[Federal Register Volume 80, Number 197 (Tuesday, October 13, 2015)]
[Proposed Rules]
[Pages 61646-61715]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2015-25556]



[[Page 61645]]

Vol. 80

Tuesday,

No. 197

October 13, 2015

Part IV





Department of the Interior





-----------------------------------------------------------------------





Bureau of Land Management





-----------------------------------------------------------------------





43 CFR Parts 3160 and 3170





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

  Federal Register / Vol. 80 , No. 197 / Tuesday, October 13, 2015 / 
Proposed Rules  

[[Page 61646]]


-----------------------------------------------------------------------

DEPARTMENT OF THE INTERIOR

Bureau of Land Management

43 CFR Parts 3160 and 3170

[15X.LLWO300000.L13100000.NB0000]
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: Proposed rule.

-----------------------------------------------------------------------

SUMMARY: This proposed rule would revise and replace Onshore Oil and 
Gas Order No. 5 (Order 5) with a new regulation that would be codified 
in the Code of Federal Regulations. This proposed rule would establish 
the minimum standards for accurate measurement and proper reporting of 
all gas removed or sold from Federal and Indian leases (except the 
Osage Tribe), units, unit participating areas, and areas subject to 
communitization agreements, by providing a system for production 
accountability by operators, lessees, purchasers, and transporters. 
This proposed rule would include requirements for the hardware and 
software related to approved metering equipment, overall measurement 
performance standards, and reporting and record keeping. The proposed 
rule would identify certain specific acts of noncompliance that would 
result in an immediate assessment and would provide a process for the 
BLM to consider variances from the requirements of this proposed rule.

DATES: Send your comments on this proposed rule to the BLM on or before 
December 14, 2015. The BLM is not obligated to consider any comments 
received after the above date in making its decision on the final rule.
    If you wish to comment on the information collection requirements 
in this proposed rule, please note that the Office of Management and 
Budget (OMB) is required to make a decision concerning the collection 
of information contained in this proposed rule between 30 to 60 days 
after publication of this document in the Federal Register. Therefore, 
a comment to OMB is best assured of having its full effect if OMB 
receives it by November 12, 2015.

ADDRESSES: Mail: U.S. Department of the Interior, Director (630), 
Bureau of Land Management, Mail Stop 2134 LM, 1849 C St. NW., 
Washington, DC 20240, Attention: 1004-AE17. Personal or messenger 
delivery: 20 M Street SE., Room 2134LM, Washington, DC 20003. Federal 
eRulemaking Portal: http://www.regulations.gov. Follow the instructions 
at this Web site.
    Comments on the information collection burdens: Fax: Office of 
Management and Budget (OMB), Office of Information and Regulatory 
Affairs, Desk Officer for the Department of the Interior, fax 202-395-
5806. Electronic mail: [email protected]. Please indicate 
``Attention: OMB Control Number 1004-XXXX,'' regardless of the method 
used to submit comments on the information collection burdens. If you 
submit comments on the information collection burdens, you should 
provide the BLM with a copy of your comments, at one of the addresses 
shown above, so that we can summarize all written comments and address 
them in the final rule preamble.

FOR FURTHER INFORMATION CONTACT: Richard Estabrook, petroleum engineer, 
Division of Fluid Minerals, 707-468-4052. 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 Information Relay Service (FIRS) at 1-800-877-8339 
to contact the above individual during normal business hours. FIRS 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. The information collection request for this proposed 
rule has been submitted to OMB for review under 44 U.S.C. 3507(d). A 
copy of the request can be obtained from the BLM by electronic mail 
request to Jennifer Spencer at [email protected] or by telephone request 
to 202-912-7146. You may also review the information collection request 
online at http://www.reginfo.gov/public/do/PRAMain.

SUPPLEMENTARY INFORMATION:

Executive Summary

    The BLM's regulations that govern how gas produced from onshore 
Federal and Indian leases is measured and accounted for are more than 
25 years old and need to be updated to be consistent with modern 
industry practices. Federal laws, metering technology, and industry 
standards have changed significantly since the BLM adopted Order 5 in 
1989. In a number of separate reports, three outside independent 
entities--the Interior Secretary's Subcommittee on Royalty Management 
(the Subcommittee) in 2007, the Department of the Interior's Office of 
the Inspector General (OIG) in 2009, and the Government Accountability 
Office (GAO) in 2010, 2011, 2013, and 2015--have repeatedly recommended 
that the BLM evaluate its gas measurement guidance and regulations to 
ensure that operators pay the proper royalties. Specifically, these 
groups found that Interior 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 technologies or processes are not addressed in the 
future. As explained below, the provisions of this proposed rule 
respond to these recommendations by the Subcommittee, the GAO, and the 
OIG.
    The BLM's oil and gas program is one of the most important mineral 
leasing programs in the Federal Government. Domestic production from 
Federal and Indian onshore oil and gas leases accounts for 
approximately 10 percent of the nation's natural gas supply and 7 
percent of its oil. In Fiscal Year (FY) 2014, the Office of Natural 
Resources Revenue (ONRR) reported that onshore Federal oil and gas 
leases produced about 148 million barrels of oil, 2.48 trillion cubic 
feet of natural gas, and 2.9 billion gallons of natural gas liquids, 
with a market value of more than $27 billion and generating royalties 
of almost $3.1 billion. Nearly half of these revenues are distributed 
to the States in which the leases are located. Leases on Tribal and 
Indian lands produced 56 million barrels of oil, 240 billion cubic feet 
of natural gas, 182 million gallons of natural gas liquids, with a 
market value of almost $6 billion and generating royalties of over $1 
billion that were all distributed to the applicable tribes and 
individual allottee owners. Despite the magnitude of this production, 
the BLM's rules governing how that gas is measured and accounted for 
are more than 25 years old and need to be updated and strengthened. 
Federal laws, technology, and industry standards have all changed 
significantly in that time.
    The Secretary of the Interior has the authority under various 
Federal and Indian mineral leasing laws to manage oil and gas 
operations. The Secretary has delegated this authority to the BLM, 
which issued onshore oil and gas operating regulations codified at 43 
CFR part 3160. Over the years, the BLM issued seven Onshore Oil and Gas 
Orders that deal with different aspects of oil and gas production. 
These Orders were published in the Federal Register, both for public 
comment and in final form, but they do not appear in the Code of 
Federal Regulations (CFR). This proposed rule would replace Order 5,

[[Page 61647]]

Measurement of Gas, with a new regulation that would be codified in the 
CFR.
    The discussion that immediately follows summarizes and briefly 
explains the most significant changes proposed in this rule. Each of 
these will be 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 discussion.

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

    The most significant proposed change would be new requirements for 
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. So 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. Under the flow equation, a 10 percent error in 
relative density would result in a 5 percent error in the volume 
calculation. Both heating value and relative density are determined 
from the same gas sample.
    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 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 which found significant sample-to-sample variability in heating 
value and relative density at many of the 180 gas facility measurement 
points (FMP) it analyzed. The ``BLM Gas Variability Study Final 
Report,'' 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 in 
heating value and relative density in this study was 5.09 
percent, which, across the board, could amount to $127 
million in royalty based on 2008 total onshore Federal and Indian 
royalty payments of about $2.5 billion (p. 16). Uncertainty is a 
statistical range of error that indicates the risk of measurement 
error.
    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 a number of 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 proposed rule would strengthen the BLM's regulations on 
measuring heating value and relative density by requiring operators to 
sample all meters more frequently than currently required under Order 
5, except marginal-volume meters (measuring 15 Mcf/day or less) whose 
sampling frequency (i.e., annually) would not change. Low-volume FMPs 
(measuring more than 15 Mcf/day, but less than or equal to 100 Mcf/day) 
would have to be sampled every 6 months; high-volume FMPs (measuring 
more than 100 Mcf/day, but less than or equal to 1,000 Mcf/day) would 
initially be sampled every 3 months; very-high-volume FMPs (measuring 
more than 1,000 Mcf/day) would initially be sampled every month.
    The proposed rule would also set 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 developing this proposed 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 which has very consistent 
heating values from one sample to the next. If a high- or very-high-
volume FMP did not meet these proposed heating-value uncertainty 
limits, the BLM would adjust the sampling frequency at that FMP until 
the heating value meets the proposed uncertainty standards. If a high- 
or very-high-volume FMP continues to not meet the uncertainty 
standards, the BLM could require the installation of composite samplers 
or on-line gas chromatographs, which automatically sample gas at 
frequent intervals.
    In addition to prescribing uncertainty standards and more frequent 
sampling, this proposed rule also would improve measurement and 
reporting of heating values and relative density by setting standards 
for gas sampling and analysis. These proposed standards would specify 
sampling locations and methods, analysis methods, and the minimum 
number of components that would have to be analyzed. The proposed 
standards would also set requirements for how and when operators report 
the results to the BLM and ONRR, and would define the effective date of 
the heating value and relative density that is determined from the 
sample.

2. Meter Inspections (Sec.  3175.80)

    This proposed rule would require 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. Visual meter tube inspections would be 
required once every 5 years at low-volume FMPs, once every 2 years at 
high-volume FMPs, and yearly at very-high-volume FMPs. The BLM could 
increase this frequency and require a detailed meter-tube inspection of 
a low-volume FMP meter if the visual inspection identifies any issues 
or if the meter tube operates in adverse conditions, such as with 
corrosive or erosive gas flow. A detailed meter-tube inspection 
involves removing or disassembling the meter run. Detailed meter-tube 
inspections would be required once every 10 years at high-volume FMPs 
and once every 5 years at very-high-volume FMPs. Operators would have 
to replace meter tubes that no longer meet the requirements proposed in 
this rule.

[[Page 61648]]

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

    The proposed rule would increase routine meter verification or 
calibration requirements for metering equipment at very-high-volume 
FMPs and decrease the requirements at marginal-volume FMPs. 
Verification frequency would be unchanged for high-volume FMPs, as well 
as for low-volume FMPs that use mechanical recorder systems. 
Verification frequency would be decreased for low-volume FMPs using 
electronic gas measurement (EGM) systems.
    Under Order 5, all meters must undergo routine verification every 3 
months, regardless of the throughput volume. This proposed rule would 
require monthly verification for very-high-volume FMPs, while the 
verification requirement for high-volume FMPs would remain at every 3 
months. The rationale for this proposed change is that the consequences 
of measurement and royalty-calculation errors at very-high-volume FMPs 
are more serious than they are at high-, low-, and marginal-volume 
FMPs. The schedule for routine verification for low- and marginal-
volume FMPs that use EGM systems would decrease to every 6 months for 
low-volume FMPs and yearly for marginal-volume FMPs.
    The routine verification schedule for low- and marginal-volume FMPs 
that use mechanical chart recorders would be every 3 months for low-
volume FMPs and every 6 months for marginal-volume FMPs. The proposed 
rule would restrict the use of mechanical chart recorders to low- and 
marginal-volume FMPs because the accuracy and performance of mechanical 
chart recorders is not defined well enough for the BLM to quantify 
overall measurement uncertainty. Between 80 percent and 90 percent of 
gas meters at Federal onshore and Indian FMPs use EGM systems.

4. Requirements for EGM Systems (Sec. Sec.  3175.30, 3175.100 through 
3175.104, and 3175.130 through 3175.144)

    Although industry has used EGM systems for about 30 years, Order 5 
does not address them. Instead, the BLM has regulated their use through 
statewide Notices to Lessees (NTLs), which do not address many aspects 
unique to EGMs, such as volume calculation and data-gathering and 
retention requirements. This proposed rule includes many of the 
existing NTL requirements for EGM systems and adds some new ones 
relating to on-site information, gauge lines, verification, test 
equipment, calculations, and information generated and retained by the 
EGM systems. The proposed rule would make a significant change in those 
requirements by revising the maximum flow-rate uncertainty that is 
currently allowed under existing statewide NTLs. Currently, flow-rate 
equipment at FMPs that measure more than 100 Mcf/day is required to 
meet a 3 percent uncertainty level. The proposed rule would 
maintain that requirement for high-volume FMPs. However, under this 
proposed rule, equipment at very-high-volume FMPs would have to comply 
with a new 2 percent uncertainty requirement. Consistent 
with existing guidance, flow-rate equipment at FMPs that measure less 
than 100 Mcf/day would continue to be exempt from these uncertainty 
requirements. The BLM would maintain this exemption because it believes 
that compliance costs for these wells could cause some operators to 
shut in their wells instead of making changes. The BLM believes the 
royalties lost by such shut-ins would exceed any royalties that might 
be gained through upgrades at such facilities. The BLM is interested in 
any additional information about costs of compliance relative to 
royalty lost from maintaining the existing exemption.
    One area that existing NTLs do not address and that this proposed 
rule would address 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 is 
programmed into the flow computers, to calculate volumes and flow 
rates. Currently, the BLM must accept 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 proposed rule would require operators or 
manufacturers to ``type test'' transducers and flow-computer software 
at independent testing facilities, using a standard testing protocol, 
to quantify the uncertainty of transducers and flow-computer software 
that are already in use and that will be used in the future. The test 
results would then be incorporated into the calculation of overall 
measurement uncertainty for each piece of equipment tested.
    An integral part of the BLM's evaluation process would be the 
Production Measurement Team (PMT), made up of measurement experts 
designated by the BLM.\1\ The proposed rule would have 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 
would post the make, model, and range of the transducer or software 
version on the BLM Web site as being appropriate for use. The BLM would 
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, or new measurement sampling, or analysis methods.

    \1\ The PMT would be distinguished from the Department of the 
Interior's Gas and Oil Measurement Team (DOI GOMT), which consists 
of members with gas or oil measurement expertise from the BLM, the 
ONRR, and the Bureau of Safety and Environmental Enforcement (BSEE). 
BSEE handles production accountability for Federal offshore leases. 
The DOI GOMT is a coordinating body that enables the BLM and BSEE to 
consider measurement issues and track developments of common concern 
to both agencies. The BLM is not proposing a dual-agency approval 
process for use of new measurement technologies for onshore leases. 
The BLM anticipates that the members of the BLM PMT would 
participate as part of the DOI GOMT.

I. Public Comment procedures
II. Background
III. Discussion of Proposed Rule
IV. Onshore Order Public Meetings
V. Procedural Matters

I. Public Comment Procedures

    If you wish to comment on the proposed rule, you may submit your 
comments by any one of several methods specified see ADDRESSES. If you 
wish to comment on the information collection requirements, you should 
send those comments directly to the OMB as outlined, see ADDRESSES; 
however, we ask that you also provide a copy of those comments to the 
BLM.
    Please make your comments as specific as possible by confining them 
to issues for which comments are sought in this notice, and explain the 
basis for your comments. The comments and recommendations that will be 
most useful and likely to influence agency decisions are:
    1. Those supported by quantitative information or studies; and
    2. Those that include citations to, and analyses of, the applicable 
laws and regulations.
    The BLM is not obligated to consider or include in the 
Administrative Record for the rule comments received after the close of 
the comment period (see DATES) or comments delivered to an address 
other than those listed above (see ADDRESSES).
    Comments, including names and street addresses of respondents, will 
be available for public review at the

[[Page 61649]]

address listed under ADDRESSES during regular hours (7:45 a.m. to 4:15 
p.m.), Monday through Friday, except holidays.
    Before including your address, phone number, email address, or 
other personal identifying information in your comment, you should be 
aware that your entire comment--including your personal identifying 
information--may be made publicly available at any time. While you can 
ask us in your comment to withhold your personal identifying 
information from public review, we cannot guarantee that we will be 
able to do so.

II. Background

    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. Although they are not codified in the CFR, all Onshore Orders 
have been issued under Administrative Procedure Act notice and comment 
rulemaking procedures and apply nationwide to all Federal and Indian 
(except the Osage Tribe) onshore oil and gas leases. The table in 43 
CFR 3164.1(b) lists the existing Orders. This proposed rule would 
update and replace Order 5, which supplements primarily 43 CFR 3162.4, 
3162.7-3, subpart 3163, and subpart 3165. Section 3162.4 covers records 
and reports. Section 3162.7-3 covers the measurement of gas produced 
from Federal and Indian (except the Osage Tribe) oil and gas leases. 
Subpart 3163 covers non-compliance, assessments, and civil penalties. 
Subpart 3165 covers relief, conflicts, and appeals. Order 5 has been in 
effect since March 27, 1989 (see 54 FR 8100).
    This proposed rule would also supersede the following statewide 
NTLs:
     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
     CO NTL 2014-01, May 19, 2014
    Although Order 5 and the statewide NTLs listed above would be 
superseded by this rule, their provisions would remain in effect for 
measurement facilities already in place on the effective date of the 
final rule through the phase-in periods specified in proposed Sec.  
3175.60(c) and (d).
    Part of the Department of the Interior's responsibility in ensuring 
correct payment of royalty on gas extracted from Federal onshore and 
Indian leases is to achieve accurate measurement, proper reporting, and 
accountability.
    In 2007, the Secretary of the Interior commissioned the 
Subcommittee to report to the Royalty Policy Committee (RPC), which is 
chartered under the Federal Advisory Committee Act, to provide advice 
to the Secretary and other Departmental officials responsible for 
managing mineral leasing activities and to provide a forum for members 
of the public to voice their concerns about mineral leasing activities. 
The proposed rule is in part a result of the recommendations contained 
in the Subcommittee's report, which was issued on December 17, 2007. 
The proposed changes in this rule also address findings and 
recommendations made in two GAO reports and one OIG report, including: 
(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).
    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 Interior provide Department-wide 
guidance on measurement technologies not addressed in current 
regulations and approve variances for measurement technologies in 
instances when the technologies are not addressed in current 
regulations or Department-wide guidance (see ibid., p. 80). The OIG 
Report made a similar recommendation that the BLM, ``Ensure that oil 
and gas regulations are current by updating and issuing onshore orders 
. . . .'' (see page 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 time frame for issuing final regulations for 
oil measurement.'' (Ibid., p. 32.)
    The GAO's recommendations regarding the 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. Specifically, the GAO concluded that the BLM does not have 
``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)
    Specifically, of the 110 recommendations made in the 2007 
Subcommittee report, 12 recommendations relate directly to improving 
the operators' measurement and reporting of natural gas volume and 
heating value. The Subcommittee recommendations focus on the 
measurement and reporting of heating value because it has a direct 
impact on royalties. Measuring heating value is as important to 
calculating royalty as measuring gas volume. As noted previously, Order 
5 requires only yearly measurement of natural gas heating value. The 
BLM does not have any 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 proposed requirements 
in subpart 3175 would establish these standards.
    The proposed changes also address findings and recommendations made 
in the 2010 and 2015 GAO reports. The 2010 GAO report made 19 
recommendations to improve the BLM's ability to ensure that oil and gas 
produced from Federal and Indian lands is accurately measured and 
properly reported. Some of those recommendations relate to gas 
measurement. For example, the report recommends that the BLM establish 
goals that would allow it to witness gas sample collections; however, 
the BLM must first establish gas sampling standards as a basis for 
inspection and enforcement actions. This rulemaking would establish 
these standards. The 2015 GAO report recommends, among other things, 
that the BLM issue new

[[Page 61650]]

regulations pertaining to oil and gas measurement.
    Finally, Order 5 is now 26 years old, and many improvements in 
technology and industry standards have occurred since that time that 
are not addressed in BLM regulations. In the absence of a new rule, the 
BLM has had to address these issues through statewide NTLs and site-
specific variances. The following summarizes why the BLM is proposing 
to include some of these changes in this proposed rule:
     The BLM estimates that between 80 percent and 90 percent 
of gas meters used for royalty determination incorporate EGM systems. 
EGM systems are not addressed in Order 5, which covers only mechanical 
chart recorders. BLM requirements for EGM systems, as stated in the 
various statewide NTLs, are based on the requirements for mechanical 
recorders in Order 5 and do not address many aspects unique to EGMs, 
such as volume calculation, data-gathering, and retention requirements. 
The proposed rule would add requirements specific to EGMs such as new 
calibration procedures, the use of the latest flow equations, and 
minimum requirements for quantity transaction records, configuration 
logs, and event logs.
     Order 5 allows pipe-tapped orifice plates to be used for 
royalty measurement. Industry has moved away from pipe-tapped orifice 
plates for custody transfer due to a relatively high degree of 
measurement uncertainty inherent in that technology. The proposed rule 
would allow only flange-tapped orifice plates.
     The only industry standard adopted by Order 5 is American 
Gas Association (AGA) Report No. 3, 1985, which sets standards for 
orifice plates. This standard has since been superseded based on 
additional research and analysis. The new standards, which are 
incorporated by reference in this proposed rule, reduce bias and 
uncertainty.
     Order 5 does not adopt industry standards related to 
technologies for EGM systems, calculation of supercompressibility, gas 
sampling and analysis, calculation of heating value and relative 
density, or testing protocols for alternate types of primary devices. 
The proposed rule would add requirements to address all of these 
shortcomings in Order 5 and would establish the PMT to review new 
technology.
     Order 5 does not establish testing and approval standards 
for flow conditioners, transducers used in EGM systems, or flow 
computer software. To ensure accuracy of measurement, independent 
verification of these devices, as proposed in this rule, is necessary.

III. Discussion of Proposed Rule

A. Comparison of Order 5 to Proposed Rule

    The following chart explains the major changes between Order 5 and 
the proposed rule.

------------------------------------------------------------------------
            Order 5               Proposed Rule     Substantive changes
------------------------------------------------------------------------
I. Introduction
A. Authority..................  No section in      This section of Order
                                 this proposed      5 would appear in
                                 rule.              proposed 43 CFR
                                                    3170.1. New subpart
                                                    3170 was proposed
                                                    separately in
                                                    connection with
                                                    proposed new 43 CFR
                                                    subpart 3173 (site
                                                    security), (80 FR
                                                    40768, July 13,
                                                    2015).
B. Purpose....................  No section in the  The purpose of this
                                 proposed rule.     proposed rule is to
                                                    revise and replace
                                                    Order 5 with a new
                                                    regulation that
                                                    would be codified in
                                                    the CFR.
C. Scope......................  No section in      See proposed new 43
                                 this proposed      CFR 3170.2 (80 FR
                                 rule.              40802, July 13,
                                                    2015).
II. Definitions...............  43 CFR 3175.10...  The list of
                                                    definitions in the
                                                    proposed rule would
                                                    be expanded to
                                                    include numerous
                                                    additional technical
                                                    terms and volume
                                                    thresholds for
                                                    applicability of
                                                    requirements.
                                                    Definitions relating
                                                    to enforcement
                                                    actions would be
                                                    removed. A list of
                                                    additional acronyms
                                                    would be added.
III. Requirements
A. Required Recordkeeping.....  No section in      See proposed new 43
                                 this proposed      CFR 3170.7 (80 FR
                                 rule.              40804, July 13,
                                                    2015).
B. General....................  43 CFR 3175.31...  The proposed rule
                                                    would adopt, in
                                                    whole or in part,
                                                    the latest
                                                    applicable versions
                                                    of relevant API and
                                                    GPA standards.
                                                    Timelines for
                                                    retrofitting
                                                    existing equipment
                                                    to comply with the
                                                    rule would be added
                                                    on a sliding scale
                                                    based on four
                                                    different volume
                                                    thresholds. These
                                                    volume thresholds
                                                    would be established
                                                    to allow exceptions
                                                    to specific
                                                    requirements for
                                                    lower-volume FMPs.
                                                   This proposed rule
                                                    would remove the
                                                    enforcement,
                                                    corrective action,
                                                    and abatement period
                                                    provisions of Order
                                                    5. In their place,
                                                    the BLM would
                                                    develop an internal
                                                    inspection and
                                                    enforcement handbook
                                                    that would direct
                                                    inspectors on how to
                                                    classify a
                                                    violation, how to
                                                    determine what the
                                                    corrective action
                                                    should be, and the
                                                    proper timeframe for
                                                    correcting the
                                                    violation.
                                                   This change would
                                                    improve consistency
                                                    and clarity in
                                                    enforcement
                                                    nationally. The
                                                    enforcement actions
                                                    listed in Order 5
                                                    give the impression
                                                    that they are
                                                    mandatory. In
                                                    practice, the
                                                    violations' severity
                                                    and corrective
                                                    action timeframes
                                                    should be decided on
                                                    a case-by-case
                                                    basis, using the
                                                    definitions in the
                                                    regulations. In
                                                    deciding how severe
                                                    a violation is, BLM
                                                    inspectors must take
                                                    into account whether
                                                    a violation ``could
                                                    result in immediate,
                                                    substantial, and
                                                    adverse impacts on .
                                                    . . production
                                                    accountability, or
                                                    royalty income.''
                                                    What constitutes a
                                                    ``major'' violation
                                                    in a high-volume
                                                    meter could, for
                                                    example, be very
                                                    different from what
                                                    constitutes a
                                                    ``major'' violation
                                                    in a meter measuring
                                                    substantially lower
                                                    production. The
                                                    authorized officer
                                                    (AO) would use the
                                                    enforcement handbook
                                                    in conjunction with
                                                    43 CFR subpart 3163
                                                    when determining
                                                    appropriate
                                                    assessments and
                                                    civil penalties.
     Adoption of AGA
     Report No. 3.

[[Page 61651]]

 
     Applicability to
     existing and future
     meters.
     Exemptions for
     meters measuring less
     than 100 Mcf/day.
     Enforcement......
C. Gas Measurement by Orifice
 Meter
Paragraphs 1, 2, 3, 6, 8, 9,    43 CFR 3175.80...  The proposed rule
 10, 11 (Orifice plate and                          would adopt, in
 meter tube standards).                             whole or in part,
                                                    the current API
                                                    standards for
                                                    orifice plates and
                                                    combine all the
                                                    requirements for
                                                    orifice plates in
                                                    one section.
Paragraphs 4, 5, 7, 12, 13,     43 CFR 3175.90-    The proposed rule
 14, 15, 16, 17, 18, 19 (Chart   3175.94.           would restrict the
 recorder standards).                               use of mechanical
                                                    recorders to those
                                                    FMPs measuring 100
                                                    Mcf/day or less. In
                                                    addition, it would
                                                    establish new
                                                    standards for volume
                                                    calculation,
                                                    verification, and
                                                    design parameters
                                                    for manifolds and
                                                    gauge lines. The
                                                    proposed rule would
                                                    also lower the
                                                    volume threshold for
                                                    required use of
                                                    continuous
                                                    temperature
                                                    recorders from 200
                                                    Mcf/day or less, to
                                                    15 Mcf/day or less.
Paragraph 20 (Volume estimate   43 CFR 3175.126..  The requirement for
 for malfunction or out of                          estimating volumes
 service).                                          when metering
                                                    equipment is
                                                    malfunctioning or
                                                    out-of-service would
                                                    make clear the
                                                    acceptable methods
                                                    of estimating volume
                                                    and associated
                                                    documentation.
Paragraph 21 (Volume            43 CFR 3175.90-    The proposed rule
 calculation AGA 3).             3175.94,           would update the
                                 3175.100-3175.10   reference to
                                 3.                 industry standards
                                                    for required flow-
                                                    rate calculations.
                                                    Requirements would
                                                    be added to clarify
                                                    how volume is
                                                    determined from the
                                                    calculated flow
                                                    rate.
Paragraph 22 (Location of       43 CFR 3175.70...  Requirements for
 meter requirement).                                obtaining approval
                                                    for off-lease
                                                    measurement and
                                                    commingling and
                                                    allocation would be
                                                    revised and moved
                                                    into the proposed
                                                    new rule that would
                                                    replace Onshore Oil
                                                    and Gas Order No. 3
                                                    (Order 3) published
                                                    previously (proposed
                                                    43 CFR subpart
                                                    3173), 80 FR 40768
                                                    (July 13, 2015), but
                                                    would be referenced
                                                    in this subpart.
Paragraph 23 (Btu requirement)  43 CFR 3175.110-   The requirements for
                                 3175.121.          gas sampling and
                                                    analysis would be
                                                    expanded to include
                                                    requirements for
                                                    sampling location
                                                    and methods,
                                                    sampling frequency,
                                                    analysis methods,
                                                    and the minimum
                                                    number of components
                                                    to be analyzed. This
                                                    section would also
                                                    define the effective
                                                    date of the heating
                                                    value and relative
                                                    density determined
                                                    from the sample.
Paragraph 24 (Calibration form  43 CFR 3175.90,    The information
 information requirement).       3175.92,           required on meter
                                 3175.100, and      calibration reports
                                 3175.102.          would be expanded
                                                    for both mechanical
                                                    recorders and EGM
                                                    systems.
Paragraph 25 (Atmospheric       43 CFR 3175.90,    The proposed rule
 pressure requirement).          3175.92,           would change the
                                 3175.100, and      basis for
                                 3175.102.          determining
                                                    atmospheric pressure
                                                    from a contract
                                                    value to a
                                                    measurement or
                                                    calculation based on
                                                    elevation. The
                                                    calculation is
                                                    prescribed in the
                                                    proposed rule.
Paragraph 26 (Method and        43 CFR 3175.110-   Order 5 has no
 frequency--specific gravity).   3175.120.          requirements
                                                    pertaining to the
                                                    determination of
                                                    relative density.
                                                    The proposed rule
                                                    would establish
                                                    methods for deriving
                                                    the relative density
                                                    from the gas
                                                    analysis.
No requirements for EGM         43 CFR 3175.100-   Order 5 does not
 systems--Addressed in           3175.126.          address EGM systems;
 statewide NTLs.                                    however, these
                                                    devices are
                                                    addressed in the
                                                    statewide NTLs for
                                                    electronic flow
                                                    computers. The
                                                    proposed rule would
                                                    adopt many of the
                                                    provisions of the
                                                    statewide NTLs and
                                                    add requirements
                                                    relating to on-site
                                                    information, gauge
                                                    lines, verification,
                                                    test equipment,
                                                    calculations, and
                                                    information
                                                    generated and
                                                    retained by the EGM
                                                    system.
D. Gas Measurement by Other     43 CFR 3175.47,    Requirements for
 Methods or at Other Locations   3175.48, and       obtaining approval
 Acceptable to the Authorized    3175.70.           for off-lease
 Officer.                                           measurement and
                                                    commingling and
                                                    allocation would be
                                                    revised and moved
                                                    into the new
                                                    proposed rule that
                                                    would replace Order
                                                    3 published
                                                    previously and cited
                                                    above, but would be
                                                    referenced in this
                                                    subpart. In
                                                    addition, this
                                                    proposed change
                                                    would establish a
                                                    consistent and
                                                    nationwide process
                                                    for review and
                                                    approval of
                                                    alternate primary
                                                    devices and flow
                                                    conditioners used in
                                                    conjunction with
                                                    flange-tapped
                                                    orifice plates.
No requirements for transducer  43 CFR 3175.130-   The proposed rule
 or flow computer testing.       3175.144.          would establish a
                                                    testing protocol and
                                                    approval process for
                                                    transducers used in
                                                    EGM systems and flow-
                                                    computer software.
No requirements for reporting   43 CFR 3175.126..  The proposed rule
 of volume and heating value.                       would establish
                                                    standards for
                                                    heating value
                                                    reporting, averaging
                                                    heating value from
                                                    multiple FMPs and
                                                    multiple samples,
                                                    and volume
                                                    reporting.
IV. Variance from Minimum       No section in      See proposed new 43
 Standards.                      this proposed      CFR 3170.6 (80 FR
                                 rule.              40804, July 13,
                                                    2015).

[[Page 61652]]

 
No immediate assessments......  43 CFR 3175.150..  The proposed rule
                                                    would add 10 new
                                                    violations that
                                                    would be subject to
                                                    an immediate
                                                    assessment of
                                                    $1,000, as follows:
                                                    (1) New FMP orifice
                                                    plate inspections
                                                    not conducted and
                                                    documented; (2)
                                                    Routine FMP orifice
                                                    plate inspections
                                                    not conducted and
                                                    documented; (3)
                                                    Visual meter-tube
                                                    inspection not
                                                    conducted and
                                                    documented; (4)
                                                    Detailed meter-tube
                                                    inspections not
                                                    conducted and
                                                    documented; (5)
                                                    Initial mechanical-
                                                    recorder
                                                    verification not
                                                    conducted and
                                                    documented; (6)
                                                    Routine mechanical-
                                                    recorder
                                                    verifications not
                                                    conducted and
                                                    documented; (7)
                                                    Initial EGM-system
                                                    verification not
                                                    conducted and
                                                    documented; (8)
                                                    Routine EGM-system
                                                    verification not
                                                    conducted and
                                                    documented; (9) Spot
                                                    samples for low-
                                                    volume and marginal-
                                                    volume FMPs not
                                                    taken at the
                                                    required frequency;
                                                    and (10) Spot
                                                    samples for high-
                                                    volume and very-high-
                                                    volume FMPs not
                                                    taken at the
                                                    required frequency.
------------------------------------------------------------------------

B. Section-by-Section Analysis

    This proposed rule would be codified primarily in a new 43 CFR 
subpart 3175. As noted previously, the BLM has already proposed a rule 
to revise and replace Order 3 (site security), 80 FR 40768 (July 13, 
2015). It is the BLM's intent to codify any final rule resulting from 
that proposal at new 43 CFR subpart 3173. The BLM also anticipates 
proposing a new rule to replace Onshore Oil and Gas Order No. 4, 54 FR 
8086 (February 24, 1989), governing measurement of oil for royalty 
purposes. The BLM's intent is to codify any final rule governing oil 
measurement at new 43 CFR subpart 3174. Given this structure, it is the 
BLM's intent that part 3170, which was proposed together with proposed 
43 CFR subpart 3173, would contain definitions of certain terms common 
to more than one of the proposed rules, as well as other provisions 
common to all rules, i.e., provisions prohibiting by-pass of and 
tampering with meters; procedures for obtaining variances from the 
requirements of a particular rule; requirements for recordkeeping, 
records retention, and submission; and administrative appeal 
procedures. Those common provisions in new subpart 3170 were already 
proposed in connection with the rule to replace Order 3.
    In addition to the new subpart 3175 provisions, the BLM is also 
proposing changes to certain other provisions in 43 CFR subparts 3162, 
3163, and 3165. The proposed provisions related to the new subpart 3175 
are discussed first in the section-by-section analysis below; changes 
to other subparts are discussed at the end of the section-by-section 
analysis.
Subpart 3175 and Related Provisions


Sec.  3175.10  Definitions and Acronyms

    The proposed rule would include numerous new definitions because 
much of the terminology used in the proposed rule is technical in 
nature and may not be readily understood by all readers. The BLM would 
add other definitions because their meaning, as used in the proposed 
rule, may be different from what is commonly understood, or the 
definition would include a specific regulatory requirement.
    Definitions of terms commonly used in gas measurement or which are 
already defined in 43 CFR parts 3000, 3100, or 3160 are not discussed 
in this preamble.
    The proposed rule would define 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. 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. 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 primary device that is approved 
in Order 5 and in this proposed 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 approve their use 
under the requirements of proposed Sec.  3175.47.
    The secondary device measures the differential pressure along with 
static pressure and temperature. The secondary device consists of 
either the differential-pressure, static-pressure, and temperature 
transducers in an EGM system or a mechanical recorder (including the 
differential, static, and temperature elements, and the clock, pens, 
pen linkages, and circular chart). 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 proposed rule would add 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 proposed Sec.  3175.30(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 would 
need to be able to identify the make, model, and upper range limit 
(URL) of each transducer because the uncertainty of the transducer 
varies between 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.
    Other EGM systems are assembled using a variety of transducers and 
flow computers and cannot be identified by

[[Page 61653]]

a single make and model number. Instead, the BLM would identify each 
transducer by its own make and model. These are referred to as 
``component'' EGM systems. Component systems would 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 proposed rule would add a definition for ``hydrocarbon dew 
point.'' The hydrocarbon dew point is the temperature at which liquids 
begin to form within a gas mixture. Because it is not common to 
determine hydrocarbon dew points for wellhead metering applications on 
Federal and Indian leases, the BLM would establish 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 hydrocarbon dew point. 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 hydrocarbon 
dew point at the primary device. The AO may approve a different 
hydrocarbon dew point if data from an equation-of-state, chilled 
mirror, or other approved method is submitted.
    The proposed rule would define ``marginal-volume FMP'' as an FMP 
that measures a default volume of 15 Mcf/day or less. FMPs classified 
as ``marginal-volume'' would be exempt from many of the requirements in 
this proposed rule. The 15 Mcf/day default threshold 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 for FMPs that are 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
     10-year equipment life.
    [GRAPHIC] [TIFF OMITTED] TP13OC15.008
    
    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 because the lease, unit participating area (PA), or 
communitized area (CA) would be shut-in if there were no exemptions for 
marginal-volume FMPs. 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. The U.S. Energy Information Administration projects 
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.\2\ 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 indicates that it 
may not be profitable to invest in the necessary equipment to meet the 
proposed requirements for a low-volume FMP. Instead, it would be more 
economic for an operator to shut in the FMP than to make the necessary 
investments. Therefore, 15 Mcf/day is proposed as the default threshold 
of a marginal-volume FMP. The AO may approve a higher threshold where 
circumstances warrant.
---------------------------------------------------------------------------

    \2\ ``Annual Energy Outlook 2014 with Projections to 2040'', 
U.S. Department of Energy, Energy Information Administration (DOE/
EIA-0383(2014), April, 2014, Figure MT-41.
---------------------------------------------------------------------------

    The proposed rule would define ``low-volume FMP'' as an FMP flowing 
100 Mcf/day or less but more than 15 Mcf/day. Low-volume FMPs would 
have to meet minimum requirements to ensure that measurements are not 
biased, but would be exempt from the minimum uncertainty requirements 
in Sec.  3175.30(a) of the proposed rule. It is anticipated that this 
classification would encompass 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 because costs are 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 BLM requirements stated in the statewide NTLs 
for electronic flow computers (EFCs).

