM adopted in this rule.
    Section 3175.102(g) also defines the points that are used to 
determine the flow rate error. Calculated flow-rate error will vary 
depending on the verification points used in the calculation. The 
normal operating points must be used because these points, by 
definition, represent the flow rate normally measured by the meter. As 
specified in Table 1 to Sec.  3175.100, very-low-volume FMPs are exempt 
from this requirement because the volumes are so small that even 
relatively large errors discovered during the verification process will 
not result in significant lost royalties, and thus, the process of 
amending reports would not be worth the costs involved for either the 
operator or the BLM. Please see the example given in the discussion of 
Sec.  3175.92(f).
Sec. 3175.102(h)
    Section 3175.102(h)(1) requires verification equipment to be 
certified at least every 2 years. The purpose of this requirement is to 
ensure that the verification or calibration equipment meets its 
specified level of accuracy and does not introduce significant bias 
into the field meter during calibration. Two-year certification of 
verification equipment is not required by API 21.1; however, the BLM 
believes that periodic certification is necessary. This requirement is 
consistent with requirements in the previous edition of API 21.1 
(1993), which was adopted by the statewide NTLs for EFCs. This section 
also requires that proof of certification be available to the BLM at 
the time of inspection and sets minimum standards as to what the 
documentation must include. The minimum documentation standard 
represents common industry practice.
    Section 3175.102(h)(2) adopts language in API 21.1, Subsection 8.4, 
regarding the accuracy of test equipment. The statewide NTLs, which 
adopted the standards of API 21.1 (1993), required that the test 
equipment be at least two times more accurate than the device being 
tested. The purpose of this requirement was to reduce the additional 
uncertainty from the test equipment to an insignificant level. Many of 
the newer transducers being used in the field are of such high accuracy 
that field test equipment cannot meet the standard of being twice as 
accurate. Therefore, the current API 21.1 allows test equipment with an 
uncertainty of no more than 0.10 percent of the upper calibrated limit 
of the transducer being tested, even if it is not two times more 
accurate than the transducer being tested. For example, verifying a 
transducer with a reference accuracy of 0.10 percent of the upper 
calibrated limit with test equipment that was at least twice as 
accurate as the device being tested, would require the test equipment 
to have an accuracy of 0.05 percent or better of the upper calibrated 
limit of the device being tested. This level of accuracy is very 
difficult to achieve outside of a laboratory. As a result, API 21.1, 
Subsection 8.4, and Sec.  3175.102(h) only require the test equipment 
to have an accuracy of 0.10 percent of the upper calibrated limit of 
the device being tested. However, because the test equipment is no 
longer at least twice as accurate as the device being tested (they 
would both have an accuracy of 0.10 percent in this example), the 
additional uncertainty from the test equipment is no longer 
insignificant and must be accounted for when determining overall 
measurement uncertainty. The BLM will verify the overall measurement 
uncertainty--including the effects of the calibration equipment 
uncertainty--by using the BLM uncertainty calculator or an equivalent 
tool during the witnessing of a meter verification.
    The BLM received several comments in response to this proposed 
requirement. The commenters stated that improvements in the accuracy of 
transducers are outpacing improvements in the accuracy of test 
equipment, and it is difficult to find test equipment that is twice as 
accurate as the transducers under test outside of a laboratory setting. 
The commenters recommended granting a variance in this situation. The 
BLM recognizes that many transducers are accurate enough that field 
test equipment cannot achieve double the accuracy of the transducer 
under test. That is why the BLM added paragraph (h)(2)(ii) to this 
section. Paragraph (h)(2)(ii) allows operators to use test equipment 
with an accuracy of 0.10 percent of the upper calibrated limit of the 
transducer under test even if it is not twice as accurate as the 
transducer under test. The additional uncertainty resulting from test 
equipment that is not at least twice as accurate as the transducer 
under test is accounted for in the calculation of overall measurement 
uncertainty. The BLM made no changes based on these comments.

[[Page 81576]]

Sec. 3175.103--Flow Rate, Volume, and Average Value Calculation
Sec. 3175.103(a)
    Section 3175.103(a) would have prescribed the equations that must 
be used to calculate the flow rate for all FMPs. Proposed Sec.  
3175.103(a)(1) would have applied to flange-tapped orifice plates and 
would have represented a change from the statewide EFC NTLs because the 
NTLs allowed the use of either the API 14.3.3 or the AGA Report No. 3 
(1985) flow equation. The proposed rule would not have allowed the use 
of the AGA Report No. 3 (1985) flow equation because it is not as 
accurate as the API 14.3.3 flow equation and can result in measurement 
bias. The NTLs also allowed the use of either AGA Report 8 (API 14.2) 
or NX-19 to calculate supercompressibility. The proposed rule would 
have only allowed API 14.2 because it is a more accurate calculation.
    The BLM received several comments in response to this proposed 
requirement stating that AGA report No. 3 (1992 and 1985) and AGA 
Report No. 8 (1992) should be allowed since these are very similar to 
the latest standard and any change to a newer standard would put 
significant expense upon the operator. The BLM agrees that updating 
older flow computers with the latest calculation software may be cost 
prohibitive for low- and very-low-volume FMPs, especially if the 
manufacturer no longer supports software upgrades. Additionally, the 
difference in volume calculated with the latest API equations as 
compared to older versions of the API equations is not that significant 
for low- and very-low-volume FMPs. For these reasons, the BLM 
grandfathered low- and very-low-volume FMPs installed prior to the 
effective date of this rule from having to use the latest API 
equations. Please see the discussion under Sec.  3175.61.
    The BLM has incorporated AGA Report No. 8 (1992) in the final rule; 
therefore, any flow computer using the calculations in AGA Report No. 8 
would be in compliance with this rule. Very-low-volume FMPs are 
grandfathered from the requirement to calculate supercompressibility 
under API 14.3; however these flow computers still have to calculate 
supercompressibility under NX-19. The BLM made no changes based on 
these comments.
    Proposed Sec.  3175.103(a)(2) would have required use of BLM-
approved equations for devices other than a flange-tapped orifice 
plate. Because there are typically no API standards for these devices, 
the PMT would have to check the equations derived by the manufacturer 
to ensure they are consistent with the laboratory testing of these 
devices. For example, a manufacturer may use one equation to establish 
the discharge coefficient for a new type of meter that is being tested 
in the laboratory, while using another equation for the meter it 
supplies to operators in the field, potentially resulting in 
measurement bias or increased uncertainty. The BLM would have required 
that only the equation used during testing be used in the field.
    The BLM received several comments stating that the BLM should use 
equations established by API and AGA rather than those provided by the 
PMT. Under the proposed rule, the BLM would have only approved a make 
and model of a meter if it was a differential type of meter other than 
a flange-tapped orifice plate. The flange-tapped orifice meter is the 
only differential type flow meter for which there is an AGA or API 
standard; there are no AGA or API standards for any other differential 
type flow meters requiring testing and review by the PMT. As a result, 
the PMT would have to verify and approve the flow equations proposed by 
the manufacturer based on the testing of that device. In the final 
rule, the BLM has added linear meters to the types of meters that the 
BLM could approve by make and model in Sec.  3175.48. There are 
standards for many linear meters currently on the market, such as 
ultrasonic meters, Coriolis meters, and turbine meters. In light of the 
revised approval process for linear meters, the BLM added a provision 
to this paragraph to clarify that the flow rate equations recommended 
by the PMT and approved by the BLM would apply only if there are no 
industry standards for that device.
    One commenter stated that the flow rate calculation method 
developed by the PMT should be effective within 6 months of approval by 
the BLM. The flow rate calculation method would be effective 
immediately after approval by the BLM. The BLM did not make any changes 
to the rule based on this comment.
Sec. 3175.103(b)
    Section 3175.103(b) establishes a standard method for determining 
atmospheric pressure that is used to convert psig to psia. The BLM 
received one comment supporting the proposed requirement. The BLM made 
no changes based on this comment.
Sec. 3175.103(c)
    Section 3175.103(c) requires that volumes and other variables used 
for verification be determined under API 21.1.4 and Annex B of API 
21.1. The BLM did not receive any comments on this paragraph.
Sec. 3175.104--Logs and Records
Sec. 3175.104(a)
    Section 3175.104(a) establishes minimum standards for the data that 
must be provided in a daily and hourly QTR. The data requirements are 
listed in API 21.1, Subsection 5.2. In the proposed version of Sec.  
3175.104(a), the BLM would have required that the QTR include the FMP 
number (by referencing Sec.  3170.7), that certain data be reported to 
five significant digits, and that the data must be original, unaltered, 
unprocessed, and unedited. API 21.1, Subsection 5.2, recommends that 
the data be stored with enough resolution to allow recalculation within 
50 parts per million, but it does not specify the number of significant 
digits required in the QTR. The BLM proposed to add this requirement 
because if too few significant digits are reported it is impossible for 
the BLM to recalculate the reported volume with sufficient accuracy to 
determine if it is correct or in error. The BLM believes that five 
significant digits are sufficient to recalculate the reported volumes 
to the necessary level of accuracy.
    Section 3175.104(a) also requires that both daily and hourly QTRs 
submitted to the BLM must be original, unaltered, unprocessed, and 
unedited. It is common practice for operators to submit BLM-required 
QTRs using third-party software that compiles data from the flow 
computers and uses it to generate a standard report. However, the BLM 
has found in numerous cases that the data submitted from the third-
party software is not the same as the data generated directly by the 
flow computer. In addition, the BLM consistently has problems verifying 
the volumes reported through reports generated by third-party software. 
Under proposed Sec.  3175.104(a), the BLM would not have accepted 
reports generated by third-party software at all. This provision has 
been revised in the final rule to clarify that the BLM will accept data 
that was generated by third-party software, so long as that software is 
approved through the PMT process.
    The BLM received several comments in response to these proposed 
requirements. Several commenters stated that many accounting systems 
are not capable of handling an 11-digit FMP number. The BLM agrees with 
these commenters and eliminated the requirement in Sec.  3170.7(g) to 
store the FMP number in the accounting system. Instead, operators must 
use either an

[[Page 81577]]

FMP number or the lease, unit PA, or CA number, along with a unique 
meter identification number, on their logs and records.
    The BLM received several comments stating that reporting to five 
significant digits would be unworkable and recommending reporting to a 
specified number of decimal places. The BLM agrees with this comment 
and changed the final rule to require five decimal places for volume, 
flow time, extension, and three decimal places for average differential 
pressure, static pressure, and temperature.
    The commenters also stated that the BLM should allow data to be 
collected and stored in third party software that meets the 
requirements of this section and has been reviewed by the PMT. One 
commenter stated that hand collection of data from each FMP would 
require significant additions in staffing. Another commenter suggested 
that approving third party software packages should be the role of the 
PMT. The BLM agrees with these comments and established a provision for 
the PMT to review accounting systems and recommend approval by the BLM 
it if it meets the requirements under Sec.  3175.49.
Sec. 3175.104(b)
    Section 3175.104(b) establishes minimum standards for the data that 
must be provided in the configuration log. The unedited data are 
similar to the existing requirements found in API 21.1. In addition, 
the BLM proposed to require:
     The FMP number, once established;
     The software/firmware identifiers that would allow the BLM 
to determine if the software or firmware version was approved by the 
BLM;
     For very-low-volume FMPs, the fixed temperature, if the 
temperature is not continuously measured, that would allow the BLM to 
recalculate volumes;
     The static-pressure tap location that would allow the BLM 
to recalculate volumes and verify the flow rate calculations done by 
the flow computer; and
     A snapshot report that would allow the BLM to verify the 
flow-rate calculation of the flow computer.
    As described under Sec.  3175.104(a), configuration logs generated 
by third-party software would not have been accepted. Based on the 
comments received under Sec.  3175.104(a), the PMT will review and 
recommend approval of third-party software under Sec.  3175.49.
    In the final rule, the BLM adopted all of the proposed requirements 
listed above, with the exception of the FMP number requirement. The 
comments received by the BLM on Sec.  3175.104(a), regarding the FMP 
number also apply to this section. As discussed above, the final rule 
does not require operators to place the FMP number in the configuration 
log.
    The BLM received one comment stating that since the default 
location of the static-pressure tap is upstream per API 14.3.4.1, the 
static-pressure tap location should not have to be maintained in the 
configuration log unless it is located downstream. The BLM disagrees 
with the comment. It is not burdensome to identify the location of the 
static-pressure tap, and it will avoid confusion when performing 
audits.
Sec. 3175.104(c)
    Section 3175.104(c) establishes minimum standards for the data that 
must be provided in the event log. This section requires that the event 
log retain all logged changes for the time period specified in proposed 
Sec.  3170.7 (see 80 FR 40768 (July 13, 2015)). This provision will 
ensure that a complete meter history is maintained to allow 
verification of volumes. Proposed Sec.  3175.104(c)(1) would have been 
a new requirement to record power outages in the event log. This is not 
currently required by API 21.1 or the statewide NTLs for EFCs.
    The BLM received several comments in response to the proposed 
requirement in Sec.  3175.104(c)(1) (final Sec.  3175.104(c)) that the 
event log must record all power outages that inhibit the meter's 
ability to collect and store new data. The commenters stated that it is 
impossible to record a power off event with no power. Although the BLM 
believes that flow computer manufacturers could comply with this 
requirement by simply adding an additional clock, the BLM eliminated 
this requirement from the final rule because, apparently, flow 
computers do not currently have this capability.
Sec. 3175.104(d)
    Section 3175.109(d) requires the operator to retain an alarm log 
following API 21.1, Subsection 5.6. The alarm log records events that 
could potentially affect measurement, such as over-ranging the 
transducers, low power, or the failure of a transducer. The BLM did not 
receive any comments on this section.
Sec. 3175.104(e)
    Based on comments the BLM received on Sec.  3175.104(a), the BLM 
added Sec.  3175.104(e) to the final rule, which requires any 
accounting system used to submit QTRs, configuration logs, or even logs 
to the BLM, to be approved by the BLM based on a recommendation from 
the PMT. Please see Sec.  3175.49 for further discussion.
Sec. 3175.110--Gas Sampling and Analysis
    This section sets standards for gas sampling and analysis at FMPs. 
Although there are industry standards for gas sampling and analysis, 
none of these standards are adopted in whole because the BLM believes 
that they would be difficult to enforce as written. However, some 
specific requirements within these standards are sufficiently 
enforceable and are adopted in this section. Heating value, which is 
determined from a gas sample, is as important to royalty determination 
as volume. Relative density, which is determined from the same gas 
sample, affects the calculation of volume. To ensure the gas heating 
value and relative density are properly determined and reported, the 
BLM developed requirements that address where a sample must be taken, 
how it must be taken, how the sample is analyzed, and how heating value 
is reported.
    Table 1 to Sec.  3175.110 contains a summary of requirements for 
gas sampling and analysis. The first column of Table 1 to Sec.  
3175.110 lists the subject of the standard. The second column contains 
a reference for the standard (by section number and paragraph) that 
applies to each subject area. The final four columns indicate the 
categories of FMPs for which the standard applies. The FMPs are 
categorized by the amount of flow they measure on a monthly basis. As 
in other tables, ``VL'' is very-low-volume FMP, ``L'' is low-volume 
FMP, ``H'' is high-volume FMP, and ``VH'' is very-high-volume FMP. 
Definitions of the various classifications are included in Sec.  
3175.10. An ``x'' in a column indicates that the standard listed 
applies to that category of FMP.
    The BLM received numerous comments objecting to the proposed 
requirements in Sec.  3175.110, suggesting that the BLM should use the 
API, AGA, and GPA gas sampling standards as written instead of 
developing new standards, or work with these organizations to develop 
new or revised standards if needed. The BLM incorporated the API and 
GPA sample standards to the extent possible. However, the BLM added 
clarification to the standards to ensure they are enforceable and to 
ensure that heating values are not under-reported by excluding liquids 
that may be flowing through the meter. Further explanation of these and 
other comments are discussed in the individual sections relating to gas 
sampling and analysis.

[[Page 81578]]

The BLM did not make any changes to this section based on these 
comments.
    One commenter stated that the cost of gas sampling and meter 
inspection frequencies would require them to increase staff by two-
fold. However, the commenter did not offer any data to support this 
assertion. The BLM has accounted for this cost in the Economic and 
Threshold Analysis by accounting for the cost of taking a gas sample 
and performing a meter inspection. These costs include the labor costs 
of taking a sample which would also account for hiring additional staff 
if needed. The BLM did not make any changes to the rule based on this 
comment.
    Another commenter stated that increased gas sampling frequency 
could negatively impact royalties from Coalbed Methane (CBM) production 
because the heating value of CBM tends to decline over time as the 
amount of carbon dioxide increases. Specifically, the presence of 
carbon dioxide in CBM gas decreases its heating value. As stated 
earlier, the goal of the rule is to improve measurement accuracy and 
verifiability, not to increase total royalty revenue. Therefore, it is 
the BLM's intent that the reported heating value needs to reflect, to 
the extent possible, the actual heating value of the gas being 
produced.
Sec. 3175.111--General Sampling Requirements
Sec. 3175.111(a)
    Section 3175.111(a) establishes the allowable methods of sampling. 
These sampling methods have been reviewed by the BLM and have been 
determined to be acceptable for heating value and relative density 
determination at FMPs. The BLM did not receive any comments on this 
paragraph.
Sec. 3175.111(b)
    Proposed Sec.  3175.111(b) would have set standards for heating 
requirements based on several industry references requiring the heating 
of all sampling components to at least 30 [deg]F above the HCDP. The 
purpose of the heating requirement is to prevent the condensation of 
heavier components, which could bias the heating value. This proposed 
section would have applied to all sampling systems, including spot 
sampling using a cylinder, spot sampling using a portable GC, composite 
sampling, and on-line GCs. Because most of the onshore FMPs will be 
downstream of a separator, the HCDP is defined in Sec.  3175.10 as the 
flowing temperature of the gas at the FMP, unless otherwise approved by 
the AO. This would have required the heating of all components of the 
gas sampling system at locations where the ambient temperature is less 
than 30 [deg]F above the flowing temperature at the time of sampling.
    The BLM received numerous comments objecting to Sec.  3175.111(b) 
in the proposed rule. Several commenters stated that the 30 [deg]F 
requirement in API 14.1 was intended to prevent condensation and not to 
vaporize the gas being sampled. Other commenters stated that the 30 
[deg]F requirement applies when the HCDP is calculated and is not 
required if the HCDP is known. Because the BLM assumed the HCDP is the 
same as the flowing temperature of the gas in most cases, the 
commenters state that heating to 30 [deg]F above flowing temperature is 
not required. One commenter suggested the BLM change the proposed rule 
to require operators to maintain the temperature of all gas sampling 
components at or above the flowing gas temperature. The BLM agrees with 
these comments and changed this paragraph to give operators the option 
of maintaining all sampling components at or above the flowing 
temperature of the gas or 30 [deg]F above a calculated HCDP, whichever 
is less. The latter option would most likely apply to lean gases where 
the calculated HCDP is well below the flowing gas temperature.
    One commenter stated that it is not necessary to assume the HCDP 
equals flowing temperature, and the HCDP can be calculated off of a 
previous sample. While the BLM agrees with this statement, nothing in 
the definition of HCDP would prevent an operator from proposing this 
method to the BLM for determining the HCDP at a particular FMP. The 
calculated HCDP would, however, be subject to the 30 [deg]F heating 
requirement under the rule. The BLM did not make any changes to the 
rule based on this comment.
    Another commenter stated that heating is not necessary for a dry 
gas. The BLM agrees that this may be true depending on the 
circumstances and what the commenter considers a ``dry gas.'' If, for 
example, a dry (lean) gas has a calculated HCDP of 25 [deg]F (and the 
AO approved the use of a calculated HCDP), and the sample was taken 
when the ambient temperature was 60 [deg]F, no heating would be 
required because the ambient temperature, and hence the temperature of 
the sampling equipment, would be greater than 30 [deg]F above the 
calculated HCDP. The BLM did not make any changes to the rule in 
response to this comment because the rule already accommodates this 
scenario.
    One commenter stated that sampling without heating could bias the 
heating value to the high side. While the commenter did not elaborate 
on why they believe this is true, the BLM agrees that heating is 
necessary to obtain an accurate heating value. The BLM did not make any 
changes to the proposed rule based on this comment.
Sec. 3175.112--Sampling Probe and Tubing
    As specified in Table 1 to Sec.  3175.110, very-low-volume FMPs are 
exempt from all requirements in Sec.  3175.112 because, based on BLM 
experience with this level of production, a requirement to install or 
relocate a sample probe in very-low-volume FMPs could cause the well to 
be shut in.
Sec. 3175.112(a)
    Section 3175.112(a) requires that all gas samples must be taken 
from a probe that complies with requirements of this section. The 
intent of the standard is to obtain a representative sample of the gas 
flowing through the meter. Samples taken from the wall of a pipe or a 
meter manifold are not representative of the gas flowing through the 
meter and could bias the heating value used in royalty determination. 
The BLM did not receive any comments on this paragraph.
Sec. 3175.112(b)
    Proposed Sec.  3175.112(b)(1) would have placed limits on how far 
away the sample probe can be from the primary device to ensure that the 
sample taken accurately represents the gas flowing through the meter. 
API 14.1 requires the sample probe to be at least five pipe diameters 
downstream of a major disturbance such as a primary device, but it does 
not specify a maximum distance. Under this proposal the operator would 
have had to place the sample probe between 1.0 and 2.0 times dimension 
``DL'' (downstream length) downstream of the primary device. Dimension 
``DL'' (API 14.3.2, Tables 7 and 8) ranges from 2.8 to 4.5 pipe 
diameters, depending on the Beta ratio. Therefore, the sample probe 
would have had to be placed between 2.8 and 9.0 pipe diameters 
downstream of the orifice plate, which is different than the 
requirement in API 14.1 noted above.
    The sampling methods listed in API 14.1 and GPA 2166-05 will 
provide representative samples only if the gas is at or above the HCDP. 
It is likely that the gas at many FMPs is at or below the HCDP because 
many FMPs are immediately downstream of a separator. A separator 
necessarily operates at the HCDP, and any temperature reduction between 
the separator and the meter will cause liquids to form at the meter. To 
properly account for the total energy

[[Page 81579]]

content of the hydrocarbons flowing through the meter, the sample must 
account for any liquids that are present. Gas immediately downstream of 
a primary device has a higher velocity, lower pressure, and a higher 
amount of turbulence than gas further away from the primary device. For 
the proposed rule, the BLM hypothesized that liquids present 
immediately downstream of the primary device are more likely to be 
disbursed into the gas stream than attached to the pipe walls. 
Therefore, a sample probe placed as close to the primary device as 
possible should have captured a more representative sample of the 
hydrocarbons--both liquid and gas--flowing through the meter than a 
sample probe placed further downstream of the meter. Any liquids 
captured by the sample probe would have been vaporized because of the 
heating requirements in proposed Sec.  3175.111(b).
    The BLM requested data supporting or contradicting any correlation 
between sample probe location and heating value or composition. The BLM 
also requested alternatives to this proposal, such as wet gas sampling 
techniques. The BLM did not receive any data or alternatives.
    The BLM received numerous comments objecting to Sec.  
3175.112(b)(1) in the proposed rule. Many of the commenters stated that 
there is no technology currently available to extract entrained liquids 
to determine an accurate heating value, and that API 14.1 and GPA 2166 
are only applicable to single-phase gas streams at or above the HCDP of 
the gas. Other commenters stated that the required sample probe 
location in the proposed rule is in direct conflict with API and GPA 
standards, and the BLM should just adopt those standards as written. 
Some comments stated that moving sample probes to comply with the 
proposed requirement would be cost prohibitive, could interfere with 
the pressure recovery downstream of the orifice plate, and would make 
it difficult to comply with both the sample probe placement 
requirements in API 14.1 as well as the proposed requirement. Several 
comments stated that low and very-low-volume FMPs should be exempt from 
the requirement. The BLM agrees with these comments and changed the 
final rule to adopt the sample probe placement requirements in API 
14.1. However, the BLM retained the requirement that the sample probe 
be the first obstruction downstream of the primary device.
    The BLM received one comment stating that the proper place to 
sample the gas is upstream of the orifice plate because liquids are 
less likely to fall out. Because the commenter did not provide any data 
to substantiate this claim, the BLM did not make any changes to the 
rule based on this comment.
    Section 3175.112(b)(2) requires that the sample probe must be 
exposed to the same ambient temperature as the primary device. Locating 
the sample probe in the same ambient temperature as the primary device 
is not specifically addressed in API or GPA standards, but is intended 
to ensure that the gas sample contains the same constituents as the gas 
that flowed through the primary device. For example, if a primary 
device is located inside a heated meter house and the sample probe is 
outside the meter house, then condensation of heavier gas components 
could occur between the primary device and the sample point, thereby 
biasing the heating value and relative density of the gas.
    The BLM received several comments objecting to the proposed 
requirement. The example provided for this requirement was specific to 
moving the sample probe into a heated meter house. The commenters 
believe it is impractical and cost prohibitive for the sample probe to 
be moved to a location where it is at the same ambient temperature as 
the primary device. The BLM agrees with this comment and added language 
to the final rule that allows the operator to comply with this standard 
by adding insulation or heat tracing along the entire meter run in lieu 
of moving the probe. Because it is difficult to define with any 
uniformity what level of insulation is needed to meet the intent of 
this requirement due to regional and local variations in operating 
conditions, the BLM did not establish specific requirements with 
respect to insulation in the final rule and, instead, added language 
which states that the AO may prescribe the quality of the insulation 
based on site specific factors such as ambient temperature, flowing 
temperature of the gas, composition of the gas, and location of the 
sample probe in relation to the orifice plate (i.e., inside or outside 
of a meter house). Note that the insulation option pertaining to the 
sample probe is identical to the insulation option pertaining to the 
thermometer well under Sec.  3175.80(l)(2). Therefore, if an operator 
applied insulation to comply with the sample probe requirements in this 
section, they would also comply with the thermometer-well requirements 
under Sec.  3175.80(l)(2) and vice versa.
    One commenter stated that this requirement is not necessary because 
of the requirement in Sec.  3175.111(b) to maintain the temperature of 
all sampling equipment at or above the flowing temperature of the gas. 
The BLM does not agree with this comment. While the heating requirement 
in Sec.  3175.111(b) ensures that liquids will not form once the gas 
leaves the meter tube, it does nothing to ensure that the liquids do 
not form inside the meter tube. Any drop in temperature between the 
orifice plate and the sample probe could cause liquids to form. Because 
liquids tend to travel along the walls of the pipe, there is less 
chance that they would be collected in the sample even without a 
membrane filter installed in the sample probe. This increases the 
potential for liquids forming after the orifice plate to be unaccounted 
for. In practice, by complying with the requirement in Sec.  
3175.80(l), for thermometer wells to sense the same gas temperature 
that exists at the orifice plate, and with Sec.  3175.112(b)(1) 
requiring the sample probe to be the first obstruction downstream of 
the orifice plate, operators would automatically comply with this 
requirement. In other words, if an operator insulated a meter run to 
comply with Sec.  3175.80(l), the insulation would also cover the 
sample probe, which must be placed upstream of the thermometer well. 
The BLM did not make any changes to the rule as a result of this 
comment.
Sec. 3175.112(c)
    Section 3175.112(c)(1) through (3) sets standards for the design 
and type of the sample probe, which are based on API 14.1 and GPA 2166. 
The sample probe ensures that the gas sample is representative of the 
gas flowing through the meter. The sample probe extracts the gas from 
the center of the flowing stream, where the velocity is the highest. 
Samples taken from or near the walls of the pipe tend to contain more 
liquids and are less representative of the gas flowing through the 
meter. The BLM did not receive any comments on these two paragraphs.
    Proposed Sec.  3175.112(c)(3) would have required that the 
collection end of the probe be placed in the center third of the pipe 
cross-section.
    The BLM received a comment objecting to this requirement. The 
commenter believes this requirement is appropriate for pipe up to 6 
inches in diameter; however, for any pipe diameter above 8 inches there 
is a risk of failure because of resonant vibration fatiguing the probe. 
The commenter recommended that the BLM use API 14.1, Subsection 7.4.1, 
Table 1, for sample probes used in 8-inch and greater runs. The BLM 
agrees with the comment and has changed the requirement by requiring 
the sample

[[Page 81580]]

probe to be the shorter of the length needed to place the collection 
end of the probe in the middle third of the pipe cross-section or as 
stated in API 14.1, Table 1. In practice, nearly all FMPs will default 
to the first criterion because the vast majority of meter tubes at FMPs 
are between 2 and 4 inches in diameter.
    Section 3175.112(c)(4) prohibits the use of membranes or other 
devices used in sample probes to filter out liquids that may be flowing 
through the FMP. Because a significant number of FMPs operate very near 
the HCDP, there is a high potential for small amounts of liquid to flow 
through the meter. These liquids will typically consist of the heavier 
hydrocarbon components that contain high heating values. The use of 
membranes or filters in the sampling probe could block these liquids 
from entering the sampling system and could result in heating values 
lower than the actual heating value of the fluids passing through the 
meter. This could result in a bias that would be in violation of Sec.  
3175.30(c).
    The BLM received numerous comments objecting to the proposed 
requirement in Sec.  3175.112(c)(4). Most of the commenters objected to 
the potential introduction of liquids into the gas sample which could 
significantly bias the heating value. The commenters stated that API 
14.1 and GPA 2166 do not apply to multi-phase flow and there are 
currently no methods to accurately determine the heating value from 
multi-phase flow. Commenters also stated that prohibiting filters in 
the sample probe is contrary to API 14.1 and GPA 2166 and the BLM 
should adopt these standards as written.
    The BLM disagrees with these comments and did not make any changes 
to this requirement as a result. The BLM recognizes that the sampling 
standards in API 14.1 and GPA 2166 are only intended for single-phase 
gas streams and that prohibiting membrane filters could potentially 
bias the heating value if liquids are present. However, the commenters 
ignore the reality that liquids are often present at the FMP. The mere 
fact that sample probe filters are manufactured and used is an 
admission by the gas measurement community that liquids are present. If 
there were no liquids present, there would be no need for filters 
designed to keep liquids from entering the sampling system. By 
intentionally excluding liquids from the sample, the heating value 
derived from the sample will not represent the true value of the 
molecules flowing through the meter and will be biased to the low side, 
resulting in an underpayment of royalty. The BLM also disagrees with 
the implication by the commenters that filters are required to obtain 
an accurate heating value. The BLM does not understand how the 
commenters can deem a heating value to be accurate when the sampling 
system is designed to reject those components which have the greatest 
impact on the heating value. The BLM also believes that there are 
other, perhaps better ways to minimize the liquids at an FMP. For 
example, installing properly sized and functioning separators and 
insulating or heat tracing the meter run would help to avoid liquids. 
Unlike the membrane filter, these would minimize liquids at their 
source without biasing the heating value of a gas sample.
    The BLM received several comments stating that the prohibition of 
filters in the sample probe conflicts with the requirement to clean GC 
filters in Sec.  3175.113(d)(2) of the proposed rule, and that GC 
filters are necessary to protect the GC. The BLM believes that the 
commenters have misinterpreted this requirement. The BLM is not 
prohibiting filters at the inlet to GCs. The prohibition of filters in 
Sec.  3175.112(c)(4) is specific to filters in the sampling probe. The 
BLM did not make any changes to the rule based on these comments.
Sec. 3175.112(d)
    Section 3175.112(d) sets standards for the sample tubing that are 
based on API 14.1 and GPA 2166. To avoid reactions with potentially 
corrosive elements in the gas stream, the sample tubing can be made 
only from stainless steel or Nylon 11. Materials, such as carbon steel, 
can react with certain elements in the gas stream and alter the 
composition of the gas. The BLM did not receive any comments on this 
paragraph.
Sec. 3175.113--Spot Samples--General Requirements
Sec. 3175.113(a)
    Section 3175.113(a) provides an automatic extension of time for the 
next sample if the FMP is not flowing at the time the sample was due. 
Sampling a non-flowing meter would not provide any useful data. Under 
the proposed rule, a sample would have been required to be taken within 
5 days of the date the FMP resumed flow.
    The BLM received numerous comments objecting to the 5-day extension 
in Sec.  3175.113(a). The commenters stated that 5 days is not 
sufficient time to determine whether a meter has resumed flow and to 
schedule a technician to go out to the site and collect a sample, 
especially for meters that flow intermittently or are in a remote 
location requiring extended travel time. Suggestions for increasing the 
timeframe ranged from 10 days to 1 month, although no specific 
rationale was given for these timeframes. The BLM agrees that 5 days 
may not be long enough and has changed the timeframe from 5 days to 15 
days as a result. The BLM believes that 15 days should be adequate time 
to identify the resumption of flow and schedule a technician to travel 
to the site and collect a sample. Most locations have 
telecommunications systems that allow the flow rate of a meter to be 
monitored remotely, and the resumption of flow could be detected almost 
immediately. For those locations that do not have telecommunications, 
personnel are typically onsite on a daily basis to monitor and inspect 
the equipment. The BLM rejected a 30-day timeframe because, especially 
for high- and very-high-volume FMPs, this could overlap with the due 
date of the next required sample. In addition to the comments 
suggesting specific timeframes, one commenter suggested requiring the 
sample be taken as soon as practical after flow resumes, while another 
commenter suggested the language specify that the meter has to resume 
continuous flow. The BLM did not make any changes as a result of these 
comments because the terms ``as soon as practical'' and ``continuous 
flow'' are not readily enforceable.
Sec. 3175.113(b)
    Proposed Sec.  3175.113(b) would have required the operator to 
notify the BLM at least 72 hours before gas sampling. A 72-hour 
notification period was proposed to allow sufficient time for the BLM 
to arrange schedules as necessary to be present when the sample is 
taken.
    The BLM received many comments objecting to this proposed 
requirement. The majority of the commenters believe that 72-hour 
notification is unreasonable and burdensome. Several commenters 
suggested that the BLM should allow for the submission of monthly 
schedules which gives the BLM the ability to witness samples. The BLM 
agrees with these comments and included the option to submit monthly or 
quarterly sampling schedules to the BLM.
Sec. 3175.113(c)
    Section 3175.113(c) establishes requirements for sample cylinders 
used in spot or composite sampling. Proposed Sec.  3175.113(c)(1) and 
(2) would have adopted requirements for cylinder construction material 
and minimum capacity that are based on API and GPA standards.

