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

> Briefs, arguments, decisions, and more.

URL: https://www.frixlaw.com/law-library/documents/fr%3A2016-25405

## Record

- **Collection:** Federal Register
- **Document type:** Rule
- **Published:** November 17, 2016
- **Citation:** 81 FR 81462

## Text

DEPARTMENT OF THE INTERIOR
Bureau of Land Management
43 CFR Parts 3160 and 3170
[17X.LLWO310000.L13100000.PP0000]
RIN 1004-AE16
Onshore Oil and Gas Operations; Federal and Indian Oil and Gas Leases; Measurement of Oil

AGENCY:

Bureau of Land Management, Interior.

ACTION:

Final rule.

SUMMARY:

This final rule updates and replaces Onshore Oil and Gas Order Number 4, Measurement of Oil (Order 4) with new regulations codified in the Code of Federal Regulations (CFR). It establishes minimum standards for the measurement of oil produced from Federal and Indian (except Osage Tribe) leases to ensure that production is accurately measured and properly accounted for.

DATES:

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

ADDRESSES:

Mail:
U.S. Department of the Interior, Director (630), Bureau of Land Management, Mail Stop 2134 LM, 1849 C St. NW., Washington, DC 20240, Attention: 1004-AE16.

Personal or messenger delivery:
20 M Street SE., Room 2134LM, Washington, DC 20003.

FOR FURTHER INFORMATION CONTACT:

Mike McLaren, Petroleum Engineer, BLM Wyoming, Pinedale Field Office, 1625 West Pine St., P.O. Box 768, Pinedale, WY 82941, or by telephone at 307-367-5389, for information about the requirements of this final rule; or Steven Wells, Division Chief, Fluid Minerals Division, 202-912-7143, for information regarding the Bureau of Land Management's (BLM's) Fluid Minerals Program. For questions related to regulatory process issues, please contact Faith Bremner at 202-912-7441. Persons who use a telecommunications device for the deaf (TDD) may call the Federal Relay Service at 800-877-8339 to contact the above individuals during normal business hours. The Service is available 24 hours a day, 7 days a week to leave a message or question with the above individuals. You will receive a reply during normal business hours.

SUPPLEMENTARY INFORMATION:

I. Overview and Background

II. Overview of Final Rule, Section-by-Section Analysis, and Response to Comments on the Proposed Rule

III. Overview of Public Involvement and Consistency With GAO Recommendations

IV. Procedural Matters

I. Overview and Background

The BLM developed this rule based on the proposed rule published in the
Federal Register
on September 30, 2015 (80 FR 58952), and the BLM's consideration of tribal and public comments received on the proposed rule. This final rule strengthens the BLM's policies governing production accountability by updating its minimum standards for oil measurement to reflect the considerable changes in technology and industry practices that have occurred in the 25 years since Order 4 was issued. It also responds to recommendations the United States Government Accountability Office (GAO), the Department of the Interior's (Interior's or Department's) Office of the Inspector General (OIG), and the Secretary of the Interior's (Secretary's) Royalty Policy Committee (RPC), Subcommittee on Royalty Management (Subcommittee) made with respect to the BLM's production verification efforts. As explained in this preamble, the overall volume uncertainty and performance goals established by this rule are designed to ensure that the oil volume reported on an Oil and Gas Operations Report (OGOR) submitted to the Office of Natural Resources Revenue (ONRR) is sufficiently accurate to ensure that the royalties due are paid.

Like the proposed rule, the final rule addresses the use of new oil meter technology, proper measurement documentation, and recordkeeping; establishes performance standards for oil measurement systems; and includes a mechanism for the BLM to review, and approve for use, new oil measurement technology and systems. The final rule expands the acts of noncompliance that would result in an immediate assessment. Finally, it sets forth a process for the BLM to consider variances from these requirements.

Key changes incorporated into the final rule include provisions that allow operators to use Coriolis measurement systems (CMSs) and automatic tank gauging (ATG) systems without having to obtain variances from the BLM.

This final rule, as well as the final rules to update and replace Onshore Oil and Gas Orders Numbers 3 (Order 3) and 5 (Order 5) related to site security and the measurement of gas, respectively, enhance the BLM's overall production verification and accountability program.

The Secretary has the authority under various Federal and Indian mineral leasing laws to manage oil and gas operations on Federal and Indian (except Osage Tribe) lands. Governing laws include, but are not limited to, the Mineral Leasing Act (MLA), 30 U.S.C. 181
et seq.;
the Mineral Leasing Act for Acquired Lands, 30 U.S.C. 351
et seq.;
the Federal Oil and Gas Royalty Management Act (FOGRMA), 30 U.S.C. 1701
et seq.;
the Indian Mineral Leasing Act, 25 U.S.C. 396a
et seq.;
the Act of March 3, 1909, 25 U.S.C. 396; the Indian Mineral Development Act, 25 U.S.C. 2101
et seq.;
and the Federal Land Policy and Management Act (FLPMA), 43 U.S.C. 1701,
et seq.
1

1
Each of the statutes cited above expressly authorizes the Secretary of the Interior to promulgate necessary and appropriate rules and regulations governing those leases.
See e.g.,
30 U.S.C. 189; 30 U.S.C. 359; 30 U.S.C. 1751; 25 U.S.C. 396d; 25 U.S.C. 396; 25 U.S.C. 2107; and 43 U.S.C 1740. The Secretary has delegated this authority to the BLM. Specifically, under Secretarial Order Number 3087, dated December 3, 1982, as amended on February 7, 1983 (48 FR 8983), and the Departmental Manual (235 DM 1.1), the Secretary has delegated regulatory authority over onshore oil and gas development on Federal and Indian (except Osage Tribe) lands to the BLM. For Indian leases, the delegation of authority to the BLM is reflected in 25 CFR parts 211, 212, 213, 225, and 227. In addition, as authorized by 43 U.S.C. 1731(a), the Secretary has delegated to the BLM regulatory responsibility for oil and gas operations in Indian lands. 235 DM 1.1.K.

The BLM's onshore oil and gas program is one of the most significant mineral-leasing programs in the Federal Government. In the fiscal year (FY) 2015 sales year, onshore Federal oil and gas lease holders sold 180 million barrels of oil,
2

2.5 trillion cubic feet of natural gas,
3

and 2.6 billion gallons of natural gas liquids, with a market value of more than $17.7 billion, and generating royalties of almost $2 billion. Nearly half of these revenues were distributed to the States in which the leases are located. Lease holders on tribal and Indian lands sold 59 million barrels of oil, 239 billion cubic feet of natural gas, and 182 million gallons of natural gas liquids, with a market value of over $3.6 billion, and generating royalties of over $0.6 billion that were all distributed to the applicable tribes and individual allotment owners. Under applicable laws, royalties are owed on all production removed or sold from Federal and Indian oil and gas leases.

The basis for those royalty payments is the measured production from those leases.

2
This figure includes 168 million barrels of regularly classified oil, plus additional sales of condensate, sweet and sour crude, black wax crude, other liquid hydrocarbons, inlet scrubber and drip or scrubber condensate, and oil losses, all of which are considered to be part of oil sales for accounting purposes.

3
This figure includes all processed and unprocessed volumes recovered on-lease, nitrogen, fuel gas, coal bed methane, and any volumes of gas lost due to venting or flaring.

As explained in the preamble for the proposed rule, given the magnitude of oil production on Federal and Indian lands, and the BLM's statutory and management obligations, it is critically important that the BLM ensure that operators accurately measure, properly report, and account for that production. However, the BLM's rules governing how that oil is measured and accounted for are more than 25 years old and need to be updated and strengthened. Federal laws, technology, and industry standards have all changed significantly in that time. The final rule addresses the outdated nature of existing requirements and helps achieve the BLM's objective of ensuring accurate measurement by updating and replacing Order 4's requirements with regulations codified in the CFR, at a new 43 CFR subpart 3174. These new regulations reflect changes in oil measurement practices and technology since Order 4 was first promulgated in 1989.
4

4
Order 4, which was published in the
Federal Register
on February 24, 1989 (54 FR 8056), has been in effect since August 23, 1989.

These updated requirements are the result of the BLM's evaluation of its existing requirements, based on its experience in the field, and based on the conclusion of multiple reports and evaluations of the BLM's oil and gas program—one by the Subcommittee, issued in 2007; one by the OIG, issued in 2009; and two reports prepared by the GAO, issued in 2010 and 2015. Each of these is described further below.

In 2007, the Secretary appointed an independent panel—the Subcommittee—to review the Department's procedures and processes related to the management of mineral revenues and to provide advice to the Department based on that review.
5

In a report dated December 17, 2007, the Subcommittee determined that the BLM's production accountability methods are “unconsolidated, outdated, and sometimes insufficient.” The report observed that:

5
The Subcommittee was commissioned to report to the RPC, which was chartered under the Federal Advisory Committee Act to provide advice to the Secretary and other Departmental officials responsible for managing mineral leasing activities and to provide a forum for the public to voice concerns about mineral leasing activities.

• BLM policy and guidance have not been consolidated into a single document or publication, resulting in the BLM's 31 oil and gas field offices using varying policies and guidance (see page 31);

• Some BLM policy and guidance are outdated and some policy memoranda have expired (ibid.); and

• Some BLM State Offices have issued their own “Notices to Lessees and Operators” (NTLs) for oil and gas operations. While such NTLs may have a positive effect on local oil and gas field operations, they nevertheless lack a national perspective and may introduce inconsistencies among the States (ibid.).

The Subcommittee specifically recommended that the BLM evaluate Order 4 to determine whether it includes sufficient guidance for ensuring that accurate royalties are paid on Federal oil production. As explained in the preamble to the proposed rule, the Interior Department formed a Fluid Minerals Team, comprising Departmental oil and gas experts. The team determined that Order 4 should be updated in light of changes in technology, the BLM, and industry practices.

As noted, in addition to the Subcommittee report, findings and recommendation addressing similar issues have been issued by the GAO (Report to Congressional Requesters,
Oil and Gas Management, Interior's Oil and Gas Production Verification Efforts Do Not Provide Reasonable Assurance of Accurate Measurement of Production Volumes,
GAO-10-313 (GAO 2010 Report), and Report to Congressional Requesters,
Oil and Gas Resources, Interior's Production Verification Efforts: Data Have Improved but Further Actions Needed,
GAO 15-39 (GAO 2015 Report)) and the OIG (
Bureau of Land Management's Oil and Gas Inspection and Enforcement Program,
CR-EV-0001-2009 (OIG Report)).

In its 2010 report, the GAO found that the Department's measurement regulations and policies do not provide reasonable assurances that oil and gas are accurately measured because, among other things, the Department's policies for tracking where and how oil and gas are measured are not consistent and effective (GAO 2010 Report, p. 20). The report also found that the BLM's regulations do not reflect current industry-adopted measurement technologies and standards designed to improve oil and gas measurement (ibid.). The GAO recommended that Interior provide Department-wide guidance on measurement technologies not addressed in current regulations and approve variances for measurement technologies in instances when the technologies are not addressed in current regulations or Department-wide guidance (see ibid., p. 80). The OIG report made a similar recommendation that the BLM, “Ensure that oil and gas regulations are current by updating and issuing onshore orders. . . .” (see p. 11). In its 2015 report, the GAO reiterated that “Interior's measurement regulations do not reflect current measurement technologies and standards,” and that this “hampers the agency's ability to have reasonable assurance that oil and gas production is being measured accurately and verified . . .” (GAO 2015 Report, p. 16). Among its recommendations were that the Secretary direct the BLM to “meet its established time frame for issuing final regulations for oil measurement” (ibid., p. 32). The OIG made similar recommendations based on the Subcommittee's report observing that the BLM should, “(e)nsure that oil . . . regulations are current by updating and issuing onshore orders . . .” (OIG Report, p. 11).