[[Page 61654]]

    The proposed rule would define ``high-volume FMP,'' as an FMP 
flowing more than 100 Mcf/day, but not more than 1,000 Mcf/day. 
Proposed requirements for high-volume FMPs would ensure that there is 
no statistically significant bias in the measurement and would achieve 
an overall measurement of uncertainty of 3 percent or less. 
The BLM anticipates that the higher flow rates would make retrofitting 
to achieve minimum uncertainty levels more economically feasible. The 
requirements for high-volume FMPs would be similar to current BLM 
requirements as stated in the statewide NTLs for EFCs.
    The proposed rule would define ``very-high-volume FMP,'' as an FMP 
flowing more than 1,000 Mcf/day. Proposed requirements for very-high-
volume FMPS would require lower uncertainty than would be required for 
high-volume FMPs (2 percent, compared to 3 
percent) and would increase the frequency of primary device inspection 
and secondary device verification. Stricter measurement accuracy 
requirements would be imposed for very-high-volume FMPs due to the risk 
of mis-measurement having 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.
    The proposed rule would adopt three definitions from API Manual of 
Petroleum Measurement Standards (MPMS) 21.1. The terms ``lower 
calibrated limit'' and ``upper calibrated limit'' would replace the 
term ``span'' as used in the statewide NTLs for EFCs.
    In addition, the term ``redundancy verification'' would be added to 
address verifications done by comparing the readings from two sets of 
transducers installed on the same primary device.


Sec.  3175.20  General Requirements

    Proposed Sec.  3175.20 would require 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).


Sec.  3175.30  Specific Performance requirements

    Proposed Sec.  3175.30 would set overall performance standards for 
measuring gas produced from Federal and Indian leases, regardless of 
the type of meters used. Order 5 has no explicit statement of 
performance standards. The performance standards would provide specific 
objective criteria with which the BLM could analyze meter systems not 
specifically allowed under the proposed rule. The performance standards 
also formed the basis of determining the standards that would apply to 
each flow-rate class of meter (i.e., marginal, low, high, and very-high 
volume).
    The first performance standard in proposed Sec.  3175.30(a) is the 
maximum allowable flow-rate measurement uncertainty. Uncertainty 
indicates the risk of measurement error. For high-volume FMPs (flow 
rate greater than 100 Mcf/day, but less than or equal to 1,000 Mcf/
day), the maximum allowed overall flow-rate measurement uncertainty 
would be 3 percent, which is the same as what is currently 
required in all of the statewide NTLs for EFCs; therefore, this 
requirement does not represent a change from existing standards. For 
very-high-volume FMPs (flow rate of more than 1,000 Mcf/day), the 
maximum allowable flow-rate uncertainty would be reduced to 2 percent, because uncertainty in higher-volume meters represents 
a greater risk of affecting royalty than in lower-volume meters. In 
addition, upgrades necessary to achieve an uncertainty of 2 
percent for very-high-volume FMPs will be more cost effective. Not only 
do the higher flow rates make these necessary upgrades more economic, 
many of the measurement uncertainty problems associated with lower 
volume FMPs, such as intermittent flow, are not as prevalent with 
higher volume FMPs. This is a change from the existing statewide NTLs, 
which use the 3 percent requirement for all meters 
measuring more than 100 Mcf/day. As with the existing statewide NTLs, 
meters measuring 100 Mcf/day or less (low-volume FMPs and marginal-
volume FMPs) would be exempt from maximum uncertainty requirements.
    This proposed section would also specify 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.
    Proposed Sec.  3175.30(a)(3) 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 quantity transaction record. However, daily quantity 
transaction records 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 quantity 
transaction record is not available to the AO, the next best source for 
uncertainty determinations would be the average flowing parameters from 
the previous day, which are required under proposed Sec.  
3175.101(b)(4)(ix) through (xi) of this rule.
    The BLM would enforce measurement uncertainty using standard 
calculations such as those found in API MPMS 14.3.1, which are 
incorporated into the BLM uncertainty calculator (www.wy.blm.gov). 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 data used to calculate relative density under proposed 
Sec.  3175.120(c) would allow the BLM to quantify relative density 
uncertainty by performing a statistical analysis of historic relative 
density variability and include it in the determination of overall 
measurement uncertainty, making these uncertainty calculations more 
accurate.
    Proposed Sec.  3175.30(b) would add an uncertainty requirement for 
the measurement of heating value. This would be added 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. (The vast 
majority of gas sold domestically in the United States is priced on a 
$/MMBtu basis.) In that situation, the royalty is computed by the 
following equation: Royalty owed = measured volume x heating value per 
unit volume (i.e., MMBtu/Mcf) x royalty value (i.e., the arm's-length 
price in $/MMBtu) x 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

[[Page 61655]]

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 would be 
determined by performing a statistical analysis of the historic 
variability of heating values over the past year.
    For composite sampling and on-line gas chromatographs, the BLM 
would determine the heating value uncertainty by analyzing the 
equipment, procedures, and calculations used to derive the heating 
value.
    The uncertainty limits proposed 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 
proposed 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 heating 
value. For very-high-volume FMP's, 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 
proposed rule therefore would prescribe these respective levels as the 
allowed average annual heating value uncertainty.
    Proposed Sec.  3175.30(c) would establish the degree of allowable 
bias in a measurement. Bias, unlike uncertainty, results in measurement 
error; uncertainty only indicates the risk of measurement error. For 
all FMPs, except marginal FMPs, no statistically significant bias would 
be 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.
    Although bias is not specifically addressed in Order 5 or the 
statewide NTLs, the intent of the existing standards is to reduce bias 
to less than significant levels. Therefore, minimizing bias does not 
represent a change in BLM policy.
    The bias requirement does not apply to marginal-volume FMPs because 
marginal-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. If it is uneconomic to upgrade a meter to eliminate bias, 
the operator could opt to shut in production rather than making the 
necessary upgrades. Therefore, the BLM has determined that it is in the 
public interest to accept some risk of measurement bias in marginal-
volume FMPs in view of maintaining gas production.
    Proposed Sec.  3175.30(d) would require that all measurement 
equipment must allow for independent verification by the BLM. As with 
the bias requirements, Order 5 and the statewide NTLs for EFCs only 
allow meters that can be independently verified by the BLM and, 
therefore, this requirement would not be a change from existing policy. 
The verifiability requirement in this section would prohibit the use of 
measurement equipment that does not allow for independent verification. 
For example, if a new meter was 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 was developed that used 
proprietary methods which 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.


Sec.  3175.31   Incorporation by Reference

    The proposed rule would incorporate 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 API and the GPA, with input from the oil and gas industry. The 
BLM has reviewed these standards and determined that they would achieve 
the intent of Sec. Sec.  3175.30 and 3175.46 through 3175.125 of this 
proposed rule. The legal effect of incorporation by reference is that 
the incorporated standards become regulatory requirements. This 
proposed rule would incorporate the current versions of the standards 
listed.
    Some of the standards referenced in this section would be 
incorporated in their entirety. For other standards, the BLM would 
incorporate only those sections that are enforceable, meet the intent 
of Sec.  3175.30 of this proposed rule, or do not need further 
clarification.
    The proposed incorporation of industry standards follows the 
requirements found in 1 CFR part 51. Industry standards proposed for 
incorporation are eligible 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 proposed for incorporation 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 proposed 43 CFR 3174.4 meets the requirements of 1 
CFR 51.9. Where appropriate, the BLM proposes to incorporate an 
industry standard governing a particular process by reference and then 
impose requirements that are in addition to and/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 and GPA materials for which the BLM is seeking 
incorporation by reference are available for inspection at the BLM, 
Division of Fluid Minerals; 20 M Street SE., Washington, DC 20003; 202-
912-7162; and at all BLM offices with jurisdiction over oil and gas 
activities. The API materials are available for inspection 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 
www.publications.api.org. The GPA materials are available for 
inspection at the GPA, 6526 E. 60th Street, Tulsa, OK 74145; telephone 
918-493-3872.
    The following describes the API and GPA standards that the BLM 
proposes to incorporate by reference into this rule:
    API Manual of Petroleum Measurement Standards (MPMS) Chapter 14, 
Section 1, Collecting and Handling of Natural Gas Samples for Custody 
Transfer, Sixth Edition, February 2006, Reaffirmed 2011 (``API

[[Page 61656]]

14.1.12.10''). The purpose of this standard is to provide a 
comprehensive guideline 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 2, 
Compressibility Factors of Natural Gas and Other Related Hydrocarbon 
Gases, Second Edition, August 1994, Reaffirmed March 1, 2006 (``API 
14.2''). 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.
    API MPMS, Chapter 14, Section 3, Part 1, General Equations and 
Uncertainty Guidelines, Fourth Edition, September 2012, Errata, July 
2013. (``API 14.3.1.4.1''). 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, Part 2, Specifications and 
Installation Requirements, Fourth Edition, April 2000, Reaffirmed 2011 
(``API 14.3.2,'' ``API 14.3.2.4,'' ``API 14.3.2.5.1 through API 
14.3.2.5.4,'' ``API 14.3.2.5.5.1 through API 14.3.2.5.5.3,'' ``API 
14.3.2.6.2,'' ``API 14.3.2.6.3,'' ``API 14.3.2.6.5,'' and ``API 14.3.2, 
Appendix 2-D''). 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, Part 3, Natural Gas Applications, 
Fourth Edition, November 2013 (``API 14.3.3,'' ``API 14.3.3.4,'' and 
``API 14.3.3.5.'' and ``API 14.3.3.5.6,''). 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 (``API 14.5,'' ``API 14.5.3.7,'' and ``API 
14.5.7.1''). This standard presents procedures for calculating, at base 
conditions from composition, the following properties of natural gas 
mixtures: gross heating value, relative density (real and ideal), 
compressibility factor, and theoretical hydrocarbon liquid content.
    API MPMS Chapter 21, Section 1, Electronic Gas Measurement, Second 
Edition, February 2013 (``API 21.1,'' ``API 21.1.4,'' ``API 
21.1.4.4.5,'' ``API 21.1.5.2,'' ``API 21.1.5.3,'' ``API 21.1.5.4,'' 
``API 21.1.5.4.2,'' ``API 21.1.5.5,'' ``API 21.1.5.6,'' ``API 
21.1.7.3,'' ``API 21.1.7.3.3,'' ``API 21.1.8.2,'' ``API 21.1.8.2.2.2, 
Equation 24,'' ``API 21.1.9,'' ``API 21.1 Annex B,'' ``API 21.1 Annex 
G,'' ``API 21.1 Annex H, Equation H.1,'' and ``API 21.1 Annex I''). 
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, Section 2, Differential Pressure Flow 
Measurement Devices, First Edition, August 2005, Reaffirmed 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, Revised 2005 (``GPA 2166-05 Section 9.1,'' ``GPA 
2166.05 Section 9.5,'' ``GPA 2166-05 Sections 9.7.1 through 9.7.3,'' 
``GPA 2166-05 Appendix A,'' ``GPA 2166-05 Appendix B.3,'' ``GPA 2166-05 
Appendix D''). 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 2261-00, Analysis for Natural Gas and Similar Gaseous 
Mixtures by Gas Chromatography, Revised 2000 (``GPA 2261-00'', ``GPA 
2261-00, Section 4,'' GPA 2261-00, Section 5,'' ``GPA 2261-00, Section 
9''). This standard establishes a method to determine the chemical 
composition of natural gas and similar gaseous mixtures.
    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''). 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.


Sec. Sec.  3175.40-3175.45  Measurement Equipment Approved by Standard 
or Make and Model

    Proposed Sec.  3175.40 would provide that the specific types of 
measurement equipment identified in proposed Sec. Sec.  3175.41--
3175.45 could be installed at FMPs without further approval. Flange-
tapped orifice plates (proposed Sec.  3175.41) have been rigorously 
tested and shown that they are capable of meeting the performance 
standards of proposed Sec.  3175.30(a). Mechanical recorders (proposed 
Sec.  3175.42) 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 proposed Sec. Sec.  3175.30(b) and (c) is well-
established. Because mechanical recorders would be limited to marginal-
volume and low-volume FMPs under the proposed rule, they would not have 
to meet the uncertainty requirements of proposed Sec.  3175.30(a).
    While EGM systems are widely accepted for use in custody-transfer 
applications, there are currently no standardized protocols by which 
they are tested to document their performance capabilities and 
limitations. Proposed Sec.  3175.43 (transducers) and proposed Sec.  
3175.44 (flow computer software) would require these components of an 
EGM system to be tested under the protocols proposed in Sec. Sec.  
3175.130 and 3175.140, respectively, in order to be used at high- or 
very-high-volume FMPs.
    To make the review and approval process consistent, all data 
received from the testing would be reviewed by the PMT, who would make 
recommendations to the BLM. If approved, the BLM would post the make, 
model, and range or software version on the BLM Web site at www.blm.gov 
as being appropriate for use at high- and very-high-volume FMPs. The 
posting could include conditions of use. This would be a new 
requirement. Transducers used at marginal- and low-volume FMPs would 
not require testing under proposed Sec.  3175.130 or approval through 
the PMT. The primary purpose of the testing protocol is to determine 
the uncertainty of the transducer under a variety of operating 
conditions. Because marginal- and low-volume FMPs are not subject to 
the uncertainty requirements under Sec.  3175.30(a), testing the 
performance of the transducer would be unnecessary in that context. 
However, flow computer software used at marginal-volume and low-volume 
FMPs (proposed Sec.  3175.44) would not be exempt from testing under 
proposed Sec.  3175.140.

[[Page 61657]]

    Gas chromatographs (proposed Sec.  3175.45) are not addressed in 
Order 5 or statewide NTLs. They have been rigorously tested and used in 
industry for custody transfer applications and their ability to meet 
the requirements of Sec.  3175.30 has been demonstrated. Therefore, the 
proposed rule would allow their use in determining heating value and 
relative density as long as they meet the design, operation, 
verification, calibration, and other requirements of proposed 
Sec. Sec.  3175.117 and 3175.118.


Sec. Sec.  3175.46 and 3175.47  Approval of Isolating Flow Conditioners 
and Differential Primary Devices Other Than Flange-Tapped Orifice 
Plates

    Proposed Sec. Sec.  3175.46 and 3175.47 contain new provisions that 
would establish a consistent nationwide process that the PMT would use 
to approve certain other devices without the BLM having to update its 
regulations, issue other forms of guidance such as NTLs, or grant 
approvals on a case-by-case basis. The PMT would act as a central 
advisory body for approving equipment and methods not addressed in the 
proposed regulations. As noted above, the PMT is a panel of oil and gas 
measurement experts designated by the BLM that would be charged with 
reviewing changes in industry measurement technology. These proposed 
sections would describe and clarify the process for approval of 
specific makes and models of other primary devices and flow 
conditioners used in conjunction with flange-tapped orifice plates, 
including specific testing protocols and procedures for review of test 
data. These sections also would clarify the makes and models of devices 
approved for use and the conditions under which operators may use them.
    Under the proposed rule, if the PMT recommends, and the BLM 
approves new equipment, the BLM would post the make and model of the 
device on the BLM Web site www.blm.gov as being appropriate for use at 
an FMP for gas measurement going forward--i.e., subsequent users of the 
technology would not have to go through the PMT process. The web 
posting identifying the equipment or technology would include, as 
appropriate, conditions of use.
    Proposed Sec.  3175.46 would prescribe a testing protocol for flow 
conditioners used in conjunction with flange-tapped orifice plates. The 
proposed rule references the current API MPMS 14.3.2 (2000), Appendix 
2-D, which provides a testing protocol for flow conditioners. Based on 
the BLM's experience with other testing protocols, the BLM could 
prescribe additional testing beyond what Appendix 2-D requires, to meet 
the intent of the uncertainty limits in proposed Sec.  3175.30(a). 
Additional testing protocols would be posted on the BLM's Web site at 
www.blm.gov.
    Proposed Sec.  3175.47 would prescribe a testing protocol for 
differential types of primary devices other than flange-tapped orifice 
plates. The protocol is based largely on API MPMS 22.2. The BLM is 
aware that the API is in the process of making significant changes to 
this protocol; however, the modifications have not yet been published. 
Therefore, the BLM could include additional testing requirements beyond 
those in the current version of API MPMS 22.2 to help ensure that tests 
are conducted and applied in a manner that meets the intent of proposed 
Sec.  3175.30 of this rule. The BLM would post any additional testing 
protocols on its Web site at www.blm.gov.


Sec.  3175.48  Linear Measurement Devices

    Proposed Sec.  3175.48 would provide a process for the BLM to 
approve linear measurement devices such as ultrasonic meters, Coriolis 
meters, and other devices on a case-by-case basis.


Sec.  3175.60  Timeframes for compliance

    Proposed Sec.  3175.60(a) would require all meters installed after 
the effective date of the final rule to meet the proposed requirements. 
Proposed paragraph (b) would set timeframes for compliance with the 
provisions of this rule for equipment existing on the effective date of 
the final rule. The timeframes for compliance generally would depend on 
the average flow rate at the FMP. Higher-volume FMPs would have shorter 
timeframes for compliance with this proposed rule because they present 
a greater risk to royalty than lower-volume FMPs and the costs to 
comply could be recovered in a shorter period of time.
    Proposed paragraphs (b)(1)(ii) and (b)(2)(ii) include 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 go into effect immediately for high-
volume and very-high-volume FMPs on the effective date of the final 
rule. This would allow 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.
    The BLM is not proposing to ``grandfather'' existing equipment. 
Operators would be required to upgrade measurement equipment at FMPs to 
meet the new standards, except for those FMPs that are specifically 
exempted in the rule. The reason for not grandfathering existing 
equipment is that compliance with the API and GPA standards that would 
be adopted by the proposed rule is necessary to minimize bias and meet 
the proposed uncertainty standards. The BLM is responsible for ensuring 
accurate, unbiased, and verifiable measurement, as stated in proposed 
Sec.  3175.30 of this rule, regardless of when the measurement 
equipment was installed.
    Although this rule would supersede Order 5 and any NTLs, variance 
approvals, and written orders relating to gas measurement, paragraph 
(c) would specify that their requirements would remain in effect 
through the timeframes specified in paragraph (b). Paragraph (d) would 
establish the dates on which the applicable NTLs, variance approvals, 
and written orders relating to gas measurement would be rescinded. 
These dates correspond to the phase-in timeframes given in paragraph 
(b).


Sec.  3175.70  Measurement Location

    Proposed Sec.  3175.70 would require 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 included in the 
proposed rule that would replace Order 3 (new subpart 3173) referred to 
previously.


Sec.  3175.80  Flange-Tapped Orifice Plates (Primary Device)

    Proposed Sec.  3175.80 would prescribe standards for the 
installation, operation, and inspection of flange-tapped orifice plate 
primary devices. The standards would include requirements described in 
the proposed rule as well as requirements described in API standards 
that would be incorporated by reference. Table 1 is included in this 
proposed section 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 lists the subject area for which a standard exists. The second column 
of Table 1 contains a reference to the standard that applies to the 
subject area described in the first column. For subject areas where the 
BLM would adopt an API standard verbatim, the specific API reference is 
shown. For subject areas where there is

[[Page 61658]]

no API standard or the API standard requires additional clarification, 
the reference in Table 1 cites the paragraph in the proposed section 
that addresses the subject area.
    The final four columns of Table 1 indicate the categories of FMPs 
to which the standard would apply. The FMPs are categorized by the 
amount of flow they measure on a monthly basis as follows: ``M'' is 
marginal-volume, ``L'' is low-volume, ``H'' is high-volume, and ``V'' 
is very-high volume. Definitions for these various classifications are 
included in the definitions section in proposed 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 proposed standard. The 
requirements of the proposed rule would vary depending on the average 
monthly flow rate being measured. In general, the higher the flow rate, 
the greater the risk of mis-measurement, and the stricter the 
requirements would be.
    Proposed Sec.  3175.80 would adopt API MPMS 14.3.1.4.1, 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 first three of these conditions do not 
represent a change from Order 5, which incorporates the 1985 AGA Report 
No. 3. 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 in the 
proposed rule 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 proposed 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 proposed rule is not specifically stated in the AGA 
Report No. 3 (1985); however, all gases are generally considered 
Newtonian fluids. Therefore, this does not represent a change in 
requirements.
    The proposed requirement for maintaining a Reynolds number greater 
than 4,000 represents a change from Order 5. Order 5 does not have a 
requirement for a minimum Reynolds number. 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 all meters using the 
principle of differential pressure, including orifice meters, the flow 
equation assumes 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 
thousand standard cubic feet per day (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 inches and 4 inches in diameter. Because low-, high-, and 
very-high volume FMPs all exceed 15 Mcf/day by definition, most FMPs 
within these categories and with line sizes of 4 inches or less, would 
operate at Reynolds numbers well above 4,000. Marginal-volume FMPs 
would be exempt from this requirement. Therefore, adoption of the 
proposed requirement to maintain a Reynolds number greater than 4,000 
would not represent a significant change from existing conditions. The 
proposed requirement for maintaining a Reynolds number greater than 
4,000 for low-, high-, and very-high volume FMPs would 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.
    Marginal-volume FMPs could fall below this limit, but would be 
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 marginal-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 would not significantly affect royalty, and the 
potential error in royalty is small compared to the potential loss of 
royalty if production were shut in.
    Proposed Sec.  3175.80 would adopt API MPMS 14.3.2.4, which 
establishes requirements for orifice plate construction and condition. 
Orifice plate standards adopted would be virtually the same as they are 
in the AGA Report No. 3 (1985). No exemptions to this requirement are 
proposed, 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. Therefore, the BLM proposes to incorporate API MPMS 
14.3.2.4.

[[Page 61659]]

[GRAPHIC] [TIFF OMITTED] TP13OC15.009

    Proposed Sec.  3175.80 would adopt API MPMS 14.3.2.6.2 regarding 
orifice plate eccentricity and perpendicularity. The term 
``eccentricity'' refers to the centering of the orifice plate in the 
meter tube and ``perpendicularity'' refers to the alignment of the 
orifice plate with respect to the axis of the meter tube. This 
represents a change from the existing requirements in AGA Report Number 
3 (1985), since the eccentricity tolerances are significantly smaller 
in the new API standard proposed for incorporation, and will reduce the 
uncertainty of measurement. Eccentricity can affect the flow profile of 
the gas through the orifice and larger Beta ratio \3\ 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 (see Figure 2). However, the BLM does not 
believe based on its experience in the field that this proposed change 
would impose significant costs on operators because many new and 
existing meter installations use specially designed orifice plate 
holders that meet the new tolerances. Some ``flange-fitting'' 
installations may have to be retrofitted with alignment pins or other 
devices to meet the tighter tolerances. The BLM is asking for data on 
the cost of this retrofit and on the number of meters that it may 
affect.
---------------------------------------------------------------------------

    \3\ Beta ratio is the ratio of the orifice plate bore to the 
inside diameter of the meter tube
---------------------------------------------------------------------------

    The proposed section also incorporates a requirement for the 
orifice plate to be installed perpendicular to the meter tube axis as 
required by API MPMS 14.3.2.6.2.2. This requirement is not explicitly 
stated in Order 5. However, virtually all orifice plate holders, new 
and existing, maintain perpendicularity between the orifice plate and 
the meter-tube axis. Therefore, the BLM does not anticipate that this 
proposed change would impose significant costs.
    Proposed Sec.  3175.80(a) would redefine the allowable Beta ratio 
range for flange-tapped orifice meters to be between 0.10 and 0.75, as 
recommended by API MPMS 14.3.2. Order 5 established Beta ratio limits 
of 0.15 and 0.70 for meters measuring more than 100 Mcf/day. These 
limits were based on AGA Report No. 3 (1985), which was the orifice 
metering standard in effect at the time Order 5 was published. In the 
early 1990s, additional testing was done on orifice meters, which 
resulted in an increased Beta ratio range and a more accurate 
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. 
Because this rule would propose to expand the allowable Beta ratio 
range, it would be slightly less restrictive than Order 5 for high-
volume and very-high-volume FMPs.
    This section would also apply the Beta ratio limits to low-volume 
FMPs, which would be a change from Order 5. Order 5 exempts meters 
measuring 100 Mcf/day or less from the Beta ratio limits. 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 MPMS 14.3.2 is based on the inability to maintain 
edge sharpness in Beta ratios below 0.10. Therefore, there is a 
potential for bias if the BLM were to allow Beta ratios lower than 
0.10. Because the proposed rule would allow Beta ratios as low as 0.10, 
and Beta ratios less than 0.10 are relatively rare, this change would 
not be significant.
    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 proposes to maintain the upper Beta 
ratio limit in API MPMS 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, so the 0.75 upper Beta ratio limit for low-volume FMPs would 
not be a significant change either.
    Marginal-volume FMPs would be exempt from any Beta ratio 
restrictions in the proposed rule because it can be difficult to obtain 
a measureable amount of differential pressure with a Beta ratio of 0.10 
or greater at very low flow rates. The increased uncertainty and 
potential for bias by allowing a Beta ratio less than 0.10 on marginal-
volume FMPs is offset by the ability to accurately measure a 
differential pressure and record flow.
    Proposed Sec.  3175.80(b) would establish a minimum orifice bore 
diameter of 0.45 inches for high-volume and very-high-volume FMPs. This 
would be a new requirement. API MPMS 14.3.1.12.4.1 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

[[Page 61660]]

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.  3175.30(a). To ensure that 
high-volume and very-high-volume FMPs maintain the uncertainty required 
in proposed Sec.  3175.30(a), the BLM is proposing to prohibit 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 
marginal-volume FMPs, they would be allowed for use in these FMPs.
    Proposed Sec.  3175.80(c) would require bi-weekly orifice plate 
inspections for FMPs measuring production from wells first coming into 
production, which would be a new requirement. It is common for new 
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. The proposed requirement would increase the orifice plate 
inspection frequency until it could be demonstrated that the production 
of particulate matter from a new well first coming into production has 
subsided. The bi-weekly inspection requirement would apply to existing 
FMPs already measuring production from one or more other wells through 
which gas from a new well first coming into production is measured.
    Under this proposed rule, once a bi-weekly inspection demonstrates 
that no detectable wear occurred over the previous 2 weeks, the BLM 
would consider the well production to have stabilized and the 
inspection frequency would revert to the frequency proposed in Table 1. 
There would be no exemptions proposed 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 would not apply to marginal wells 
anyway because rarely would a newly-drilled well have only marginal 
levels of gas production.
    Proposed Sec.  3175.80(d) would establish a frequency for routine 
orifice plate inspections. The term ``routine'' is used to 
differentiate this proposed requirement from proposed Sec.  3175.80(c) 
of this rule for new FMPs measuring production from new wells. Under 
this rule, the proposed inspection frequency would depend on the 
average flow rate measured by the FMP. The required inspection 
frequency, in months, is given in Table 1. 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 would be 
required. Order 5 requires orifice plates to be pulled and inspected 
every 6 months, regardless of the flow rate. For high-volume and very-
high-volume FMPs, this proposal would increase the frequency of orifice 
plate inspections to every 3 months and every month, respectively. For 
marginal-volume FMPs, the proposed frequency would be reduced to every 
12 months, and for low-volume FMPs there would be no change from the 
existing inspection frequency of every 6 months. Order 5 also requires 
that an orifice plate inspection take place during the calibration of 
the secondary device. This requirement would be retained in the 
proposed rule.
    Proposed Sec.  3175.80(e) would require the operator to document 
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 would be a new requirement, many meter operators already 
record this information as part of their meter calibrations. Thus, this 
requirement would not be a significant change from prevailing industry 
practice.
    Proposed Sec.  3175.80(f) would require meter tubes to be 
constructed in compliance with current API standards. This proposed 
requirement would not include meter tube lengths, which would be 
addressed in proposed Sec.  3175.80(k). The BLM has reviewed the API 
standards referenced and believes that they meet the intent of Sec.  
3175.30 of the proposed rule. Order 5 adopted the meter tube 
construction standards of the AGA Report No. 3 (1985). A comparison of 
meter tube construction requirements between the proposed rule and 
Order 5 is outlined in the following table. The term ``Potentially'' as 
used in the table means that a retrofit could be required if the 
existing meter tube did not meet the requirements of API MPMS 14.3.2. 
It is possible, for example, that a meter tube constructed before 2000 
could still meet the roughness and roundness standards in API MPMS 
14.3.2.

----------------------------------------------------------------------------------------------------------------
                                        Proposed (API 14.3.2,     Existing (AGA Report
              Parameter                         2000)                 No. 3, 1985)          Require retrofit?
----------------------------------------------------------------------------------------------------------------
Surface roughness (Ra)...............  [beta] >= 0.6: 34        Ra <= 300 [mu]in.......  No
                                        [mu]in <= Ra < 250
                                        [mu]in.
                                       [beta] < 0.6: 34 [mu]in
                                        <= Ra < 300 [mu]in.
Meter tube diameter..................  Average of 4             Average of 4             No
                                        measurements 1 inch      measurements 1 inch
                                        upstream of orifice.     upstream of orifice.
Upstream check measurements..........  2 additional cross       2 additional cross       No.
                                        sections.                sections.
Downstream check measurements........  At 1 inch downstream of  At 1 inch downstream of  No.
                                        the orifice.             the orifice.
Roundness at inlet section...........  Difference between any   Difference between       Potentially.
                                        measurement and the      maximum and minimum
                                        average diameter <=      measurement <= 0.5% to
                                        0.25% of average         5% of average diameter
                                        diameter.                as a function of
                                                                 [beta].
Roundness at all upstream sections...  Difference between       Not specified..........  Potentially.
                                        maximum and minimum <=
                                        0.5% of average
                                        diameter.
Roundness at downstream section......  Difference between any   Difference between any   Potentially.
                                        measurement and the      measurement and the
                                        average diameter <=      average diameter <=
                                        0.5% of average          0.5% to 5% of average
                                        diameter.                diameter as a function
                                                                 of [beta].
Abrupt changes.......................  Not allowed............  Not allowed............  No.
Gaskets, protrusions, recesses.......  Protrusions prohibited;  Recesses restricted if   No.
                                        recesses restricted if   > 0.25 inches.
                                        > 0.25 inches.

