Waste Prevention, Production Subject to Royalties, and Resource Conservation, 6615-6686 [2016-01865]
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Vol. 81
Monday,
No. 25
February 8, 2016
Part II
Department of the Interior
asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Bureau of Land Management
43 CFR Parts 3100, 3160, and 3170
Waste Prevention, Production Subject to Royalties, and Resource
Conservation; Proposed Rule
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Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules
DEPARTMENT OF THE INTERIOR
Bureau of Land Management
43 CFR Parts 3100, 3160, and 3170
[15X.LLWO300000.L13100000.NB0000]
RIN 1004–AE14
Waste Prevention, Production Subject
to Royalties, and Resource
Conservation
Bureau of Land Management,
Interior.
ACTION: Proposed rule.
AGENCY:
The Bureau of Land
Management (BLM) is proposing new
regulations to reduce waste of natural
gas from venting, flaring, and leaks
during oil and natural gas production
activities on onshore Federal and Indian
leases. The regulations would also
clarify when produced gas lost through
venting, flaring, or leaks is subject to
royalties, and when oil and gas
production used on site would be
royalty-free. These proposed regulations
would be codified at new 43 CFR
subparts 3178 and 3179. They would
replace the existing provisions related to
venting, flaring, and royalty-free use of
gas contained in the 1979 Notice to
Lessees and Operators of Onshore
Federal and Indian Oil and Gas Leases,
Royalty or Compensation for Oil and
Gas Lost (NTL–4A), which are over 3
decades old.
DATES: Send your comments on this
proposed rule to the BLM on or before
April 8, 2016. The BLM is not obligated
to consider any comments received after
this date in making its decision on the
final rule.
As explained later, the proposed rule
would establish new information
collection requirements that must be
approved by the Office of Management
and Budget (OMB). If you wish to
comment on the information collection
requirements in this proposed rule,
please note that the OMB is required to
make a decision concerning the
collection of information contained in
this proposed rule between 30 and 60
days after publication of this document
in the Federal Register. Therefore, a
comment to the OMB on the proposed
information collection requirements is
best assured of having its full effect if
the OMB receives it by March 9, 2016.
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–AE14. Personal or
messenger delivery: 20 M Street SE.,
Room 2134LM, Washington, DC 20003.
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SUMMARY:
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Federal eRulemaking Portal: https://
www.regulations.gov. Follow the
instructions at this Web site.
Comments on the information
collection burdens: Fax: Office of
Management and Budget (OMB), Office
of Information and Regulatory Affairs,
Desk Officer for the Department of the
Interior, fax 202–395–5806. Electronic
mail: OIRA_Submission@omb.eop.gov.
Please indicate ‘‘Attention: OMB
Control Number 1004–XXXX,’’
regardless of the method used to submit
comments on the information collection
burdens. If you submit comments on the
information collection burdens, you
should provide the BLM with a copy, at
one of the addresses shown earlier in
this section, so that we can summarize
all written comments and address them
in the final rule preamble.
FOR FURTHER INFORMATION CONTACT: Eric
Jones at the BLM Moab Field Office, 82
East Dogwood Ave., Moab, UT 84532, or
by telephone at 435–259–2117; or
Timothy Spisak at the BLM Washington
Office, 20 M Street SE., Room 2134LM,
Washington, DC 20003, or by telephone
at 202–912–7311. For questions relating
to regulatory process issues, contact
Faith Bremner at 202–912–7441.
Persons who use a
telecommunications device for the deaf
(TDD) may call the Federal Information
Relay Service (FIRS) at 1–800–877–8339
to contact these individuals during
normal business hours. FIRS is available
24 hours a day, 7 days a week to leave
a message or question with these
individuals. You will receive a reply
during normal business hours.
SUPPLEMENTARY INFORMATION:
I. Executive Summary
A. Background
This proposed regulation aims to
reduce the waste of natural gas from
mineral leases administered by the
BLM. This gas is lost during oil and gas
production activities through flaring or
venting of the gas, and equipment leaks.
While oil and gas production
technology has advanced dramatically
in recent years, the BLM’s requirements
to minimize waste of gas have not been
updated in over 30 years. The Mineral
Leasing Act of 1920 (MLA) requires the
BLM to ensure that lessees ‘‘use all
reasonable precautions to prevent waste
of oil or gas developed in the
land . . . .’’ 30 U.S.C. 225. The BLM
believes there are economical, costeffective, and reasonable measures that
operators should take to minimize
waste, which will enhance our nation’s
natural gas supplies, boost royalty
receipts for American taxpayers, tribes,
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and States, and reduce environmental
damage from venting and flaring.
The BLM’s onshore oil and gas
management program is a major
contributor to our nation’s oil and gas
production. The BLM manages more
than 245 million acres of land and 700
million acres of subsurface estate,
making up nearly a third of the nation’s
mineral estate. Domestic production
from over 100,000 Federal onshore oil
and gas wells accounts for 11 percent of
the Nation’s natural gas supply and 5
percent of its oil. In Fiscal Year (FY)
2014, operators produced 204.6 million
barrels (bbl) of oil, 2 trillion cubic feet
(Tcf) of natural gas, and 3.1 billion
gallons of natural gas liquids (NGLs)
from onshore Federal and Indian oil and
gas leases. The production value of this
oil and gas exceeded $27.2 billion and
generated approximately $3.1 billion in
royalties.1
Over the past decade, the United
States has experienced a dramatic
increase in oil and natural gas
production due to technological
advances, such as hydraulic fracturing
combined with directional and/or
horizontal drilling. This boost in
production has brought many benefits
in the form of expanded and more
secure domestic oil and gas supplies,
lower oil and gas prices, increased
economic activity, and greater royalty
revenues for Federal, State and tribal
governments. At the same time, the
American public has not benefited from
the full potential of this increased
production, due to the flaring, venting,
and leakage of significant quantities of
gas during the production process.
According to data reported to the Office
of Natural Resources Revenue (ONRR),
Federal and Indian onshore lessees and
operators lost 375 billion cubic feet (Bcf)
of natural gas between 2009 and 2014—
enough gas to serve about 5.1 million
households for a year, assuming 2009
usage levels.2
Flaring, venting, and leaks waste a
valuable resource that could be put to
productive use, and deprive American
taxpayers, tribes, and States of royalty
revenues. In addition, the wasted gas
may harm local communities and
1 Office of Natural Resources Revenue (ONRR),
Statistical Information, https://statistics.onrr.gov/
ReportTool.aspx using Sales Year—FY2014—
Federal Onshore—All States Sales Value and
Revenue for Oil, NGL, and Gas products as of
December 2, 2015.
2 The Energy Information Administration (EIA),
Trends in U.S. Residential Natural Gas
Consumption, https://www.eia.gov/pub/oil_gas/
natural_gas/feature_articles/2010/ngtren
dsresidcon/ngtrendsresidcon.pdf (reporting that in
2009, U.S. residential consumption was
approximately 74 Mcf per household with natural
gas service).