The GAO's recommendations related to the adequacy of the BLM's oil measurement rules are also significant because they form one of the bases for the GAO's inclusion of the BLM's oil and gas program on the GAO's High Risk List in 2011 (Report to Congressional Committees,
High Risk Series, An Update,
GAO-11-278). Specifically, the GAO concluded in 2011 “that Interior's verification of the volume of oil . . . produced from Federal leases--on which royalties are due the Federal government--does not provide reasonable assurance that operators are accurately measuring and reporting these volumes” (GAO-11-278, p. 15). Because the GAO's recommendations have not yet been fully implemented, the onshore oil and gas program has remained on the High Risk List in subsequent updates in 2013 (Report to Congressional Committees,
High Risk Series, An Update,
GAO-13-283) and 2015 (Report to Congressional Committees,
High Risk Series, An Update,
GAO-15-290).

Up-to-date measurement requirements are critically important because they help ensure that oil and gas produced from Federal and Indian leases are properly accounted for, thus ensuring that operators pay the proper royalties due.

As explained in more detail below, the final rule makes a number of changes that modernize and strengthen the existing requirements in Order 4. In general, this final rule will give industry more choices and flexibility for measuring oil produced from Federal and Indian leases and will also make it easier for operators in the future to adopt new technologies and processes as the industry continues to advance.

In addition to updating requirements with respect to existing technologies, the final rule also specifically recognizes advances in measurement technology by affirmatively allowing operators to use a CMS
6

or an ATG/hybrid tank measurement system without first receiving a variance from the BLM, as is currently required.
7

In response to GAO and RPC concerns that BLM field offices put out various policies and guidance, the final rule establishes nationwide requirements and standards for this measurement equipment, including a nationwide process for reviewing and approving new technology as it is developed. This change is significant because CMSs have proven to be reliable and accurate in field and laboratory testing and, when the time comes to replace their older systems, more and more operators are opting to use CMSs.

6
A CMS is a metering system that uses a Coriolis flow meter in conjunction with a tertiary device, pressure transducer, and temperature transducer in order to derive and report gross standard oil volume. A Coriolis flow meter is based on the principle that fluid mass flow through a tube results in a measurable twisting or distortion and consequent oscillation of the tube. Sensors measure that oscillation and allow for a determination of various variables, including volume.

7
As explained in the proposed rule, since this equipment was not included in Order 4, the BLM did not have uniform national performance standards for these systems, which has led BLM state and field offices, while approving variances, to specify their own. The state-by-state approach results in inconsistencies among offices with respect to the requirements imposed on operators.

Similarly, operators in newer well fields have been using ATG systems for internal inventory purposes for over 10 years and only recently have they started using them to measure oil for sales and royalty-determination purposes. The BLM reviewed proprietary ATG test data that operators submitted to the BLM—both as public comment on the proposed rule and in support of variance requests to have ATG systems replace manual tank gauging. Based on that review, the BLM believes that ATG/hybrid systems can meet or exceed this rule's tank-gauging standards and as a result they should be expressly allowed. Affirmatively allowing ATG and hybrid systems will also increase worker safety because eliminating the need for workers to climb on top of tanks, open hatches, and manually measure or sample oil reduces their exposure to the fumes coming out of the tanks.
8

The final rule's incorporation of ATG/hybrid systems as a permissible measurement method gives operators an additional tool to address growing safety concerns.
9

8
The Durango Herald,
New hazard with oilfield work,
March 7, 2016;
http://www.durangoherald.com/article/20160307/NEWS01/160309666/New-hazard-with-oilfield-work.

9
In recent months this safety issue has been highlighted by news reports of the deaths of oil workers who died after manually opening oil tank hatches and being exposed to toxic fumes.

In recognition that new measurement technologies and processes, like CMSs and ATG systems, will continue to be developed and evolve, the final rule puts in place a process and criteria that will allow for a new Production Measurement Team (PMT) to review, and for the BLM to approve for use nationwide, new measurement technologies that are demonstrated to be reliable and accurate.
10

Under this new system, operators would have to prove to the BLM that new technologies meet or exceed this rule's new uncertainty performance standards, which for the first time give the BLM a set of objective criteria that can be applied to evaluate and approve any new meters, electronic components, computers, software, and procedures not specifically addressed in these regulations. Unlike the current variance system where operators must make such a showing each and every time they wish to deploy a new technology, under the PMT approach, once a technology has been approved by the BLM based on the PMT's review, that technology can be employed at additional facilities or by additional operators without a subsequent BLM approval, so long as those facilities and operators follow all conditions of approval (COAs) established by the PMT.

10
The PMT is distinct from the Interior's Gas and Oil Measurement Team (DOI GOMT), which consists of members with gas or oil measurement expertise from the BLM, the ONRR, and the Bureau of Safety and Environmental Enforcement (BSEE). BSEE handles production accountability for Federal offshore leases. The DOI GOMT is a coordinating body that enables the BLM and BSEE to consider measurement issues and track developments of common concern to both agencies. The BLM expects that the members of the BLM PMT would participate as part of the DOI GOMT.

Recognizing the newness of the PMT process, the final rule includes a 2-year phase-in for that system. Over the next 2 years, the BLM will develop and post on its Web site an uncertainty calculator that will help the BLM and industry determine if a particular measurement system or a new device meets the rule's uncertainty requirements. As an operator designs a new system, the operator can plug its components into the calculator and know before installing the system whether that system meets the requirements, and could be approved by the PMT. Once the BLM approves a new technology for use, it will post the make, model, size, or software version on its Web site as approved for use for all operators nationwide.

With respect to the PMT, it should be noted that while the final rule provides that the PMT will review requests and make recommendations to the BLM for approval, it is the BLM's intent that such approvals will be issued by a BLM AO with authority over the oil and gas program nationally (
e.g.,
the Director, a Deputy Director, or an Assistant Director), as opposed to that authority being delegated to a local level. This is consistent with recommendations from the RPC, GAO, and OIG that decisions on variances be granted at the national level to ensure they are consistent and have the appropriate perspective, as opposed to more local levels, which can result in inconsistencies among BLM field offices.

In another important departure from Order 4, this final rule avoids, where possible, cookbook-style lists of requirements for operators to follow when determining oil quantity and quality. Instead, in many instances, the rule simply requires operators to follow the applicable industry standards, which were developed through a consensus process by professional industry groups, with input from Federal oil and gas experts. In each instance, the BLM carefully reviewed the applicable standards and determined they are technically sufficient to meet the BLM's production verification needs and are structured in such a way that they can be enforced by BLM personnel in the field. The incorporation of industry standards into the final rule gives operators more flexibility to comply with the requirements of these regulations. For example, Order 4 had one specific way for operators to measure oil temperature—by inserting a thermometer in the approximate vertical center of the fluid column, not less than 12 inches from the tank shell for 5 minutes. The final rule still allows operators to measure oil temperature using this method, but they can now also follow American Petroleum Institute (API) Chapter 7 standards, which provide for operators to use built-in tank thermometers or to take measurements from the flow lines that lead to the haulers' trucks.

The rule also adopts a number of smaller changes which, taken together, will increase measurement accuracy, increase verifiability, and reduce waste. First, it would prohibit the use of automatic temperature/gravity compensators on lease automatic custody transfer (LACT) systems, which are required equipment under Order 4. These compensators automatically

adjust LACT totalizer readings to account for temperature effects and, in some cases, oil gravity effects on volume. However, because these automatic compensators do not maintain the raw data the BLM needs to verify that the compensators are functioning correctly or that the totalizer readings are correct, this rule requires operators to use temperature averaging devices instead, which record and average the temperatures of the fluids flowing through the LACT. This requirement ensures that the necessary audit trail is maintained. Such a system strikes the right balance because it gives operators the data they need to manually correct the volumes from the totalizer for the effects of temperature and oil gravity, while ensuring that the BLM has the raw data needed to verify the results and confirm system functionality.

Finally, the rule requires all oil storage tanks, hatches, connections, and other access points to be installed and maintained in accordance with manufacturers' specifications. This requirement, in effect, requires operators to maintain the pressure-vacuum integrity that manufacturers designed and built into their equipment. This in turn will minimize hydrocarbon gas lost to the atmosphere.

II. Overview of Final Rule, Section-by-Section Analysis and Response to Comments on the Proposed Rule

A. General Overview of the Final Rule

As discussed in the background section of this preamble, the BLM's rules concerning oil measurement found in Order 4 have not kept pace with industry standards and practices, statutory requirements, or applicable measurement technology and practices. The final rule enhances the BLM's overall production accountability efforts by addressing these concerns and ensuring that the oil produced from Federal and Indian (except Osage Tribe) leases is adequately accounted for, ultimately ensuring that all royalties due are paid.

The following table provides an overview of the changes between the proposed rule and this final rule. A similar chart explaining the differences between the proposed rule and Order 4 appears in the proposed rule at 80 FR 58955-58956.

Proposed rule
Final rule
Substantive changes

43 CFR 3174.1—Definitions and Acronyms
43 CFR 3174.1—Definitions and Acronyms
The final rule removes definitions for “registered volume,” “resistance thermal device,” and “turbulent flow.” It changes the definitions for “base pressure” and “Coriolis meter.” It adds new definitions for “indicated volume” and “transducer.”

43 CFR 3174.2—General Requirements
43 CFR 3174.2—General Requirements

The final rule gives operators a phase-in period of 1 to 4 years after the rule's effective date to bring existing facility measurement point (FMP) equipment into compliance. This timeframe is based on the operators' production volumes and it coincides with their schedule for applying for their FMP numbers. A new paragraph (g) in this section delays for 2 years a requirement that operators begin using approved equipment listed on the BLM website (
www.blm.gov
).

43 CFR 3174.3—Specific Measurement Performance Requirements
43 CFR 3174.3—Incorporation by Reference
The final rule adopts the latest versions of certain API standards and incorporates them by reference into the BLM's oil and gas regulations. It incorporates by reference many API standards that did not appear in the proposed rule and removes two industry standards developed by the American Society for Testing and Materials (ASTM).

43 CFR 3174.4—Incorporation by Reference
43 CFR 3174.4—Specific Measurement Performance Requirements
The final rule establishes two thresholds for overall oil measurement uncertainty levels. For FMPs measuring greater than or equal to 30,000 barrels (bbl)/month, the maximum uncertainty is ±0.50 percent. For FMPs measuring less than 30,000 bbl/month, the maximum uncertainty level is ±1.50 percent. Paragraph (d) is revised to clarify that the PMT, following the process outlined in § 3174.13, will make a determination whether proposed alternative equipment or measurement procedures meet or exceed the objectives and intent of this section.

43 CFR 3174.5 and 3174.6—Oil Measurement by Manual Tank Gauging
43 CFR 3174.5 and 3174.6—Oil Measurement by Tank Gauging

The final rule requires operators to submit sales tank calibration charts (tank tables) to the authorized officer (AO) within 45 days after calibrating or recalibrating. It allows operators to use ATG systems and, by replacing prescriptive language with additional industry standards, it gives operators more options for tank gauging, sampling, calibrating sales tanks, and determining temperature, oil gravity, and sediment and water (S&W) content. The final rule specifies manual gauging accuracy to the nearest
1/4
inch for tanks of 1,000 bbl or less and gauging accuracy to the nearest
1/8
inch for tanks greater than 1,000 bbl. All oil storage tanks must be clearly identified with an operator-generated unique number.

43 CFR 3174.7 and 3174.8—LACT Systems
43 CFR 3174.7 and 3174.8—LACT Systems
The final rule requires operators to notify the AO of any LACT system failures or equipment malfunctions, or other failures that could adversely affect oil measurement within 72 hours upon discovery. The requirement in proposed § 3174.7(b) that operators generate an additional run ticket before proving a LACT system has been modified. A related change in § 3174.12(b)(1) makes it clear that LACT systems that use flow computers are exempt from the requirement that operators close a run ticket before proving a LACT system. The table in proposed § 3174.7(c) entitled, “Standards to Measure Oil by a LACT System,” has been removed and in its place the final rule requires operators to complete measurement tickets as required under § 3174.12(b). Industry standards have been added to replace prescriptive language in the proposed rule. This gives operators more choices for collecting, mixing, and analyzing samples. The final rule clarifies that LACT systems may have either a Coriolis meter or a positive displacement (PD) meter.