[[Page 81581]]

    The BLM received a few comments objecting to the proposed 
requirement in Sec.  3175.113(c)(1). The commenters suggested that the 
BLM allow the use of aluminum cylinders because they are approved by 
the Department of Transportation for shipping samples and have been 
used without metal contamination issues. Some commenters indicated that 
the requirement in this paragraph to use stainless-steel cylinders 
would result in excessive cost to industry. Several commenters stated 
that the rule should allow their use in low-pressure applications. The 
BLM agrees with these comments and changed the rule to incorporate API 
14.1, Subsection 9.1, regarding the allowable materials of 
construction, rather than requiring that sample cylinders be 
constructed of stainless steel. Under API 14.1, Subsection 9.1, sample 
cylinders can be made out of aluminum, but only if the aluminum is hard 
anodized.
    Section 3175.113(c)(3) requires that sample cylinders be cleaned 
according to GPA standards. This section also requires operators to 
have documentation of the cylinder cleaning.
    The BLM received a few comments either supporting or objecting to 
this proposed requirement. Several commenters supported the idea of 
cleaning the sample cylinders and maintaining a record of cleaning, 
which could include the use of a disposable tag indicating the cylinder 
was cleaned. Other commenters objected to both the need for cleaning 
sample cylinders and the need to keep a record of the cleaning. These 
commenters stated that this requirement is costly and burdensome with 
negligible benefit, and that a contaminated cylinder would be obvious 
(the commenter did not provide any information as to why that would be 
obvious). Another commenter believed cleaning and the associated 
documentation is the responsibility of the lab, not the operator. The 
BLM believes that clean sample cylinders are crucial in obtaining a 
representative sample of the gas, and that documentation of the 
cleaning is the only way BLM inspectors can ensure the cylinders are 
clean. Although the BLM did not change the rule based on these 
comments, we did change the wording of this requirement in the final 
rule to clarify that the operator must maintain this documentation 
onsite during sampling and make the documentation available to the BLM 
on request.
    Proposed Sec.  3175.113(c)(4) would have required clean sample 
cylinders to be sealed in a manner that prevents opening the sample 
cylinder without breaking the seal. It is important to be able to 
verify that sample cylinders are clean before sampling to avoid 
contaminating a sample. Therefore, the BLM sought comments on the 
practicality and cost of installing a physical seal on the sample 
cylinder as proposed in Sec.  3175.113(c)(4), or on other methods that 
the BLM could use to verify that the cylinders are clean. The BLM did 
not receive any suggestions as to how a sample cylinder could be 
sealed. The BLM is not aware of any industry standard or common 
industry practice that requires a seal to be used.
    The BLM received several comments objecting to the proposed 
requirement in Sec.  3175.113(c)(4). Most commenters stated that 
sealing the cylinders is not an industry practice and will result in 
extra expense that will have minimal gain. Several commenters stated 
that there is no way to seal a cylinder while other commenters stated 
that it was unclear in the proposed rule when the cylinder would have 
to be sealed (before or after the sample was taken) and what type of 
seal would be acceptable to the BLM. The BLM agrees with the comments 
stating there is no cost-effective method to seal sample cylinders and 
deleted this requirement in the final rule. The BLM believes that the 
documentation required in Sec.  3175.113(c)(3) will ensure that sample 
cylinder cleaning is taking place to the best extent possible.
Sec. 3175.113(d)
    Section 3175.113(d) sets standards for spot sampling using a 
portable GC. This section primarily addresses the sampling aspects; the 
analysis requirements are prescribed in Sec.  3175.118. Both the GPA 
and API recognize that the use of sampling separators, while sometimes 
necessary for ensuring that liquids do not enter the GC, can also cause 
significant bias in heating value if not used properly. Section 
3175.113(d)(1) adopts GPA standards for the material of construction, 
heating, cleaning, and operation of sampling separators. It also 
requires documentation that the sample separator was cleaned as 
required under GPA 2166-05 Appendix A.
    The BLM received several comments objecting to this requirement. 
One commenter cautioned against the use of separators because of the 
potential for liquids to condense in the cylinder and get into the GC. 
Another commenter stated that this requirement is impractical to do 
prior to taking each sample because the cleaning equipment cannot be 
carried to the field. The commenter suggested the BLM only require 
sample separator cleaning on a periodic basis. The BLM considered 
prohibiting the use of sample cylinders altogether because API 14.1, 
Subsection 8.7, cautions against their use. However, the BLM also 
believes that if used properly they can protect the GC while not 
contaminating the sample. In order to ensure that the sample separator 
does not contaminate a sample, the BLM believes it is essential to 
require the separator to meet the same standards as a sample cylinder 
regarding cleaning. The BLM disagrees with the comments suggesting only 
periodic cleaning and did not make any changes to the rule based on 
these comments. The BLM did add language to the final rule clarifying 
that the same documentation and availability of the documentation 
required for sample cylinders is required for separators.
    Proposed Sec.  3175.113(d)(2) would have required the filter at the 
inlet to the GC to be cleaned or replaced before taking a sample. 
Industry standards do not provide specific requirements for how often 
the filter should be cleaned or replaced; however, a contaminated 
filter could bias the heating value.
    The BLM received numerous comments objecting to the proposed 
requirement in Sec.  3175.113(d)(2). Most of the commenters stated that 
cleaning the GC filter prior to each sample is expensive and 
impractical because it would require the operator to carry cleaning 
agents to the field which are difficult to transport. Several 
commenters stated that the filter should only be cleaned or replaced as 
necessary or when the operator suspects the filter is contaminated. The 
BLM agrees with these comments and deleted this requirement as a 
result. While the BLM believes that a contaminated filter could cause 
an errant analysis, there is no way to inspect or enforce a requirement 
for periodic or ``as needed'' cleaning or replacement frequency.
    Several commenters expressed concern over the removal of the filter 
at the inlet to the GC because liquids, such as glycol and compressor 
oil, could damage the GC. The BLM did not make any changes to the rule 
based on this comment because nowhere has the BLM proposed removing the 
filter at the inlet of the GC.
    Section 3175.113(d)(2) (Sec.  3175.113(d)(3) in proposed rule) 
requires the sample line and the sample port to be purged before 
sealing the connection between them. This requirement was derived from 
GPA 2166-05, which requires a similar purge when sample cylinders are 
being used. The purpose of this requirement is to disperse any 
contaminants that may have collected in the sample port and to

[[Page 81582]]

purge any air that may otherwise enter the sample line.
    The BLM received a few comments on this section. While the 
commenters did not object to this requirement, they suggested that the 
BLM reword the requirement to clarify that the purging must be done 
with the gas being sampled, not with air. One commenter recommended 
that the BLM change the phrase ``before sealing the connection'' to 
``before completing the connection.'' The BLM agrees with these 
comments and made the requested wording changes in the final rule.
    Section Sec.  3175.113(d)(3) (Sec.  3175.113(d)(4) in the proposed 
rule) would have required portable GCs to adhere to the same minimum 
standards as laboratory GCs under proposed Sec.  3175.118. The 
requirements of proposed Sec.  3175.118 would have included provisions 
regarding the design, operation, verification, and calibration of GCs, 
the number of consecutive samples that must be run, the verification 
frequency, when a calibration had to be done, standards for calibration 
gas, and the GC calibration report.
    The BLM received one comment requesting clarification of Sec.  
3175.113(d)(3) (Sec.  3175.113(d)(4) in proposed rule). The commenter 
stated that the requirement for a GC to be ``designed'' in accordance 
with GPA 2261-13 (GPA 2261-00 was referenced in the proposed rule) does 
not provide sufficient flexibility for the development of new 
technology and processes. The BLM agrees with this comment and reworded 
the requirement in the final rule to read: ``The portable GC must be 
operated, verified, and cali brated . . .'' instead of ``The portable 
GC must be designed, operated, and calibrated . . . .'' The BLM 
believes that removing the word ``designed'' will help provide 
flexibility for new technology and adding the word ``verified'' will 
help ensure that both the verification and calibration of a GC is done 
under Sec.  3175.118.
    The BLM added Sec.  3175.113(d)(4) to the final rule in response to 
changes made to Sec.  3175.118(c)(1). In the proposed rule, this 
section would have required portable GCs to be verified not more than 
24 hours before sampling at an FMP. This proposed requirement would 
have facilitated the BLM's ability to ensure that the portable GC was 
verified properly prior to sampling. In response to comments arguing 
against the practicality of verifying a portable GC every 24 hours, the 
BLM eliminated this requirement in the final rule. However, the BLM 
believes that in order to ensure portable GCs have been verified in 
accordance with the provisions of Sec.  3175.118, the operator must 
have the documentation of the verification onsite and available to the 
BLM when using a portable GC.
    Proposed Sec.  3175.113(d)(5) would have prohibited the use of 
portable GCs if the flowing pressure at the sample port was less than 
15 psig, which can affect accuracy of the device. This proposed 
requirement was based on GPA 2166-05.
    The BLM received a few comments objecting to proposed Sec.  
3175.113(d)(5). The commenters stated that GCs can sample with 
pressures down to 5 psig because of newer technology and the use of 
vacuum pumps to help step up the pressure in accordance with API 14.1, 
Subsection 11.10. One commenter suggested the BLM not allow portable 
GCs to take samples below 15 psig unless the GC is approved by the PMT 
to handle pressures below 15 psig. Based on these comments, the BLM 
removed this requirement in the final rule. The BLM believes that 
setting a minimum pressure for portable GCs would tie the regulation to 
existing technology. The BLM generally agrees with the comment that 
review and approval of new GC technology could be a role for the PMT.
    The BLM also added Sec.  3175.113(d)(5) and (6) to the final rule 
in response to changes made to Sec.  3175.118(b). Under the proposed 
rule, Sec.  3175.118(b) would have required that for both portable and 
laboratory GCs, samples would have to be analyzed until three 
consecutive samples were within the repeatability standards of GPA 
2261-00, Section 9. Based on comments received on this section, this 
requirement was eliminated in the final rule. Please see the discussion 
on Sec.  3175.118(b). Portable GCs are subject to a less controlled 
environment than are laboratory GCs and also analyze a live gas stream 
with varying composition. Laboratory GCs analyze fixed-composition 
samples stored in sample cylinders. For these reasons the BLM believes 
that additional quality control standards are needed for portable GCs 
to ensure the gas sampling and analyses are accurate. Section 
3175.113(d)(5) establishes the minimum number of samples that must be 
taken and analyzed. For very-low- and low-volume FMPs, a minimum of 
three samples and analyses are required. For high- and very-high-volume 
FMPs, the final rule establishes tolerances between the highest and 
lowest heating values for three consecutive samples. The basis for the 
tolerances is explained under the discussion for Sec.  3175.118(b). The 
BLM believes that three samples provide a reasonable balance between 
cost and statistical representation of the gas being sampled.
    Section 3175.113(d)(6) sets standards on how the heating value and 
relative density from the samples and analyses taken under Sec.  
3175.113(d)(5) are determined. One method that is explicitly allowed in 
the final rule is to calculate the heating value and relative density 
by taking the average of the heating values and relative densities 
determined from the three samples taken. The other method explicitly 
allowed by the rule is to use the median heating value and relative 
density from the three samples taken. The BLM also added a provision 
where the BLM can approve additional methods.
Sec. 3175.114--Spot Samples--Allowable Methods
    Section 3175.114 adopts three spot sampling methods using a 
cylinder and one method using a portable GC. The three allowable 
methods using a cylinder were selected for their ability to accurately 
obtain a representative gas sample at or near the HCDP, the relative 
effectiveness of the method, and the ease of obtaining the sample. 
Because the BLM determined that the procedures required by either GPA 
or API standards were clear and enforceable as written, the BLM adopted 
them verbatim.
    The most common method currently in use at FMPs is the ``purging--
fill and empty'' method, which is one of the methods that is allowed in 
the rule (Sec.  3175.114(a)(1)); therefore, it is not expected that 
this requirement will result in any significant changes to current 
industry practice. Section 3175.114(a)(2) also allows the helium 
``pop'' method and Sec.  3175.114(a)(3) allows the ``floating piston 
cylinder'' method. The fourth spot sampling method (Sec.  
3175.114(a)(4)) is the use of a portable GC, which is discussed in 
Sec.  3175.113(d). Section 3175.114(a)(5) provides that the BLM would 
post other approved methods on its website once they are reviewed by 
the PMT and approved by the BLM.
    Section 3175.114(b) allows the use of a vacuum gathering system 
when the operator uses a ``purging--fill and empty'' method or a helium 
``pop'' method and when the flowing pressure is less than or equal to 
15 psig. Of the four spot sampling methods allowed in this section, API 
14.1, Subsection 11.10, recommends that only the ``purging--fill and 
empty'' method and the helium ``pop'' method be used in conjunction 
with the vacuum gathering system. As a result, the ``floating piston 
cylinder'' method is not allowed in conjunction with a vacuum gathering 
system. Based

[[Page 81583]]

on comments on Sec.  3175.113(d)(5), the BLM removed the prohibition 
for using portable GCs when the pressure is less than 15 psig.
    Several comments objected to the BLM's piecemeal adoption of API 
14.1 and GPA 2166 and stated that the BLM should have incorporated both 
documents in whole, including all of the sampling methods referred to 
in Appendix F of API 14.1. One commenter also objected to the BLM's 
incorporating these standards and then using the standards to sample 
gas containing liquids. The commenter stated that both of these 
standards are only intended for single phase gas sampling and should 
not be applied when liquids are present. The BLM did not make any 
changes as a result of these comments. The issue of sampling with 
liquids present is discussed under Sec.  3175.112. The BLM is only 
enforcing specific parts of API 14.1 and GPA 2166 because these parts 
are directly relevant to the BLM's goal of ensuring that samples are 
properly taken and are clear and enforceable as written.
    The BLM selected the sampling methods described in this section 
because data show they work well at the HCDP under the controlled 
temperature conditions, and both the ``purging--fill and empty'' and 
helium ``pop'' methods are repeatable, as documented in the July 2004 
study, Evaluation of a Proposed Gas Sampling Method Performance 
Verification Test Protocol, conducted by Southwest Research Institute 
for the United States Minerals Management Service. The methods 
indicated in this subpart were chosen for a combination of ease of use 
and accurate determination of the composition and heating value in 
field situations. The BLM found: (1) The evacuated cylinder method is 
prone to leaky valves or operator error that could introduce air into 
the evacuated cylinder; (2) The reduced-pressure method can cause 
condensation of heavy components with re-vaporization prior to sampling 
because this process is below the pressure of the pipeline, leading to 
cooling from the expansion of the gas; (3) With the water displacement 
method, water can absorb carbon dioxide, hydrogen sulfide, and other 
components which will affect the water vapor content of the sample; (4) 
Similar issues were found utilizing the glycol displacement method; and 
(5) The purged-controlled rate method encouraged the possibility of 
liquids condensing due to the pressure reduction as the purging is 
performed.
Sec. 3175.115--Spot Samples--Frequency
Sec. 3175.115(a)
    Section 3175.115(a) requires that gas samples be taken at least 
every 6 months at low-volume FMPs and at least annually at very-low-
volume FMPs. The BLM determined that annual sampling has the potential 
for biasing the heating value. If, for example, an annual sample is 
always taken in January when the ambient temperature is low, there 
could be a higher possibility that the heavier components could liquefy 
and bias the composition. This would not be consistent with Sec.  
3175.31(c), which requires the absence of significant bias in low-
volume FMPs. The BLM believes that sampling at low-volume FMPs at least 
every 6 months will reduce the potential for bias.
    Section 3175.115(a) will require spot samples at high- and very-
high-volume FMPs to be taken at least every 3 months and every month, 
respectively, unless the BLM determines that more frequent analysis is 
required under Sec.  3175.115(b). The sampling frequencies presented in 
Table 1 to Sec.  3175.110 were developed as part of the ``BLM Gas 
Variability Study Final Report,'' May 21, 2010. The study used 1,895 
gas analyses from 217 points of royalty settlement and concluded that 
heating value variability is not a function of reservoir type, 
production type, age, richness of the gas, flowing temperature, flow 
rate, or other factors that were included in the study. Instead, the 
study found that heating value variability appears to be unique to each 
meter. The BLM believes that the lack of correlation with at least some 
of the factors identified here could be a symptom of poor sampling 
practices in the field. The study also concluded that heating-value 
uncertainty over a period of time is manifested by the variability of 
the heating value, and more frequent sampling would lessen the 
uncertainty of an average annual heating value, regardless of whether 
the variability is due to actual changes in gas composition or to poor 
sampling practices. The frequencies shown in Table 1 to Sec.  3175.110 
for high- and very-high-volume FMPs are typical of the sampling 
frequency required to obtain the heating value certainty levels that 
are required in Sec.  3175.31(b)(1) and (2).
    The BLM received several comments on the proposed sampling 
frequencies in Table 1 to Sec.  3175.110 of the proposed rule. One 
commenter did not believe the proposed sampling frequencies occurred 
often enough and proposed a frequency of once every 6 months for very-
low-volume and low-volume FMPs, and once per month for high- and very-
high-volume FMPs. The commenter did not submit any data or rationale 
for the proposed frequencies. Another commenter suggested that 
increased sampling is not needed for ``dry'' gas wells, although no 
definition of what constitutes a ``dry'' gas well was given by 
commenter, nor did the commenter provide any data to support that a 
lower frequency for these FMPs is justified. Another commenter stated 
that the frequencies are too high in general and do not account for 
driving time. Again, the commenter did not submit any data justifying 
this comment. The BLM did not make any changes to the proposed rule 
based on these comments because the BLM believes the frequencies are 
reasonable as written in the proposed rule and no data were provided to 
justify a different frequency.
    One commenter stated that it is a violation of existing contracts 
to change required sampling frequencies. The BLM did not make any 
changes to the rule based on this comment because all existing Federal 
oil and gas leases require compliance with the applicable Federal 
regulations, even if those regulations are stricter than the provisions 
of a gas sales contract attached to any particular lease.
    One commenter expressed a concern that the BLM was intending to 
assign a Btu value to a particular zone. The BLM has no intention of 
assigning Btu values to particular zones. If that were the intent, the 
BLM would have required that in the proposed rule instead of proposing 
provisions to ensure the accuracy and verifiability of heating values 
measured at each FMP. No changes to the rule were made as a result of 
this comment.
Sec. 3175.115(b)
    Section 3175.115(b) will allow the BLM to require a different 
sampling frequency if analysis of the historic heating value 
variability at a given FMP results in an uncertainty that exceeds what 
is required in Sec.  3175.31(b)(1) and (2). Under Sec.  3175.115(b), 
the BLM can increase or decrease the required sampling frequency given 
in Table 1 to Sec.  3175.110. To implement this requirement, the BLM is 
developing a database called GARVS. This database will be used to 
collect gas sampling and analysis information from Federal and Indian 
oil and gas operators. GARVS will analyze those data to implement other 
gas sampling requirements as well. The sample frequency calculation in 
GARVS will be based on the heating values entered into the system under 
Sec.  3175.120(f).

[[Page 81584]]

    Several comments asserted that the method of calculating a sampling 
frequency was not provided in the proposed rule. While the BLM did not 
propose a calculation method in the proposed rule, a calculation method 
was included in the BLM Gas Variability Study that was included with 
the documentation on the proposed rule. The BLM did not make any 
changes as a result of these comments.
    Many commenters stated that the sampling frequency should be based 
on volume, not variability. The BLM disagrees. While there is some 
economic rationale for sampling less frequently at lower-volume meters, 
any volume-based sampling frequency is arbitrary and ignores 
statistical methods. As stated by other commenters, the uncertainty of 
any given heating value is only a function of the analytic procedures 
used to obtain and analyze the sample. To clarify the comment, if, for 
example, a particular sampling and analysis method provides a heating 
value uncertainty of 2 percent, more frequent sampling 
would not eliminate that uncertainty. In other words, if an operator 
took one sample per year and was confident that the process was done 
properly and the heating value derived from that sample was 2 percent, there would be no benefit to sampling any more 
frequently. The reason for more frequent sampling is not related to the 
uncertainty of each sample; rather, it is related to the uncertainty of 
deriving heating values over a period of time from snapshots of heating 
values taken during that time period. If, for example, the heating 
value at a particular meter were always the same, there would be no 
reason to take spot samples from this meter regardless of how much 
volume it measured. On the other hand, if the heating value at a 
particular meter were known to vary greatly from sample to sample, the 
heating value from one sample could misrepresent the average heating 
value of the gas flowing through the meter and result in significant 
underpayment or overpayment of royalty. The solution would be to take 
more samples of the highly fluctuating meter to obtain a better 
representation of the true heating value over time. The difference in 
sampling frequency between the first example and the second example is 
not related to the volume measured; rather, it is related to the degree 
of heating value variability at that meter. The cause of the high 
degree of fluctuation in the second example--whether it be actual 
changes in the gas composition, poor sampling practice, or 
environmental conditions during sampling--is largely irrelevant. Volume 
has bearing on sampling frequency only in that sampling entails a cost 
and at lower-volume meters, the cost of more frequent sampling due to 
high variability is simply not worth the potential loss or gain in 
revenue resulting from less frequent sampling. The BLM incorporated 
statistically based sampling frequencies for high- and very-high-volume 
FMPs where economics is not as important a consideration and volume-
based sampling frequencies for lower-volume FMPs where economics is a 
consideration. The BLM did not make any changes to the proposed rule as 
a result of these comments.
    One commenter stated that based on their experience performing gas 
analyses, fluctuations in heating value are typically due to changes in 
pressure, temperature, or down-hole equipment and have nothing to do 
with volume. The BLM Gas Variability Study did not find any correlation 
between heating value variability and pressure, temperature, or down-
hole equipment. The BLM did not make any changes to the rule because no 
changes were requested by the commenter.
    One commenter wondered if the BLM is requiring increased sampling 
frequency because it believes that operators use poor sampling 
practices. The BLM has no data to conclude that poor sampling practices 
are the cause of high heating value variability. However, there are 
only two potential causes of high variability: The actual composition 
of the gas is changing significantly over time or the operator is using 
poor sampling practices. Regardless of the cause, the only way to 
achieve a set level of average annual heating value uncertainty is to 
change the sampling frequency to achieve the required level of 
uncertainty. As explained elsewhere in this preamble, the sampling 
frequency can change (become more or less frequent) depending on what 
the data shows for a particular facility over time. The BLM did not 
make any changes to the rule based on this comment.
    The BLM received numerous comments stating that uncertainty and 
variability are two unrelated concepts, and the BLM should not use 
variability as a trigger for increased sampling frequency. The BLM 
agrees that variability should not be the trigger. That is why the BLM 
is using average annual heating value uncertainty as the trigger. The 
relationship between variability and average annual heating value 
uncertainty is explained in the discussion of Sec.  3175.31(b). The BLM 
did not make any changes to the rule based on this comment.
    Several comments suggested that the BLM provide industry with the 
sampling frequency algorithm. The BLM agrees with this comment and has 
provided the algorithm in the final rule. It is the same algorithm 
provided in the BLM Gas Variability Study, which was posted at 
www.regulations.gov with the proposed rule.
    Several commenters suggested that the BLM should work with industry 
to develop sampling schedules or conduct further study before 
implementing this requirement. While the BLM does not believe further 
study is needed to support this method, the rule allows the BLM to 
approve other methods that achieve the same goal (see Sec.  
3175.31(a)(4)). These other methods could be developed jointly with 
industry. One commenter stated that they were in favor of the 
requirement to allow sampling frequency adjustment. The BLM did not 
make any changes to the rule based on this comment, as no changes were 
requested by the commenter.
    One commenter stated that changing the required sampling 
frequencies for high- and very-high-volume FMPs when there is a change 
in the variability of previous heating values would create uncertainty 
for operators of these FMPs, posing an excessive burden on industry. 
Based on this and other comments, the BLM added a provision in the 
final rule (Sec.  3175.115(b)(1)) that would prohibit the BLM from 
changing the sampling frequency for a high-volume FMP for 2 years after 
the FMP starts measuring gas (or 4 years from the effective date of the 
rule, whichever is later). For very-high volume FMPs, the BLM could not 
change the sampling frequency for 1 year after the FMP starts measuring 
gas (or 3 years from the effective date of the rule, whichever is 
later). Based on the initial 3-month sampling frequency required for 
high-volume FMPs in Table 1 to Sec.  3175.110, this would result in the 
collection, analysis, and reporting of at least eight samples before 
the BLM could change the sampling frequency. For very-high-volume FMPs, 
the monthly sampling required in Table 1 to Sec.  3175.110 would yield 
at least 12 samples. Assuming the operator is tracking the variability 
of these samples using the equation given under the definition of 
heating value variability (see Sec.  3175.10(a)), the operator will 
have ample indication that an FMP has a variability that is high enough 
to warrant an increased sampling frequency. The operator would also 
have the opportunity to address the high variability by implementing 
additional training or quality-control measures in the sampling and 
analysis of that FMP.

[[Page 81585]]

    Section 3175.115(b)(3) clarifies that the new sampling frequency 
would remain in effect until a different sampling frequency is 
justified by an increase or decrease of the variability of previous 
heating values. In proposed Sec.  3175.115(b)(3) (Sec.  3175.115(b)(4) 
in the final rule), GARVS would have rounded down the calculated 
sampling frequency to one of seven possible values: Every week, every 2 
weeks, every month, every 2 months, every 3 months, every 6 months, or 
every 12 months. The BLM would notify the operator of the new required 
sampling frequency. Several comments stated that the increased sampling 
frequency would be difficult logistically, especially if it is once per 
week as in the proposed rule. Because the BLM agrees that weekly 
sampling is probably not practical in many situations, the BLM 
eliminated the requirement for weekly sampling in the final rule. A 2-
week sampling frequency is the maximum sampling frequency that the BLM 
will require under Sec.  3175.115(b)(4) of the final rule. In addition, 
the BLM eliminated the entry in Table 1 to Sec.  3175.115 that 
corresponded to weekly sampling.
    One commenter stated that the cost of performing additional gas 
sampling and entering the gas analyses into GARVS would be prohibitive, 
although the commenter did not submit any data to substantiate this 
claim. The BLM does not believe that the new gas sampling requirements 
are cost prohibitive. Under the new volume thresholds, very-low-volume 
meters, for which no increase in gas sampling frequency is required as 
compared to Order 5, constitute 51 percent of all FMPs. The rule only 
requires one additional sample per year at low-volume FMPs. The 
estimated cost increase for low-volume FMPs, which constitute 38 
percent of all FMPs, is $100 per year per FMP. The rule only requires 
higher sampling frequencies at FMPs flowing more than 200 Mcf/day, 
which only constitute 11 percent of FMPs. The BLM's analysis indicates 
that even at a maximum sampling frequency of once every 2 weeks, the 
requirement is not cost prohibitive. The BLM does not anticipate a 
significant cost of entering the gas analyses into GARVS because GARVS 
will allow a direct download of gas analysis data from approved third-
party software packages that most operators already use. The BLM did 
not make any changes to the rule as a result of this comment.
    Proposed Sec.  3175.115(b)(4) (Sec.  3175.115(b)(5) in the final 
rule) would have required the operator to install a composite sampling 
system or an on-line GC if sampling every week would still not be 
sufficient to achieve the certainty levels that would be required under 
Sec.  3175.31(b)(1) or (2).
    The BLM received several comments stating that composite samplers 
and on-line GCs are only cost-effective on high-volume meters. One 
commenter stated that composite samplers are not cost-effective unless 
the flow rate is over 5,000 Mcf/day and on-line GCs are not cost-
effective unless the flow rate is over 15,000 Mcf/day. Another 
commenter stated that composite samplers and on-line GCs are not cost-
effective on high-volume FMPs (as defined in the proposed rule) and the 
``low end'' of the very-high-volume threshold. Installed cost estimates 
for on-line GCs given by commenters ranged from $45,000 to $110,000. 
The BLM generally agrees with these comments and eliminated the 
requirement in the proposed rule for high-volume FMPs to use composite 
samplers or on-line GCs if operators could not achieve an average 
annual heating value uncertainty of 2 percent through spot 
sampling. The BLM believes that the use of composite samplers would not 
be cost prohibitive at very-high-volume FMPs. Although the BLM did not 
receive any cost estimates for composite sampling systems in the 
comments, research shows that a heated composite sampling system costs 
about $8,000 and using a 2.5 multiplier for the installed cost, as 
recommended by several commenters, results in an installed cost of 
about $20,000. A $20,000 cost would have a payout of less than 10 days 
at a flow rate of 1,000 Mcf/day.
    One commenter expressed the opinion that the BLM is trying to force 
the use of composite sampling systems or on-line GCs at every FMP. 
Neither the proposed rule nor the final rule would force every FMP to 
have a composite sampling system or on-line GCs. Although the BLM did 
not make any changes to the rule based on this comment, the BLM is 
aware that these devices are expensive and removed the proposed 
requirement for composite sampling systems or on-line GCs at high-
volume FMPs. The BLM estimates that as a result, only 900 FMPs 
nationwide will fall into the very-high-volume category. From the BLM 
Gas Variability Study, approximately 25 percent of all FMPs included in 
the study would not be able to meet a 1 percent average annual heating 
value uncertainty with a 2-week sampling frequency, the maximum spot 
sampling frequency required in the rule. Some of the data in the study 
also suggest that variability tends to be less for higher flow rate 
meters, although the sample size was too small to reach any definite 
conclusion. Therefore, the BLM estimates that composite sampling 
systems or on-line GCs would only be required on a maximum of 225 FMPs, 
or 0.3 percent of all FMPs nationwide.
    One commenter stated that composite samplers and on-line GCs may 
not perform well with two-phase flow and would have no demonstrated 
benefit. The BLM does not believe that FMPs flowing at 1,000 Mcf/day or 
greater will have significant issues with two-phase flow. Generally, 
two-phase flow occurs at lower-volume meters where it is difficult to 
obtain adequate separation and control temperature drop between the 
separator and meter. The commenter did not provide any data to 
substantiate their argument that two-phase flow would be an issue with 
higher-volume FMPs. The BLM also disagrees that a composite sampler 
would have no benefit. A properly designed and operating composite 
sampling system will result in a heating value that is truly integrated 
over time, thereby eliminating the uncertainty caused by basing heating 
value over a time period on heating value ``snapshots'' in time. The 
BLM did not make any changes as a result of this comment.
    One commenter stated that composite samplers or on-line GCs may 
still have more than 2 percent uncertainty. The commenter 
did not provide any data to substantiate this claim, however. As stated 
earlier, the performance requirement in Sec.  3175.31(b) relates to 
average annual heating value uncertainty, not to the uncertainty of a 
single sample or analysis. To address this comment, the BLM added 
language to Sec.  3175.115(b)(5) that states, ``Composite sampling 
systems or on-line gas chromatographs that are installed and operated 
in accordance with this section comply with the uncertainty requirement 
of Sec.  3175.31(b)(2).'' This should eliminate any confusion with this 
requirement.
Sec. 3175.115(c)
    Section 3175.115(c) establishes the maximum allowable time between 
samples for the range of sampling frequencies that the BLM would 
require, as shown in Table 1 to Sec.  3175.115. This allows some 
flexibility for situations where the operator is not able to access the 
location on the day the sample was due, although the total number of 
samples required every year would not change. For example, if the 
required sampling frequency was once per month, the operator would have 
to obtain 12 samples per year. If the operator took a sample on January 
1st, the operator would have until February 14th to take the next 
sample (45 days later). In the final rule, the BLM

[[Page 81586]]

adjusted Table 1 to Sec.  3175.115 by eliminating the weekly sampling 
entry to correspond to the changes made in Sec.  3175.115(b)(4).
Sec. 3175.115(d)
    If a composite sampling system or on-line GC is required by the BLM 
under Sec.  3175.115(b)(5) or opted for by the operator, Sec.  
3175.115(d) requires that device to be installed and operational within 
30 days after the due date of the next sample. For example, if the 
required sampling frequency is every 2 weeks and the next sample is due 
on April 18th, the composite sampling system or on-line GC must be 
operational by May 18th. The operator is not required to take spot 
samples within this 30-day time period. The BLM considers both 
composite sampling and the use of on-line GCs to be superior to spot 
sampling, as long as they are installed and operated under the 
requirements in proposed Sec. Sec.  3175.116 and 3175.117, 
respectively.
    Numerous comments argued that the 30-day timeframe to install a 
composite sampling system or on-line GC under Sec.  3175.115(d) is too 
short to account for the time to design, order, and install the system. 
The comments suggested timeframes ranging from 3 months for composite 
sampling systems to 6 months for both composite sampling systems and 
on-line GCs. The BLM disagrees with these comments because the BLM 
added a provision under Sec.  3175.115(b) that will delay the 
requirement to install a composite sampling system or on-line GC at 
very-high-volume FMPs until 1 year of gas analysis data are gathered. 
For very-high-volume FMPs, this will result in a minimum of 12 samples 
based on the initial monthly sampling frequency required in Table 1 to 
Sec.  3175.110.
    The BLM believes that an operator of a very-high-volume FMP should 
have ample indication after 6 months of production (i.e., six samples) 
whether the FMP will have a high enough heating value variability that 
a composite sampling system or on-line GC will likely be required. If 
the operator begins the process of ordering a composite sampling system 
or on-line GC after 6 months, it would be ready to go within the 30-day 
timeframe of when the BLM requires it to be installed as required in 
Sec.  3175.115(d). The BLM did not make any changes as a result of 
these comments. However, the BLM made two other revisions based on 
other comments that should result in many fewer composite samplers or 
on-line GCs being required as compared to the proposed rule. First, 
given the high production-decline rate of many wells on Federal and 
Indian leases, the 1-year delay will most likely be enough time for 
many FMPs that were originally categorized as very-high-volume to drop 
to lower-volume categories that are not subject to the requirement to 
install on-line GCs or composite sampling systems. Second, for FMPs 
that measure gas from newly drilled wells, the BLM will no longer 
include any production from that well prior to the second full month of 
its production, when determining the flow rate category for an FMP (see 
the definition of ``averaging period'' in 43 CFR 3170.3). As a result, 
with these changes, it is likely that many FMPs that would have been 
initially categorized as very-high-volume in the proposed rule will no 
longer meet the very-high-volume threshold in the final rule.
Sec. 3175.115(e)
    Section 3175.115(e) addresses FMPs where a composite sampling 
system or on-line GC was removed from service. In these situations, the 
spot sampling frequency for that meter reverts to the requirement under 
Sec.  3175.115(a) and (b). The BLM did not receive any comments on this 
section.
Sec. 3175.116--Composite Sampling Methods
    Section 3175.116 sets standards for composite sampling. The BLM 
used API 14.1, Subsection 13.1, as the basis for Sec.  3175.116(a) 
through (c). Section 3175.116(d) requires the composite sampling system 
to meet the heating-value uncertainty requirements of Sec.  3175.31(b).
    Although the BLM did not receive any comments on this section, we 
removed proposed paragraph (d) , which would have required the 
composite sampling system to meet the heating value uncertainty 
requirements of Sec.  3175.31(b). Based on comments received on Sec.  
3175.115, the BLM added a statement to Sec.  3175.115(b)(5) declaring 
that composite sampling systems and on-line GCs comply with the heating 
value uncertainty requirements of Sec.  3175.31(b). Therefore, 
paragraph (d) is no longer necessary.
Sec. 3175.117--On-Line Gas Chromatographs
    Section 3175.117 sets standards for on-line GCs. Because there are 
few industry standards for these devices, the BLM was particularly 
interested in comments on the proposed requirements or whether 
different or alternative standards should be adopted.
    The BLM received one comment that questioned the use of GPA 2261 
for extended analysis relating to on-line GCs. The BLM agrees with the 
comment and has incorporated by reference GPA 2286-14, which relates to 
the procedures for obtaining an extended analysis. Because extended 
analyses apply to more than just on-line GCs, this standard is 
referenced under Sec.  3175.118(e) (discussed below).
    The BLM also removed proposed paragraph (b) from this section, 
which would have required the on-line GC to meet the heating value 
uncertainty requirements of Sec.  3175.31(b). Based on comments 
received on Sec.  3175.115, the BLM added a statement to Sec.  
3175.115(b)(5) declaring that composite sampling systems and on-line 
GCs comply with the heating value uncertainty requirements of Sec.  
3175.31(b). Therefore, paragraph (b) of this section is no longer 
necessary. As a result of this change, paragraph (d) of this section 
was moved to paragraph (b).
Sec. 3175.118--Gas Chromatograph Requirements
    This section establishes requirements for the analysis of gas 
samples.
Sec. 3175.118(a)
    Under proposed Sec.  3175.118(a), these minimum standards would 
have applied to all GCs, including portable, on-line, and stationary 
laboratory GCs. These requirements were derived primarily from two 
industry standards: GPA 2261-00 and GPA 2198-03. The BLM received 
several comments that GPA 2261-00 has been updated with GPA 2261-13, 
and that the BLM should be incorporating the most recent version of 
this standard. The BLM agrees with these comments and incorporates GPA 
2261-13 into the final rule. The BLM also deleted the word ``designed'' 
from the requirement because GC technology may progress faster than the 
GPA standards can be updated and requiring GCs to be designed to a 
specific GPA standard could impede the acceptance of new technology.
Sec. 3175.118(b)
    Proposed Sec.  3175.118(b) would have required that gas samples be 
run until three consecutive runs met the repeatability standards stated 
in GPA 2261-00. Obtaining three consistent analysis results would have 
ensured that any contaminants in the GC system have been purged and 
that system repeatability is achieved. This proposed section would have 
also required that the sum of the un-normalized mole percentages of the 
gas components detected are between 99 percent and 101 percent to 
ensure proper functioning of the GC system. This requirement was based 
on GPA 2261-

[[Page 81587]]

00. The mole percentage is the percent of a particular molecule in a 
gas sample. For example, if there were 2 propane molecules for every 
100 molecules in a gas sample, the mole percentage of propane would be 
2. If the GC were perfectly accurate (zero uncertainty), the sum of 
mole percentages would always add up to 100. However, due to the 
uncertainties in the calibration and operation of the GC, the sum of 
the mole percentages varies from 100 percent. The amount of variation 
is an indication of how well the GC is performing and is a tool for 
quality control.
    The BLM received numerous comments objecting to the proposed 
requirement to run analyses until the sum of the un-normalized mole 
percentage is between 99 percent and 101 percent. The commenters stated 
that this is only applicable when verifying the GC and not for the 
actual analysis. The comments stated that this is often unachievable 
for portable GCs because of changes in atmospheric pressure during the 
analysis, especially when the inlet pressure to the GC is less than 30 
psig. Suggestions included a range of 97 to 103 mole percent and 98 to 
102 mole percent. The BLM agrees with these comments and changed the 
rule to read ``97 to 103'' mole percent. This would apply to both 
portable GCs and laboratory GCs.
    The BLM received numerous comments objecting to the proposed 
requirement to perform analyses until three consecutive runs are within 
the repeatability tolerance listed in GPA 2261-00. The commenters 
stated that the repeatability tolerances are not applicable to the 
analysis of field samples and that they only apply to calibration gas. 
One commenter stated that it can be difficult to extract more than 
three samples from a sample cylinder due to its limited volume and 
several commenters stated that it would be expensive and time consuming 
to meet the GPA repeatability standard for each sample. Several 
commenters stated that this is not applicable for portable GCs because 
the composition of the gas may actually change as more samples are run 
through the GC. Some commenters suggested that the rule require two 
consecutive runs, but only for calibration and verification. The BLM 
agrees with these comments and deleted this requirement altogether for 
laboratory GCs.
    The BLM believes that some criteria for portable GCs are needed and 
added a repeatability requirement to Sec.  3175.113(d)(5) as a result. 
For high-volume FMPs, the operator must continue to analyze samples 
until three consecutive samples result in a difference between the 
maximum and minimum heating value of 16 Btu/scf or less. For very-high-
volume FMPs, the limit is 8 Btu/scf. These limits were derived from the 
statistical method used in API 4.2, Appendix C, for determining the 
maximum allowable difference between proving runs necessary to achieve 
a set level of uncertainty. The equation used for this determination in 
Appendix C is:
[GRAPHIC] [TIFF OMITTED] TR17NO16.043

Where:

(a)MF = uncertainty of the average in the meter proving set
(w)MF = (high value--low value) of n runs in the proving set, 
divided by the average of the data set
t(%,n-1) = student ``t'' function, where the percentage is the 
confidence level and n is the number of proving runs
D(n) = factor that converts (high value--low value) to standard 
deviation

    This equation is equally applicable to heating value deviation 
in successive gas analysis runs and is rewritten by substituting 
``HV'' (heating value) for ``MF'' (meter factor):
[GRAPHIC] [TIFF OMITTED] TR17NO16.044

Where:

(a)HV = uncertainty of the average in the gas analysis set;
(w)HV = (high value-low value) of n runs in the proving set, divided 
by the average of the data set; and
n = the number of consecutive samples used for analysis.