[[Page 61661]]

 
Tap hole location....................  1 inch from upstream     1 inch from upstream     No.
                                        and downstream orifice   and downstream orifice
                                        plate faces,             plate faces,
                                        respectively.            respectively.
Tap hole location tolerance..........  Range from 0.015 inches  Range from 0.015 inches  No.
                                        to 0.15 inches           to 0.15 inches
                                        depending on size and    depending on size and
                                        [beta].                  [beta].
Tap hole diameter....................  0.375 0.016  0.250 to 0.375 inches    No (holes can be re-
                                        inches (2-3 inch         (2-3 inch nominal        drilled).
                                        nominal diameter);       diameter); 0.250 to
                                        0.500 0.016 inches (4    and greater nominal
                                        inch and greater         diameter).
                                        nominal diameter).
----------------------------------------------------------------------------------------------------------------
Note: [beta] = the Beta ratio; [mu]in = micro-inches (millionth of an inch) Ra = average roughness of surface
  finish of the orifice plate

    The primary difference in meter tube requirements between Order 5 
and the proposed rule is the roundness specifications for the meter 
tube at upstream and downstream locations. The orifice plate 
uncertainty specifications given in API MPMS 14.3.1 are based on the 
tighter roundness tolerances proposed in this rule. The roundness 
specifications in the AGA Report No. 3 (1985) would increase the 
uncertainty by an unknown amount. However, there is no existing 
evidence that bias results from a less round pipe, as allowed in the 
AGA Report No. 3 (1985).
    Uncertainty is the risk of mismeasurement; in contrast, bias 
necessarily results in mismeasurement. For example, an uncertainty of 
plus or minus 3 percent means that the meter could be reading anywhere 
between 3 percent low and 3 percent high. On the other hand, a bias of 
plus 3 percent means the meter is reading 3 percent high. This rule 
proposes to restrict the amount of allowable risk or uncertainty of 
measurement in high-volume and very-high-volume meters. To do so, 
however, the BLM must be able to quantify the individual sources of 
uncertainty that go into the calculation of overall measurement 
uncertainty. This rule also proposes to eliminate statistically 
significant bias in all FMPs other than marginal-volume FMPs.
    Proposed Sec.  3175.80(f)(1) and (2) would include an exception 
allowing low-volume FMPs to continue using the tolerances in the AGA 
Report No (1985). While the BLM recognizes this could result in higher 
uncertainty, we are not proposing uncertainty requirements for low-
volume FMPs. Since the AGA Report No. 3 (1985) is no longer readily 
available to the public, and cannot be incorporated by reference, this 
proposed rule includes an equation in proposed Sec.  3175.80(f)(1) that 
approximates the roundness tolerance graph in the AGA Report No. 3 
(1985).
    Marginal FMPs would not be required to meet the construction 
standards of either API MPMS 14.3.2 (2000) or the 1985 Report No. 3 
(AGA), since the cost to bring these meters up to the appropriate 
standards could be prohibitive based on experience with these 
production levels.
    Proposed Sec.  3175.80(g) would address isolating flow conditioners 
and tube bundle flow straighteners. To achieve the orifice plate 
uncertainty stated in API MPMS 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 MPMS 14.3.1 is discussed in 
proposed Sec.  3178.80(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.
    Proposed Sec.  3175.80(g) would allow isolating flow conditioners 
to be used at FMPs if they have been reviewed and approved by the BLM 
under Sec.  3175.46 of the proposed rule. Isolating flow conditioners 
are not addressed in Order 5 and currently must be approved on a meter-
by-meter basis using the variance process. The approval of isolating 
flow conditioners in the proposed rule would increase consistency and 
eliminate the time and expense it takes to apply for and obtain a 
variance for each FMP.
    Proposed Sec.  3175.80(g) would adopt API MPMS 14.3.2.5.5.1 through 
14.3.2.5.5.3 regarding the construction of 19-tube-bundle flow 
straighteners used for flow conditioning. Use of 19-tube-bundle flow 
straighteners constructed and installed under these API standards would 
not require BLM approval. Under Order 5, a minimum of four tubes were 
required in a tube-bundle flow straightener. The proposed rule would 
require a tube-bundle flow straightener, if used, to consist of 19 
tubes because all of the findings in API MPMS 14.3.2.5.5.1 through 
14.3.2.5.5.3 are based on 19-tube flow straighteners. Adoption of the 
proposed rule would prohibit 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 in size. Without the ability to use either 
7-tube- or 19-tube-bundle flow straighteners, 2-inch meters would be 
required to be retrofitted to use either: (1) A proprietary type of 
isolating flow conditioner approved in accordance with proposed Sec.  
3175.46; or (2) No flow conditioner, typically requiring much longer 
lengths of pipe upstream of the orifice plate. Marginal-volume FMPs are 
proposed to be exempt from the requirement to retrofit because the 
costs involved are believed to outweigh the benefits based upon 
experience with these production levels.
    Proposed Sec.  3175.80(h) would require an internal visual 
inspection of all meter tubes at the frequency, in years, shown in 
Table 1. The visual inspection would have 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 this proposed rule.
    Proposed Sec.  3175.80(i) would require a detailed inspection of 
meter tubes on

[[Page 61662]]

high- and very-high-volume FMPs at the frequency, in years, shown in 
Table 1 (10 years for high-volume FMPs and 5 years for very-high-volume 
FMPs). The AO could increase this frequency, and could require 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 operates in adverse conditions (such as 
corrosive or erosive gas flow), or has 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 inspection would be 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. Marginal-volume FMPs would be 
exempt from the inspection requirement because they would be exempt 
from the construction standards of API MPMS 14.3.2.
    Proposed Sec.  3175.80(j) would require operators to keep 
documentation of all meter tube inspections performed. The BLM would 
use this documentation to establish that the inspections met the 
requirements of the rule, for auditing purposes, and to track the rate 
of change in meter tube condition to support a change of inspection 
frequency, if needed. Marginal-volume FMPs would be exempt from this 
requirement because no meter tube inspections are required.
    Proposed Sec.  3175.80(k) would establish requirements 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 discussion of swirl and asymmetry in Sec.  3175.80(g)). Marginal-
volume FMPs are proposed to be 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. 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 MPMS 14.3.1 was published in 2000, 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 MPMS 
14.3.2 should already comply with the more stringent requirements for 
meter tube length and tube-bundle placement.
    Because the meter tube lengths in API MPMS 14.3.2 are required to 
achieve the stated uncertainty, paragraph (k)(1) proposes to adopt 
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 prior to 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. Most high-
volume and very-high-volume FMPs were installed after 2000, in 
compliance with the meter tube length requirements of API MPMS 14.3.2. 
Therefore, the proposed requirement is not a significant change from 
existing conditions.
    While low-volume FMPs would not be subject to the uncertainty 
requirements under proposed Sec.  3175.30(a), they still would have to 
be free of statistically significant bias under proposed Sec.  
3175.30(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 
would also be subject to the meter tube length requirements of API MPMS 
14.3.2 under proposed paragraph (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 MPMS 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.
    Proposed paragraph (k)(2) would allow 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 shows the shorter meter 
tube lengths required in the AGA Report No. 3 (1985) result in 
statistically significant bias. Since the AGA Report No. 3 (1985) is no 
longer readily available to the public, and cannot be incorporated by 
reference, this section includes equations that approximate the meter 
tube length graphs in the AGA Report (1985), Figures 4-8.
    Proposed Sec.  3175.80(l) would set standards for thermometer 
wells, including the adoption of API MPMS 14.3.2.6.5 in proposed Sec.  
3175.80(l)(1). While the provisions of the API standard proposed for 
adoption in the proposed rule are the same as those in the AGA Report 
No. 3 (1985), several additional items would be added that constitute a 
change from Order 5. First, proposed Sec.  3175.80(l)(2) would require 
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 MPMS 14.3.2.6.5, 
significant temperature measurement error could occur if the ambient 
conditions at the thermometer well are different. 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 require the thermometer well to be relocated inside 
of the heated meter house even if the existing location is in 
compliance with API MPMS 14.3.2.6.5.
    Proposed Sec.  3175.80(l)(3) would apply 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

[[Page 61663]]

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 orifice will generally result in less measurement 
bias; and therefore, the proposed rule would specify that this 
thermometer well is the one that must be used for primary temperature 
measurement.
    Proposed Sec.  3175.80(l)(4) would require 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 
proposed rule would include a new requirement that a thermally 
conductive liquid be used in the thermometer well because this would 
provide a more accurate temperature measurement.
    Marginal-volume FMPs would be exempt from the requirement to have 
thermometer wells because proposed Sec. Sec.  3175.91(c) and 
3175.101(e) would allow operators to estimate flowing temperature in 
lieu of a temperature measurement for marginal-volume FMPs. Order 5 
exempts meters measuring less than 200 Mcf/day from continuous 
temperature measurement; however, the only alternative to continuous 
measurement allowed in Order 5 is instantaneous measurement, which 
still requires a thermometer well. Therefore, the proposed requirement 
for low-volume, high-volume, and very-high-volume FMPs to have a 
thermometer well would not constitute a significant change from Order 
5.
    Proposed Sec.  3175.80(m) would require operators to locate the 
sample probe as required in Sec.  3175.112(b). This would be a new 
requirement. The reference to proposed Sec.  3175.112(b) is in proposed 
Sec.  3175.80(m) because the sample probe is part of the primary 
device. Please see the discussion of proposed Sec.  3175.112(b) for an 
explanation of the requirement.
    Proposed Sec.  3175.80(n) would include a new 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. Order 5 does not 
require meter tube inspection. Because meter tube inspections would not 
be required for marginal FMPs, they would be exempt from this 
requirement.


Sec.  3175.90  Mechanical Recorders (Secondary Device)

    Proposed Sec.  3175.90(a) would limit the use of mechanical 
recorders, also known as chart recorders, to marginal-volume and low-
volume FMPs, which would be a change from Order 5. Mechanical recorders 
would not be allowed at high-volume and very-high-volume FMPs because 
they may not be able to meet the uncertainty requirements of proposed 
Sec.  3175.30(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 is no data which indicate that the use of mechanical 
recorders results in statistically significant bias, mechanical 
recorders are proposed to be allowed at low-volume and marginal-volume 
FMPs due to the limited production from these facilities.
    Table 2 was developed as part of proposed Sec.  3175.90 to clarify 
and provide easy reference to the requirements that would apply to 
different aspects of mechanical recorders. No industry standards are 
cited in Table 2 because there are no industry standards applicable to 
mechanical recorders. The first column of Table 2 lists the subject of 
the standard. The second column of Table 2 contains a reference to the 
section and specific paragraph in the proposed rule for the standard 
that applies to each subject area. (The standards are prescribed in 
proposed Sec. Sec.  3175.91 and 3175.92.)
    The final two columns of Table 2 indicate the FMPs to which the 
standard would apply. The FMPs are categorized by the amount of flow 
they measure on a monthly basis as follows: ``M'' is marginal-volume 
FMP and ``L'' is low-volume FMP. As noted previously, mechanical 
recorders would not be allowed at high-volume and very-high-volume 
FMPs; therefore, the table in this section does not include 
corresponding columns for them. Definitions for the various FMP 
categories are given in proposed 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 proposed requirement.


Sec.  3175.91  Installation and Operation of Mechanical Recorders

    Proposed Sec.  3175.91(a) would set requirements for gauge lines, 
which Order 5 does not address. 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 require a 
minimum gauge line inside diameter of 0.375'' 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.
    Proposed Sec.  3175.91(a)(2) would allow 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.
    Proposed Sec.  3175.91(a)(3) would require 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.
    Proposed requirements in Sec.  3175.91(a)(4) through (7) 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 MPMS 14.3.2.5.4.3 recommends that gauge lines be 
the same diameter along their entire length, which would be adopted as 
a minimum standard in proposed paragraph (a)(4).
    Proposed Sec. Sec.  3175.91(a)(5) and (6) 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

[[Page 61664]]

proposed paragraphs would allow only the static-pressure connection in 
a gauge line and would 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. Sec.  3175.91(a)(7) 
proposes to limit the gauge lines to 6 feet in length, again to 
minimize the gas contained in the gauge lines.
    Marginal-volume FMPs would be exempt from the requirements of 
proposed Sec.  3175.91(a) because any bias or uncertainty caused by 
improperly designed gauge lines of marginal-volume and low-volume FMPs 
would not have a significant royalty impact.
    Proposed Sec.  3175.91(b) would require that all differential pens 
record at a minimum of 10 percent of the chart range for the majority 
of the flowing period. This would be a change from Order 5, which has 
no requirements for the differential pen position for meters measuring 
100 Mcf/day or less on a monthly basis. However, the integration of the 
differential pen when 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. Marginal-volume FMPs would be exempt from 
this requirement due to the cost associated with compliance.
    The proposed rule would eliminate the current requirement in Order 
5 that the static pen operate in the outer 2/3 of the chart range for 
the majority of the flowing period, regardless of flow rate. The 
primary purpose of this requirement in Order 5 was to reduce 
measurement uncertainty caused by the operation of the static pen near 
the hub. However, because proposed Sec.  3175.30(a) would exempt 
marginal-volume and low-volume FMPs from uncertainty limitations, this 
requirement would no longer be necessary thereby relieving an 
operational burden at these FMPs.
    Proposed Sec.  3175.91(c) would require the flowing temperature to 
be continuously recorded for low-volume FMPs. Flowing temperature is 
needed to determine flowing gas density, which is critical to 
determining flow rate and volume. Order 5 requires continuous 
temperature measurement only for meters measuring more than 200 Mcf/
day. For meters flowing 200 Mcf/day or less, the use of an indicating 
thermometer is allowed under Order 5. 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 proposed Sec.  
3175.30(c) would prohibit bias that is statistically significant for 
low-volume FMPs, we propose applying the requirement for continuous 
recorders to low-volume FMPs, but not to marginal-volume FMPs, as 
specified in Table 2.
    Proposed Sec.  3175.91(d) would require certain information to be 
available on-site at the FMP and available to the AO at all times. This 
requirement would allow the BLM to calculate the average flow rate 
indicated by the chart and to verify compliance with this rule. The 
information that would be required under proposed Sec.  3175.91(d)(2), 
(3), (7), and (8) is not required under Order 5, but typically is 
already available on-site. 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. 
Therefore, because this information is typically already available on 
site, the proposed requirement would not be a significant change from 
current industry practice.
    The information that the operator would have to retain on-site at 
the FMP under proposed Sec.  3175.91(d)(1), (4), (5), (6), (9), (10), 
(11), (12), and (13) is not currently required and thus typically has 
not been maintained on-site as a matter of practice. This proposed 
requirement therefore represents a change from Order 5. The required 
information proposed in these paragraphs includes the differential 
pressure bellows range, the relative density of the gas, the units of 
measure for static pressure (psia or psig), the meter elevation, the 
orifice bore diameter, the type and location of flow conditioner, the 
date of the last orifice plate inspection, and the date of the last 
meter verification. The BLM is proposing to require this information to 
be maintained on-site to enable the AO to determine if the meter is 
operating in compliance with this proposed rule and to determine the 
reasonableness of reported volume.
    Proposed Sec.  3175.91(e) would require 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 to determine volume, any parameters 
recorded off the chart will not be accounted for, which results in 
biased measurement. Although this would be a new requirement, operating 
a mechanical recorder within the range of the elements is common 
industry practice and would not constitute a significant change.


Sec.  3175.92  Verification and Calibration of Mechanical Recorders

    Proposed Sec.  3175.92(a) would set requirements for the 
verification and calibration of mechanical recorders upon installation 
or after repairs, and would define the procedures that operators would 
be required to follow. Order 5 also requires a verification of 
mechanical recorders upon installation or after repairs. This proposal 
would be a minor change to Order 5 requirements because the proposed 
rule differentiates the procedures that are specific to this type of 
verification from a routine verification that would be required under 
Sec.  3175.92(b) of the proposed rule.
    Proposed Sec.  3175.92(a)(1) would require the operator to perform 
a successful leak test before starting the mechanical recorder 
verification. While the requirement for a leak test is in Order 5, the 
proposed rule would specify the tests that operators would have to 
perform. We are proposing 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 provision would also be added 
to this section requiring a successful leak test to precede a 
verification. This is implied in Order 5, but not explicitly stated.
    Proposed Sec.  3175.92(a)(2) would require that the differential- 
and static-pressure pens operate independently of each other, which is 
accomplished by adjusting the time lag between the pens. Although Order 
5 includes a requirement for a time-lag test, the specific amount of 
required time lag would be new to this proposed rule. Examples of 
appropriate time lag are given for a 24-hour chart and an 8-day

[[Page 61665]]

chart because these are the charts that are normally used as test 
charts for verification and calibration.
    Proposed Sec.  3175.92(a)(3) would require a test of the 
differential pen arc. This is the same as the requirement Order 5.
    Proposed Sec.  3175.92(a)(4) would require 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 
element ranges. This would be a change from Order 5, which only 
requires a verification at zero and 100 percent of the element range 
and the normal operating position of the pens. The additional 
verification points would help 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 pounds per square 
inch, absolute (psia) instead of pounds per square inch, gauge (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 
proposed 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 would not be 
available for a newly installed or repaired recorder.
    Proposed Sec.  3175.92(a)(5) would require 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 would be a change from Order 5, which has no 
requirements for verification of the temperature element. This 
requirement would ensure that the temperature element is recording 
accurately over the range of expected flowing temperature.
    Proposed Sec.  3175.92(a)(6) would establish 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 2-1, 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. The proposed 
requirement is less restrictive than the language of Order 5, which 
requires ``zero'' error for all three elements. Our experience over the 
last 3 decades indicates that a zero error is unattainable.
    Proposed Sec.  3175.92(a)(7) would establish standards for when the 
static-pressure pen is offset to account for atmospheric pressure. This 
would be a new requirement. The equation used to determine atmospheric 
pressure is discussed in Appendix 2 of this proposed rule. This rule 
proposes to add 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.
    Proposed Sec.  3175.92(b) would establish requirements for how 
often a routine verification must be performed, with the minimum 
frequency, in months, shown in Table 2 in proposed Sec.  3175.90. Under 
Order 5, a verification must be conducted every 3 months. This proposed 
rule would continue to require verification every 3 months for a low-
volume FMP and would reduce the required frequency to every 6 months 
for a marginal-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 marginal-volume FMPs because chart recorders tend to drift 
more than the transducers of an EGM system.
    Proposed Sec.  3175.92(c) would establish procedures for performing 
a routine verification. These procedures would vary from the procedures 
used for verification after installation or repair, which are discussed 
in proposed Sec.  3175.92(a).
    Proposed Sec.  3175.92(c)(1) would require that a successful leak 
test be performed before starting the verification. See the previous 
discussion of leak testing under proposed Sec.  3175.92(a)(1). Section 
3175.92(c)(2) would prohibit any adjustments to the recorder until the 
as-found verifications are obtained. Although this is not an explicit 
requirement in Order 5, it is general industry practice to obtain the 
as-found readings before making adjustments. However, some adjustments 
that have traditionally been allowed under Order 5 would be 
specifically prohibited under this proposed 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 or not a volume correction would be 
required under 3175.92(f). This proposed section would make it clear 
that no adjustments, including the previous example, are allowed before 
obtaining the as-found values.
    Proposed Sec.  3175.92(c)(3) would require 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. This would be a change from Order 5, which only requires a 
verification at zero and 100 percent of the element range and the 
normal operating position of the pens. The additional verification 
points were included to better 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.
    Proposed Sec.  3175.92(c)(3)(i) would require that an as-found 
verification be done at a point that represents where the differential 
and static pens normally operate. This is the same requirement that is 
in Order 5. This section would require verification at the points where 
the pens normally operate only if there is enough information on-site 
to determine where these points are.
    Proposed Sec.  3175.92(c)(3)(ii) would establish additional 
requirements if there is not sufficient information on site 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 would 
be required at 5 percent 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

[[Page 61666]]

verification points would be required at the lower end to allow the 
calculation of flow-rate error throughout the range of the differential 
and static pressure elements. This would be a new requirement.
    Proposed Sec.  3175.92(c)(4) would establish 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. Order 5 has no requirements for 
determining the as-found values of flowing temperature and therefore 
this would be a new requirement.
    Proposed Sec.  3175.92(c)(5) would establish 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 proposed Sec.  3175.92(c)(3) or (4), are not 
within these thresholds, the element must be calibrated. For a 
discussion of the thresholds, see previous discussion of proposed Sec.  
3175.92(a)(6) and (7). The proposed requirement is less restrictive 
than the language of Order 5, which requires that the meter 
(differential pressure, static pressure, and temperature elements) be 
adjusted to ``zero'' error. In our experience over the last 3 decades, 
a zero error is unattainable.
    Proposed Sec.  3175.92(c)(6) would require 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 of proposed Sec.  3175.92(a)(3) for further 
explanation of this proposed requirement.
    Proposed Sec.  3175.92(c)(7) would require a test of the 
differential-pen arc. This is the same as the requirement in Order 5.
    Proposed Sec.  3175.92(c)(8) would require an as-left verification 
if an adjustment to any of the meter elements was made. As-left 
readings are implied in Order 5 because the operator is required to 
adjust the meter to zero error. Obtaining as-left readings whenever a 
calibration is performed is also standard industry practice. The 
purpose of the as-left verification is to ensure that the calibration 
process, required in proposed Sec.  3175.92(c)(5) through (7), was 
successful before returning the meter to service.
    Proposed Sec.  3175.92(c)(9) would establish 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 proposed Sec.  3175.92(c)(3) and (4), are not within the 
thresholds shown in Table 2-1, the element must be replaced and 
verified under proposed Sec.  3175.92(c)(5) through (7). The proposed 
requirement is less restrictive than the language of Order 5, which 
requires that the meter (differential pressure, static pressure, and 
temperature elements) be adjusted to ``zero'' error. In our experience 
over the last 3 decades, a zero error is unattainable.
    Proposed Sec.  3175.92(c)(10) would establish standards if the 
static-pressure pen is offset to account for atmospheric pressure. 
Please see previous discussion of proposed Sec.  3175.92(a)(7) for 
further explanation of this proposed requirement.
    Marginal-volume FMPs would not be exempt from any of the 
verification or calibration requirements in proposed Sec.  3175.92(c) 
because these requirements would not result in significant additional 
cost and are necessary to reduce potential measurement bias.
    Proposed Sec.  3175.92(d) would establish the minimum information 
required on a verification/calibration report. 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 proposed 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 proposed rule would require 
documentation similar to Order 5, with the addition of the normal 
operating points for differential pressure, static pressure, flowing 
temperature, and the differential-device condition. The proposed rule 
would add 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 
proposed rule would require the primary-device documentation because 
the primary device is pulled and inspected at the same time as the 
operator performs a mechanical-recorder verification.
    Proposed Sec.  3175.92(e) would require the operator to notify the 
AO at least 72 hours before verification of the recording device. Order 
5 requires only a 24-hour notice. The BLM proposes a longer 
notification period because a 24-hour notice is generally not enough 
time for the AO to be present at a verification. A 72-hour notice would 
be sufficient for the BLM to rearrange schedules, as necessary, to be 
present at the verification.
    Proposed Sec.  3175.92(f) would require 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. Order 5 requires operators to submit amended reports 
if the error is greater than 2 percent regardless of how much flow the 
error represents. 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 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 allowed to be measured with a chart recorder. Marginal-volume FMPs 
would be 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 discovered that an FMP measuring 15 Mcf/day 
was 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 OGOR reports and it could take 
several hours for both the BLM and ONRR to review and process those 
reports.
    This proposed paragraph would also clarify a similar requirement in 
Order 5 by defining the points that are used to determine the flow-rate 
error. Calculated flow-rate error will vary depending on the 
verification points

[[Page 61667]]

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.
    Proposed Sec.  3175.92(g) would require verification equipment to 
be certified at least every 2 years. The purpose of this requirement 
would be 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, although this would be a new 
requirement in this rule. The proposed paragraph would also require 
that proof of certification be available to the BLM and would set 
minimum standards as to what the documentation must include. Although 
this would also be a new requirement, it represents common industry 
practice.


Sec.  3175.93  Integration Statements

    Proposed Sec.  3175.93 would establish 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. This would be a new 
requirement.


Sec.  3175.94  Volume Determination

    Proposed Sec.  3175.94(a) would establish the methodology for 
determining volume from the integration of a chart. The methodology 
would include the adoption of the equations published in API MPMS 
14.3.3 or AGA Report No. 3 (1985) for flange-tapped orifice plates. 
Under this proposal, operators using mechanical recorders would have 
the option to continue using the older AGA Report No. 3 (1985) flow 
equation. (Operators using EGM systems, on the other hand, would be 
required to use the flow equations in API 14.3.3 (2013) (see proposed 
Sec.  3175.103).)
    There are three primary reasons for allowing mechanical recorders 
to use a less strict standard. First, chart recorders, unlike EGM 
systems, would be restricted to FMPs measuring 100 Mcf/day or less. 
Therefore, any errors caused by using the older 1985 flow equation 
would not have nearly as significant of an effect on measured volume or 
royalty than they would 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 proposed 100 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 (1985). The BLM 
is seeking data on the cost for chart integration companies to switch 
over to the new API MPMS 14.3.3 flow rate.
    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 (Cd) 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 MPMS 14.3.3 provides equations for calculating 
instantaneous flow rate, it is silent on determining volume. Therefore, 
the methodology presented in API MPMS 21.1 for EGM systems would be 
adapted 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.
    Proposed Sec.  3175.94(a)(3) defines the source of the data that 
goes into the flow equation.
    Proposed Sec.  3175.94(b) would establish 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. Order 5 requires the use of the atmospheric pressure defined 
in the buy/sell contract, if specified. If it is not specified, Order 5 
requires atmospheric pressure to be determined through a measurement or 
a calculation based on elevation. The BLM is proposing to eliminate 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.
    This rule also proposes to eliminate the option of operators 
measuring actual atmospheric pressure at the meter location for 
mechanical recorders. Instead, atmospheric pressure would be determined 
from an equation or Table (see Appendix 2) 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 change would 
have no significant impact on current industry practice. The

[[Page 61668]]

treatment of atmospheric pressure for mechanical recorders would be 
different than it would be for EGM systems because many EGM systems 
measure absolute pressure, whereas all mechanical recorders are gauge-
pressure devices (please see the discussion of proposed 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 2 to 
the proposed rule, produces similar results to the equation normally 
used for atmospheric pressure for elevations less than 7,000 feet mean 
sea level (see Figure 3).


Sec.  3175.100  Electronic Gas Measurement (Secondary and Tertiary 
Device)

    Proposed Sec.  3175.100 would set standards for the installation, 
operation, and inspection of EGM systems used for FMPs. The proposed 
standards include requirements prescribed in the proposed rule as well 
as requirements in referenced API documents. Table 3 was developed as 
part of proposed Sec.  3175.100 to clarify and provide easy reference 
to what requirements apply to different aspects of EGM systems and to 
adopt specific API standards as necessary. The first column of Table 3 
lists the subject area for which a standard is proposed. The second 
column of Table 3 contains a reference for the standard that would 
apply to the subject area described in the first column (by section 
number and paragraph, mostly in proposed Sec. Sec.  3175.101 through 
3175.104). The final four columns of Table 3 indicate the FMP 
categories to which the standard would apply. As is the case in other 
tables, the FMPs are categorized by the amount of flow they measure on 
a monthly basis as follows: ``M'' is marginal-volume FMP, ``L'' is low-
volume FMP, ``H'' is high-volume FMP, and ``V'' is very-high-volume 
FMP. Definitions for the various classifications are given in proposed 
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 
between inspections. For example, the maximum time between 
verifications, in months, is shown in Table 3 under ``Routine 
verification frequency.'' Any character in a column other than an ``x'' 
is explained in the body of the proposed standard.
    Proposed Sec.  3175.100 would adopt API MPMS 21.1.7.3, regarding 
EGM equipment commissioning; API MPMS 21.1.9, regarding access and data 
security; and API MPMS 21.4.4.5, 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 MPMS 21.1 (1993); therefore, this is not a 
significant change from existing requirements.


Sec.  3175.101  Installation and Operation of Electronic Gas 
Measurement Systems

    Proposed Sec.  3175.101(a) would set requirements for manifolds and 
gauge lines, which are not addressed in Order 5. Gauge lines connect 
the pressure taps on the primary device to the EGM secondary device and 
can contribute to bias and uncertainty if not properly designed and 
installed. (The requirements in this proposed section are similar to 
the requirements for installation and operation of gauge lines used in 
mechanical recorders.)
    It is standard industry practice to install gauge lines with a 
minimum inside diameter of 0.375'', as is proposed in Sec.  
3175.101(a)(1). The intent of this standard is to reduce frictional 
effects potentially caused by smaller line sizes.
    Proposed Sec.  3175.101(a)(2) would be a new requirement that gauge 
lines be made only of stainless steel. Carbon steel, copper, plastic 
tubing, or other material could corrode and leak, presenting a safety 
issue as well as biased measurement.
    Proposed Sec.  3175.101(a)(3) would require 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. While 
both of these requirements are new, they do not represent a significant 
change from standard industry practice.
    The requirements in proposed Sec.  3175.101(a)(1), (4), (5), (6) 
and (7) are intended to reduce a phenomenon known as ``gauge line 
error,'' 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 MPMS 14.3.2.5.4.3 recommends that 
gauge lines be the same diameter along their entire length, which would 
be adopted as a minimum standard in proposed Sec.  3175.101(a)(4).
    Proposed Sec. Sec.  3175.101(a)(5) and (6) 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 would prohibit anything except the static-
pressure connection in a gauge line, and are intended to 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 and other equipment. A 
second set of transducers would be allowed if the operator chooses to 
employ redundancy verification. Proposed Sec.  3175.101(a)(7) would 
limit the gauge lines to 6 feet in length, again to minimize the amount 
of gas volume contained in the gauge lines. Both of these requirements 
would be new.
    Marginal-volume FMPs would be exempt from the requirements of 
proposed Sec.  3175.101(a) because the potential effect on royalty 
would be minimal and our experience suggests that the costs would 
outweigh potential royalty benefits.
    Proposed Sec.  3175.101(b) and (c) would specify the minimum 
information that the operator would have to maintain on site 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; (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 and transducers have been type-tested under the 
protocols described in proposed Sec. Sec.  3175.130 and 3175.140; (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.
    Proposed Sec.  3175.101(b) would require that each EGM system 
include a display and would set minimum requirements for the 
information to be displayed. The proposed requirements are similar to 
existing requirements in paragraph 4 of the statewide NTLs for EFCs 
with the following additions and modifications:
    (1) Proposed Sec.  3175.101(b)(3) would require the units of 
measure to be on the display; in contrast, the statewide NTLs only 
require the units of measure to be on site. We propose this change 
because of the potential to misidentify the units of measure on the 
data card that would otherwise be required.
    (2) Instead of a meter identification number as currently required, 
Sec.  3175.101(b)(4)(i) would require the

[[Page 61669]]

new FMP number to be displayed so that the BLM can identify the meter.
    (3) The software version requirement proposed in Sec.  
3175.101(b)(4)(ii) is in addition to existing requirements and would be 
used to ensure that the software version in use has gone through the 
testing protocol proposed in Sec. Sec.  3175.130 and 3175.140.
    (4) The previous day flow time proposed in Sec.  
3175.101(b)(4)(viii) would be a new requirement to allow the 
calculation of average daily flow rate.
    (5) The previous day average differential pressure, static 
pressure, and flowing temperature proposed in Sec.  3175.101(b)(4)(ix), 
(x), and (xi), respectively, would be new requirements which would 
provide the BLM with average values to use in the determination of 
uncertainty and would define the ``normal'' operating point for 
verification purposes. The BLM proposes these requirements because 
instantaneous values are often not representative of typical operating 
conditions, especially in meters that experience highly variable flow 
rates such as those associated with plunger lift operations.
    (6) The proposed requirement for displaying relative density in 
Sec.  3175.101(b)(4)(xii) would be a new requirement because relative 
density is typically updated every time a new gas analysis is obtained 
and the updates are often done remotely, making it difficult to update 
a data card in a timely manner.
    (7) The primary device information proposed in Sec.  
3175.101(b)(4)(xiii) would be required because the size can change 
every time an orifice plate or other type of primary device is changed 
and the calculation of flow rate is based on these values.
    (8) Proposed Sec.  3175.101(b)(5) would require that the 
instantaneous values be displayed consecutively to allow a more 
accurate verification of the instantaneous flow rate. The more time 
that passes between the display of instantaneous data, the more the 
flow rate can change over that time and the less accurate the 
verification is.
    Proposed Sec.  3175.101(c) would set requirements for information 
that must be on site, but not necessarily on the EGM system display. 
These requirements are similar to the requirements of the statewide 
NTLs for EFCs, with the following additions and modifications:
    (1) The elevation of the FMP that would be required under proposed 
Sec.  3175.101(c)(1) would allow the BLM to verify the value of 
atmospheric pressure used to derive the absolute static pressure.
    (2) Proposed Sec.  3175.101(c)(3) would require the make, model, 
and location of flow conditioners to be identified to ensure that all 
flow conditioners have been approved by the BLM and installed according 
to BLM requirements.
    (3) Proposed Sec.  3175.101(c)(4) would require that the location 
of 19-tube-bundle flow straighteners (if used) be indicated in the on-
site records so that BLM inspectors can verify that they have been 
installed to API specifications.
    (4) The flow computer make and model number that would be required 
under proposed Sec.  3175.101(c)(5) and (c)(6) would allow the BLM to 
verify that the flow computer has been tested under the protocol 
described in proposed Sec.  3175.140 and has been approved by the BLM 
as required in proposed Sec.  3175.44.
    (5) Proposed Sec.  3175.101(c)(9) and (c)(10) would add 
requirements to maintain on site the dates of the last primary-device 
inspection and secondary-device verification. This would allow the BLM 
to determine whether the meter is being inspected and verified as 
required under proposed Sec. Sec.  3175.80(c), 3175.80(d), 3175.92(b) 
and 3175.102(b). Proposed requirements in Sec.  3175.101(c)(2), (3), 
(7) and (8) are the same as the existing requirements in the statewide 
NTLs for EFCs.
    Proposed Sec.  3175.101(d) would require the differential pressure, 
static pressure, and temperature transducers to be operated within the 
lower and upper calibrated limits of the transducer. Inputs that are 
outside of these limits would be 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 be 
the maximum value for which it was calibrated, even when the pressure 
being measured exceeds that value. For example, if a differential 
pressure transducer that has a calibrated range of 250 inches of water 
is measuring a differential pressure of 300 inches of water, the 
transducer output will be 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.
    Proposed Sec.  3175.101(e) would require the flowing-gas 
temperature to be continuously recorded. Flowing temperature is needed 
to determine flowing gas density, which is critical to determining flow 
rate and volume. Order 5 requires continuous temperature measurement 
for meters measuring more than 200 Mcf/day, while the proposed rule 
would require continuous temperature measurement on all FMPs except 
marginal-volume FMPs. Marginal-volume FMPs would be exempt from this 
requirement because the potential effect on royalty would be minimal 
and our experience suggests that the costs would outweigh potential 
royalty. For marginal-volume FMPs, any errors introduced by using an 
estimated temperature in lieu of a measured temperature would not have 
a significant impact on royalties.