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surrounding areas through visual and
noise impacts from flaring, and regional
and global air pollution problems of
smog, particulate matter, toxic air
pollution (such as benzene, a
carcinogen) and climate change. The
primary constituent of natural gas is
methane, and increases in gas wasted
through venting, flaring or leaks
contribute to increases in atmospheric
methane levels. Methane is an
especially powerful greenhouse gas
(GHG), with climate impacts roughly 25
times those of CO2, if measured over a
100-year period, or 86 times those of
CO2, if measured over a 20-year period.3
Thus, measures to conserve gas and
avoid waste may significantly benefit
local communities, public health, and
the environment.
The BLM oversees oil and gas
activities under the authority of a
variety of laws, including the MLA, the
Mineral Leasing Act for Acquired Lands
of 1947 (MLAAL), the Federal Oil and
Gas Royalty Management Act
(FOGRMA), the Federal Land Policy and
Management Act of 1976 (FLPMA), the
Indian Mineral Leasing Act of 1938
(IMLA), the Indian Mineral
Development Act of 1982 (IMDA), and
the Act of March 3, 1909.4 In particular,
the MLA requires the BLM to ensure
that lessees ‘‘use all reasonable
precautions to prevent waste of oil or
gas developed in the land . . . .’’ 5 This
proposal would replace current
requirements related to flaring, venting,
and royalty-free use of production,
which are contained in NTL–4A; amend
the BLM’s oil and gas regulations at 43
CFR part 3160; and add new subparts
3178 and 3179. It would apply to all
Federal and Indian (other than Osage
Tribe) onshore oil and gas leases as well
as leases and business agreements
entered into by tribes (including IMDA
agreements), as consistent with those
agreements and with principles of
Federal Indian law.6
3 See Intergovernmental Panel on Climate Change,
Climate Change 2013: The Physical Science Basis,
Chapter 8, Anthropogenic and Natural Radiative
Forcing, at 714 (Table 8.7), available at https://
www.ipcc.ch/pdf/assessment-report/ar5/wg1/
WG1AR5_Chapter08_FINAL.pdf.
4 Mineral Leasing Act, 30 U.S.C. 188–287;
Mineral Leasing Act for Acquired Lands, 30 U.S.C.
351–360; Federal Oil and Gas Royalty Management
Act, 30 U.S.C. 1701–1758; Federal Land Policy and
Management Act of 1976, 43 U.S.C. 1701–1785;
Indian Mineral Leasing Act of 1938, 25 U.S.C.
396a–g; Indian Mineral Development Act of 1982,
25 U.S.C. 2101–2108; Act of March 3, 1909, 25
U.S.C. 396.
5 30 U.S.C. 225.
6 Key statutes underpinning this proposed
regulation contain exceptions for the Osage Tribe.
Specifically, the Osage Tribe is excepted from the
application of both the Indian Mineral Leasing Act
and the Federal Oil and Gas Royalty Management
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Several oversight reviews, including
reviews by the Inspector General of the
Department of the Interior and the
Government Accountability Office
(GAO), have raised concerns about
waste of gas, found that the BLM’s
existing requirements regarding venting
and flaring are insufficient, expressed
concerns about the ‘‘lack of price
flexibility in royalty rates,’’ 7 and
identified concerns about royalty-free
use of gas. These reports recommended
that the BLM update its regulations to
address waste prevention, afford
flexibility in rate setting, and clarify
policies regarding royalty-free, on-site
use of oil and gas. With respect to waste,
the GAO found that ‘‘around 40 percent
of natural gas estimated to be vented
and flared on onshore Federal leases
could be economically captured with
currently available control
technologies.’’ 8 The GAO recommended
that the BLM reduce venting and flaring
of gas by revising its regulations ‘‘to
make it clear that technologies should
be used where they can economically
capture sources of vented and flared gas,
including gas from liquid unloading,
well completions, pneumatic valves,
and glycol dehydrators.’’ 9 The GAO
further recommended that the BLM
consider expanded use of infrared
cameras to identify opportunities to
minimize lost gas.10
This proposed rule would align the
BLM’s royalty rate for new competitive
Federal oil and gas leases with the
regime envisioned by the MLA, which
specifies ‘‘a rate of not less than 12.5
percent in amount or value of the
production removed or sold from the
lease.’’ 11 In addition, the proposed rule
would update the BLM’s existing NTL–
4A requirements related to venting,
flaring, and royalty-free use of natural
gas from onshore Federal and Indian
leases. Under NTL–4A, operators must
apply to the BLM on a case-by-case
basis for approval to flare royalty-free,
based on economic criteria. We propose
to reduce the need for case-by-case
applications by clarifying when flared
Act, 25 U.S.C. 396f; 43 U.S.C. 1702(3), 1702(4). The
leasing of Osage Reservation lands for oil and gas
mining is subject to special Bureau of Indian Affairs
regulations contained in 43 CFR part 226.
7 GAO, Oil and Gas Royalties: The Federal System
for Collecting Oil and Gas Revenues Needs
Comprehensive Reassessment, GAO–08–691,
September 2008, 6.
8 GAO, Federal Oil and Gas Leases: Opportunities
Exist to Capture Vented and Flared Natural Gas,
Which Would Increase Royalty Payments and
Reduce Greenhouse Gases, GAO–11–34, (Oct.
2010), 2.
9 Ibid. at 34.
10 Ibid. at 34.
11 30 U.S.C. 226(b)(1)(A) (emphasis added); see
also 30 U.S.C. 352 (applying the MLA’s leasing
provisions to leases on acquired land).
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or vented natural gas is subject to
royalties. Further, with respect to
venting and flaring of natural gas, we
propose to: Prohibit venting, except in
certain limited circumstances; limit the
rate of routine flaring at development oil
wells; 12 require operators to detect and
repair leaks; and mandate reductions in
venting from: Pneumatic controllers and
pneumatic pumps that operate by
releasing natural gas; storage vessels;
activities to unload liquids from a well;
and well drilling, completion, and
testing activities. Finally, the proposed
rule would require operators to submit
gas capture plans with their
Applications for Permits to Drill new
wells.
The BLM has engaged in substantial
stakeholder outreach in the course of
developing this proposal. In 2014, the
BLM conducted a series of forums to
consult with tribal governments and
solicit stakeholder views to inform the
development of this proposed rule, with
public meetings (some of which were
livestreamed) in Colorado, New Mexico,
North Dakota, and Washington, DC. 13
For each forum, we held a tribal
outreach session in the morning and a
public outreach session in the
afternoon. We also accepted informal
comments generated as a result of the
public/tribal outreach sessions. Since
those meetings, we have continued to
consult with stakeholders throughout
the rule development process, including
numerous meetings and calls with State
representatives, individual companies,
trade associations, and nongovernmental organizations (NGOs). We
have also received and considered many
reports, peer-reviewed studies, and
letters from stakeholders providing
information and views on what the BLM
should propose.
The BLM conducted additional
outreach with States where there is
extensive oil and gas production from
BLM-administered leases. We have
carefully reviewed State regulations and
guidance and consulted with State
regulatory bodies that oversee aspects of
oil and gas production to discuss their
requirements and practices. The BLM
intends to continue close interaction
with State and tribal regulators.
The BLM is not the only entity to
recognize the need to reduce flaring and
12 ‘‘Development oil well’’ or ‘‘development gas
well’’ means a well drilled to produce oil or gas,
respectively, from an established field in which
hydrocarbons have been discovered and from
which they are being produced at a profit or
expected profit.