    The accuracy of the heating value uncertainty in the data analysis 
set is defined as the average annual uncertainty in Sec.  3175.31(b), 
which is 2 percent for high-volume FMPs and 1 percent for very-high-
volume FMPs. The BLM realizes that average annual heating value 
uncertainty is not the same as the uncertainty of average heating value 
in the data analysis set. In reality, the uncertainty of the average 
heating value in the data analysis set should be much less than the 
average annual heating value uncertainty, perhaps as much as five times 
less. For example, in Sec.  3174.11, the allowable meter factor 
difference between provings is 0.25 percent, while the maximum 
allowable deviation between meter factors during a proving is 0.05 
percent. The allowable meter factor difference is analogous to the 
average annual heating value and the maximum allowable deviation 
between meter factors during a proving is analogous to the maximum 
allowable deviation between consecutive heating values when using a 
portable GC. For high-volume FMPs, a value of 2 percent is substituted 
for (a)HV in the equation above, the value of t for a 95 percent 
confidence level and three samples is 4.303, and the value of D(n) for 
three samples is 1.693. With these values, the above equation is solved 
for w(HV) as follows:
[GRAPHIC] [TIFF OMITTED] TR17NO16.045

    The result of this equation (0.013 or 1.3 percent) is the maximum 
deviation allowed between the maximum and minimum heating value 
determined over three consecutive samples that will result in a data 
set uncertainty of 2 percent. Using an average heating value of 1,200 
Btu/scf, the maximum allowable deviation in heating value is 16 Btu/
scf. For very-high-volume FMPs (one percent uncertainty), the maximum 
allowable deviation is 8 Btu/scf. The BLM believes that, in practice, 
heating value variability over three consecutive samples is well within 
this tolerance in most cases.
Sec. 3175.118(c)
    In the final rule, the BLM combined Sec.  3175.118(c) through (h) 
of the proposed rule into Sec.  3175.118(c) because all of these 
paragraphs address the calibration of GCs. Therefore, comments relating 
to the provisions of Sec.  3175.118(c) through (h) of the proposed rule 
are all addressed here.
    Proposed Sec.  3175.118(c) would have set a minimum frequency for 
verification of GCs. More frequent verifications would have been 
required for portable GCs (Sec.  3175.118(c)(1) of the proposed rule) 
because these devices may be exposed to field conditions such as 
temperature changes, dust, and transportation effects. All of these 
conditions have the potential to affect

[[Page 81588]]

calibration. In contrast, laboratory GCs (Sec.  3175.118(c)(2) of the 
proposed rule) are not exposed to these conditions; therefore, they do 
not need to be verified as often.
    The BLM received several comments objecting to the requirement in 
Sec.  3175.118(c)(1) of the proposed rule to verify a portable GC 
within 24 hours of taking a sample at an FMP. The commenters stated 
that daily verification of a GC is impractical because of the time it 
takes to do the verification and that the calibration facility is at a 
fixed location. One commenter stated that daily verification is not 
needed if the lab follows strict quality control procedures. The BLM 
agrees with these comments and changed the verification frequency for 
portable GCs to coincide with that for laboratory GCs (once every 7 
days) and moved the requirement to Sec.  3175.118(c)(1).
    Proposed Sec.  3175.118(d) would have required that the gas used 
for verification be different than the gas used for calibration. This 
requirement was proposed because it is relatively easy to alter the 
composition of a reference gas if it is not handled properly. An errant 
reference gas used to calibrate a GC would not be detected if the same 
gas is used for verification, which could lead to a biased heating 
value.
    The BLM received several comments objecting to the requirement in 
proposed Sec.  3175.118(d). These comments recommended deleting this 
provision because compromised calibration gas can be detected with 
quality control procedures such as monitoring the response factors of 
the calibration gas. The commenters also stated that neither GPA nor 
API require this and the operator would have to have two bottles of 
certified calibration gas which is expensive. The BLM agrees with these 
comments and deleted the requirement as a result. However, in its 
place, the BLM added minimum quality control requirements to the final 
rule. These requirements are in: Sec.  3175.118(c)(3), which requires 
the operator to authenticate all new gases under the standards of GPA 
2198-03, Section 5; Sec.  3175.118(c)(4), which requires the operator 
to maintain the gas under GPA 2198-03, Section 6; and Sec.  
3175.118(c)(5), which requires a GC to be calibrated if the composition 
of the calibration gas as determined by the GC varies from the 
certified composition of the calibration gas by more than the 
reproducibility values listed in GPA 2261-13, Section 10.
    Section 3175.118(c)(5) (Sec.  3175.118(e) in the proposed rule) 
would have required a calibration of the GC if the repeatability 
identified in GPA 2261-00, Section 9, could not be achieved during a 
verification.
    Numerous comments objected to this and said that the intent of the 
GPA standard cited was only for replication of the same sample. The BLM 
agrees with these comments and changed the wording to reference the 
``reproducibility'' standard in GPA 2261-13, instead of the 
repeatability standard. The BLM believes this change is appropriate 
because it accounts for differences in analyzing the same sample 
between different laboratories. The different laboratories are, in this 
case, the laboratory from which the calibration gas originated and the 
laboratory receiving and testing the calibration gas. The BLM also 
updated the reference from GPA 2261-00 in the proposed rule to GPA 
2261-13 in the final rule.
    Section 3175.118(f) in the proposed rule, requiring a GC to be re-
verified if a calibration was performed, was moved to Sec.  
3175.118(c)(6) in the final rule. The BLM did not receive any comments 
on this section.
    The requirement in Sec.  3175.118(h) of the proposed rule for all 
calibration gases to meet the standards of GPA 2198-03 was moved to 
Sec.  3175.118(c)(2) of the final rule. The BLM did not receive any 
comments on this paragraph.
Sec. 3175.118(d)
    Section 3175.118(d) requires documentation of the verification, 
calibration, and quality control process, which includes the 
requirements from Sec.  3175.118(i) in the proposed rule. This section 
requires the documentation to be retained as required under the record-
retention requirements in 43 CFR 3170.6 and provided to the BLM on 
request. For portable GCs, the rule (Sec.  3175.113(d)(4)) requires 
documentation to be available onsite. The purpose of the latter 
requirement is that it allows the BLM to inspect the verification 
documents while witnessing a spot sample that is taken with a portable 
GC. If the verification has not been performed in accordance with the 
requirements of Sec.  3175.118(d), the GC cannot be used to analyze the 
sample.
    The BLM added three new requirements to the documentation 
requirements in this section (proposed Sec.  3175.118(i)). These new 
requirements will help ensure that operators are implementing the 
quality-control measures required in the final rule in lieu of the 
requirement in the proposed rule to use a different gas for 
verification than was used for calibration. Section 3175.118(d)(7)(ii) 
requires documentation that new calibration gas was authenticated under 
Sec.  3175.118(c)(3), and Sec.  3175.118(d)(7)(iii) requires 
documentation that calibration gas was maintained under Sec.  
3175.118(c)(4). Section 3175.118(d)(8) also requires the documentation 
to include the chromatograms generated during the verification process.
Sec. 3175.118(e)
    The BLM received several comments stating that GPA 2261-13 is 
intended for analyses through hexanes-plus and should not be used for 
the extended analysis that the BLM is requiring under Sec.  
3175.119(b). The commenters recommended that the BLM incorporate by 
reference GPA 2286-14, which is used for extended analysis. The BLM 
agrees with these comments and added Sec.  3175.118(e) to the final 
rule to require extended analyses to be taken in accordance with GPA 
2286-14, which is incorporated by reference in the final rule. This 
paragraph allows the BLM to approve other methods as well.
Sec. 3175.119--Components To Analyze
    Section 3175.119(a) of the final rule requires gas analyses through 
hexane+ (C6+) for all low- and very-low-volume FMPs. For 
high- and very-high-volume FMPs where the concentration of 
C6+ exceeds 0.5 mole percent, the operator has two options. 
One option (Sec.  3175.119(b)) is for the operator to take an extended 
analysis (through C9+) every time the sample exceeds 0.5 
mole percent of C6+. The other option (Sec.  3175.119(c)) is 
for the operator to take periodic extended analyses and adjust the 
hexane-heptane-octane split (see Sec.  3175.126(a)(3)) based on those 
periodic analyses to eliminate any heating value bias that may exist. 
The second option could be more attractive to operators of FMPs that 
consistently have concentrations of C6+ in excess of 0.5 
mole percent.
    Analysis through C6+ is common industry practice and 
does not represent a significant change from existing procedures. 
Although components heavier than hexane exist in gas streams, these 
components are typically included in the C6+ concentration 
given by the GC by using an assumed split of hexane, heptane, and 
octane. Under proposed Sec.  3175.126(a)(3), the heating value of 
C6+ would have been derived from an assumed gas mixture 
consisting of 60 mole percent hexane, 30 mole percent heptane, and 10 
mole percent octane. At concentrations of C6+ below the 0.25 
mole percent threshold given in

[[Page 81589]]

proposed Sec.  3175.119(b), the uncertainty due to the assumed gas 
mixture given in Sec.  3175.126(a)(3) does not significantly contribute 
to the overall uncertainty in heating value and would not significantly 
affect royalty.
    Proposed Sec.  3175.119(b) would have required an extended analysis 
of the gas sample, through nonane+, if the concentration of 
C6+ from the standard analysis is 0.25 mole percent or 
greater. As indicated in Table 1 to Sec.  3175.110, this requirement 
does not apply to very-low-volume FMPs or low-volume FMPs. The 
threshold of 0.25 mole percent was derived through numerical simulation 
of the assumed composition of C6+ (60 mole percent hexanes, 
30 mole percent heptanes, and 10 mole percent octanes) compared to 
randomly generated values of hexanes, heptanes, octanes, and nonanes. 
The numerical simulation showed that the additional uncertainty of the 
fixed C6+ mixture required in Sec.  3175.126(a)(3) does not 
significantly add to the heating value uncertainties required in Sec.  
3175.31(b), until the mole percentage of C6+ exceeds 0.25 
mole percent. In the proposed rule, the BLM sought data that confirms 
or refutes the results of our numerical simulation. Specifically, we 
sought data comparing heating values determined with a C6+ 
analysis with heating values of the same samples determined through an 
extended analysis.
    The BLM received multiple comments objecting to the requirement to 
perform an extended analysis because, according to the commenters, 
extended analyses are expensive and provide little royalty or revenue 
benefit. The BLM received one comment that the 60-30-10 split of 
C6+ approximates the result of a C6+ analysis in 
a fair and equitable manner, and that the BLM should consider custom 
splits only in locations with high C6+ concentrations.
    One commenter indicated that the difference in heating value 
between a C6+ analysis and an extended analysis is less than 
the accuracy of the GC, and therefore, is not significant. Several 
commenters submitted data showing the difference in heating value based 
on a C6+ analysis and an extended analysis. The BLM analyzed 
these data and generated a graph showing the difference in heating 
value between a C6+ analysis and an extended analysis as a 
function of the mole percentage of C6+, assuming a 60-30-10 
split of hexane, heptane, and octane, respectively (Figure 2).
[GRAPHIC] [TIFF OMITTED] TR17NO16.046

    The BLM does not believe that Figure 2, generated from the data 
supplied by the commenters, supports the commenter's conclusions that 
the difference between an extended analysis and a C6+ 
analysis is less than the accuracy of a GC and is not significant or 
necessary. To analyze these data, the BLM first determined whether the 
apparent bias in the data as the mole percent of C6+ 
increases is statistically significant. To do this, the BLM used the 
reproducibility column from Table VI of GPA 2261-13, which gives an 
indication of the amount of deviation a given component will exhibit 
when a sample containing that component is analyzed at different 
laboratories. The BLM then applied these reproducibilities to an 
assumed gas analysis that resulted in a heating value similar to the 
heating values supplied by the commenter (approximately 1,119 Btu/scf) 
using a ``Monte Carlo'' methodology. From this analysis, the 
uncertainty in any given heating value is approximately 2 
Btu/scf at a 95 percent confidence level. The threshold of 
significance, using the definition provided in subpart 3170 is:
[GRAPHIC] [TIFF OMITTED] TR17NO16.047

Where:

Ts = threshold of significance
Ua = the uncertainty of data set a
Ub = the uncertainty of data set b

    Because this analysis compares data points to each other, the 
uncertainty of both data sets ``a'' and ``b'' is 2 Btu/scf, 
which yields a threshold of significance of 2.8 Btu/scf. In 
other words, any difference between two data points that is greater 
than 2.8 Btu/scf is statistically significant, and is 
outside the uncertainty associated with the gas chromatograph that 
derived these data

[[Page 81590]]

points. From Figure 2, there are three points that fall outside of the 
2.8 Btu/scf threshold at the bottom right-hand part of the 
graph. These three points include three of the four highest mole 
percentages of C6+ included in the data (1.0, 1.1, and 1.15 
mole percent C6+). As a result, the BLM concludes that the 
data presented by the commenters indicates a statistically significant 
bias associated with the assumed 60-30-10 split of C6+ when 
the mole percent of C6+ is 1.0 mole percent or higher. 
Therefore, the BLM disagrees with the comment that the difference in 
heating value between a C6+ analysis and an extended 
analysis is less than the accuracy of the GC, and therefore it is not 
significant. The BLM did not make any changes to the rule based on 
these comments.
    Commenters also made various suggestions regarding extended 
analysis that included not requiring an extended analysis in any 
circumstance and adjusting the C6+ threshold for requiring 
an extended analysis to a higher percentage (suggested values ranged 
from 0.5 mole percent to 1.0 mole percent). The BLM agrees with the 
comments suggesting a different threshold and changed the threshold at 
which an extended analysis is required from 0.25 mole percent in the 
proposed rule to 0.50 mole percent in the final rule. Not only does 
Figure 2 show a bias in the heating value when the mole percent of 
C6+ exceeds 1.0 mole percent (assuming a C6+ 
split of 60-30-10 hexane, heptane, and octane, respectively), Figure 2 
also suggests a correlation (correlation coefficient of 0.61) between 
the concentration of C6+ and heating value.
    The BLM notes that Figure 2 is based on one data set that contains 
a fairly narrow range of heating values (1,086 Btu/scf to 1,181 Btu/
scf) and, as such, may not be representative of potential bias or 
correlations that exist outside of that heating value range. Based on 
the threshold of significance analysis describe above, the BLM agrees 
that the 0.25 mole percent threshold from the proposed rule is too low 
and most likely would be less than the uncertainty of most GCs. 
However, the BLM believes that a threshold of 1 mole percent of 
C6+ is too high because the evidence supplied by one of the 
commenters (Figure 2) demonstrates that statistically significant bias 
is already present when the mole percent of C6+ reaches 1 
percent. As a result, the BLM raised the threshold to 0.5 mole percent 
of C6+, which is one of the thresholds suggested by a 
commenter. The BLM believes that the 0.5 mole-percent threshold is a 
reasonable balance between ensuring that heating values are not biased 
and reducing the economic burden to operators associated with the 0.25 
mole percent threshold in the proposed rule.
    Several commenters suggested that instead of requiring an extended 
analysis every time the C6+ analysis exceeds the threshold, 
the operator could periodically perform an extended analysis and, based 
on that analysis, could adjust the C6+ split (hexane, 
heptane, and octane) to eliminate any bias. The BLM agrees with this 
comment and included a new Sec.  3175.119(c) that will allow this in 
lieu of performing an extended analysis every time the mole percent 
exceeds the threshold. If the operator chooses this option, the new 
paragraph requires an extended analysis once per year for high-volume 
FMPs and twice per year for very-high-volume FMPs.
    One commenter suggested basing the threshold on the Btu content in 
combination with the mole percentage of C6+. The BLM 
analyzed the suggestion of basing the threshold on the Btu content 
rather than on the mole percentage of C6+. Figure 3 shows 
the same data as in Figure 2, but plotted against heating value instead 
of the mole percentage of C6+. Based on an analysis of 
Figure 3, the BLM believes the relationship between heating value 
difference and heating value (correlation coefficient of 0.24) is much 
less clear than the relationship between heating value difference and 
concentration of C6+; therefore, the BLM did not adopt the 
suggestion to base the threshold on heating value.
[GRAPHIC] [TIFF OMITTED] TR17NO16.048

    One commenter provided some cost data to show the additional cost 
of requiring extended analyses as compared to a standard C6+ 
analysis. While the BLM acknowledges that extended analyses are more 
expensive than C6+ analyses, the changes made to the final 
rule (increasing the threshold from 0.25 mole percent C6+ to 
0.50 mole percent C6+ and allowing periodic extended 
analysis to adjust the hexane, heptane, octane split) will minimize

[[Page 81591]]

these costs. In addition, the BLM considered these costs in determining 
the thresholds for the various flow-rate categories (see the BLM 
Threshold Analysis). However, in the Threshold Analysis, the cost of 
complying with the requirements in the final rule relating to volume 
measurement were higher than the cost of complying with the 
requirements in the final rule relating to heating value determination. 
Therefore, the thresholds are based on the cost of volume determination 
rather than on the costs of heating value determination. The BLM did 
not make any changes based on this comment.
    Several commenters objected to the BLM simulation used to determine 
the 0.25 mole percent threshold and the significant variance in heating 
value which resulted from the simulation. Other commenters requested 
that the simulation be provided for review, and suggested further 
review prior to implementing this rule. Multiple commenters expressed 
concern over the availability or ability of many labs to provide the 
extended analysis, and whether measurement systems are able to handle 
the extended analysis input. The BLM did not make any changes to the 
rule based on these comments. The BLM did not provide the simulation 
because it only established the basis for the proposed threshold. The 
BLM specifically asked for data showing the difference between 
C6+ analysis and an extended analysis as a function of the 
concentration of C6+ and based the final threshold on this 
data. The BLM was unable to evaluate comments concerning the 
laboratory's ability to perform C6+ analysis, and those that 
contended measurement systems may not be able to take a C6+ 
analysis as input, because the commenters did not supply data or 
rationale to support their comment. A comment also stated that low-
volume and very-low-volume FMPs should be exempt from uncertainty of 
heating value, and that extended analysis should only be required once 
per year. Low- and very-low-volume FMPs were exempt from the extended 
analysis requirement in the proposed rule, and are still exempt in the 
final rule, as shown in Table 1 to Sec.  3175.110. The BLM did change 
the rule by adding Sec.  3175.119(c) which allows operators of high-
volume FMPs the option of performing an extended analysis once per 
year; operators of very high-volume FMPs have the option of performing 
a semi-annual extended analysis.
Sec. 3175.120--Gas Analysis Report Requirements
    Section 3175.120 establishes minimum standards for the information 
that must be included in a gas analysis report. This information allows 
the BLM to verify that the sampling and analysis comply with the 
requirements in Sec.  3175.110, and enables the BLM to independently 
verify the heating value and relative density used for royalty 
determination.
    Section 3175.120(a) establishes the minimum requirements for the 
information required in a gas analysis report. The BLM did not receive 
any comments on this paragraph.
    Section 3175.120(b) requires that gas components not tested be 
annotated as such on the gas analysis report. It is common practice for 
industry to include a mole percentage for each component shown on a gas 
analysis report, even if there was no analysis run for that component. 
For example, the gas analysis report might indicate the mole percentage 
for hydrogen sulfide to be ``0.00 percent,'' when, in fact, the sample 
was not tested for hydrogen sulfide.
    The BLM received several comments objecting to this requirement 
because they said it would take time and money to implement and may 
require reprogramming of some systems. For the following reasons, the 
BLM did not make any changes to the rule based on these comments. The 
BLM believes that the current practice of reporting zero concentration 
for untested components is misleading and potentially dangerous, 
especially for components such as hydrogen sulfide. For example, if a 
gas analysis report shows a concentration of zero for hydrogen sulfide, 
the person looking at the analysis could falsely conclude that there is 
no hydrogen sulfide present. This could have serious safety 
consequences. Unless an extended analysis is run, concentrations of 
hexanes, heptanes, octanes, and nonanes are not individually tested; 
however, many gas analyses report zero for these concentrations. 
Because the BLM is requiring extended analyses in some cases (see Sec.  
3175.119(b)), the reporting of zero for hexanes, heptanes, octanes, and 
nonanes, when these components are not tested, is misleading because it 
could indicate that an extended analysis was run when it was not. 
Although the commenters did not quantify for the BLM the additional 
time and expense they would incur from this requirement, the BLM 
believes that it would be negligible. One commenter suggested that a 
blank or null entry of a component in a gas analysis could be used to 
indicate that it was not tested. While the BLM agrees with this 
comment, no changes were made to the rule because the suggestion would 
satisfy the requirement as written.
    Section 3175.120(c) specifies that heating value and relative 
density must be calculated under API 14.5, while Sec.  3175.120(d) 
specifies that supercompressibility be calculated under AGA Report No. 
8. The BLM changed the reference from API 14.2 in the proposed rule to 
AGA Report No. 8 in the final rule because the BLM determined that the 
API 14.2 standard primarily referenced the AGA Report No. 8 standard. 
The BLM believes that the latter is the most appropriate source for the 
supercompressibility calculations.
    One commenter stated that the rule needs to specify the version and 
date of API 14.5 and API 14.2, and went on to suggest that the BLM 
should adopt the new standards for calculating the thermodynamic 
properties of gas in 14.2.1 and 14.2. The BLM did not make any changes 
to the rule as a result of this comment because the incorporation by 
reference section of the rule (Sec.  3175.30) already specifies the 
version and date. The new version of API 14.2 that the commenter refers 
to is not yet publically available; therefore the BLM cannot 
incorporate it. As noted above, the BLM references AGA Report No. 8 in 
the final rule instead of API 14.2.
    Proposed Sec.  3175.120(e) would have required operators to submit 
all gas analysis reports to the BLM within 5 days of the due date for 
the sample. For high-volume and very-high-volume FMPs, the gas analyses 
would be used to calculate the required sampling frequencies under 
Sec.  3175.115(c). Requiring the submission of all gas analyses allows 
the BLM to verify heating-value and relative-density calculations and 
it allows the BLM to determine operator compliance with other sampling 
requirements in proposed Sec.  3175.110. The method of determining gas 
sampling frequency for high-volume and very-high-volume FMPs assumes a 
random data set. The intentional omission of valid gas analyses would 
invalidate this assumption and could result in a biased annual average 
heating value. This could be considered tampering with a measurement 
process under 43 CFR 3170.4.
    The BLM received many comments objecting to the 5-day timeframe to 
submit gas analyses to the BLM. The comments stated that 5 days is not 
reasonable because of the process required to obtain the analysis, send 
it out to a laboratory, get it analyzed, and then evaluate the 
analysis. Commenters suggested timeframes ranging from 15 days to 30 
days. The BLM agrees with

[[Page 81592]]

these comments and changed the timeframe from 5 days to 15 days. The 
BLM believes that 15 days is a reasonable amount of time in which to 
obtain, analyze, evaluate, and submit the results to the BLM. The BLM 
did not opt for a longer period of time because this could cause 
confusion when, for example, the required sampling frequency is twice 
per month. In this case, a longer timeframe could result in overlapping 
periods of time.
    One commenter questioned how an operator would meet the 5-day 
reporting timeframe in the proposed rule if the well is not flowing at 
the time the sample was due. The BLM addresses this situation in Sec.  
3175.113(a) of both the proposed and final rule. If the FMP is not 
flowing at the time the sample is due, the operator has 15 days from 
the resumption of flow to sample the FMP.
    Proposed Sec.  3175.120(f) would have required operators to submit 
all gas analysis reports to the BLM using the GARVS online computer 
system that the BLM is developing. Under the proposed rule, operators 
would have been required to submit all gas analyses electronically, 
unless the operator is a small business, as defined by the U.S. Small 
Business Administration, and does not have access to the Internet. The 
BLM received numerous comments on this requirement stating that the BLM 
should delay implementation of this requirement until GARVS is 
developed and the industry knows what the system requirements will be. 
The BLM agrees with this comment and is delaying this requirement for 2 
years from the effective date of this rule. For further discussion of 
GARVS implementation, see the earlier discussion of Sec.  3175.60.
Sec. 3175.121--Effective Date of a Spot or Composite Gas Sample
    Proposed Sec.  3175.121 would have established an effective date 
for the heating value and relative density determined from spot or 
composite sampling and analysis. Section 3175.121(a) establishes the 
effective date as the date on which the spot sample was taken unless it 
is otherwise specified on the gas analysis report. For example, 
industry will sometimes choose the first day of the month as the 
effective date to simplify accounting. While the BLM believes this is 
an acceptable practice, there is a need to place limits on the length 
of time between the sample date and the effective date based on 
inconsistencies found as part of the Gas Variability Study discussed 
earlier. Section 3175.121(b) establishes that the effective date can be 
no later than the first day of the month following the date on which 
the operator received the laboratory analysis of the sample. This 
accounts for the delay that often occurs between taking the sample, 
obtaining the analysis, and applying the results of the analysis. If, 
for example, a sample were taken toward the end of March, the results 
of the analysis may not be available until after the first of April. 
Section 3175.121(b) would allow the effective date to be the first of 
May. Based on the Gas Variability Study conducted by the BLM, the 
timing of the effective date of the sample is less important than the 
timing of the samples taken over the year.
    Proposed Sec.  3175.121(c) would have required the effective dates 
of a composite sample to coincide with the time that the sample 
cylinder was collecting samples. A composite sampling system takes 
small samples of gas over the course of a month or some other time 
period, and places each small sample into one cylinder. At the end of 
that time period, the cylinder contains a gas sample that is 
representative of the gas that flowed through the meter over that time 
period. Therefore, the proposed rule would have established the 
effective date as the date on which the composite sample cylinder was 
installed.
    The BLM received multiple comments objecting to the requirement 
that the installation date of the composite sample cylinder should be 
the effective date of the sample. The commenters argued that sample 
cylinders on composite samplers are typically removed the last week of 
the month and the heating value and relative density from that sample 
are applied for the whole month. The new cylinder is installed 
immediately after the old cylinder is removed. If the effective date is 
the day the cylinder is installed, as required in the proposed rule, 
the heating value and relative density would be extrapolated back 
nearly a month. This, according to commenters, is not consistent with 
industry practice. The BLM agrees with these comments and made two 
changes to the rule as a result. First, the BLM changed the effective 
date for the composite sample from the first of the month that the 
sample cylinder was installed, to the first of the month that the 
sample cylinder was removed. Second, the BLM added language that allows 
the BLM to accept other methods, as long as they are specified on the 
gas analysis report.
    The BLM received one comment suggesting that the proposed effective 
date of spot or composite gas sample would cause retroactive 
adjustments on past volumes, heating value and prior period corrections 
resulting in resubmission of OGORs, with little or no impact on royalty 
significance. In response to this comment, the BLM added Sec.  
3175.121(d) to clarify that the requirements of this section only apply 
to reports generated after January 17, 2017.
Sec. 3175.125--Calculation of Heating Value and Volume
    Section 3175.125(a) defines how the operator must calculate heating 
value. Section 3175.125(a)(1) and (2) define how to calculate the gross 
and real heating value. The calculation and reporting of gross and real 
heating value are standard industry practices.
    Section 3175.125(b)(1) establishes a standard method for 
determining the average heating value to be reported for a lease, unit 
PA, or CA, when the lease, unit PA, or CA contains more than one FMP. 
Consistent with current ONRR guidance (Minerals Production Reporter 
Handbook, Release 1.0, 05/09/01, Glossary at 14), this method requires 
the use of a volume-weighted average heating value to be reported. 
Section 3175.125(b)(2) establishes a requirement for determining the 
average heating value of an FMP when the effective date of a gas 
analysis is other than the first of the month. This methodology also 
requires a volume-weighted average for determining the heating value to 
be reported. Although this is not specifically addressed in the 
Reporter Handbook, the method is consistent with the volume-weighted 
average proposed for multiple FMPs. The BLM did not receive any 
comments on this section.
Sec. 3175.126--Reporting of Heating Value and Volume
    Section 3175.126 defines the conditions under which operators must 
report the heating value and volume for royalty purposes.
Sec. 3175.126(a)
    The reporting of gross and real heating value in Sec.  3175.126(a) 
is consistent with standard industry practice. The BLM did not receive 
any comments on this paragraph.
    Section 3175.126(a)(1) requires operators to report the ``dry'' 
heating value (no water vapor) unless they make an onsite measurement 
of water vapor using a method approved by the BLM. This could be a 
change for some operators because gas sales contracts often call for 
``wet'' or as-delivered heating values to be used. The BLM has 
determined that ``wet'' heating values almost always bias the heating 
value to the low side because the definition of ``wet'' heating value 
assumes the gas is

[[Page 81593]]

saturated with water vapor at 14.73 psi and 60 [deg]F. If the actual 
flowing pressure of the gas is greater than 14.73 psi or the actual 
flowing temperature is less than 60 [deg]F, the use of a ``wet'' 
heating value will overstate the amount of water vapor that can be 
physically present, and, therefore, understate the heating value of the 
gas. Therefore, the BLM is requiring a ``dry'' heating value 
determination unless the actual amount of water vapor is physically 
measured and reported on the gas analysis report. This requirement is 
consistent with established BLM practice as reflected in BLM Washington 
Office Instruction Memorandum (IM) 2009-186, dated July 28, 2009.
    The BLM would have considered allowing an adjustment in heating 
value for assumed water-vapor saturation at flowing pressure and 
temperature (sometimes referred to as ``as delivered'') in the final 
rule if sufficient data had been presented in the public comments to 
determine under what flowing conditions the assumption is valid; 
however, no data were submitted with the public comments.
    This section also defines the acceptable methods to measure water 
vapor: The BLM may approve a chilled mirror, a laser detection system, 
and other methods reviewed by the PMT and approved by the BLM. Stain 
tubes and other similar measurement methods are not allowed because of 
the high degree of uncertainty inherent in these devices.
    The BLM received multiple comments objecting to the proposed 
requirement that heating value must be reported ``dry.'' These comments 
indicate that ``dry'' Btu creates a bias, and recommend that the BLM 
adopt the water-vapor adjustment methods in GPA 2172. One commenter 
stated that water saturation was closer to as-delivered than dry. While 
the BLM agrees that most gas may have some degree of water saturation, 
the commenters did not submit any data to substantiate their argument 
that the gas is saturated or the degree to which the gas is saturated. 
The BLM received proprietary data from one operator outside of the 
comment period on the proposed rule that clearly show that gas is not 
consistently saturated with water vapor. According to this data, 
saturation levels range from 20 percent to 100 percent. Again, no data 
to the contrary was submitted by any of the commenters. Assuming that 
gas is always 100 percent saturated with water vapor would cause a bias 
in the reported heating value, which would result in the underpayment 
of royalty. The BLM does not contest that the requirement to report all 
heating values on a dry basis probably results in a bias as well. 
However, under paragraph (a)(1) of this section, industry has the 
option of measuring water vapor or developing other methods to remove 
this potential bias. The BLM would have no recourse for the low bias 
resulting from allowing operators to report on an as-delivered basis. 
The BLM did not make any changes to the rule as a result of these 
comments.
    Several comments indicated that the water saturation levels on low 
pressure wells (e.g., coalbed methane wells) are nearly impossible to 
obtain with current technologies, and determining water saturation is 
prohibitively expensive in general gas analysis. One comment suggested 
that all wells should have water vapor content measured and that water 
vapor saturation should be measured on the same frequency as Btu 
determination. The BLM is not requiring operators to measure water 
vapor; this is an economic decision the operator must make. If the 
operator believes that the additional royalty they are paying on a dry 
heating value is more than the cost of installing and operating water 
vapor measurement equipment, the operator would have an economic 
incentive to purchase the equipment. If the operator chooses not to 
install water vapor measuring equipment, then the public and Indian 
tribes will not suffer any financial loss as a result. In addition, the 
BLM does not require wellhead measurement, but measurement prior to 
removal or sales from the lease, unit PA, or CA, unless otherwise 
approved by the AO. Therefore, if an operator believes that wellhead 
measurement of water vapor is prohibitively expensive, the operator 
could combine the production from multiple wells within a lease, CA, or 
unit PA and measure the combined stream without needing approval from 
the BLM. The BLM did not make any changes to the rule as a result of 
these comments.
    Other comments suggested that the BLM should accept the as-
delivered basis until operators and the BLM can figure out a better way 
to estimate water vapor content, and that the presence of free water 
during an inspection indicates that the gas is saturated. The BLM 
rejects the idea of using the as-delivered basis as the default until 
the BLM and industry can figure out a better way to estimate water-
vapor content. If the BLM were to accept the as-delivered basis as the 
default, industry would have no economic incentive to pursue more 
accurate measurement techniques. The BLM also rejects the notion that 
the presence of free water indicates the gas is saturated with water 
vapor. While that argument may be true at the time when the inspection 
was made, it is also possible that the free water will disappear when, 
for example, the temperature rises, thereby increasing the amount of 
water vapor the gas can hold. The BLM did not make any changes to the 
rule as a result of these comments.
    One commenter requested more time to collect data. The BLM rejects 
the idea of granting more time for industry to collect data. The BLM 
has been publicly asking for water vapor data at API meetings for at 
least 6 years. The BLM did not make any changes to the rule as a result 
of this comment.
    Another commenter expressed concerns over the conflict between BLM 
regulations requiring a dry heating value and State regulations 
requiring the heating value to be reported on some other basis. The BLM 
did not make any changes as a result of these comments. The BLM does 
not believe that the requirement to report a dry heating value 
conflicts with State regulations. The BLM understands that State 
reporting requirements may differ from the BLM and ONRR's requirements 
for reporting of Federal and Indian production. This difference is 
currently seen in reporting of gas volumes, in that some states require 
a pressure base of 15.05 psia, or 14.65 psia, whereas the BLM 
requirement is 14.73 psia. The BLM does not see this difference as a 
conflict, just a variable way to report heating value. The BLM did not 
make any changes to the rule as a result of this comment.
    Section 3175.126(a)(2) requires the heating value to be reported at 
14.73 psia and 60 [deg]F. This requirement is consistent with ONRR 
regulations at 30 CFR 1202.152(a)(1)(ii). The BLM received a comment 
cautioning that heating value and volume must be reported at the same 
pressure or temperature and objecting to the requirement to report 
heating value at any other standard (such as 14.73 psia and 60 [deg]F), 
than that specified in the sales contract. The BLM did not make any 
changes as a result of this comment. The BLM acknowledges that the 
volume and heating value reported on the monthly OGOR should be at the 
same pressure and temperature. ONRR requires that all volumes and 
heating value be reported at a standardized pressure of 14.73 psia and 
60 [deg]F, even when this standard conflicts with the gas sales 
contract. Both the gas volume calculation methods (Sec. Sec.  3175.94 
and 3175.103) and the heating value calculation methods (see Sec.  
3175.126(a)(2)) require a base pressure of 14.73 psia and 60 [deg]F.