Sec.  3175.102  Verification and Calibration of Electronic Gas 
Measurement Systems

    Proposed Sec.  3175.102(a) would include several specific 
requirements for the verification and calibration of transducers 
following installation and repair. Order 5 also requires a verification 
upon installation or after repairs. This would be a minor change to 
Order 5 to differentiate the procedures that are specific to this type 
of verification from the procedures required for a routine verification 
under proposed Sec.  3175.102(c). The primary difference between 
proposed Sec. Sec.  3175.102(a) and (c) is that an as-found 
verification would not be required if the meter is being verified 
following installation or repair.
    Proposed Sec.  3175.102(a)(1) would require a leak test before 
performing a verification or calibration. (Please see the previous 
discussion regarding proposed Sec.  3175.92(a)(1) for further 
explanation of leak testing.)
    Proposed Sec.  3175.102(a)(2) would require a verification to be 
done at the points required by API MPMS 21.1.7.3.3 (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 would be an addition to the 
requirements of Order 5 and the statewide NTLs for EFCs, and would 
include more verification points than are required for a routine 
verification described in proposed Sec.  3175.102(c). The purpose of 
requiring more verification points in this section would be: (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

[[Page 61670]]

verification is required to ensure that new or repaired equipment is 
working properly by verifying more points between the lower and upper 
calibrated limits of the transducer.
    Proposed Sec.  3175.102(a)(3) would also require 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 2 of the proposed rule, or be based on a measurement 
made at the time of verification for absolute-pressure transducers in 
an EGM system. This would be a change from requirements in Order 5 
because under this proposal, the value for atmospheric pressure defined 
in the buy/sell contract would no longer be allowed unless it met the 
requirements stated in this section. The BLM is proposing to eliminate 
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 proposed requirement is different from the requirements in 
proposed 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 would be 
allowed only when calibrating an absolute pressure transducer. It would 
not be 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 would not be allowed.
    Proposed Sec.  3175.102(a)(4) would require 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 be a new 
requirement that would eliminate measurement errors caused by static 
pressure zero-shift of the differential pressure transducer. Re-zeroing 
is recommended in API MPMS 21.1.8.2.2.3, but not required. The BLM 
proposes to require it here.
    Proposed Sec.  3175.102(b) would establish requirements for how 
often a routine verification must be done where the minimum frequency, 
in months, is shown in Table 3 in proposed Sec.  3175.100. Under Order 
5, a verification must be conducted every 3 months. The proposed rule 
would require 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 marginal-volume FMPs. Because there is a 
greater risk of measurement error for volume calculation for a given 
transducer error at higher-volume FMPs, the proposed rule would 
increase the verification frequency as the measured volume increases.
    Proposed Sec.  3175.102(c) would adopt the procedures in API MPMS 
21.1.8.2 for the routine verification and calibration of transducers 
with a number of additions and clarifications. Order 5 also requires a 
routine verification. The primary difference between Sec.  3175.102(a) 
and (c) is that an as-found verification is required for routine 
verifications.
    Proposed Sec.  3175.102(c)(1) would require a leak test before 
performing a verification. A leak test is not specified in API MPMS 
21.1.8.2; however, the BLM believes that performing a leak test is 
critical to obtaining accurate measurement. Please see previous 
discussion of proposed Sec.  3175.92(a)(1) for further explanation of 
leak testing.
    Proposed Sec.  3175.102(c)(2) and (3) would require that the 
operator perform a verification at the normal operating point of each 
transducer. This clarifies the requirements in API MPMS 21.1.8.2.2.3, 
which requires a verification at either the normal point or 50 percent 
of the upper user-defined operating limit. This section would also 
define how the normal operating point is determined because this is a 
common point of confusion for operators and the BLM.
    Proposed Sec.  3175.102(c)(4) would require 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 (see previous discussion of proposed Sec.  3175.102(a)(4) for 
further explanation of zero shift). API MPMS 21.1.8.2.2.3 recommends 
that this correction be made, but does not require it. API also 
provides a methodology for the correction. The correction methodology 
in API MPMS 21.1, Annex H would be required in this section.
    Proposed Sec.  3175.102(c)(5) would adopt the allowable tolerance 
between the test device and the device being tested as stated in API 
MPMS 21.1.8.2.2.2. This tolerance is based on the reference uncertainty 
of the transducer and the uncertainty of the test equipment.
    Proposed Sec.  3175.102(c)(6) would clarify that all required 
verification points must be within the verification tolerance before 
returning the meter to service. This requirement is implied by API MPMS 
21.1.8.2.2.2, but is not clearly stated.
    Proposed Sec.  3175.102(c)(7) would require the differential 
pressure transducer to be zeroed at working pressure before returning 
the meter to service. This is implied by API MPMS 21.1.8.2.2.3, but not 
required. Refer to the discussion of zero shift under 3175.102(a)(4) 
for further information.
    Proposed Sec.  3175.102(d) would allow for redundancy verification 
in lieu of a routine verification under Sec.  3175.102(c). Redundancy 
verification was added to the current version of API MPMS 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

[[Page 61671]]

EGM systems. If the readings vary by more than a set amount, both sets 
of transducers would have to be calibrated and verified. Operators 
would have the option of performing routine verifications at the 
frequency required under proposed 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 proposed rule would adopt API MPMS 
21.1.8.2 procedures for redundancy verifications with several additions 
and clarifications as follows.
    Proposed Sec.  3175.102(d)(1) would require the operator to 
identify separately the primary set of transducers from the set of 
transducers that is used as a check. This requirement would allow the 
BLM to know which set should be used for auditing the volumes reported 
on the Oil and Gas Operations Report (OGOR).
    Proposed Sec.  3175.102(d)(2) would require the operator to compare 
the average differential pressure, static pressure, and temperature 
readings taken by each transducer set every calendar month. API MPMS 
21.1.8.2 does not specify a frequency at which this comparison should 
be done.
    Proposed Sec.  3175.102(d)(3) would establish the tolerance between 
the two sets of transducers that would trigger a verification of both 
sets of transducers under proposed Sec.  3175.102(c). API MPMS 21.1 
does not establish a set tolerance. This proposed section would also 
require the operator to perform a verification within 5 days of 
discovering the tolerance had been exceeded.
    Proposed Sec.  3175.102(e) would establish requirements for 
documenting a verification and calibration. The new documentation 
requirements would be similar to the requirements in Order 5, with the 
following additions and modifications:
     The FMP number, once assigned, would be a new requirement 
and would take the place of the station or meter number previously 
required;
     The lease, communitization agreement, unit, or 
participating area number would no longer be required once the FMP 
number is assigned, because the FMP number would provide this 
information;
     The temperature and pressure base would no longer be 
required in this proposed rule since these values are set in regulation 
(43 CFR 3162.7-3);
     Recording the time and date of the previous verification 
would be a new requirement and was added to allow the BLM to enforce 
the required verification frequencies;
     Recording the normal operating point for differential 
pressure, static pressure, and flowing temperature would be a new 
requirement to allow the BLM to ensure that the required verification 
points were tested and to facilitate the determination of meter 
verification error.
     Recording the condition of the differential device would 
be a new requirement because documentation of differential device 
condition is needed to ensure accurate measurement. Since inspection of 
the primary device would be required at the same time a verification is 
performed, this was added to the verification report; and
     Recording information regarding the verification equipment 
would be a new requirement to allow the BLM to determine that the 
proper verification tolerances were used.
    This section would also establish the information that the operator 
must retain on site for redundancy verifications.
    Proposed Sec.  3175.102(f) would require the operator to notify the 
BLM at least 72 hours before verification of an EGM system. Order 5 
requires only 24-hour notice. A longer notification period is proposed 
because 24-hour notice is generally not enough time for the BLM to be 
present at a verification. A 72-hour notice would be sufficient for the 
BLM to rearrange schedules, as necessary, to be present at the 
verification.
    Proposed Sec.  3175.102(g) would require correction of flow-rate 
errors greater than 2 percent or 2 Mcf/day, whichever is less, if they 
are due to the transducers being out of calibration, by submitting 
amended reports to ONRR. This is a change from Order 5, which required 
amended reports only if the flow-rate error was greater than 2 percent. 
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 proposes to add an 
additional threshold of 2 Mcf/day to exempt amended reports on low-
volume FMPs.
    Proposed paragraph (9) would also clarify a similar requirement in 
Order 5 to submit corrected reports if the flow-rate-error threshold is 
exceeded by defining 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 3 
(proposed Sec.  3175.100), marginal-volume FMPs would be 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 
3175.92(f)).
    Proposed Sec.  3175.102(h)(1) would require verification equipment 
to be certified at least every 2 years. The purpose of this requirement 
would be 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 MPMS 21.1; however, the 
BLM believes that periodic certification is necessary. The proposal 
would not represent a change from existing requirements. This proposed 
requirement is consistent with requirements in the previous edition of 
API MPMS 21.1 (1993), which is adopted by the statewide NTLS for EFCs. 
The proposed section would also require that proof of certification be 
available to the BLM and would set minimum standards as to what the 
documentation must include. Although the minimum documentation 
standards would be a new requirement, they represent common industry 
practice.
    Proposed paragraph (b) would modify the test equipment requirements 
in the statewide NTLs by adopting language in API MPMS 21.1.8.4. The 
statewide NTLs, which adopted the standards of API MPMS 21.1 (1993), 
required that the test equipment be at least 2 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 MPMS 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 was 
not two times more accurate than the transducer being tested. For 
example, verifying a transducer with a reference accuracy of 0.10 
percent of 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

[[Page 61672]]

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 MPMS 21.1.8.4, and proposed Sec.  
3175.102(h), would 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 would have to be 
accounted for when determining overall measurement uncertainty. The BLM 
would 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.


Sec.   3175.103 Flow Rate, Volume, and Average Value Calculation

    Proposed Sec.  3175.103(a) would prescribe the equations that must 
be used to calculate the flow rate. Proposed Sec.  3175.103(a)(1) would 
apply to flange-tapped orifice plates and would represent a change from 
the statewide EFC NTLs because the NTLs allow the use of either the API 
MPMS 14.3.3 or the AGA Report No.3 (1985) flow equation. The proposed 
rule would not allow the use of the AGA Report No. 3 (1985) flow 
equation because it is not as accurate as the API MPMS 14.3.3 flow 
equation and can result in measurement bias. The NTLs also allow the 
use of either AGA Report 8 (API MPMS 14.2) \4\ or NX-19 \5\ to 
calculate supercompressibility. The proposed rule would only allow API 
MPMS 14.2 because it is a more accurate calculation.
---------------------------------------------------------------------------

    \4\ AGA Report 8, ``Compressibility Factors of Natural Gas and 
Other Related Hydrocarbon Gases'', is the same as API MPMS 14.2.
    \5\ NX-19 was published in 1961 by the AGA Pipeline Research 
Committee and was officially titled the ``PAR Research Project NX-
19''; it was the predecessor to API MPMS 14.2 for the calculation of 
compressibility factors.
---------------------------------------------------------------------------

    Proposed Sec.  3175.103(a)(2) would require 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 
were 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 require that only the equation 
used during testing be used in the field. This would be a new 
requirement.
    Proposed Sec.  3175.103(b) would establish a standard method for 
determining atmospheric pressure that is used to convert psig to psia. 
This would be a new requirement because Order 5 requires the use of the 
atmospheric pressure defined in the buy/sell contract, if specified. If 
it is not specified, Order 5 requires atmospheric pressure to be 
determined through a measurement or a calculation based on elevation. 
(See the previous discussion of proposed Sec.  3175.94(b) for an 
explanation of the rationale for this change.)
    Proposed Sec.  3175.103(c) would require that volumes and other 
variables used for verification be determined under API MPMS 21.1.4 and 
Annex B of API MPMS 21.1. This would be a change to existing 
requirements because the existing statewide EFC NTLs adopt the previous 
version of API MPMS 21.1.


Sec.  3175.104  Logs and Records

    Proposed Sec.  3175.104(a) would establish minimum standards for 
the data that must be provided in a daily and hourly quantity 
transaction record. The data requirements are listed in API MPMS 
21.1.5.2, with the following additions and modifications:
     The FMP number, once established, would be required on all 
reports (API MPMS 21.1 does not require this data);
     The number of required significant digits is specified. 
API MPMS 21.1.5.2 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 
quantity transaction record (QTR). The BLM added 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 is sufficient to recalculate the reported volumes to 
the necessary level of accuracy; and
     An indication of whether the QTR shows the integral value 
or average extension under API MPMS 21.1. (Integral value generally is 
the summation of the product of the square root of the differential 
pressure and the square root of the static pressure taken at one-second 
intervals over an hour or a day. Average extension is the integral 
value divided by the flowing time.) API MPMS 21.1 allows either the 
integral value or average extension to be reported; however, the 
recalculation of reported volume is performed differently depending on 
which value is given. For the BLM to use the appropriate equation to 
recalculate volumes, the BLM must know what value is listed.
    This proposed paragraph would require 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 this proposed paragraph, data submitted to the BLM that was 
generated by third-party software would not meet the requirements of 
this section and the BLM would not accept it.
    Proposed Sec.  3175.104(b) would be a new requirement that would 
establish 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 MPMS 21.1, which was adopted by the statewide 
NTLs for EFCs, with the following additions and modifications:
     The FMP number, once established, would be required on all 
reports;
     The software/firmware identifiers that would allow the BLM 
to determine if the software or firmware version was approved by the 
BLM;
     For marginal-volume FMPs, the fixed temperature, if the 
temperature is not continuously measured, that would allow the BLM to 
recalculate volumes; and
     The static-pressure tap location that would allow the BLM 
to recalculate volumes and verify the flow rate calculations done by 
the flow computer.

As described under proposed Sec.  3175.104(a), configuration logs 
generated by third-party software would not be accepted. This proposed 
paragraph would also require that the configuration log contain a 
snapshot report that would allow the BLM to verify the flow-rate 
calculation of the flow computer.

    Proposed Sec.  3175.104(c) would establish minimum standards for 
the data that must be provided in the event

[[Page 61673]]

log. This proposed section would require that the event log retain all 
logged changes for the time period specified in proposed Sec.  3170.7, 
published previously. See 80 FR 40,768 (July 13, 2015) This provision 
would be added to ensure that a complete meter history is maintained to 
allow verification of volumes. Proposed Sec.  3175.104(c)(1) would be a 
new requirement to record power outages in the event log. This is not 
currently required by API MPMS 21.1 or the statewide NTLs for EFCs. The 
BLM is proposing this requirement to ensure that the BLM can determine 
when the meter was not receiving data to calculate flow rate or volume.
    Proposed Sec.  3175.109(d) would require the operator to retain an 
alarm log as required in API MPMS 21.1.5.6. The alarm log records 
events that could potentially affect measurement, such as over-ranging 
the transducers, low power, or the failure of a transducer.


Sec.  3175.110  Gas Sampling and Analysis

    All of the provisions in proposed Sec.  3175.110 would be new, 
since the only requirement in Order 5 relating to gas sampling is for 
an annual determination of heating value. This proposed section would 
set standards for gas sampling and analysis at FMPs. Although there are 
industry standards for gas sampling and analysis, none of these 
standards were proposed for adoption 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 would be 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 is proposing the requirements described in this 
section. These requirements would address where a sample must be taken, 
how it must be taken, how the sample is analyzed, and how heating value 
is reported.
    Table 4 in this proposed section contains a summary of requirements 
for gas sampling and analysis. The first column of Table 4 lists the 
subject of the proposed standard. The second column contains a 
reference for the standard (by section number and paragraph) that would 
apply to each subject area. The final four columns indicate the 
categories of FMPs for which the standard would apply. The FMPs are 
categorized by the amount of flow they measure on a monthly basis. As 
in other tables, ``M'' is marginal-volume FMP, ``L'' is low-volume FMP, 
``H'' is high-volume FMP, and ``V'' is very-high-volume FMP. 
Definitions of the various classifications are included in proposed 
Sec.  3175.10. An ``x'' in a column indicates that the standard listed 
applies to that category of FMP.


Sec.  3175.111  General Sampling Requirements

    Proposed Sec.  3175.111(a) would establish 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.
    Proposed Sec.  3175.111(b) would set standards for heating 
requirements which are based on several industry references requiring 
the heating of all sampling components to at least 30 [deg]F above the 
hydrocarbon dew point. The purpose of the heating requirement is to 
prevent the condensation of heavier components, which could bias the 
heating value. This proposed section would apply to all sampling 
systems, including spot sampling using a cylinder, spot sampling using 
a portable gas chromatograph, composite sampling, and on-line gas 
chromatographs. Because most of the onshore FMPs will be downstream of 
a separator, the ``hydrocarbon dew point'' would be defined as the 
flowing temperature of the gas at the time of sampling, unless 
otherwise approved by the AO (see the proposed definition of 
``hydrocarbon dew point''). This would require 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.


Sec.  3175.112  Sampling Probe and Tubing

    Proposed Sec.  3175.112 would set standards for the location of the 
sample probe. The intent of the standard would be to obtain a 
representative sample of the gas flowing through the meter. Samples 
taken from the wall of a pipe or a meter manifold would not be 
representative of the gas flowing through the meter and could bias the 
heating value used in royalty determination.
    Proposed Sec.  3175.112(b)(1) places 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 
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 2.7 and 2.8) ranges from 2.8 to 4.5, depending on 
the Beta ratio. Therefore, the sample probe would have 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 
hydrocarbon dew point. It is likely that the gas at many FMPs is at or 
below the hydrocarbon dew point because many FMPs are immediately 
downstream of a separator. A separator necessarily operates at the 
hydrocarbon dew point, 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 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. As a result, the BLM believes 
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 capture 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 be vaporized because of the heating 
requirements in Sec.  3175.111(b).
    The BLM is requesting data supporting or contradicting any 
correlation between sample probe location and heating value or 
composition. The BLM is also requesting alternatives to this proposal, 
such as wet gas sampling techniques.
    Locating the sample probe in the same ambient conditions as the 
primary device, as proposed in Sec.  3175.112(b)(2), 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

[[Page 61674]]

primary device and the sample point, thereby biasing the heating value 
and relative density of the gas.
    Proposed Sec.  3175.112(c)(1) through (3) would set standards for 
the design of the sample probe, which are based on API MPMS 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.
    Proposed Sec.  3175.112(c)(4) would prohibit 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 hydrocarbon dew point, 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 would result in heating values lower than the actual heating 
value of the fluids passing through the meter. This would result in a 
bias that would be in violation of proposed Sec.  3175.30(c).
    Proposed Sec.  3175.112(d) would set standards for the sample 
tubing which are based on API MPMS 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.
    As specified in Table 4 in proposed Sec.  3175.110, marginal-volume 
FMPs are exempt from all requirements in proposed Sec.  3175.112 
because, based on BLM experience with this level of production, a 
requirement to install or relocate a sample probe in marginal-volume 
FMPs could cause the well to be shut in.


Sec.  3175.113  Spot Samples--General Requirements

    Proposed Sec.  3175.113(a) would provide an automatic extension of 
the time for the next sample if the FMP were not flowing at the time 
the sample was due. Sampling a non-flowing meter would not provide any 
useful data. A sample would be required to be taken within 5 days of 
the date the FMP resumed flow.
    Proposed Sec.  3175.113(b) would require the operator to notify the 
BLM at least 72 hours before gas sampling. A 72-hour notification 
period is proposed to allow sufficient time for the BLM to arrange 
schedules as necessary to be present when the sample is taken.
    Proposed Sec.  3175.113(c) would establish requirements for sample 
cylinders used in spot or composite sampling. Proposed Sec.  
3175.113(c)(1) and (2) would adopt requirements for cylinder 
construction material and minimum capacity that are based on API and 
GPA standards.
    Proposed Sec.  3175.113(c)(3) would require that sample cylinders 
be cleaned according to GPA standards. This proposed section also would 
require documentation of the cylinder cleaning.
    It is important to be able to verify that sample cylinders are 
clean before sampling to avoid contaminating a sample. Therefore, the 
BLM is seeking comment 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 
the cylinders are clean. The BLM is not aware of any industry standard 
or common industry practice that requires a seal to be used.
    Proposed Sec.  3175.113(d) would set standards for spot sampling 
using a portable gas chromatograph. This section primarily addresses 
the sampling aspects; the analysis requirements are prescribed in 
proposed 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 gas chromatograph, can also cause significant 
bias in heating value if not used properly. Proposed Sec.  
3175.113(d)(1) would adopt GPA standards for the material of 
construction, heating, cleaning, and operation of sampling separators. 
It would also require documentation that the sample separator was 
cleaned as required under GPA 2166-05 Appendix A.
    Proposed Sec.  3175.113(d)(2) would require the filter at the inlet 
to the gas chromatograph 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.
    Proposed Sec.  3175.113(d)(3) would require 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 purge any air that may otherwise enter the 
sample line.
    Proposed Sec.  3175.113(d)(4) would require portable gas 
chromatographs to adhere to the same minimum standards as laboratory 
gas chromatographs under proposed Sec.  3175.118.
    Proposed Sec.  3175.113(d)(5) would prohibit the use of portable 
gas chromatographs if the flowing pressure at the sample port was less 
than 15 psig, which can affect accuracy of the device. This proposed 
requirement is based on GPA 2166-05.


Sec.  3175.114  Spot Samples--Allowable Methods

    Proposed Sec.  3175.114 would adopt three spot sampling methods 
using a cylinder and one method using a portable gas chromatograph. The 
three allowable methods using a cylinder were selected for their 
ability to accurately obtain a representative gas sample at or near the 
hydrocarbon dew point, 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 proposes to adopt them verbatim.
    The most common method currently in use at points of royalty 
settlement for Federal and Indian leases is the ``Purging--Fill and 
Empty Method,'' which is one of the methods that would be allowed in 
the proposed rule; therefore, it is not expected that this requirement 
would result in any significant changes to current industry practice. 
Proposed Sec.  3175.114(a) would also allow the helium ``pop'' method 
and the floating piston cylinder method. The fourth proposed spot 
sampling method (proposed Sec.  3175.114(a)(4)) is the use of a 
portable gas chromatograph, which is discussed in proposed Sec.  
3175.113(d). Proposed Sec.  3175.114(d) would provide that the BLM 
would post other approved methods on its Web site.
    Proposed Sec.  3175.114(b) would allow 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 14.1.12.10 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, neither the floating piston 
cylinder method nor the portable gas chromatograph method would be 
allowed in conjunction with a vacuum gathering system.

[[Page 61675]]

Sec.  3175.115  Spot Samples--Frequency

    Proposed Sec.  3175.115(a) would require that gas samples at low-
volume FMPs be taken at least every 6 months. Gas samples would have to 
be taken at marginal-volume FMPs at least annually, which is the same 
requirement as in Order 5. The BLM determined that sampling no more 
often than annually has the potential for biasing the heating value. 
If, for example, an annual sample was 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 proposed Sec.  3175.30(c), which would 
require the absence of significant bias in low-volume FMPs. The BLM 
believes that sampling at low-volume FMPs at least every 6 months would 
reduce the potential for bias.
    Proposed Sec.  3175.115(a) would 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 4 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 a number of other factors that were included in the study. 
Instead, the study found that heating value variability appeared 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 practice 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 practice.
    The frequencies shown in Table 4 for high- and very-high-volume 
FMPs are typical of the sampling frequency required to obtain the 
heating value certainty levels that would be required in proposed Sec.  
3175.30(b)(1) and (2). Proposed Sec.  3175.115(b) would 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 would be required in proposed Sec.  3175.30(b)(1) and (2). 
Under proposed Sec.  3175.115(b), the BLM could increase or decrease 
the required sampling frequency given in Table 4. To implement this 
proposed requirement, the BLM would develop a database called the Gas 
Analysis Reporting Verification System (GARVS). This database would be 
used to collect gas sampling and analysis information from Federal and 
Indian oil and gas operators. GARVS would perform analysis of that data 
to implement other proposed gas sampling requirements as well. The 
sample frequency calculation in GARVS would be based on the heating 
values entered into the system under proposed Sec.  3175.120(f). GARVS 
would round 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.
    Proposed Sec.  3175.115(b)(2) would clarify 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.
    Proposed Sec.  3175.115(b)(3) would limit the maximum sampling 
frequency to once per week. If weekly sampling would still not be 
sufficient to achieve the certainty levels that would be required under 
3175.30(b)(1) or (2), then under 3175.115(b)(4), the BLM could require 
the operator to install a composite sampling system or an on-line gas 
chromatograph.
    Proposed Sec.  3175.115(c) would establish the maximum allowable 
time between samples for the range of sampling frequencies that the BLM 
would require, as shown in Table 5. This would allow 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).
    If a composite sampling system or on-line gas chromatograph is 
required by the BLM under proposed Sec.  3175.115(b)(5) or opted for by 
the operator, proposed Sec.  3175.115(d) would require that device to 
be operational within 30 days after the due date of the next sample. 
For example, if the required sampling frequency was weekly and the next 
sample was due on February 18th, the composite sampling system or on-
line gas chromatograph would have to be operational by March 18th. The 
operator would not be required to take spot samples within this 30-day 
time period. The BLM considers both composite sampling and the use of 
on-line gas chromatographs 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.
    Proposed Sec.  3175.115(e) would address meters where a composite 
sampling system or on-line gas chromatograph was removed from service. 
In these situations, the spot sampling frequency for that meter would 
revert to that required under proposed Sec.  3175.115(a) and (b).


Sec.  3175.116  Composite Sampling Methods

    Proposed Sec.  3175.116 would set standards for composite sampling. 
The BLM used API MPMS 14.1.13.1 as the basis for Sec.  3175.116(a) 
through (c). Proposed Sec.  3175.116(d) would require the composite 
sampling system to meet the heating-value uncertainty requirements of 
proposed Sec.  3175.30(b).


Sec.  3175.117  On-Line Gas Chromatographs

    Proposed Sec.  3175.117 would set standards for online gas 
chromatographs. Because there are few industry standards for these 
devices, the BLM is particularly interested in comments on these 
proposed requirements or whether different or alternative standards 
should be adopted. The BLM is aware that API MPMS 22.6, a testing 
protocol for gas chromatographs, is nearing completion and is 
requesting comments on whether it should be incorporated by reference 
in the final rule.


Sec.  3175.118  Gas Chromatograph Requirements

    Proposed Sec.  3175.118 would establish requirements for the 
analysis of gas samples. Under proposed Sec.  3175.118(a), these 
minimum standards would apply to all gas chromatographs, including 
portable, online, and stationary laboratory gas chromatographs. These 
requirements are derived primarily from two industry standards: GPA 
2166-00 and GPA 2198-03.
    Proposed Sec.  3175.118(b) would require that gas samples be run 
until three consecutive runs have met the repeatability standards 
stated in GPA 2261-00. Obtaining three consistent analysis results 
would ensure that any contaminants in the gas chromatograph system have 
been purged and that

[[Page 61676]]

system repeatability is achieved. This proposed section would also 
require that the sum of the un-normalized mole percents of the gas 
components detected are between 99 percent and 101 percent to ensure 
proper functioning of the gas chromatograph system. This requirement is 
based on GPA 2261-00. The mole percent 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 percent of 
propane would be 2.
    Proposed Sec.  3175.118(c) would set a minimum frequency for 
verification of gas chromatographs. More frequent verifications would 
be required for portable gas chromatographs 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 calibration. In contrast, laboratory gas chromatographs are not 
exposed to these conditions; therefore, they would not need to be 
verified as often.
    Proposed Sec.  3175.118(d) would require that the gas used for 
verification be different than the gas used for calibration. This 
requirement is 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 gas chromatograph would not be 
detected if the same gas is used for verification, which could lead to 
a biased heating value.
    Proposed Sec.  3175.118(e) would require a calibration of the gas 
chromatograph if the specified repeatability could not be achieved 
during a verification. The calibration would have to comply with GPA 
2261-00, Section 9. This section would clarify when a calibration is 
needed.
    Proposed Sec.  3175.118(f) would require the equivalent of an as-
left verification after the gas chromatograph was calibrated. A final 
verification would ensure that the calibration of the gas chromatograph 
was successful.
    Proposed Sec.  3175.118(g) would prohibit the use of a gas 
chromatograph that has not been verified under Sec.  3175.118(e). This 
requirement would ensure that gas samples from FMPs are analyzed with 
gas chromatographs that will yield accurate heating values.
    Proposed Sec.  3175.118(h) would adopt the calibration gas 
standards of GPA 2198-03. This requirement would ensure the accuracy of 
the gas measurement used to calibrate gas chromatographs.
    Proposed Sec.  3175.118(i) would require documentation of gas 
chromatograph verification to be retained as required under the record-
retention requirements in proposed Sec.  3170.7, published previously 
(80 FR 40768 (July 13, 2015)). For portable gas chromatographs, the 
documentation must be available onsite. The purpose of the latter 
requirement is that it would allow the BLM to inspect the verification 
documents while witnessing a spot sample that is taken with a portable 
gas chromatograph. If the verification had not been performed at the 
frequency required in proposed Sec.  3175.118(c)(1), or did not meet 
the standards of Sec.  3175.118(e), the gas chromatograph would not be 
allowed to analyze the sample.


Sec.  3175.119  Components to Analyze

    Proposed Sec.  3175.119 would establish the minimum gas components 
which the operator must analyze. Section 3175.119(a) would require an 
analysis through hexane+ for all FMPs and would also include carbon 
dioxide and nitrogen analysis. Analysis through hexane+ 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 hexane+ 
concentration given by the gas chromatograph. Under proposed Sec.  
3175.126(a)(3), the heating value of hexane+ would be derived from an 
assumed gas mixture consisting of 60 mole percent hexane, 30 mole 
percent heptane, and 10 mole percent octane. At concentrations of 
hexane+ below the threshold given in 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 require an extended analysis of 
the gas sample, through nonane+, if the concentration of hexane+ from 
the standard analysis is 0.25 mole percent or greater. This requirement 
would not apply to marginal-volume FMPs or low-volume FMPs. The 
threshold of 0.25 mole percent was derived through numerical simulation 
of the assumed composition of hexane+ (60 mole percent hexane, 30 mole 
percent heptanes, and 10 mole percent octane) compared to randomly 
generated values of hexane, heptanes, octane, and nonane. The numerical 
simulation showed that the additional uncertainty of the fixed hexane+ 
mixture required in Sec.  3175.126(a)(3) does not significantly add to 
the heating value uncertainties required in Sec.  3175.30(b), until the 
mole percent of hexane+ exceeds 0.25 mole percent. The BLM is seeking 
data that confirms or refutes the results of our numerical simulation. 
Specifically, we are seeking data comparing heating values determined 
with a hexane+ analysis with heating values of the same samples 
determined through an extended analysis.


Sec.  3175.120  Gas Analysis Report Requirements

    Proposed Sec.  3175.120 would establish minimum standards for the 
information that must be included in a gas analysis report. This 
information would allow the BLM to verify that the sampling and 
analysis comply with the requirements proposed in Sec.  3175.110, and 
would enable the BLM to independently verify the heating value and 
relative density used for royalty determination.
    Proposed Sec.  3175.120(b) would require that gas components not 
tested be annotated as such on the gas analysis report. It is common 
practice for industry to include a mole percent 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 percent for hydrogen sulfide to be ``0.00 percent,'' when, in 
fact, the sample was not tested for hydrogen sulfide. The BLM believes 
this practice to be potentially misleading.
    Proposed Sec.  3175.120(c) and (d) would adopt API MPMS 14.5 and 
14.2, respectively. The BLM believes that these API standards are 
appropriate for heating value, relative density, and base 
supercompressibility calculations.
    Proposed Sec.  3175.120(e) would require 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 would 
allow the BLM to verify heating-value and relative-density calculations 
and it would allow 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 proposed 43 CFR 3170.4, published previously. 
See 80 FR 40768 (July 13, 2015).
    Proposed Sec.  3175.120(f) would require operators to submit all 
gas analysis

[[Page 61677]]

reports to the BLM using the GARVS online computer system that the BLM 
is developing. The GARVS would be implemented before the effective date 
of the final rule. Operators would be 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.


Sec.  3175.121  Effective Date of a Spot or Composite Gas Sample

    Proposed Sec.  3175.121 would establish an effective date for the 
heating value and relative density determined from spot or composite 
sampling and analysis. Section 3175.121(a) would establish 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. Proposed Sec.  3175.121(b) would 
establish that the effective date could 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 would account 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. The proposed requirement 
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 require 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 
heating value and relative density determined from that sample are 
valid only for the time period the cylinder was collecting samples.


Sec.  3175.125  Calculation of Heating Value and Volume

    Proposed Sec.  3175.125(a) would be a new requirement that would 
define how the operator must calculate heating value. Proposed 
paragraphs (a)(1) and (a)(2) would define the calculation of gross and 
real heating value. Although this would be a new requirement, the 
calculation and reporting of gross and real heating value is standard 
industry practice.
    Proposed Sec.  3175.125(b)(1) would establish 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), the proposed method 
requires the use of a volume-weighted average heating value to be 
reported. Proposed Sec.  3175.125(b)(2) would establish 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. The 
proposed 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.


Sec.  3175.126  Reporting of Heating Value and Volume

    Proposed Sec.  3175.126 would be a new requirement that would 
define the conditions under which the heating value and volume would be 
reported for royalty purposes. The reporting of gross and real heating 
value in Sec.  3175.126(a) would be consistent with standard industry 
practice.
    The proposed requirement to report ``dry'' heating value (no water 
vapor) in proposed Sec.  3175.126(a)(1) would be a change for some 
operators because gas sales contracts often call for ``wet'' or 
saturated 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 
saturated with water vapor at 14.73 psi and 60\0\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 proposing to require a ``dry'' heating value 
determination basis unless the actual amount of water vapor is 
physically measured and reported on the gas analysis report. This 
requirement is consistent with an existing provision in ONRR 
regulations at 30 CFR 1202.152(a)(1)(i) which requires the heating 
value to be reported at the same level of water saturation as volume. 
Established BLM practice is reflected in BLM Washington Office 
Instruction Memorandum (IM) 2009-186, dated July 28, 2009, which 
explains:

    This IM establishes the BLM policy that, when verifying the 
heating value reported on OGOR-B, the dry reporting basis from the 
gas analysis must be used unless the water vapor content was 
determined as part of the analysis, in which case the real or actual 
heating value will be used. If it is found that the operator has 
been reporting on the wrong basis, it must be resolved per the 
instructions in IM 2009-174, ``Request for Modified or Missing Oil 
and Gas Operations Report from the Minerals Management Service.'' 
The description of what was found must state (for typical gas 
analyses): ``Gas volumes have been determined based on the 
assumption that no water vapor is present. Heating value must be 
based on the same degree of water saturation. The heating value 
must, therefore, be reported on a dry basis.''

    The Minerals Management Service (MMS) regulations (30 CFR 
202.152(a)(1)(i)) [6] state:
---------------------------------------------------------------------------

    \6\ Now ONRR regulations at 30 CFR 1202.152(a)(1)(i).

    ``Report gas volumes and British thermal unit (Btu) heating 
values, if applicable, under the same degree of water saturation.''
    The BLM has interpreted this to mean a dry or real/actual 
reporting basis. In order to determine gas volumes, the relative 
density (or specific gravity) of the gas must be known. The relative 
density is determined from the same gas analyses that are used to 
determine heating value. Because water vapor cannot be detected by 
most gas chromatographs, the vast majority of gas analyses do not 
include water vapor as a constituent of the gas sample even if some 
water vapor is present. While adjustments to the heating value of 
the gas can be made based on assumptions of water saturation, 
relative density is rarely adjusted to account for the water vapor 
that may or may not be present. In essence, the relative density 
used to determine volume is almost always on a ``dry'' basis because 
water vapor is excluded from the calculation. The ``dry'' relative 
density is included in the calculations to determine gas flow rate 
and gas volume; therefore, the volume is ultimately determined on a 
``dry'' basis. According to the MMS regulation cited above, if 
volume is reported on a ``dry'' basis, heating values must also be 
reported on a dry basis.
    In the rare instance where water vapor content is actually 
measured and included in the gas analysis, the relative density 
calculation includes the actual water vapor content. This would 
result in volume being

[[Page 61678]]

determined on a ``real'' or ``actual'' basis. If volume is 
determined on a real or actual basis, then the heating value must 
also be reported on a real or actual basis according to the MMS 
regulations.