13 Further information can be found at the BLM
oil and gas program’s outreach-events page:
https://www.blm.gov/wo/st/en/prog/energy/public_
events_on_oil.html.
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venting from oil and gas production
activities. Domestically, the
Environmental Protection Agency (EPA)
and a few individual States have been
active in this area, as have some oil and
gas producers. In 2012, for example, the
EPA adopted Clean Air Act new source
performance standards (NSPS) for
certain activities in the oil and gas
production sector. These regulations
target reductions of volatile organic
compounds (VOCs) and have the effect
of reducing venting and leaks. The EPA
recently proposed regulations to amend
the 2012 NSPS for the oil and natural
gas source category by setting standards
for both methane and VOCs for certain
equipment, processes and activities
across this source category (40 CFR part
60 subpart OOOOa rulemaking).14 This
EPA proposal would have the effect of
further reducing gas losses through
venting and leaks.
In addition, several States with BLMadministered lands and mineral
interests have acted in this area.
Colorado has adopted comprehensive
statewide regulations to limit emissions
of VOCs from venting and leaks from oil
and gas production activities.15 The
Colorado regulations require operators
to implement leak detection and repair
(LDAR) programs, replace high-bleed
pneumatic controllers with low-bleed
pneumatic controllers, and control
emissions from storage vessels, among
other things. Wyoming has adopted
similar comprehensive regulations that
apply in the Upper Green River Basin,
a ‘‘nonattainment area’’ where air
quality does not meet national ozone
standards adopted by the EPA under the
Clean Air Act.16 North Dakota has also
adopted an innovative program to phase
down flaring by operators across the
State, requiring 91 percent gas capture
by 2020.17 Pennsylvania has issued
guidance that exempts oil and gas
facilities from certain air quality
permitting requirements if they
implement changes to reduce gas loss,
such as developing an LDAR program,
14 EPA, Oil and Natural Gas Sector: Emission
Standards for New and Modified Sources, Proposed
Rule, 80 FR 56593 (Sept. 18, 2015). For further
information about EPA’s existing and proposed
NSPS standards for this source category, see Section
IV.I.3 of this preamble below.
15 Colorado Air Quality Control Commission
Regulations, Regulation 7, 5 CCR 1001–9, Sections
XII, XVII, XVIII, available at https://
www.colorado.gov/pacific/sites/default/files/5-CCR1001-9_0.pdf.
16 Wyoming, Nonattainment Area Regulations Ch.
8 (June 2015), available at https://soswy.state.wy.us/
Rules/RULES/9868.pdf.
17 North Dakota Industrial Commission Order
24665 Policy Guidance Version 102215, available at
https://www.dmr.nd.gov/oilgas/GuidancePolicy
NorthDakotaIndustrialCommissionorder24665.pdf.
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reducing VOC emissions from storage
vessels, and limiting flaring activity.18
The oil and gas industry has also
taken voluntary actions to reduce flaring
and venting. Many of these efforts have
been initiated by companies
participating in Natural Gas STAR, a
voluntary EPA-industry partnership
program that encourages oil and natural
gas companies to adopt cost-effective
technologies and practices that improve
operational efficiency and reduce
methane emissions. Twenty-six
companies in the production sector
currently participate in Natural Gas
STAR, and they reported that they
achieved about 50 Bcf of methane
emissions reductions in 2013.19 To
further encourage emissions reductions
from the oil and gas sector, the EPA
announced, in July 2015, a voluntary
program called the Natural Gas STAR
Methane Challenge, in which
companies would make ambitious
commitments to reduce methane
emissions and would track their
progress in achieving those
reductions.20 In addition, six oil and gas
companies have joined together to form
the One Future Coalition, which aims to
‘‘(e)nhance the energy delivery
efficiency of the natural gas supply
chain by limiting energy waste and by
achieving a methane ‘leak/loss rate’ of
no more than one percent.’’ 21
Given these activities, it is important
to ensure that updated BLM
requirements do not subject operators to
conflicting or redundant requirements.
Thus, in addition to our outreach to
States, we are coordinating closely with
the EPA as it works to finalize its 40
CFR part 60 subpart OOOOa
rulemaking.
The ongoing EPA and State regulatory
activities do not, however, obviate the
need for the BLM, in its role as a public
land manager, to update its
18 Pennsylvania Department of Environmental
Protection, Air Quality Permit Exemptions (Aug. 10,
2013), available at https://www.elibrary
.dep.state.pa.us/dsweb/Get/Document-96215/2752101-003.pdf, at 8–11.
19 EPA Natural Gas STAR Accomplishments,
available at https://www3.epa.gov/gasstar/
accomplishments/.
20 EPA Natural Gas Star Methane Challenge,
Program Proposal, available at https://
www3.epa.gov/gasstar/methanechallenge/
index.html.
21 Maria Galluci, Six Major Oil & Gas Firms Agree
To Cut Potent Methane Emissions Ahead Of UN
Climate Change Summit, International Business
Times, Sept. 23, 2014, https://www.ibtimes.com/sixmajor-oil-gas-firms-agree-cut-potent-methaneemissions-ahead-un-climate-change-summit1693517; https://www.gastechnology.org/CH4/
Documents/Fiji-George-CH4-presentationSep2014.pdf; One Future: Our Nation’s Energy, 1,
6 (Sept. 2014), https://www.gastechnology.org/CH4/
Documents/Fiji-George-CH4-presentationSep2014.pdf.
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requirements governing flaring, venting,
and leaks to ensure that the public’s
resources and assets are not wasted and
are developed in a manner that provides
for long term productivity and
sustainability. First, the BLM has an
independent legal responsibility, and a
proprietary interest as a land manager,
to oversee oil and gas production
activities on Federal and Indian leases.
The BLM has requirements in place, but
as independent reviews have pointed
out, the existing requirements pre-date,
and thus do not account for, significant
technological developments. Updating
and clarifying the regulations will make
them more effective, more transparent,
and easier to understand and
administer, and will reduce operators’
compliance burdens in some respects.
The BLM must ensure that it has
modern, effective requirements to
govern oil and gas operations on BLMadministered leases. Second, as a
practical matter, neither the EPA nor
State regulations adequately address the
issue of waste of gas from BLMadministered leases. The EPA
regulations are directed at air pollution
reduction, not waste prevention; they
focus largely on new sources; and they
do not address all avenues for reducing
waste (for example, they do not impose
flaring limits for associated gas).