[[Page 81594]]

    The composition of C6+ that would have been required 
under the proposed rule for heating value and relative density 
calculation is given in Sec.  3175.126(a)(3). This composition is based 
on examples shown in API 14.5, Annex B.
    The BLM received one comment suggesting that if an operator has 
better data for this split, they should be able to use it, and 
requested an example of how the BLM would implement this. Another 
comment indicated that the ``actual'' composition, not the ``deemed'' 
composition should be used. The BLM agrees with these comments and 
added a paragraph to the final rule that would allow operators to use a 
hexane-heptane-octane split that is derived from an extended analysis 
taken under Sec.  3175.119(c). In this scenario, operators would take 
periodic extended analyses when the composition of C6+ 
exceeds 0.50 mole percent, and use the actual extended analysis to 
derive a hexane-heptane-octane split that they would apply to the 
C6+ analyses until they took the next required extended 
analysis. For analyses that are 0.50 mole percent or less of 
C6+, the operator does not have to run an extended analysis 
and could use the 60-30-10 split in paragraph (a)(3)(i) of this 
section. See the discussion under Sec.  3175.119(b) for a further 
discussion of the impact of C6+ on heating value.
    One commenter requested the reference for using the 60-30-10 split. 
The BLM did not make any changes to the rule based on this comment. The 
reference for this split was given in the preamble to the proposed rule 
(see 80 FR 61678).
Sec. 3175.126(b)
    Section 3175.126(b) describes the way in which gas volume must be 
reported by operators for royalty purposes. Section 3175.126(b)(1) 
prohibits the practice of adjusting volumes for assumed water vapor 
content, since this is currently done in some cases in lieu of 
adjusting the heating value for water vapor content. This results in 
the volume being underreported. The BLM would have considered allowing 
a volume adjustment for water vapor if sufficient data were submitted 
during the public comment period to support an adjustment, as discussed 
above. No data were submitted, however.
    Section 3175.126(b)(2) will require the unedited volume on a QTR 
(EGM systems) or an integration statement (mechanical recorders) to 
match the volume reported for royalty purposes, unless edits to the 
data can be justified and documented by the operator. The BLM did not 
receive any comments on this paragraph.
Sec. 3175.126(c)
    Proposed Sec.  3175.126(c) would have established new requirements 
for edits and adjustments to volume or heating value. Section 
3175.126(c)(1) would have set requirements as to how operators would 
adjust volumes and heating values if measuring equipment is out of 
service or malfunctioning. The BLM received several comments regarding 
the methodology required for error correction and/or adjustment of 
volume or heating value on a QTR. One comment indicated the methods 
were too prescriptive, and a second comment recommended adding wording 
to Sec.  3175.126(c)(1)(i). The BLM agrees that the required 
methodology in proposed Sec.  3175.126(c)(1)(i) and (ii) was too 
prescriptive, and determined that documentation required by Sec.  
3175.126(c)(2) and (3) allows adequate determination of the cause of 
the error and the adjustment methodology utilized to correct volume 
errors. Therefore, The BLM deleted Sec.  3175.126(c)(1)(i) and (ii).
    Section 3175.126(c)(2) requires documentation justifying all edits 
made to data affecting volumes or heating values reported on the OGORs. 
While the BLM recognizes that meter malfunctions and other factors can 
necessitate editing the data to obtain a more correct volume, this 
section requires operators to thoroughly justify and document the edits 
made. This includes QTRs and integration statements. The operator must 
retain the documentation as required under 43 CFR 3170.7 and submit it 
to the BLM upon request. The BLM did not receive any comments on this 
section.
    Section 3175.126(c)(3) requires that any edited data be clearly 
identified on reports used to determine volumes or heating values 
reported on the OGORs and cross-referenced to the documentation 
required in Sec.  3175.126(c)(2). This includes QTRs and integration 
statements. The BLM received one comment stating that the requirement 
to clearly identify all volumes that have been changed or edited would 
result in changes to industry accounting systems, and require the 
development of a new interface with OGOR comment reporting. The BLM did 
not make any changes as a result of this comment. The BLM does not 
intend to require ``comments'' on OGORs due to changes or edits to 
volumes and heating value. The intent of the requirement is to have the 
operator, purchaser, or transporter document changes, edits and provide 
justification. The operator must then maintain this documentation and 
make it available to the BLM upon request.
    Section 3175.126(c)(4) requires OGORs submitted to ONRR to be 
amended when inaccuracies are discovered at an FMP. The BLM did not 
receive any comments on this paragraph, and made no changes in the 
final rule.
Sec. 3175.130--Transducer Testing Protocol
    Section 3175.130 establishes a testing protocol for differential-
pressure, static-pressure, and temperature transducers used in 
conjunction with differential-flow meters at FMPs. This section was 
added to implement the requirements in Sec.  3175.31(a) for flow-rate 
uncertainty limits. To determine flow-rate uncertainty, it is necessary 
to first determine the uncertainty of the variables that go into the 
calculation of the flow rate. For differential flow meters, these 
variables include differential pressure, static pressure, and flowing 
temperature. Transducers (secondary devices) derive these variables by 
measuring, among other things, the pressure drop created by the primary 
device (e.g., an orifice plate). Therefore, the uncertainty of these 
variables is dependent on the uncertainty of the transducer's ability 
to convert the physical parameters measured into a digital value that 
the flow computer can use to calculate flow rate and, ultimately, 
volume.
    Currently, methods used to determine uncertainty (i.e., the BLM 
Uncertainty Calculator) rely on performance specifications published by 
the transducer manufacturers. However, the methods that manufacturers 
use to determine and report these performance specifications are 
typically proprietary, performed in-house, and the BLM cannot verify 
them. In addition, the BLM believes that there is little consistency 
among manufacturers regarding the standards and methods used to 
establish and report performance specifications.
    The testing procedures in Sec. Sec.  3175.131 through 3175.135 are 
based, in large part, on testing procedures published by the 
International Electrotechnical Commission (IEC). Some of these 
standards are already used by several transducer manufacturers; however 
it is unknown which manufacturers use which standards or to what extent 
they do so. Based on numerous comments received under Sec.  3175.43, 
the BLM will mandate this protocol only for new transducers that are 
not used at FMPs by the effective date of this rule (see the discussion 
under Sec.  3175.43).

[[Page 81595]]

    Numerous comments suggested that the BLM eliminate this requirement 
and use existing American National Standards Institute (ANSI), 
International Society of Automation (ISA), National Fire Protection 
Association (NFPA), GPA, AGA, and API standards instead. The BLM did 
not make any changes to the rule based on these comments because the 
BLM is not aware of any standards for testing transducers specific to 
oil and gas operations.
    One commenter asked if the BLM was intending to incorporate the 
draft API standards 22.4 (transducer testing protocol) and 22.5 (flow-
computer software testing protocol) into the final rule. The BLM would 
have considered incorporating the draft API standards into the rule if 
they had been published in time. As an alternative, the BLM may seek to 
amend the regulations once the new API standards are published. The BLM 
participated in the working groups for both of the draft API standards 
and believes that, in general, the provisions of the draft standards 
would be beneficial in accomplishing the goals of a testing protocol. 
No changes to the proposed rule were made as a result of this comment.
    Several comments stated that testing should be the responsibility 
of the manufacturer, not the operator, and that the BLM should use 
performance standards rather than require testing of components. See 
the response to these comments under Sec.  3175.43.
    One commenter suggested that the BLM only require testing of those 
transducers commonly used in the field. The BLM is only requiring 
testing of transducers that manufacturers or operators want to use on 
Federal and Indian leases. Therefore, if a manufacturer or operator 
wants to use a particular transducer, they must have it tested in 
accordance with this rule. The fact that the transducer is commonly or 
not commonly used has no bearing on the BLM's acceptance of 
transducers. The BLM did not make any changes to the rule in response 
to this comment.
Sec. 3175.131--General Requirements for Transducer Testing
    Section 3175.131(a) establishes standards for test facilities 
qualified to perform the transducer-testing protocol. Proposed Sec.  
3175.130(a)(1) would have required tests to be carried out by a lab 
that is not affiliated with the manufacturer to avoid any real or 
perceived conflict of interest. Traceability to the NIST proposed in 
Sec.  3175.131(a)(2) was based on IEC Standard 1298-1, section 7.1.
    One comment expressed concerns that limiting the standards body to 
NIST would prevent the use of international labs. The BLM agrees with 
these comments and added a definition of qualified test facility that 
refers to NIST or an equivalent international standard.
    Numerous comments suggested that the BLM allow in-house testing of 
transducers because sending transducers to an independent facility 
would be burdensome and cost prohibitive. In addition, the comments 
stated, there are very few independent facilities that could perform 
this testing and they would be overwhelmed by manufacturers trying to 
comply with this requirement, making it difficult to get the testing 
done in a timely manner. Some of the commenters suggested that the BLM 
should allow in-house facilities if they are certified by a national or 
international standards body such as NIST or ISO. The BLM agrees that 
transducer testing is specialized and there may not be many independent 
laboratories capable of performing these tests. Therefore, in the final 
rule, the BLM does not require this testing to be performed by an 
independent lab as long as it meets the definition of a ``qualified 
test facility.''
    In general, the testing requirements in Sec.  3175.131(c) through 
(h) are based on IEC standard 1298-1, Section 6.7. While the IEC does 
not specify the minimum number of devices required for a representative 
number, the BLM is requiring (in Sec.  3175.131(b)(1)) that at least 
five transducers be tested to ensure testing of a statistically 
representative sample of the transducers coming off the assembly line. 
The BLM specifically requested comments on whether the testing of five 
transducers is a statistically representative sample. The BLM received 
no comments on paragraphs (c) through (h) of this section.
    Section 3175.131(b) requires that the testing protocol be applied 
to each make, model, and URL of transducers used at FMPs, to ensure 
that any transducer with the potential to have unique performance 
characteristics is tested.
    One commenter asked if an existing transmitter would have to be 
replaced if the model was not type tested. First, the requirement to 
type test transducers does not apply to very-low-volume or low-volume 
FMPs. Second, under the final rule, existing transducers at high- and 
very-high-volume FMPs would not have to be replaced as long as the 
operator or manufacturer submitted the test data the manufacturer used 
to derive their published performance specifications. The BLM did not 
make any changes to the rule as a result of these comments.
    Two commenters expressed a concern that testing each model number 
could extend to tens of thousands of variations of transducers. The BLM 
agrees that there could be confusion over how many combinations of 
models need to be tested under this section and added language to Sec.  
3175.131(b) to clarify what constitutes a ``model'' (Sec.  
3175.131(b)(3)) and how the testing applies to multi-variable 
transducers (Sec.  3175.131(b)(4)). The BLM is only concerned with 
testing aspects of a transducer that affect its performance. For 
example, one manufacturer makes the following models of a multi-
variable transducer:
[GRAPHIC] [TIFF OMITTED] TR17NO16.049

A 3-digit model number suffix that is added to each of the base model 
numbers indicates the output type (three possible combinations), the 
mounting type (four possible combinations), and the location of the 
static pressure sensor (two possible combinations). Assuming that the 
output type, mounting type, and static

[[Page 81596]]

pressure sensor location do not affect the performance of the 
transducer, none of these combinations would have to be tested. In 
addition, language in the final rule clarifies that a particular cell 
only has to be tested once under the protocol. In this example, the 
operator or manufacturer would only have to test only eight ranges for 
this make and model (100'', 400'', 800'', 1,200'', 150 psia, 500 psia, 
1,500 psia, and 3,000 psia).
    Test equipment requirements for field calibrations are listed under 
Sec.  3175.102(c). One commenter stated that the BLM should not require 
test equipment used to calibrate transducers in the field to meet the 
accuracy requirement in Sec.  3175.131(d), which requires the test 
equipment to be four times more accurate than the equipment being 
tested. The test equipment accuracy requirements in Sec.  3175.131(d) 
are specific to transducer type testing. The BLM did not make any 
changes to the rule in response to this comment.
Sec. 3175.132--Testing of Reference Accuracy and 3175.133--Testing of 
Influence Effects
    Sections 3175.132 and 3175.133 establish specific testing 
requirements for reference accuracy and influence effects. These 
requirements are based on the following IEC standards: IEC 1298 1, IEC 
1298-2, IEC 1298-3, and IEC 60770-1. The testing described in the 
proposed rule would have required a long-term stability test that would 
have cycled each transmitter through several influence effects over a 
period of 24 weeks.
    Numerous comments expressed concern about the long-term stability 
test that would have been required in the proposed rule. The comments 
stated that this test would cost hundreds of thousands of dollars to 
perform for each make, model, and range tested, and that there are very 
few test facilities with the capability to perform this test. The BLM 
agrees with these comments and removed the requirement for a long term 
stability test in the final rule. However, removing this requirement 
raised issues about how the BLM would address long-term stability in 
the field. To address these issues, the BLM added Sec.  3175.102(c)(3) 
that requires the operator to replace any transducer if, on two 
consecutive routine verifications, the as-found values were off by more 
than the manufacturer's specification for long-term stability, as 
adjusted for static pressure and ambient temperature. The BLM believes 
that this requirement will ensure that transducers that exhibit a high 
degree of drift are identified and replaced.
Sec. 3175.134--Transducer Test Reporting
    Section 3175.134 requires documentation of the transducer testing 
(under Sec. Sec.  3175.131 through 3175.133 of this subpart) and the 
submission of the documentation to the PMT. The PMT will use the 
documentation to determine the uncertainty and influence effects of 
each make, model, and range of transducer tested. The BLM did not 
receive any comments on this section.
Sec. 3175.135--Uncertainty Determination
    Section 3175.135 establishes a method of deriving reference 
uncertainty and quantifying influence effects from the tests required 
by this protocol. The methods for determining reference uncertainty are 
based on IEC Standard 1298-2, Section 4.1.7. While the IEC standards 
define the methods to be used for influence-effect testing, no specific 
methods are given to quantify the influence effects; therefore, the BLM 
developed statistical methods to determine zero-based effects and span-
based effects. In addition, all uncertainty calculations use a 
``student t-distribution'' to account for the small number of 
transducers of a particular make, model, URL, and turndown, to be 
tested. After a transducer has been tested under Sec. Sec.  3175.131 
through 3175.134, the PMT will review the results. Once the BLM 
approves the device, the BLM will list the approved transducers for use 
at FMPs (see Sec.  3175.43), and list the make, model, URL, and 
turndown of approved transducers on the BLM Web site along with any 
operating limitations or other conditions. The BLM did not receive any 
comments on this section.
Sec. 3175.140--Flow-Computer Software Testing
    Section 3175.140 provides that the BLM will approve a particular 
version of flow-computer software for use in a specific make and model 
of flow computer only if the testing is performed under the testing 
protocol in Sec. Sec.  3175.141 through 3175.144, to ensure that 
calculations meet API standards. Unlike the testing protocol for 
transducers in Sec.  3175.130, which is used to derive performance 
specifications, the testing protocol for flow computers includes pass-
fail criteria. Testing is only required for those software revisions 
that affect volume or flow rate calculations, heating value, or the 
audit trail.
    Numerous comments suggested that the BLM eliminate this requirement 
and use existing ANSI, ISA, NFPA, GPA, AGA, and API standards instead. 
One commenter asked if the BLM was intending to incorporate the draft 
API standards 22.4 (transducer testing protocol) and 22.5 (flow-
computer software testing protocol) into the final rule. See the 
response to these comments under Sec.  3175.130. The BLM did not make 
any changes to the rule in response to these comments.
    One commenter stated that flow-computer testing will take 3 years 
to get approved. The BLM disagrees with this comment and did not make 
any changes to the rule. Assuming the manufacturers perform the testing 
in accordance with the requirements of this section and submit all 
required data to the PMT, the review process should be simple and fast.
    One commenter stated that the BLM should use uncertainty 
performance standards instead of requiring testing under this section. 
The BLM established uncertainty performance goals in Sec.  3175.30 of 
the proposed rule (Sec.  3175.31 in the final rule). However, the BLM 
does not believe that verifying the calculations done by EGM systems is 
an uncertainty issue. There is no reason that flow-computer software 
should not be able to accurately calculate the flow rate, volume, 
heating values, and other parameters, within a very small tolerance of 
the true values. If the flow-computer software calculates incorrect 
values, that miscalculation does not reflect uncertainty but bias, 
because the error in the EGM's software will systematically generate 
values that are too low (or too high). The BLM did not make any changes 
to the rule in response to this comment.
    Several comments stated that the BLM should have provided the 
reference software for review. The BLM did not provide the reference 
software for review because it has not yet been developed. The BLM 
intends to work with API in developing reference software that is 
acceptable to all parties. Because the BLM delayed the implementation 
of the flow-computer software requirements by 2 years, there will be 
time to establish reference software. The BLM did not make any changes 
to the rule in response to this comment.
    One commenter stated that there should be a process in place to 
avoid various companies having to test the same software. All software 
testing required under this section will be reviewed by the PMT. Once a 
software version is reviewed by the PMT and approved by the BLM, it 
will be posted on the BLM website and will be approved for use by 
anyone. This will avoid the potential for different

[[Page 81597]]

companies having to test the same software. The BLM did not make any 
changes to the rule in response to this comment.
    One commenter asked if a software version that is run in different 
flow computers would require separate tests for each flow computer 
under this section. The answer is yes. Because of the potential for 
software to run differently on different hardware platforms, the BLM 
will approve software versions that are specific to a make and model of 
flow computer on which it was tested. Although no changes to the intent 
of the final rule were made as a result of this comment, the BLM did 
add some language to both this section and to Sec.  3175.44 to clarify 
this intent.
Sec. 3175.141--General Requirements for Flow-Computer Software Testing
    The testing procedures in this section are based, in large part, on 
a testing protocol in API 21.1, Annex E. Section 3175.141(a) requires 
that all testing be done by an independent laboratory to avoid any real 
or perceived conflict of interest in the testing.
    Several commenters stated that the BLM should allow in-house 
testing of flow-computer software under this section. The BLM disagrees 
with these comments because independent testing prevents any real or 
perceived conflict of interest between the manufacturer and the testing 
process and it is in the public interest. The BLM is allowing in-house 
testing of transducers (Sec.  3175.131(a)) only because transducer 
testing requires highly specialized equipment that only manufacturers 
are likely to have and requiring transducer testing at an independent 
qualified test facility could create an economic burden and delays. 
However, flow-computer software testing does not require highly 
specialized equipment and can readily be done by many testing 
facilities. Because the commenters did not provide any compelling 
arguments as to why independent testing of flow-computer software is 
onerous, the BLM did not make any changes to the rule in response to 
these comments.
    Section 3175.141(b)(1) requires that each make, model, and software 
version tested must be identical to the software version installed at 
an FMP. Section 3175.141(b)(2) requires that each software version be 
given a unique identifier, which must be part of the display (see Sec.  
3175.101(b)(4)) and the configuration log (see Sec.  3175.104(b)(2)) to 
allow the BLM to verify that the software version has been tested under 
the protocol in this section.
    One commenter asked how the BLM would handle software versions that 
do not require testing under this section. For example, if the 
manufacturer of an EGM system installs a new version of software that 
does not need to be tested under this section, the commenter asked how 
this version of the software would get on the approved software list. 
Although the details of this process will be resolved within the 2-year 
implementation timeframe that is part of the final rule (see Sec.  
3175.60(a)(4) and (b)(1)(iv)), the BLM added a phrase to Sec.  
3175.44(b)(2) that states that the operator or manufacturer must 
provide the BLM with a list of the software versions that do not 
require testing, along with a brief description of what changes were 
made from the previous version. If the PMT agrees, the PMT will confirm 
that the changes described by the manufacturer do not require testing, 
and then add the software version to the list of approved software 
versions.
    One commenter asked who would determine whether a version of 
software needs to be tested under this section. The BLM will have to 
rely on the manufacturer to make that determination, although the 
process described in the previous paragraph will allow the PMT to 
verify that the software version did not need to be tested. The BLM did 
not make any changes to the rule in response to this comment.
    Section 3175.141(c) provides that input variables may be either 
applied directly to the hardware registers or applied physically to a 
transducer. In the latter event, the values received by the hardware 
register from the transducer (which are subject to some uncertainty) 
must be recorded. The BLM did not receive any comments on this section.
    Section 3175.141(d) establishes a pass-fail criterion for the 
software testing. The digital values obtained for the testing in 
Sec. Sec.  3175.142 and 3175.143 are entered into BLM-approved 
reference software, and the resulting values of flow rate, volume, 
integral value, flow time, and averages of the live input variables are 
compared to the values determined from the software under test. A 
maximum allowable error of 50 parts per million (0.005 percent) is 
established in Sec.  3175.141(d)(2). The BLM did not receive any 
comments on this section.
Sec. 3175.142--Required Static Tests
    Section 3175.142(a) sets out six required tests to ensure that the 
instantaneous flow rate is being properly calculated by the flow 
computer. The parameters for each of the six tests set out in Tables 1 
and 2 to Sec.  3175.142 are designed to test various aspects of the 
calculations, including supercompressibility, gas expansion, and 
discharge coefficient over a range of conditions that could be 
encountered in the field. The BLM did not receive any comments on this 
section.
    Section 3175.142(b) tests the ability of the software to accurately 
accumulate volume, integral value, and flow time, and calculate average 
values of the live input variables over a period of time with fixed 
inputs applied. The BLM did not receive any comments on this section.
    Section 3175.142(c) of the final rule requires that additional 
tests be performed that assess the ability of the event log to capture 
all required events, and the software's ability to handle inputs to a 
transducer that are beyond its calibrated span. Proposed Sec.  
3175.142(c)(3) would have required testing the ability of the software 
to record the length of any power outage that inhibited the computer's 
ability to collect and store live data. Based on comments received 
under Sec.  3175.104(c)(1), the BLM eliminated the need for the event 
log to retain a record of all power outages that inhibit the meter's 
ability to collect and store new data. Therefore, the BLM removed the 
provision in this paragraph that would have required testing of this 
event-logging feature.
Sec. 3175.143--Required Dynamic Tests
    Section 3175.143 establishes required dynamic tests that test the 
ability of the software to accurately calculate volume, integral value, 
flow time, and averages of the live input variables under dynamic 
flowing conditions. The tests are designed to simulate extreme flowing 
conditions and include a square wave test, a sawtooth test, a random 
test, and a long-term volume accumulation test. A square wave test 
applies an input instantaneously, holds that input constant for a 
period of time and then returns the input to zero instantaneously. A 
sawtooth test increases an input over time until it reaches a maximum 
value, and then decreases that input over time until it reaches zero. A 
random test applies inputs randomly. The BLM did not receive any 
comments on this section.
Sec. 3175.144--Flow-Computer Software Test Reporting
    After a software version has been tested under Sec. Sec.  3175.141 
through 3175.143, the PMT would review the results and make a 
recommendation to the BLM. If the BLM determines that the

[[Page 81598]]

test was successful, the BLM would approve the use of the software 
version and flow computer and would list the make and model of the flow 
computer, along with the software version tested, on the BLM website 
(see Sec.  3175.44).
Sec. 3175.150--Immediate Assessments
    Section 3175.150 identifies violations that are subject to 
immediate assessments. The BLM received several comments in response to 
the proposed immediate assessments in Sec.  3175.150. The commenters 
stated that the immediate assessments were not necessary and 
duplicative in that an operator could receive an assessment and, 
potentially, a civil penalty for the same infraction. The commenters 
further stated that there was an absence of due process in that these 
immediate assessments were based on ``non-transparent rules'' and a BLM 
internal Inspection and Enforcement Handbook, which has not yet been 
developed (See discussion of Inspection and Enforcement Handbook in 
section II.B of this preamble--General Overview of Comments Received). 
The commenter suggested that the proposed rule required perfection from 
the operators on items that are performed a thousand times a day. A few 
commenters suggested breaking the immediate assessment into a major and 
minor category with a $1,000 assessment for major violations and $250 
for minor violations.
    As discussed in the preamble to the proposed rule, the immediate 
assessments provided for in Sec.  3175.150 are promulgated pursuant to 
the Secretary of the Interior's general rulemaking authority under the 
MLA (30 U.S.C. 189), as well as her specific authority to stipulate 
remedies for the breach of lease obligations (30 U.S.C. 188(a)). See 80 
FR 61646, 61680 (Oct. 13, 2015).
    Some commenters argued that the immediate assessments in Sec.  
3175.150 are 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 oil and gas operating 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. These leases incorporate the operating regulations by 
reference. Thus, the immediate assessments contained in the regulations 
act as ``liquidated damages'' owed by operators who 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.
    Several commenters argued that the proposed revision of Sec.  
3175.150 exceeded the BLM's statutory authority under FOGRMA insofar as 
the proposed revision sought to impose immediate assessments on 
purchasers and transporters. Upon further review and analysis of FOGRMA 
and other authorities, the BLM has been persuaded to remove the 
immediate assessments on purchasers and transporters from the final 
rule.
    One commenter stated that operators should be provided with a 1-
year phase-in period before they could be assessed for violations. The 
BLM agrees with this comment, but did not make any changes because the 
phase-in periods given in Sec.  3175.60 also applies to immediate 
assessments. The shortest phase-in period is 1 year for high- and very-
high-volume FMPs, which is the same phase-in period requested by the 
commenter.
    Some commenters asked that the final rule allow for administrative 
review of immediate assessments. The BLM always envisioned that 
immediate assessments would be subject to administrative review 
pursuant to 43 CFR 3170.8.
    The BLM sought comment on whether the immediate assessments in 
proposed Sec.  3175.150 should be higher or lower and what other 
factors the BLM should consider in setting these assessments. (See 80 
FR 61646, 61680 (Oct. 13, 2015)). The BLM noted that it proposed 
assessment amounts that approximate the average cost to the agency of 
identifying and remediating the violations. Some commenters argued that 
the assessments should be increased to $15,000 per violation per day--a 
punitive amount that would deter noncompliance. However, as liquidated 
damages, these assessments should not be punitive; rather, these 
assessments should be designed to reasonably compensate the BLM for 
damages associated with the violations. (See 80 FR 61646, 61680 (Oct. 
13, 2015), quoting 52 FR 5384, 5387 (Feb. 20, 1987)). Because the BLM 
is not persuaded that the proposed assessment amounts were 
inappropriate, the BLM has chosen to retain the proposed assessment 
amounts in the final rule.
Miscellaneous Changes to Other BLM Regulations in 43 CFR Part 3160
    As noted at the beginning of the Section-by-Section discussion of 
this preamble, this final rule also makes changes to certain provisions 
of 43 CFR part 3160. Specifically, the final rule makes changes to 43 
CFR 3162.7-3, 3163.1, and 3164.1. While some of these changes have 
already been discussed in connection with other provisions of the final 
rule to which they relate, each one is also explained below.
    1. Consistent with the proposed rule, the final rule revises Sec.  
3162.7-3, Measurement of gas, to reflect the fact that the standards 
governing oil and gas measurement are now found in subpart 3175.
    2. Section 3163.1, Remedies for acts of noncompliance, is being 
revised, consistent with the proposed rule, in several respects. As 
explained in connection with Sec.  3175.150 of this final rule, the 
BLM's existing regulations contain provisions authorizing the BLM to 
impose assessments on operators and operating rights owners for 
violations of lease terms and conditions or any other applicable law. 
These assessments are a form of liquidated damages designed to capture 
the costs incurred by the BLM in identifying and responding to the 
violations. These assessments are not intended to be punitive and are 
distinct from any civil penalties or other remedies that may be sought 
in connection with any particular violation.
    The existing regulations establish two categories of assessments. 
There is a general category, which authorizes assessments for major and 
minor violations. Those assessments may be imposed only after a written 
notice that provides a corrective or abatement period, subject to the 
limitations in existing paragraph (c) of Sec.  3163.1. As explained in 
the preamble to the proposed rule and with respect to Sec.  3175.150 of 
the final rule, there are also currently four specific violations where 
the BLM's existing rules authorize the imposition of immediate 
assessments. Through this final rule, the BLM is modifying the approach 
to assessments in its regulations.
    Rather than having certain specific violations be subject to 
immediate assessments, while major and minor violations are only 
subject to assessments after notice and an opportunity to cure, this 
final rule revises Sec.  3163.1 so that all assessments under that 
section may be imposed immediately, consistent with the purpose of 
those assessments. As explained in the preamble to the proposed rule, 
the BLM believes that for these assessments, which represent liquidated 
damages rather than punitive fines, the notice and opportunity to cure 
provided for in existing regulations is

[[Page 81599]]

unnecessary and represents an inefficient allocation of the BLM's 
inspection resources. The BLM's regulations governing oil and gas 
operations are clear and provide operators and other parties with ample 
notice of their obligations. The BLM incurs inspection and enforcement 
costs every time an operator violates one of these regulations. The 
assessment merely compensates the BLM for those costs. Therefore, it is 
unnecessary to also provide an additional corrective or abatement 
period before imposing the assessment.
    In addition to better reflecting the purpose for which these 
assessments were established, this change will also result in 
administrative efficiencies. Under the current regulations, the BLM has 
to first identify a violation; then, if the violation identified is not 
one of the small number of violations currently subject to an immediate 
assessment, the BLM has to issue a notice identifying the violation and 
specifying a corrective period. The BLM then has to follow up and 
determine whether corrective actions have been taken in response to the 
notice before an assessment can be imposed. All of these steps cause 
the BLM to incur additional costs and commit additional inspection 
resources.
    Therefore, the final rule revises paragraphs (a)(1) and (2) to 
allow the BLM to impose fixed assessments of $1,000 on a per-violation, 
per-inspection basis for major violations, and $250 on a per-violation, 
per-inspection basis for minor violations. The revisions to paragraphs 
(a)(1) and (2) maintain the BLM's discretion to impose such assessments 
on a case-by-case basis. The revisions are also consistent with Sec.  
3175.150 because they increase the immediate assessment for major 
violations to $1,000, which is appropriate given the types of 
violations that would be considered major. These changes do not affect 
Sec.  3163.1(a)(3) through (6).
    In addition to revising the approach to assessments, this final 
rule also revises paragraph (a) to make it apply to ``any person.'' 
Under this final rule, the civil assessments under Sec.  3163.1 are no 
longer limited to operating rights owners and operators. This change 
enables the BLM to impose assessments directly on parties who contract 
with operating rights owners or operators to perform activities on 
Federal or Indian leases that violate applicable regulations, lease 
terms, notices, or orders in performing those activities, and thereby 
cause the agency to incur the costs to detect and remedy those 
violations. While the operating rights owner or operator is responsible 
for violations committed by contractors, and therefore is subject to 
assessments for the contractor's non-compliance, the contractors 
themselves are also obligated to comply with applicable regulations, 
lease terms, notices, and orders.
    The authority for these immediate assessments was discussed 
extensively in the preamble to the proposed rule in connection with 
proposed changes to Sec. Sec.  3163.1 and 3175.150 and is not restated 
here. As explained there, the immediate assessments provided for in 
Sec.  3163.1 are promulgated pursuant to the Secretary's general 
rulemaking authority under the MLA (30 U.S.C. 189), as well as her 
specific authority to stipulate remedies for the breach of lease 
obligations (30 U.S.C. 188(a)). See 80 FR 61646, 61680 (Oct. 13, 2015).
    Paragraph (b) in the current regulations identifies specific 
serious violations for which immediate assessments are imposed upon 
discovery without exception. These are: (1) Failure to install a 
blowout preventer or other equivalent well control equipment; (2) 
Drilling without approval or causing surface disturbance on Federal or 
Indian surface preliminary to drilling without approval; and (3) 
Failure to obtain approval of a plan for well abandonment prior to 
commencement of such operations. Since these assessments are already 
imposed immediately, paragraph (b)'s approach to these assessments is 
retained; however, the final rule does make two revisions to paragraph 
(b).
    First, it makes paragraph (b) consistent with the revised paragraph 
(a) and acknowledges that certain additional immediate assessments are 
identified in subparts 3173, 3174, and 3175.
    Second, paragraph (b) is revised to make the first two assessments 
found in paragraph (b) flat assessments of $1,000 on a per-violation, 
per-inspection basis, instead of the current framework, which 
contemplates an assessment of $500 per day up to a maximum cap of 
$5,000. As explained in connection with Sec.  3175.150, the BLM chose 
the $1,000 figure because it approximates the average cost to the 
agency to identify such violations. Section 3163.1(b)(3) is unchanged 
by this final rule.
    Since the final rule shifts from assessments that accrue on a daily 
basis to ones that can be assessed on a per-violation, per-inspection 
basis, the daily limitations imposed by existing paragraph (c) are no 
longer necessary. Therefore, the final rule deletes paragraph (c). 
Similarly, existing paragraph (d), which provides that continued 
noncompliance subjects the operating rights owner or operator to civil 
penalties under Sec.  3163.2 of this subpart, is also removed because 
the BLM determined that it was redundant and unnecessary. Continued 
noncompliance may subject a party to civil penalties under Sec.  3163.2 
and the statute that it implements (Section 109 of FOGRMA, 30 U.S.C. 
1719) regardless of whether the assessment regulation so provides. As a 
result of these specific changes, the current paragraph (e) is re-
designated as paragraph (c).
    As for Sec.  3175.150, some commenters asserted that the immediate 
assessments identified in the proposed rule were excessive, 
unnecessary, and duplicative in that an operator could receive an 
assessment and, potentially, a civil penalty under Sec.  3163.2 for the 
same infraction. Other commenters express concern that there is an 
absence of due process in that these immediate assessments would be 
based on ``non-transparent rules'' and a BLM Internal Inspection and 
Enforcement Handbook, which has not yet been developed. The commenter 
suggested that the proposed rule required perfection from the operators 
on items that are performed a thousand times a day.
    The BLM does not agree with these comments. The use of immediate 
assessments for breaches of the oil and gas operating 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. These leases incorporate the operating regulations by 
reference. Thus, the immediate assessments contained in the regulations 
act as ``liquidated damages'' owed by operators who 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.
    Another commenter expressed concern about the effect of this change 
on the BLM's workload and staffing. Still another commenter asked the 
BLM to provide an economic justification for the shift in approach with 
respect to immediate assessments and inspection and enforcement more 
generally. All of these concerns have already been addressed in this 
preamble in Section II(B)--General Overview of Comments Received.
    One commenter asserted that the BLM lacks authority over 
contractors. The BLM does not agree with this assertion. While the 
operating rights owner or

[[Page 81600]]

operator is responsible (and liable for penalties) for violations 
committed by contractors, the contractors are also themselves subject 
to the requirements of certain statutes and regulations. As a result, 
the BLM is revising its regulations governing both assessments and 
civil penalties to enable the BLM to hold contractors directly 
responsible for violations they commit. This change also better 
reflects the current practice with respect to oilfield operations.
    Some commenters asked that the final rule allow for administrative 
review of immediate assessments. The BLM always envisioned that 
immediate assessments would be subject to administrative review 
pursuant to 43 CFR 3170.8.
    Some commenters argued that the assessments should be increased to 
$15,000 per violation per day--a punitive amount that would deter 
noncompliance. However, as explained above, the purpose of these 
assessments is to approximate the average cost to the BLM of 
identifying and remediating violations. As liquidated damages, these 
assessments should not be punitive, but rather, should be designed to 
reasonably compensate the BLM for damages associated with the 
violations. (See 80 FR 61646, 61680 (Oct. 13, 2015), quoting 52 FR 
5384, 5387 (Feb. 20, 1987)). The BLM did not make any changes in 
response to these comments.
    3. Section 3164.1, Onshore Oil and Gas Orders, the table will be 
revised to remove the reference to Order 5 because this proposed rule 
would replace Order 5.