IM 2009-186 at 2.

    The BLM would consider 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 is presented in the public comments on this proposed 
rule that shows this to be a valid assumption and under what flowing 
conditions the assumption is valid. Alternatively, if sufficient data 
is supplied, the BLM may consider adjusting volumes for water vapor in 
lieu of a heating value adjustment. The BLM will review information and 
comments submitted to determine if an approach different from the one 
proposed is justified.
    The proposed section also defines the acceptable methods to measure 
water vapor: A chilled mirror, a laser detection system, and other 
methods that the BLM may approve through the PMT. Stain tubes and other 
similar measurement methods would not be allowed because of the high 
degree of uncertainty inherent in these devices.
    Proposed Sec.  3175.126(a)(2) would require the heating value to be 
reported at 14.73 psia and 60[deg]F. Although this was not required in 
Order 5, it is currently required by ONRR regulations at 30 CFR 
1202.152(a)(1)(ii).
    The composition of hexane+ that would be required for heating value 
and relative density calculation is given in Sec.  3175.126(a)(3). This 
composition was based on examples shown in API MPMS 14.5, Annex B.
    Proposed Sec.  3175.126(b) would define the volume of gas that must 
be reported for royalty purposes. Proposed Sec.  3175.126(b)(1) would 
prohibit 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 may consider in the final rule 
allowing for water-vapor adjustment if sufficient data are submitted 
during the public comment period to support an adjustment, as discussed 
above. This would be a new requirement.
    Proposed Sec.  3175.126(b)(2) would require the unedited volume on 
a quantity transaction record (EGM systems) or an integration statement 
(mechanical recorders) to match the volume reported for royalty 
purposes, unless edits to the data could be justified and documented by 
the operator. This would be a new requirement and it is needed for 
verification of production.
    Proposed Sec.  3175.126(c) would establish new requirements for 
edits and adjustments to volume or heating value. Section 
3175.126(c)(1) would allow for estimating volumes or heating values if 
measuring equipment is out of service or malfunctioning. Although this 
is similar to a requirement in Order 5, additional requirements would 
be added to prescribe how the estimates would be determined.
    Proposed Sec.  3175.126(c)(2) would require 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 would require operators to thoroughly 
justify and document the edits made. This would include quantity 
transaction records and integration statements. The operator would 
retain the documentation as required under proposed Sec.  3170.7 and 
would submit it to the BLM upon request. This would be a new 
requirement.
    Proposed Sec.  3175.126(c)(3) would require 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 3175.126(c)(2). This would include quantity transaction 
records and integration statements. This would be a new requirement.
    Proposed Sec.  3175.126(c)(4) would require the amendment of the 
OGOR reports submitted to ONRR in the case of an inaccuracy discovered 
in an FMP. Although this would be a new requirement, it is similar to 
the requirement for correcting calibration errors in Order 5.


Sec.  3175.130  Transducer Testing Protocol

    Proposed Sec.  3175.130 would establish a testing protocol for 
differential-pressure, static-pressure, and temperature transducers 
used in conjunction with differential-flow meters at FMPs. This would 
be a new requirement. This section would be added to implement the 
requirements proposed in Sec.  3175.131(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 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 proposed 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.


Sec.  3175.131  General Requirements for Transducer Testing

    Proposed Sec.  3175.131(a) would establish standards for test 
facilities qualified to perform the transducer-testing protocol. 
Proposed Sec.  3175.130(a)(1) would require 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) is based on IEC Standard 1298-1, section 7.1.
    Proposed Sec.  3175.131(b) would require 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.
    In general, the testing requirements in paragraphs (c) through (h) 
of this proposed section 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 proposing (in paragraph (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 seeks comments on whether the 
testing

[[Page 61679]]

of five transducers is a statistically representative sample.


Sec.  Sec.  3175.132 and 3175.133  Testing of Reference Accuracy and 
Influence Effects

    Proposed Sec. Sec.  3175.132 and 3175.133 would 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.


Sec.  3175.134  Transducer Test Reporting

    Proposed Sec.  3175.134 would require documentation of the testing 
and the submission of the documentation to the PMT. The PMT would use 
the documentation to determine the uncertainty and influence effects of 
each make, model, and range of transducer tested.


Sec.  3175.135  Uncertainty Determination

    Proposed Sec.  3175.135 would establish 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 proposed Sec. Sec.  
3175.130 through 3175.134, the PMT would review the results. The BLM 
would 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.


Sec.  3175.140  Flow Computer Software Testing Protocol

    Proposed Sec.  3175.140 would provide that the BLM would approve a 
particular version of flow-computer software if the testing is 
performed under the testing protocol in proposed Sec. Sec.  3175.141 
through 3175.144, to ensure that calculations meet API standards. 
Unlike the testing protocol for transducers proposed in Sec.  3175.130, 
which is used to derive performance specifications, the testing 
protocol for flow computers would establish pass-fail criteria. This 
would be a new requirement. Testing would only be required for those 
software revisions that affect volume or flow rate calculations, 
heating value, or the audit trail.


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 MPMS 21.1, Annex E.
    Proposed Sec.  3175.141(a) would require that all testing be done 
by an independent laboratory to avoid any real or perceived conflict of 
interest in the testing.
    Proposed Sec.  3175.141(b)(1) would require that each make, model, 
and software version tested must be identical to the software version 
installed at an FMP. Proposed Sec.  3175.141(b)(2) would require that 
each software version be given a unique identifier, which would have to 
be part of the display (see proposed Sec.  3175.101(b)(4)(ii)) and the 
configuration log (see proposed Sec.  3175.104(b)(2)) to allow the BLM 
to verify that the software version has been tested under the protocol 
proposed in this section.
    Proposed Sec.  3175.141(c) would provide 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.
    Proposed Sec.  3175.141(d) would establish a pass-fail criteria for 
the software testing. The digital values obtained for the testing in 
proposed Sec. Sec.  3175.142 and 3175.143 would be entered into 
reference software approved by the BLM, and the resulting values of 
flow rate, volume, integral value, flow time, and averages of the live 
input variables would be compared to the values determined from the 
software under test. A maximum allowable error of 50 parts per million 
(0.005 percent) would be established in proposed Sec.  3175.141(d)(2).


Sec.  3175.142  Required Static Tests

    Proposed Sec.  3175.142(a) would set out six required tests to 
ensure that the instantaneous flow rate was being properly calculated 
by the flow computer. The parameters for each of the six tests set out 
in Tables 6 and 7 in this proposed section 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.
    Proposed Sec.  3175.142(b) would test 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.
    Proposed Sec.  3175.142(c) would test the ability of the event log 
to capture all required events, test the software's ability to handle 
inputs to a transducer that are beyond its calibrated span, and test 
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.


Sec.  3175.143  Required Dynamic Tests

    Proposed Sec.  3175.143 would establish required dynamic tests that 
would 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.


Sec.  3175.144  Flow-computer Software Test Reporting

    After a software version has been tested under proposed Sec. Sec.  
3175.141 through 3175.143, the PMT would review the results. If the 
test was deemed 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 
Web site (see proposed Sec.  3175.44).


Sec.  3175.150  Immediate Assessments

    Proposed Sec.  3175.150 would identify 10 specific violations that 
would be subject to elevated civil assessment amounts, as opposed to 
being subject to the provisions for major and minor violations 
generally under current guidance. The BLM's existing regulations at 43 
CFR 3163.1 and Order 3 establish assessments that an operator or 
operating rights owner may be subject to for failure to comply with the 
terms and conditions of a lease or any applicable legal requirements. 
The authority for the BLM to impose these assessments was explained in 
the preamble to the final rule in which 43

[[Page 61680]]

CFR 3163.1 was originally promulgated in 1987:

    The provisions providing assessments have been promulgated under 
the Secretary of the Interior's general authority, which is set out 
in Section 32 of the Mineral Leasing Act of 1920, as amended and 
supplemented (30 U.S.C. 189), and under the various other mineral 
leasing laws. Specific authority for the assessments is found in 
Section 31(a) of the Mineral Leasing Act (30 U.S.C. 188(a)), which 
states, in part ``. . . the lease may provide for resort to 
appropriate methods for the settlement of disputes or for remedies 
for breach of specified conditions thereof.'' All Federal onshore 
and Indian oil and gas lessees must, by the specific terms of their 
leases which incorporate the regulations by reference, comply with 
all applicable laws and regulations. Failure of the lessee to comply 
with the law and applicable regulations is a breach of the lease, 
and such failure may also be a breach of other specific lease terms 
and conditions. Under Section 31(a) of the Act and the terms of its 
leases, the BLM may go to court to seek cancellation of the lease in 
these circumstances. However, since at least 1942, the BLM (and 
formerly the Conservation Division, U.S. Geological Survey), has 
recognized that lease cancellation is too drastic a remedy, except 
in extreme cases. Therefore, a system of liquidated damages was 
established to set lesser remedies in lieu of lease cancellation. 
The BLM recognizes that liquidated damages cannot be punitive, but 
are a reasonable effort to compensate as fully as possible the 
offended party, in this case the lessor, for the damage resulting 
from a breach where a precise financial loss would be difficult to 
establish. This situation occurs when a lessee fails to comply with 
the operating and reporting requirements. The rules, therefore, 
establish uniform estimates for the damages sustained, depending on 
the nature of the breach. 52 FR 5384 (February 20, 1987).


In sum, these civil assessments are intended to reflect the costs 
incurred by the BLM associated with identifying these violations and 
ensuring compliance with applicable remedial requirements.
    The existing regulations establish assessments for major and minor 
violations generally and identify four violations that warrant 
immediate assessments. Those violations and corresponding assessments 
are: (1) Failure to install a blowout preventer or other equivalent 
well-control equipment, $500 per day, not to exceed $5,000; (2) 
Drilling without approval or causing surface disturbance on Federal or 
Indian surface preliminary to drilling without approval, $500 per day, 
not to exceed $5,000; (3) Failure to obtain prior approval of a well-
abandonment plan, $500 total; and, in Order 3, (4) Removing a Federal 
seal without BLM approval, $250. These assessments are in addition to 
the civil penalties authorized under Section 109 of the Federal Oil and 
Gas Royalty Management Act (FOGRMA), 30 U.S.C. 1719.
    As explained in connection with the changes to 43 CFR 3163.1 being 
proposed as part of this rule, the BLM is proposing that all civil 
assessments under Sec.  3163.1 or proposed subparts 3173, 3174, and 
3175, should be immediate. With respect to the requirements of the 
proposed subpart 3175, the proposed rule would identify 10 specific 
violations that would be subject to elevated assessments as opposed to 
being subject to the amounts specified under 43 CFR 3163.1 for major 
and minor violations. These violations would be subject to a $1,000 
assessment and include the following:
    1. New FMP orifice plate inspections were not conducted as required 
under proposed Sec.  3175.80(c);
    2. Routine FMP orifice plate inspections were not conducted as 
required under proposed Sec.  3175.80(d);
    3. Visual meter-tube inspections were not conducted as required 
under proposed Sec.  3175.80(h);
    4. Detailed meter-tube inspections were not conducted as required 
under proposed Sec.  3175.80(i);
    5. An initial mechanical recorder verification was not conducted as 
required under proposed Sec.  3175.92(a);
    6. Routine mechanical recorder verifications were not conducted as 
required under proposed Sec.  3175.92(b);
    7. An initial EGM system verification was not conducted as required 
under proposed Sec.  3175.102(a);
    8. Routine EGM system verifications were not conducted as required 
under proposed Sec.  3175.102(b);
    9. Spot samples for low-volume and marginal-volume FMPs were not 
taken as required under proposed Sec.  3175.115(a); and
    10. Spot samples for high- and very-high-volume FMPs were not taken 
as required under proposed Sec.  3175.115(a) and (b).
    The BLM chose the $1,000 figure because it approximates the average 
of what it would cost the agency, based on an analysis of its costs, to 
identify and document each of the aforementioned violations and verify 
that the necessary remedial actions have been completed. The BLM seeks 
comment on whether these assessments should be higher or lower or what 
other factors it should consider in setting them.
Miscellaneous Changes to Other BLM Regulations in 43 CFR Part 3160
    As noted at the beginning of this section-by-section analysis, the 
BLM is proposing other changes to provisions in 43 CFR part 3160. Some 
of the changes have been discussed already. The remaining proposed 
revisions are those noted here.
    1. Section 3162.7-3, Measurement of gas, would be rewritten to 
reflect this proposed rule.
    2. Section 3163.1, Remedies for acts of noncompliance, would be 
rewritten in part in several respects. As explained in connection with 
proposed revisions to proposed Sec.  3175.150, the BLM's existing 
regulations contain provisions authorizing the BLM to impose 
assessments on operators and operating rights owners for violation of 
the terms and conditions of their lease 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 these 
violations. These assessments are not intended to be punitive.
    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).\7\ As discussed with respect to 
proposed Sec.  3175.150, there are also currently four specific 
violations where the BLM's existing rules authorize the imposition of 
immediate assessments. The BLM is proposing to modify this approach. 
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, the BLM is 
proposing that all assessments under Sec.  3163.1 may be imposed 
immediately. The BLM believes that the notice and opportunity to cure 
currently specified for major and minor violations is 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 
responsibilities. As such, the BLM does not believe it is necessary to 
provide an additional corrective or abatement period before imposing an 
assessment for major or minor violations. This change will also result 
in administrative efficiencies. Under the

[[Page 61681]]

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 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 costs and 
occupy inspection resources.
---------------------------------------------------------------------------

    \7\ 43 CFR 3163.1(c) provides that ``[a]ssessments under 
paragraph (a)(1) of this section shall not exceed $1,000 per day, 
per operating rights owner or operator, per lease. Assessments under 
paragraph (a)(2) of this section shall not exceed a total of $500 
per operating rights owner or operator, per lease, per inspection.''
---------------------------------------------------------------------------

    Therefore, the BLM is proposing to revise 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.\8\ The 
revisions to paragraphs (a)(1) and (2) would maintain the BLM's 
discretion to impose such assessments on a case-by-case basis; however, 
the BLM is proposing to increase the assessments for major violations 
to $1,000 consistent with the other provisions proposed here as the 
nature of the violations are the same. The existing provisions found in 
subparagraphs 3163.1(a)(3) through (6) would remain unchanged.
---------------------------------------------------------------------------

    \8\ Under existing regulations, a ``major violation'' is one 
that ``causes or threatens immediate, substantial, and adverse 
impacts on public health and safety, the environment, production 
accountability, or royalty income'' (Order 3, Sec. (II)(m)). A 
``minor violation'' is defined as one that ``does not rise to the 
level of a `major violation.' '' (id., Sec. (II)(N)). As explained 
in the proposed rule to replace Order 3, the BLM is considering 
removing prescriptive regulatory definitions for ``Violation'' 
(major or minor) (80 FR 40,773, 40,787). Instead, the BLM would 
address these issues and the difference between a major and minor 
violation in an inspection and enforcement handbook, and, as 
appropriate, manuals or instructional memoranda (id.).
---------------------------------------------------------------------------

    The introductory language in paragraph (a) would also be revised to 
apply to ``any person'' and would no longer be limited to operating 
rights owners and operators. This proposed change would enable the 
agency 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. Thus, the BLM is proposing to revise 
the regulations to enable the agency to impose assessments directly on 
the party whose non-compliance imposes costs on the agency. (The 
discussion of the new immediate assessments in proposed Sec.  3175.150 
explains the authority for assessments of this kind.) The proposed 
change would also make Sec.  3163.1(a) consistent with the proposed 
revision to Sec.  3163.2.
    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. These assessments are already imposed 
immediately. Accordingly, no changes were required as a result of the 
proposed change in the general approach to assessments. The BLM has, 
however, proposed clarifications to paragraph (b) to make it consistent 
with the changes proposed for paragraph (a) and to acknowledge that 
certain assessments would be identified in proposed subparts 3173, 
3174, and 3175.
    In addition, the BLM proposes to revise the first two assessments 
found in paragraph (b) to make each of them flat assessments of $1,000 
that would be imposed 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. The BLM 
seeks comment on whether these assessments should be higher or lower or 
what other factors it should consider in setting them. Paragraph 
3163.1(b)(3) would be unchanged by this proposed rule.
    In connection with the proposed shift 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) would no longer be necessary. Therefore, paragraph (c) is proposed 
for deletion.
    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, would be removed. 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, and 
therefore the requirements of paragraph (d) were determined to be 
redundant and unnecessary.
    Finally, as a result of these changes, the current paragraph (e) 
would be re-designated as paragraph (c).
    3. Section 3163.2, Civil penalties, would be rewritten in part in 
several respects. First, in connection with the recently proposed 
subpart 3173, 80 FR 40,768 (July 13, 2015), the BLM proposes to add new 
language and provisions to address purchasers and transporters who are 
not operating rights owners to make Sec.  3163.2 consistent with the 
requirements of Section 109 of FOGRMA, 30 U.S.C. 1719, which subjects a 
purchaser or transporter to civil penalties if they fail to maintain 
and submit required records. As explained in the proposed rule for 
subpart 3173, this change resulted in the re-designation of paragraphs 
(a) and (b) of Sec.  3163.2. The revisions proposed in this rule assume 
the changes proposed in subpart 3173 are ultimately adopted.
    In addition to the changes proposed as part of the proposed rule 
for subpart 3173, the BLM proposes to revise paragraphs (a)(1) and 
(b)(1) to refer to ``any person'' and ``the person,'' respectively, 
rather than limiting the applicability of civil penalties to an 
operating rights owner or operator to be consistent with the statutory 
language found in Section 109(a) of FOGRMA, 30 U.S.C 1719(a). This 
proposed change would clarify that potential penalty liability exists 
for parties who contract with operating rights owners or operators to 
perform activities on Federal or Indian leases who violate applicable 
regulations, statutes, or lease terms in performing those activities. 
While the operating rights owner or operator is responsible (and liable 
for penalties) for violations committed by contractors, the contractors 
are also themselves subject to the requirements of the statutes, 
regulations, and lease terms. The BLM is proposing to revise the 
regulations to enable the agency to hold contractors directly 
responsible for violations they commit. Paragraph (g) also would be 
revised accordingly.
    In addition, on April 21, 2015, the BLM published an Advance Notice 
of Proposed rulemaking (ANPR) (80 FR 22148) in which it requested 
public comment on whether the current regulatory caps on civil penalty 
assessments in 43 CFR 3163.2 (b), (d), (e), and (f) should be removed. 
As

[[Page 61682]]

explained in the ANPR, the caps found in existing regulations are not 
required by statute and limit the total amount of the applicable 
penalties that can be assessed. Given that a modern oil and gas well 
can cost $5 million to $10 million dollars to drill, the BLM does not 
believe the existing caps provide an adequate deterrence for unlawful 
conduct, particularly drilling on Federal onshore leases without 
authorization and drilling into leased parcels in knowing and willful 
trespass. Similar concerns were expressed by the Department's OIG in a 
recent report, dated September 29, 2014--Bureau of Land Management, 
Federal Onshore Oil & Gas Trespass and Drilling Without Approval (No. 
CR-IS-BLM-0004-2014). In that report, the OIG expressed concern with 
the BLM's existing policies and procedures to detect trespass in or 
drilling without approval on Federal onshore oil and gas leases. Among 
other things, the OIG questioned the adequacy of the BLM's policies to 
deter such activities and recommended that the BLM pursue increased 
monetary fines.
    The comment period on the ANPR closed on June 19, 2015. The BLM 
received approximately 82,000 comments. Of the 82,000 received, roughly 
40 were unique, and the remainder were form comments. Of that 40, nine 
addressed the question of whether the caps imposed on civil penalties 
should be removed. Six of the nine comments that discussed the issue 
were in favor of changes to the existing caps; five asserted that 
existing caps do not provide adequate deterrence, while the sixth 
suggested that the caps be retained but increased to account for 
inflation. Three of the nine comments were generally opposed to any 
changes because of potential deterrence effects to development on 
public lands, but did not otherwise provide any detailed information.
    After consideration of comments received and the concerns 
identified by the BLM and the OIG, the BLM is proposing as part of this 
rulemaking to remove those caps. Paragraphs (b), (d), (e), and (f) 
would be rewritten accordingly, while maintaining the statutory limits 
imposed on the amount that may be assessed on a daily basis (30 U.S.C. 
1719(a)-(d)).\9\ With the proposed removal of the caps, paragraph (j) 
was determined to be unnecessary given that its requirements were 
tiered off the expiration of the cap periods in the existing 
regulations.
---------------------------------------------------------------------------

    \9\ The statutory limit on daily penalties associated with 
paragraphs (a) and (d) of 3163.2 appears in 30 U.S.C. 1719(a); the 
limit associated with paragraph (b) appears in 30 U.S.C. 1719(b); 
the limit associated with paragraph (e) appears in 30 U.S.C. 
1719(c); and the limit associated with paragraph (f) appears in 30 
U.S.C. 1719(d).
---------------------------------------------------------------------------

    Third, the BLM is also proposing to delete all of paragraph (g). 
The existing requirements of paragraph (g)(1) and (g)(2)(iii), which 
require initial proposed penalties to be at the maximum rate, are being 
removed because they are inconsistent with subsequent judicial and 
administrative decisions regarding the computation and setting of 
penalties. The BLM also determined that the requirements in paragraph 
(g)(1) and (g)(2)(iii) establishing caps on a per operating rights 
owner or operator per lease) would be removed as those provisions are 
inconsistent with the BLM's proposal to remove caps on penalties that 
are not required by statute. With respect to paragraphs (g)(2)(i) and 
(g)(2)(ii), the BLM is proposing to remove the additional notice 
procedure and corrective period for minor violations required under 
those paragraphs because it does not believe those provisions are 
necessary. The BLM's regulations governing oil and gas operations are 
clear, and provide more than adequate notice of what is required, 
making additional notification requirements unnecessary and 
administratively inefficient. As a result, all of paragraph (g) would 
be removed as part of this proposal. The removal of paragraph (g) means 
that existing paragraph (i) would be re-designated (g).
    Finally, the BLM is proposing to move the substance of existing 
paragraph (k), which requires the revocation of a transporter's 
authority to remove crude oil produced from, or allocated to, any 
Federal or Indian lease if it fails to permit inspection for required 
documentation under 43 CFR 3162.7-1(c)), to paragraph (d) in order to 
streamline the regulations.
    4. Paragraph (a) of Sec.  3165.3 Notice, State Director review and 
hearing on the record, would be revised to refer to ``any person'' 
consistent with the revisions to Section 3163.1 and 3163.2.
    5. Section 3164.1, Onshore Oil and Gas Orders, the table would be 
revised to remove the reference to Order 5 because this proposed rule 
would replace Order 5.

IV. Onshore Order Public Meetings, April 24-25, 2013

    On April 24 and 25, 2013, the BLM held a series of public meetings 
to discuss draft proposed revisions to Orders 3 and 5, as well as 
Onshore Oil and Gas Order No. 4 (oil measurement). The meetings were 
webcast so that tribal members, industry, and the public across the 
country could participate and ask questions either in person or over 
the Internet. More than 200 people either logged in or were physically 
present for at least a portion of the meetings. Following the forum, 
the BLM opened a 36-day informal comment period, during which 13 
comment letters were submitted. The following summarizes comments 
relating to Order 5 and gas measurement:
    1. Meter tube inspections. The BLM received numerous comments 
regarding the cost and potential for lost revenue due to the draft 
proposed meter tube inspection frequencies: Once every 5 years for FMPs 
measuring more than 15 Mcf/day and less than or equal to 100 Mcf/day; 
once every 2 years for FMPs measuring more than 100 Mcf/day and less 
than or equal to 1,000 Mcf/day; and once every year for FMPs measuring 
more than 1,000 Mcf/day. The commenters stated that the burden is even 
higher for welded meter runs, where the meter tubes cannot be easily 
disassembled and removed for inspection, than for flanged meter runs. 
Because the meter must be shut in to perform the inspections, the 
commenters stated that there would be no royalty revenue generated 
during the time the inspection is conducted, which could take up to one 
day to complete and longer if problems are found. In addition, the 
potential for increased measurement uncertainty and bias is minimal and 
in most cases wouldn't make up for the lost revenue while performing 
the inspection. One commenter recommended that the BLM should only 
require routine meter tube inspections on FMPs measuring more than 
1,000 Mcf/day. Another commenter suggested a threshold of 5,000 Mcf/
day. Other commenters recommended the use of a borescope in lieu of a 
complete meter tube inspection. The BLM has analyzed the comments and 
generally agrees with the points made by the commenters. As a result, 
the draft proposal was changed to propose that routine detailed meter 
tube inspections (i.e., disassembling and measuring the inside 
diameter) would only be required on high- and very-high volume FMPs and 
the frequency of these inspections was reduced from every 2 years to 
every 10 years for high-volume FMPs and from every year to every 5 
years for very-high-volume FMPs. In addition, the BLM would now require 
a visual inspection using a borescope as suggested by one of the 
commenters to identify those meter tubes where there are noticeable 
issues that would signal the need for a detailed meter tube inspection. 
A complete discussion of the proposed changes

[[Page 61683]]

appears in the earlier discussion of meter tube inspections under 
proposed Sec.  3175.80(h) and (i).
    2. Heating value reporting basis. The BLM received numerous 
comments objecting to the draft proposed requirement to report the 
heating value of gas removed from Federal or Indian leases on a ``dry'' 
basis. Heating value reported on a dry basis assumes that there is no 
water vapor in the gas. The commenters suggested that the BLM accept 
heating value reported on an ``as delivered'' basis instead, which 
assumes that the gas is saturated with water vapor at metered pressure 
and temperature as addressed in the GPA publication 2172-09. The 
rationale given by the commenters is that all gas contains some degree 
of water vapor and forcing operators to report on a dry basis will 
result in overpayment of royalty.
    Because the water vapor content in a gas sample is not easily 
measured, industry has been using various assumptions of water vapor 
content for decades. One commonly used assumption is that the gas is 
saturated with water vapor at 14.73 psia and 60[deg]F. This assumption 
has no factual basis and typically results in a reduction of heating 
value (and royalty) due to water vapor that cannot physically exist at 
the meter. The publication of GPA 2172-09 was the first industry 
standard addressing the ``as delivered'' basis, which assumes the gas 
is saturated with water vapor at metered pressure and temperature. The 
``as delivered'' basis, however, is still an assumption that lowers the 
heating value of the gas and the royalty that is owed. The BLM believes 
that in the absence of data showing otherwise, heating value should be 
reported based on the assumption that the gas contains no water vapor. 
To be marketable, gas must be dehydrated to pipeline specifications, 
which are generally very close to no water vapor. Moreover, under the 
longstanding ``marketable condition'' rule, the lessee must perform 
that dehydration without deducting the costs in determining royalty 
value. 30 CFR 1206.152(i); 1206.153(i); and 1206.174(h); Devon Energy 
Corp. v. Kempthorne, 558 F.3d 1030 (D.C. Cir. 2008). The BLM does not 
believe that the public, Indian tribes, or Indian allottees should 
suffer a reduced royalty based on an assumption that is unsupported by 
data.
    The BLM will consider allowing heating value to be reported on an 
as-delivered basis (or some adaptation of it) if we receive sufficient 
data showing that assuming water vapor saturation, or a certain level 
of water vapor, under metered pressure and temperature is reasonable 
and supported by field data. See discussion of proposed Sec.  
3175.120(a)(3) for further explanation of heating value reporting 
basis.
    3. Extended analysis. The BLM received numerous comments objecting 
to the draft proposed requirement for extended analysis of heavier 
hydrocarbons (through nonane +) if the hexane + concentration was 
greater than 0.25 mole percent. Some commenters objected to an extended 
analysis under any circumstance while other commenters suggested that 
the requirement be applied only to high-volume and very-high-volume 
FMPs. The reasoning given by the commenters is that extended analysis 
adds significant cost to performing a gas analysis and results in very 
little change in heating value. One commenter referenced a study which 
concluded that the difference between a hexane + analysis and an 
extended analysis resulted in less than a 2 Btu/scf difference.
    Based on these comments, the BLM has changed the extended analysis 
requirement in the proposed rule to apply only to high-volume and very-
high-volume FMPs. The BLM's analysis shows that using an assumed 
component distribution for hexane+ (60 percent hexane, 30 percent 
heptane, and 10 percent octane) results in additional uncertainty as 
the hexane+ concentration increases, but does not result in 
statistically significant bias. Because the heating value certainty 
standards proposed in Sec.  3175.30(b) do not apply to marginal-volume 
and low-volume FMPs, marginal- and low-volume FMPs should not be 
subject to the proposed extended analysis requirement. The BLM may 
consider further modifications to the proposed extended analysis 
requirement if commenters submit sufficient extended analysis data that 
show there is little difference in heating value between the hexane+ 
analysis and the extended analysis.
    4. Dynamic sampling frequency. The BLM received numerous comments 
on the draft proposed dynamic gas sampling frequency. The majority of 
the comments said it would be impractical to have the sampling 
frequency for high-volume and very-high-volume FMPs change after every 
sample to meet the heating value certainty requirements given in 
proposed Sec.  3175.115. Other comments said the draft proposed heating 
value certainty levels would be more restrictive than the heating value 
uncertainties given in publications such as GPA 2166. One comment 
concluded that the only way to meet the draft proposed certainty level 
for very-high-volume FMPs would be to install a composite sampling 
system which would be costly and may not work properly on wellhead 
applications.
    Based on these comments, the BLM is proposing a modified version of 
the dynamic sampling frequency discussed at the public meetings. 
Following the suggestion of one of the commenters, this proposed rule 
would establish an initial sampling frequency and then allow for an 
adjustment of that frequency based on historic heating-value 
variability. Rather than having sampling frequencies calculated to the 
nearest day, the calculated sampling frequency would be rounded down to 
the nearest of one of seven set frequencies: Weekly, every 2 weeks, 
monthly, every 2 months, every 3 months, every 6 months, and annually. 
The frequency would not change until a new calculation resulted in 
either an increase or decrease of the frequency. In addition, the BLM 
raised the uncertainty standards in proposed Sec.  3175.30(b). We 
believe the modifications will simplify implementation while still 
meeting the objective of achieving a set level of uncertainty. Please 
see the discussion of proposed Sec.  3175.115 for further explanation 
of gas sampling frequency.
    5. Grandfathering existing equipment. Several comments suggested 
that the BLM ``grandfather'' existing equipment from the requirements 
of the draft proposed rule. The BLM did not make any changes to the 
proposed rule based on these comments.
    Grandfathering is generally unworkable for two reasons. First, 
grandfathering would result in two tiers of equipment--older equipment 
that must meet the standards of a rule that is no longer in effect and 
newer equipment which would have to meet the standards of the new rule. 
This would not only require the BLM to maintain, inspect against, and 
enforce two sets of regulations (one of which no longer applies to 
equipment coming into service), but also to track which FMPs have been 
grandfathered and which are subject to the new regulations.
    Second, the reason for promulgating new regulations is that the BLM 
believes new regulations could better ensure accurate and verifiable 
measurement of oil and gas removed or sold from Federal and Indian 
leases. In lieu of grandfathering, the BLM has proposed grace periods 
for bringing existing facilities into compliance with the proposed 
standards (see proposed Sec.  3175.60). These grace periods are tiered 
to the volume measured by the FMP, giving more time to bring lower-

[[Page 61684]]

volume FMPs into compliance. The proposed rule would allow meter tubes 
at low volume FMPs to meet the eccentricity requirements required in 
AGA Report No. 3 (1985). Please see previous discussion of proposed 
Sec.  3175.80(f) for further explanation of this proposed requirement.
    6. Transducer and software type testing. The BLM received several 
comments expressing concern over the draft proposed requirement for 
type testing computer software and transducers that are already in use. 
The comments state that existing equipment met or exceeded API or GPA 
standards at the time of installation and, therefore, should be exempt 
from any new type-testing requirement. One commenter suggested that 
equipment used on marginal-volume and low-volume FMPs should be exempt 
from the type testing requirement.
    The BLM is unaware of any API or GPA standards relating to 
transducer performance; that is the reason we are proposing the 
transducer type-testing protocol in this rule (and why API is 
developing a new standard to address type testing). The proposed type-
testing requirement for transducers would not prescribe a standard for 
transducers. The type testing requirement would quantify the 
uncertainty of the device tested under specified test conditions. The 
results of the test would be incorporated into the calculation of 
overall measurement uncertainty. The transducer performance determined 
under the proposed protocol could, however, be sufficiently different 
from the manufacturer's specifications as to result in unacceptable 
overall meter uncertainty. The BLM does not believe that this will 
result in a significant cost burden to operators, and specifically 
requests comment on costs to comply with this proposed requirement.
    The BLM agrees with the comments regarding marginal-volume and low-
volume FMPs and has exempted both categories of FMPs in the proposed 
rule. Because transducer testing defines the uncertainty of the devices 
and marginal volume and low volume FMPs are not subject to uncertainty 
requirements, we did not feel that characterizing the performance of 
transducers used at these FMPs is necessary. See the discussion of 
proposed Sec. Sec.  3175.43 and 3175.130 for further explanation of 
this proposed requirement.
    However, the BLM did not exempt low-volume FMPs from the flow 
computer software testing. Errors in flow-computer software can cause 
biases in measurement. Because low-volume FMPs would have to meet the 
performance requirements for bias in proposed Sec.  3175.140, flow-
computer software testing requirements would apply.
    7. Purchasers and transporters. The BLM received one comment 
objecting to the draft proposed requirement that would allow the BLM to 
take enforcement actions against purchasers and transporters for not 
maintaining and submitting records. The requirement for purchasers and 
transporters to maintain records is imposed by Section 103(a) of 
FOGRMA, 30 U.S.C. 1713(a). The BLM believes that enforcement of that 
requirement is appropriate.
    8. Ultrasonic meters. The BLM received one comment suggesting that 
the proposed rule include ultrasonic meters. Although the BLM does not 
currently accept linear meters, including ultrasonic meters, for gas 
measurement, a linear meter approval section was added to the proposed 
rule (proposed Sec.  3175.48) based on this comment. However, the 
approval would be on a case-by-case basis as determined by the PMT.
    9. CO2 operations. The BLM received one comment about the necessity 
of gas sampling for CO2 operations because CO2 
has no heating value. While the BLM agrees that heating value would 
have no bearing on the royalty paid for CO2, gas sampling 
would still be required to determine the gas gravity which is used in 
volume determination. The BLM did not make any changes to the proposed 
rule based on this comment. The BLM can address specific requirements 
relating to CO2 operations on a case-by-case basis through 
the variance process.
    10. Volume thresholds. The BLM received one comment objecting to 
lowering the low-volume threshold from 100 Mcf/day in Order 5 to 15 
Mcf/day in the draft proposed rule. The proposed rule does not lower 
the threshold for low-volume FMPs. It would create a new category of 
marginal-volume FMPs. Order 5 makes only three exemptions from its 
requirements for meters measuring less than 100 Mcf/day: (1) The 
operator does not have to comply with Beta ratio limits; (2) The 
operator does not have to operate the differential pen of a chart 
recorder in the outer two-thirds of the chart for a majority of the 
flowing period; and (3) The operator does not need a continuous 
temperature recorder (the threshold for continuous temperature 
recorders is 200 Mcf/day). The proposed rule would generally maintain 
these exemptions for low-volume FMPs. The tier for marginal-volume FMPs 
was added to give additional relief from other requirements for those 
FMPs where production is on the edge of economic viability.
    11. Certainty levels for very-high-volume FMPs. Several commenters 
objected to the proposed 1.5 percent uncertainty 
requirement for very-high-volume FMPs, stating that this could only be 
achieved with near-ideal flowing conditions. These conditions do not 
typically exist at the on-lease measurement points typical to the BLM. 
After further consideration, the BLM agrees that an uncertainty of 
1.5 percent may be difficult to achieve, even for very-
high-volume FMPs. As a result, the BLM increased the proposed 
uncertainty requirement for very-high-volume FMPs to 2 
percent.