Similarly, no State has established a
comprehensive set of requirements
addressing all three avenues for waste—
flaring, venting, and leaks—and only a
few States have significant requirements
in even one of these areas. It is wholly
within the BLM’s statutory authority to
address flaring, venting, and leaks in its
capacity as a land manager with a
responsibility to ensure the longevity
and long term productivity of public
lands and resources, including gas
resources. Part I.B. of this preamble,
below, offers a summary of the proposed
rule’s provisions, benefits, and costs,
and parts V and VI of this preamble
provide more detail about those
provisions (part V) and impacts (part
VI). Overall, the BLM estimates that the
benefits of this rule would outweigh its
costs by a significant margin. Under
certain assumptions, for example, the
rule is expected to produce net benefits
ranging from $115 million to $188
million per year (assuming the EPA
finalizes 40 CFR part 60 subpart OOOOa
and calculating costs and cost savings
using a 7 percent discount rate) or from
$138 million to $232 million per year
(assuming the EPA finalizes 40 CFR part
60 subpart OOOOa and calculating costs
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and cost savings using a 3 percent
discount rate).22
development oil wells (as opposed to
flaring during exploration, well testing,
and emergencies). Over 90 percent of
B. Summary of Proposal
this flaring occurred in North Dakota,
The proposed rule would require
South Dakota, and New Mexico.28
operators to take various actions to
The BLM is proposing to prohibit
reduce waste of gas, establish clear
venting of natural gas, except under
criteria for when flared gas would
certain conditions, including in
qualify as waste and therefore be subject emergencies, as would be defined in the
to royalties, and clarify the on-site uses
regulations.29 With respect to flaring,
of gas that are exempt from royalties.
the BLM proposes to limit the rate of
The BLM has identified several key
routine flaring of associated gas from
points in the oil and gas production
development oil wells and retain the
process where waste-prevention actions current exemptions from gas capture
would be most effective and least costly. requirements and royalties for gas flared
Specifically, we propose to focus on
in other situations, as long as the
reducing waste from the following
operator has complied with the
aspects of the production process:
proposed requirements to minimize
Flaring of associated gas from
such losses. These exemptions include
development oil wells; gas leaks from
gas lost in the normal course of well
equipment and facilities located at the
drilling and well completion; well tests;
well site, as well as from compressors
emergencies, as would be defined in the
located on the lease; operation of highregulations; 30 and gas flared from
bleed pneumatic controllers and certain exploration or wildcat wells, or
pneumatic pumps; gas emissions from
delineation wells (wells drilled to
vessels; downhole well maintenance
define the boundaries of a mineral
and liquids unloading; and well drilling deposit).
The primary alternative to flaring
and completions. The following
associated gas from oil wells is to
discussion summarizes the proposed
requirements applicable to each of these capture, transport, and process that gas
for sale, using the same technologies
aspects of the production process.
These requirements would impose
that are used for natural gas production.
The capture and sale of associated gas
annual costs and yield annual benefits,
but both costs and benefits are expected is viable where there is sufficient gas
production to offset the costs of
to vary over time. Over the first few
connecting to or expanding existing
years, compliance activity (and
associated costs and gas savings) would pipeline infrastructure. In addition,
likely be highest. During this time, some technologies for capturing and using gas
operators would have to add or improve without a pipeline are becoming
gas-capture capability, and some would increasingly available. This capture
infrastructure may include: Separating
have to replace existing equipment.
After these transitional years, we expect out NGLs or liquefying the natural gas
(LNG), allowing the resulting liquids to
that both compliance activities and gas
be trucked off location; converting the
savings from this rule would be
gas into compressed natural gas (CNG)
significantly reduced.
for use on-site or to be trucked off
1. Venting and Flaring
location; and using the gas to run microIn 2013, operators vented about 22 Bcf turbines to generate power for use onand flared at least 76 Bcf of natural gas
site or for sale back to the grid.
from BLM-administered leases.23 The
Gas is flared under a variety of
2013 flaring estimate, a 109 percent
circumstances. Some circumstances,
increase from 2009 levels,24 represents
such as emergencies, can occur
2.6 percent of the total production from
unplanned in the course of oil and gas
BLM-administered leases in that year
production. Further, in a new field,
(2,901 Bcf) 25 and sufficient gas to
operators and the midstream processing
supply over 1 million households.26 Of
companies that commonly build and
this, roughly 71 Bcf came from oil
operate gas gathering and processing
wells.27 Analysis of data supplied by the infrastructure may not have sufficient
ONRR suggests that most of this was
information about how much gas will be
routine flaring of associated gas from
produced to invest in building gathering
lines and processing plants. In other
22 BLM, Economic Impact and Regulatory
instances, however, operators may
Threshold Analysis for 43 CFR 3178 (Royalty Free
decide to focus on near-term oil
Use of Production) and 43 CFR 3179 (Venting and
production rather than investing in the
Flaring Requirements) (2015) (hereinafter RIA) at 7.
23 RIA at 119–120.
gas capture and transmission
24 RIA
119.
at 111 (Appendix A–2).
26 See footnote 2 (assuming 2009 usage levels).
27 RIA at 33.
25 RIA
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28 RIA
at 122 (Appendix A–8, Table 4).
proposed 43 CFR 3179.105.
30 Ibid.
29 See
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infrastructure that would be necessary
to realize a profit from the associated
gas.
On BLM-administered leases, two
situations result in substantial flaring of
associated gas. In some areas, there is
capture infrastructure, but the rate of
new well construction is outpacing the
infrastructure capacity. This accounts
for the majority of flaring on BLMadministered leases. In other areas,
capture and processing infrastructure
has not yet been built out.
Currently, under NTL–4A, operators
must seek BLM approval to flare on a
case-by-case basis, with limited
exceptions. Operators must provide
economic data with each request,
demonstrating that requiring the gas to
be captured would ‘‘lead to the
premature abandonment of recoverable
oil reserves and ultimately to a greater
loss of equivalent energy than would be
recovered’’ if the flaring were approved.
This approach results in a substantial
amount of paper-work, but does not
significantly limit flaring, as BLM has
commonly, although not always,
approved these requests.
The BLM proposes to simplify,
clarify, and strengthen its approach to
reducing flaring by establishing clear
parameters for when routine flaring
from development wells is allowed, and
by setting a limit on the rate of flaring
from individual wells. As a general
matter, operators would no longer have
to obtain permission for flaring on a
case-by-case basis, provided they stay
within the proposed prescribed limit.
Specifically, we propose to limit
routine flaring of associated gas from
development wells to 1,800 thousand
cubic feet (Mcf) per month per well,
averaged across all of the producing
wells on a lease. This limit is similar to
requirements in Wyoming and Utah,
which limit flaring to 60 Mcf/day and
1,800 Mcf/month, respectively, unless
the operator obtains State approval of a
higher limit.31 The BLM estimates that
this limit would reduce flaring by up to
74 percent, although there is substantial
uncertainty regarding this estimate. The
BLM proposes to retain the authority to
allow higher rates of flaring in specific
circumstances, where adhering to the
proposed flaring limit would impose
such costs as to cause the operator to
cease production and abandon
significant recoverable oil reserves
under the lease. In making this
31 Wyoming Operational Rules, Drilling Rules
Section Ch. 3, Section 39(b), available at https://
soswy.state.wy.us/Rules/RULES/9584.pdf (60 Mcf/
day); Utah R649–3–20, Gas Flaring or Venting
Section 1.1, available at (https://www.rules.utah.gov/
publicat/code/r649/r649-003.htm#T20 (1,800 Mcf/
mo.).