43 CFR 3174.9—Coriolis Measurement System—General Requirements and Components
43 CFR 3174.9—Coriolis Measurement System—General Requirements and Components
The final rule is revised to clarify that operators can use CMSs as a standalone unit, independent of a LACT system. The table in paragraph (d) entitled, “Standards Applicable to CMS Use,” has been removed and in its place the final rule requires operators to complete measurement tickets, as required under § 3174.12(b). Prescriptive language in proposed paragraph (e) that dictated which CMS components should be used during set up and installation of a CMS, for the most part, has been removed and replaced with industry standards, which give operators more flexibility. The requirement for a back pressure valve has been removed and operators may use any means to apply sufficient back pressure to ensure single-phase flow so long as it meets industry standard API 5.6. Industry standards have been added to give operators more options for automatic sampling and for mixing and handling samples. A new paragraph (g) has been added that requires operators to follow API 12.2.1 and API 12.2.2 for calculating net standard volume. A similar, more prescriptive requirement for calculating net standard volume appeared in proposed § 3174.10(g), which has been removed from the final rule.

43 CFR 3174.10—Coriolis Measurement System—Operating Requirements
43 CFR 3174.10—Coriolis meter for LACT and CMS Measurement Applications
Requirement for straight piping upstream and downstream of a meter has been removed from the final rule. The requirement for verifying the meter zero value is revised to be less prescriptive and instead requires operators to follow manufacturers' specifications and procedures. The requirement that operators keep the log containing the meter factor, zero verification, and zero adjustments on site has been changed to require them to make it available to the AO upon request.

43 CFR 3174.11—Meter-Proving Requirements
43 CFR 3174.11—Meter-Proving Requirements
The final rule requires proving every 3 months (quarterly) after last proving, or after every 75,000 bbl of volume flows through the meter, whichever comes first, but no more frequently than monthly. The rule includes verification requirements for pressure, temperature, and density measurement devices with each proving. The table in proposed paragraph (b) entitled, “Minimum Standards for Proving FMP Meters,” has been removed because it is not needed. The proposed requirement for master meter repeatability of 0.0002 (0.02 percent) has been changed to 0.0005 (0.05 percent). The frequency for proving master meters is no less than once every 12 months. The final rule replaces prescriptive language that dictated the sizes and proving frequencies of displacement provers with requirements that operators follow industry standards. Paragraph (c)(4) adds the requirement that operators follow industry standards when calculating the average meter factor. Paragraph (c)(6) contains new language on how to utilize multiple meter factors. Meter-proving reports may be submitted to the AO in either hard-copy or electronic format.

43 CFR 3174.12—Measurement Tickets
43 CFR 3174.12—Measurement Tickets
The final rule requires that oil measurement tickets for LACT systems and CMS be closed at the end of each month and before proving unless utilizing flow computers. The rule allows the use of electronic measurement tickets. The final rule no longer requires the operator's representative to certify that the measurement on a completed run ticket is correct. The final rule has also removed the requirement that operators must notify the AO within 7 days if they disagree with a tank gauger's measurement.

43 CFR 3174.13—Oil Measurement by Other Methods
43 CFR 3174.13—Oil Measurement by Other Methods
None.

43 CFR 3174.14—Determination of Oil Volumes by Methods Other Than Measurement
43 CFR 3174.14—Determination of Oil Volumes by Methods Other Than Measurement
None.

43 CFR 3174.15—Immediate Assessments
43 CFR 3174.15—Immediate Assessments
The final rule removes one of the six violations listed in the proposed rule: Failure to notify the AO within 7 days of any changes to any CMS internal calibration factors (proposed violation #4). Of the five remaining violations listed, the final rule changes the timeframe from “within 24 hours” to “within 72 hours” that operators must notify the AO of any LACT system failure or equipment malfunction resulting in use of an unapproved alternative method of measurement (violation #2 in the final rule). The final rule also removes the word “variance” from the violation of failure to obtain a written approval before using any oil measurement method other than tank gauging, LACT system, or CMS at an FMP (violation #5 in the final rule).

B. Section-by-Section Analysis of the Final Rule and Response to Comments on Specific Provisions of the Proposed Rule

This final rule is codified primarily in a new 43 CFR subpart 3174 within a new part 3170. In addition to this rule, the BLM has also prepared separate rules to update and replace Onshore Oil and Gas Order Number 3 (Order 3) (site security), which will be codified at a new 43 CFR subpart 3173; and Onshore Oil and Gas Order Number 5 (Order 5) (gas measurement), which will be codified at a new 43 CFR subpart 3175. The rules to replace Orders 3 and 5 are being published concurrently with this rule. In addition to establishing a new 43 CFR subpart 3173, the rule to replace Order 3 establishes 43 CFR part 3170 and subpart 3170. Subpart 3170 contains definitions of certain terms common to more than one of these rules, as well as other provisions common to all of the rules, such as provisions prohibiting bypass of and tampering with meters; procedures for obtaining variances from the requirements of a particular rule; requirements for recordkeeping, records retention, and submission; and administrative appeal procedures. All of the definitions and substantive provisions of subpart 3170 also apply to this new subpart 3174.

Certain provisions of this final rule will result in amendments to related provisions in the onshore oil and gas operations rules in 43 CFR part 3160. The amendments to those provisions are also discussed below.

Subpart 3174 and Related Provisions

Section 3174.1 Definitions and Acronyms

Section 3174.1 defines terms and acronyms used in subpart 3174. Defining these terms and acronyms is necessary to ensure consistent interpretation and implementation of this rule. The BLM received a number of comments on this section. Except as noted in this section, the terms and acronyms in § 3174.1 did not change between the draft and final rule. A summary of the definitions and acronyms that were not changed in the final rule may be found in the proposed rule.

Several commenters recommended that base pressure should be defined as 14.696 pounds per square inch, absolute (psia), as opposed to defining it, as in the proposed rule, as the atmospheric pressure or the vapor pressure of the liquid at 60 °F, whichever is higher. Subsequent research has shown that base pressure should be defined as a fixed amount and therefore the BLM agrees with these comments. As a result, the definition of base pressure has been changed to 14.696 psia in the final rule.

Several commenters had concerns about the definition of Coriolis meter and Coriolis metering system (CMS). They suggested we replace the word “measures” in the definition of Coriolis meter with the word “infers.” The BLM agrees with this comment because the Coriolis meter does not actually measure volume directly as a positive displacement (PD) meter does, by isolating the flowing liquid into segments of known volume, but instead analyzes the interaction between the flowing fluid and the oscillation of the tubes. As a result, the definition of Coriolis has been changed to say that a Coriolis meter infers a mass flow rate. Another commenter said the definition of CMS should be changed to say the CMS reports “net standard oil volume” instead of “net oil volume,” while another commenter noted that the Coriolis meter displays “gross,” not “net” standard volumes. The BLM agrees with these suggestions because the Coriolis meter is capable of correcting to gross standard volume, but not capable of deducting the S&W content to derive net standard volumes. The definition has been changed in the final rule to “gross standard volume” as a result of this comment.

Another commenter requested that we include a definition in the rule for “vapor tight.” The proposed rule at § 3174.5(b)(3) required all oil storage tanks, hatches, connections, and other access points to be vapor tight. The BLM agrees that the term “vapor tight” should be defined and has defined the term to mean capable of holding pressure differential only slightly higher than that of installed pressure-relieving or vapor recovery devices.

A few commenters suggested that all of the definitions in the rule should come from the API standards, rather than be the BLM's own customized definitions. After comparing the API definitions against the BLM's definitions in the rule, the BLM does not agree with this suggestion. Not all API definitions fit the terms used in the rule. For example, one commenter said the BLM should use the API definition for LACT systems, which defines turbine meters as an example of a meter that can be part of a LACT system. The BLM disagrees with this comment because the rule does not allow turbine meters to be used at a FMP. The BLM has used many API definitions in the rule, but not all of them are suitable for this rule, therefore, this rule was not changed as a result of these comments.

Three commenters suggested that we include definitions for the acronyms “AO,” authorized officer; “PA,” participating area; and “CA,” communitization agreement. The definitions for the acronyms AO, PA, and CA are included in the definitions section of 43 CFR subpart 3170, which is in a related rulemaking previously discussed. As a result, no change was made to this rule as a result of these comments.

One commenter suggested that we not use the term “registered volume,” but rather the term “indicated volume.” The

BLM agrees that the term “indicated volume” is a more appropriate term for the definition and aligns with common industry language, and as a result has changed the definition in the rule to reflect the definition for indicated volume.

One commenter said the term “resistance thermal device” is not a common industry term and suggested we change it to “resistance thermal detector.” As a result of this comment and a review of comments and changes to other sections, the term and definition for “resistance thermal device” has been removed and replaced by the term “transducer.” Transducer has been defined to be an electronic device that converts a physical property—such as pressure, temperature, or electrical resistance—into an electrical output signal that varies proportionally with the magnitude of the physical property. This defines a broader spectrum of devices and can include a resistance thermal detector. This use of the term “transducer” aligns with common industry practice and better suits the BLM's objective of ensuring that there is sufficient flexibility built into the rule.

One commenter suggested that we change our definition of “turbulent flow” to include a reference to the common measure for determining the flow, which is by Reynolds number. Since the final rule does not contain the turbulent-flow requirements that appeared in the proposed rule at § 3174.8(b)(1), the BLM has removed this term from the definitions section.

Based on changes to other sections resulting in new terms being introduced, a definition for “dynamic meter factor” has been included as meaning a kinetic meter factor derived by linear interpolation or polynomial fit, used for conditions where a series of meter factors have been determined over a range of normal operating conditions. In the revised non-prescriptive structure of the final rule, the term “opaque oil” is no longer used, as such the definition has been removed.

Section 3174.2 General Requirements

Paragraphs (a) through (d) of § 3174.2 refer the reader to other sections in this rule and to 43 CFR subpart 3173, which is addressed in the rulemaking to replace Order 3. That rulemaking contains the requirements for oil storage tanks, on-lease oil measurement, commingling, and FMP numbers, respectively. All comments received on these paragraphs are addressed in the corresponding section discussions later in this preamble and in the preamble for 43 CFR subpart 3173.

Section 3174.2(e) specifies that all equipment used to measure the volume of oil for royalty purposes at an FMP installed after the effective date of this subpart must comply with the requirements of this subpart. The BLM received no comments on this requirement.

Section 3174.2(f) requires that measuring procedures and equipment used to measure oil for royalty purposes that are in use on the effective date of this rule, must comply with the requirements of this subpart on or before the date the operator is required to apply for an FMP number under 3173.12(e) of this part. Prior to that date, measuring procedures and equipment used to measure oil for royalty purposes, that is in use on the effective date of this rule, must continue to comply with the requirements of Onshore Oil and Gas Order No. 4, Measurement of oil, 54 FR 8086 (Feb 24, 1989), and any COAs and written orders applicable to that equipment.

The proposed rule would have required operators to bring existing equipment used at FMPs into compliance within 180 days after the effective date of the final rule. Many commenters said 180 days is not enough time to plan for and bring existing equipment into compliance. The BLM agrees, and in response, this final rule provides a phase-in period of 1 to 4 years after the rule's effective date to bring existing equipment into compliance.