V. Procedural Matters

Executive Order 12866, Regulatory Planning and Review

    Executive Order 12866 provides that the Office of Information and 
Regulatory Affairs (OIRA) will review all significant rules. The OIRA 
has determined that this rule is significant because it would raise 
novel legal or policy issues.
    Executive Order 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 Executive Order directs agencies to consider regulatory approaches 
that reduce burdens and maintain flexibility and freedom of choice for 
the public where these approaches are relevant, feasible, and 
consistent with regulatory objectives. E.O. 13563 emphasizes further 
that regulations must be based on the best available science and that 
the rulemaking process must allow for public participation and an open 
exchange of ideas. We have developed this rulemaking consistent with 
these requirements.

Regulatory Flexibility Act

    The BLM certifies that this proposed rule would 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 mining, including the extraction of crude 
oil and natural gas, are defined by the SBA regulations as a business 
concern, including an individual proprietorship, partnership, limited

[[Page 61685]]

liability company, or corporation, with fewer than 500 employees.
    Of the 6,628 domestic firms involved in onshore oil and gas 
extraction, 99 percent (or 6,561) had fewer than 500 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 would 
be potentially affected by the proposed 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 proposed 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 proposed changes would increase the regulated community's 
annual costs by about $46 million, or an average of about $13,000 per 
entity per year (not including anticipated increased royalty on 
increased revenue discussed earlier). In addition, there would be one-
time costs associated with implementing the proposed changes of as much 
as $33 million, or an average of approximately $8,900 per entity 
affected by the proposed rule, phased in over a 3-year period. For 
further information on these costs estimates, please see the Economic 
and Threshold Analysis prepared for this proposed rule. The BLM is 
specifically seeking comment on that analysis and the assumptions used 
to generate these estimates.
    Recognizing that the SBA definition for a small business in the 
relevant categories is one with fewer than 500 employees, which 
represents a wide range of possible oil and gas producers, the BLM, as 
part of an 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 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 would 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) and at www.regulations.gov, search for 1004-AE17.
    All of the proposed provisions would apply to entities regardless 
of size. However, entities with the greatest activity (e.g., numerous 
FMPs) would likely experience the greatest increase in compliance 
costs.
    Based on the available information, we conclude that the proposed 
rule would 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 proposed rule is not a major rule under 5 U.S.C. 804(2), the 
Small Business Regulatory Enforcement Fairness Act. This rule would not 
have an annual effect on the economy of $100 million or more. As 
explained under the preamble discussion concerning Executive Order 
12866, Regulatory Planning and Review, the proposed rule would 
increase, by about $46 million annually, the cost associated with the 
development and production of gas resources under Federal and Indian 
oil and gas leases. There would also be a one-time cost estimated to be 
$33 million.
    This rulemaking proposes to replace Order 5 to ensure that gas 
produced from Federal and Indian oil and gas leases is more accurately 
accounted for. As described under the section concerning Executive 
Order 12866, Regulatory Planning and Review, the average estimated 
annual increased cost to each entity that produces gas from all Federal 
and Indian leases for implementing these changes would be about $13,000 
per year, and a one-time average cost of about $8,900 per entity, 
phased in over a 3-year period.
    This proposed rule:
     Would not cause a major increase in costs or prices for 
consumers, individual industries, Federal, State, tribal, or local 
government agencies, or geographic regions; and
     Would 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 proposed rule would not ``significantly or uniquely'' 
affect small governments. A Small Government Agency Plan is 
unnecessary.
     This proposed rule would 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 proposed rule is not a ``significant regulatory action'' under 
the Unfunded Mandates Reform Act. The changes proposed in this rule 
would not impose any requirements on any State or local governmental 
entity.

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

    The proposed rule would not have significant takings implications 
as defined under Executive Order 12630. A takings implication 
assessment is not required. This proposed rule would revise 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 proposed rule would not impose requirements or limitations on 
private property use or require dedications or exactions from owners of 
private property, and as such, the proposed rule is not a governmental 
action capable of interfering with constitutionally protected property 
rights. Therefore, the proposed rule would not cause a taking of 
private property or require further discussion of takings implications 
under this Executive Order.

Executive Order 13132, Federalism

    Under Executive Order 13132, the BLM finds that the proposed rule 
would not have significant Federalism implications. A Federalism 
assessment is not required. This proposed rule would 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

[[Page 61686]]

Departmental Manual 2, the BLM evaluated possible effects of the 
proposed rule on federally recognized Indian tribes. The BLM approves 
proposed operations on all Indian onshore oil and gas leases (other 
than those of the Osage Tribe). Therefore, the proposed rule has the 
potential to affect Indian tribes. In conformance with the Secretary's 
policy on tribal consultation, the BLM held three tribal consultation 
meetings to which more than 175 tribal entities were invited. The 
consultations were held in:
     Tulsa, Oklahoma on July 11, 2011;
     Farmington, New Mexico on July 13, 2011; and
     Billings, Montana on August 24, 2011.
    In addition, the BLM hosted a tribal workshop and webcast on April 
24, 2013. The purpose of these meetings was to solicit initial feedback 
and preliminary comments from the tribes. Comments from the tribes will 
continue to be accepted and consultation will continue as this 
rulemaking proceeds. To date, the tribes have expressed concerns about 
the subordination of tribal laws, rules, and regulations to the 
proposed rule; tribes' representation on the DOI GOMT; and the BLM's 
Inspection and Enforcement program's ability to enforce the terms of 
this proposed rule. While the BLM will continue to address these 
concerns, none of the concerns expressed relate to or affect the 
substance of this proposed rule.

Executive Order 12988, Civil Justice Reform

    Under Executive Order 12988, we have determined that the proposed 
rule would 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 proposed 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 Executive Order 13352, the BLM has determined that this 
proposed rule would not impede facilitating cooperative conservation 
and would take appropriate account of and consider the interests of 
persons with ownership or other legally recognized interests in land or 
other natural resources. This rulemaking process will involve 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 will provide that the programs, projects, and activities are 
consistent with protecting public health and safety.

Paperwork Reduction Act

I. 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. This proposed rule contains 
information collection requirements that are subject to review by OMB 
under the PRA. Collections of information include any request or 
requirement that persons obtain, maintain, retain, or report 
information to an agency, or disclose information to a third party or 
to the public (44 U.S.C. 3502(3) and 5 CFR 1320.3(c)). After 
promulgating a final rule and receiving approval from the OMB (in the 
form of a new control number), the BLM intends to ask OMB to combine 
the activities authorized by the new control number with existing 
control number 1004-0137, Onshore Oil and Gas Operations (expiration 
date January 31, 2018).
    The information collection activities in this proposed rule are 
described 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.
    The information collection request for this proposed rule has been 
submitted to OMB for review under 44 U.S.C. 3507(d). A copy of the 
request can be obtained from the BLM by electronic mail request to 
Jennifer Spencer at [email protected] or by telephone request to 202-
912-7146. You may also review the information collection request online 
at http://www.reginfo.gov/public/do/PRAMain.
    The BLM requests comments on the following subjects:
    1. Whether the collection of information is necessary for the 
proper functioning of the BLM, including whether the information will 
have practical utility;
    2. The accuracy of the BLM's estimate of the burden of collecting 
the information, including the validity of the methodology and 
assumptions used;
    3. The quality, utility, and clarity of the information to be 
collected; and
    4. How to minimize the information collection burden on those who 
are to respond, including the use of appropriate automated, electronic, 
mechanical, or other forms of information technology.
    If you want to comment on the information collection requirements 
of this proposed rule, please send your comments directly to OMB, with 
a copy to the BLM, as directed in the DATES and ADDRESSES sections of 
this preamble. Please identify your comments with ``OMB Control Number 
1004-XXXX.'' OMB is required to make a decision concerning the 
collection of information contained in this proposed rule between 30 to 
60 days after publication of this document in the Federal Register. 
Therefore, a comment to OMB is best assured of having its full effect 
if OMB receives it by November 12, 2015.
II. Summary of Proposed Information Collection Requirements
    Title: Measurement of Gas.
    OMB Control Number: Not assigned. This is a new collection of 
information.
    Description of Respondents: Holders of Federal and Indian (except 
Osage Tribe) oil and gas leases, operators, purchasers, transporters, 
and 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.
    Respondents' Obligation: Required to obtain or retain a benefit.
    Frequency of Collection: On occasion, with the following exception:
    Proposed Sec.  3175.120 would require the submission of gas 
analysis reports to the BLM within 5 days of the following due dates 
for the sample as specified in proposed Sec.  3175.115:
    (a) Gas samples at low-volume FMPs would be required at least every 
6 months;
    (b) Gas samples at marginal-volume FMPs would be required at least 
annually; and
    (c) Spot samples at high- and very-high-volume FMPs would be 
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).
    Abstract: This proposed rule would update 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 proposed rule would assist the BLM in 
ensuring the accurate measurement and proper reporting of all gas 
removed or sold from Federal and Indian leases, units, unit 
participating

[[Page 61687]]

areas, and areas subject to communitization agreements, by providing a 
system for production accountability by operators, lessees, purchasers, 
and transporters.
    Estimated Total Annual Burden Hours: The proposed rule would result 
in an estimated 273,208 responses and 470,716 burden hours annually.
    Estimated Total Non-Hour Cost: In order to comply with the proposed 
rule, operators would be required to install or modify equipment at an 
estimated cost of $32 million.
III. Proposed Information Collection Requirements
A. Documentation To Be Reviewed by the Production Measurement Team 
(PMT)
    Some of the information collection activities in the proposed rule 
would involve review of documentation by the PMT, made up of 
measurement experts from the BLM. The PMT would act as a central BLM 
advisory body for reviewing and approving devices and software not 
specifically addressed in the currently proposed regulations. The 
documentation submitted to the PMT would assist the BLM in ensuring 
that the hardware and software used in gas measurement are in 
compliance with performance standards proposed in this rule.
1. Flow Conditioner Testing Report
    Proposed Sec.  3175.46 would provide for listing of approved makes 
and models of isolating flow conditioners at www.blm.gov, and would 
provide for a procedure for seeking approval of additional makes and 
models. That procedure would involve preparing a report that would have 
to show the results of testing required by proposed Sec.  3175.46. Upon 
review of the report, the PMT would make a recommendation to the BLM to 
approve use of the device, disapprove use of the device, or approve it 
with conditions for its use. The BLM would add any approved device to a 
list of approved flow conditioners at www.blm.gov.
2. Differential Primary Devices Other Than Flange-Tapped Orifice Plates
    Proposed Sec.  3175.47 would authorize operators to seek approval 
to use a particular make and model of a differential primary device 
(other than flange-tapped orifice plates and those listed at 
www.blm.gov) by collecting all test data required under API 22.2 
(incorporated by reference, see Sec.  3175.31) and reporting it to the 
PMT. The PMT would review the test data to ensure that the primary 
device meets the relevant requirements and make a recommendation to the 
BLM to approve use of the device, disapprove use of the device, or 
approve its use with conditions.

3. Linear Measurement Device Testing Report

    Proposed Sec.  3175.48 would require submission of a report showing 
the results of each test required by the PMT. This report would be 
reviewed by the PMT and would be a pre-requisite for BLM approval of a 
linear type of meter in lieu of an approved type of differential meter. 
This requirement would assist the BLM in ensuring that meters used in 
gas measurement are in compliance with performance standards.'' The PMT 
would review the data to determine whether the meter meets the 
requirements of Sec.  3175.30, and make a recommendation to the BLM, 
which would approve use of the device, disapprove use of the device, or 
approve its use with conditions.
4. Transducer Testing Report
    Proposed Sec.  3175.43 would require submission of a report showing 
the results of each test required by proposed Sec. Sec.  3175.131 
through 3175.135, including all data points recorded. This report would 
be reviewed by the PMT, and would be a pre-requisite for BLM approval 
of a particular make and model of transducer for use in an electronic 
gas metering (EGM) system. This requirement would assist the BLM in 
ensuring that transducers used in gas measurement are in compliance 
with performance standards.
5. Flow-Computer and Software Version Testing Report
    Proposed Sec.  3175.44 would require submission of a report showing 
the results of each test required by proposed Sec. Sec.  3175.141 
through 3175.143, including all data points recorded. This report would 
be reviewed by the PMT, and would be a pre-requisite for BLM approval 
of software for use in an electronic gas measurement (EGM) system. This 
requirement would assist the BLM in ensuring that software used in gas 
measurement is in compliance with performance standards.
B. Other Proposed Information Collection Activities
1. Orifice Plate Inspection Report
    Proposed Sec.  3175.80(e) would require operators to retain, and 
submit to the BLM upon request, usually during a production audit, 
documentation for every orifice plate inspection and include that 
documentation as part of the verification report required at proposed 
Sec.  3175.92(d) (where the operator uses mechanical recorders) or 
proposed Sec.  3175.102(e) (where the operator uses EGM systems). The 
documentation would be required to include:
     The information required in proposed Sec.  3170.7(g) 
(i.e., the FMP number and the name of the company that created the 
record);
     Plate orientation (bevel upstream or downstream);
     Measured orifice bore diameter;
     Confirmation that the plate condition complies with the 
applicable API standard;
     The presence of oil, grease, paraffin, scale, or other 
contaminants found on the plate;
     Time and date of inspection; and
     Whether or not the plate was replaced.
2. Meter-Tube Inspection Report
    Proposed Sec.  3175.80(j) would require operators to retain, and 
submit to the BLM upon request, usually during a production audit, 
documentation demonstrating that the meter tube complies with 
applicable API standards and showing completion of all required 
measurements. Upon request, the operator would also be required to 
provide the information required in proposed Sec.  3170.7(g) (i.e., the 
FMP number and the name of the company that created the record).
3. Verification for Mechanical Recorders
    Proposed 43 CFR 3175.92(d) would require operators to retain, and 
submit to the BLM upon request, usually during a production audit, 
documentation of each verification for mechanical recorders. This 
documentation would be required to include:
     The information required in proposed Sec.  3170.7(g) 
(i.e., the FMP number and the name of the company that created the 
record);
     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);
     The type and location of taps (flange or pipe, upstream or 
downstream static tap);

[[Page 61688]]

     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.
4. Retention of Test Equipment Recertification
    Proposed Sec.  3175.92(g) would require operators to certify test 
equipment used to verify or calibrate the static pressure, differential 
pressure, and temperature elements/transducers at an FMP at least every 
2 years. Documentation of the recertification would be required to be 
on-site during all verifications and would be required to show:
     Test equipment serial number, make, and model;
     The date on which the recertification took place;
     The test equipment measurement range; and
     The uncertainty determined or verified as part of the 
recertification.
5. Mechanical Recorder Integration Statement
    Proposed Sec.  3175.93 would require operators to retain, and 
submit to the BLM upon request, usually during a production audit, 
integration statements containing the following information:
     The information required in proposed Sec.  3170.7(g) 
(i.e., the FMP number and the name of the company that created the 
record);
     The name of the company performing the integration;
     The month and year for which the integration statement 
applies;
     Meter-tube inside diameter (inches);
     Information of the primary device;
     Relative density (specific gravity);
     CO2 content (mole percent);
     N2 content (mole percent);
     Heating value calculated under Sec.  3175.125 (Btu/
standard cubic feet);
     Atmospheric pressure or elevation at the FMP;
     Pressure base;
     Temperature base;
     Static pressure tap location (upstream or downstream);
     Chart rotation (hours or days);
     Differential pressure bellows range (inches of water);
     Static pressure element range (psi); and
     For each chart or day integrated, the time and date on and 
time and date off, average differential pressure (inches of water), 
average static pressure, static pressure units of measure (psia or 
psig), average temperature ([deg] F), integrator counts or extension, 
hours of flow, and volume (Mcf).
6. Routine Verification for EGMs
    Proposed Sec.  3175.102(e)(1) would require operators to retain, 
and submit to the BLM upon request, usually during a production audit, 
documentation of each verification of an EGM . This documentation would 
be required to include:
     The information required in proposed Sec.  3170.7(g) 
(i.e., the FMP number and the name of the company that created the 
record);
     The time and date of the verification and the last 
verification date;
     Primary device data (meter-tube inside diameter and 
differential-device size, beta or area ratio);
     The type and location of taps (flange or pipe, upstream or 
downstream static tap);
     The flow computer make and model;
     The make and model number for each transducer, for 
component-type EGM systems;
     Transducer data (make, model, differential, static, 
temperature URL, and upper calibrated limit);
     The normal operating points for differential pressure, 
static pressure, and flowing temperature;
     Atmospheric pressure;
     Verification points (as-found and applied) for each 
transducer;
     Verification points (as-left and applied) for each 
transducer, if calibration was performed;
     The differential device inspection date and condition 
(e.g., clean, sharp edge, or surface condition);
     Verification of equipment make, model, range, accuracy, 
and last certification date;
     The name, contact information, and affiliation of the 
person performing the verification and any witness, if applicable; and
     Remarks, if any.
7. Redundancy Verification Check for EGMs
    Proposed 43 CFR 3175.102(e)(2) would allow redundancy verification 
in lieu of routine verification. If an operator opts to use redundancy 
verification, the proposed rule would establish standards for the 
information that must be retained and submitted to the BLM upon 
request, usually during a production audit. The following would be the 
required information for redundancy verification checks:
     The information required in proposed Sec.  3170.7(g) 
(i.e., the FMP number and the name of the company that created the 
record);
     The month and year for which the redundancy check applies;
     The makes, models, upper range limits, and upper 
calibrated limits of the primary set of transducers;
     The makes, models, upper range limits, and upper 
calibrated limits of the check set of transducers;
     The information required in API 21.1, Annex I, which 
includes comparisons of volume, energy, differential pressure, static 
pressure, and temperature both in tabular form (average values) and 
graphical form (instantaneous values);
     The tolerance for differential pressure, static pressure, 
and temperature as calculated under proposed 43 CFR 3175.102(d)(2) of 
this section; and
     Whether or not each transducer required verification under 
paragraph (c) of this section.
8. Quantity Transaction Record
    Proposed Sec.  3175.104(a) would require operators to retain the 
original, unaltered, unprocessed, and unedited daily and hourly 
quantity transaction record (QTR) and submit them to the BLM upon 
request, usually during a production audit. The proposed rule would 
require the QTR to contain the information identified in API 21.1.5.2 
(date and time identifier, quantity [volume, mass and/or energy], flow 
time, integral value/average extension, differential pressure average, 
static pressure average, temperature average, and relative density, 
energy content, composition, and/or density averages must be included 
if they are live inputs), with the following additions and 
clarifications:
     The information required in proposed Sec.  3170.7(g) 
(i.e., the FMP number and the name of the company that created the 
record);
     The volume, flow time, integral value or average 
extension, and the average differential pressure, static pressure, and 
temperature as calculated in proposed Sec.  3175.103(c), reported to at 
least five significant digits; and
     A statement of whether the operator has submitted the 
integral value or average extension.

[[Page 61689]]

9. Configuration Log
    Proposed 43 CFR 3175.104(b) would require operators to retain, and 
submit to the BLM upon request, usually during a production audit, the 
original, unaltered, unprocessed, and unedited configuration log. The 
proposed rule would require the configuration log to contain the 
information under API 21.1.5.4 (meter identifier, date and time 
collected, contract hour, atmospheric pressure for sites with gauge 
pressure transmitters, pressure base, temperature base, timestamp 
definition, calibrated or user defined span for differential pressure, 
no flow cutoff, calibrated or user defined span for static pressure, 
static pressure type [absolute or gauge], calibrated or user defined 
operating range for temperature or fixed temperature if not live, gas 
composition [if not live], relative density [if not live], 
compressibility [if not live], energy content [if not live], meter tube 
reference inside diameter, meter tube material, meter tube reference 
temperature, meter tube static pressure tap location [upstream/
downstream], orifice plate reference bore size, orifice plate material, 
orifice plate reference temperature. discharge coefficient calculation 
method/reference, gas expansion factor method/reference, 
compressibility calculation method/reference, quantity calculation 
period, sampling rate, variables included in the integral value, base 
compressibility of air, absolute viscosity [cP], ratio of specific 
heats, meter elevation or contract value of atmospheric pressure, other 
factors used to determine flow rate, alarm set points [differential 
pressure low, differential pressure high, static pressure low, static 
pressure high, flowing temperature low, flowing temperature high.] For 
primary devices other than an orifice plate, the primary device type, 
material, reference temperature, size, Beta/area ratio, discharge 
coefficient, and factors necessary to calculate discharge coefficient) 
including, with the following additions and clarifications:
     The information required in proposed Sec.  3170.7(g) 
(i.e., the FMP number and the name of the company that created the 
record);
     Software/firmware identifiers that comply with applicable 
API standards;
     The fixed temperature, if not live ([deg] F);
     The static-pressure tap location (upstream or downstream); 
and
     The flow computer snapshot report in API 21.1.5.4.2 and 
API 21.1, Annex G.
10. Event Log
    Proposed Sec.  3175.104(c) would require operators to retain the 
original, unaltered, unprocessed, and unedited event log and submit it 
to the BLM upon request, usually during a production audit. The event 
log must comply with API 21.1.5.5 (the chronological listing of the 
date and time of any change to a constant flow parameter that can 
affect the quantity transaction record, along with the old and new 
value), with the following additions and clarifications:
     The event log must record all power outages (including the 
length of the outage) that inhibit the meter's ability to collect and 
store new data; and
     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 proposed Sec.  3170.7, or 
the life of the FMP, whichever is shorter.
11. Gas Chromatograph Verification
    Proposed 3175.117(c) and (d) would require operators to retain the 
manufacturer's specifications and installation and operational 
recommendations for on-line gas chromatographs, and the results of all 
verifications of on-line gas chromatographs and submit the information 
to the BLM upon request, usually during a production audit. Proposed 
Sec.  3175.118(i) would require the gas chromatograph verification to 
contain:
     The components analyzed;
     The response factor for each component;
     The peak area for each component;
     The mole percent of each component as determined by the 
GC;
     The mole percent of each component in the gas used for 
verification;
     The difference between the mole percents determined in 
paragraphs (i)(4) and (i)(5) of this section, expressed in relative 
percent;
     Documentation that the gas used for verification meets the 
requirements of GPA 2198-03 (incorporated by reference, see Sec.  
3175.31), including a unique identification number of the calibration 
gas used and the name of the supplier of the calibration gas;
     The time and date the verification was performed; and
     The name and affiliation of the person performing the 
verification.
12. Gas Analysis Report
    Operators would be required to submit gas analysis reports to the 
BLM within 5 days of the due date for the sample as specified in 
proposed Sec.  3175.115. Submission would be done electronically into a 
BLM database. Paragraph (a) would provide that, unless otherwise 
required under paragraph (b), spot samples for all FMPs would be 
required to be taken and analyzed at the frequency specified at Table 4 
of proposed Sec.  3175.110.
    Paragraph (b) would provide that the BLM could change the required 
sampling frequency for high-volume and very-high-volume FMPs if the BLM 
determines that the sampling frequency required in Table 4 is not 
sufficient to achieve the heating value certainty levels required in 
proposed Sec.  3175.30(b). Table 5 at paragraph (c) would limit the 
amount of time that would be allowed between any two samples.
    Proposed 3175.120 would require gas analysis reports to contain the 
following information:
     The information required in proposed Sec.  3170.7(g) 
(i.e., the FMP number and the name of the company that created the 
record);
     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;
     The date and time of the analysis;
     For spot samples, the effective date, if other than the 
date of sampling;
     For composite samples, the effective start and end date;
     The name of the laboratory where the analysis was 
performed;
     The device used for analysis (i.e., GC, calorimeter, or 
mass spectrometer);
     The make and model of analyzer;
     The date of last calibration or verification of the 
analyzer;
     The flowing temperature at the time of sampling;
     The flowing pressure at the time of sampling, including 
units of measure (psia or psig);
     The flow rate at the time of the sampling;
     The ambient air temperature at the time the sample was 
taken;
     Whether or not heat trace or any other method of heating 
was used;
     The type of sample (i.e., spot-cylinder, spot-portable GC, 
composite);
     The sampling method if spot-cylinder (e.g., fill and 
empty, helium pop);
     A list of the components of the gas tested;
     The un-normalized mole percentages of the components 
tested, including a summation of those mole percents;
     The normalized mole percent of each component tested, 
including a summation of those mole percents;

[[Page 61690]]

     The ideal heating value (Btu/scf);
     The real heating value (Btu/scf), dry basis;
     The pressure base and temperature base;
     The relative density; and
     The name of the company obtaining the gas sample.
    Components that are listed on the analysis report, but not tested, 
would be required to be annotated as such.
13. Quantity Transaction Report Edits
    Proposed Sec.  3175.126(c)(2) would require operators to identify 
and verifiably justify all values on daily and hourly QTRs that have 
been changed or edited as a result of measurement errors stemming from 
an equipment malfunction causing discrepancies in the calculated volume 
or heating value of the gas. This documentation would be required to be 
retained under proposed Sec.  3170.7 and submitted to the BLM upon 
request, usually during a production audit.
IV. Burden Estimates
    The following table itemizes the annual estimated information 
collection burdens of this proposed rule:

------------------------------------------------------------------------
                                    Number of    Hours per
         Type of response           responses     response   Total hours
A                                            B            C            D
------------------------------------------------------------------------
Flow Conditioner Testing Report              1          400          400
 (43 CFR 3175.46)................
Differential Primary Devices                 1          400          400
 Other than Flange-Tapped Orifice
 Plates (43 CFR 3175.47).........
Linear Measurement Device Testing            1          200          200
 Report (43 CFR 3175.48).........
Verification for Mechanical                  0            0            0
 Recorders (43 CFR 3175.92(d))
 Usual and customary, within the
 meaning of 5 CFR 1320.3(b)(2)...
Mechanical Recorder Integration              0            0            0
 Statement (43 CFR 3175.93) Usual
 and customary, within the
 meaning of 5 CFR 1320.3(b)(2)...
Routine Verification for EGMs (43            0            0            0
 CFR 3175.102(e)) Usual and
 customary, within the meaning of
 5 CFR 1320.3(b)(2)..............
Event Log (43 CFR 3175.104(c))               0            0            0
 Usual and customary, within the
 meaning of 5 CFR 1320.3(b)(2)...
Transducer Testing Report (43 CFR           20          395        7,900
 3175.134).......................
Flow-Computer and Software                  20          395        7.900
 Version Testing Report (43 CFR
 3175.144).......................
Orifice Plate Inspection Report         28,436            1       28,436
 (43 CFR 3175.80(e))
 Recordkeeping requirement.......
Meter-Tube Inspection Report (43        16,160         4.35       70,296
 CFR 3175.80(j)) Recordkeeping
 requirement.....................
Retention of Test Equipment              2,000          0.1          200
 Recertification on-site (43 CFR
 3175.92(g)).....................
Redundancy Verification Check for        1,000          0.5          500
 EGMs (43 CFR 3175.102(e)(2))
 Recordkeeping requirement.......
Quantity Transaction Record (43          3,185            3        9,555
 CFR 3175.104(a)) Recordkeeping
 requirement.....................
Configuration Log (43 CFR                3,185            3        9,555
 3175.104(b)) Recordkeeping
 requirement.....................
Gas Chromatograph Verification               0            0            0
 (43 CFR 3175.117(c) and (d))
 Usual and customary, within the
 meaning of 5 CFR 1320.3(b)(2)...
Gas Analysis Report (43 CFR            219,199         1.53      335,374
 3175.120).......................
Quantity Transaction Record Edits            0            0            0
 (43 CFR 3175.126(c)(2)) Usual
 and customary, within the
 meaning of 5 CFR 1320.3(b)(2)...
                                  --------------------------------------
    Totals.......................      273,208                   470,716
------------------------------------------------------------------------

    The information collection activities that appear in the above 
table with the notation, ``Usual and customary, within the meaning of 5 
CFR 1320.3(b)(2)'' are standard industry practices and will not result 
in collection burdens for industry in addition to those incurred in the 
ordinary course of their business. For reasons documented in the 
descriptions of the proposed information collection requirements, the 
BLM believes the burdens of these proposals are exempt from the PRA in 
accordance with 5 CFR 1320.3(b)(2). That is why no burdens are 
indicated for those activities.
    The information collection activities that appear in the above 
table with the notation, ``Recordkeeping requirement'' are included in 
this PRA analysis because this proposed rule would require respondents 
to collect and retain certain information. However, any requirement to 
submit the information to the BLM (usually during a production audit) 
would be in accordance with the BLM's proposed rule on site security, 
which was published on July 13, 2015 (80 FR 40768). OMB has assigned 
control number 1004-0207 to that proposed rule, but has not yet 
authorized the BLM to begin collecting information under that control 
number.

National Environmental Policy Act

    The BLM has prepared a draft environmental assessment (EA) that 
concludes that this proposed rule would not have a significant impact 
on the quality of the environment under NEPA, 42 U.S.C. 4332(2)(C), 
therefore a detailed statement under NEPA is not required. A copy of 
the draft EA can be viewed at www.regulations.gov (use the search term 
1004-AE17, open the Docket Folder, and look under Supporting Documents) 
and at the address specified in the ADDRESSES section.
    The proposed rule would not impact the environment significantly. 
For the most part, the proposed rule would in substance update the 
provisions of Order 5 and would involve changes that are of an 
administrative, technical, or procedural nature that would apply to the 
BLM's and the lessee's or operator's administrative processes. For 
example, the proposed rule would clarify the acceptable methods for 
estimating and documenting reported volumes of gas when metering 
equipment is malfunctioning or out of service. The proposed rule would 
also establish new requirements for gas sampling, including sampling 
location and methods, sampling frequency, analysis methods, and the 
minimum number of components to be analyzed. Finally, the proposed rule 
would establish new meter equipment, maintenance, inspection, and 
reporting standards. These changes would 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. We will consider 
any new information we receive during the public comment period for the 
proposed rule that may inform our analysis of the potential 
environmental impacts of the rule.

[[Page 61691]]

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

    This proposed rule would 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 proposed rule would 
strengthen the BLM's accountability requirements for operators under 
Federal and Indian oil and gas leases. As discussed above, these 
changes would prescribe a number of specific requirements for 
production measurement, including sampling, measuring, and analysis 
protocol; categories of violations; and reporting requirements. The 
proposal also establishes specific requirements related to the physical 
makeup of meter components. All of the changes would increase the 
regulated community's annual costs by about $46 million, or an average 
of approximately $13,000 per entity per year. There would be an 
additional one-time cost to industry of about $33 million to comply 
with the changes, or an average of approximately $8,900 per entity, 
phased in over a 3-year period. Entities with the greatest activity 
(e.g., numerous FMPs) would incur higher costs. Additional information 
on these costs estimates can be found in the Economic and Threshold 
Analysis prepared for this proposed rule. The BLM is specifically 
seeking comment on that analysis and the assumptions used therein.
    We expect that the proposed rule would 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 proposed rule, we did not conduct or use a 
study, experiment, or survey requiring peer review under the 
Information Quality Act (Pub. L. 106-554, Appendix C Title IV, Section 
515, 114 Stat. 2763A-153).

Clarity of the Regulations

    Executive Order 12866 requires each agency to write regulations 
that are simple and easy to understand. We invite your comments on how 
to make these proposed regulations easier to understand, including 
answers to questions such as the following:
    1. Are the requirements in the proposed regulations clearly stated?
    2. Do the proposed regulations contain technical language or jargon 
that interferes with their clarity?
    3. Does the format of the proposed regulations (grouping and order 
of sections, use of headings, paragraphing, etc.) aid or reduce their 
clarity?
    4. Would the regulations be easier to understand if they were 
divided into more (but shorter) sections?
    5. Is the description of the proposed regulations in the 
SUPPLEMENTARY INFORMATION section of this preamble helpful in 
understanding the proposed regulations? How could this description be 
more helpful in making the proposed regulations easier to understand?
    Please send any comments you have on the clarity of the regulations 
to the address specified in the ADDRESSES section.

Authors

    The principal authors of this rule are: Richard Estabrook of the 
BLM Washington Office; Gary Roth of the BLM Buffalo, Wyoming Field 
Office; Wanda Weatherford of the BLM Farmington, New Mexico Field 
Office; Clifford Johnson of the BLM Vernal, Utah Field Office; and 
Rodney Brashear of the BLM Durango, Colorado Field Office, assisted by 
Mike Wade of the BLM Washington Office; Joe Berry and Faith Bremner of 
the staff of BLM's Regulatory Affairs Division; John Barder, Office of 
Natural Resources Revenue; and Geoffrey Heath, Department of the 
Interior's Office of the Solicitor.

List of Subjects in 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.