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 discuss 
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 
October 13, 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 and gas 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 and gas 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 with respect to Order 5, that:
     The BLM's gas measurement rules are generally outdate and 
do not reflect modern measurement technologies or practices;
     There were not sufficient goals/requirements related to 
gas sampling, BTU sampling and reporting, and orifice plate and meter 
tube inspections; and
     Some BLM State offices have issued their own guidance, 
which lacks a national perspective, creating the potential for 
inconsistent application of requirements.
    The final rule addresses these recommendations by specifically 
recognizing modern industry practices and measurement technologies with 
respect to each of these, while also updating relevant documentation 
and recordkeeping requirements in order to ensure that all production 
is properly accounted for.

IV. Procedural Matters

Executive Order 12866 and 13563, Regulatory Planning and Review

    E.O. 12866 provides that the Office of Information and Regulatory 
Affairs (OIRA) in the Office of Management and Budget will review all 
significant rules. OIRA has determined that this final rule is not 
significant because it will not have an annual effect on the economy of 
$100 million or more and does not raise novel legal or policy issues. 
E.O. 13563 reaffirms the principles of E.O. 12866 while calling for 
improvements in the nation's regulatory system so that it promotes 
predictability, reduces uncertainty, and uses the best, most 
innovative, and least burdensome tools for achieving regulatory ends. 
The E.O. 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. We have developed this rulemaking consistent with these 
requirements.

Regulatory Flexibility Act

    The BLM certifies that this final rule will not have a significant 
economic impact on a substantial number of small entities under the 
Regulatory Flexibility Act (5 U.S.C. 601 et seq.). The Small Business 
Administration (SBA) has developed size standards to define small 
entities, and those size standards can be found at 13 CFR 121.201. 
Small entities for crude petroleum and natural gas extraction (North 
American Industrial Classification System or NAICS code 211111) are 
defined by the SBA regulations as a business concern, including an 
individual proprietorship, partnership, limited liability company, or 
corporation, with fewer than 1,250 employees.
    U.S. Census data show that in 2013, of the 6,460 domestic firms 
involved in crude petroleum and natural gas extraction, 99 percent (or 
6,370) had fewer than 500 employees. This means that all or nearly all 
U.S. firms involved in crude petroleum and natural gas extraction in 
2013 fell within the SBA's size standard of fewer than 1,250 employees. 
Based on this national data, the preponderance of firms involved in 
developing oil and gas resources are small entities as defined by the 
SBA. As such, it appears a substantial number of small entities will be 
affected by the

[[Page 81601]]

final rule. Using the best available data, the BLM estimates there are 
approximately 3,700 lessees and operators conducting gas operations on 
Federal and Indian lands that could be affected by the final rule.
    In addition to determining whether a substantial number of small 
entities are likely to be affected by this rule, the BLM must also 
determine whether the rule is anticipated to have a significant 
economic impact on those small entities. On an ongoing basis, we 
estimate the changes will increase the regulated community's annual 
costs by about $12.1 million, or an average of about $3,300 per entity 
per year. There will also be an estimated $6.2 million, or $1,700 per 
entity per year, in additional royalty payments from operators to the 
BLM. However, these are considered transfer payments, and are thus not 
included in the estimate of the final rule's net economic impact. In 
addition to annual costs, there will be one-time costs associated with 
implementing the changes of as much as $23.3 million, or an average of 
approximately $6,300 per entity affected by the rule. These costs are 
phased in over a 3-year period, at an average cost of $7.8 million per 
year or $2,100 per entity per year. When these annualized one-time 
costs are combined with annual costs, industry's average annual cost is 
$19.9 million per year (or $5,400 per entity per year) for the first 
three years following enactment of the final rule, after which it 
experiences just the annual burden of $12.1 million or $3,300 per 
entity per year. For further information on these costs estimates, 
please see the Economic and Threshold Analysis prepared for this final 
rule.
    Recognizing that the SBA definition for a small business for a 
crude petroleum and natural gas extraction firm is one with fewer than 
1,250 employees, which represents a wide range of possible oil and gas 
producers, the BLM, as part of the Economic and Threshold Analysis 
conducted for this rulemaking, looked at income data for three 
different small-sized entities that currently hold Federal oil and gas 
leases that were issued in competitive lease sales. Using annual 
reports that these companies filed with the U.S. Securities and 
Exchange Commission for 2012, 2013, and 2014, the BLM concluded that 
the one-time costs and the annual ongoing costs will result in a 
reduction in the profit margins of these entities ranging from 0.0005 
percent to 0.5742 percent, with an average reduction of 0.0362 percent. 
Copies of the analysis can be obtained from the contact person listed 
above (see FOR FURTHER INFORMATION CONTACT).
    All of the provisions will apply to entities regardless of size. 
However, entities with the greatest activity (e.g., numerous FMPs) will 
likely experience the greatest increase in compliance costs.
    Based on the available information, we conclude that the rule will 
not have a significant impact on a substantial number of small 
entities. Therefore, a final Regulatory Flexibility Analysis is not 
required, and a Small Entity Compliance Guide is not required.

Small Business Regulatory Enforcement Fairness Act

    This 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.
    This final rule will update and replace the requirements of Order 5 
to ensure that gas produced from Federal and Indian oil and gas leases 
is accurately measured and accounted for. As explained in the Economic 
and Threshold Analysis, the rule will increase, by about $12.1 million 
annually ($3,300 per entity), the cost associated with the development 
and production of gas resources under Federal and Indian oil and gas 
leases, plus an estimated $6.2 million in increased royalty payments 
($1,700 per entity) to the BLM that are considered transfer payments 
with no net economic impact. There will also be a one-time cost 
estimated to be $23.3 million, phased in over a 3-year period ($6,300 
per entity). For the first 3 years following enactment of the final 
rule, annual plus annualized one-time cost average $19.9 million per 
year ($5,400 per entity). After the first 3 years, the estimated burden 
on industry is just the estimated annual cost of $12.1 million ($3,300 
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

    Under the Unfunded Mandates Reform Act (2 U.S.C. 1501 et seq.), we 
find that:
     This final rule will not ``significantly or uniquely'' 
affect small governments. A Small Government Agency Plan is 
unnecessary.
     This final rule will not include any Federal mandate that 
may result in the expenditure by State, local, and tribal governments, 
in the aggregate, or by the private sector, of $100 million or greater 
in any single year.
    The final rule is not a ``significant regulatory action'' under the 
Unfunded Mandates Reform Act. The changes in this final rule will not 
impose any requirements on any State or local governmental entity.

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

    This rule will not have significant takings implications as defined 
under E.O. 12630. Therefore, a takings implication assessment is not 
required. This rule revises the minimum standards for accurate 
measurement and proper reporting of gas produced from Federal and 
Indian leases, unit PAs, and CAs by providing an improved system for 
production accountability by operators and lessees. Gas production from 
Federal and Indian leases is subject to lease terms that expressly 
require that lease activities be conducted in compliance with 
applicable Federal laws and regulations. The implementation of this 
rule will not impose requirements or limitations on private property 
use or require dedications or exactions from owners of private 
property, and as such, the rule is not a governmental action capable of 
interfering with constitutionally protected property rights. Therefore, 
the rule will not cause a taking of private property or require further 
discussion of takings implications under this E.O.

Executive Order 13132, Federalism

    Under E.O. 13132, the BLM finds that the rule will not have 
significant Federalism implications. A Federalism assessment is not 
required. This rule will not change the role of or responsibilities 
among Federal, State, and local governmental entities. It does not 
relate to the structure and role of the States and would not have 
direct or substantive 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

[[Page 81602]]

operations on all Indian (except Osage Tribe) onshore oil and gas 
leases. Therefore, the final rule will affect Indian tribes. In 
conformance with the Secretary's policy on tribal consultation, the BLM 
invited more than 175 tribal entities to tribal consultation meetings 
both before the rule was proposed and during the public comment period 
on the proposed rule. The consultations were held in both pre-
publication and post-publication:
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, D.C. 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 as 
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 addition, some tribes expressed concern about the cost of 
performing detailed meter tube inspections, the proposed requirement 
for the location of the sample probe because it would be contrary to 
API specification, the requirement to report a dry heating value when 
water vapor is known to be present, and the cost and benefit of 
requiring sample cylinders to be sealed after they are cleaned. 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 only. That said, the BLM 
will continue to consult with tribes on measurement issues that impact 
them and their resources. The BLM did make changes to the rule based on 
these and other comments received by industry. In response to the 
concern over the cost of performing detailed meter tube inspections, 
the BLM eliminated the requirement to perform routine detailed meter-
tube inspections; these inspections will now only be triggered by a 
basic inspection that reveals the need to perform a detailed 
inspection. In addition, the detailed inspection will only be required 
on high- and very-high-volume FMPs under the final rule. The final rule 
also re-defined the thresholds separating low-, high-, and very-high-
volume FMPs, which reduced the estimated percentage of high- and very-
high-volume FMPs subject to detailed inspections from 22 percent under 
the proposed rule to 11 percent under the final rule.
    In response to concerns expressed over the proposed requirement for 
the location of the sample probe, the BLM eliminated the proposed 
requirement and reverted to placing the sample probe as required by API 
standards. The BLM did not make any changes to the requirement in the 
proposed rule to report heating value on a dry basis because industry 
did not submit any data that would justify an alternative. On the 
contrary, the data that the BLM did receive indicated that the 
assumption of water vapor saturation as the basis for heating value, 
suggested by one tribal member, would result in under reporting of 
heating value. In response to concerns over the costs and benefits of 
the proposed requirement to seal sample cylinders after cleaning, the 
BLM determined that it was not a feasible requirement and deleted it in 
the final rule.

Executive Order 12988, Civil Justice Reform

    Under E.O. 12988, we have determined that the rule will not unduly 
burden the judicial system and meets the requirements of Sections 3(a) 
and 3(b)(2) of the Order. We have reviewed the rule to eliminate 
drafting errors and ambiguity. It has been written to 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 rule will not 
impede facilitating cooperative conservation and takes appropriate 
account of the interests of persons with ownership or other legally 
recognized interests in land or other natural resources. The rulemaking 
process involved Federal, State, local and tribal governments, private 
for-profit and nonprofit institutions, other nongovernmental entities 
and individuals in the decision-making via the public comment process 
for the rule. The process ensured that the programs, projects, and 
activities are consistent with protecting public health and safety.

Paperwork Reduction Act

Overview
    The Paperwork Reduction Act (PRA) (44 U.S.C. 3501-3521) provides 
that an agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information, unless it displays a 
currently valid OMB control number. The PRA and OMB regulations (see 5 
CFR 1320.3(c) and (k)) provide that collections of information include 
requests and requirements that an individual, partnership, or 
corporation obtain information, and report it to a Federal agency.
    This final 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 1004-0210.
Summary
    Title: Measurement of Gas.
    Forms: None.
    OMB Control Number: 1004-0210.
    Description of Respondents: Holders of Federal and Indian (except 
Osage Tribe) oil and gas leases, operators, purchasers, transporters, 
any other person directly involved in producing, transporting, 
purchasing, or selling, including measuring, oil or gas through the 
point of royalty measurement or the point of first sale, and 
manufacturers of equipment or software used in measuring natural gas.
    Abstract: This rule updates the BLM's regulations pertaining to gas 
measurement, taking into account changes in the gas industry's 
measurement technologies and standards. The information collection 
activities in this rule will assist the BLM in ensuring the accurate 
measurement and proper reporting of all gas removed or sold from 
Federal and Indian (except Osage Tribe) leases, units, unit 
participating areas, and areas subject to communitization agreements, 
by providing a system for production accountability by operators, 
lessees, purchasers, and transporters.

[[Page 81603]]

    Frequency of Collection: On occasion, except for 43 CFR 3175.115 
and 3175.120, which require submission of gas analysis reports at 
frequencies that vary from monthly to annually.
    Obligation to Respond: Required to obtain or retain benefits.
    Estimated Annual and Annualized Responses: 276,797.
    Estimated Reporting and Recordkeeping ``Hour'' Burden: 77,950 
hours.
    Estimated Non-Hour Cost: $21,194,881in annual non-hour burdens for 
the first 3 years following the effective date of the final rule, and 
$19,495,765 in annual non-hour burdens after that.
Discussion of Information Collection Activities
    The information collection activities in the final rule are 
discussed below along with estimates of the annual burdens. Included in 
the burden estimates are the time for reviewing instructions, searching 
existing data sources, gathering and maintaining the data needed, and 
completing and reviewing each component of the proposed information 
collection requirements.
    Some of these information collection activities are usual and 
customary because they are required by gas sales contracts and/or 
industry standards. To the extent they are usual and customary, they 
are not ``burdens'' under the PRA (see 5 CFR 1320.3(b)(2)). To the 
extent these regulations increase the frequency of data gathering 
beyond what is usual and customary, or require more information than is 
usual and customary, the incremental burdens are included in the 
burdens disclosed here.
    Where these regulations require operators to maintain records and 
submit information at the request of the BLM (usually during production 
audits), the burdens of disclosure to the respondent and to the Federal 
Government are included in the estimated burdens for ``Required 
Recordkeeping and Records Submission'' for 43 CFR 3170.7, a regulation 
that is part of the rulemaking for site security (RIN 1004-AE15, 
control no. 1004-0207). The recordkeeping burdens are included among 
the information collection activities for this rule.
    The information collection activities in this rule can be organized 
in the following categories:
    A. Testing of Makes and Models of Gas-Measurement Equipment;
    B. Inspection and Verification; and
    C. Determining and Reporting Volumes, Heating Value, and Relative 
Density
    Each category is discussed below.

A. Testing of Makes and Models of Gas-Measurement Equipment or Software

    Some provisions in the final rule provide for the listing of 
approved makes and models of gas-measurement equipment or software at 
www.blm.gov. They also provide for procedures that operators or 
manufacturers may use to seek approval of other makes and models. The 
operator or manufacturer arranges for testing of the equipment or 
software by a qualified testing facility. The testing is accomplished 
by comparing the requested equipment or software with reference 
standards specified in the regulations. Next, the operator or 
manufacturer submits a report to the BLM's PMT. The PMT, which consists 
of BLM employees who are experts in oil and gas measurement, acts as a 
central advisory body for reviewing and approving devices and software 
not specifically addressed and approved in these regulations. The 
report must show the results of the testing, as well as descriptions of 
the test set-up and procedures, qualifications of the test facility, 
and uncertainty analyses.
    The PMT reviews the report, and then recommends that use of the 
device or software be approved, disapproved, or approved with 
conditions. Approval or approval with conditions by the PMT is a pre-
requisite for BLM approval of a device or software that is not included 
on a list of approved makes and models in the regulations. These 
information collection activities assist the BLM in ensuring that the 
equipment and software used in gas measurement are in compliance with 
the relevant performance standards.
    We estimate that a limited number of respondents will choose to 
seek approval of makes and models of equipment or software, and the 
frequency of such requests will be limited. For the most part, we 
anticipate one-time, start-up requests during the first 3 years after 
the effective date of the rule. We calculated cumulative burden 
estimates for these activities for the first 3 years after the 
effective date of the rule. We annualized these burden estimates for 
inclusion in the total estimated hour burdens of this rule.
    Most of these procedures begin when the operator or manufacturer 
arranges for testing of the equipment or software by a qualified 
testing facility. Because the qualified testing facility will generally 
be a contractor, and not employees of a respondent, we estimated non-
hour burdens for those procedures. The exception is the procedure for 
requesting approval of makes and models of transducers that are used 
before the effective date of this rule. For those makes and models, the 
final rule allows operators or manufacturers to submit existing test 
data in lieu of arranging for testing by a qualified testing facility. 
We estimate no non-hour burdens in those circumstances.
    The information collection activities within this category are:
    1. Transducers--Test Data Collection and Submission for Existing 
Makes and Models (43 CFR 3175.43 and 3175.130);
    2. Transducers--Test Data Collection and Submission for Future 
Makes and Models (43 CFR 3175.43 and 3175.130);
    3. Flow-Computer Software--Test Data Collection and Submission for 
Existing Makes and Models (43 CFR 3175.44 and 3175.140);
    4. Flow-Computer Software--Test Data Collection and Submission for 
Future Makes and Models (43 CFR 3175.44 and 3175.140);
    5. Isolating Flow Conditioners--Test Data Collection and Submission 
for Existing Makes and Models (43 CFR 3175.46);
    6. Differential Primary Devices Other than Flange-Tapped Orifice 
Plates--Test Data Collection and Submission for Existing Makes and 
Models (43 CFR 3175.47);
    7. Linear Measurement Devices--Test Data Collection and Submission 
for Existing Makes and Models (43 CFR 3175.48);
    8. Linear Measurement Devices--Test Data Collection and Submission 
for Future Makes and Models (43 CFR 3175.48);
    9. Accounting Systems--Test Data Collection and Submission for 
Existing Makes and Models (43 CFR 3175.49); and
    10. Accounting Systems--Test Data Collection and Submission for 
Future Makes and Models (43 CFR 3175.49).

B. Inspection and Verification

    Inspection and verification activities assist the BLM in ensuring 
that the equipment used to measure gas is in good working order. The 
information that is required in each ``inspection'' depends on what 
type of equipment must be examined. The information that is required in 
each ``verification'' is in accordance with the definition of that term 
at 43 CFR 3175.10(a): ``The amount of error in a differential pressure, 
static pressure, or temperature transducer or element by comparing the 
readings of the transducer or element with the

[[Page 81604]]

readings from a certified test device with known accuracy.''
    Virtually all gas contracts and industry standards require periodic 
removal and inspection of equipment that is used to measure and analyze 
the content of natural gas. To the extent these regulations increase 
the frequency of inspection beyond what is usual and customary, or 
require more information than is usual and customary, the incremental 
burdens are disclosed here. Where these regulations require operators 
to submit information at the request of the BLM (usually during 
production audits), the burdens to the respondent and to the Federal 
Government are included in the estimated burdens for ``Required 
Recordkeeping and Records Submission'' for 43 CFR 3170.7, a regulation 
that is part of the rulemaking for site security (RIN 1004-AE15, 
control no. 1004-0207).
    The information collection activities within this category are:
    1. Schedule of Basic Meter Tube Inspection (43 CFR 3175.80(h)(3));
    2. Basic Inspection of Meter Tubes--Data Collection and Submission 
(43 CFR 3175.80(h)(5));
    3. Detailed Inspection of Meter Tubes--Data Collection and 
Submission (43 CFR 3175.80(i) and (j));
    4. Request for Extension of Time for a Detailed Meter Tube 
Inspection (43 CFR 1375.80(i));
    5. Redundancy Verification Check for Electronic Gas Measurement 
Systems (43 CFR 3175.102(e)(2));
    6. Notification of Verification (43 CFR 3175.92(e) and 
3175.102(f));
    7. Sample Cylinder Cleaning--Documentation (43 CFR 3175.113(c)(3));
    8. Sample Separator Cleaning--Documentation (43 3175.113(d)(1));
    9. Evacuation and Pre-charge for the Helium Pop Method--
Documentation (43 CFR 3175.114(a)(2));
    10. O-ring and Lubricant Composition for the Floating Piston 
Method--Documentation (43 CFR 3175.114(a)(3));
    11. Schedule for Spot Sampling (43 CFR 3175.113(b));
    12. Submission of On-line Gas Chromatograph Specifications (43 CFR 
3175.117(c)); and
    13. Gas Chromatograph Verification--Documentation (43 CFR 
3175.118(d)).

C. Determining and Reporting Volumes, Heating Value, and Relative 
Density

    Natural gas consists mainly of methane and also includes varying 
amounts of other hydrocarbons, nitrogen, and carbon dioxide. These 
regulations assist in determining what components are in samples of 
natural gas, and in what percentages. They also assist in determining 
the volumes of natural gas produced. These measurements are necessary 
for calculating royalties accurately.
    The information collection activities within this category are:
    1. Quantity Transaction Record (43 CFR 3175.104(a));
    2. Configuration Log (43 CFR 3175.104(b)); and
    3. Gas Analysis Report--Entry Into Gas Analysis Reporting and 
Verification System (43 CFR 3175.120(f)).
Burden Estimates
    The BLM estimates 276,797 responses, 77,950 hours, and $5,030,088 
hour burdens annually for industry for the first three years after the 
rule is enacted and 276,720 responses, 76,340 hours, and $4,926,201 
hour burdens annually for industry after that. These estimates include 
both annual estimates of recurring burdens and one-time burdens for 
initial implementation of the rule. The one-time burdens are shown as 
the average of the total burdens divided by three (i.e., spread over 
the next three years).
    The burdens to respondents include time spent for compiling and 
preparing information. The frequency of response for each of the 
information collections is ``on occasion,'' with the exception of 43 
CFR 3175.120, which requires submission of gas analysis reports to the 
BLM within 15 days following due dates for spot samples as specified in 
Sec.  3175.115:
     Gas spot samples at very-low-volume FMPs are required at 
least annually;
     Gas samples at low-volume FMPs are required at least every 
6 months, and
     Spot samples at high- and very-high-volume FMPs are 
required at least every 3 months and every month, respectively, unless 
the BLM determines that more frequent analysis is required under Sec.  
3175.115(c).
    The following table itemizes the hour burdens.

[[Page 81605]]

[GRAPHIC] [TIFF OMITTED] TR17NO16.050


[[Page 81606]]


[GRAPHIC] [TIFF OMITTED] TR17NO16.051


[[Page 81607]]


[GRAPHIC] [TIFF OMITTED] TR17NO16.052

National Environmental Policy Act
    The BLM prepared an environmental assessment (EA), a Finding of No 
Significant Impact (FONSI), and a Decision Record (DR) that concludes 
that the final rule will not constitute a major Federal action 
significantly affecting the quality of the human environment under 
Section 102(2)(C) of the National Environmental Policy Act (NEPA), 42 
U.S.C. 4332(2)(C). Therefore, a detailed statement under NEPA is not 
required. Copies of the EA, FONSI, and DR are available for review and 
on file in the BLM Administrative Record at the address specified in 
the ADDRESSES section.
    As explained in the EA, FONSI, and DR, the final rule will 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 final 
rule clarifies the acceptable methods for estimating and documenting 
reported volumes of gas when metering equipment is malfunctioning or 
out of service. The final rule also establishes new

[[Page 81608]]

requirements for gas sampling, including sampling location and methods, 
sampling frequency, analysis methods, and the minimum number of 
components to be analyzed. Similarly, the final rule establishes new 
meter equipment, maintenance, inspection, and reporting standards. 
These changes will enhance the agency's ability to account for the gas 
produced from Federal and Indian lands, but should have minimal to no 
impact on the environment.
    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 the 
impacts of three separate rulemakings, stating CEQ regulations that 
require connected actions to be evaluated in a single document. These 
commenters suggested that the BLM should prepare a single EIS to 
address all three rules.
    The BLM did not make any changes in response to these comments. 
CEQ's NEPA regulations at 40 CFR 1508.18 do identify new or revised 
agency rules and regulations as an example of a Federal action, but new 
agency regulations that are procedural or administrative in nature are 
categorically excluded from NEPA review pursuant to 43 CFR 46.210(i). 
Nevertheless the BLM chose to complete an EA for the rule, to assess 
the potential environmental impacts of the few provisions that could 
result in on-the-ground changes to measurement facilities. As noted in 
the EA, the BLM concludes that those few provisions will not have a 
significant impact on the environment.
    With respect to whether the three rulemakings to replace BLM's 
existing Onshore Orders 3, 4, and 5 are connected actions for purposes 
of NEPA, the BLM does not agree with the commenter's suggestion. While 
the BLM acknowledges that the rules are related and have been designed 
to work together, each rule is an independent and freestanding effort; 
none of the rules automatically triggers other actions that may impact 
the environment; none of the rules requires for its implementation that 
other actions be taken previously or simultaneously; and none depends 
on a larger action for its justification. Thus, the BLM reasonably 
decided to go forward with three EAs rather than a single overarching 
EIS.
    With respect to economic impacts, the BLM has determined that the 
economic analysis referred to in this preamble and in the EA prepared 
for this rule adequately discloses that the rule will increase costs to 
operator, but that those increased costs will be small compared to the 
costs of operating an oil and gas well. Therefore, the BLM did not make 
any changes in response to that comments.
    Other commenters stated the BLM did not adequately address 
potential surface impacts to private land, did not minimize surface 
impacts, did not address a reasonable range of alternatives, and did 
not adequately describe the Affected Environment. The BLM did not make 
any changes in response to these comments. The BLM anticipates that in 
the majority of cases, operators will use existing surface disturbances 
to come into compliance with the final rule, such as using existing 
well pad locations. Use of existing disturbance will minimize new 
surface construction and surface impacts. Since any new facilities will 
likely be constructed, relocated, or retrofitted on lease at an 
existing facility, the likelihood that the regulations will result in 
new impacts to private surface is low. In the rare instance new 
pipelines or other facilities prove to be necessary on private surface, 
BLM authorization for activities on split estate will include site-
specific NEPA documentation, with appropriate project-level mitigation 
and best management practices. In short, surface disturbance on private 
lands is likely to be minimal, and any attempt to estimate these 
impacts at this time would be speculative.
    Finally, commenters asserted that BLM did not satisfy its 
obligation under NEPA 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 are anticipated to be minimal. The EA, FONSI, and DR 
were updated to address these comments, but the revisions 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

    This final rule will not have a significant adverse effect on the 
nation's energy supply, distribution or use, including a shortfall in 
supply or price increase. Changes in this final rule will strengthen 
the BLM's accountability requirements for operators under Federal and 
Indian oil and gas leases. As discussed above, these changes will 
prescribe specific requirements for production measurement, including 
sampling, measuring, and analysis protocol; categories of violations; 
and reporting requirements. The final rule also establishes specific 
requirements related to the physical makeup of meter components. All of 
the changes will increase the regulated community's annual costs by 
about $19.9 million in annual and annualized one-time costs (or $5,400 
per entity per year) for the first 3 years after the final rule is 
enacted, and then $12.1 million, or an average of approximately $3,300 
per entity per year after that plus an additional $6.2 million in 
royalty payments from industry to the BLM that are considered a 
transfer payment and thus not a net economic impact. Entities with the 
greatest activity (e.g., numerous FMPs) will incur higher costs. 
Additional information on these costs estimates can be found in the 
Economic and Threshold Analysis prepared for this final rule.
    We expect that the final rule will not result in a net change in 
the quantity of oil and gas that is produced from oil and gas leases on 
Federal and Indian lands.
Information Quality Act
    In developing this rule, we did not conduct or use a study, 
experiment, or survey requiring peer review under the Information 
Quality Act (Pub. L. No. 106-554, Appendix C Title IV, Section 515, 114 
Stat. 2763A-153).
Authors
    The principal authors of this rule are Richard Estabrook, Petroleum 
Engineer, BLM Washington Office; Rodney Brashear, Petroleum Engineer 
Technician, BLM Tres Rios Field Office; Jim Hutchinson, Assistant Field 
Manager, BLM Newcastle Field Office; Jeff Jette, Petroleum Engineering 
Technician, BLM Buffalo Field Office; Clifford Johnson of the BLM 
Vernal Field Office; Gary Roth, Petroleum Engineering Technician, BLM 
Buffalo Field Office; and Noell Sturdevant, I&E Coordinator, BLM New 
Mexico State Office. The team was assisted by

[[Page 81609]]

Michael Wade, BLM Washington Office; Faith Bremner, Jean Sonneman, Joe 
Berry 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; John Barder, 
ONRR Denver Officer; Dylan Fuge, Counselor to the Director, BLM; 
Christopher Rhymes, Attorney Advisor, Office of the Solicitor, 
Department of the Interior; and Wanda Weatherford (formerly with BLM) 
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 exploration, Oil and gas measurement, Penalties; 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 is revised 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.  3162.7-3 to read as follows:


Sec.  3162.7-3   Measurement of gas.

    All gas removed or sold from a lease, communitized area, or unit 
participating area must be measured under subpart 3175 of this chapter. 
All measurement must be on the lease, communitized area, or unit from 
which the gas originated and must not be commingled with gas 
originating from other sources unless approved by the authorized 
officer under subpart 3173 of this chapter.

0
3. Amend Sec.  3163.1 by revising paragraphs (a) introductory text, 
(a)(1) and (2), (b) introductory text, (b)(1) and (2), removing 
paragraphs (c) and (d), redesignating paragraph (e) as paragraph (c), 
and revising newly redesignated paragraph (c) to read as follows:


Sec.  3163.1   Remedies for acts of noncompliance.

    (a) Whenever any person fails or refuses to comply with the 
regulations in this part, the terms of any lease or permit, or the 
requirements of any notice or order, the authorized officer shall 
notify that person in writing of the violation or default.
    (1) For major violations, the authorized officer may also subject 
the person to an assessment of $1,000 per violation, per inspection.
    (2) For minor violations, the authorized officer may also subject 
the person to an assessment of $250 per violation, per inspection.
* * * * *
    (b) Certain instances of noncompliance are violations of such a 
nature as to warrant the imposition of immediate major assessments upon 
discovery, as compared to those established by paragraph (a) of this 
section. Upon discovery the following violations, as well as the 
violations identified in subparts 3173, 3174, and 3175 of this chapter, 
will result in assessments in the specified amounts per violation, per 
inspection, without exception:
    (1) For failure to install blowout preventer or other equivalent 
well control equipment, as required by the approved drilling plan, 
$1,000;
    (2) For drilling without approval or for causing surface 
disturbance on Federal or Indian surface preliminary to drilling 
without approval, $1,000;
* * * * *
    (c) On a case-by-case basis, the State Director may compromise or 
reduce assessments under this section. In compromising or reducing the 
amount of the assessment, the State Director will state in the record 
the reasons for such determination.


Sec.  3164.1   [Amended]

0
4. Amend Sec.  3164.1, in paragraph (b), by removing the fifth entry in 
the chart.

PART 3170--ONSHORE OIL AND GAS PRODUCTION

0
5. 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
6. Add subpart 3175 to part 3170 to read as follows:
Subpart 3175--Measurement of Gas
Sec.
3175.10 Definitions and acronyms.
3175.20 General requirements.
3175.30 Incorporation by reference.
3175.31 Specific performance requirements.
3175.40 Measurement equipment approved by standard or make and 
model.
3175.41 Flange-tapped orifice plates.
3175.42 Chart recorders.
3175.43 Transducers.
3175.44 Flow-computer software.
3175.45 Gas chromatographs.
3175.46 Isolating flow conditioners.
3175.47 Differential primary devices other than flange-tapped 
orifice plates.
3175.48 Linear measurement devices.
3175.49 Accounting systems.
3175.60 Timeframes for compliance.
3175.61 Grandfathering.
3175.70 Measurement location.
3175.80 Flange-tapped orifice plates (primary devices).
3175.90 Mechanical recorder (secondary device).
3175.91 Installation and operation of mechanical recorders.
3175.92 Verification and calibration of mechanical recorders.
3175.93 Integration statements.
3175.94 Volume determination.
3175.100 Electronic gas measurement (secondary and tertiary device).
3175.101 Installation and operation of electronic gas measurement 
systems.
3175.102 Verification and calibration of electronic gas measurement 
systems.
3175.103 Flow rate, volume, and average value calculation.
3175.104 Logs and records.
3175.110 Gas sampling and analysis.
3175.111 General sampling requirements.
3175.112 Sampling probe and tubing.
3175.113 Spot samples--general requirements.
3175.114 Spot samples--allowable methods.
3175.115 Spot samples--frequency.
3175.116 Composite sampling methods.
3175.117 On-line gas chromatographs.
3175.118 Gas chromatograph requirements.
3175.119 Components to analyze.
3175.120 Gas analysis report requirements.
3175.121 Effective date of a spot or composite gas sample.
3175.125 Calculation of heating value and volume.
3175.126 Reporting of heating value and volume.
3175.130 Transducer testing protocol.
3175.131 General requirements for transducer testing.
3175.132 Testing of reference accuracy.
3175.133 Testing of influence effects.
3175.134 Transducer test reporting.
3175.135 Uncertainty determination.
3175.140 Flow-computer software testing.
3175.141 General requirements for flow-computer software testing.
3175.142 Required static tests.
3175.143 Required dynamic tests.
3175.144 Flow-computer software test reporting.