The 1- to 4-year phase-in period is based on the time-frames established for operators to apply for their FMP numbers, which is provided for in 43 CFR 3173.12 and is addressed in a related rulemaking that is updating and replacing Order 3. This modified implementation timeframe in the final rule links compliance with the oil measurement requirement to an operator's production volumes, with lower-volume producers having more time to comply. Under this new approach, the highest 25 percent of the producing leases, CAs, or unit PAs are required to be in compliance the earliest—within 12 months of the effective date of this rule. All remaining leases, CAs, or unit PAs, based on volume thresholds, are staged out over the following 3 years.

Commenters' greatest concern with the 180-day deadline was that it was not enough time to generate new oil-storage-tank calibration tables that would have allowed them to measure volumes in
1/8
-inch increments, as required in § 3174.6 of the proposed rule.
11

That is no longer a concern, however, because the final rule does not require that volumes be measured in
1/8
-inch increments.

11
Order 4 requires
1/4
-inch gauging accuracy for tanks with a capacity of 1,000 bbl or less and requires strapping tables at
1/4
-inch increments. For tanks with a capacity greater than 1,000 bbl, Order 4 requires a
1/8
-inch gauging accuracy and strapping tables at
1/8
-inch increments.

In the proposed rule, the BLM proposed switching to the
1/8
-inch gauging accuracy for all tanks in order to meet one objective of the rule—to bring the oil measurement regulations up to current industry standards. However, API has two contradictory standards for manual gauging measurement accuracy on oil storage tanks—API 3.1A calls for
1/8
-inch gauging accuracy for all tanks, while API 18.1 calls for a
1/4
-inch gauging accuracy for tanks of 1,000 bbl or less. Based on this change in industry standards and its own experience, the BLM assumed that new calibration tables could be generated from existing tank strapping measurements. Commenters disagreed, saying operators would have to hire engineering companies to reanalyze some 40,000 sales tanks across the nation. They said numerous tanks would have to be physically re-measured, or re-strapped. Some commenters said that, due to budgeting, equipment, and weather constraints, it could take them a year to re-strap their tanks. Others said it could take months to do the job.

As discussed later in § 3174.6, the BLM has decided to retain the
1/4
-inch gauging accuracy requirement for oil tanks with a capacity of 1,000 bbl or less, which is the current requirement, eliminating the need for operators to re-strap their tanks. To implement these standards, the BLM plans to develop a liquids uncertainty calculator that will allow its inspectors to enforce oil tank measurement uncertainty requirements for operators who elect to use automatic and hybrid tank gauging systems. It will take the BLM about 2 years to develop the uncertainty calculator and verify that automated equipment meets the uncertainty standards. During this time, operators who use automatic and hybrid tank gauging systems will still have to meet the measurement performance requirements.

Some commenters argued that existing equipment used at FMPs should not have to meet any deadline for coming into compliance with this rule's requirement and should instead be exempted from complying entirely (that is, grandfathered).

For example, one commenter said the BLM should grandfather all existing

equipment, but require all new installations or installations that undergo repairs costing more than 50 percent of the cost of new equipment to meet the new standards. The BLM does not agree with this proposed change for several reasons. The rule's only equipment retrofit requirement is that all automatic temperature/gravity compensators be replaced with temperature averagers. Temperature averagers are relatively inexpensive, costing around $6,500 per device, and automatic temperature/gravity compensators are not used on very many LACT systems. The BLM estimates that over 80 percent of all LACTs on Federal and Indian leases already have temperature averagers installed. A second issue the BLM has with this proposed change is that it would require the BLM to monitor all maintenance activity and estimate costs of repairs on “grandfathered” equipment. Finally, the commenter did not explain or provide justification for how this proposed change would be preferable to the proposed rule.

Another commenter said, as an alternative to grandfathering, equipment serving low-volume and marginal FMPs should be exempted from the requirements. The BLM does not see a need for this exemption because low-volume or marginal wells will, in most cases, be measured by manual tank gauging. Since the tank-gauging requirements in this final rule have not changed relative to the requirements in Order 4, this change was unnecessary.

Another commenter disagreed with the proposed rule's prohibition of automatic temperature/gravity compensators. These compensators should be grandfathered, the commenter said, as long as an audit trail exists whereby the raw data is available and the final results from the compensators can be recreated from this data. The commenter further stated that systems that cannot provide such data should be grandfathered in the final rule. The BLM disagrees. The fact remains that automatic compensator systems alter the raw data before any audit trail is created. They automatically change a meter's totalizer readings, erasing the raw data that the BLM and the operator need to verify that the compensators are functioning correctly and that the totalizer reading is correct.

Another commenter said that if existing equipment is not grandfathered, operators may need to install new LACT units in order to comply, which in turn would require operators to re-pipe their wells. According to this commenter, this would result in undue surface disturbance, excessive expenses, strain on the labor force, and wells that are currently in secondary recovery or that do not produce large amounts of oil being plugged prematurely, leaving behind undeveloped and valuable resources. The BLM disagrees with this interpretation of the rule's requirements. The only equipment that would have to be replaced at an FMP under both the proposed and final rules is the automatic temperature/gravity compensator, which is only one component of a PD meter of a LACT unit. Operators must replace these devices with temperature averagers, which allow operators to collect and retain the raw data the BLM needs to verify results and confirm and preserve system functionality. Based on the BLM's experience, this replacement can occur without replacing the entire LACT system. Additionally, as explained elsewhere in this preamble, most existing LACT systems do not use automatic temperature/gravity compensators.

One commenter said the midstream sector (the pipeline companies and processing plants at or downstream of the meters) would suffer if the rule does not grandfather existing equipment. The commenter did not explain or specify any negative impacts on the midstream sector from the requirement that operators replace automatic temperature/gravity compensators on LACTs. The BLM is not aware of any negative impacts this would have on the midstream sector and the commenter did not provide any information on how the midstream sector will suffer from accurate, verifiable measurement on a lease, PA, or CA. As a result, the BLM does not agree with the commenter and no change has been made to the rule based on this comment.

Several commenters said properly operating equipment should be grandfathered, and, if it must be replaced, operators should be allowed to negotiate installation timeframes with local BLM field offices. The BLM believes that this recommendation would perpetuate the problem of program requirements being inconsistently applied from state to state or field office to field office and therefore did not change the rule as a result of these comments. One of the primary goals of this final rule is to provide some nationwide consistency as to the application of these requirements.

Another commenter said that existing facilities and equipment should be grandfathered because operators could not afford an “investment of this magnitude” to retrofit equipment to meet the new standards. The commenter did not provide any details regarding what is meant by an “investment of this magnitude.” The BLM disagrees with the implication that replacing automatic temperature/gravity compensators on a LACT is a significant investment. The cost to replace automatic temperature/gravity compensators on LACT systems with temperature averagers is relatively minor—approximately $6,500 per system. No change resulted from this comment.

The BLM does not believe that existing equipment should be grandfathered. For years, the GAO and industry have voiced concerns that the BLM's measurement regulations are outdated and make it harder for the BLM to have reasonable assurance that production is being accurately measured and verified. This rule aims to address these concerns at both new and existing facilities.

Section 3174.2(g) exempts meters that are used for allocation measurement as part of commingling approvals from complying with the requirements of this subpart. Commingling approvals will be governed under new requirements in 43 CFR 3173.14, which are addressed in the rulemaking that is updating and replacing Order 3. One commenter said that meters used for allocating production from wells in approved commingling arrangements or that are in the same unit, PA, or CA should be required to meet API standards for allocation measurement. The commenter did not state a reason for this suggestion. Since the BLM does not want to impose blanket allocation measurement requirements that may not be relevant to every situation, it did not adopt this suggestion. Instead, the final rule retains the AO's discretion to include those requirements as a condition of approval on a case-by-case basis.

Section 3174.3 Incorporation by Reference (IBR)

This section previously appeared as § 3174.4 in the proposed rule, but based on edits made to the final rule, this section and proposed § 3174.3 have been switched. All comments discussed below were submitted for the previously proposed § 3174.4.

This rule incorporates a number of industry standards and recommended practices, either in whole or in part, without republishing the standards in their entirety in the CFR, a practice known as IBR. These standards have been developed through a consensus process, facilitated by the API, with input from the oil and gas industry and Federal agencies with oil and gas operational oversight responsibilities. The BLM has reviewed these standards

and determined that they will achieve the intent of 43 CFR 3174.4 through 3174.13 of this rule. The legal effect of IBR is that the incorporated standards become regulatory requirements. With the approval of the Director of the Federal Register, this rule incorporates the current versions of the standards listed.

Some of the standards referenced in this section have been incorporated in their entirety. For other standards, the BLM incorporates only those sections that are relevant to the rule, meet the intent of § 3174.3 of the rule, and do not need further clarification.

The incorporation of industry standards follows the requirements found in 1 CFR part 51. The industry standards in this final rule are eligible for incorporation under 1 CFR 51.7 because, among other things, they will substantially reduce the volume of material published in the
Federal Register
; the standards are published, bound, numbered, and organized; and the standards incorporated are readily available to the general public through purchase from the standards organization or through inspection at any BLM office with oil and gas administrative responsibilities (1 CFR 51.7(a)(3) and (a)(4)). The language of incorporation in § 3174.3 meets the requirements of 1 CFR 51.9. Where appropriate, the BLM has incorporated by reference an industry standard governing a particular process and then imposed requirements that add to or modify the requirements imposed by that standard (
e.g.,
the BLM sets a specific value for a variable where the industry standard proposed a range of values or options).

All of the API materials that the BLM is incorporating by reference are available for inspection at the BLM, Division of Fluid Minerals; 20 M Street SE; Washington, DC 20003; 202-912-7162; and at all BLM offices with jurisdiction over oil and gas activities. The API materials are available for inspection and purchase at the API, 1220 L Street NW., Washington, DC 20005; telephone 202-682-8000; API also offers free, read-only access to some of the material at
http://publications.api.org.

The following describes the API standards that the BLM has incorporated by reference into this rule:

API Manual of Petroleum Measurement Standards (MPMS) Chapter 2—Tank Calibration, Section 2A, Measurement and Calibration of Upright Cylindrical Tanks by the Manual Tank Strapping Method; First Edition, February 1995; Reaffirmed February 2012 (“API 2.2A”). This standard describes the procedures for calibrating upright cylindrical tanks used for storing oil.

API MPMS Chapter 2—Tank Calibration, Section 2.2B, Calibration of Upright Cylindrical Tanks Using the Optical Reference Line Method; First Edition, March 1989; Reaffirmed January 2013 (“API 2.2B”). This standard describes measurement and calibration procedures for determining the diameters of upright welded cylindrical tanks, or vertical cylindrical tanks with a smooth surface and either floating or fixed roofs.

API MPMS Chapter 2—Tank Calibration, Section 2C, Calibration of Upright Cylindrical Tanks Using the Optical-triangulation Method; First Edition, January 2002; Reaffirmed May 2008 (“API 2.2C”). This standard describes a calibration procedure for applications to tanks above 26 feet in diameter with cylindrical courses that are substantially vertical.

API MPMS Chapter 3, Section 1A, Standard Practice for the Manual Gauging of Petroleum and Petroleum Products; Third Edition, August 2013 (“API 3.1A”). This standard describes the following: (a) The procedures for manually gauging the liquid level of petroleum and petroleum products in non-pressure fixed roof tanks; (b) Procedures for manually gauging the level of free water that may be found with the petroleum or petroleum products; (c) Methods used to verify the length of gauge tapes under field conditions and the influence of bob weights and temperature on the gauge tape length; and (d) Influences that may affect the position of gauging reference point (either the datum plate or the reference gauge point).

API MPMS Chapter 3—Tank Gauging, Section 1B, Standard Practice for Level Measurement of Liquid Hydrocarbons in Stationary Tanks by Automatic Tank Gauging; Second Edition, June 2001; Reaffirmed August 2011 (“API 3.1B”). This standard describes the level measurement of liquid hydrocarbons in stationary, above ground, atmospheric storage tanks using automatic tank gauges (ATG). This standard discusses automatic tank gauging in general, accuracy, installation, commissioning, calibration, and verification of ATG that measure either innage or ullage.