Lists of Subjects in 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 1, 2015.
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 proposes to amend 43 CFR part 3160 and add a new subpart 
3175 to new 43 CFR part 3170 as follows:

PART 3160--ONSHORE OIL AND GAS OPERATIONS

0
1. The authority citation for part 3160 continues to read as follows:

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

0
2. Revise Sec.  3162.7-3 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 title. 
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 title.
0
3. Amend Sec.  3163.1 by revising paragraphs (a) introductory text, 
(a)(1), (a)(2), (b) introductory text, (b)(1), and (b)(2), removing 
paragraphs (c) and (d), and redesignating paragraph (e) as paragraph 
(c) and revising it. The revisions 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 part, 
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

[[Page 61692]]

of the assessment, the State Director will state in the record the 
reasons for such determination.
    4. Amend Sec.  3163.2 by revising paragraphs (a), (b), and (d) 
through (f), removing paragraphs (g), (j) and (k), redesignating 
paragraph (i) as paragraph (g) and revising it. The revisions read as 
follows:


Sec.  3163.2  Civil penalties.

    (a)(1) Whenever any person fails or refuses to comply with any 
applicable requirements of the Federal Oil and Gas Royalty Management 
Act, any mineral leasing law, any regulation thereunder, or the terms 
of any lease or permit issued thereunder, the authorized officer will 
notify the person in writing of the violation, unless the violation was 
discovered and reported to the authorized officer by the liable person 
or the notice was previously issued under Sec.  3163.1 of this subpart.
    (2) Whenever a purchaser or transporter who is not an operating 
rights owner or operator fails or refuses to comply with 30 U.S.C. 1713 
or applicable rules or regulations regarding records relevant to 
determining the quality, quantity, and disposition of oil or gas 
produced from or allocable to a Federal or Indian oil and gas lease, 
the authorized officer will notify the purchaser or transporter, as 
appropriate, in writing of the violation.
    (b)(1) If the violation is not corrected within 20 days of such 
notice or report, or such longer time as the authorized officer may 
agree to in writing, the person will be liable for a civil penalty of 
up to $500 per violation for each day such violation continues, dating 
from the date of such notice or report. Any amount imposed and paid as 
assessments under Sec.  3163.1(a)(1) of this subpart will be deducted 
from penalties under this section.
    (2) If the violation specified in paragraph (a) of this section is 
not corrected within 40 days of such notice or report, or a longer 
period as the authorized officer may agree to in writing, the person 
will be liable for a civil penalty of up to $5,000 per violation for 
each day the violation continues, dating from the date of such notice 
or report. Any amount imposed and paid as assessments under Sec.  
3163.1(a)(1) of this subpart will be deducted from penalties under this 
section.
* * * * *
    (d) Whenever a transporter fails to permit inspection for proper 
documentation by any authorized representative, as provided in Sec.  
3162.7-1(c) of this title, the transporter shall be liable for a civil 
penalty of up to $500 per day for the violation, dating from the date 
of notice of the failure to permit inspection and continuing until the 
proper documentation is provided. If the violation continues beyond 20 
days, the authorized officer will revoke the transporter's authority to 
remove crude oil produced from, or allocated to, any Federal or Indian 
lease under the authority of that authorized officer. This revocation 
of the transporter's authority will continue until the transporter 
provides proper documentation and pays any related penalty.
    (e) Any person shall be liable for a civil penalty of up to $10,000 
per violation for each day such violation continues, if the person:
    (1) Fails or refuses to permit lawful entry or inspection 
authorized by Sec.  3162.1(b) of this title; or
    (2) Knowingly or willfully fails to notify the authorized officer 
by letter or Sundry Notice, Form 3160-5 or orally to be followed by a 
letter or Sundry Notice, not later than the 5th business day after any 
well begins production on which royalty is due, or resumes production 
in the case of a well which has been off of production for more than 90 
days, from a well located on a lease site, or allocated to a lease 
site, of the date on which such production began or resumed.
    (f) Any person shall be liable for a civil penalty of up to $25,000 
per violation for each day such violation continues, if the person:
    (1) Knowingly or willfully prepares, maintains or submits false, 
inaccurate or misleading reports, notices, affidavits, records, data or 
other written information required by this part; or
    (2) Knowingly or willfully takes or removes, transports, uses or 
diverts any oil or gas from any Federal or Indian lease site without 
having valid legal authority to do so; or
    (3) Purchases, accepts, sells, transports or conveys to another any 
oil or gas knowing or having reason to know that such oil or gas was 
stolen or unlawfully removed or diverted from a Federal or Indian lease 
site.
    (g) Civil penalties provided by this section are supplemental to, 
and not in derogation of, any other penalties or assessments for 
noncompliance in any other provision of law, except as provided in 
paragraphs (a) and (b) of this section.
* * * * *


Sec.  3164.1  [Amended]

0
5. Amend Sec.  3164.1, in paragraph (b), by removing the fifth entry in 
the chart (the reference to Order No. 5, Measurement of gas).
0
6. Amend Sec.  3165.3 by revising paragraph (a) to read as follows:


Sec.  3165.3  Notice, State Director review and hearing on the record.

    (a) Notice. (1) Whenever any person, including an operating rights 
owner or operator, as appropriate, fails to comply with any provisions 
of the lease, the regulations in this part, applicable orders or 
notices, or any other appropriate order of the authorized officer, the 
authorized officer will issue a written notice or order to the 
appropriate party and the lessee(s) to remedy any defaults or 
violations.
* * * * *

PART 3170--ONSHORE OIL AND GAS PRODUCTION

0
7. The authority citation for part 3170, proposed to be added on July 
13, 2015 (80 CFR 40768), 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
8. Add subpart 3175 to part 3170, proposed to be added on July 13, 2015 
(80 FR 40768), to read as follows:

Subpart 3175--Measurement of Gas

Sec.
3175.10 Definitions and acronyms.
3175.20 General requirements.
3175.30 Specific performance requirements.
3175.31 Incorporation by reference.
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 computers.
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.
3175.60 Timeframes for compliance.
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.

[[Page 61693]]

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.
3175.150 Immediate assessments.
Appendix 1.A to Subpart 3175.
Appendix 1.B to Subpart 3175.
Appendix 2 to Subpart 3175.


Sec.  3175.10  Definitions and acronyms.

    (a) As used in this subpart, the term:
    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] TP13OC15.010

    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 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[ordm]F.
    Component-type electronic gas measurement system means an 
electronic gas measurement system comprised of 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 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, unless otherwise specified, 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 (psi) and 60[deg] F.
    High-volume facility measurement point or high-volume FMP means any 
FMP that measures more than 100 Mcf/day, but less than or equal to 
1,000 Mcf/day, averaged over the previous 12 months or the life of the 
FMP, whichever is shorter.
    Hydrocarbon dew point means the temperature at which hydrocarbon 
liquids begin to form. 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. The result of an integration is an integration 
statement which 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 15 Mcf/day, but less than or equal to 100 
Mcf/day, averaged over the previous 12 months, or the life of the FMP, 
whichever is shorter.

[[Page 61694]]

    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.
    Marginal-volume facility measurement point or marginal-volume FMP 
means any FMP that measures 15 Mcf/day or less averaged over the 
previous 12 months, or the life of the FMP, whichever is shorter, 
unless the AO approves a higher rate.
    Mean means the sum of all the members of a data set divided by the 
number of items 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 percent.
    Normal flowing point means the differential pressure, static 
pressure, and flowing temperature at which the FMP normally operates 
when gas is flowing through it.
    Primary device means the 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.
    Quantity transaction record (QTR) means a report generated by EGM 
equipment that summarizes the daily and hourly volume 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 defined as:
[GRAPHIC] [TIFF OMITTED] TP13OC15.011

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 by comparing the readings of two sets of transducers placed 
on the same meter.
    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 where 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 number of a 
transducer or flow computer changes the EGM 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.
    Significant digit means any digit of a number that is known with 
certainty.
    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, equal to the square root of the arithmetic mean of the 
squares of the deviations from the arithmetic mean.
    Statistically significant means the difference between two data 
sets that exceeds the threshold of significance.
    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] TP13OC15.012

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 transducer to determine its performance 
over a range of operating conditions.
    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-high-volume facility measurement point or very-high-volume FMP 
means any FMP that measures more than 1,000 Mcf/day averaged over the 
previous 12 months or the life of the FMP, whichever is shorter.
    (b) As used in this subpart the following additional acronyms carry 
the meaning prescribed:
    GARVS means the BLM's Gas Analysis Reporting and Verifications 
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.
    WIS means Well Information System or any successor electronic 
system.


Sec.  3175.20  General requirements.

    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.


Sec.  3175.30  Specific performance requirements.

    (a) Flow rate measurement certainty 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:

[[Page 61695]]

    (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)(ix) through (xi) of this subpart.
    (b) Heating value certainty 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.
    (c) Bias. For low-volume, high-volume, and very-high-volume FMPs, 
the measuring equipment used for both flow rate and 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 is 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.  3175.31  Incorporation by reference.

    (a) Certain material identified in paragraphs (b) and (c) of 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. To enforce any edition other than that specified in this 
section, the BLM must publish notice of change in the Federal Register 
and the material must be 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. 
It is also available for inspection at the National Archives and 
Records Administration (NARA). For information on the availability of 
this material at NARA, call 202-741-6030 or go to http://www.archives.gov/federal_register/code_of_federal_regulations/ibr_locations.html. In addition, the material incorporated by reference 
is available from the sources of that material identified in paragraphs 
(b) and (c) of this section, as follows:
    (b) American Petroleum Institute (API), 1220 L Street NW., 
Washington, DC 20005; telephone 202-682-8000. API also offers free, 
read-only access to some of the material at www.publications.api.org.
    (1) API Manual of Petroleum Measurement Standards (MPMS) Chapter 
14, Section 1, Collecting and Handling of Natural Gas Samples for 
Custody Transfer, Sixth Edition, February 2006, Reaffirmed 2011 (``API 
14.1.12.10''), incorporation by reference (IBR) approved for Sec.  
3175.114(b).
    (2) API MPMS Chapter 14, Section 2, Compressibility Factors of 
Natural Gas and Other Related Hydrocarbon Gases, Second Edition, August 
1994, Reaffirmed March 1, 2006 (``API 14.2''), IBR approved for 
Sec. Sec.  3175.103(a)(1)(ii) and 3175.120(d).
    (3) API MPMS, Chapter 14, Section 3, Part 1, General Equations and 
Uncertainty Guidelines, Fourth Edition, September 2012, Errata, July 
2013. (``API 14.3.1.4.1''), IBR approved for Sec.  3175.80 Table 1.
    (4) API MPMS Chapter 14, Section 3, Part 2, Specifications and 
Installation Requirements, Fourth Edition, April 2000, Reaffirmed 2011 
(``API 14.3.2,'' ``API 14.3.2.4,'' ``API 14.3.2.5.1 through API 
14.3.2.5.4,'' ``API 14.3.2.5.5.1 through API 14.3.2.5.5.3,'' ``API 
14.3.2.6.2,'' ``API 14.3.2.6.3,'' ``API 14.3.2.6.5,'' and ``API 14.3.2, 
Appendix 2-D''), IBR approved for Sec. Sec.  3175.46(b) and (c), 
3175.80 Table 1, 3175.80(c), 3175.80(d), 3175.80(e)(4), 3175.80(f), 
3175.80(g), 3175.80(g)(3), 3175.80(i), 3175.80(j), 3175.80(k), 
3175.80(l), and 3175.112(b)(1).
    (5) API MPMS Chapter 14, Section 3, Part 3, Natural Gas 
Applications, Fourth Edition, November 2013 (``API 14.3.3,'' ``API 
14.3.3.4,'' and ``API 14.3.3.5.'' and ``API 14.3.3.5.6,''), IBR 
approved for Sec. Sec.  3175.94(a)(1) and 3175.103(a)(1)(i).
    (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 (``API 14.5,'' ``API 14.5.3.7,'' and ``API 
14.5.7.1''), IBR approved for Sec. Sec.  3175.120(c) and 3175.125 
(a)(1).
    (7) API MPMS Chapter 21, Section 1, Electronic Gas Measurement, 
Second Edition, February 2013 (``API 21.1,'' ``API 21.1.4,'' ``API 
21.1.4.4.5,'' ``API 21.1.5.2,'' ``API 21.1.5.3,'' ``API 21.1.5.4,'' 
``API 21.1.5.4.2,'' ``API 21.1.5.5,'' ``API 21.1.5.6,'' ``API 
21.1.7.3,'' ``API 21.1.7.3.3,'' ``API 21.1.8.2,'' ``API 21.1.8.2.2.2, 
Equation 24,'' ``API 21.1.9,'' ``API 21.1 Annex B,'' ``API 21.1 Annex 
G,'' ``API 21.1 Annex H, Equation H.1,'' and ``API 21.1 Annex I''), IBR 
approved for Sec. Sec.  3175.100 Table 3, 3175.101(e), 3175.102(a)(2), 
3175.102(c), 3175.102(c)(4), 3175.102(c)(5), 3175.102(d), 
3175.102(e)(2)(v), 3175.103(b), 3175.103(c), 3175,104(a), 3175.104(b), 
3175.104(b)(2), 3175.104(c), and 3175.104(d).
    (8) API MPMS Chapter 22, Section 2, Differential Pressure Flow 
Measurement Devices, First Edition, August 2005, Reaffirmed 2012 (``API 
22.2''), IBR approved for Sec.  3175.47 (a), (b), and (c).
    (c) 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 Section 
9.1,'' ``GPA 2166.05 Section 9.5,'' ``GPA 2166-05 Sections 9.7.1 
through 9.7.3,'' ``GPA 2166-05 Appendix A,'' ``GPA 2166-05 Appendix 
B.3,'' ``GPA 2166-05 Appendix D''), IBR approved for Sec. Sec.  
3175.113(c)(3), 3175.113(d)(1)(ii), 3175.113(d)(1)(iii), 
3175.114(a)(1), 3175.114(a)(2), 3175.114(a)(3), 3175.117(a).
    (2) GPA Standard 2261-00, Analysis for Natural Gas and Similar 
Gaseous Mixtures by Gas Chromatography, Revised 2000 (``GPA 2261-00'', 
``GPA 2261-00, Section 4,'' GPA 2261-00, Section 5,'' ``GPA 2261-00, 
Section 9''), IBR approved for Sec.  3175.118(a)(b)(c) and (e).
    (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. Sec.  
3175.118(h), 3175.118(i)(7). Note 1 to Sec.  3175.31(b) and (c): You 
may also be able to purchase these standards from the following 
resellers: Techstreet, 3916 Ranchero Drive, Ann Arbor, MI 48108; 
telephone 734-780-8000; www.techstreet.com/api/apigate.html; IHS Inc., 
321 Inverness Drive South, Englewood, CO 80112; 303-790-0600; 
www.ihs.com; SAI Global, 610 Winters Avenue, Paramus, NJ 07652; 
telephone 201-986-1131.


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

    The measurement equipment described in Sec. Sec.  3175.41 through 
3175.48 is approved for use at FMPs under the conditions and 
circumstances stated in those sections if it meets or exceeds the 
minimum standards prescribed in this subpart.


Sec.  3175.41  Flange-tapped orifice plates.

    Flange-tapped orifice plates constructed and installed under Sec.  
3175.80 of this subpart are approved for use.

[[Page 61696]]

Sec.  3175.42  Chart recorders.

    Chart recorders used in conjunction with approved differential-type 
meters that are installed, operated, and maintained under Sec.  3175.90 
of this subpart are approved for use for low-volume and marginal-volume 
FMPs only, and are not approved for high-volume or very-high-volume 
FMPs.


Sec.  3175.43  Transducers.

    (a) A specific make, model, and URL of a transducer used in 
conjunction with differential meters for high-volume or very-high-
volume FMPs is approved for use if it meets the following requirements:
    (1) It has been type-tested under Sec.  3175.130 of this subpart;
    (2) The documentation required in Sec.  3175.130 of this subpart 
has been submitted to the PMT; and
    (3) It has been placed on the list of type-tested equipment 
maintained at www.blm.gov.
    (b) All transducers used at marginal- and low-volume FMPs are 
approved for use.


Sec.  3175.44  Flow computers.

    (a) A specific make and model of flow computer and software version 
is approved for use if it meets the following requirements:
    (1) The documentation required in Sec.  3175.140 of this subpart 
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 of this 
subpart, except as provided in paragraph (b) of this section; and
    (3) It has been placed on the list of approved equipment maintained 
at www.blm.gov.
    (b) Software revisions that do not affect or that do not have the 
potential to affect determination of flow rate, determination of 
volume, and data or calculations used to verify flow rate or volume are 
not required to be type-tested.


Sec.  3175.45  Gas chromatographs.

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


Sec.  3175.46  Isolating flow conditioners.

    An approved make and model of isolating flow conditioner that is 
listed at www.blm.gov and used in conjunction with flange-tapped 
orifice plates is approved for use if it is installed, operated, and 
maintained in compliance with BLM requirements specified at 
www.blm.gov. 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 
laboratory that is NIST traceable and not affiliated with the flow-
conditioner manufacturer.
    (b) The operator or manufacturer must test the flow conditioner 
under API 14.3.2, Appendix 2-D (incorporated by reference, see Sec.  
3175.31), and under any additional test protocols that the BLM requires 
that are posted on the BLM's Web site at www.blm.gov, 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, Appendix 2-D (incorporated by 
reference, see Sec.  3175.31) and make a recommendation 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.

    The make and model of a differential primary device that is listed 
at www.blm.gov is approved for use if it is installed, operated, and 
maintained in compliance with BLM requirements specified at 
www.blm.gov. Approval of a particular make and model is obtained as 
follows:
    (a) The primary device must be tested under API 22.2 (incorporated 
by reference, see Sec.  3175.31), and under any additional protocols 
that the BLM requires that are posted on the BLM's Web site at 
www.blm.gov, at a laboratory that is NIST traceable and not affiliated 
with the primary device manufacturer;
    (b) The operator must submit to the BLM all test data required 
under API 22.2 (incorporated by reference, see Sec.  3175.31);
    (c) 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.  3175.31) and Sec.  3175.30(c) and (d) of this subpart 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.
    (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.  3175.48  Linear measurement devices.

    The BLM may approve linear measurement devices such as ultrasonic 
meters, Coriolis meters, positive displacement meters, and turbine 
meters on a case-by-case basis. To request approval, the operator must 
submit to the AO all data that the BLM requires. The PMT will review 
the data to determine whether the meter meets the requirements of Sec.  
3175.30 of this subpart, and make a recommendation to the BLM, which 
will either approve use of the device, disapprove use of the device, or 
approve its use with conditions.


Sec.  3175.60  Timeframes for compliance.

    (a) The measuring procedures and equipment installed at any FMP on 
or after [EFFECTIVE DATE OF THE FINAL RULE] must comply with all of the 
requirements of this subpart upon installation.
    (b) Measuring procedures and equipment at any FMP in place before 
[EFFECTIVE DATE OF FINAL RULE] must comply with the requirements of 
this subpart within the timeframes specified in this paragraph.
    (1) Very-high-volume FMPs must comply with:
    (i) All of the requirements of this subpart except as specified in 
paragraph (b)(1)(ii) of this section by [SIX MONTHS AFTER THE EFFECTIVE 
DATE OF THE FINAL RULE]; and
    (ii) The gas analysis reporting requirements of Sec.  3175.120(f) 
of this subpart beginning on [EFFECTIVE DATE OF FINAL RULE].
    (2) High-volume FMPs must comply with:
    (i) All of the requirements of this subpart except as specified in 
paragraph (b)(2)(ii) of this section by [ONE YEAR AFTER THE EFFECTIVE 
DATE OF THE FINAL RULE]; and
    (ii) The gas analysis reporting requirements of Sec.  3175.120(f) 
of this subpart beginning on [EFFECTIVE DATE OF FINAL RULE].
    (3) Low-volume FMPs must comply with all of the requirements of 
this subpart by [TWO YEARS AFTER THE EFFECTIVE DATE OF THE FINAL RULE].
    (4) Marginal-volume FMPs must comply with all of the requirements 
of this regulation by [THREE YEARS AFTER THE EFFECTIVE DATE OF THE 
FINAL RULE].
    (c) During the phase-in timeframes in paragraph (b) of this 
section, measuring procedures and equipment in place before [EFFECTIVE 
DATE OF THE FINAL RULE] must comply with the requirements of the 
predecessor rule to this subpart, i.e., Onshore Oil and Gas Order No. 
5, Measurement of Gas, 54 FR 8100 (Feb. 24, 1989), and applicable NTLs, 
COAs, and written orders.

[[Page 61697]]

    (d) The applicability of existing NTLs, variance approvals, and 
written orders that establish requirements or standards related to gas 
measurement are rescinded as of:
    (i) [SIX MONTHS AFTER THE EFFECTIVE DATE OF THE FINAL RULE] for 
very-high-volume FMPs;
    (ii) [ONE YEAR AFTER THE EFFECTIVE DATE OF THE FINAL RULE] for 
high-volume FMPs;
    (iii) [TWO YEARS AFTER THE EFFECTIVE DATE OF THE FINAL RULE] for 
low-volume FMPs; and
    (iv) [THREE YEARS AFTER THE EFFECTIVE DATE OF THE FINAL RULE] for 
marginal-volume FMPs;


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, or 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).

    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.

                                                   Table 1--Standards for Flange-Tapped Orifice Plates
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                         Reference (API
                                     standards incorporated
              Subject                by reference, see Sec.             M                      L                      H                      V
                                             3175.31)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Fluid conditions...................  API 14.3.1.4.1........  n/a...................  x....................  x....................  x
Orifice plate construction and       API 14.3.2.4..........  x.....................  x....................  x....................  x
 condition.
Orifice plate eccentricity and       API 14.3.2.6.2........  x.....................  x....................  x....................  x
 perpendicularity.
Beta ratio range...................  Sec.   3175.80(a).....  n/a...................  x....................  x....................  x
Minimum orifice size...............  Sec.   3175.80(b).....  n/a...................  n/a..................  x....................  x
New FMP orifice plate inspection *.  Sec.   3175.80(c).....  x.....................  x....................  x....................  x
Routine orifice plate inspection     Sec.   3175.80(d).....  12....................  6....................  3....................  1
 frequency, in months. *
Documentation of orifice plate       Sec.   3175.80(e).....  x.....................  x....................  x....................  x
 inspection.
Meter tube construction and          Sec.   3175.80(f).....  n/a...................  x....................  x....................  x
 condition.
Flow conditioners including 19-tube  Sec.   3175.80(g).....  n/a...................  x....................  x....................  x
 bundles.
Visual meter tube inspection         Sec.   3175.80(h).....  n/a...................  5....................  2....................  1
 frequency, in years. *
Detailed meter tube inspection       Sec.   3175.80(i).....  n/a...................  **...................  10...................  5
 frequency, in years. *
Documentation of meter tube          Sec.   3175.80(j).....  n/a...................  x....................  x....................  x
 inspection.
Meter tube length..................  Sec.   3175.80(k).....  n/a...................  x....................  x....................  x
Thermometer wells..................  Sec.   3175.80(l).....  n/a...................  x....................  x....................  x
Sample probe location..............  Sec.   3175.80(m).....  x.....................  x....................  x....................  x
Notification of meter tube           Sec.   3175.80(n).....  n/a...................  x....................  x....................  x
 installation or inspection.
--------------------------------------------------------------------------------------------------------------------------------------------------------
M=Marginal-volume FMP; L=Low-volume FMP; H=High-volume FMP; V=Very-high-volume FMP; * = Immediate assessment for non-compliance under Sec.   3175.150 of
  this subpart; **=If ordered by the AO after notification required under Sec.   3175.80(h)(3).

    Except as stated in the text of this section or as prescribed in 
Table 1, the standards and requirements in this section apply to all 
flange-tapped orifice plates.
    (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 (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 14.3.2.4 and API 
14.3.2.6.2 (both incorporated by reference, see Sec.  3175.31), the 
operator must replace the orifice plate. When the bi-weekly inspection 
shows that the orifice plate complies with API 14.3.2.4 and API 
14.3.2.6.2 (both incorporated by reference, see Sec.  3175.31), 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 during verification of the 
secondary device. The operator must replace orifice plates that do not 
comply with API 14.3.2.4 or API 14.3.2.6.2 (both incorporated by 
reference, see Sec.  3175.31) 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), mechanical recorders, or 
Sec.  3175.102(e), EGM systems, of this subpart). 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 subpart;
    (2) Plate orientation (bevel upstream or downstream);
    (3) Measured orifice bore diameter;
    (4) Plate condition (compliance with API 14.3.2.4 (incorporated by 
reference, see Sec.  3175.31));
    (5) The presence of oil, grease, paraffin, scale, or other 
contaminants found 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 14.3.2.5.1 
through API 14.3.2.5.4 (all incorporated by reference, see Sec.  
3175.31). The following exception is allowed for meter tubes at low-
volume FMPs only if:
    (1) The difference between the maximum and the minimum inside 
diameter of the meter tube measured 1 inch upstream of the orifice 
plate does not exceed the following tolerance:

T = 5.0[beta]\2\ - 2.5[beta] + 0.2

Where:

    T = tolerance of average diameter, in percent
    [beta] = the Beta ratio


and


[[Page 61698]]


    (2) The difference between any measured inside diameter of the 
meter tube and the average inside diameter of the meter tube measured 1 
inch downstream of the orifice plate does not exceed the tolerance 
given by the equation in paragraph (f)(1) of this section.
    (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 of this subpart) or 19-tube-bundle flow 
straighteners constructed and located in compliance with API 
14.3.2.5.5.1 through API 14.3.2.5.5.3 (all incorporated by reference, 
see Sec.  3175.31).
    (h) Visual meter tube inspection. The operator must:
    (1) Visually inspect meter tubes within the timeframe (in years) 
specified in Table 1.
    (2) Use a borescope or equivalent device, capable of determining 
the condition of the inside of the meter tube along the entire upstream 
and downstream lengths required by paragraph (k) of this section, 
including the tap holes and the plate holder. The visual inspection 
must be able to identify obstructions, pitting, and buildup of foreign 
substances (e.g., grease and scale).
    (3) Notify the AO within 72 hours if a visual inspection identifies 
conditions that indicate the meter tube does not comply with API 
14.3.2.5.1 through API 14.3.2.5.4 (all incorporated by reference, see 
Sec.  3175.31).
    (4) Maintain documentation of the findings from the visual meter 
tube inspection including:
    (i) The information required in Sec.  3170.7(g) of this subpart;
    (ii) The time and date of inspection; and
    (iii) The type of equipment used to make the inspection;
    (iv) A description of findings, including location and severity of 
pitting, obstructions, and buildup of foreign substances.
    (5) Conducting a detailed inspection such as that required under 
paragraph (i) of this section in lieu of a visual inspection satisfies 
the requirement of this paragraph.
    (i) Detailed meter tube inspection. (1) The operator must 
physically measure and inspect the meter tube used in a high-volume or 
very-high-volume FMP at the frequency (in years) identified in Table 1, 
to determine if the meter tube complies with API 14.3.2.5.1 through API 
14.3.2.5.4 (all incorporated by reference, see Sec.  3175.31).
    (2) The AO may adjust the detailed meter inspection frequencies if 
a visual inspection under paragraph (h) of this section identifies 
issues regarding compliance with the identified API standards or the 
operator provides documentation that demonstrates that a different 
frequency is warranted.
    (3) The AO may require additional inspections if conditions 
warrant, such as corrosive- or erosive-flow conditions (e.g., high 
H2S or CO2 content) or signs of physical damage 
to the meter tube.
    (4) If a visual inspection of a meter at a low-volume FMP reveals 
noncompliance with any requirement of API 14.3.2.5.1 through API 
14.3.2.5.4 (all incorporated by reference, see Sec.  3175.31), or if 
the meter tube operates in corrosive- or erosive-flow conditions or has 
signs of physical damage, the AO may require a detailed inspection.
    (j) The operator must retain documentation demonstrating that the 
meter tube complies with API 14.3.2.5.1 through API 14.3.2.5.4 (all 
incorporated by reference, see Sec.  3175.31) and showing all required 
measurements. The operator must provide such documentation to the BLM 
upon request for every meter-tube inspection (see Appendix 1 to this 
subpart for sample inspection sheet). Documentation must also include 
the information required in Sec.  3170.7(g) of this subpart.
    (k) Meter tube lengths. (1) For all very-high-volume FMPs, all 
high-volume FMPs, and low-volume FMPs that utilize 19- tube-bundle flow 
straighteners, meter-tube lengths and the location of 19-tube-bundle 
flow straighteners, if applicable, must comply with API 14.3.2.6.3 
(incorporated by reference, see Sec.  3175.31). If the calculated 
diameter ratio ([beta]) falls between the values in Tables 2-7, 2-8a, 
or 2-8b of that API section, the length identified for the larger 
diameter ratio in the 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.
    (2) For low-volume FMPs that do not utilize 19-tube-bundle flow 
straighteners, meter tube lengths may either comply with paragraph 
(k)(1) of this section or with the lengths calculated as follows:

------------------------------------------------------------------------
                                   Minimum upstream   Minimum downstream
                                   meter tube length   meter tube length
      Upstream disturbance          * (nominal pipe     * (nominal pipe
                                     diameters, D)       diameters, D)
------------------------------------------------------------------------
Double out-of-plane elbows; less  125[beta]3 -        3.03[beta] + 2.16
 than 10D separation (Figure 5,    87.5[beta]2 +
 AGA Report No. 3, 1985).          36.3[beta] + 13.3.
Double in-plane elbows; less      B<0.4: 8.7........
 than 10D separation (Figure 6,   [beta]>=0.4:
 AGA Report No. 3, 1985).          83.8[beta]2 -
                                   59.8[beta] + 19.2.
Double in-plane elbows; greater   [beta]<0.41: 6.0..
 than 10D separation (Figure 7,   [beta]>=0.41:.....
 AGA Report No. 3, 1985).         84.8[beta]2 -
                                   67.5[beta] + 19.4.
Concentric reducer or expander    B<0.35: 6.0.......
 (Figure 8, AGA Report No. 3,     [beta]>=0.35:.....
 1985).                           31.3[beta]2 -
                                   15.6[beta] + 7.64.
All other configurations (Figure  125[beta]3 -
 4, AGA Report No. 3, 1985).       87.5[beta]2 +
                                   36.3[beta] + 13.3.
------------------------------------------------------------------------
Notes: (1) [beta] is the Beta ratio; (2) To obtain the lengths in
  inches, you must multiply the result of the equation by the nominal
  pipe diameter of the meter tube (e.g. 2-inch, 3-inch, 4-inch); (3) The
  equations are an approximation of the meter tube length figures from
  AGA Report No. 3 (1985).

    (l) Thermometer wells. (1) Thermometer wells 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 
14.3.2.6.5 (incorporated by reference, see Sec.  3175.31).
    (2) Thermometer wells must be exposed to the same ambient 
conditions as the primary device. For example, if the primary device is 
located in a heated meter house, the thermometer well also must be 
located in the same heated meter house.
    (3) Where multiple thermometer wells have been installed in a meter 
tube, the flowing temperature must be measured

[[Page 61699]]

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) of this subpart.
    (n) The operator must notify the AO at least 72 hours before a 
visual or detailed meter-tube inspection or installation of a new meter 
tube.


Sec.  3175.90  Mechanical recorder (secondary device).

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

                                   Table 2--Standards for Mechanical Recorders
----------------------------------------------------------------------------------------------------------------
               Subject                        Reference                    M                        L
----------------------------------------------------------------------------------------------------------------
Applications for use.................  Sec.   3175.90(a)......  x......................  x
Manifolds and gauge/impulse lines....  Sec.   3175.91(a)......  n/a....................  x
Differential pressure pen position...  Sec.   3175.91(b)......  n/a....................  x
Flowing temperature recording........  Sec.   3175.91(c)......  n/a....................  x
On-site data requirements............  Sec.   3175.91(d)......  x......................  x
Operating within the element ranges..  Sec.   3175.91(e)......  x......................  x
Verification after installation or     Sec.   3175.92(a)......  x......................  x
 following repair *.
Routine verification and verification  Sec.   3175.92(b)......  6......................  3
 frequency, in months*.
Routine verification procedures......  Sec.   3175.92(c)......  x......................  x
Documentation of verification........  Sec.   3175.92(d)......  x......................  x
Notification of verification.........  Sec.   3175.92(e)......  x......................  x
Volume correction....................  Sec.   3175.92(f)......  n/a....................  x
Test equipment recertification.......  Sec.   3175.92(g)......  x......................  x
Integration statement requirements...  Sec.   3175.93.........  x......................  x
Volume determination.................  Sec.   3175.94(a)......  x......................  x
Atmospheric pressure.................  Sec.   3175.94(b)......  x......................  x
----------------------------------------------------------------------------------------------------------------
M=Marginal-volume FMP; L=Low-volume FMP; * = Immediate assessment for non-compliance under Sec.   3175.150 of
  this subpart.

Sec.  3175.91  Installation and operation of mechanical recorders.

    (a) Gauge lines connecting the pressure taps to the mechanical 
recorder must:
    (1) Have an internal diameter not less than 3/8'', including ports 
and valves;
    (2) Be constructed of stainless steel;
    (3) Be sloped upwards from the pressure taps at a minimum pitch of 
1 inch per foot of length;
    (4) Be the same internal diameter along their entire length;
    (5) Not include any tees, except for the static pressure line;
    (6) Not be connected to more than one differential-pressure bellows 
and static-pressure element, or to any other device; and
    (7) Be no longer than 6 feet.
    (b) The differential pressure pen must record at a minimum reading 
of 10 percent of the differential-bellows range for the majority of the 
flowing period.
    (c) The flowing temperature of the gas must be continuously 
recorded and used in the volume calculations under Sec.  3175.94(a)(1) 
of this subpart.
    (d) The following information must be maintained at the FMP in a 
legible condition, in compliance with Sec.  3170.7(g) of this subpart, 
and accessible to the AO at all times:
    (1) Differential-bellows range;
    (2) Static-pressure-element range;
    (3) Temperature-element range;
    (4) Relative density (specific gravity);
    (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 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 required in this part, the operator must 
perform a leak test. The verification must not proceed until no leaks 
are present. The leak test must be conducted in a manner that will 
detect leaks in the following:
    (i) All connections and fittings of the secondary device, including 
meter manifolds and verification equipment;
    (ii) The isolation valves; and
    (iii) The equalizer valves.
    (2) The time lag between the differential and static pen must be 
adjusted, 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 adjusted, if 
necessary, to duplicate the test chart's time arc over the full range 
of the test chart.
    (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 the following table, the operator must replace and 
verify the element whose readings were outside the applicable 
tolerances before returning the meter to service.