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determination, the BLM would consider
the costs of capture, and the costs and
revenues of all oil and gas production
on the lease. Further, the BLM proposes
to create a 2-year renewable exemption
from the flaring limit, available only for
certain existing leases that are located a
significant distance from gas processing
facilities and flaring at a rate well above
the proposed flaring limit. Holders of
these leases have, until now, had no
prior notice of the proposed flaring
limit. Given the significant distance
from these leases to the nearest gas
capture facilities, and the leases’ high
rates of gas flaring, operators at these
sites might have few options to meet the
proposed flaring limit other than
shutting in the wells. The BLM
anticipates the number of leases eligible
for this 2-year exemption would decline
over time, as production of oil and
associated gas from existing leases
naturally declines.
The BLM proposes to phase in the
flaring limit over the first 2 years after
the rule becomes effective, in
recognition of the fact that some wells
are flaring at rates considerably higher
than 1,800 Mcf/month, not all wells will
be able to use on-site capture
technologies, and connecting to gas
pipeline infrastructure may take some
time. We propose that in the first year
after the effective date of the rule, the
flaring limit per well, averaged across
all of the producing wells on a lease,
would be 7,200 Mcf/month. In the
second year, it would be 3,600 Mcf/
month. The 1,800 Mcf/month limit
would apply beginning in the third year
of the rule.
The BLM is also proposing that prior
to drilling a new development oil well,
an operator would have to evaluate the
opportunities and prepare a plan to
minimize waste of associated gas from
that well, and the operator would need
to submit this plan along with the
Application for Permit to Drill or
Reenter (APD). The BLM proposes to
require submission of a plan with
specific content, to ensure that operators
have carefully considered and planned
for gas capture prior to drilling.
In addition to these requirements to
reduce flaring, the BLM proposes to
update existing royalty provisions by
more specifically defining when a loss
of gas would be considered
‘‘unavoidable’’ and royalty-free, and
when it would be considered
‘‘avoidable’’ and subject to royalties. A
loss of gas would be deemed
unavoidable when an operator has
complied with all applicable
requirements and taken prudent and
reasonable steps to avoid waste, and the
gas is lost from any of the following
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specified operations or sources, subject
to limits specified in the proposed
regulations: Emergencies; well drilling,
well completion and related operations;
initial production tests and subsequent
well tests; exploratory coalbed methane
well dewatering; leaks; venting from
pneumatic devices in the normal course
of operation; evaporation from storage
vessels; and downhole well
maintenance and liquids unloading. A
loss of gas would also be deemed
unavoidable when gas is flared (or, in
limited circumstances, vented) from a
well that is not connected to gas capture
infrastructure, provided the BLM has
not otherwise determined that the loss
of gas is avoidable, pursuant to the
provisions of the 1,800 Mcf/month limit
in § 3179.6. All losses of gas not
specifically found to be unavoidable
would be considered avoidable and
subject to royalties. Thus, royalties
would apply to associated gas flared
from a development well that is already
connected to capture infrastructure.
Under these circumstances, operators
have made an economic choice to flare,
and that flaring should not be
considered an unavoidable consequence
of oil production.
Currently, there is a backlog of
requests for approval to flare royaltyfree pending with the BLM. By
establishing clear categories for
avoidable and unavoidable losses, and
thus clarifying when gas may be flared
without payment of royalties, the BLM
aims to reduce the number of
applications for approval to flare
royalty-free and thereby reduce the
burden on both operators and the BLM.
The BLM could then use these
administrative resources to process
applications for permit to drill and
right-of-way applications, and to
conduct inspections, among other
activities.
The costs and benefits of the flaring
provisions are as follows. First, the rule
proposes to require the metering of
flared volumes when gas flaring meets
or exceeds 50 Mcf/day for a flare stack
or manifold. We estimate compliance
costs ranging from $1.0–1.8 million per
year when the capital costs of
equipment are annualized with a 7
percent discount rate, or $0.9–1.6
million per year when the capital costs
of equipment are annualized with a 3
percent discount rate.32
32 RIA
at 69.
For purposes of this analysis, we present costs
and benefits using discount rates of 7% and 3% to
annualize the costs of capital investments. OMB
Circular A–94 (Revised) ‘‘Guidelines and Discount
Rates for Benefit-Cost Analysis of Federal
Programs,’’ https://www.whitehouse.gov/omb/
circulars_a094/, directs agencies to conduct
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We estimate that the proposed flaring
limits, including the 3-year phase-in
period would affect an estimated 435–
885 leases in any given year. These
requirements could pose total costs of
about $32–68 million per year (7
percent discount rate) or $26–43 million
per year (3 percent discount rate).
Because these requirements would drive
additional capture of gas, the flaring
limits are also projected to pose total
cost savings (from the value of the
captured gas) of about $40–58 million
per year (7 percent discount rate) or
$40–64 million per year (3 percent
discount rate). We also estimate that
they would increase natural gas
production by 2.5–5.0 Bcf per year, and
increase NGL production by 36–51
million gallons per year. The net
benefits of these requirements are
estimated to range from negative $10 to
positive $8 million per year (7 percent
discount rate) or $13–30 million per
year (3 percent discount rate).33
2. Leaks
One significant source of the 22 Bcf of
gas vented from Federal and Indian
leases in 2013 is leakage. The BLM
estimates that up to 4.35 Bcf of natural
gas was lost in 2013 as a result of leaks
or other fugitive emissions at operations
on BLM-administered leases.34 Multiple
studies have found that once leaks are
detected, the vast majority can be
repaired with a positive return to the
operator. In addition, both Colorado and
Wyoming (for part of the State) have
recently adopted LDAR requirements for
oil and gas production,35 and EPA has
adopted and proposed additional LDAR
requirements for certain new and
modified oil and gas production
sources.36
The BLM believes that LDAR
programs are a cost-effective means of
baseline analyses using a discount rate of 7%,
which ‘‘approximates the marginal pretax rate of
return on an average investment in the private
sector in recent years.’’ It also recommends that
agencies show sensitivity of the discounted net
present value and other outcomes using additional
discount rates. The BLM chose to use a second
discount rate of 3%, because the literature suggests
that there is a divergence between private discount
rates (considered by firms or industry) and social
discount rates (considered by society), with private
rates exceeding social rates. Further, it is common
for regulatory impact analyses to analyze outcomes
using a 3% discount rate, particularly for the
environmental benefits of proposed regulations.
33 RIA at 60.
34 RIA at 3.
35 Colorado Air Quality Control Commission
Regulations, Regulation 7, 5 CCR 1001–9, Section
XVII.F; Wyoming, Nonattainment Area Regulations
Ch. 8, Section 6(g) (June 2015), available at
https://soswy.state.wy.us/Rules/RULES/9868.pdf.
36 Standards of Performance for Crude Oil and
Natural Gas Production, Transmission and
Distribution, 60 CFR subpart OOOO; 80 CFR 56593,
56660–56698.
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reducing waste in oil and gas
production. We are proposing to require
operators to use an instrument-based
approach to leak detection. Operators
would be required initially to conduct
semi-annual inspections at their well
sites and compressor locations. If an
operator finds no more than 2 leaks at
a facility for two consecutive
inspections, the operator may change to
annual inspections at that facility. If the
operator finds more than 2 leaks at a
facility for two consecutive inspections,
the operator must inspect for leaks
quarterly. If an operator that is required
to inspect for leaks quarterly finds no
more than 2 leaks at a given facility in
two sequential inspections, the operator
could then change back to semi-annual
inspections, and so forth. Once a leak is
identified, the BLM proposes that the
operator would be required to repair the
leak as soon as practicable, but no later
than 15 calendar days after discovery,
absent good cause. Operators would
have to verify the effectiveness of a
repair within 15 calendar days of the
repair, using the same method used to
detect the leak. Operators would also be
required to keep records documenting
the dates and results of leak inspections,
repairs, and follow-up inspections.