API MPMS Chapter 3—Tank Gauging, Section 6, Measurement of Liquid Hydrocarbons by Hybrid Tank Measurement Systems; First Edition, February 2001; Errata September 2005; Reaffirmed October 2011 (“API 3.6”). This standard describes the selection, installation, commissioning, calibration, and verification of Hybrid Tank Measurement Systems. This standard also provides a method of uncertainty analysis to enable users to select the correct components and configurations to address for the intended application.

API MPMS Chapter 4—Proving Systems, Section 1, Introduction; Third Edition, February 2005; Reaffirmed June 2014 (“API 4.1”). Section 1 is a general introduction to the subject of proving meters.

API MPMS Chapter 4—Proving Systems, Section 2, Displacement Provers; Third Edition, September 2003; Reaffirmed March 2011 (“API 4.2”). This standard outlines the essential elements of meter provers that do, and also do not, accumulate a minimum of 10,000 whole meter pulses between detector switches, and provides design and installation details for the types of displacement provers that are currently in use. The provers discussed in this chapter are designed for proving measurement devices under dynamic operating conditions with single-phase liquid hydrocarbons.

API MPMS Chapter 4, Section 5, Master-Meter Provers; Fourth Edition, June 2016 (“API 4.5”). This standard covers the use of displacement and Coriolis meters as master meters. The requirements in this standard are for single-phase liquid hydrocarbons.

API MPMS Chapter 4—Proving Systems, Section 6, Pulse Interpolation; Second Edition, May 1999; Errata April 2007; Reaffirmed October 2013 (“API 4.6”). This standard describes how the double-chronometry method of pulse interpolation, including system operating requirements and equipment testing, is applied to meter proving.

API MPMS Chapter 4, Section 8, Operation of Proving Systems; Second Edition September 2013 (“API 4.8”). This standard provides information for operating meter provers on single-phase liquid hydrocarbons.

API MPMS Chapter 4—Proving Systems, Section 9, Methods of Calibration for Displacement and Volumetric Tank Provers, Part 2, Determination of the Volume of Displacement and Tank Provers by the Waterdraw Method of Calibration; First Edition, December 2005; Reaffirmed July 2015 (“API 4.9.2”). This standard covers all of the procedures required to determine the field data necessary to calculate a Base Prover Volume of Displacement Provers by the Waterdraw Method of Calibration.

API MPMS Chapter 5—Metering, Section 6, Measurement of Liquid Hydrocarbons by Coriolis Meters; First Edition, October 2002; Reaffirmed November 2013 (“API 5.6”). This standard is applicable to custody-

transfer applications for liquid hydrocarbons. Topics covered are API standards used in the operation of Coriolis meters, proving and verification using volume-based methods, installation, operation, and maintenance.

API MPMS Chapter 6—Metering Assemblies, Section 1, Lease Automatic Custody Transfer (LACT) Systems; Second Edition, May 1991; Reaffirmed May 2012 (“API 6.1”). This standard describes the design, installation, calibration, and operation of a LACT system.

API MPMS Chapter 7, Temperature Determination; First Edition, June 2001; Reaffirmed February 2012 (“API 7”). This standard describes the methods, equipment, and procedures for determining the temperature of petroleum and petroleum products under both static and dynamic conditions.

API MPMS Chapter 7.3, Temperature Determination—Fixed Automatic Tank Temperature Systems, Second Edition, October 2011 (“API 7.3”). This standard describes the methods, equipment, and procedures for determining the temperature of petroleum and petroleum products under static conditions using automatic methods.

API MPMS Chapter 8, Section 1, Standard Practice for Manual Sampling of Petroleum and Petroleum Products; Fourth Edition, October 2013 (“API 8.1”). This standard covers procedures and equipment for manually obtaining samples of liquid petroleum and petroleum products from the sample point into the primary containers.

API MPMS Chapter 8, Section 2, Standard Practice for Automatic Sampling of Petroleum and Petroleum Products; Third Edition, October 2015 (“API 8.2”). This standard describes general procedures and equipment for automatically obtaining samples of liquid petroleum, petroleum products, and crude oils from a sample point into a primary container.

API MPMS Chapter 8—Sampling, Section 3, Standard Practice for Mixing and Handling of Liquid Samples of Petroleum and Petroleum Products; First Edition, October 1995; Errata March 1996; Reaffirmed, March 2010 (“API 8.3”). This standard covers the handling, mixing, and conditioning procedures required to ensure that a particular representative sample of the liquid petroleum or petroleum product is delivered from the primary sample container/receiver into the analytical test apparatus or into intermediate containers.

API MPMS Chapter 9, Section 1, Standard Test Method for Density, Relative Density, or API Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method; Third Edition, December 2012 (“API 9.1”). This standard covers the determination, using a glass hydrometer in conjunction with a series of calculations, of the density, relative density, or API gravity of crude petroleum, petroleum products, or mixtures of petroleum and nonpetroleum products normally handled as liquids and having a Reid vapor pressure of 101.325 kPa (14.696 psi) or less.

API MPMS Chapter 9, Section 2, Standard Test Method for Density or Relative Density of Light Hydrocarbons by Pressure Hydrometer; Third Edition, December 2012 (“API 9.2”), This standard covers the determination of the density or relative density of light hydrocarbons including liquefied petroleum gases having a Reid vapor pressure exceeding 101.325 kPa (14.696 psi).

API MPMS Chapter 9, Section 3, Standard Test Method for Density, Relative Density, and API Gravity of Crude Petroleum and Liquid Petroleum Products by Thermohydrometer Method; Third Edition, December 2012 (“API 9.3”). This standard covers the determination, using a glass thermohydrometer in conjunction with a series of calculations, of the density, relative density, or API gravity of crude petroleum, petroleum products, or mixtures of petroleum and nonpetroleum products normally handled as liquids and having a Reid vapor pressure of 101.325 kPa (14.696 psi) or less.

API MPMS Chapter 10 Section 4, Determination of Water and/or Sediment in Crude Oil by the Centrifuge Method (Field Procedure); Fourth Edition, October 2013; Errata March 2015 (“API 10.4”). This standard describes the field centrifuge method for determining both water and sediment, or sediment only, in crude oil.

API MPMS Chapter 11—Physical Properties Data, Section 1, Temperature and Pressure Volume Correction Factors for Generalized Crude Oils, Refined Products and Lubricating Oils; May 2004; Addendum 1, September 2007; Reaffirmed August 2013 (“API 11.1”). This standard provides the algorithm and implementation procedure for the correction of temperature and pressure effects on density and volume of liquid hydrocarbons that fall within the categories of crude oil.

API MPMS Chapter 12—Calculation of Petroleum Quantities, Section 2, Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 1, Introduction; Second Edition, May 1995; Reaffirmed March 2014 (“API 12.2.1”). This standard provides standardized calculation methods for the quantification of liquids and the determination of base prover volumes under defined conditions. The standard specifies the equations for computing correction factors, rules for rounding, calculational sequences, and discrimination levels to be employed in the calculations.

API MPMS Chapter 12—Calculation of Petroleum Quantities, Section 2, Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 2, Measurement Tickets; Third Edition, June 2003; Reaffirmed September 2010 (“API 12.2.2”). This standard provides standardized calculation methods for the quantification of liquids and specifies the equations for computing correction factors, rules for rounding, calculation sequences, and discrimination levels to be employed in the calculations.

API MPMS Chapter 12—Calculation of Petroleum Quantities, Section 2, Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 3, Proving Report; First Edition, October 1998; Reaffirmed March 2009 (“API 12.2.3”). This standard provides standardized calculation methods for the determination of meter factors under defined conditions. The criteria contained here will allow different entities using various computer languages on different computer hardware (or by manual calculations) to arrive at identical results using the same standardized input data. This document also specifies the equations for computing correction factors, including the calculation sequence, discrimination levels, and rules for rounding to be employed in the calculations.

API MPMS Chapter 12—Calculation of Petroleum Quantities, Section 2, Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 4, Calculation of Base Prover Volumes by the Waterdraw Method; First Edition, December, 1997; Reaffirmed March 2009; Errata July 2009 (“API 12.2.4”). This standard provides standardized calculation methods for the quantification of liquids and the determination of base prover volumes under defined conditions. The criteria contained in this document allow different individuals, using various computer languages on different computer hardware (or manual calculations), to arrive at identical results using the same standardized

input data. This standard specifies the equations for computing correction factors, rules for rounding, the sequence of the calculations, and the discrimination levels of all numbers to be used in these calculations.

API MPMS Chapter 13—Statistical Aspects of Measuring and Sampling, Section 1, Statistical Concepts and Procedures in Measurements; First Edition, June 1985; Reaffirmed February 2011, Errata July 2013 (“API 13.1”). This standard covers the basic concepts involved in estimating errors by statistical techniques and ensuring that results are quoted in the most meaningful way. This standard also discusses the statistical procedures that should be followed in estimating a true quantity from one or more measurements and in deriving the range of uncertainty of the results.

API MPMS Chapter 13, Section 3, Measurement Uncertainty; First Edition, May 2016 (“API 13.3”). This standard establishes a methodology for developing an uncertainty analysis.

API MPMS Chapter 14, Section 3/American Gas Association Report No. 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids—Concentric, Square-edged Orifice Meters, Part 1, Section 12, General Equations and Uncertainty Guidelines; Fourth Edition, September 2012; Errata July 2013 (“API 14.3”). This standard provides reference for engineering equations and uncertainty estimations.

API MPMS Chapter 18—Custody Transfer, Section 1, Measurement Procedures for Crude Oil Gathered From Small Tanks by Truck; Second Edition, April 1997; Reaffirmed February 2012 (“API 18.1”). This standard describes the procedures, organized into a recommended sequence of steps, for manually determining the quantity and quality of crude oil being transferred under field conditions.

API MPMS Chapter 18, Section 2, Custody Transfer of Crude Oil from Lease tanks Using Alternative Measurement Methods, First Edition, July 2016 (“API 18.2”). This standard defines the minimum equipment and methods used to determine the quantity and quality of oil being loaded from a lease tank to a truck trailer without requiring direct access to a lease tank gauge hatch.

API MPMS Chapter 21—Flow Measurement Using Electronic Metering Systems, Section 2, Electronic Liquid Volume Measurement Using Positive Displacement and Turbine Meters; First Edition, June 1998; Reaffirmed August 2011 (“API 21.2”). This standard provides for the effective utilization of electronic liquid measurement systems for custody-transfer measurement of liquid hydrocarbons.

API Recommended Practice (RP) 12R1, Setting, Maintenance, Inspection, Operation and Repair of Tanks in Production Service; Fifth Edition, August 1997; Reaffirmed April 2008 (“API RP 12R1”). This recommended practice is a guide on new tank installations and maintenance of existing tanks. Specific provisions of this recommended practice are identified as requirements in this final rule.

API RP 2556, Correction Gauge Tables for Incrustation; Second Edition, August 1993; Reaffirmed November 2013 (“API RP 2556”). This recommended practice provides for correcting gauge tables for incrustation applied to tank capacity tables. The tables given in this recommended practice show the percent of error of measurement caused by varying thicknesses of uniform incrustation in tanks of various sizes.

The BLM received numerous comments addressing the incorporation by reference documents. Several commenters were concerned that the BLM was not incorporating the most recent versions of API standards. The API standards are dynamic standards that are constantly being reviewed and updated. The commenters referred to standards that were updated and published either after the proposed rule published or during the BLM's final internal review process before publishing the proposed rule. The BLM generally agrees with the commenters that the latest editions of industry standards should be incorporated and has made the change here after reviewing the latest version of the standards to confirm they will satisfy the applicable requirements.

