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

> Briefs, arguments, decisions, and more.

URL: https://www.frixlaw.com/law-library/documents/fr%3A2015-25556

## Record

- **Collection:** Federal Register
- **Document type:** Proposed Rule
- **Published:** October 13, 2015
- **Citation:** 80 FR 61646

## Text

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:

OIRA_Submission@omb.eop.gov
. 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
j35spenc@blm.gov
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,

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 (§§ 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 (§ 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.

3. Meter Verification or Calibration (§§ 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 (§§ 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

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 § 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 § 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

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 proposed rule
This section of Order 5 would appear in 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 proposed rule
The purpose of this 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 this proposed rule
See proposed new 43 CFR 3170.2 (80 FR 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 this proposed rule
See proposed new 43 CFR 3170.7 (80 FR 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

• 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, 10, 11 (Orifice plate and meter tube standards)
43 CFR 3175.80
The proposed rule would adopt, in 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, 14, 15, 16, 17, 18, 19 (Chart recorder standards)
43 CFR 3175.90-3175.94
The proposed rule would restrict the 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 for malfunction or out of service)
43 CFR 3175.126
The requirement for estimating volumes when metering equipment is malfunctioning or out-of-service would make clear the acceptable methods of estimating volume and associated documentation.

Paragraph 21 (Volume calculation AGA 3)
43 CFR 3175.90-3175.94, 3175.100-3175.103
The proposed rule would update the reference to 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 meter requirement)
43 CFR 3175.70
Requirements for 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 3175.110-3175.121
The requirements for 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 information requirement)
43 CFR 3175.90, 3175.92, 3175.100, and 3175.102
The information required on meter calibration reports would be expanded for both mechanical recorders and EGM systems.

Paragraph 25 (Atmospheric pressure requirement)
43 CFR 3175.90, 3175.92, 3175.100, and 3175.102
The proposed rule would change the basis for 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 frequency—specific gravity)
43 CFR 3175.110-3175.120
Order 5 has no 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 systems—Addressed in statewide NTLs
43 CFR 3175.100-3175.126
Order 5 does not address EGM systems; 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 Methods or at Other Locations Acceptable to the Authorized Officer
43 CFR 3175.47, 3175.48, and 3175.70
Requirements for obtaining approval for off-lease 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 or flow computer testing
43 CFR 3175.130-3175.144
The proposed rule would establish a testing protocol and approval process for transducers used in EGM systems and flow-computer software.

No requirements for reporting of volume and heating value
43 CFR 3175.126
The proposed rule would establish standards for heating value reporting, averaging heating value from multiple FMPs and multiple samples, and volume reporting.

IV. Variance from Minimum Standards
No section in this proposed rule
See proposed new 43 CFR 3170.6 (80 FR 40804, July 13, 2015).

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

§ 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 § 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 § 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

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.

EP13OC15.008

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 § 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).

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.

§ 3175.20
General Requirements
Proposed § 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 § 3170.6).

§ 3175.30
Specific Performance requirements

Proposed § 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 § 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 § 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 § 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 § 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 § 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 × heating value per unit volume (
i.e.,
MMBtu/Mcf) × royalty value (
i.e.,
the arm's-length price in $/MMBtu) × royalty rate. Thus, a 5 percent error in heating value would result in the same error in royalty as a 5 percent error in volume measurement.

The BLM recognizes that the heating value determined from a spot sample only represents a snapshot in time, and the actual heating value at any point after the sample was taken may be different. The probable difference is a function of the degree of variability in heating values determined from previous samples. If, for example, the previous heating values for a meter are very consistent, then the BLM would expect that the difference between the heating value based on a spot sample and the actual heating value at any given time after the spot sample was

taken would be relatively small. The opposite would be true if the previous heating values had a wide range of variability. Therefore, the uncertainty of the heating value calculated from spot sampling 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 § 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 § 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 § 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.

§ 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 §§ 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 § 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

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.

§§ 3175.40-3175.45
Measurement Equipment Approved by Standard or Make and Model
Proposed § 3175.40 would provide that the specific types of measurement equipment identified in proposed §§ 3175.41—3175.45 could be installed at FMPs without further approval. Flange-tapped orifice plates (proposed § 3175.41) have been rigorously tested and shown that they are capable of meeting the performance standards of proposed § 3175.30(a). Mechanical recorders (proposed § 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 §§ 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 § 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 § 3175.43 (transducers) and proposed § 3175.44 (flow computer software) would require these components of an EGM system to be tested under the protocols proposed in §§ 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 § 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 § 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 § 3175.44) would not be exempt from testing under proposed § 3175.140.

Gas chromatographs (proposed § 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 § 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 §§ 3175.117 and 3175.118.