The costs and benefits of the BLM’s
proposed LDAR requirements depend
on the rest of the regulatory landscape.
Assuming that the EPA finalizes its 40
CFR part 60 subpart OOOOa rulemaking
for new and modified sources,37 then
the BLM expects that its proposed
requirements would impact up to
36,700 existing wellsites, and pose total
costs of about $69–70 million per year
(using 7 percent and 3 percent discount
rates). These requirements are also
projected to result in cost savings of
about $12–15 million per year (7
percent discount rate) or $15–17 million
per year (3 percent discount rate),
increase gas production by 3.9 Bcf per
year, and reduce VOC emissions by
18,600 tons per year (tpy). We estimate
they would reduce methane emissions
by 67,000 tpy, producing monetized
benefits of $73 million per year in 2017–
2019, $87 million per year in 2020–
2024, and $100 million in 2025 and
2026. Thus, we estimate that these
provisions would result in net benefits
of $19–21 million per year in 2017–
37 The RIA includes a broader discussion of the
estimates of the costs and benefits of this proposed
rule if the EPA does not finalize its 40 CFR part 60
subpart OOOOa rulemaking, but the preamble omits
some of those estimates to simplify the discussion.
EPA’s proposed requirements would apply to wells
that are new, ‘‘modified,’’ or ‘‘reconstructed’’ after
September 18, 2015. See 40 CFR 60.14 and 60.15
for EPA’s definitions of ‘‘modification’’ and
‘‘reconstruction.’’
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2019, $31–35 million per year in 2020–
2024, and $43–48 million in 2025 and
2026.38
If, for analytical purposes we assume
a baseline in which EPA does not
finalize its proposed LDAR
requirements, we estimate the following
impacts. We project that the proposed
LDAR requirements would affect up to
about 37,000–38,000 wellsites per year,
and pose total costs of about $70–71
million per year (using 7 percent and 3
percent discount rates). These
requirements are also projected to result
in cost savings of about $12–18 million
per year (using 7 percent and 3 percent
discount rates), increase gas production
by 3.9–4.0 Bcf per year, and reduce VOC
emissions by 19,000 tpy. We estimate
these proposed requirements would also
reduce methane emissions by 68,000
tpy, producing monetized benefits of
$75 million per year in 2017–2019, $88
million per year in 2020–2024, and $102
million in 2025 and 2026. Thus, we
estimate that these proposed provisions
would result in net benefits of $19–21
million per year in 2017–2019, $30–35
million per year in 2020–2024, and $43–
48 million in 2025 and 2026.39
These estimates represent the
maximum likely impact. As noted
previously, some operators currently
have LDAR programs. This analysis
accounts for existing State requirements
in Colorado, Utah, and Wyoming, but it
does not account for existing (voluntary
or required) LDAR activities conducted
by operators outside of those States. If
we accounted for these existing
activities, then the costs, emissions
reductions, incremental production, and
royalty estimates resulting from this
proposed rule would be less than those
shown.
3. Pneumatic Controllers and Pneumatic
Pumps
Pneumatic controllers and pneumatic
pumps are operated by gas pressure and
emit gas as part of their normal
operations. We estimate that on BLMadministered leases in 2013, about 5.4
Bcf of natural gas was lost from
pneumatic controllers, and about 2.5 Bcf
was lost from all pneumatic pumps.40
Further, we estimate that the proposed
rule would impact up to 15,600 high
bleed pneumatic controllers (pneumatic
controllers with bleed rates of more than
6 standard cubic feet per hour (scf/
hour)) on BLM-administered leases.41 A
recent study by the consulting firm ICF
International (ICF) identified
38 RIA
at 109.
at 108–109.
40 RIA at 3.
41 RIA at 78.
39 RIA
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replacement of high-bleed pneumatic
controllers with low-bleed pneumatic
controllers (pneumatic controllers with
bleed rates of 6 scf/hour or less) as one
of the most inexpensive options for
reducing methane, estimating that it
would actually save industry $2.65 per
Mcf of avoided methane emissions.42
EPA generally prohibits the use of
new high-bleed pneumatic controllers,43
and Colorado and Wyoming (in part of
the State) have required replacement of
existing high-bleed pneumatic
controllers with low-bleed pneumatic
controllers.44 The State of Wyoming has
regulations that require pneumatic
pumps used in the Upper Green River
Basin to destroy or capture emissions or
be replaced by zero-emission solar-,
electric-, or air-driven pumps by January
1, 2017.45
The BLM is proposing to require
operators to replace high-bleed
pneumatic controllers with low-bleed or
no-bleed pneumatic controllers within 1
year of the effective date of the final
rule. This requirement would apply
only to pneumatic controllers that are
not subject to EPA regulations. The BLM
also proposes exceptions to this
requirement, including where the
operator demonstrates, and the BLM
concurs, that replacing the controller(s)
would impose such costs as to cause the
operator to cease production and
abandon significant recoverable oil
reserves under the lease. In making this
determination, the BLM would consider
the costs of capture, and the costs and
revenues of all oil and gas production
on the lease.
We estimate that the proposed
pneumatic controller requirements
would impact up to about 15,600
existing low-bleed pneumatic devices,
and pose total costs of about $6 million
per year (capital costs annualized using
a 7 percent discount rate) or $5 million
per year (capital costs annualized using
a 3 percent discount rate). Because the
sale of recovered gas is expected to
offset the engineering costs of new
controllers, the BLM expects that
42 ICF International, Economic Analysis of
Methane Emission Reduction Opportunities in the
U.S. in the Onshore Oil and Natural Gas Industries,
4–4 (Mar. 2014), available at https://www.edf.org/
sites/default/files/methane_cost_curve_report.pdf
(ICF 2014 Study) (base case assumed $4/Mcf price
for recovered gas and a 10 percent discount rate/
cost of capital).
43 40 CFR 60.5390.
44 Colorado Air Quality Control Commission
Regulations, Regulation 7, 5 CCR 1001–9, Section
XVIII; Wyoming, Nonattainment Area Regulations
Ch. 8, Section 6(f) (June 2015),
available at https://soswy.state.wy.us/Rules/RULES/
9868.pdf.
45 Wyoming, Nonattainment Area Regulations Ch.
8, Section 6(e) (June 2015), available at https://
soswy.state.wy.us/Rules/RULES/9868.pdf.
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compliance with the pneumatic
controller requirements would increase
gas production by 2.9 Bcf per year,
result in cost savings to the industry of
about $9–11 million per year (using a 7
percent discount rate) or $11–12 million
per year (using a 3 percent discount
rate). On net, we project that the
industry would save $3–5 million per
year (using a 7 percent discount rate) or
$6–7 million per year (using a 3 percent
discount rate) under these requirements.