Several commenters said that some of the incorporated materials in the proposed rule were in conflict. For example, ASTM D1250-1980 version tables 5A and 6A for temperature and gravity correction factors and API 11.1 for the correction of temperature effects on density and volume provide differing correction factors that may result in different corrected oil volumes. The BLM agrees with these comments and has removed ASTM D1250-1980 tables 5A and 6A from the list of incorporated materials. The final rule now refers to API 11.1 for calculations of temperature and pressure effects on density and volume.

Several commenters expressed concern that the BLM will not be updating the incorporated industry standards as new versions are published. The BLM is aware of the need to continuously monitor the industry standards as they are revised and updated, and intends to draft guidance to ensure that the BLM's rules and the incorporated standards they reference are kept up-to-date as technology and practices change. Under the applicable IBR rules, however, the BLM cannot automatically incorporate updated versions of standards into BLM regulations. The rules require that BLM reference the specific version of any particular standard being incorporated. Recognizing that these standards are continually being updated, the BLM intends to undertake periodic rulemakings to make corresponding updates to the relevant regulations. In the interim, an operator could submit a request to the PMT for a variance to comply with a newer version of a standard in lieu of compliance with the version listed above.

Many commenters said the BLM should rewrite the rule to be less prescriptive, to primarily reference industry standards, and to include additional API standards that would expand industry options for achieving accurate measurement. They argued that a highly prescriptive rule would discourage industry from adopting new technology as it becomes available. Upon careful consideration of these comments, the BLM has decided to take a less prescriptive approach that will achieve the ultimate goal of accurate measurement, while still maintaining our requirements for an audit trail and production accountability, and that will provide reasonable versatility for operators. The rule has been modified to be less prescriptive than the proposed rule and includes more industry standards that operators may choose from to comply with the requirements of the final rule. For example, the tank gauging section at § 3174.6 has been rewritten to refer more to industry standards and less to step-by-step instructions and requirements. Proposed § 3174.6(b)(3) had a list of requirements for taking oil samples prior to the opening gauge and was geared towards manual tank gauging. Section 3174.6(b)(3) of the final rule instead requires operators to follow one of two industry standards for taking oil samples prior to the opening gauge—API 8.1 for manual sampling or API 8.2 for sampling by automatic sampling systems. This paves the way for operators to use hybrid tank measurement systems and any other new technology that may come along in the coming years. Where necessary, the rule enhances or modifies an industry standard to ensure that the BLM's audit trail and production accountability

requirements relate to lease activity and are met. For example, the rule modifies the industry standard for the tolerance on the verification for ATG systems, from ±
3/16
inch to ±
1/4
inch, in response to field test data that showed properly calibrated equipment has difficulty meeting the ±
3/16
inch tolerance specified in industry standards. Also industry standards call for monthly ATG systems verification. This rule instead requires that ATG systems be verified monthly or before sales, whichever is later. This change will help smaller producers that may have sales only once every 2 or 3 months.

Several commenters had the opposite view and said the BLM should not incorporate industry standards, but rather make its regulations predominantly prescriptive, explicitly stating what is allowed and required. Their reasoning for this approach was that API RPs are optional for industry to consider following, while industry must follow BLM regulations. The BLM disagrees with the commenter's description of how these rules will be applied. Under the final rule, operators are required to comply with industry standards or practices that are incorporated by reference. As discussed earlier, the BLM has decided to take a less prescriptive approach and, where possible, incorporate multiple industry standards to give operators a choice for achieving a particular measurement standard.

Several commenters said the BLM should incorporate forthcoming industry standards that have not yet been finalized into the rule. The BLM cannot incorporate a standard that an industry trade association has not yet published. An unpublished standard is subject to change. It is possible the trade association creating the standard could completely rewrite the draft standard after the BLM incorporated it into this rule, in ways that would compromise the BLM's ability to enforce audit-trail or production-accountability requirements. The BLM disagrees with these comments and has not incorporated any unpublished standards into the rule.

One commenter suggested the BLM not incorporate industry standards but rather copy industry standard language directly into the rule. Copyright restrictions prevent the BLM from taking this course of action. Also this approach makes it harder for the BLM to update these requirements in the future. The final rule was not revised as a result of this comment.

Another commenter said the BLM is statutorily prohibited from cherry-picking industry standards for inclusion in the rule—picking and choosing which standards to apply and which to ignore. The BLM disagrees with this comment. Some industry standards do not meet the rule's goals and objectives and have not been incorporated. For example, there are industry standards for turbine meters, but the BLM does not allow these meters to be used at an FMP because, in some situations, they do not meet the BLM's accuracy requirements.

Several commenters said that incorporating industry standards puts an unreasonable financial burden on industry because it forces industry to purchase the published standards from the trade groups that create them. The BLM agrees that the cost of purchasing a complete set of industry standards is not insignificant. However, the API provides the public free, read-only access to most of the standards incorporated in this final rule. In addition, all incorporated material is available for inspection at the BLM's Division of Fluid Minerals, 20 M Street SE., Washington, DC 20003, and at all BLM offices with jurisdiction over oil and gas activities. It is also available for inspection at the National Archives and Records Administration (NARA). Several commenters stated that the BLM has not made a good effort to provide these newly required standards for public review. The BLM disagrees with this comment. As stated earlier, all industry standards incorporated by reference are available for inspection at the BLM, Division of Fluid Minerals, and at all BLM offices with jurisdiction over oil and gas activities.

The commenter also said the documents are not available in the BLM's Washington Office or in any particular field office. The BLM disagrees. The documents are available for review in the BLM's Washington Office and in all local offices that have jurisdiction over oil and gas activities. It has come to the BLM's attention that some local office personnel may not be aware of how to access the incorporated standards and, as part of the implementation process for the final rule, the BLM plans to carry out a training program to ensure that field office staff can readily access the standards as needed.

Several commenters expressed concern about who is responsible for complying with the incorporated standards—operators or their contractors. The incorporated standards are regulatory requirements, and operators are responsible for ensuring that third parties that do not have a contractual relationship with the BLM comply with the incorporated industry standards. Existing BLM regulations at 43 CFR 3162.3 state that a contractor on a leasehold will be considered the agent of the operator for such operations with full responsibility for acting on behalf of the operator for purposes of complying with applicable laws, regulations, the lease terms, NTLs, Onshore Oil and Gas Orders, and other orders and instructions of the AO.

Several commenters said the industry standards as written are not enforceable by the BLM. The BLM disagrees. Many of the industry standards employ the terms “shall” and “should,” with “shall” denoting a minimum requirement necessary to conform to the specification, and “should” denoting a recommendation or that which is advised, though is not required, in order to conform to the specification. However, once the standards are incorporated into BLM regulations, operators must comply with them whether the standard uses the word “shall” or “should.” One commenter inquired whether operators will be required to follow a standard, and if any deviation from a standard is a violation. As stated previously, operators must comply with all incorporated standards and material, and any deviation without an approved variance is a violation.

Section 3174.4 Specific Measurement Performance Requirements

This section was previously published as § 3174.3. Based on edits made to the final rule, this section and previously published § 3174.4 have been switched. All discussion of comments here were submitted under the previous proposed § 3174.3.

Section 3174.4(a)(1) sets volume-based overall performance standards for measuring oil produced from Federal and Indian leases, regardless of the type of meters or measurement method used. The overall volume uncertainty performance goals apply to volumes reported on the OGOR Part B (Production Disposition), commonly referred to as an OGOR B. FMPs measuring greater than or equal to 30,000 bbl per month must achieve an overall measurement uncertainty within ±0.50 percent. FMPs measuring less than 30,000 bbl per month must achieve an overall measurement uncertainty within ±1.50 percent. Existing Order 4 has no explicit statement of performance standards. The BLM will apply the performance standards in this final rule to FMPs as part of the compliance process. The performance goals could result in operating limitations (such as a minimum flow rate through the meter); however, they could also allow flexibility for various operational functions (for example, the

range of error between the meter in the field and the meter prover between successive runs during a proving). To facilitate this process, the BLM is developing an oil uncertainty calculator similar to the BLM's gas uncertainty calculator currently in use. The uncertainty calculator will be an internal tool for BLM employees to use to verify uncertainty. Once it is developed, the uncertainty calculator will be available for the public to review and use. The methods for calculating uncertainty have been clarified in the final rule to be in accordance with statistical concepts described in API 13.1, the methodologies in API 13.3, the quadrature sum (square root of the sum of the squares) method described in API 14.3.1; Subsection 12.3, and other methods approved by the AO. Uncertainty indicates the risk of measurement error. The performance standards provide specific objective criteria against which the BLM could analyze operator requests to use new metering technology, measurement systems, and procedures not specifically addressed in the rule. The two-tiered uncertainty thresholds established in § 3174.4(a)(1) set the maximum allowable volume measurement uncertainty. The BLM believes that the measurement uncertainties established are reasonable, based on equipment capabilities, industry standard practices and procedures, and BLM field experience.

As noted, for FMPs measuring greater than or equal to 30,000 bbl per month, the maximum overall volume measurement uncertainty allowed is ±0.50 percent. The BLM has established the ±0.50 percent uncertainty limit based on uncertainty calculations and public comments received on the proposed rule, discussed below. The overall uncertainty calculation includes the effects of the meter accuracy; maximum allowable meter-factor drift between meter provings; the minimum standard for repeatability during a proving; the accuracy of the pressure and temperature transducers used to determine the correction for pressure on liquids (CPL) factors, and the correction for temperature on liquids (CTL) factors; and the uncertainty of the CPL and CTL calculations. The BLM chose the volume threshold of 30,000 bbl per month for this uncertainty level after determining that at this monthly volume, a one-percentage-point decrease in the expected over- or underpayment of royalties—from ±1.5 percent to ±0.5 percent—evaluated over a 5-year time frame, equals $150,000. This $150,000 amount reflects the cost to purchase a LACT system, based on price quotes from several distributors. In other words, requiring a LACT system, in terms of increased accuracy, will generate benefits that equal or exceed the cost of the new system. In making this calculation, the BLM assumed a 5-year crude oil price average of $67.58 per bbl,
12

and a royalty rate of 12.5 percent. FMPs with production volumes less than 30,000-bbl-per-month production volume do not generate sufficient volumes that the potential royalty risk justifies installing a LACT system with an expected 5-year lifespan. As a result, the maximum proposed overall measurement uncertainty for these FMPs is ±1.5 percent. The BLM believes based on available data and its experience that a ±1.5 percent threshold is reasonable and readily achievable by manual tank gauging. Based on the BLM's analysis and review of comments received, the BLM determined that the overall uncertainty of manual tank gauging ranges from ±0.6 percent to ±2.50 percent depending on the volume of oil removed from the tank at the time of sale. A ±0.6 percent uncertainty results from potential measurement error applied to large volumes, while a ±2.50 percent uncertainty results from the same potential measurement error applied to smaller volumes removed during one load-out. The ±1.5 percent uncertainty in the final rule reflects the high average calculated uncertainty for a typical truck load-out by tank gauging, which BLM believe is representative of onshore operations more generally, and therefore is an appropriate threshold to use in this rule.

12
Based on the projected nominal West Texas Intermediate crude oil spot price published in the U.S. Energy Information Administration's
2016 Annual Energy Outlook Reference case scenario.

The two-tiered uncertainty performance requirements in the final rule reflect modifications from the proposed rule, based on comments received. First, one commenter noted that the proposed rule did not give guidance on how the uncertainty was to be calculated. The BLM agrees with this comment and the final rule makes it clear that the uncertainty is to be calculated using API 13.1, Statistical Concepts and Procedures; API 13.3, the uncertainty methodologies; the quadrature sum method as described in API 14.3.1, Subsection 12.3, General Equations and Uncertainty Guidelines; or other methods approved by the AO.