§§ 3175.46 and 3175.47
Approval of Isolating Flow Conditioners and Differential Primary Devices Other Than Flange-Tapped Orifice Plates
Proposed §§ 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 § 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 § 3175.30(a). Additional testing protocols would be posted on the BLM's Web site at
www.blm.gov
.

Proposed § 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 § 3175.30 of this rule. The BLM would post any additional testing protocols on its Web site at
www.blm.gov
.

§ 3175.48
Linear Measurement Devices
Proposed § 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.

§ 3175.60
Timeframes for compliance
Proposed § 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 § 3175.115, the gas-analysis submittal requirements in proposed § 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 § 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).

§ 3175.70
Measurement Location
Proposed § 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.

§ 3175.80
Flange-Tapped Orifice Plates (Primary Device)

Proposed § 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

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 § 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 § 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 § 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.

EP13OC15.009

Proposed § 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 § 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 § 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

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 § 3175.30(a). To ensure that high-volume and very-high-volume FMPs maintain the uncertainty required in proposed § 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 § 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 § 3175.80(d) would establish a frequency for routine orifice plate inspections. The term “routine” is used to differentiate this proposed requirement from proposed § 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 § 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 § 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 § 3175.80(k). The BLM has reviewed the API standards referenced and believes that they meet the intent of § 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.

Parameter
Proposed (API 14.3.2, 2000)
Existing (AGA Report No. 3, 1985)
Require retrofit?

Surface roughness (R
a
)

β ≥ 0.6: 34 μin ≤ R
a
< 250 μin

β < 0.6: 34 μin ≤ R
a
< 300 μin

R
a
≤ 300 μin

No

Meter tube diameter
Average of 4 measurements 1 inch upstream of orifice
Average of 4 measurements 1 inch upstream of orifice
No

Upstream check measurements
2 additional cross sections
2 additional cross sections
No.

Downstream check measurements
At 1 inch downstream of the orifice
At 1 inch downstream of the orifice
No.

Roundness at inlet section
Difference between any measurement and the average diameter ≤ 0.25% of average diameter
Difference between maximum and minimum measurement ≤ 0.5% to 5% of average diameter as a function of β
Potentially.

Roundness at all upstream sections
Difference between maximum and minimum ≤ 0.5% of average diameter
Not specified
Potentially.

Roundness at downstream section
Difference between any measurement and the average diameter ≤ 0.5% of average diameter
Difference between any measurement and the average diameter ≤ 0.5% to 5% of average diameter as a function of β
Potentially.

Abrupt changes
Not allowed
Not allowed
No.

Gaskets, protrusions, recesses
Protrusions prohibited; recesses restricted if > 0.25 inches
Recesses restricted if > 0.25 inches
No.

Tap hole location
1 inch from upstream and downstream orifice plate faces, respectively
1 inch from upstream and downstream orifice plate faces, respectively
No.

Tap hole location tolerance
Range from 0.015 inches to 0.15 inches depending on size and β
Range from 0.015 inches to 0.15 inches depending on size and β
No.

Tap hole diameter
0.375 ±0.016 inches (2-3 inch nominal diameter); 0.500 ±0.016 inches (4 inch and greater nominal diameter)
0.250 to 0.375 inches (2-3 inch nominal diameter); 0.250 to 0.500 inches (4 inch and greater nominal diameter)
No (holes can be re-drilled).

Note:
β = the Beta ratio; μin = micro-inches (millionth of an inch) R
a
= 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 § 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 § 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 § 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 § 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 § 3175.80(g) would allow isolating flow conditioners to be used at FMPs if they have been reviewed and approved by the BLM under § 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 § 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 § 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 § 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 § 3175.80(i) of this proposed rule.

Proposed § 3175.80(i) would require a detailed inspection of meter tubes on

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 § 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 § 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 § 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 § 3175.30(a), they still would have to be free of statistically significant bias under proposed § 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 § 3175.80(l) would set standards for thermometer wells, including the adoption of API MPMS 14.3.2.6.5 in proposed § 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 § 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 § 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

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 § 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 §§ 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 § 3175.80(m) would require operators to locate the sample probe as required in § 3175.112(b). This would be a new requirement. The reference to proposed § 3175.112(b) is in proposed § 3175.80(m) because the sample probe is part of the primary device. Please see the discussion of proposed § 3175.112(b) for an explanation of the requirement.

Proposed § 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.

§ 3175.90
Mechanical Recorders (Secondary Device)
Proposed § 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 § 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 § 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 §§ 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 § 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.

§ 3175.91
Installation and Operation of Mechanical Recorders
Proposed § 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 § 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 § 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 § 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 § 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 §§ 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

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. § 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 § 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 § 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

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Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3A2015-25556. Public record. Not legal advice.