These requirements are also projected to
reduce methane emissions by 43,000
tpy, producing monetized benefits of
$48 million per year in 2017–2019, $56
million per year in 2020–2024, and $65
million in 2025 and 2026. The resulting
net benefits of $53–68 million per year
(using a 7 percent discount rate for costs
and cost savings) or net benefits of $54–
73 million per year (using a 3 percent
discount rate for costs and cost savings),
along with a reduction in VOC
emissions of about 200,000 tpy.46
For pneumatic pumps, the BLM is
proposing to require the operator to
either: (1) Replace a pneumatic
chemical injection or diaphragm pump
with a zero-emissions pump; or (2)
Route the pneumatic chemical injection
or diaphragm pump to a flare. This
requirement would apply only to
pneumatic pumps that are not subject to
EPA regulations. In addition, an
operator would be exempt from this
requirement if it demonstrates, and the
BLM concurs, that: (1) There is no flare
already available on-site or routing to a
flare device is technically infeasible;
and (2) A zero-emission pneumatic
pump is not a viable alternative to
perform the required function. An
operator would also be exempt if the
operator demonstrates and the BLM
concurs that replacing the pneumatic
pump(s) would impose such costs as to
cause the operator to cease production
and abandon significant recoverable oil
reserves under the lease. In making this
determination, the BLM would consider
the costs of capture, and the costs and
revenues of all oil and gas production
on the lease.
If the EPA finalizes its concurrent 40
CFR part 60 subpart OOOOa
rulemaking, the BLM estimates that
these requirements would impact up to
8,775 existing pumps, posing total costs
of about $2.5 million per year. They
would also increase gas production by
0.46 Bcf per year and result in cost
savings of about result in cost savings of
$1.5–1.9 million per year (7 percent
discount rate) or $1.75–2.15 million per
year (3 percent discount rate). In
addition, they are projected to reduce
46 Regulatory
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methane emissions by about 16,000 tpy,
producing monetized benefits of $18
million per year in 2017–2019, $21
million per year in 2020–2024, and $24
million in 2025 and 2026. This would
result in net benefits of $17 million per
year in 2017–2019, $20 million per year
in 2020–2024, and $23 million in 2025
and 2026, as well as reducing VOC
emissions by about 4,000 tpy.47
Assuming, for purposes of analysis,
that EPA does not finalize the 40 CFR
part 60 subpart OOOOa rulemaking, the
BLM estimates that the pneumatic
pump requirements would affect up to
about 8,775 existing pumps and about
75 new pumps per year, posing total
costs of about $2.5–2.7 million per year
(using 7 percent and 3 percent discount
rates). They would also increase gas
production by 0.5 Bcf per year and
result in cost savings of about $1.5–2.2
million per year (using 7 percent and 3
percent discount rates). In addition,
they are projected to reduce methane
emissions by about 16,000–17,000 tpy,
producing monetized benefits of $18
million per year in 2017–2019, $22
million per year in 2020–2024, and $26
million in 2025 and 2026. This would
result in net benefits of $17 million per
year in 2017–2019, $21–22 million per
year in 2020–2024, and $25 million in
2025 and 2026, as well as reducing VOC
emissions by about 4,000 tpy.48
4. Storage Vessels
Vapors released from storage vessels
are a lost source of energy and revenue,
present safety concerns, and contribute
to local air pollution and climate
change. We estimate that 2.77 Bcf of
natural gas was lost in 2013 from storage
tank venting on Federal and Indian
lands.49 Of that volume, we estimate
that 1.82 Bcf was lost from storage
vessels used in natural gas production
and 0.95 Bcf of gas was lost from storage
vessels used in oil production.50
Tank vapors can be controlled by
routing them to a flare or combustor, or
by installing a vapor recovery unit
(VRU). New and modified vessels used
in oil and gas production are already
subject to EPA emissions limits, which
require that individual storage vessels
with VOC emissions equal to or greater
than 6 tpy achieve at least a 95 percent
reduction in VOC emissions from
baseline levels. Colorado and part of
Wyoming have similar, somewhat more
47 RIA
at 82.
at 81.
49 RIA at 3.
50 RIA at 19.
48 RIA
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stringent, requirements for storage
vessels.51
The BLM proposes to address gas
losses from existing storage vessels,
which are not covered by the EPA
standards. The BLM believes that
reducing venting from existing storage
vessels, which have higher rates of
venting, is a reasonably cost-effective
means of reducing gas losses. Rather
than establishing new and separate
standards for venting from existing
vessels, we have been informed by
operators that it would be easier to
comply if we simply require existing
vessels on BLM-administered leases to
meet standards that are the same as the
EPA standards that already apply to
new and modified vessels on those
leases. Additionally, there does not
appear to be a uniform conversion factor
that we could use to translate the VOC
standards established by EPA, Colorado,
and Wyoming to a whole gas standard.
Depending on the content of a vessel,
the same quantity of gas released from
the vessel may contain different
quantities of VOCs. Thus, even though
the BLM is concerned about loss of all
hydrocarbons from vessels, not just loss
of VOCs, we propose to use VOCs as a
proxy for whole gas, and thus to apply
the control requirement to existing
vessels with at least 6 tpy of VOCs,
using the same applicability threshold
as EPA and Colorado.52 (Wyoming also
uses VOC emissions to determine
applicability, but has a lower
threshold.53)
The BLM proposes to require that
operators route VOC emissions from
existing storage vessels subject to these
requirements to combustion devices,
continuous flares, or sales lines within
6 months after the effective date of the
rule. The BLM would grant an exception
to this requirement if the operator
submits an economic analysis
demonstrating—and the BLM agrees—
that compliance would impose such
costs as to cause the operator to cease
production and abandon significant
recoverable oil reserves under the lease.
In making this determination, the BLM
would consider the costs of capture, and
the costs and revenues of all oil and gas
production on the lease. Consistent with
the EPA requirements for new vessels,
51 Colorado Air Quality Control Commission
Regulations, Regulation 7, 5 CCR 1001–9, Sections
XII.D–F; XVII.C; Wyoming, Nonattainment Area
Regulations Ch. 8, Section 6(c) (June 2015),
available at https://soswy.state.wy.us/Rules/RULES/
9868.pdf.
52 40 CFR 60.5395; Colorado Air Quality Control
Commission Regulations, Regulation 7, 5 CCR
1001–9, Section XVII.C.
53 Wyoming, Nonattainment Area Regulations Ch.
8, Section 6(c)(i)(a) (June 2015), available at https://
soswy.state.wy.us/Rules/RULES/9868.pdf.
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these requirements would no longer
apply if the uncontrolled VOC
emissions fall below 4 tpy for 12
months.
The BLM estimates that the proposed
requirements would affect about 300
existing storage vessels on BLMadministered leases, and pose total costs
of about $6 million per year (using 7
percent and 3 percent discount rates).54
We project that these requirements
would increase gas production by 0.04
Bcf per year, resulting in cost savings of
about $0.1–0.2 million per year (using 7
percent and 3 percent discount rates).