                Table 2-1--Mechanical Recorder Tolerances
------------------------------------------------------------------------
                  Element                          Allowable error
------------------------------------------------------------------------
Differential Pressure.....................  0.5%
Static Pressure...........................  1.0%
Temperature...............................  2 [deg]F
------------------------------------------------------------------------

    (7) If the static-pressure pen is offset for atmospheric pressure:
    (i) The atmospheric pressure must be calculated under Attachment 2 
of this subpart; and
    (ii) The pen must be offset prior to obtaining the as-left 
verification values

[[Page 61700]]

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 2, in 
months (see Sec.  3175.90 of this subpart).
    (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 
following readings in the order listed: Zero (vented to atmosphere), 50 
percent of the element range, 100 percent of the element range, 80 
percent of the element range, 20 percent of the element range, zero 
(vented to atmosphere), 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 paragraphs (c)(3) or (4) of this section are not 
within the tolerances shown in Table 2-1, when compared to the values 
applied by the test equipment.
    (6) The operator must adjust the time lag between the differential 
and static pen, if necessary, to be 1/96 of the chart rotation period, 
measured at the chart hub. For example, the time lag is 15 minutes on a 
24-hour test chart and 2 hours on an 8-day test chart.
    (7) The meter's differential pen arc must be able to duplicate the 
test chart's time arc over the full range of the test chart, and must 
be adjusted, if necessary.
    (8) If any adjustment to the meter was made, the operator must 
perform an as-left verification on each element adjusted using the 
procedures in paragraphs (c)(3) and (4) of this section.
    (9) If, after an as-left verification, any of the readings required 
in paragraph (c)(3) or (4) of this section vary by more than the 
tolerances shown in Table 2-1 when compared with the test-device 
reading, the element whose readings are outside the applicable 
tolerances must be replaced and verified under this section before 
returning the meter to service.
    (10) If the static-pressure pen is offset for atmospheric pressure:
    (i) The atmospheric pressure must be calculated under Appendix 2 of 
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 subpart, 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);
    (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) The operator must notify the AO at least 72 hours before 
conducting the verifications required by this subpart.
    (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 Mcf/day, the volumes reported on the OGOR and on royalty 
reports submitted to ONRR must be corrected beginning with the date 
that the inaccuracy occurred. If that date is unknown, the volumes must 
be corrected beginning with the production month that includes the date 
that is half way between the date of the last verification and the date 
of the current verification.
    (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 subpart;
    (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);

[[Page 61701]]

    (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] TP13OC15.022

where:

    Cd = discharge coefficient, calculated under API 
14.3.3 (incorporated by reference, see Sec.  3175.31). or AGA Report 
No. 3 (1985)
    [beta] = Beta ratio.
    Y = gas expansion factor, calculated under API 14.3.3.5.6 
(incorporated by reference, see Sec.  3175.31) or AGA Report No. 3 
(1985)
    d = orifice diameter, in inches.
    Zb = supercompressibility at base pressure and 
temperature
    Gr = relative density (specific gravity).
    Zf = supercompressibility at flowing pressure and 
temperature
    Tf = average flowing temperature, in degrees Rankine.

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


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

    The following table lists the API standards and BLM requirements 
that the operator must follow to install and maintain an EGM system on 
a differential-type primary device. A requirement applies when a column 
is marked with an ``x'' or a number.

                            Table 3--Standards for Electronic Gas Measurement Systems
----------------------------------------------------------------------------------------------------------------
                                       Reference (API
                                          standards
              Subject                  incorporated by          M             L             H             V
                                    reference,  see Sec.
                                           3175.31)
----------------------------------------------------------------------------------------------------------------
EGM commissioning.................  API 21.1.7.3........          n/a             x             x             x
Access and data security..........  API. 21.1.9.........            x             x             x             x
No-flow cutoff....................  API 21.1.4.4.5......            x             x             x             x
Manifolds and gauge lines.........  Sec.   3175.101(a)..          n/a             x             x             x
Display requirements..............  Sec.   3175.101(b)..            x             x             x             x
On-site information...............  Sec.   3175.101(c)..            x             x             x             x
Operating within the calibrated     Sec.   3175.101(d)..          n/a             x             x             x
 limits.
Flowing-temperature measurement...  Sec.   3175.101(e)..          n/a             x             x             x
Verification after installation or  Sec.   3175.102(a)..            x             x             x             x
 following repair*.
Routine verification frequency, in  Sec.   3175.102(b)..           12             6             3             1
 months*.
Routine verification procedures...  Sec.   3175.102(c)..            x             x             x             x
Redundancy verification...........  Sec.   3175.102(d)..            x             x             x             x
Documentation of verification.....  Sec.   3175.102(e)..            x             x             x             x
Notification of verification......  Sec.   3175.102(f)..            x             x             x             x
Volume correction.................  Sec.   3175.102(g)..          n/a             x             x             x
Test-equipment certification......  Sec.   3175.102(h)..            x             x             x             x
Flow-rate calculation.............  Sec.   3175.103(a)..            x             x             x             x
Atmospheric pressure..............  3175.103(b).........            x             x             x             x
Volume calculation................  Sec.   3175.103(c)..            x             x             x             x
QTR requirements..................  Sec.   3175.104(a)..            x             x             x             x
Configuration log requirements....  Sec.   3175.104(b)..            x             x             x             x
Event log.........................  Sec.   3175.104(c)..            x             x             x             x
----------------------------------------------------------------------------------------------------------------
M=Marginal-volume FMP; L=Low-volume FMP; H=High-volume FMP; V=Very-high-volume FMP = Immediate assessment for
  non-compliance under Sec.   3175.150 of this subpart.


[[Page 61702]]

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 an internal diameter not less than \3/8\-inch, including 
ports and valves;
    (2) Be constructed of stainless steel;
    (3) Be sloped upwards from the pressure taps at a minimum pitch of 
1 inch per foot of length;
    (4) Have the same internal diameter along their entire length;
    (5) Not include any tees except for the static pressure line;
    (6) 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
    (7) 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 following variables:
    (i) The FMP number or, if an FMP number has not yet been assigned, 
a unique meter-identification number;
    (ii) Software version;
    (iii) Current flowing static pressure with units (psia or psig);
    (iv) Current differential pressure (inches of water);
    (v) Current flowing temperature ([deg] F);
    (vi) Current flow rate (Mcf/day or scf/day);
    (vii) Previous-day volume (Mcf);
    (viii) Previous-day flow time;
    (ix) Previous-day average differential pressure (inches of water);
    (x) Previous-day average static pressure with units (psia or psig);
    (xi) Previous-day average flowing temperature ([deg] F);
    (xii) Relative density (specific gravity); and
    (xiii) Primary device information such as orifice-bore diameter 
(inches) or Beta or area ratio and discharge coefficient, as 
applicable; and
    (5) Display items (iii) through (v) in paragraph (b)(4) of this 
section consecutively.
    (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) Elevation of the FMP;
    (3) Meter-tube mean inside diameter;
    (3) Make, model, and location of approved isolating flow 
conditioners, if used;
    (4) Location of the downstream end of 19-tube-bundle flow 
straighteners, if used;
    (5) For self-contained EGM systems, the make and model number of 
the system;
    (6) For component-type EGM systems, the make and model number of 
each transducer and the flow computer;
    (7) URL and upper calibrated limit for each transducer;
    (8) Location of the static pressure tap (upstream or downstream);
    (9) Last primary-device inspection date; and
    (10) 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.
    (e) The flowing temperature of the gas must be continuously 
measured and used in the flow-rate calculations under API 21.1.4 
(incorporated by reference, see Sec.  3175.31).


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

    (a) Verification after installation or following 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) of 
this subpart.
    (2) The operator must verify the points listed in API 21.1.7.3.3 
(incorporated by reference, see Sec.  3175.31) 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 21.1.8.2.2.2, Equation 24 (incorporated by reference, see Sec.  
3175.31), then that transducer must be replaced and retested 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 2 to this subpart or measured by a 
NIST-certified barometer with a stated accuracy of 0.05 
psi, or better.
    (4) Before putting a meter into service, the differential-pressure 
transducer must be re-zeroed with full working pressure applied to both 
sides of the transducer.
    (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 3, in months (see Sec.  3175.100 of this 
subpart); 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 21.1.8.2 (incorporated by reference, see 
Sec.  3175.31), 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) of this subpart.
    (2) An as-found verification for differential and static pressure 
must be conducted at the normal operating point of each transducer. The 
normal operating point is the flow-time linear average taken over the 
previous day (i.e. the value required in Sec.  3175.101(b)(4)(ix) and 
(x) of this subpart), or a longer period if available at the time of 
verification.
    (3) If either the differential- or static-pressure transducer is 
calibrated, the as-left verification must include the normal operating 
point of that transducer, as defined in paragraph (c)(2) of this 
section.
    (4) The as-found values for differential pressure obtained with the 
low side vented to atmospheric pressure must be corrected to working 
pressure values using API 21.1, Annex H, Equation H.1 (incorporated by 
reference, see Sec.  3175.31).
    (5) The verification tolerance for differential and static pressure 
is defined by API 21.1.8.2.2.2, Equation 24 (incorporated by reference, 
see Sec.  3175.31). The verification tolerance for temperature is 0.5 
degrees F.
    (6) All required verification points must be within the 
verification tolerance before returning the meter to service.
    (7) Before returning a meter to service, the differential pressure 
transducer must be rezeroed with full working pressure applied to both 
sides of the transducer.
    (d) Redundancy verification procedures. Redundancy verifications 
must be performed as required under API 21.1.8.2 (incorporated by 
reference,

[[Page 61703]]

see Sec.  3175.31), 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 average of differential pressure, static pressure, and 
temperature readings from the primary transducers with the check 
transducers;
    (3) If for any transducer the difference between the averages 
exceeds the tolerance defined by the following equation:

[GRAPHIC] [TIFF OMITTED] TP13OC15.013

where

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

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.  3170.6 of this part, 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.  3175.31);
    (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) The operator must notify the AO at least 72 hours before 
conducting the tests and verifications required by paragraph (c) of 
this section.
    (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 less, 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.
    (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) It must have a stated accuracy of at least 0.10 percent of the 
upper calibrated limit of the transducer being verified.


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

    (a) The flow rate must be calculated as follows:
    (1) For flange-tapped orifice plates, the flow rate must be 
calculated under:
    (i) API 14.3.3.4 and API 14.3.3.5 (both incorporated by reference, 
see Sec.  3175.31); and
    (ii) API 14.2 (incorporated by reference, see Sec.  3175.31), for 
supercompressibility.
    (2) For primary devices other than flange-tapped orifice plates, 
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 21.1.8.3.3 
(incorporated by reference, see Sec.  3175.31).
    (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 of this subpart must be determined under 
API 21.1. 4 and API 21.1 Annex B (both incorporated by reference, see 
Sec.  3175.31).


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 21.1.5.2 
(incorporated by reference, see Sec.  3175.31), with the following 
additions and clarifications:
    (1) The information required in Sec.  3170.7(g) of this part;
    (2) The volume, flow time, integral value or average extension, and 
the average differential pressure, static pressure, and temperature as 
calculated in Sec.  3175.103(c) of this subpart, reported to at least 
five significant digits; and

[[Page 61704]]

    (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 21.1.5.4 (including 
the flow computer snapshot report in API 21.1.5.4.2) and API 21.1 Annex 
G (all three incorporated by reference, see Sec.  3175.31), with the 
following additions and clarifications:
    (1) The information required in Sec.  3170.7(g) of this part;
    (2) Software/firmware identifiers under API 21.1.5.3 (incorporated 
by reference, see Sec.  3175.31);
    (3) For marginal-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 21.1.5.5 (incorporated by reference, see Sec.  
3175.31), with the following additions and clarifications:
    (1) The event log must record all power outages that inhibit the 
meter's ability to collect and store new data. The event log must 
indicate the length of the outage; and
    (2) 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 21.1.5.6 (incorporated 
by reference, see Sec.  3175.31).


Sec.  3175.110  Gas sampling and analysis.

    The following table lists the standards and practices that the 
operator must follow to obtain a reliable, accurate gas sample for the 
determination of relative density and heating value. A requirement 
applies when a column is marked with an ``x'' or a number.

                                                           Table 4--Gas Sampling and Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
              Subject                       Reference                   M                      L                      H                      V
--------------------------------------------------------------------------------------------------------------------------------------------------------
Types of sampling..................  Sec.   3175.111(a)....  x.....................  x....................  x....................  x
Heating requirements...............  Sec.   3175.111(b)....  x.....................  x....................  x....................  x
Samples taken from probes..........  Sec.   3175.112(a)....  n/a...................  x....................  x....................  x
Location of sample probe...........  Sec.   3175.112(b)....  n/a...................  x....................  x....................  x
Sample probe design and type.......  Sec.   3175.112(c)....  n/a...................  x....................  x....................  x
Sample tubing......................  Sec.   3175.112(d)....  n/a...................  x....................  x....................  x
Spot sample while flowing..........  Sec.   3175.113(a)....  x.....................  x....................  x....................  x
Notification of spot samples.......  Sec.   3175.113(b)....  x.....................  x....................  x....................  x
Sample cylinder requirements.......  Sec.   3175.113(c)....  x.....................  x....................  x....................  x
Spot sampling using portable GCs...  Sec.   3175.113(d)....  x.....................  x....................  x....................  x
Allowable methods of spot sampling.  Sec.   3175.114.......  x.....................  x....................  x....................  x
Spot sampling frequency, low and     Sec.   3175.115(a)....  12....................  6....................  n/a..................  n/a
 marginal FMPs (in months)*.
Initial spot sampling frequency,     Sec.   3175.115(a)....  n/a...................  n/a..................  3....................  1
 high and very-high FMPs (in
 months)*.
Adjustment of spot sampling          Sec.   3175.115(b)....  n/a...................  n/a..................  x....................  x
 frequencies, high and very-high
 FMPs.
Maximum time between samples.......  Sec.   3175.115(c)....  x.....................  x....................  x....................  x
Installation of composite sampler    Sec.   3175.115(d)....  x.....................  x....................  x....................  x
 or on-line GC.
Removal of composite sampler or on-  Sec.   3175.115(e)....  x.....................  x....................  x....................  x
 line GC.
Composite sampling methods.........  Sec.   3175.116.......  x.....................  x....................  x....................  x
On-line gas chromatographs.........  Sec.   3175.117.......  x.....................  x....................  x....................  x
Gas chromatograph requirements.....  Sec.   3175.118.......  x.....................  x....................  x....................  x
Minimum components to analyze......  Sec.   3175.119(a)....  x.....................  x....................  x....................  x
Extended analysis..................  Sec.   3175.119(b)....  n/a...................  n/a..................  x....................  x
Gas analysis report requirements...  Sec.   3175.120.......  x.....................  x....................  x....................  x
Effective date of spot and           Sec.   3175.121.......  x.....................  x....................  x....................  x
 composite samples.
--------------------------------------------------------------------------------------------------------------------------------------------------------
M = Marginal-volume FMP; L = Low-volume FMP; H = High-volume FMP; V = Very-high-volume FMP, * = Immediate assessment for non-compliance under Sec.
  3175.150 of this subpart

Sec.  3175.111  General sampling requirements.

    (a) Samples must be taken by one of the following methods:
    (1) Spot sampling under Sec. Sec.  3175.113 to 3175.115 of this 
subpart;
    (2) Flow-proportional composite sampling under Sec.  3175.116 of 
this subpart; or
    (3) On-line gas chromatograph under Sec.  3175.117 of this subpart.
    (b) The temperature of all gas sampling components must be 
maintained at least 30[emsp14][deg]F above the hydrocarbon dew point of 
the gas at all times during the sampling process.


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 
downstream of the primary device between 1.0 and 2.0 times dimension 
``DL'' (Downstream Length) from API 14.3.2 (incorporated by reference, 
see Sec.  3175.31), Table 2.7 or 2.8, as appropriate, and must be the 
first obstruction downstream of the primary device.
    (2) The sample probe must be exposed to the same ambient conditions 
as the primary device. For example, if the primary device is located in 
a heated meter house, the sample probe must also be located in the same 
heated 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[emsp14][deg]F above the hydrocarbon dew 
point of the gas.
    (3) The sample probe length must be long enough to place the 
collection end of the probe in the center one third of the pipe cross-
section.
    (4) The use of membranes, screens, or filters at any point in the 
sample probe is prohibited.

[[Page 61705]]

    (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 5 days of when 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) of this subpart.
    (b) The operator must notify the AO at least 72 hours before 
obtaining a spot sample as required by this subpart.
    (c) Sample cylinder requirements. Sample cylinders must:
    (1) Be constructed of stainless steel;
    (2) Have a minimum capacity of 300 cubic centimeters;
    (3) Be cleaned before sampling under GPA 2166-05, Appendix A 
(incorporated by reference, see Sec.  3175.31), or an equivalent method 
(of which cleaning the operator must maintain documentation); and
    (4) Be physically sealed in a manner that prevents opening the 
sample cylinder without breaking the seal before sampling.
    (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.  3175.31), or an equivalent method, prior to 
sampling (of which cleaning the operator must maintain documentation); 
and
    (iii) Be operated under GPA 2166-05, Appendix B.3 (incorporated by 
reference, see Sec.  3175.31).
    (2) Filters at the inlet of the GC must be cleaned or replaced 
before sampling.
    (3) The sample port and inlet to the sample line must be purged 
before sealing the connection between them.
    (4) The portable GC must be designed, operated, and calibrated 
under Sec.  3175.118 of this subpart.
    (5) Portable GCs may not be used when the flowing pressure of the 
gas is less than 15 psig.


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.  3175.31);
    (2) Helium ``pop'' method. Samples taken using this method must 
comply with GPA 2166-05, Section 9.5 (incorporated by reference, see 
Sec.  3175.31). The operator must maintain documentation demonstrating 
that the cylinder was evacuated and pre-charged before sampling and 
make it 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.  3175.31). The operator must 
maintain documentation of the seal material and type of lubricant used 
and make it available to the AO upon request;
    (4) Portable gas chromatograph. Samples taken using this method 
must comply with Sec.  3175.118 of this subpart.
    (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 14.1.12.10 (incorporated by reference, see Sec.  
3175.31), 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 4 (see 
Sec.  3175.110).
    (b) 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 4 is not sufficient to achieve the 
heating value certainty levels required in Sec.  3175.30(b) of this 
subpart.
    (1) The BLM will calculate the new sampling frequency needed to 
achieve the heating value certainty levels required in Sec.  3175.30(b) 
of this subpart. The BLM will base the sampling frequency calculation 
on the statistical variability of previously reported heating values. 
The BLM will notify the operator of the new sampling frequency.
    (2) The new sampling frequency will remain in effect until the 
variability of previous heating values justifies a different frequency.
    (3) The new sampling frequency will not be more frequent than once 
per week nor less frequent than once every 6 months.
    (4) The BLM may require the installation of a composite sampling 
system or on-line GC if the heating value certainty levels in 
3175.30(b) of this subpart cannot be achieved through spot sampling.
    (c) The time between any two samples must not exceed the timeframes 
shown in Table 5.

                  Table 5--Maximum time between samples
------------------------------------------------------------------------
                                                Then the maximum time
If the required sampling frequency is once    between samples (in days)
               during every:                             is:
------------------------------------------------------------------------
Week......................................                             9
2 weeks...................................                            18
Month.....................................                            45
2 months..................................                            75
3 months..................................                           105
6 months..................................                           195
12 months.................................                           380
------------------------------------------------------------------------

    (d) If a composite sampling system or an on-line GC is installed 
under Sec. Sec.  3175.116 or 3175.117 of this subpart, either on the 
operator's own initiative or in response to a BLM order to change the 
sampling frequency for a high-volume or very-high-volume FMP under 
paragraph (b) 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).

[[Page 61706]]

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.
    (d) The composite sampling system must meet the heating value 
uncertainty requirements of Sec.  3175.30(b) of this subpart.


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.  3175.31), 
and the manufacturer's specifications, instructions, and 
recommendations.
    (b) The on-line GC must meet the uncertainty requirements for 
heating values required in Sec.  3175.30(b) of this subpart.
    (c) Upon request, the operator must submit to the AO the 
manufacturer's specifications and installation and operational 
recommendations.
    (d) The GC must comply with the verification and calibration 
requirements of Sec.  3175.118 of this subpart. The results of all 
verifications must be submitted to the AO upon request.


Sec.  3175.118  Gas chromatograph requirements.

    (a) All GCs must be designed, installed, operated, and calibrated 
under GPA 2261-00 (incorporated by reference, see Sec.  3175.31).
    (b) Samples must be analyzed until three consecutive runs are 
within the repeatability standards listed in GPA 2261-00, Section 9 
(incorporated by reference, see Sec.  3175.31), and the unnormalized 
sum of the mole percent of all gases analyzed is between 99 and 101 
percent.
    (c) GCs must be verified under GPA 2261-00 (incorporated by 
reference, see Sec.  3175.31), Sections 4 and 5, at the following 
frequencies:
    (1) For portable GCs that are used for spot sampling, not more than 
24 hours before sampling at an FMP; or
    (2) For laboratory and on-line GCs, not less than once every 7 
days.
    (d) The gas used for verification must not be the same gas used for 
calibration.
    (e) If the composition of the sample as determined by the GC varies 
from the composition of the calibration gas by more than the 
repeatability values listed in GPA 2261-00, Section 9 (incorporated by 
reference, see Sec.  3175.31), the GC must be calibrated under GPA 
2261-00, Section 5 (incorporated by reference, see Sec.  3175.31).
    (f) If the GC is calibrated, it must be re-verified under 
paragraphs (d) and (e) of this section.
    (g) A GC may not be used to analyze any sample from an FMP until 
the verification meets the standards of paragraph (e) of this section.
    (h) All gases used for verification and calibration must meet the 
standards of GPA 2198-03 (incorporated by reference, see Sec.  
3175.31).
    (i) 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. For portable GCs used for spot 
sampling, documentation of the last verification must be on site at the 
time of sampling. 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 (i)(4) and (i)(5) of this section, expressed in relative 
percent;
    (7) Documentation that the gas used for verification meets the 
requirements of GPA 2198-03 (incorporated by reference, see Sec.  
3175.31), including a unique identification number of the calibration 
gas used and the name of the supplier of the calibration gas;
    (8) The time and date the verification was performed; and
    (9) The name and affiliation of the person performing the 
verification.


Sec.  3175.119  Components to analyze.

    (a) The gas must be analyzed for the following components:
    (1) Methane;
    (2) Ethane;
    (3) Propane;
    (4) Iso Butane;
    (5) Normal Butane;
    (6) Pentanes;
    (7) Hexanes + (C6+);
    (8) Carbon dioxide; and
    (9) Nitrogen.
    (b) For high-volume and very high-volume FMPs, if the concentration 
of C6+ exceeds 0.25 mole percent, the following gas 
components must also be analyzed:
    (1) Hexane;
    (2) Heptane;
    (3) Octane; and
    (4) Nonane+.


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 the sampling;
    (13) The ambient air temperature at the time the sample was taken;
    (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 percentages 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 pressure base and temperature base;
    (23) The relative density; and
    (24) 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.  3175.31).
    (d) The base supercompressibility must be calculated under API 14.2 
(incorporated by reference, see Sec.  3175.31).
    (e) The operator must submit all gas analysis reports to the BLM 
within 5

[[Page 61707]]

days of the due date for the sample as specified in Sec.  3175.115 of 
this subpart.
    (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 only in cases where 
the operator demonstrates that it is a small business, as defined by 
the U.S. Small Business Administration, and does not have access to the 
Internet.


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

    (a) Unless otherwise specified on the gas analysis report, the 
effective date of a spot sample is the date on which the sample was 
taken.
    (b) The effective date of a spot gas sample may be no later than 
the first day of the production month following the operator's receipt 
of the laboratory analysis of the sample.
    (c) The effective date of a composite sample is the date when the 
sample cylinder was installed.


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 14.5.3.7 (incorporated by 
reference, see Sec.  3175.31) and must be calculated under API 14.5.7.1 
(incorporated by reference, see Sec.  3175.31); and
    (2) Real heating value must be calculated by dividing the gross 
heating value of the gas calculated under paragraph (a)(1) by the 
compressibility factor of the gas at 14.73 psia and 60[emsp14][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] TP13OC15.014

Where:

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

    (2) If the effective date of a heating value for an FMP is other 
than the first day of the reporting month, the average heating value of 
the FMP must be the volume-weighted average of heating values, 
determined as follows:
[GRAPHIC] [TIFF OMITTED] TP13OC15.015

Where:

    HVi = the heating value for FMP i, in Btu/scf
    HVi,j = the heating value for FMP i, for 
partial month j, in Btu/scf
    Vi,j = the volume measured by FMP i, 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. Sec.  3175.94 
(mechanical recorders) or 3175.103(c) (EGM systems) of this subpart.


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[emsp14][deg]F; and
    (3) For samples analyzed under Sec.  3175.119(a) of this subpart, 
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;
    (ii) 30 percent n-heptane; and
    (iii) 10 percent n-octane;
    (b) The volume for royalty purposes must be reported on the OGOR in 
units of Mcf as follows:
    (1) The volumes must not be adjusted for water vapor content or any 
other factors that are not included in the calculations required in 
Sec. Sec.  3175.94 or 3175.103 of this subpart; 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 which 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 
subsisted must be estimated as follows:
    (i) For volume errors, during the time the measurement equipment 
was malfunctioning or out of service, use the average of the flow rate 
before the time the error occurred and the flow rate after the error 
was corrected; and
    (ii) For heating value errors, use the average of the heating 
values determined from five samples from the same FMP taken closest in 
time to the period in which the error subsisted, excluding the heating 
value(s) from the sample(s) known to be in error. If fewer than five 
heating values have been obtained, use the average of the most recent 
heating values that are known not to be in error.
    (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 of this subpart.

[[Page 61708]]

Sec.  3175.131  General requirements for transducer testing.

    (a) Qualified test facilities. (1) All testing must be performed by 
an independent test facility not affiliated with the manufacturer.
    (2) All equipment used for testing must be traceable to the NIST 
and have a current certification proving its traceability.
    (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 is ascertainable from the serial number.
    (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, 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 of this subpart 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.  3175.30(a) of this subpart.
    (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 of this subpart are completed.
    (h) For all of the testing required in Sec. Sec.  3175.132 and 
3175.133 of this subpart, 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 paragraph (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 then 
be tested at least three times for accuracy under Sec.  3175.131(h) of 
this subpart. The results of these tests must be used to determine the 
transducer's reference accuracy under Sec.  3175.135 of this subpart.


Sec.  3175.133  Testing of influence effects.

    (a) General requirements. (1) Reference conditions (see Sec.  
3175.132 of this subpart), 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 of 
this subpart.
    (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) of this subpart.

[[Page 61709]]

    (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) of this subpart.
    (d) Mounting position effects. The transducer must be tested for 
accuracy at four different orientations under Sec.  3175.131(h) of this 
subpart 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 original plane; and
    (4) At an angle of +10[deg] from a vertical plane perpendicular to 
the original plane.
    (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 one minute.
    (2) After removing the applied pressure, the transducer must be 
tested for accuracy under Sec.  3175.131(h) of this subpart.
    (3) No more than 5 minutes must be allowed between performing the 
procedures described in paragraphs (e)(1) and (e)(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) 20 frequency sweeps from 10 Hz to 2,000 Hz to 10 Hz must be 
applied to the transducer at a rate of one 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.
    (g) Long-term stability. (1) Long-term stability must be 
established through six consecutive testing cycles, each lasting 4 
weeks, and each cycle consisting of the following combination of 
temperature and input conditions:

------------------------------------------------------------------------
                                                 Input (%)   Temperature
                     Week                         of span      ([deg]F)
------------------------------------------------------------------------
1.............................................            0          -22
2.............................................           30          +38
3.............................................           60          +68
4.............................................           60         +122
------------------------------------------------------------------------

    (2) At the end of each cycle, the transmitter must be brought back 
to the same reference conditions used to determine the reference 
accuracy and allowed to stabilize for at least 3 hours. The transmitter 
must then be tested for accuracy under Sec.  3175.131(h) of this 
subpart.


Sec.  3175.134  Transducer test reporting.

    (a) Each test required by Sec. Sec.  3175.131 through 3175.133 of 
this subpart 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 AO. If the PMT determines 
that all testing was completed as required by Sec. Sec.  3175.131 
through 3175.133 of this subpart, it will make a recommendation that 
the BLM post the transducer make, model, and range, along with the 
reference uncertainty, influence effects, and any operating 
restrictions to the BLM's Web site (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 of this 
subpart 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 
of this subpart 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] TP13OC15.016

    Where Ei, Hi, and Ri, are 
described in paragraph 3175.134(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 = [sigma] x tdist

where:

    [sigma] = 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 of this subpart 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] TP13OC15.017

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 of this subpart
    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[emsp14][deg]F for ambient 
temperature effects)


and:

    [Delta]Zn,i = Zn,i - Zref,i


[[Page 61710]]


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] TP13OC15.018

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 = [sigma] Ez,n x tdist
    Es,n = [sigma] Es,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
    [sigma]z,n = the standard deviation of the zero-based 
differences from the influence effect tests under Sec.  3175.133 of 
this subpart and the reference uncertainty tests, in percent
    [sigma]s,n = the standard deviation of the span-based 
differences from the influence effect tests under Sec.  3175.133 of 
this subpart 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 an EGM system only if the testing performed on the software 
meets all of the standards and requirements in Sec. Sec.  3175.141 
through 3175.144 of this subpart. 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.


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

    (a) Qualified test facilities. All testing must be performed by an 
independent test facility not affiliated with the 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 of this subpart, 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 of this subpart 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 Web site 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) of this subpart for each test 
identified in Table 6, using the gas compositions identified in Table 
7, as prescribed in Table 6.

                                                                           Table 6--Required Inputs for Static Testing
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                        Differential                                           Composition (see
                     Test                         Pipe inside      Orifice diameter   pressure (inches   Static pressure        Flowing        Table 7 of this         Static Tap  location
                                               diameter (inches)       (inches)          of water)            (psia)        temperature (F)        section)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1............................................              2.067              0.500                  1                 15                 40                  1  Up.
2............................................                                 1.500                800                140                 80                  2  Down.
3............................................              6.065              1.000                100               1000                -40                  1  Up.
4............................................                                 4.000                 50                500                150                  1  Down.
5............................................              4.026              1.000                100               1000                -40                  2  Down.
6............................................                                 3.000                 50                500                150                  2  Up.
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------


            Table 7--Required Compositions for Static Testing
------------------------------------------------------------------------
                                         Composition (mole percent)
             Component             -------------------------------------
                                      Composition 1      Composition 2
------------------------------------------------------------------------
Methane...........................            92.0000            76.0000
Ethane............................             3.3000             8.3000
Propane...........................             1.5000             3.6000
i-Butane..........................             0.4900             0.9000
n-Butane..........................             0.3600             1.5000
i-Pentane.........................             0.4000             1.0000
n-Pentane.........................             0.3000             0.5000
n-Hexane..........................             0.3000             0.8000
n-Heptane.........................             0.2000             0.3000
n-Octane..........................             0.1000             0.2000

[[Page 61711]]

 
n-Nonane..........................             0.0500             0.1000
Carbon dioxide....................             0.8000             5.3000
Nitrogen..........................             0.2000             1.4000
Helium............................             0.0000             0.0500
Oxygen............................             0.0000             0.0300
Hydrogen sulfide..................             0.0000             0.0200
------------------------------------------------------------------------

    (b) Sums and averages. (1) Fixed input values from test 2 in Table 
6 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) of this 
subpart:
    (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) of this subpart;
    (2) Inputs simulating a 15 percent and 150 percent over-range of 
the differential and static pressure transducers must be entered to 
verify that the over-range condition triggered an alarm or an entry in 
the event log; and
    (3) The power to the flow computer must be shut off for at least 1 
hour and then restored to verify that the power outage and time of 
outage was recorded in the event log or indicated on the quantity 
transaction 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 a duration of 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) of this subpart:
    (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 a duration of 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 20[emsp14][deg]F and approximately 100[emsp14][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) of this 
subpart:
    (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 a duration of 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[emsp14][deg]F to approximately 100[emsp14][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) of this subpart:
    (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.

[[Page 61712]]

    (2) At the end of the 7-day test period, the accumulated volume 
must meet the criteria in Sec.  3175.141(d) of this subpart.


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 of this subpart. 
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. If the PMT determines 
all testing was completed as required by this section, it will make a 
recommendation that the BLM post the software version on the BLM's Web 
site (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:

              Violations subject to an immediate assessment
------------------------------------------------------------------------
                                                              Assessment
                         Violation:                           amount per
                                                              violation:
------------------------------------------------------------------------
1. New FMP orifice plate inspections were not conducted as         1,000
 required by Sec.   3175.80(c) of this subpart.............
2. Routine FMP orifice plate inspections were not conducted        1,000
 as required by Sec.   3175.80(d) of this subpart..........
3. Visual meter-tube inspections were not conducted as             1,000
 required by Sec.   3175.80(h) of this subpart.............
4. Detailed meter-tube inspections were not conducted as           1.000
 required by Sec.   3175.80(i) of this subpart.............
5. An initial mechanical recorder verification was not             1,000
 conducted as required by Sec.   3175.92(a) of this subpart
6. Routine mechanical recorder verifications were not              1,000
 conducted as required by Sec.   3175.92(b) of this subpart
7. An initial EGM system verification was not conducted as         1,000
 required by Sec.   3175.102(a) of this subpart............
8. Routine EGM system verifications were not conducted as          1,000
 required by Sec.   3175.102(b) of this subpart............
9. Spot samples for low-volume and marginal-volume FMPs            1,000
 were not taken as required by Sec.   3175.115(a) of this
 subpart...................................................
10. Spot samples for high- and very-high-volume FMPs were          1,000
 not taken as required by Sec.   3175.115(a) and (b) of
 this subpart..............................................
------------------------------------------------------------------------

BILLING CODE 4310-84-C
[GRAPHIC] [TIFF OMITTED] TP13OC15.019


[[Page 61713]]


[GRAPHIC] [TIFF OMITTED] TP13OC15.020


[[Page 61714]]


[GRAPHIC] [TIFF OMITTED] TP13OC15.021

    Part of the verification process involves venting the pressure 
device to the atmosphere, recording the reading from the device, and 
calibrating (adjusting) the reading, if necessary. When a gauge-
pressure device is vented to the atmosphere, the reading of the device 
should be ``zero'' because both sides of the device are sensing 
atmospheric pressure. The calibrator will calibrate the device to read 
``zero'' if necessary. When verifying an absolute pressure device, 
however, the reading should equal the local atmospheric pressure 
because one side of the device

[[Page 61715]]

is sensing atmospheric pressure and the other side of the device is 
sensing an absolute vacuum. The calibrator will calibrate the device to 
read local atmospheric pressure if necessary. The most accurate way to 
determine atmospheric pressure at the time of verification is to 
measure it with a barometer. Although the use of an atmospheric 
pressure calculated from elevation results in higher uncertainty, the 
increased uncertainty is accounted for in the BLM uncertainty 
calculator.
[FR Doc. 2015-25556 Filed 10-9-15; 8:45 am]
BILLING CODE 4310-84-P