Another commenter agreed that it is appropriate to permit a certain amount of measurement uncertainty and to utilize a tiered approach for uncertainty based on volume. However, the commenter disagreed with the proposed rule's three-tiered uncertainty requirement: ± 0.35 percent for FMPs measuring more than 10,000 bbl per month; ± 1 percent for FMPs measuring more than 100 bbl per month and less than or equal to 10,000 bbl per month; and ± 2.5 percent for FMPs measuring less than 100 bbl per month. The commenter said the proposed ± 2.5 percent uncertainty level for FMPs measuring volumes less than 100 bbl/month is both unnecessary and counterproductive. This commenter noted that there are a large number of older, low-volume wells operating on BLM and tribal leases, and argued that the ± 2.5 percent uncertainty for those operations could cause some low-volume operators to shut in their wells, resulting in a significant cumulative loss of Federal revenue from royalties. Commenters instead recommended that the BLM eliminate the lowest-volume category of the three uncertainty levels under proposed § 3174.3(a)(1). They further recommended that all FMPs with monthly volumes averaged over the previous 12 months that are less than 10,000 bbl/month should be subject to an uncertainty level of ± 1.0 percent. The commenters also said that this gives the BLM more discretion over when a less stringent uncertainty level for low-volume operators is appropriate based on site-specific factors.

The BLM partially agrees with these comments. After reanalyzing the uncertainty data and volume thresholds, the BLM has eliminated the lowest tier of uncertainty. However, this rule uses a 30,000 bbl per month volume as the dividing volume between the two tiers, and sets the uncertainty level for the highest-producing tier at ±0.50 percent and the uncertainty level for the lowest-producing tier at ±1.5 percent, which will be high enough for most tank-gauging operations while still ensuring the rules achieve accurate measurement.

The BLM chose the 30,000 bbl per month volume as the dividing line between the two tiers, and their respective uncertainty performance standards, based on what it would cost an operator to install and operate a LACT system, relative to the risk that the operator would under- or overpay royalties if measuring by tank gauging. The calculation for this assumes: A LACT system costs $150,000 and has a 5-year expected equipment lifespan, tank gauging results in a ±1.5 percent uncertainty, the 5-year oil price averages $67.58 per bbl, and the royalty rate is 12.5 percent. The following equation shows the calculation used to arrive at the 30,000 bbl per month volume

dividing line between the two tiers of uncertainty performance requirements:

Monthly volume = $150,000/((Uncertainty × Oil price × Royalty rate) × 60 months)

One commenter suggested that the performance standards for uncertainty should not be less than ±1.0 percent. A performance standard of less than ±1.0 percent is excessively onerous, the commenter said, and does not provide a substantial benefit compared to a ±1.0 percent standard. This commenter did not justify why a ±1.0 percent uncertainty standard is reasonable or how anything less is onerous. The BLM disagrees with this comment. The root square sum method of calculating the uncertainty of a LACT system with a PD meter configured and operated under the requirements of Order 4 calculates an overall uncertainty of ±0.32 percent. The final rule makes only minor changes to the Order 4 LACT requirements, so a calculated overall uncertainty rate under this rule will be similar to the existing requirements of Order 4. A LACT system with either a PD meter or a Coriolis meter is very capable of achieving the ±0.50 percent uncertainty when constructed and operated according to the requirements of this rule and corresponding API standards; no change was made as a result of this comment.

One commenter said BLM regulations do not need to specify equipment models that are acceptable for use in custody transfer measurement when uniform uncertainty metrics are utilized. The commenter stated that if any equipment meets the established uncertainty-performance standards for a measurement system, and that uncertainty can be validated and maintained, such equipment should then be allowed to be used for oil measurement. The BLM partly agrees with this comment, which is why this final rule establishes a procedure whereby the PMT can review and approve the use of new equipment and measurement methods, so long as the new equipment and methods meet the performance uncertainty and verifiability standards of the rule. The BLM believes that once this equipment has been proven to be capable of meeting the uncertainty performance and verifiability standards of this rule, then that equipment can be approved for use.

The second part of this comment suggests that the volume uncertainty limit of ±0.35 percent in the proposed rule for high-volume producers is excessively small (strict) for measurement installations that measure in excess of 10,000 bbl/month. The commenter further stated that the BLM failed to provide any basis for the proposed allowable volume uncertainty calculations. The proposed rule did not offer any detail as to how the uncertainty limit of ±0.35 percent includes any effects of maximum allowable meter-factor drift between meter proving, the minimum standard for repeatability during proving the accuracy of pressure and temperature transducers for volumetric correction, and the uncertainty in the volume-correction factor correction. The commenter also said the BLM did not disclose the data that it utilized to determine the ±1.0 percent uncertainty limit for FMPs in the 100 to 10,000 bbl/month range.

The BLM conducted an overall uncertainty calculation for a LACT utilizing a PD meter operated and proven under the requirements of Order 4. The results of this calculation provided an overall uncertainty of ±0.32 percent, which was what the BLM used to establish the higher standard in the proposed rule. The commenter did not provide a more appropriate uncertainty calculation to justify their claim that ±0.35 percent is excessively small for installations that measure in excess of 10,000 bbl per month. As a result no specific changes were made in response to this comment; however, as noted elsewhere in this section, the BLM has modified the uncertainty thresholds for larger-volume FMPs.

In order to identify appropriate thresholds, the BLM reviewed a proprietary third-party uncertainty calculation for tank gauging using Order 4 requirements for a 400 bbl tank. The results indicate that the overall uncertainty varies depending upon the volume removed from the tank. The overall uncertainty in the calculation varied from ±0.6 percent for large volumes removed to uncertainties of ±2.50 percent for very small volumes removed. The BLM reviewed overall uncertainty calculations in order to determine reasonable uncertainty requirement in the rule.

Several commenters said the BLM should re-evaluate its proposed measurement uncertainty (±0.35 percent), claiming the methodology appears to be flawed. They further stated the proposed oil measurement rule demands a level of accuracy that would not apply to heavy oil regimes and that would increase operating costs beyond what is necessary or of value. They suggest that operators with heavy oil operations may receive unwarranted and costly penalties at a greater rate than the rest of the petroleum industry, and that heavy oil producers would be disproportionately impacted by the proposed standard. These commenters did not submit justification for their claims, and when the BLM contacted them to clarify this comment, they still failed to justify or explain how heavy oil regimes would be disproportionately impacted by the rule. No change to the rule resulted from these comments.

One commenter requested that the ±0.35 percent performance uncertainty be adjusted to ±1.0 percent for meters measuring 10,000 barrels per day. The commenter agreed with comments that the API submitted to the BLM on the proposed rule and requests that the BLM use the Order 4 proving and uncertainty performance requirements for LACT systems. The BLM has re-analyzed the uncertainty performance requirements and volume thresholds, and, based on the re-evaluation and other comments received showing a different uncertainty calculation resulting in a slightly higher uncertainty than proposed, has changed the rule's uncertainty performance standards to encompass reasonable flexibility in evaluating alternative measurement equipment and methods and adjusted the volume thresholds to match volumes where the risk to royalty would equal the expense of installing a LACT or CMS to require a more accurate measurement.

Another commenter said the overall volume uncertainty limit of ±0.35 percent for measurement installations with throughputs greater than 10,000 bbl/month is unreasonably and excessively strict, given the potential number of sources of measurement error. The error should be calculated to include the uncertainty from all sources of error in the oil volumetric calculation chain. The BLM agrees in part with the comment that a ±0.35 percent uncertainty may be somewhat strict in some applications. The ±0.35 percent has been calculated to include all sources of error in the LACT measurement calculation chain, based on other comments providing similar calculations. The BLM has chosen to use a slightly higher uncertainty level in the final rule to give some leeway when considering approvals for future measurement technology and procedures for use on Federal and Indian leases. This commenter also suggested that systems installed at FMPs that measure less than 100 bbl/month should have the option to pay royalties as if they were producing at the rate of 100 bbl/month and avoid the cost of installing measurement equipment that could make their operations economically infeasible. The BLM

disagrees with the concept of paying royalties based on a fixed volume rather than royalties based on actual measurements. In addition, if the uncertainty standards would render a lease uneconomic, the operator can seek an exemption from the requirements under § 3174.4(a)(2). No change to the rule resulted from this comment.

One commenter said they were unable to verify the uncertainty levels proposed without the “calculator” that the BLM is developing. This commenter created its own uncertainty calculation using the following assumptions: A maximum allowable deviation for temperature of 0.25 °F and pressure of 0.25 psi. The uncertainty was calculated to be ±0.46 percent in this one instance.

The BLM appreciates receiving this comment as it provides useful input and actual calculation results to support the commenter's position. As a result of this comment and further analysis, the BLM agrees that this uncertainty calculation could reflect one possible application and has adjusted the rule's lower overall uncertainty performance requirements for the highest-producing tier to ±0.50 percent.

One commenter expressed concern that the cost of complying with this provision will increase as uncertainty standards are updated. However, there is nothing in this provision that provides for the updating of the uncertainty threshold standards.

Under § 3174.4(a)(2), only a BLM State Director, with the written concurrence of the PMT, prepared in coordination with the Deputy Director, can grant an exception to the prescribed uncertainty levels. Granting an exception requires a showing that meeting the required uncertainly levels would involve extraordinary cost or unacceptable adverse environmental effects. By having the State Directors make these decisions, with concurrence of the PMT (prepared in coordination with the Deputy Director), the BLM hopes to ensure that there is consistent application of the performance standards across the Bureau and that approvals for exceptions from the performance standards are granted in limited circumstances. In the proposed rule, the BLM had proposed to require concurrence from the Director; however, upon further review, the BLM modified the written concurrence requirement to require written concurrence from the PMT that has been prepared in coordination with the Deputy Director. The BLM feels this approach would be more appropriate given that the PMT will have the necessary technical expertise, while requiring coordination with the Deputy Director ensures such changes have the necessary national policy perspective.

The BLM received several comments on its approach to exceptions to the proposed rule's uncertainty limits. A few commenters requested that the BLM clarify and limit the criteria a BLM State Director can use to grant exceptions. The BLM does not believe additional clarification is necessary and the rule's description of potential extraordinary circumstance(s) that could result in an exception to the uncertainty levels is sufficient. The BLM cannot identify every situation or event that could warrant an exception. The intent of the rule is that an exception is not a normal occurrence, and to allow exceptions only in limited, special circumstances. No change to the rule resulted from this comment.

Similarly, another commenter urged the BLM to clarify the manner in which exceptions may be granted and to clearly define the term “extraordinary cost.” According to this commenter, a lack of clear guidance on these exceptions will result in unrealistic expectations from operators and inconsistent application by the BLM. Again, there could be numerous circumstances under which an exception could be warranted, and the BLM cannot accurately anticipate and address all of these in the rule. It will be up to the individual or entity applying for the exception to make the case to justify an exception. The process for granting exceptions is more likely to be consistent if decisions are left to State Directors, with written concurrence from the PMT (prepared in coordination with the Deputy Director). No change to the rule resulted from this comment.

One commenter questioned why, on the one hand, the proposed rule would have authorized BLM State Directors to grant exceptions to uncertainty standards for equipment at FMPs (with BLM Director concurrence) and on the other hand, the rule at § 3174.4(d) gives the PMT the authority to recommend and the BLM to decide whether proposed alternative equipment or measurement procedures meets or exceeds the uncertainty standards. The commenter questioned a process that will rely on the availability of the PMT and State Directors to review and evaluate requests for exceptions. The commenter said BLM technical experts are often overworked, and therefore the PMT approval process is likely to take a considerable amount of time and hinder operators' ability to effectively develop Federal oil and gas resources. The BLM agrees that its technical experts have a significant workload and face a number of competing demands. However, one reason for creating a BLM-wide PMT is to relieve field offices of having to review new technology, and to provide a consistent BLM-wide decision-making process. The BLM believes that this structure should minimize the amount of time it will take for the BLM to process requests for evaluation of new equipment, and to evaluate requests for exemptions from the uncertainty requirements. No change to the rule resulted from this comment.