[[Page 81610]]

3175.150 Immediate assessments.
Appendix A to Subpart 3175--Table of Atmospheric Pressures


Sec.  3175.10   Definitions and acronyms.

    (a) As used in this subpart, the term:
    AGA Report No. (followed by a number) means a standard prescribed 
by the American Gas Association, with the number referring to the 
specific standard.
    Area ratio means the smallest unrestricted area at the primary 
device divided by the cross-sectional area of the meter tube. For 
example, the area ratio (Ar) of an orifice plate is the area 
of the orifice bore (Ad) divided by the area of the meter 
tube (AD). For an orifice plate with a bore diameter (d) of 
1.000 inches in a meter tube with an inside diameter (D) of 2.000 
inches the area ratio is 0.25 and is calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR17NO16.053

    As-found means the reading of a mechanical or electronic transducer 
when compared to a certified test device, prior to making any 
adjustments to the transducer.
    As-left means the reading of a mechanical or electronic transducer 
when compared to a certified test device, after making adjustments to 
the transducer, but prior to returning the transducer to service.
    Atmospheric pressure means the pressure exerted by the weight of 
the atmosphere at a specific location.
    Beta ratio means the measured diameter of the orifice bore divided 
by the measured inside diameter of the meter tube. This is also 
referred to as a diameter ratio.
    Bias means a systematic shift in the mean value of a set of 
measurements away from the true value of what is being measured.
    British thermal unit (Btu) means the amount of heat needed to raise 
the temperature of one pound of water by 1 [deg]F.
    Component-type electronic gas measurement system means an 
electronic gas measurement system comprising transducers and a flow 
computer, each identified by a separate make and model, from which 
performance specifications are obtained.
    Configuration log means a list of all fixed or user-programmable 
parameters used by the flow computer that could affect the calculation 
or verification of flow rate, volume, or heating value.
    Discharge coefficient means an empirically derived correction 
factor that is applied to the theoretical differential flow equation in 
order to calculate a flow rate that is within stated uncertainty 
limits.
    Effective date of a spot or composite gas sample means the first 
day on which the relative density and heating value determined from the 
sample are used in calculating the volume and quality on which royalty 
is based.
    Electronic gas measurement (EGM) means all of the hardware and 
software necessary to convert the static pressure, differential 
pressure, and flowing temperature developed as part of a primary 
device, to a quantity, rate, or quality measurement that is used to 
determine Federal royalty. For orifice meters, this includes the 
differential-pressure transducer, static-pressure transducer, flowing-
temperature transducer, on-line gas chromatograph (if used), flow 
computer, display, memory, and any internal or external processes used 
to edit and present the data or values measured.
    Element range means the difference between the minimum and maximum 
value that the element (differential-pressure bellows, static-pressure 
element, and temperature element) of a mechanical recorder is designed 
to measure.
    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.
    GPA (followed by a number) means a standard prescribed by the Gas 
Processors Association, with the number referring to the specific 
standard.
    Heating value means the gross heat energy released by the complete 
combustion of one standard cubic foot of gas at 14.73 pounds per square 
inch absolute (psia) and 60[deg] F.
    Heating value variability means the deviation of previous heating 
values over a given time period from the average heating value over 
that same time period, calculated at a 95 percent confidence level. 
Unless otherwise approved by the BLM, variability is determined with 
the following equation:
[GRAPHIC] [TIFF OMITTED] TR17NO16.054

Where:

V95 = heating value variability, %
[sigma]HV = standard deviation of the previous 5 heating 
values
2.776 = the ``student-t'' function for a probability of 0.05 and 4 
degrees of freedom (degree of freedom is the number of samples minus 
1)
HV= the average heating value over the time period used to determine 
the standard deviation

    High-volume facility measurement point or high-volume FMP means any 
FMP that measures more than 200 Mcf/day, but less than or equal to 
1,000 Mcf/day over the averaging period.
    Hydrocarbon dew point means the temperature at which hydrocarbon 
liquids begin to form within a gas mixture. For the purpose of this 
regulation, the hydrocarbon dew point is the flowing temperature of the 
gas measured at the FMP, unless otherwise approved by the AO.
    Integration means a process by which the lines on a circular chart 
(differential pressure, static pressure, and flowing temperature) used 
in conjunction with a mechanical chart recorder are re-traced or 
interpreted in order to determine the volume that is represented by the 
area under the lines. An integration statement documents the values 
determined from the integration.
    Live input variable means a datum that is automatically obtained in 
real time by an EGM system.
    Low-volume facility measurement point or low-volume FMP means any 
FMP that measures more than 35 Mcf/day, but less than or equal to 200 
Mcf/day, over the averaging period.
    Lower calibrated limit means the minimum engineering value for 
which a transducer was calibrated by certified equipment, either in the 
factory or in the field.

[[Page 81611]]

    Mean means the sum of all the values in a data set divided by the 
number of values in the data set.
    Mole percent means the number of molecules of a particular type 
that are present in a gas mixture divided by the total number of 
molecules in the gas mixture, expressed as a percentage.
    Normal flowing point means the differential pressure, static 
pressure, and flowing temperature at which an FMP normally operates 
when gas is flowing through it.
    Primary device means the volume-measurement equipment installed in 
a pipeline that creates a measureable and predictable pressure drop in 
response to the flow rate of fluid through the pipeline. It includes 
the pressure-drop device, device holder, pressure taps, required 
lengths of pipe upstream and downstream of the pressure-drop device, 
and any flow conditioners that may be used to establish a fully 
developed symmetrical flow profile.
    Qualified test facility means a facility with currently certified 
measurement systems for mass, length, time, temperature, and pressure 
traceable to the NIST primary standards or applicable international 
standards approved by the BLM.
    Quantity transaction record (QTR) means a report generated by an 
EGM system that summarizes the daily and hourly volumes calculated by 
the flow computer and the average or totals of the dynamic data that is 
used in the calculation of volume.
    Reynolds number means the ratio of the inertial forces to the 
viscous forces of the fluid flow, and is defined as:
[GRAPHIC] [TIFF OMITTED] TR17NO16.055

Where:

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

    Redundancy verification means a process of verifying the accuracy 
of an EGM system by comparing the readings of two sets of transducers 
placed on the same primary device.
    Secondary device means the differential-pressure, static-pressure, 
and temperature transducers in an EGM system, or a mechanical recorder, 
including the differential pressure, static pressure, and temperature 
elements, and the clock, pens, pen linkages, and circular chart.
    Self-contained EGM system means an EGM system in which the 
transducers and flow computer are identified by a single make and model 
number from which the performance specifications for the transducers 
and flow computer are obtained. Any change to the make or model numbers 
of either a transducer or a flow computer within a self-contained EGM 
system changes the system to a component-type EGM system.
    Senior fitting means a type of orifice plate holder that allows the 
orifice plate to be removed, inspected, and replaced without isolating 
and depressurizing the meter tube.
    Standard cubic foot (scf) means a cubic foot of gas at 14.73 psia 
and 60[deg] F.
    Standard deviation means a measure of the variation in a 
distribution, and is equal to the square root of the arithmetic mean of 
the squares of the deviations of each value in the distribution from 
the arithmetic mean of the distribution.
    Tertiary device means, for EGM systems, the flow computer and 
associated memory, calculation, and display functions.
    Threshold of significance means the maximum difference between two 
data sets (a and b) that can be attributed to uncertainty effects. The 
threshold of significance is determined as follows:
[GRAPHIC] [TIFF OMITTED] TR17NO16.056

Where:

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

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


Sec.  3175.20   General requirements.

    Measurement of all gas at an FMP must comply with the standards 
prescribed in this subpart, except as otherwise approved under Sec.  
3170.6 of this part.


Sec.  3175.30   Incorporation by reference.

    (a) Certain material identified 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; and at all BLM offices with jurisdiction over oil 
and gas activities; and is available from the sources listed

[[Page 81612]]

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 Gas Association (AGA), 400 North Capitol Street NW., 
Suite 450, Washington, DC 20001; telephone 202-824-7000.
    (1) AGA Report No. 3, Orifice Metering of Natural Gas and Other 
Related Hydrocarbon Fluids, Second Edition, September, 1985 (``AGA 
Report No. 3 (1985)''), IBR approved for Sec. Sec.  3175.61(a) and (b), 
3175.80(k), and 3175.94(a).
    (2) AGA Transmission Measurement Committee Report No. 8, 
Compressibility Factors of Natural Gas and Other Related Hydrocarbon 
Gases; Second Edition, November 1992 (``AGA Report No. 8''), IBR 
approved for Sec. Sec.  3175.103(a) and 3175.120(d).
    (c) American Petroleum Institute (API), 1220 L Street NW., 
Washington, DC 20005; telephone 202-682-8000. API also offers free, 
read-only access to some of the material at https://publications.api.org.
    (1) API Manual of Petroleum Measurement Standards (MPMS) Chapter 
14--Natural Gas Fluids Measurement, Section 1, Collecting and Handling 
of Natural Gas Samples for Custody Transfer; Seventh Edition, May 2016 
(``API 14.1''), IBR approved for Sec. Sec.  3175.112(b) and (c), 
3175.113(c), and 3175.114(b).
    (2) API MPMS, Chapter 14, Section 3, Orifice Metering of Natural 
Gas and Other Related Hydrocarbon Fluids--Concentric, Square-edged 
Orifice Meters, Part 1, General Equations and Uncertainty Guidelines; 
Fourth Edition, September 2012; Errata, July 2013 (``API 14.3.1''), IBR 
approved for Sec.  3175.31(a) and Table 1 to Sec.  3175.80.
    (3) API MPMS Chapter 14, Section 3, Orifice Metering of Natural Gas 
and Other Related Hydrocarbon Fluids--Concentric, Square-edged Orifice 
Meters, Part 2, Specification and Installation Requirements; Fifth 
Edition, March 2016 (``API 14.3.2''), IBR approved for Sec. Sec.  
3175.46(b) and (c), 3175.61(a), 3175.80(c) through (g) and (i) through 
(l), and Table 1 to Sec.  3175.80.
    (4) API MPMS Chapter 14, Section 3, Orifice Metering of Natural Gas 
and Other Related Hydrocarbon Fluids--Concentric, Square-edged Orifice 
Meters, Part 3, Natural Gas Applications; Fourth Edition, November 2013 
(``API 14.3.3''), IBR approved for Sec. Sec.  3175.94(a) and 
3175.103(a).
    (5) API MPMS Chapter 14, Natural Gas Fluids Measurement, Section 3, 
Concentric, Square-Edged Orifice Meters, Part 3, Natural Gas 
Applications, Third Edition, August, 1992 (``API 14.3.3 (1992)''), IBR 
approved for Sec.  3175.61(b).
    (6) API MPMS, Chapter 14, Section 5, Calculation of Gross Heating 
Value, Relative Density, Compressibility and Theoretical Hydrocarbon 
Liquid Content for Natural Gas Mixtures for Custody Transfer; Third 
Edition, January 2009; Reaffirmed February 2014 (``API 14.5''), IBR 
approved for Sec. Sec.  3175.120(c) and 3175.125(a).
    (7) API MPMS Chapter 21, Section 1, Flow Measurement Using 
Electronic Metering Systems--Electronic Gas Measurement; Second 
Edition, February 2013 (``API 21.1''), IBR approved for Table 1 to 
Sec.  3175.100, Sec. Sec.  3175.101(e), 3175.102(a) and (c) through 
(e), 3175.103(b) and (c), and 3175.104(a) through (d).
    (8) API MPMS Chapter 22--Testing Protocol, Section 2, Differential 
Pressure Flow Measurement Devices; First Edition, August 2005; 
Reaffirmed August 2012 (``API 22.2''), IBR approved for Sec.  
3175.47(b) through (d).
    (d) Gas Processors Association (GPA), 6526 E. 60th Street, Tulsa, 
OK 74145; telephone 918-493-3872.
    (1) GPA Standard 2166-05, Obtaining Natural Gas Samples for 
Analysis by Gas Chromatography Revised 2005 (``GPA 2166-05''), IBR 
approved for Sec. Sec.  3175.113(c) and (d), 3175.114(a), and 
3175.117(a).
    (2) GPA Standard 2261-13, Analysis for Natural Gas and Similar 
Gaseous Mixtures by Gas Chromatography; Revised 2013 (``GPA 2261-13''), 
IBR approved for Sec.  3175.118(a) and (c).
    (3) GPA Standard 2198-03, Selection, Preparation, Validation, Care 
and Storage of Natural Gas and Natural Gas Liquids Reference Standard 
Blends; Revised 2003 (``GPA 2198-03''), IBR approved for Sec.  
3175.118(c).
    (4) GPA Standard 2286-14, Method for the Extended Analysis of 
Natural Gas and Similar Gaseous Mixtures by Temperature Program Gas 
Chromatography; Revised 2014 (``GPA 2286-14''), IBR approved for Sec.  
3175.118(e).
    (e) Pipeline Research Council International (PRCI), 3141 Fairview 
Park Dr., Suite 525, Falls Church, VA 22042; telephone 703-205-1600.
    (1) PRCI Contract-NX-19, Manual for the Determination of 
Supercompressibility Factors for Natural Gas; December 1962 (``PRCI NX 
19''), IBR approved for Sec.  3175.61(b).
    (2) [Reserved]
    Note to paragraphs (b) through (e): You may also be able to 
purchase these standards from the following resellers: Techstreet, 3916 
Ranchero Drive, Ann Arbor, MI 48108; telephone 734-780-8000; 
www.techstreet.com/api/apigate.html; IHS Inc., 321 Inverness Drive 
South, Englewood, CO 80112; 303-790-0600; www.ihs.com; SAI Global, 610 
Winters Ave., Paramus, NJ 07652; telephone 201-986-1131; https://infostore.saiglobal.com/store/.


Sec.  3175.31   Specific performance requirements.

    (a) Flow rate measurement uncertainty levels. (1) For high-volume 
FMPs, the measuring equipment must achieve an overall flow rate 
measurement uncertainty within 3 percent.
    (2) For very-high-volume FMPs, the measuring equipment must achieve 
an overall flow rate measurement uncertainty within 2 
percent.
    (3) The determination of uncertainty is based on the values of 
flowing parameters (e.g., differential pressure, static pressure, and 
flowing temperature for differential meters or velocity, mass flow 
rate, or volumetric flow rate for linear meters) determined as follows, 
listed in order of priority:
    (i) The average flowing parameters listed on the most recent daily 
QTR, if available to the BLM at the time of uncertainty determination; 
or
    (ii) The average flowing parameters from the previous day, as 
required under Sec.  3175.101(b)(4)(i) through (iii) (for differential 
meters).
    (4) The uncertainty must be calculated under API 14.3.1, Section 12 
(incorporated by reference, see Sec.  3175.30) or other methods 
approved by the AO.
    (b) Heating value uncertainty levels. (1) For high-volume FMPs, the 
measuring equipment must achieve an annual average heating value 
uncertainty within 2 percent.
    (2) For very-high-volume FMPs, the measuring equipment must achieve 
an annual average heating value uncertainty within 1 
percent.
    (3) Unless otherwise approved by the AO, the average annual heating 
value uncertainty must be determined as follows:

[[Page 81613]]

[GRAPHIC] [TIFF OMITTED] TR17NO16.057

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


Sec.  3175.40   Measurement equipment approved by standard or make and 
model.

    The measurement equipment described in Sec. Sec.  3175.41 through 
3175.49 is approved for use at FMPs under the conditions and 
circumstances stated in those sections, provided it meets or exceeds 
the minimum standards prescribed in this subpart.


Sec.  3175.41   Flange-tapped orifice plates.

    Flange-tapped orifice plates that are constructed, installed, 
operated, and maintained in accordance with the standards in Sec.  
3175.80 are approved for use.


Sec.  3175.42   Chart recorders.

    Chart recorders used in conjunction with approved differential-type 
meters that are installed, operated, and maintained in accordance with 
the standards in Sec.  3175.90 are approved for use for low-volume and 
very-low-volume FMPs only, and are not approved for high-volume or 
very-high-volume FMPs.


Sec.  3175.43   Transducers.

    (a) A transducer of a specific make, model, and URL is approved for 
use in conjunction with differential meters for high-volume or very-
high-volume FMPs if it meets the following requirements:
    (1) It has been type-tested under Sec.  3175.130;
    (2) The documentation required in Sec.  3175.134 has been submitted 
to the PMT; and
    (3) It has been approved by the BLM and placed on the list of type-
tested equipment maintained at www/blm.gov.
    (b) A transducer of a specific make, model, and URL, in use at an 
FMP before January 17, 2017, is approved for continued use if:
    (1) Data supporting the published performance specification of the 
transducer are submitted to the PMT in lieu of the documentation 
required in paragraph (a)(2) of this section; and
    (2) It has been approved by the BLM and placed on the list of type-
tested equipment maintained at www.blm.gov.
    (c) All transducers are approved for use at very-low- and low-
volume FMPs.


Sec.  3175.44   Flow-computer software.

    (a) A flow computer of a particular make and model, and equipped 
with a particular software version, is approved for use at high- and 
very-high-volume FMPs if the flow computer and software version meet 
the following requirements:
    (1) The documentation required in Sec.  3175.144 has been submitted 
to the PMT;
    (2) The PMT has determined that the flow computer and software 
version passed the type-testing required in Sec.  3175.140, except as 
provided in paragraph (b) of this section; and
    (3) The BLM has approved the flow computer and software version and 
has placed them on the list of approved equipment maintained at 
www.blm.gov.
    (b) Software versions (high- and very-high-volume FMPs). (1) 
Software revisions that affect or have the potential to affect 
determination of flow rate, determination of volume, determination of 
heating value, or data or calculations used to verify flow rate, 
volume, or heating value must be type-tested under Sec.  3175.140.
    (2) Software revisions that do not affect or have the potential to 
affect the determination of flow rate, determination of volume, 
determination of heating value, or data and calculations used to verify 
flow rate, volume, or heating value are not required to be type-tested, 
however, the operator must provide the BLM with a list of these 
software versions and a brief description of what changes were made 
from the previous version. (The software manufacturer may provide such 
information instead of the operator.)
    (c) Software versions (low- and very-low-volume FMPs). All software 
versions are approved for use at low- and very-low-volume FMPs, unless 
otherwise required by the BLM.


Sec.  3175.45   Gas chromatographs.

    GCs that meet the standards in Sec. Sec.  3175.117 and 3175.118 for 
determining heating value and relative density are approved for use.


Sec.  3175.46   Isolating flow conditioners.

    The BLM will list on www.blm.gov the make, model, and size of 
isolating flow conditioner that is approved for use in conjunction with 
a flange-tapped orifice plate, so long as the isolating flow 
conditioner is installed, operated, and maintained in compliance with 
the requirements of this section. Approval of a particular make and 
model is obtained as prescribed in this section.
    (a) All testing required under this section must be performed at a 
qualified test facility not affiliated with the flow-conditioner 
manufacturer.
    (b) The operator or manufacturer must test the flow conditioner 
under API 14.3.2, Annex D (incorporated by reference, see Sec.  
3175.30) and submit all test data to the BLM.
    (c) The PMT will review the test data to ensure that the device 
meets the requirements of API 14.3.2, Annex D (incorporated by 
reference, see Sec.  3175.30) and make a recommendation

[[Page 81614]]

to the BLM to either approve use of the device, disapprove use of the 
device, or approve it with conditions for its use.
    (d) If approved, the BLM will add the approved make and model, and 
any applicable conditions of use, to the list maintained at 
www.blm.gov.


Sec.  3175.47   Differential primary devices other than flange-tapped 
orifice plates.

    A make, model, and size of differential primary device listed at 
www.blm.gov is approved for use if it is installed, operated, and 
maintained in compliance with any applicable conditions of use 
identified on www.blm.gov for that device. Approval of a particular 
make and model is obtained as follows:
    (a) All testing required under this section must be performed at a 
qualified test facility not affiliated with the primary device 
manufacturer.
    (b) The primary device must be tested under API 22.2 (incorporated 
by reference, see Sec.  3175.30).
    (c) The operator must submit to the BLM all test data required 
under API 22.2 (incorporated by reference, see Sec.  3175.30). (The 
manufacturer of the primary device may submit such information instead 
of the operator.)
    (d) The PMT will review the test data to ensure that the primary 
device meets the requirements of API 22.2 (incorporated by reference, 
see Sec.  3175.30) and Sec.  3175.31(c) and (d) and make a 
recommendation to the BLM to either approve use of the device, 
disapprove use of the device, or approve its use with conditions.
    (e) If the primary device is approved by the BLM, the BLM will add 
the approved make and model, and any applicable conditions of use, to 
the list maintained at www.blm.gov.


Sec.  3175.48   Linear measurement devices.

    A make, model, and size of linear measurement device listed at 
www.blm.gov is approved for use if it is installed, operated, and 
maintained in compliance with any conditions of use identified on 
www.blm.gov for that device. Approval of a particular make and model is 
obtained as follows:
    (a) The linear measurement device must be tested at a qualified 
test facility not affiliated with the linear-measurement-device 
manufacturer;
    (b) The operator or manufacturer must submit to the BLM all test 
data required by the PMT;
    (c) The PMT will review the test data to ensure that the linear 
measurement device meets the requirements of Sec.  3175.31(c) and (d) 
and make a recommendation to the BLM to either approve use of the 
device, disapprove use of the device, or approve its use with 
conditions; and
    (d) If the linear measurement device is approved, the BLM will add 
the approved make and model, and any applicable conditions of use, to 
the list maintained at www.blm.gov.


Sec.  3175.49   Accounting systems.

    An accounting system with a name and version listed at www.blm.gov 
is approved for use in reporting logs and records to the BLM. The 
approval is specific to those makes and models of flow computers for 
which testing demonstrates compatibility. Approval for a particular 
name and version of accounting system used with a particular make and 
model of flow computer is obtained as follows:
    (a) For daily QTRs (see Sec.  3175.104(a)), an operator or vendor 
must submit daily QTRs to the BLM both from the accounting system and 
directly from the flow computer for at least 6 consecutive monthly 
reporting periods;
    (b) For hourly QTRs (see Sec.  3175.104(a)), an operator must 
submit hourly QTRs to the BLM both from the accounting system and 
directly from the flow computer for at least 15 consecutive daily 
reporting periods. (A vendor may submit such information on behalf of 
an operator);
    (c) For configuration logs (see Sec.  3175.104(b)), an operator 
must submit at least 10 configuration logs to the BLM taken at random 
times covering a span of at least 6 months both from the accounting 
system and directly from the flow computer. (A vendor may submit such 
information on behalf of an operator);
    (d) For event logs (see Sec.  3175.104(c)), an operator must submit 
an event log to the BLM containing at least 50 events both from the 
accounting system and directly from the flow computer. (A vendor may 
submit such information on behalf of an operator);
    (e) For alarm logs (see Sec.  3175.104(d)), an operator must submit 
an alarm log to the BLM containing at least 50 alarm conditions both 
from the accounting system and directly from the flow computer (a 
vendor may submit such information on behalf of an operator);
    (f) The BLM may require additional tests and records that may be 
necessary to determine that the software meets the requirements of 
Sec.  3175.104(a);
    (g) The records retrieved directly from the flow computer in 
paragraphs (a) through (d) of this section must be unedited;
    (h) The records retrieved from the accounting system in paragraphs 
(a) through (d) must include both edited and unedited versions; and
    (i) The BLM will approve the accounting system name and version for 
use with the make and model of flow computer used for comparison, and 
add the system name and version to the list of approved systems 
maintained at www.blm.gov if:
    (1) The BLM compares the records retrieved directly from the flow 
computer with the unedited records from the accounting system and there 
are no significant discrepancies; and
    (2) The BLM compares the records retrieved directly from the flow 
computer with the edited records from the accounting system and all 
changes are clearly indicated, the reason for each change is indicated 
or is available upon request, and the edited version is clearly 
distinguishable from the unedited version.


Sec.  3175.60   Timeframes for compliance.

    (a) New FMPs. (1) Except as allowed in paragraphs (a)(2) through 
(4) of this section, the measuring procedures and equipment installed 
at any FMP on or after January 17, 2017 must comply with all of the 
requirements of this subpart upon installation.
    (2) The gas analysis reporting requirements of Sec.  3175.120(e) 
and (f) will begin on January 17, 2019.
    (3) High- and very-high-volume FMPs must comply with the sampling 
frequency requirements of Sec.  3175.115(b) starting on January 17, 
2019. Between January 17, 2017 and January 17, 2019, the initial 
sampling frequencies required at high- and very-high-volume FMPs are 
those listed in Table 1 to Sec.  3175.110.
    (4) Equipment approvals required in Sec. Sec.  3175.43, 3175.44, 
and 3175.46 through 3175.49 will be required after January 17, 2019.
    (b) Existing FMPs. (1) Except as allowed in Sec.  3175.61, 
measuring procedures and equipment at any FMP in place before January 
17, 2017 must comply with the requirements of this subpart within the 
timeframes specified in this paragraph (b).
    (2) High- and very-high-volume FMPs must comply with:
    (i) All of the requirements of this subpart except as specified in 
paragraphs (b)(2)(ii) and (iii) of this section by January 17, 2018;
    (ii) The gas analysis reporting requirements of Sec.  3175.120(e) 
and (f) starting on January 17, 2019; and
    (iii) Equipment approvals required in Sec. Sec.  3175.43, 3175.44, 
and 3175.46 through 3175.49 starting on January 17, 2019.
    (3) Low-volume FMPs must comply with all of the requirements of 
this subpart by January 17, 2019.

[[Page 81615]]

    (4) Very-low-volume FMPs must comply with all of the requirements 
of this subpart by January 17, 2020.
    (c) During the phase-in timeframes in paragraph (b) of this 
section, measuring procedures and equipment in place before January 17, 
2017 must comply with the requirements in place prior to the issuance 
of this rule, including Onshore Oil and Gas Order No. 5, Measurement of 
Gas, and applicable NTLs, COAs, and written orders.
    (d) Onshore Oil and Gas Order No. 5, Measurement of Gas, statewide 
NTLs, variance approvals, and written orders that establish 
requirements or standards related to gas measurement and that are in 
effect on January 17, 2017 are rescinded as of:
    (1) January 17, 2018 for high-volume and very-high-volume FMPs;
    (2) January 17, 2019 for low-volume FMPs; and
    (3) January 17, 2020 for very-low-volume FMPs.


Sec.  3175.61  Grandfathering.

    (a) Meter tubes. Meter tubes installed at high- and low-volume FMPs 
before January 17, 2017 are exempt from the meter tube requirements of 
API 14.3.2, Subsection 6.2 (incorporated by reference, see Sec.  
3175.30), and Sec.  3175.80(f) and (k). For high-volume FMPs, the BLM 
will add an uncertainty of 0.25 percent to the discharge 
coefficient uncertainty when determining overall meter uncertainty 
under Sec.  3175.31(a), unless the PMT reviews, and the BLM approves, 
data showing otherwise. Meter tubes grandfathered under this section 
must still meet the following requirements:
    (1) Orifice plate eccentricity must comply with AGA Report No. 3 
(1985), Section 4.2.4 (incorporated by reference, see Sec.  3175.30).
    (2) Meter tube construction and condition must comply with AGA 
Report No. 3 (1985), Section 4.3.4 (incorporated by reference, see 
Sec.  3175.30).
    (3) Meter tube lengths. (i) Meter tube lengths must comply with AGA 
Report No. 3 (1985), Section 4.4 (dimensions ``A'' and ``A''' from 
Figures 4-8) (incorporated by reference, see Sec.  3175.30).
    (ii) If the upstream meter tube contains a 19-tube bundle flow 
straightener or isolating flow conditioner, the installation must 
comply with Sec.  3175.80(g);
    (b) EGM software. (1) EGM software installed at very-low-volume 
FMPs before January 17, 2017 is exempt from the requirements in Sec.  
3175.103(a)(1). However, flow-rate calculations must still be 
calculated in accordance with AGA Report No. 3 (1985), Section 6, or 
API 14.3.3 (1992), and supercompressibility calculations must still be 
calculated in accordance with PRCI NX 19 (all incorporated by 
reference, see Sec.  3175.30).
    (2) EGM software installed at low-volume FMPs before January 17, 
2017 is exempt from the requirements at Sec.  3175.103(a)(1)(i) if the 
differential-pressure to static-pressure ratio, based on the monthly 
average differential pressure and static pressure, is less than the 
value of ``xi'' shown in API 14.3.3 (1992), Annex G, Table 
G.1 (incorporated by reference, see Sec.  3175.30). However, flow-rate 
calculations must still be calculated in accordance with API 14.3.3 
(1992) (incorporated by reference, see Sec.  3175.30).


Sec.  3175.70  Measurement location.

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


Sec.  3175.80  Flange-tapped orifice plates (primary devices).

    Except as stated in this section, as prescribed in Table 1 to this 
section, or grandfathered under Sec.  3175.61, the standards and 
requirements in this section apply to all flange-tapped orifice plates 
(Note: The following table lists the standards in this subpart and the 
API standards that the operator must follow to install and maintain 
flange-tapped orifice plates. A requirement applies when a column is 
marked with an ``x'' or a number.).

[[Page 81616]]

[GRAPHIC] [TIFF OMITTED] TR17NO16.058

    (a) The Beta ratio must be no less than 0.10 and no greater than 
0.75.
    (b) The orifice bore diameter must be no less than 0.45 inches.
    (c) For FMPs measuring production from wells first coming into 
production, or from existing wells that have been re-fractured 
(including FMPs already measuring production from one or more other 
wells), the operator must inspect the orifice plate upon installation 
and then every 2 weeks thereafter. If the inspection shows that the 
orifice plate does not comply with API 14.3.2, Section 4 (incorporated 
by reference, see Sec.  3175.30), the operator must replace the orifice 
plate. When the inspection shows that the orifice plate complies with 
API 14.3.2, Section 4 (incorporated by reference, see Sec.  3175.30), 
the operator thereafter must inspect the orifice plate as prescribed in 
paragraph (d) of this section.
    (d) The operator must pull and inspect the orifice plate at the 
frequency (in months) identified in Table 1 to this section. The 
operator must replace orifice plates that do not comply with API 
14.3.2, Section 4 (incorporated by reference, see Sec.  3175.30), with 
an orifice plate that does comply with these standards.
    (e) The operator must retain documentation for every plate 
inspection and must include that documentation as part of the 
verification report (see Sec.  3175.92(d) for mechanical recorders, or 
Sec.  3175.102(e) for EGM systems). The operator must provide that 
documentation to the BLM upon request. The documentation must include:
    (1) The information required in Sec.  3170.7(g) of this part;
    (2) Plate orientation (bevel upstream or downstream);
    (3) Measured orifice bore diameter;
    (4) Plate condition (compliance with API 14.3.2, Section 4 
(incorporated by reference, see Sec.  3175.30));

[[Page 81617]]

    (5) The presence of oil, grease, paraffin, scale, or other 
contaminants on the plate;
    (6) Time and date of inspection; and
    (7) Whether or not the plate was replaced.
    (f) Meter tubes must meet the requirements of API 14.3.2, 
Subsections 5.1 through 5.4 (incorporated by reference, see Sec.  
3175.30).
    (g) If flow conditioners are used, they must be either isolating-
flow conditioners approved by the BLM and installed under BLM 
requirements (see Sec.  3175.46) or 19-tube-bundle flow straighteners 
constructed in compliance with API 14.3.2, Subsections 5.5.2 through 
5.5.4, and located in compliance with API 14.3.2, Subsection 6.3 
(incorporated by reference, see Sec.  3175.30).
    (h) Basic meter tube inspection. The operator must:
    (1) Perform a basic inspection of meter tubes within the timeframe 
(in years) specified in Table 1 to this section;
    (2) Conduct a basic inspection that is able to identify 
obstructions, pitting, and buildup of foreign substances (e.g., grease 
and scale);
    (3) Notify the AO at least 72 hours in advance of performing a 
basic inspection or submit a monthly or quarterly schedule of basic 
inspections to the AO in advance;
    (4) Conduct additional inspections, as the AO may require, if 
warranted by conditions, such as corrosive or erosive-flow (e.g., high 
H2S or CO2 content) or signs of physical damage 
to the meter tube;
    (5) Maintain documentation of the findings from the basic meter 
tube inspection including:
    (i) The information required in Sec.  3170.7(g) of this part;
    (ii) The time and date of inspection;
    (iii) The type of equipment used to make the inspection; and
    (iv) A description of findings, including location and severity of 
pitting, obstructions, and buildup of foreign substances; and
    (6) Complete the first inspection after January 17, 2017 within the 
timeframes (in years) given in Table 1 to this section.
    (i) Detailed meter tube inspection. (1) Within 30 days of a basic 
inspection that indicates the presence of pitting, obstructions, or a 
buildup of foreign substances, the operator must:
    (i) For low-volume FMPs, clean the meter tube of obstructions and 
foreign substances;
    (ii) For high- and very-high-volume FMPs, physically measure and 
inspect the meter tube to determine if the meter tube complies with API 
14.3.2, Subsections 5.1 through 5.4 and API 14.3.2, Subsection 6.2 
(incorporated by reference, see Sec.  3175.30), or the requirements 
under Sec.  3175.61(a), if the meter tube is grandfathered under Sec.  
3175.61(a). If the meter tube does not comply with the applicable 
standards, the operator must repair the meter tube to bring the meter 
tube into compliance with these standards or replace the meter tube 
with one that meets these standards; or
    (iii) Submit a request to the AO for an extension of the 30-day 
timeframe, justifying the need for the extension.
    (2) For all high- and very-high volume FMPs installed after January 
17, 2017, the operator must perform a detailed inspection under 
paragraph (i)(1)(ii) of this section before operation of the meter. The 
operator may submit documentation showing that the meter tube complies 
with API 14.3.2, Subsections 5.1 through 5.4 (incorporated by 
reference, see Sec.  3175.30) in lieu of performing a detailed 
inspection.
    (3) The operator must notify the AO at least 24 hours before 
performing a detailed inspection.
    (j) The operator must retain documentation of all detailed meter 
tube inspections, demonstrating that the meter tube complies with API 
14.3.2, Subsections 5.1 through 5.4 (incorporated by reference, see 
Sec.  3175.30), and showing all required measurements. The operator 
must provide such documentation to the BLM upon request for every 
meter-tube inspection. Documentation must also include the information 
required in Sec.  3170.7(g) of this part.
    (k) Meter tube lengths. (1) Meter-tube lengths and the location of 
19-tube-bundle flow straighteners, if applicable, must comply with API 
14.3.2, Subsection 6.3 (incorporated by reference, see Sec.  3175.30).
    (2) For Beta ratios of less than 0.5, the location of 19-tube 
bundle flow straighteners installed in compliance with AGA Report No. 3 
(1985), Section 4.4 (incorporated by reference, see Sec.  3175.30), 
also complies with the location of 19-tube bundle flow straighteners as 
required in paragraph (k)(1) of this section.
    (3) If the diameter ratio ([beta]) falls between the values in 
Tables 7, 8a, or 8b of API 14.3.2, Subsection 6.3 (incorporated by 
reference, see Sec.  3175.30), the length identified for the larger 
diameter ratio in the appropriate Table is the minimum requirement for 
meter-tube length and determines the location of the end of the 19-
tube-bundle flow straightener closest to the orifice plate. For 
example, if the calculated diameter ratio is 0.41, use the table entry 
for a 0.50 diameter ratio.
    (l) Thermometer wells. (1) Thermometer wells used for determining 
the flowing temperature of the gas as well as thermometer wells used 
for verification (test well) must be located in compliance with API 
14.3.2, Subsection 6.5 (incorporated by reference, see Sec.  3175.30).
    (2) Thermometer wells must be located in such a way that they can 
sense the same flowing gas temperature that exists at the orifice 
plate. The operator may accomplish this by physically locating the 
thermometer well(s) in the same ambient temperature conditions as the 
primary device (such as in a heated meter house) or by installing 
insulation and/or heat tracing along the entire meter run. If the 
operator chooses to use insulation to comply with this requirement, the 
AO may prescribe the quality of the insulation based on site specific 
factors such as ambient temperature, flowing temperature of the gas, 
composition of the gas, and location of the thermometer well in 
relation to the orifice plate (i.e., inside or outside of a meter 
house).
    (3) Where multiple thermometer wells have been installed in a meter 
tube, the flowing temperature must be measured from the thermometer 
well closest to the primary device.
    (4) Thermometer wells used to measure or verify flowing temperature 
must contain a thermally conductive liquid.
    (m) The sampling probe must be located as specified in Sec.  
3175.112(b).