Section 3174.4(b) establishes the degree of allowable bias in a measurement. Bias differs from uncertainty in that bias results in systematic measurement error, whereas uncertainty only indicates a risk of measurement error. While the BLM acknowledges that it is virtually impossible to remove all bias in measurement, the final rule requires that there be no statistically significant bias at any FMPs. When a measurement device is tested against a laboratory device or prover, there is often slight disagreement, or apparent bias, between the two. However, both the measurement device being tested and the laboratory device or prover have some inherent level of uncertainty. If the disagreement between the measurement device being tested and the laboratory device or prover is less than the uncertainty of the two devices combined, then it is not possible to distinguish apparent bias in the measurement device being tested from inherent uncertainty in the devices (sometimes referred to as “noise” in the data). Therefore, the BLM does not consider apparent bias that is less than the uncertainty of the two devices combined to be statistically significant for purposes of compliance with the final rule. However, if the shift in the mean value of a set of measurements away from the true value of what is being measured exceeds the “statistically combined uncertainty” of the devices, then the BLM requires that known shift to be corrected to as close to the actual value as possible.

The BLM received several comments concerning bias. The first commenter stated the rule does not give any guidance on how bias will be determined, or what the BLM considers to be statistically significant. In order for the bias restriction to be applied uniformly throughout the nation, the commenter asserted that the term needs to be defined in the regulation. The BLM agrees with this comment and has added a new definition for “bias” to 43 CFR subpart 3170, as part of the

rulemaking that is updating and replacing Order 3.

Another commenter noted that the BLM presented no data or calculations in the proposed rule to verify that bias issues will not exist under field conditions where many additional variables impact the statistical calculations. The commenter claimed that the rule essentially assumes that uncertainties that can be demonstrated in laboratory conditions can also be demonstrated in field conditions, which are not practical in a production scenario. The commenter asked that the BLM delete paragraph (b) from the final rule. The BLM does not agree with this comment. If a shift in the mean value of a set of measurements away from the true value of what is being measured, exceeds the statistically combined uncertainty of the devices, occurs, then the BLM requires that known shift to be corrected to as close to actual value as possible. An example of where this shift could be discovered is during a transducer verification that results in a reading that is outside of the device's stated uncertainty. This is different from uncertainty, where a potential for measurement error exists. No change to the rule resulted from this comment.

A third commenter recommended that the BLM clarify language in the preamble that discusses statistically significant bias. As noted above, the preamble quantifies statistically significant bias as being a number that is greater than the combined uncertainties of the laboratory device, or prover, and the measured device, or the “statistically combined uncertainty.” The BLM recognizes that there will always be some apparent bias resulting from the uncertainty of all devices. Bias is only considered significant when it exceeds the combined uncertainties of the devices involved. The BLM believes that the final rule accurately explains bias in terms of it being outside of the “statistically combined uncertainty” of the devices being used. No change to the rule resulted from this comment.

Section 3174.4(c) requires that all measurement equipment be subject to independent verification by the BLM that it is performing accurately and that all inputs, factors, and equations that are used to determine quantity or quality are valid. Order 4 already requires that the BLM be able to independently verify measurement methods, as well as bias, so these are not new requirements. The verifiability requirement in this section prohibits the use of measurement equipment that does not allow for independent verification. For example, if a new meter were to be developed that did not record the raw data used to derive a volume, that meter could not be used at an FMP because without the raw data the BLM would be unable to independently verify the volume. Similarly, if a meter were to be developed that used proprietary methods that precluded the ability to recalculate volumes, its use would also be prohibited.

The BLM received several comments about the verifiability requirements of this rule. One commenter seemed to suggest that the BLM did not take into account the use of automation and other measurement systems advances, such as the use of flow computers handling calculations. The comment further stated that in order to retain the raw data that the BLM needs to manually verify equipment accuracy, operators will be required to use computers that are less efficient and that require more data storage. The BLM agrees that the rule may require operators to acquire more data storage, but does not agree with the commenter that saving raw data for future verification will result in less efficient flow computers, or that it is unnecessary. The BLM manages Federal oil resources on behalf of the American taxpayer and has an affirmative obligation to ensure that the oil produced is accurately measured and accounted for. In order to satisfy those obligations it is critically important that an audit trail exists so that the BLM can verify the production data. As a result, the BLM will continue to manually verify calculations at FMPs. No change to the rule resulted from this comment.

Another commenter suggested any verifiability does not take into account the difference between live calculations at high frequencies versus averaged and accumulated data over time. The commenter also said that independent calculations should only have to fall within a statistically insignificant window. In order for independent calculations to be applied uniformly throughout the nation, they should to be defined in the regulations, the commenter said. The BLM partly agrees with this comment that calculations should be live calculations at high frequencies or calculations averaged and accumulated over time. The Inspection and Enforcement Handbook will address possible methods for the BLM to verify calculations at an FMP. No changes to the rule were made as a result of this comment, but the BLM will include guidance in the Inspection and Enforcement Handbook regarding whether calculations should be based on live calculations or averaged over time. Under the final rule, all volume calculations at an FMP must be verifiable.

One commenter asked whether the requirement that new equipment undergo independent verification will preclude new technology. The BLM does not intend to prevent or exclude new technology. In fact, this rule, by establishing performance standards, adopting industry standards, and standing up the PMT process, has been designed explicitly to provide flexibility for the BLM to adopt new technology and practices as they are developed. No changes were made in response to this comment.

Another commenter said that paragraph (c) would require the BLM to contract with an independent laboratory to verify equipment, which could take 6 months per device and cost upwards of “$500M” for each device. The BLM disagrees with this comment because § 3174.4(c) merely requires operators to have FMP equipment that can produce the source records that provide the data and equations the BLM needs to independently recalculate oil production volume and quality during production audits. No changes were made in response to this comment.

Section 3174.4(d) clarifies that the operator can propose the use of alternative equipment, provided that it meets or exceeds the uncertainty requirements of this section. The PMT will make a determination under § 3174.13 of this subpart regarding whether proposed alternative equipment or measurement procedures meets or exceeds the objectives and intent of this section. See § 3174.13 for discussion of comments concerning the PMT and the PMT review process.

Section 3174.5 Oil Measurement by Tank Gauging—General Requirements

Section 3174.5(a) specifies the general requirements for oil measurement by tank gauging as a means to accurately determine the quantity and quality of oil removed from an FMP. The BLM received many comments on this section of the proposed rule. Almost all of these comments requested that the BLM consider permitting the use of ATG systems for custody transfer applications. Order 4 allows only manual tank gauging. In the proposed rule, the BLM indicated that it was considering including provisions in the final rule allowing for the use of ATG systems, and requested data regarding whether these systems can meet the BLM's performance standards for manual tank gauging with respect to uncertainty and verifiability. The BLM requested additional data regarding ATG measurement systems because it recognizes the significant safety advantages they provide.

The majority of the commenters indicated that ATG systems are much safer for workers when compared to manual tank gauging systems, especially when workers are measuring hydrocarbon fluids such as those found in the Bakken, which have higher gravity and higher vapor pressure, and thus emit higher volumes of toxic fumes. The BLM agrees that safety concerns associated with manual tank gauging can be reduced if operators have the option of using ATG systems as well as the other measurement methods addressed in this final rule. Based on data provided in response to the proposed rule—both as public comment on the proposed rule and in support of project-specific variance requests to use ATG systems on tanks—the BLM has determined that ATG systems can meet or exceed the uncertainty thresholds for tank gauging. As a result, the rule has been changed to allow for the use of ATG systems.

The BLM received one comment that recommended the BLM prohibit the practice of oil measurement by manual tank gauging because, according to the commenter, the practice is an antiquated and considerably less reliable method of measurement. The BLM disagrees that properly conducted manual tank gauging operations are antiquated or less reliable than other methods of measurement and will continue to give operators the option of using this widely accepted practice for oil measurement, which is generally used at lower-volume facilities. However, the BLM hopes for a shift towards ATG in areas where the nature of the produced oil presents a safety concern.

In the proposed rule, § 3174.5(b) required that all oil storage tanks, hatches, connections, and other access points be vapor tight and that each oil storage tank, unless connected to a vapor recovery system, must have a pressure-vacuum relief valve installed at the highest point in the vent line or connection with another tank. Pressure-vacuum relief valves would provide for normal inflow and outflow venting at an outlet pressure that is less than the thief hatch exhaust pressure and at an inlet pressure that is greater than the thief hatch vacuum setting. The intent is to minimize hydrocarbon gas lost to the atmosphere by ensuring that venting is done under controlled conditions through the pressure-vacuum relief valve primarily in response to changes in ambient temperature. The requirement that all access points be vapor tight has been expressly included in this rule in order to eliminate confusion over the intent of Order 4, which specified all the same equipment, but did not specify the manner in which it was supposed to be operated. The implied intent of Order 4 was always that the tanks be operated such that they are vapor tight.

The BLM received numerous comments on this section, the majority of which said the proposed requirements could conflict with U.S. Environmental Protection Agency (EPA) air quality regulations and the BLM's separately proposed Methane and Waste Prevention Rule (81 FR 6616). Some of the same commenters also complained about the potential costs associated with retrofitting some of the tank batteries. The BLM disagrees with these comments. The intent of the requirement is to conserve the quantity and quality of the liquid hydrocarbons in storage by controlling the storage conditions, not to create a potential conflict with the EPA's regulations for release of harmful pollutants. The BLM also disagrees with claims made by some commenters that the potential costs associated with retrofitting existing tank batteries to make them vapor-tight would be too high. Pressure vacuum vent line valves and thief hatches are already required equipment for the existing tank battery installations under Order 4. Paragraphs (b)(3) and (4) of the proposed rule have been changed and merged into a new paragraph (b)(3) in the final rule, which now requires that all oil storage tanks be vapor tight, and, unless connected to a vapor recovery or flare system, must have a pressure-vacuum relief valve installed at the highest point in the vent line or connection with another tank. All hatches, connections, and other access points must be installed and maintained in accordance with manufacturers' specifications.

Several commenters recommended that the BLM add the requirement that oil storage tank hatches (“thief hatches” or other access points) have pressure indicators that provide a clear and immediate visual indicator of tank pressures and potential gas/vapor release hazard should the tank need to be accessed. One of the commenters said pressure indicators on tank access hatches visually display the presence of gas/vapor pressure in a tank, allowing a trained worker to make risk-based decisions before accessing a tank, including actuating a remote venting valve, venting gas to a flare, or using appropriate respiratory protection, such as a self-contained breathing apparatus or an air-line respirator. The BLM recognizes that having such information could potentially be useful to personnel in the field; however, the BLM did not make any changes in response to this comment because the pressure indicators proposed by the commenter would have no bearing on determining measured volume, and therefore are outside the scope of this rule. It should also be noted that in general the Occupational Safety and Health Administration takes the lead on adopting and enforcing employee safety requirements.

Several commenters stated it is imperative that tanks be maintained vapor tight and that there be a monitoring or inspection program to ensure compliance. The BLM agrees and the final rule has maintained the vapor tight integrity requirement for oil storage tanks. The BLM's inspection and enforcement program will continue to ensure compliance with this and all other oil and gas regulations. No additional changes were made to the final rule as a result of these comments.

One commenter stated that if the oil is weathered or stabilized, there is no need for hatches and other connections to be vapor tight. The commenter did not explain how weathered or stabilized oil could negate the need for hatches and other connections to be vapor tight. The BLM disagrees that stabilized product does not require a vapor-tight storage condition. The vapor tight integrity is an implied requirement of the current Order 4 and therefore will not require the operator to retrofit any existing equipment. In a unique situation where a variance could be justified, the operator could seek a variance through the appropriate BLM field office following the process outlined in § 3170.6 of this part, a related rulemaking that is replacing Order 3, with approval by the AO. No additional changes were

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Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3A2016-25405. Public record. Not legal advice.