Sec.  3175.90  Mechanical recorder (secondary device).

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

[[Page 81618]]

[GRAPHIC] [TIFF OMITTED] TR17NO16.059

Sec.  3175.91   Installation and operation of mechanical recorders.

    (a) Gauge lines connecting the pressure taps to the mechanical 
recorder must:
    (1) Have a nominal diameter of not less than 3/8 inch, including 
ports and valves;
    (2) Be sloped upwards from the pressure taps at a minimum pitch of 
1 inch per foot of length with no visible sag;
    (3) Be the same internal diameter along their entire length;
    (4) Not include tees, except for the static-pressure line;
    (5) Not be connected to more than one differential-pressure bellows 
and static-pressure element, or to any other device; and
    (6) Be no longer than 6 feet.
    (b) The differential-pressure pen must record at a minimum reading 
of 10 percent of the differential-pressure-bellows range for the 
majority of the flowing period. This requirement does not apply to 
inverted charts.
    (c) The flowing temperature of the gas must be continuously 
recorded and used in the volume calculations under Sec.  3175.94(a)(1).
    (d) The following information must be maintained at the FMP in a 
legible condition, in compliance with Sec.  3170.7(g) of this part, and 
accessible to the AO at all times:
    (1) Differential-pressure-bellows range;
    (2) Static-pressure-element range;
    (3) Temperature-element range;
    (4) Relative density (specific gravity) of the gas;
    (5) Static-pressure units of measure (psia or psig);
    (6) Meter elevation;
    (7) Meter-tube inside diameter;
    (8) Primary device type;
    (9) Orifice-bore or other primary-device dimensions necessary for 
device verification, Beta- or area-ratio determination, and gas-volume 
calculation;
    (10) Make, model, and location of approved isolating flow 
conditioners, if used;
    (11) Location of the downstream end of 19-tube-bundle flow 
straighteners, if used;
    (12) Date of last primary-device inspection; and
    (13) Date of last meter verification.
    (e) The differential pressure, static pressure, and flowing 
temperature elements must be operated between the lower- and upper-
calibrated limits of the respective elements.


Sec.  3175.92  Verification and calibration of mechanical recorders.

    (a) Verification after installation or following repair. (1) Before 
performing any verification of a mechanical recorder required in this 
part, the operator must perform a leak test. The verification must not 
proceed if leaks are present. The leak test must be

[[Page 81619]]

conducted in a manner that will detect leaks in the following:
    (i) All connections and fittings of the secondary device, including 
meter manifolds and verification equipment;
    (ii) The isolation valves; and
    (iii) The equalizer valves.
    (2) The operator must adjust the time lag between the differential- 
and static-pressure pens, if necessary, to be 1/96 of the chart 
rotation period, measured at the chart hub. For example, the time lag 
is 15 minutes on a 24-hour test chart and 2 hours on an 8-day test 
chart.
    (3) The meter's differential pen arc must be able to duplicate the 
test chart's time arc over the full range of the test chart, and must 
be adjusted, if necessary.
    (4) The as-left values must be verified in the following sequence 
against a certified pressure device for the differential-pressure and 
static-pressure elements (if the static-pressure pen has been offset 
for atmospheric pressure, the static-pressure element range is in 
psia):
    (i) Zero (vented to atmosphere);
    (ii) 50 percent of element range;
    (iii) 100 percent of element range;
    (iv) 80 percent of element range;
    (v) 20 percent of element range; and
    (vi) Zero (vented to atmosphere).
    (5) The following as-left temperatures must be verified by placing 
the temperature probe in a water bath with a certified test 
thermometer:
    (i) Approximately 10[deg] F below the lowest expected flowing 
temperature;
    (ii) Approximately 10[deg] F above the highest expected flowing 
temperature; and
    (iii) At the expected average flowing temperature.
    (6) If any of the readings required in paragraph (a)(4) or (5) of 
this section vary from the test device reading by more than the 
tolerances shown in Table 1 to this section, the operator must replace 
and verify the element for which readings were outside the applicable 
tolerances before returning the meter to service.
[GRAPHIC] [TIFF OMITTED] TR17NO16.060

    (7) If the static-pressure pen is offset for atmospheric pressure:
    (i) The atmospheric pressure must be calculated under appendix A to 
this subpart; and
    (ii) The pen must be offset prior to obtaining the as-left 
verification values required in paragraph (a)(4) of this section.
    (b) Routine verification frequency. The differential pressure, 
static pressure, and temperature elements must be verified under the 
requirements of this section at the frequency specified in Table 1 to 
Sec.  3175.90, in months.
    (c) Routine verification procedures. (1) Before performing any 
verification required in this part, the operator must perform a leak 
test in the manner required under paragraph (a)(1) of this section.
    (2) No adjustments to the pens or linkages may be made until an as-
found verification is obtained. If the static pen has been offset for 
atmospheric pressure, the static pen must not be reset to zero until 
the as-found verification is obtained.
    (3) The operator must obtain the as-found values of differential 
and static pressure against a certified pressure device at the readings 
listed in paragraph (a)(4) of this section, with the following 
additional requirements:
    (i) If there is sufficient data on site to determine the point at 
which the differential and static pens normally operate, the operator 
must also obtain an as-found value at those points;
    (ii) If there is not sufficient data on site to determine the 
points at which the differential and static pens normally operate, the 
operator must also obtain as-found values at 5 percent of the element 
range and 10 percent of the element range; and
    (iii) If the static-pressure pen has been offset for atmospheric 
pressure, the static-pressure element range is in units of psia.
    (4) The as-found value for temperature must be taken using a 
certified test thermometer placed in a test thermometer well if there 
is flow through the meter and the meter tube is equipped with a test 
thermometer well. If there is no flow through the meter or if the meter 
is not equipped with a test thermometer well, the temperature probe 
must be verified by placing it along with a test thermometer in an 
insulated water bath.
    (5) The element undergoing verification must be calibrated 
according to manufacturer specifications if any of the as-found values 
determined under paragraph (c)(3) or (4) of this section are not within 
the tolerances shown in Table 1 to this section, when compared to the 
values applied by the test equipment.
    (6) The operator must adjust the time lag between the differential- 
and static-pressure pens, if necessary, to be 1/96 of the chart 
rotation period, measured at the chart hub. For example, the time lag 
is 15 minutes on a 24-hour test chart and 2 hours on an 8-day test 
chart.
    (7) The meter's differential pen arc must be able to duplicate the 
test chart's time arc over the full range of the test chart, and must 
be adjusted, if necessary.
    (8) If any adjustment to the meter was made, the operator must 
perform an as-left verification on each element adjusted using the 
procedures in paragraphs (c)(3) and (4) of this section.
    (9) If, after an as-left verification, any of the readings required 
in paragraph

[[Page 81620]]

(c)(3) or (4) of this section vary by more than the tolerances shown in 
Table 1 to this section when compared with the test-device reading, any 
element which has readings that are outside of the applicable 
tolerances must be replaced and verified under this section before the 
operator returns the meter to service.
    (10) If the static-pressure pen is offset for atmospheric pressure:
    (i) The atmospheric pressure must be calculated under appendix A to 
this subpart; and
    (ii) The pen must be offset prior to obtaining the as-left 
verification values required in paragraph (c)(3) of this section.
    (d) The operator must retain documentation of each verification, as 
required under Sec.  3170.7(g) of this part, and submit it to the BLM 
upon request. This documentation must include:
    (1) The time and date of the verification and the prior 
verification date;
    (2) Primary-device data (meter-tube inside diameter and 
differential-device size and Beta or area ratio) if the orifice plate 
is pulled and inspected;
    (3) The type and location of taps (flange or pipe, upstream or 
downstream static tap);
    (4) Atmospheric pressure used to offset the static-pressure pen, if 
applicable;
    (5) Mechanical recorder data (make, model, and differential 
pressure, static pressure, and temperature element ranges);
    (6) The normal operating points for differential pressure, static 
pressure, and flowing temperature;
    (7) Verification points (as-found and applied) for each element;
    (8) Verification points (as-left and applied) for each element, if 
a calibration was performed;
    (9) Names, contact information, and affiliations of the person 
performing the verification and any witness, if applicable; and
    (10) Remarks, if any.
    (e) Notification of verification. (1) For verifications performed 
after installation or following repair, the operator must notify the AO 
at least 72 hours before conducting the verifications.
    (2) For routine verifications, the operator must notify the AO at 
least 72 hours before conducting the verification or submit a monthly 
or quarterly verification schedule to the AO in advance.
    (f) If, during the verification, the combined errors in as-found 
differential pressure, static pressure, and flowing temperature taken 
at the normal operating points tested result in a flow-rate error 
greater than 2 percent or 2 Mcf/day, whichever is greater, the volumes 
reported on the OGOR and on royalty reports submitted to ONRR must be 
corrected beginning with the date that the inaccuracy occurred. If that 
date is unknown, the volumes must be corrected beginning with the 
production month that includes the date that is half way between the 
date of the last verification and the date of the current verification. 
For example: Meter verification determined that the meter was reading 4 
Mcf/day high at the normal operating points. The average flow rate 
measured by the meter is 90 Mcf/day. There is no indication of when the 
inaccuracy occurred. The date of the current verification was December 
15, 2015. The previous verification was conducted on June 15, 2015. The 
royalty volumes reported on OGOR B that were based on this meter must 
be corrected for the 4 Mcf/day error back to September 15, 2015.
    (g) Test equipment used to verify or calibrate elements at an FMP 
must be certified at least every 2 years. Documentation of the 
recertification must be on-site during all verifications and must show:
    (1) Test equipment serial number, make, and model;
    (2) The date on which the recertification took place;
    (3) The test equipment measurement range; and
    (4) The uncertainty determined or verified as part of the 
recertification.


Sec.  3175.93   Integration statements.

    An unedited integration statement must be retained and made 
available to the BLM upon request. The integration statement must 
contain the following information:
    (a) The information required in Sec.  3170.7(g) of this part;
    (b) The name of the company performing the integration;
    (c) The month and year for which the integration statement applies;
    (d) Meter-tube inside diameter (inches);
    (e) The following primary device information, as applicable:
    (i) Orifice bore diameter (inches); or
    (ii) Beta or area ratio, discharge coefficient, and other 
information necessary to calculate the flow rate;
    (f) Relative density (specific gravity);
    (g) CO2 content (mole percent);
    (h) N2 content (mole percent);
    (i) Heating value calculated under Sec.  3175.125 (Btu/standard 
cubic feet);
    (j) Atmospheric pressure or elevation at the FMP;
    (k) Pressure base;
    (l) Temperature base;
    (m) Static-pressure tap location (upstream or downstream);
    (n) Chart rotation (hours or days);
    (o) Differential-pressure bellows range (inches of water);
    (p) Static-pressure element range (psi); and
    (q) For each chart or day integrated:
    (i) The time and date on and time and date off;
    (ii) Average differential pressure (inches of water);
    (iii) Average static pressure;
    (iv) Static-pressure units of measure (psia or psig);
    (v) Average temperature ([deg] F);
    (vi) Integrator counts or extension;
    (vii) Hours of flow; and
    (viii) Volume (Mcf).


Sec.  3175.94   Volume determination.

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

V = IMV x IV

Where:

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

    (1) If the primary device is a flange-tapped orifice plate, a 
single IMV must be calculated for each chart or chart interval using 
the following equation:
[GRAPHIC] [TIFF OMITTED] TR17NO16.061

Where:

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

    (2) For other types of primary devices, the IMV must be calculated 
using the equations and procedures recommended by the PMT and approved 
by the BLM, specific to the make, model, size, and area ratio of the 
primary device being used.
    (3) Variables that are functions of differential pressure, static 
pressure, or flowing temperature (e.g., Cd, Y, 
Zf)

[[Page 81621]]

must use the average values of differential pressure, static pressure, 
and flowing temperature as determined from the integration statement 
and reported on the integration statement for the chart or chart 
interval integrated. The flowing temperature must be the average 
flowing temperature reported on the integration statement for the chart 
or chart interval being integrated.
    (b) Atmospheric pressure used to convert static pressure in psig to 
static pressure in psia must be determined under appendix A to this 
subpart.


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

    Except as stated in this section, as prescribed in Table 1 to this 
section, or grandfathered under Sec.  3175.61, the standards and 
requirements in this section apply to all EGM systems used at FMPs 
(Note: The following table lists the standards in this subpart and the 
API standards that the operator must follow to install and maintain EGM 
systems. A requirement applies when a column is marked with an ``x'' or 
a number.).
[GRAPHIC] [TIFF OMITTED] TR17NO16.062


[[Page 81622]]




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

    (a) Manifolds and gauge lines connecting the pressure taps to the 
secondary device must:
    (1) Have a nominal diameter of not less than \3/8\-inch, including 
ports and valves;
    (2) Be sloped upwards from the pressure taps at a minimum pitch of 
1 inch per foot of length with no visible sag;
    (3) Have the same internal diameter along their entire length;
    (4) Not include tees except for the static-pressure line;
    (5) Not be connected to any other devices or more than one 
differential pressure and static-pressure transducer. If the operator 
is employing redundancy verification, two differential pressure and two 
static-pressure transducers may be connected; and
    (6) Be no longer than 6 feet.
    (b) Each FMP must include a display, which must:
    (1) Be readable without the need for data-collection units, laptop 
computers, a password, or any special equipment;
    (2) Be on site and in a location that is accessible to the AO;
    (3) Include the units of measure for each required variable;
    (4) Display the software version and previous-day's volume, as well 
as the following variables consecutively:
    (i) Current flowing static pressure with units (psia or psig);
    (ii) Current differential pressure (inches of water);
    (iii) Current flowing temperature ([deg]F); and
    (iv) Current flow rate (Mcf/day or scf/day); and
    (5) Either display or post on site and accessible to the AO an 
hourly or daily QTR (see Sec.  3175.104(a)) no more than 31 days old 
showing the following information:
    (i) Previous-period (for this section, previous period means at 
least 1 day prior, but no longer than 1 month prior) average 
differential pressure (inches of water);
    (ii) Previous-period average static pressure with units (psia or 
psig); and
    (iii) Previous-period average flowing temperature ([deg]F).
    (c) The following information must be maintained at the FMP in a 
legible condition, in compliance with Sec.  3170.7(g) of this part, and 
accessible to the AO at all times:
    (1) The unique meter ID number;
    (2) Relative density (specific gravity);
    (3) Elevation of the FMP;
    (4) Primary device information, such as orifice bore diameter 
(inches) or Beta or area ratio and discharge coefficient, as 
applicable;
    (5) Meter-tube mean inside diameter;
    (6) Make, model, and location of approved isolating flow 
conditioners, if used;
    (7) Location of the downstream end of 19-tube-bundle flow 
straighteners, if used;
    (8) For self-contained EGM systems, make and model number of the 
system;
    (9) For component-type EGM systems, make and model number of each 
transducer and the flow computer;
    (10) URL and upper calibrated limit for each transducer;
    (11) Location of the static-pressure tap (upstream or downstream);
    (12) Last primary-device inspection date; and
    (13) Last secondary device verification date.
    (d) The differential pressure, static pressure, and flowing 
temperature transducers must be operated between the lower and upper 
calibrated limits of the transducer. The BLM may approve the 
differential pressure to exceed the upper calibrated limit of the 
differential-pressure transducer for brief periods in plunger lift 
operations; however, the differential pressure may not exceed the URL.
    (e) The flowing temperature of the gas must be continuously 
measured and used in the flow-rate calculations under API 21.1, Section 
4 (incorporated by reference, see Sec.  3175.30).


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

    (a) Transducer verification and calibration after installation or 
repair. (1) Before performing any verification required in this 
section, the operator must perform a leak test in the manner prescribed 
in Sec.  3175.92(a)(1).
    (2) The operator must verify the points listed in API 21.1, 
Subsection 7.3.3 (incorporated by reference, see Sec.  3175.30), by 
comparing the values from the certified test device with the values 
used by the flow computer to calculate flow rate. If any of these as-
left readings vary from the test equipment reading by more than the 
tolerance determined by API 21.1, Subsection 8.2.2.2, Equation 24 
(incorporated by reference, see Sec.  3175.30), then that transducer 
must be replaced and the new transducer must be tested under this 
paragraph.
    (3) For absolute static-pressure transducers, the value of 
atmospheric pressure used when the transducer is vented to atmosphere 
must be calculated under appendix A to this subpart, measured by a 
NIST-certified barometer with a stated accuracy of 0.05 psi 
or better, or obtained from an absolute-pressure calibration device.
    (4) Before putting a meter into service, the differential-pressure 
transducer must be tested at zero with full working pressure applied to 
both sides of the transducer. If the absolute value of the transducer 
reading is greater than the reference accuracy of the transducer, 
expressed in inches of water column, the transducer must be re-zeroed.
    (b) Routine verification frequency. (1) If redundancy verification 
under paragraph (d) of this section is not used, the differential 
pressure, static pressure, and temperature transducers must be verified 
under the requirements of paragraph (c) of this section at the 
frequency specified in Table 1 to Sec.  3175.100, in months; or
    (2) If redundancy verification under paragraph (d) of this section 
is used, the differential pressure, static pressure, and temperature 
transducers must be verified under the requirements of paragraph (d) of 
this section. In addition, the transducers must be verified under the 
requirements of paragraph (c) of this section at least annually.
    (c) Routine verification procedures. Verifications must be 
performed according to API 21.1, Subsection 8.2 (incorporated by 
reference, see Sec.  3175.30), with the following exceptions, 
additions, and clarifications:
    (1) Before performing any verification required under this section, 
the operator must perform a leak test consistent with Sec.  
3175.92(a)(1).
    (2) An as-found verification for differential pressure, static 
pressure and temperature must be conducted at the normal operating 
point of each transducer.
    (i) The normal operating point is the mean value taken over a 
previous time period not less than 1 day or greater than 1 month. 
Acceptable mean values include means weighted based on flow time and 
flow rate.
    (ii) For differential and static-pressure transducers, the pressure 
applied to the transducer for this verification must be within five 
percentage points of the normal operating point. For example, if the 
normal operating point for differential pressure is 17 percent of the 
upper calibrated limit, the normal point verification pressure must be 
between 12 percent and 22 percent of the upper calibrated limit.
    (iii) For the temperature transducer, the water bath or test 
thermometer well must be within 20 [deg]F of the normal operating point 
for temperature.
    (3) If any of the as-found values are in error by more than the 
manufacturer's specification for stability or drift--as adjusted for 
static pressure and ambient temperature--on two consecutive

[[Page 81623]]

verifications, that transducer must be replaced prior to returning the 
meter to service.
    (4) If a transducer is calibrated, the as-left verification must 
include the normal operating point of that transducer, as defined in 
paragraph (c)(2) of this section.
    (5) The as-found values for differential pressure obtained with the 
low side vented to atmospheric pressure must be corrected to working-
pressure values using API 21.1, Annex H, Equation H.1 (incorporated by 
reference, see Sec.  3175.30).
    (6) The verification tolerance for differential and static pressure 
is defined by API 21.1, Subsection 8.2.2.2, Equation 24 (incorporated 
by reference, see Sec.  3175.30). The verification tolerance for 
temperature is equivalent to the uncertainty of the temperature 
transmitter or 0.5 [deg]F, whichever is greater.
    (7) All required verification points must be within the 
verification tolerance before returning the meter to service.
    (8) Before putting a meter into service, the differential-pressure 
transducer must be tested at zero with full working pressure applied to 
both sides of the transducer. If the absolute value of the transducer 
reading is greater than the reference accuracy of the transducer, 
expressed in inches of water column, the transducer must be re-zeroed.
    (d) Redundancy verification procedures. Redundancy verifications 
must be performed as required under API 21.1, Subsection 8.2 
(incorporated by reference, see Sec.  3175.30), with the following 
exceptions, additions, and clarifications:
    (1) The operator must identify which set of transducers is used for 
reporting on the OGOR (the primary transducers) and which set of 
transducers is used as a check (the check set of transducers);
    (2) For every calendar month, the operator must compare the flow-
time linear averages of differential pressure, static pressure, and 
temperature readings from the primary transducers with those from the 
check transducers;
    (3)(i) If for any transducer the difference between the averages 
exceeds the tolerance defined by the following equation:
[GRAPHIC] [TIFF OMITTED] TR17NO16.063

Where:

Ap is the reference accuracy of the primary transducer 
and
Ac is the reference accuracy of the check transducer.

    (ii) The operator must verify both the primary and check transducer 
under paragraph (c) of this section within the first 5 days of the 
month following the month in which the redundancy verification was 
performed. For example, if the redundancy verification for March 
reveals that the difference in the flow-time linear averages of 
differential pressure exceeded the verification tolerance, both the 
primary and check differential-pressure transducers must be verified 
under paragraph (c) of this section by April 5th.
    (e) The operator must retain documentation of each verification for 
the period required under Sec.  3170.7 of this part, including 
calibration data for transducers that were replaced, and submit it to 
the BLM upon request.
    (1) For routine verifications, this documentation must include:
    (i) The information required in Sec.  3170.7(g) of this part;
    (ii) The time and date of the verification and the last 
verification date;
    (iii) Primary device data (meter-tube inside diameter and 
differential-device size, Beta or area ratio);
    (iv) The type and location of taps (flange or pipe, upstream or 
downstream static tap);
    (v) The flow computer make and model;
    (vi) The make and model number for each transducer, for component-
type EGM systems;
    (vii) Transducer data (make, model, differential, static, 
temperature URL, and upper calibrated limit);
    (viii) The normal operating points for differential pressure, 
static pressure, and flowing temperature;
    (ix) Atmospheric pressure;
    (x) Verification points (as-found and applied) for each transducer;
    (xi) Verification points (as-left and applied) for each transducer, 
if calibration was performed;
    (xii) The differential device inspection date and condition (e.g., 
clean, sharp edge, or surface condition);
    (xiii) Verification equipment make, model, range, accuracy, and 
last certification date;
    (xiv) The name, contact information, and affiliation of the person 
performing the verification and any witness, if applicable; and
    (xv) Remarks, if any.
    (2) For redundancy verification checks, this documentation must 
include;
    (i) The information required in Sec.  3170.7(g) of this part;
    (ii) The month and year for which the redundancy check applies;
    (iii) The makes, models, upper range limits, and upper calibrated 
limits of the primary set of transducers;
    (iv) The makes, models, upper range limits, and upper calibrated 
limits of the check set of transducers;
    (v) The information required in API 21.1, Annex I (incorporated by 
reference, see Sec.  3175.30);
    (vii) The tolerance for differential pressure, static pressure, and 
temperature as calculated under paragraph (d)(2) of this section; and
    (viii) Whether or not each transducer required verification under 
paragraph (c) of this section.
    (f) Notification of verification. (1) For verifications performed 
after installation or following repair, the operator must notify the AO 
at least 72 hours before conducting the verifications.
    (2) For routine verifications, the operator must notify the AO at 
least 72 hours before conducting the verification or submit a monthly 
or quarterly verification schedule to the AO in advance.
    (g) If, during the verification, the combined errors in as-found 
differential pressure, static pressure, and flowing temperature taken 
at the normal operating points tested result in a flow-rate error 
greater than 2 percent or 2 Mcf/day, whichever is greater, the volumes 
reported on the OGOR and on royalty reports submitted to ONRR must be 
corrected beginning with the date that the inaccuracy occurred. If that 
date is unknown, the volumes must be corrected beginning with the 
production month that includes the date that is half way between the 
date of the last verification and the date of the present verification. 
See the example in Sec.  3175.92(f).
    (h) Test equipment requirements. (1) Test equipment used to verify 
or calibrate transducers at an FMP must be certified at least every 2 
years. Documentation of the certification must be on site and made 
available to the AO during all verifications and must show:
    (i) The test equipment serial number, make, and model;
    (ii) The date on which the recertification took place;
    (iii) The range of the test equipment; and
    (iv) The uncertainty determined or verified as part of the 
recertification.
    (2) Test equipment used to verify or calibrate transducers at an 
FMP must meet the following accuracy standards:
    (i) The accuracy of the test equipment, stated in actual units of 
measure, must be no greater than 0.5 times the reference accuracy of 
the transducer being verified, also stated in actual units of measure; 
or
    (ii) The equipment must have a stated accuracy of at least 0.10 
percent of the

[[Page 81624]]

upper calibrated limit of the transducer being verified.


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

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


Sec.  3175.104   Logs and records.

    (a) The operator must retain, and submit to the BLM upon request, 
the original, unaltered, unprocessed, and unedited daily and hourly 
QTRs, which must contain the information identified in API 21.1, 
Subsection 5.2 (incorporated by reference, see Sec.  3175.30), with the 
following additions and clarifications:
    (1) The information required in Sec.  3170.7(g) of this part;
    (2) The volume, flow time, and integral value or average extension 
must be reported to at least 5 decimal places. The average differential 
pressure, static pressure, and temperature as calculated in Sec.  
3175.103(c), must be reported to at least three decimal places; and
    (3) A statement of whether the operator has submitted the integral 
value or average extension.
    (b) The operator must retain, and submit to the BLM upon request, 
the original, unaltered, unprocessed, and unedited configuration log, 
which must contain the information specified in API 21.1, Subsection 
5.4 (including the flow-computer snapshot report in API 21.1, 
Subsection 5.4.2), and API 21.1, Annex G (incorporated by reference, 
see Sec.  3175.30), with the following additions and clarifications:
    (1) The information required in Sec.  3170.7(g) of this part;
    (2) Software/firmware identifiers under API 21.1, Subsection 5.3 
(incorporated by reference, see Sec.  3175.30);
    (3) For very-low-volume FMPs only, the fixed temperature, if not 
continuously measured ([deg]F); and
    (4) The static-pressure tap location (upstream or downstream).
    (c) The operator must retain, and submit to the BLM upon request, 
the original, unaltered, unprocessed, and unedited event log. The event 
log must comply with API 21.1, Subsection 5.5 (incorporated by 
reference, see Sec.  3175.30), with the following additions and 
clarifications: The event log must have sufficient capacity and must be 
retrieved and stored at intervals frequent enough to maintain a 
continuous record of events as required under Sec.  3170.7 of this 
part, or the life of the FMP, whichever is shorter.
    (d) The operator must retain an alarm log and provide it to the BLM 
upon request. The alarm log must comply with API 21.1, Subsection 5.6 
(incorporated by reference, see Sec.  3175.30).
    (e) Records may only be submitted from accounting system names and 
versions and flow computer makes and models that have been approved by 
the BLM (see Sec.  3175.49).


Sec.  3175.110   Gas sampling and analysis.

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

[[Page 81625]]

[GRAPHIC] [TIFF OMITTED] TR17NO16.064


[[Page 81626]]




Sec.  3175.111   General sampling requirements.

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


Sec.  3175.112   Sampling probe and tubing.

    (a) All gas samples must be taken from a sample probe that complies 
with the requirements of paragraphs (b) and (c) of this section.
    (b) Location of sample probe. (1) The sample probe must be located 
in the meter tube in accordance with API 14.1, Subsection 6.4.2 
(incorporated by reference, see Sec.  3175.30), and must be the first 
obstruction downstream of the primary device.
    (2) The sample probe must be exposed to the same ambient 
temperature as the primary device. The operator may accomplish this by 
physically locating the sample probe in the same ambient temperature 
conditions as the primary device (such as in a heated meter house) or 
by installing insulation and/or heat tracing along the entire meter 
run. If the operator chooses to use insulation to comply with this 
requirement, the AO may prescribe the quality of the insulation based 
on site specific factors such as ambient temperature, flowing 
temperature of the gas, composition of the gas, and location of the 
sample probe in relation to the orifice plate (i.e., inside or outside 
of a meter house).
    (c) Sample probe design and type. (1) Sample probes must be 
constructed from stainless steel.
    (2) If a regulating type of sample probe is used, the pressure-
regulating mechanism must be inside the pipe or maintained at a 
temperature of at least 30[deg] F above the hydrocarbon dew point of 
the gas.
    (3) The sample probe length must be the shorter of:
    (i) The length necessary to place the collection end of the probe 
in the center one third of the pipe cross-section; or
    (ii) The recommended length of the probe in Table 1 in API 14.1, 
Subsection 6.4 (incorporated by reference, see Sec.  3175.30).
    (4) The use of membranes, screens, or filters at any point in the 
sample probe is prohibited.
    (d) Sample tubing connecting the sample probe to the sample 
container or analyzer must be constructed of stainless steel or nylon 
11.


Sec.  3175.113  Spot samples--general requirements.

    (a) If an FMP is not flowing at the time that a sample is due, a 
sample must be taken within 15 days after flow is re-initiated. 
Documentation of the non-flowing status of the FMP must be entered into 
GARVS as required under Sec.  3175.120(f).
    (b) The operator must notify the AO at least 72 hours before 
obtaining a spot sample as required by this subpart, or submit a 
monthly or quarterly schedule of spot samples to the AO in advance of 
taking samples.
    (c) Sample cylinder requirements. Sample cylinders must:
    (1) Comply with API 14.1, Subsection 9.1 (incorporated by 
reference, see Sec.  3175.30);
    (2) Have a minimum capacity of 300 cubic centimeters; and
    (3) Be cleaned before sampling under GPA 2166-05, Appendix A 
(incorporated by reference, see Sec.  3175.30), or an equivalent 
method. The operator must maintain documentation of cleaning (see Sec.  
3170.7), have the documentation available on site during sampling, and 
provide it to the BLM upon request.
    (d) Spot sampling using portable gas chromatographs. (1) Sampling 
separators, if used, must:
    (i) Be constructed of stainless steel;
    (ii) Be cleaned under GPA 2166-05, Appendix A (incorporated by 
reference, see Sec.  3175.30), or an equivalent method, prior to 
sampling. The operator must maintain documentation of cleaning (see 
Sec.  3170.7), have the documentation available on site during 
sampling, and provide it to the BLM upon request; and
    (iii) Be operated under GPA 2166-05, Appendix B.3 (incorporated by 
reference, see Sec.  3175.30).
    (2) The sample port and inlet to the sample line must be purged 
using the gas being sampled before completing the connection between 
them.
    (3) The portable GC must be operated, verified, and calibrated 
under Sec.  3175.118.
    (4) The documentation of verification or calibration required in 
Sec.  3175.118(d) must be available for inspection by the BLM at the 
time of sampling.
    (5) Minimum number of samples and analyses. (i) For low- and very-
low-volume FMPs, at least three samples must be taken and analyzed;
    (ii) For high-volume FMPs, samples must be taken and analyzed until 
the difference between the maximum heating value and minimum heating 
value calculated from three consecutive analyses is less than or equal 
to 16 Btu/scf;
    (iii) For very-high-volume FMPs, samples must be taken and analyzed 
until the difference between the maximum heating value and minimum 
heating value calculated from three consecutive analyses is less than 
or equal to 8 Btu/scf.
    (6) The heating value and relative density used for OGOR reporting 
must be:
    (i) The mean heating value and relative density calculated from the 
three analyses required in paragraph (d)(5) of this section;
    (ii) The median heating value and relative density calculated from 
the three analyses required in paragraph (d)(5) of this section; or
    (iii) Any other method approved by the BLM.


Sec.  3175.114   Spot samples--allowable methods.

    (a) Spot samples must be obtained using one of the following 
methods:
    (1) Purging--fill and empty method. Samples taken using this method 
must comply with GPA 2166-05, Section 9.1 (incorporated by reference, 
see Sec.  3175.30);
    (2) Helium ``pop'' method. Samples taken using this method must 
comply with GPA 2166-05, Section 9.5 (incorporated by reference, see 
Sec.  3175.30). The operator must maintain documentation demonstrating 
that the cylinder was evacuated and pre-charged before sampling and 
make the documentation available to the AO upon request;
    (3) Floating piston cylinder method. Samples taken using this 
method must comply with GPA 2166-05, Sections 9.7.1 to 9.7.3 
(incorporated by reference, see Sec.  3175.30). The operator must 
maintain documentation of the seal material and type of lubricant used 
and make the documentation available to the AO upon request;
    (4) Portable gas chromatograph. Samples taken using this method 
must comply with Sec.  3175.118; or
    (5) Other methods approved by the BLM (through the PMT) and posted 
at www.blm.gov.
    (b) If the operator uses either a purging--fill and empty method or 
a helium ``pop'' method, and if the flowing pressure at the sample port 
is less than or equal to 15 psig, the operator may also employ a 
vacuum-gathering system. Samples taken using a vacuum-gathering system 
must comply with API 14.1, Subsection 11.10 (incorporated by reference, 
see

[[Page 81627]]

Sec.  3175.30), and the samples must be obtained from the discharge of 
the vacuum pump.


Sec.  3175.115   Spot samples--frequency.

    (a) Unless otherwise required under paragraph (b) of this section, 
spot samples for all FMPs must be taken and analyzed at the frequency 
(once during every period, stated in months) prescribed in Table 1 to 
Sec.  3175.110.
    (b) After the time frames listed in paragraph (b)(1) of this 
section, the BLM may change the required sampling frequency for high-
volume and very-high-volume FMPs if the BLM determines that the 
sampling frequency required in Table 1 in Sec.  3175.110 is not 
sufficient to achieve the heating value uncertainty levels required in 
Sec.  3175.31(b).
    (1) Timeframes for implementation. (i) For high-volume FMPs, the 
BLM may change the sampling frequency no sooner than 2 years after the 
FMP begins measuring gas or January 19, 2021, whichever is later; and
    (ii) For very-high-volume FMPs, the BLM may change the sampling 
frequency or require compliance with paragraph (b)(5) of this section 
no sooner than 1 year after the FMP begins measuring gas or January 17, 
2020, whichever is later.
    (2) The BLM will calculate the new sampling frequency needed to 
achieve the heating value uncertainty levels required in Sec.  
3175.31(b). The BLM will base the sampling frequency calculation on the 
heating value variability. The BLM will notify the operator of the new 
sampling frequency.
    (3) The new sampling frequency will remain in effect until the 
heating value variability justifies a different frequency.
    (4) The new sampling frequency will not be more frequent than once 
every 2 weeks nor less frequent than once every 6 months.
    (5) For very-high-volume FMPs, the BLM may require the installation 
of a composite sampling system or on-line GC if the heating value 
uncertainty levels in Sec.  3175.31(b) cannot be achieved through spot 
sampling. Composite sampling systems or on-line gas chromatographs that 
are installed and operated in accordance with this section comply with 
the uncertainty requirement of Sec.  3175.31(b)(2).
    (c) The time between any two samples must not exceed the timeframes 
shown in Table 1 to this section.
[GRAPHIC] [TIFF OMITTED] TR17NO16.065

    (d) If a composite sampling system or an on-line GC is installed 
under Sec.  3175.116 or Sec.  3175.117, either on the operator's own 
initiative or in response to a BLM order for a very-high-volume FMP 
under paragraph (b)(5) of this section, it must be installed and 
operational no more than 30 days after the due date of the next sample.
    (e) The required sampling frequency for an FMP at which a composite 
sampling system or an on-line gas chromatograph is removed from service 
is prescribed in paragraph (a) of this section.


Sec.  3175.116   Composite sampling methods.

    (a) Composite samplers must be flow-proportional.
    (b) Samples must be collected using a positive-displacement pump.
    (c) Sample cylinders must be sized to ensure the cylinder capacity 
is not exceeded within the normal collection frequency.


Sec.  3175.117   On-line gas chromatographs.

    (a) On-line GCs must be installed, operated, and maintained under 
GPA 2166-05, Appendix D (incorporated by reference, see Sec.  3175.30), 
and the manufacturer's specifications, instructions, and 
recommendations.
    (b) The GC must comply with the verification and calibration 
requirements of Sec.  3175.118. The results of all verifications must 
be submitted to the AO upon request.
    (c) Upon request, the operator must submit to the AO the 
manufacturer's specifications and installation and operational 
recommendations.


Sec.  3175.118   Gas chromatograph requirements.

    (a) All GCs must be installed, operated, and calibrated under GPA 
2261-13 (incorporated by reference, see Sec.  3175.30).
    (b) Samples must be analyzed until the un-normalized sum of the 
mole percent of all gases analyzed is between 97 and 103 percent.
    (c) A GC may not be used to analyze any sample from an FMP until 
the verification meets the standards of this paragraph (c).

[[Page 81628]]

    (1) GCs must be verified under GPA 2261-13, Section 6 (incorporated 
by reference, see Sec.  3175.30), not less than once every 7 days.
    (2) All gases used for verification and calibration must meet the 
standards of GPA 2198-03, Sections 3 and 4 (incorporated by reference, 
see Sec.  3175.30).
    (3) All new gases used for verification and calibration must be 
authenticated prior to verification or calibration under the standards 
of GPA 2198-03, Section 5 (incorporated by reference, see Sec.  
3175.30).
    (4) The gas used to calibrate a GC must be maintained under Section 
6 of GPA 2198-03 (incorporated by reference, see Sec.  3175.30).
    (5) If the composition of the gas used for verification as 
determined by the GC varies from the certified composition of the gas 
used for verification by more than the reproducibility values listed in 
GPA 2261-13, Section 10 (incorporated by reference, see Sec.  3175.30), 
the GC must be calibrated under GPA 2261-13, Section 6 (incorporated by 
reference, see Sec.  3175.30).
    (6) If the GC is calibrated, it must be re-verified under paragraph 
(c)(5) of this section.
    (d) The operator must retain documentation of the verifications for 
the period required under Sec.  3170.6 of this part, and make it 
available to the BLM upon request. The documentation must include:
    (1) The components analyzed;
    (2) The response factor for each component;
    (3) The peak area for each component;
    (4) The mole percent of each component as determined by the GC;
    (5) The mole percent of each component in the gas used for 
verification;
    (6) The difference between the mole percents determined in 
paragraphs (d)(4) and (5) of this section, expressed in relative 
percent;
    (7) Evidence that the gas used for verification and calibration:
    (i) Meets the requirements of paragraph (c)(2) of this section, 
including a unique identification number of the calibration gas used, 
the name of the supplier of the calibration gas, and the certified list 
of the mole percent of each component in the calibration gas;
    (ii) Was authenticated under paragraph (c)(3) of this section prior 
to verification or calibration, including the fidelity plots; and
    (iii) Was maintained under paragraph (c)(4) of this section, 
including the fidelity plot made as part of the calibration run;
    (8) The chromatograms generated during the verification process;
    (9) The time and date the verification was performed; and
    (10) The name and affiliation of the person performing the 
verification.
    (e) Extended analyses must be taken in accordance with GPA 2286-14 
(incorporated by reference, see Sec.  3175.30) or other method approved 
by the BLM.


Sec.  3175.119   Components to analyze.

    (a) The gas must be analyzed for the following components:
    (1) Methane;
    (2) Ethane;
    (3) Propane;
    (4) Iso Butane;
    (5) Normal Butane;
    (6) Pentanes;
    (7) Hexanes + (C6+);
    (8) Carbon dioxide; and
    (9) Nitrogen.
    (b) When the concentration of C6+ exceeds 0.5 mole 
percent, the following gas components must also be analyzed:
    (1) Hexanes;
    (2) Heptanes;
    (3) Octanes; and
    (4) Nonanes +.
    (c) In lieu of testing each sample for the components required 
under paragraph (b) of this section, the operator may periodically test 
for these components and adjust the assumed C6+ composition 
to remove bias in the heating value (see Sec.  3175.126(a)(3)). The 
C6+ composition must be applied to the mole percent of 
C6+ analyses until the next analysis is done under paragraph 
(b) of this section. The minimum analysis frequency for the components 
listed in paragraph (b) of this section is as follows:
    (1) For high-volume FMPs, once per year; and
    (2) For very-high-volume FMPs, once every 6 months.


Sec.  3175.120   Gas analysis report requirements.

    (a) The gas analysis report must contain the following information:
    (1) The information required in Sec.  3170.7(g) of this part;
    (2) The date and time that the sample for spot samples was taken 
or, for composite samples, the date the cylinder was installed and the 
date the cylinder was removed;
    (3) The date and time of the analysis;
    (4) For spot samples, the effective date, if other than the date of 
sampling;
    (5) For composite samples, the effective start and end date;
    (6) The name of the laboratory where the analysis was performed;
    (7) The device used for analysis (i.e., GC, calorimeter, or mass 
spectrometer);
    (8) The make and model of analyzer;
    (9) The date of last calibration or verification of the analyzer;
    (10) The flowing temperature at the time of sampling;
    (11) The flowing pressure at the time of sampling, including units 
of measure (psia or psig);
    (12) The flow rate at the time of sampling;
    (13) The ambient air temperature at the time of sampling;
    (14) Whether or not heat trace or any other method of heating was 
used;
    (15) The type of sample (i.e., spot-cylinder, spot-portable GC, 
composite);
    (16) The sampling method if spot-cylinder (e.g., fill and empty, 
helium pop);
    (17) A list of the components of the gas tested;
    (18) The un-normalized mole percents of the components tested, 
including a summation of those mole percents;
    (19) The normalized mole percent of each component tested, 
including a summation of those mole percents;
    (20) The ideal heating value (Btu/scf);
    (21) The real heating value (Btu/scf), dry basis;
    (22) The hexane+ split, if applicable;
    (23) The pressure base and temperature base;
    (24) The relative density; and
    (25) The name of the company obtaining the gas sample.
    (b) Components that are listed on the analysis report, but not 
tested, must be annotated as such.
    (c) The heating value and relative density must be calculated under 
API 14.5 (incorporated by reference, see Sec.  3175.30).
    (d) The base supercompressibility must be calculated under AGA 
Report No. 8 (incorporated by reference, see Sec.  3175.30).
    (e) The operator must submit all gas analysis reports to the BLM 
within 15 days of the due date for the sample as specified in Sec.  
3175.115.
    (f) Unless a variance is granted, the operator must submit all gas 
analysis reports and other required related information electronically 
through the GARVS. The BLM will grant a variance to the electronic-
submission requirement only in cases where the operator demonstrates 
that it is a small business, as defined by the U.S. Small Business 
Administration, and does not have access to the Internet.


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

    (a) Unless otherwise specified on the gas analysis report, the 
effective date of a spot sample is the date on which the sample was 
taken.

[[Page 81629]]

    (b) The effective date of a spot gas sample may be no later than 
the first day of the production month following the operator's receipt 
of the laboratory analysis of the sample.
    (c) Unless otherwise specified on the gas analysis report, the 
effective date of a composite sample is the first of the month in which 
the sample was removed.
    (d) The provisions of this section apply only to OGORs, QTRs, and 
gas sample reports generated after January 17, 2017.


Sec.  3175.125   Calculation of heating value and volume

    (a) The heating value of the gas sampled must be calculated as 
follows:
    (1) Gross heating value is defined by API 14.5, Subsection 3.7 
(incorporated by reference, see Sec.  3175.30) and must be calculated 
under API 14.5, Subsection 7.1 (incorporated by reference, see Sec.  
3175.30); and
    (2) Real heating value must be calculated by dividing the gross 
heating value of the gas calculated under paragraph (a)(1) of this 
section by the compressibility factor of the gas at 14.73 psia and 
60[deg] F.
    (b) Average heating value determination. (1) If a lease, unit PA, 
or CA has more than one FMP, the average heating value for the lease, 
unit PA, or CA for a reporting month must be the volume-weighted 
average of heating values, calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR17NO16.066

    (2) If the effective date of a heating value for an FMP is other 
than the first day of the reporting month, the average heating value of 
the FMP must be the volume-weighted average of heating values, 
determined as follows:
[GRAPHIC] [TIFF OMITTED] TR17NO16.067


Where:

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

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


Sec.  3175.126   Reporting of heating value and volume.

    (a) The gross heating value and real heating value, or average 
gross heating value and average real heating value, as applicable, 
derived from all samples and analyses must be reported on the OGOR in 
units of Btu/scf under the following conditions:
    (1) Containing no water vapor (``dry''), unless the water vapor 
content has been determined through actual on-site measurement and 
reported on the gas analysis report. The heating value may not be 
reported on the basis of an assumed water-vapor content. Acceptable 
methods of measuring water vapor are:
    (i) Chilled mirror;
    (ii) Laser detectors; and
    (iii) Other methods approved by the BLM;
    (2) Adjusted to a pressure of 14.73 psia and a temperature of 
60[deg] F; and
    (3) For samples analyzed under Sec.  3175.119(a), and 
notwithstanding any provision of a contract between the operator and a 
purchaser or transporter, the composition of hexane+ is deemed to be:
    (i) 60 percent n-hexane, 30 percent n-heptane, and 10 percent n-
octane; or
    (ii) The composition determined under Sec.  3175.119(c).
    (b) The volume for royalty purposes must be reported on the OGOR in 
units of Mcf as follows:
    (1) The volume must not be adjusted for water-vapor content or any 
other factors that are not included in the calculations required in 
Sec.  3175.94 or Sec.  3175.103; and
    (2) The volume must match the monthly volume(s) shown in the 
unedited QTR(s) or integration statement(s) unless edits to the data 
are documented under paragraph (c) of this section.
    (c) Edits and adjustments to reported volume or heating value. (1) 
If for any reason there are measurement errors stemming from an 
equipment malfunction that results in discrepancies to the calculated 
volume or heating value of the gas, the volume or heating value 
reported during the period in which the volume or heating value error 
persisted must be estimated.
    (2) All edits made to the data before the submission of the OGOR 
must be documented and include verifiable justifications for the edits 
made. This documentation must be maintained under Sec.  3170.7 of this 
part and must be submitted to the BLM upon request.
    (3) All values on daily and hourly QTRs that have been changed or 
edited must be clearly identified and must be cross referenced to the 
justification required in paragraph (c)(2) of this section.
    (4) The volumes reported on the OGOR must be corrected beginning 
with the date that the inaccuracy occurred. If that date is unknown, 
the volumes must be corrected beginning with the production month that 
includes the date that is half way between the date of the previous 
verification and the most recent verification date.


Sec.  3175.130   Transducer testing protocol.

    The BLM will approve a particular make, model, and range of 
differential-pressure, static-pressure, or temperature transducer for 
use in an EGM system only if the testing performed on the transducer 
met all of the standards and requirements stated in Sec. Sec.  3175.131 
through 3175.135.


Sec.  3175.131   General requirements for transducer testing.

    (a) All testing must be performed by a qualified test facility.
    (b) Number and selection of transducers tested. (1) A minimum of 
five transducers of the same make, model, and URL, selected at random 
from the stock used to supply normal field operations, must be type-
tested.
    (2) The serial number of each transducer selected must be 
documented. The date, location, and batch identifier, if applicable, of 
manufacture must be ascertainable from the serial number.
    (3) For the purpose of this section, the term ``model'' refers to 
the base model number on which the BLM determines the transducer 
performance. For example: A manufacturer makes a transmitter with a 
model number 1234-XYZ, where ``1234'' identifies the transmitter cell, 
``X'' identifies the output type, ``Y'' identifies the mounting type, 
and ``Z'' identifies where the static pressure is taken. The testing 
under this section would only be required on the base model number 
(``1234''), assuming that ``X'', ``Y'', or ``Z'' does not affect the 
performance of the transmitter.
    (4) For multi-variable transducers, each cell URL must be tested 
only once under this section. For example: A manufacturer of a 
transducer measuring both differential and static pressure makes a 
model with available

[[Page 81630]]

differential-pressure URLs of 100 inches, 500 inches, and 1,000 inches, 
and static-pressure URLs of 250 psia, 1,000 psia, and 2,500 psia. 
Although there are nine possible combinations of differential-pressure 
and static-pressure URLs, only six tests are required to cover each 
cell URL.
    (c) Test conditions--general. The electrical supply must meet the 
following minimum tolerances:
    (1) Rated voltage: 1 percent uncertainty;
    (2) Rated frequency: 1 percent uncertainty;
    (3) Alternating current harmonic distortion: Less than 5 percent; 
and
    (4) Direct current ripple: Less than 0.10 percent uncertainty.
    (d) The input and output (if the output is analog) of each 
transducer must be measured with equipment that has a published 
reference uncertainty less than or equal to 25 percent of the published 
reference uncertainty of the transducer under test across the 
measurement range common to both the transducer under test and the test 
instrument. Reference uncertainty for both the test instrument and the 
transducer under test must be expressed in the units the transducer 
measures to determine acceptable uncertainty. For example, if the 
transducer under test has a published reference uncertainty of 0.05 percent of span, and a span of 0 to 500 psia, then this 
transducer has a reference accuracy of 0.25 psia (0.05 
percent of 500 psia). To meet the requirements of this paragraph (d), 
the test instrument in this example must have an uncertainty of 0.0625 psia or less (25 percent of 0.25 psia).
    (e) If the manufacturer's performance specifications for the 
transducer under test include corrections made by an external device 
(such as linearization), then the external device must be tested along 
with the transducer and be connected to the transducer in the same way 
as in normal field operations.
    (f) If the manufacturer specifies the extent to which the 
measurement range of the transducer under test may be adjusted downward 
(i.e., spanned down), then each test required in Sec. Sec.  3175.132 
and 3175.133 must be carried out at least at both the URL and the 
minimum upper calibrated limit specified by the manufacturer. For upper 
calibrated limits between the maximum and the minimum span that are not 
tested, the BLM will use the greater of the uncertainties measured at 
the maximum and minimum spans in determining compliance with the 
requirements of Sec.  3175.31(a).
    (g) After initial calibration, no calibration adjustments to the 
transducer may be made until all required tests in Sec. Sec.  3175.132 
and 3175.133 are completed.
    (h) For all of the testing required in Sec. Sec.  3175.132 and 
3175.133, the term ``tested for accuracy'' means a comparison between 
the output of the transducer under test and the test equipment taken as 
follows:
    (1) The following values must be tested in the order shown, 
expressed as a percent of the transducer span:
    (i) (Ascending values) 0, 10, 20, 30, 40, 50, 60, 70, 80, 90, and 
100; and
    (ii) (Descending values) 100, 90, 80, 70, 60, 50, 40, 30, 20, 10, 
and 0.
    (2) If the device under test is an absolute-pressure transducer, 
the ``0'' values listed in paragraphs (h)(1)(i) and (ii) of this 
section must be replaced with ``atmospheric pressure at the test 
facility;''
    (3) Input approaching each required test point must be applied 
asymptotically without overshooting the test point;
    (4) The comparison of the transducer and the test equipment 
measurements must be recorded at each required point; and
    (5) For static-pressure transducers, the following test point must 
be included for all tests:
    (i) For gauge-pressure transducers, a gauge pressure of -5 psig; 
and
    (ii) For absolute-pressure transducers, an absolute pressure of 5 
psia.


Sec.  3175.132   Testing of reference accuracy.

    (a) The following reference test conditions must be maintained for 
the duration of the testing:
    (1) Ambient air temperature must be between 59 [deg]F and 77 [deg]F 
and must not vary over the duration of the test by more than 2 [deg]F;
    (2) Relative humidity must be between 45 percent and 75 percent and 
must not vary over the duration of the test by more than 5 
percent;
    (3) Atmospheric pressure must be between 12.46 psi and 15.36 psi 
and must not vary over the duration of the test by more than 0.2 psi;
    (4) The transducer must be isolated from any externally induced 
vibrations;
    (5) The transducer must be mounted according to the manufacturer's 
specifications in the same manner as it would be mounted in normal 
field operations;
    (6) The transducer must be isolated from any external 
electromagnetic fields; and
    (7) For reference accuracy testing of differential-pressure 
transducers, the downstream side of the transducer must be vented to 
the atmosphere.
    (b) Before reference testing begins, the following pre-conditioning 
steps must be followed:
    (1) After power is applied to the transducer, it must be allowed to 
stabilize for at least 30 minutes before applying any input pressure or 
temperature;
    (2) The transducer must be exercised by applying three full-range 
traverses in each direction; and
    (3) The transducer must be calibrated according to manufacturer 
specifications if a calibration is required or recommended by the 
manufacturer.
    (c) Immediately following preconditioning, the transducer must be 
tested at least three times for accuracy under Sec.  3175.131(h). The 
results of these tests must be used to determine the transducer's 
reference accuracy under Sec.  3175.135.


Sec.  3175.133   Testing of influence effects.

    (a) General requirements. (1) Reference conditions (see Sec.  
3175.132), with the exception of the influence effect being tested 
under this section, must be maintained for the duration of these tests.
    (2) After completing the required tests for each influence effect 
under this section, the transducer under test must be returned to 
reference conditions and tested for accuracy under Sec.  3175.132.
    (b) Ambient temperature. (1) The transducer's accuracy must be 
tested at the following temperatures ([deg]F): +68, +104, +140, + 68, 
0, -4, -40, +68.
    (2) The ambient temperature must be held to 4 [deg]F 
from each required temperature during the accuracy test at each point.
    (3) The rate of temperature change between tests must not exceed 
2[deg] F per minute.
    (4) The transducer must be allowed to stabilize at each test 
temperature for at least 1 hour.
    (5) For each required temperature test point listed in this 
paragraph, the transducer must be tested for accuracy under Sec.  
3175.131(h).
    (c) Static-pressure effects (differential-pressure transducers 
only). (1) For single-variable transducers, the following pressures 
must be applied equally to both sides of the transducer, expressed in 
percent of maximum rated working pressure: 0, 50, 100, 75, 25, 0.
    (2) For multivariable transducers, the following pressures must be 
applied equally to both sides of the transducer, expressed in percent 
of the URL of the static-pressure transducer: 0, 50, 100, 75, 25, 0.
    (3) For each point required in paragraphs (c)(1) and (2) of this 
section, the transducer must be tested for accuracy under Sec.  
3175.131(h).

[[Page 81631]]

    (d) Mounting position effects. The transducer must be tested for 
accuracy at four different orientations under Sec.  3175.131(h) as 
follows:
    (1) At an angle of -10[deg] from a vertical plane;
    (2) At an angle of +10[deg] from a vertical plane;
    (3) At an angle of -10[deg] from a vertical plane perpendicular to 
the vertical plane required in paragraphs (d)(1) and (2) of this 
section; and
    (4) At an angle of +10[deg] from a vertical plane perpendicular to 
the vertical plane required in paragraphs (d)(1) and (2) of this 
section.
    (e) Over-range effects. (1) A pressure of 150 percent of the URL, 
or to the maximum rated working pressure of the transducer, whichever 
is less, must be applied for at least 1 minute.
    (2) After removing the applied pressure, the transducer must be 
tested for accuracy under Sec.  3175.131(h).
    (3) No more than 5 minutes must be allowed between performing the 
procedures described in paragraphs (e)(1) and (2) of this section.
    (f) Vibration effects. (1) An initial resonance test must be 
conducted by applying the following test vibrations to the transducer 
along each of the three major axes of the transducer while measuring 
the output of the transducer with no pressure applied:
    (i) The amplitude of the applied test frequency must be at least 
0.35mm below 60 Hertz (Hz) and 49 meter per second squared (m/s\2\) 
above 60 Hz; and
    (ii) The applied frequency must be swept from 10 Hz to 2,000 Hz at 
a rate not greater than 0.5 octaves per minute.
    (2) After the initial resonance search, an endurance conditioning 
test must be conducted as follows:
    (i) Twenty frequency sweeps from 10 Hz to 2,000 Hz to 10 Hz must be 
applied to the transducer at a rate of 1 octave per minute, repeated 
for each of the 3 major axes; and
    (ii) The measurement of the transducer's output during this test is 
unnecessary.
    (3) A final resonance test must be conducted under paragraph (f)(1) 
of this section.


Sec.  3175.134   Transducer test reporting.

    (a) Each test required by Sec. Sec.  3175.131 through 3175.133 must 
be fully documented by the test facility performing the tests. The 
report must indicate the results for each required test and include all 
data points recorded.
    (b) The report must be submitted to the PMT. If the PMT determines 
that all testing was completed as required by Sec. Sec.  3175.131 
through 3175.133, it will make a recommendation that the BLM approve 
the transducer make, model, and range, along with the reference 
uncertainty, influence effects, and any operating restrictions, and 
posts them to the BLM's website at www.blm.gov as an approved device.


Sec.  3175.135   Uncertainty determination.

    (a) Reference uncertainty calculations for each transducer of a 
given make, model, URL, and turndown must be determined as follows (the 
result for each transducer is denoted by the subscript i):
    (1) Maximum error (Ei). The maximum error for each transducer is 
the maximum difference between any input value from the test device and 
the corresponding output from the transducer under test for any 
required test point, and must be expressed in percent of transducer 
span.
    (2) Hysteresis (Hi). The testing required in Sec.  3175.132 
requires at least three pairs of tests using both ascending test points 
(low to high) and descending test points (high to low) of the same 
value. Hysteresis is the maximum difference between the ascending value 
and the descending value for any single input test value of a test 
pair. Hysteresis must be expressed in percent of span.
    (3) Repeatability (Ri). The testing required under Sec.  3175.132 
requires at least three pairs of tests using both ascending test points 
(low to high) and descending test points (high to low) of the same 
value. Repeatability is the maximum difference between the value of any 
of the three ascending test points for a given input value or of the 
three descending test points for a given value. Repeatability must be 
expressed in percent of span.
    (b) Reference uncertainty of a transducer. The reference 
uncertainty of each transducer of a given make, model, URL, and 
turndown (Ur,i) must be determined as follows:
[GRAPHIC] [TIFF OMITTED] TR17NO16.068


Where Ei, Hi, and Ri, are described in 
paragraph (a) of this section. Reference uncertainty is expressed in 
percent of span.
    (c) Reference uncertainty for the make, model, URL, and turndown of 
a transducer (Ur) must be determined as follows:

Ur = s x tdist

Where:

s = the standard deviation of the reference uncertainties determined 
for each transducer (Ur,i)
tdist = the ``t-distribution'' constant as a function of degrees of 
freedom (n-1) and at a 95 percent confidence level, where n = the 
number of transducers of a specific make, model, URL, and turndown 
tested (minimum of 5)

    (d) Influence effects. The uncertainty from each influence effect 
required to be tested under Sec.  3175.133 must be determined as 
follows:
    (1) Zero-based errors of each transducer. Zero-based errors from 
each influence test must be determined as follows:
[GRAPHIC] [TIFF OMITTED] TR17NO16.069

Where:

subscript i represents the results for each transducer tested of a 
given make, model, URL, and turndown
subscript n represents the results for each influence effect test 
required under Sec.  3175.133
Ezero,n,i = Zero-based error for influence effect n, for 
transducer i, in percent of span per increment of influence effect
Mn = the magnitude of influence effect n (e.g., 1,000 psi 
for static-pressure effects, 50 [deg]F for ambient temperature 
effects)

And:

DZn,i = Zn,i-Zref ,i

Where:

Zn,i = the average output from transducer i with zero 
input from the test device, during the testing of influence effect n
Zref,i = the average output from transducer i with zero 
input from the test device, during reference testing.

    (2) Span-based errors of each transducer. Span-based errors from 
each influence effect must be determined as follows:
[GRAPHIC] [TIFF OMITTED] TR17NO16.070

Where:

Espan,n,i = Span-based error for influence effect n, for 
transducer i, in percent of reading per increment of influence 
effect
Sn,i = the average output from transducer i, with full 
span applied from the test device, during the testing for influence 
effect n.

    (3) Zero- and span-based errors due to influence effects for a 
make, model, URL, and turndown of a transducer must be determined as 
follows:

Ez,n = sz,n x tdist

Es,n = ss,n x tdist

Where:

Ez,n = the zero-based error for a make, model, URL, and 
turndown of transducer, for influence effect n, in percent of span 
per unit of magnitude for the influence effect
Es,n = the span-based error for a make, model, URL, and 
turndown of transducer, for influence effect n, in percent of 
reading per unit of magnitude for the influence effect

[[Page 81632]]

sz,n = the standard deviation of the zero-based 
differences from the influence effect tests under Sec.  3175.133 and 
the reference uncertainty tests, in percent
ss,n = the standard deviation of the span-based 
differences from the influence effect tests under Sec.  3175.133 and 
the reference uncertainty tests, in percent
tdist = the ``t-distribution'' constant as a function of 
degrees of freedom (n-1) and at a 95 percent confidence level, where 
n = the number of transducers of a specific make, model, URL, and 
turndown tested (minimum of 5).


Sec.  3175.140   Flow-computer software testing.

    The BLM will approve a particular version of flow-computer software 
for use in a specific make and model of flow computer only if the 
testing performed on the software meets all of the standards and 
requirements in Sec. Sec.  3175.141 through 3175.144. Type-testing is 
required for each software version that affects the calculation of flow 
rate, volume, heating value, live input variable averaging, flow time, 
or the integral value. Software updates or changes that do not affect 
these items do not require BLM approval.


Sec.  3175.141   General requirements for flow-computer software 
testing.

    (a) Test facility. All testing must be performed by a qualified 
test facility not affiliated with the flow-computer manufacturer.
    (b) Selection of flow-computer software to be tested. (1) Each 
software version tested must be identical to the software version 
installed at FMPs for normal field operations.
    (2) Each software version must have a unique identifier.
    (c) Testing method. Input variables may be either:
    (1) Applied directly to the hardware registers; or
    (2) Applied physically to a transducer. If input variables are 
applied physically to a transducer, the values received by the hardware 
registers from the transducer must be recorded.
    (d) Pass-fail criteria. (1) For each test listed in Sec. Sec.  
3175.142 and 3175.143, the value(s) required to be calculated by the 
software version under test must be compared to the value(s) calculated 
by BLM-approved reference software, using the same digital input for 
both.
    (2) The software under test may be used at an FMP only if the 
difference between all values calculated by the software version under 
test and the reference software is less than 50 parts per million 
(0.005 percent) and the results of the tests required in Sec. Sec.  
3175.142 and 3175.143 are satisfactory to the PMT. If the test results 
are satisfactory, the BLM will identify the software version tested as 
acceptable for use on its website at www.blm.gov.


Sec.  3175.142   Required static tests.

    (a) Instantaneous flow rate. The instantaneous flow rates must meet 
the criteria in Sec.  3175.141(d) for each test identified in Table 1 
to this section, using the gas compositions identified in Table 2 to 
this section, as prescribed in Table 1 to this section.
[GRAPHIC] [TIFF OMITTED] TR17NO16.071


[[Page 81633]]


[GRAPHIC] [TIFF OMITTED] TR17NO16.072

    (b) Sums and averages. (1) Fixed input values from test 2 in Table 
1 to this section must be applied for a period of at least 24 hours.
    (2) At the conclusion of the 24-hour period, the following hourly 
and daily values must meet the criteria in Sec.  3175.141(d):
    (i) Volume;
    (ii) Integral value;
    (iii) Flow time;
    (iv) Average differential pressure;
    (v) Average static pressure; and
    (vi) Average flowing temperature.
    (c) Other tests. The following additional tests must be performed 
on the flow-computer software:
    (1) Each parameter of the configuration log must be changed to 
ensure the event log properly records the changes according to the 
variables listed in Sec.  3175.104(c); and
    (2) Inputs simulating a 15 percent and 150 percent over-range of 
the differential and static-pressure transducer's calibrated span must 
be entered to verify that the over-range condition triggers an alarm or 
an entry in the event log.


Sec.  3175.143   Required dynamic tests.

    (a) Square wave test. The pressures and temperatures must be 
applied to the software revision under test for at least 60 minutes as 
follows:
    (1) Differential pressure. The differential pressure must be cycled 
from a low value, below the no-flow cutoff, to a high value of 
approximately 80 percent of the upper calibrated limit of the 
differential-pressure transducer. The cycle must approximate a square 
wave pattern with a period of 60 seconds, and the maximum and minimum 
values must be the same for each cycle;
    (2) Static pressure. The static pressure must be cycled between 
approximately 20 percent and approximately 80 percent of the upper 
calibrated limit of the static-pressure transducer in a square wave 
pattern identical to the cycling pattern used for the differential 
pressure. The maximum and minimum values must be the same for each 
cycle;
    (3) Temperature. The temperature must be cycled between 
approximately 20 [deg]F and approximately 100 [deg]F in a square wave 
pattern identical to the cycling pattern used for the differential 
pressure. The maximum and minimum values must be the same for each 
cycle; and
    (4) At the conclusion of the 1-hour period, the following hourly 
values must meet the criteria in Sec.  3175.141(d):
    (i) Volume;
    (ii) Integral value;
    (iii) Flow time;
    (iv) Average differential pressure;
    (v) Average static pressure; and
    (vi) Average flowing temperature.
    (b) Sawtooth test. The pressures and temperatures must be applied 
to the software revision under test for 24 hours as follows:
    (1) Differential pressure. The differential pressure must be cycled 
from a low value, below the no-flow cutoff, to a high value of 
approximately 80 percent of the maximum value of differential pressure 
for which the flow computer is designed. The cycle must approximate a 
linear sawtooth pattern between the low value and the high value and 
there must be 3 to 10 cycles per hour. The no-flow period between 
cycles must last approximately 10 percent of the cycle period;
    (2) Static pressure. The static pressure must be cycled between 
approximately 20 percent and approximately 80 percent of the maximum 
value of static pressure for which the flow computer is designed. The 
cycle must approximate a linear sawtooth pattern between the low value 
and the high value and there must be 3 to 10 cycles per hour;
    (3) Temperature. The temperature must be cycled between 
approximately

[[Page 81634]]

20 [deg]F and approximately 100 [deg]F. The cycle should approximate a 
linear sawtooth pattern between the low value and the high value and 
there must be 3 to 10 cycles per hour; and
    (4) At the conclusion of the 24-hour period, the following hourly 
and daily values must meet the criteria in Sec.  3175.141(d):
    (i) Volume;
    (ii) Integral value;
    (iii) Flow time;
    (iv) Average differential pressure;
    (v) Average static pressure; and
    (vi) Average flowing temperature.
    (c) Random test. The pressures and temperatures must be applied to 
the software revision under test for 24 hours as follows:
    (1) Differential pressure. Differential-pressure random values must 
range from a low value, below the no-flow cutoff, to a high value of 
approximately 80 percent of the upper calibrated limit of the 
differential-pressure transducer. The no-flow period between cycles 
must last for approximately 10 percent of the test period;
    (2) Static pressure. Static-pressure random values must range from 
a low value of approximately 20 percent of the upper calibrated limit 
of the static-pressure transducer, to a high value of approximately 80 
percent of the upper calibrated limit of the static-pressure 
transducer;
    (3) Temperature. Temperature random values must range from 
approximately 20 [deg]F to approximately 100 [deg]F; and
    (4) At the conclusion of the 24-hour period, the following hourly 
values must meet the criteria in Sec.  3175.141(d):
    (i) Volume;
    (ii) Integral value;
    (iii) Flow time;
    (iv) Average differential pressure;
    (v) Average static pressure; and
    (vi) Average flowing temperature.
    (d) Long-term volume accumulation test. (1) Fixed inputs of 
differential pressure, static pressure, and temperature must be applied 
to the software version under test to simulate a flow rate greater than 
500,000 Mcf/day for a period of at least 7 days.
    (2) At the end of the 7-day test period, the accumulated volume 
must meet the criteria in Sec.  3175.141(d).


Sec.  3175.144   Flow-computer software test reporting.

    (a) The test facility performing the tests must fully document each 
test required by Sec. Sec.  3175.141 through 3175.143. The report must 
indicate the results for each required test and include all data points 
recorded.
    (b) The report must be submitted to the AO by the operator or the 
manufacturer. If the PMT determines all testing was completed as 
required by this section, it will make a recommendation that the BLM 
approve the software version and post it on the BLM's website at 
www.blm.gov as approved software.


Sec.  3175.150   Immediate assessments.

    (a) Certain instances of noncompliance warrant the imposition of 
immediate assessments upon discovery. Imposition of any of these 
assessments does not preclude other appropriate enforcement actions.
    (b) The BLM will issue the assessments for the violations listed as 
follows:
[GRAPHIC] [TIFF OMITTED] TR17NO16.073


[[Page 81635]]



Appendix A to Subpart 3175--Table of Atmospheric Pressures
[GRAPHIC] [TIFF OMITTED] TR17NO16.074


[[Page 81636]]


[GRAPHIC] [TIFF OMITTED] TR17NO16.075

[FR Doc. 2016-25410 Filed 11-16-16; 8:45 am]
 BILLING CODE 4310-84-P