They would also reduce methane
emissions by 7,000 tpy, producing
monetized benefits of $8 million per
year in 2017–2019, $9 million per year
in 2020–2024, and $11 million in 2025
and 2026. Overall, we estimate that
these provisions would result in net
benefits of $2 million per year in 2017–
2019, $3–4 million per year in 2020–
2024, and $5 million in 2025 and 2026,
and reduce VOC emissions by 32,500
tpy.
5. Well Maintenance and Liquids
Unloading
Over time, as pressure in a natural gas
well drops, liquids often start
accumulating at the bottom of the well,
impeding gas production. Operators
often remove or ‘‘unload’’ the liquids,
but depending on the method, this
process can release substantial
quantities of natural gas into the
environment. In particular, operators
may allow the bottom-hole pressure to
increase and then vent or ‘‘blow down’’
or ‘‘purge’’ the well. We estimate that
3.26 Bcf of natural gas was lost in 2013
during liquids unloading operations on
Federal and Indian lands.55
There are a wide variety of methods
for liquids unloading, and technological
developments, such as automated
plunger lifts, now allow liquids to be
unloaded with minimal loss of gas. The
BLM believes that it is reasonable to
expect operators to use these available
technologies to minimize gas losses, and
we believe that failure to minimize
losses of gas from liquids unloading
now constitutes waste.
For wells drilled after the effective
date of the rule, the BLM is proposing
to prohibit unloading liquids by simply
purging the well (except in specified
circumstances). The BLM believes that
it is less costly to avoid purging
altogether at new wells than at existing
wells. In addition, the BLM is proposing
to require specified best management
practices to minimize venting from
liquids unloading at both new and
existing wells. Specifically, the operator
would be required to be on-site during
well purging events, unless the well has
an automatic control system, and the
operator would also be required to
document liquids unloading events.
This would allow the BLM to verify
compliance, and it would provide
additional information on the amounts
of gas lost through these activities on
Federal and Indian lands.
We estimate that the proposed liquids
unloading requirements would affect up
to about 1,550 existing wells and about
25 new wells per year, posing total costs
of about $6 million per year (capital
costs annualized using a 7 percent
discount rate) or $5–6 million per year
(capital costs annualized using a 3
percent discount rate). We project that
they would increase gas production by
roughly 2 Bcf per year, resulting in cost
savings of about $7–8 million per year
(using a 7 percent discount rate) or $7–
10 million per year (using a 3 percent
discount rate). In addition, these
requirements are projected to reduce
methane emissions by 30,000 to 34,000
tpy, producing monetized benefits of
$33–34 million per year in 2017–2019,
$41–43 million per year in 2020–2024,
and $50–51 million in 2025 and 2026.
Overall, we estimate that these
provisions would produce net benefits
of $35–52 million per year (using a 7
percent discount rate for costs and cost
savings) or $35–55 million per year
(using a 3 percent discount rate for costs
and cost savings), and reduce VOC
emissions by about 136,000 to 156,000
tpy.56
6. Reduction of Waste From Drilling,
Completion, and Related Operations
Substantial quantities of gas can be
lost during drilling, completion, and
refracturing (sometimes referred to by
the broader term ‘‘workover’’)
operations, and we estimate that in
2013, 2.1 Bcf of natural gas was lost
during these operations on BLMadministered leases.57 Of this, we
estimate that completion emissions from
hydraulically fractured (and refractured)
oil wells accounted for 1.4 Bcf of the
loss, emissions from hydraulically
fractured gas wells accounted for about
0.7 Bcf of the loss, and all other
completions accounted for a de minimis
amount.58
The EPA currently requires new
hydraulically fractured and refractured
gas wells to capture or flare gas that
otherwise would be released during
56 RIA
at 87.
at 3.
58 RIA at 18 (Table 6).
54 RIA
at 95.
55 RIA at 3.
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drilling and completion operations, and
EPA has announced that it plans to
extend these requirements to new
hydraulically fractured and refractured
oil wells. Nonetheless, the BLM believes
that it is appropriate for the BLM to
adopt its own requirements to minimize
the waste of gas during well drilling and
well completion and post-completion
operations at hydraulically fractured or
refractured wells and wells that are not
fractured. The BLM has an independent
statutory obligation to minimize waste
of oil and gas resources on BLMadministered leases. As proposed, the
BLM waste requirements for well
drilling and completions would extend
to both conventional and hydraulically
fractured wells, and therefore would
apply to a broader set of wells than the
EPA regulations propose to cover. Also,
the BLM anticipates that to the extent
both sets of requirements applied, the
BLM believes that an operator would
satisfy both sets of requirements by
either capturing or flaring the gas that
would otherwise be released. Thus, the
BLM is also proposing to allow an
operator to demonstrate that it is in
compliance with EPA requirements for
control of gas from well completions in
lieu of compliance with the BLM
requirements. The BLM is coordinating
closely with the EPA on the agencies’
proposals, and the BLM expects to
ensure that our final requirements
would not impose additional burdens
on an operator that complies with any
EPA requirements on new well
completions.
The proposed rule would require
operators to: Flare gas generated during
drilling operations, capture and sell that
gas, use it in operations on the lease, or
inject it into the well. We estimate that
the rule would apply to about 3,000
wells per year. Based on our experience
in the field, however, the BLM believes
that operators are already controlling
gas from drilling operations as a matter
of safety and operating practice. Thus,
we do not estimate costs associated with
this requirement. Similarly, based on
our professional experience in the field,
we believe that operators are already
controlling gas from workover
operations on conventional wells as a
matter of safety and operating practice,
and there should be no compliance
costs for this requirement.
The proposed rule would also require
operators to reduce the emissions
associated with well completions by
capturing and selling associated gas,
flaring it, using it in operations on the
lease, or injecting it. This proposal
would only impact well completions
and workovers/refractures on
conventional oil and gas wells and
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hydraulically fractured oil wells, as EPA
already covers hydraulically fractured
gas wells.
If the EPA finalizes its 40 CFR part 60
subpart OOOOa rulemaking, as we
expect, then as a practical matter, this
rule’s completion requirements will
only impact conventional well
completions, because the EPA will
regulate completions of new and
modified hydraulically fractured oil and
gas wells. We estimate that the BLM
rule would impact between 115–150
completions per year and pose costs to
the industry of less than $430,000 per
year. There would be only de minimis
anticipated incremental production,
incremental royalty, and emissions
reductions.59
If, for purposes of analysis, we assume
that EPA does not finalize its 40 CFR
part 60 subpart OOOOa rulemaking, the
BLM estimates that these provisions
would affect about 1,250 to 1,575
completions per year and pose total
costs of about $8–12 million per year
(using a 7 percent discount rate) or $12
million per year (using a 3 percent
discount rate). We further estimate that
these provisions would increase gas
production by 0.5 to 0.6 Bcf per year,
resulting in cost savings of about $2–3
million per year (using 7 percent and 3
percent discount rates). This would also
reduce methane emissions by 11,500 to
14,500 tpy, producing monetized
benefits of $13 million per year in 2017–
2019, $16–18 million per year in 2020–
2024, and $21–22 million in 2025 and
2026. Overall, under this scenario, these
provisions are estimated to produce net
benefits of $3–15 million per year
(considering the present value of costs
and cost savings using a 7 percent
discount rate) or net benefits of $3–13
million per year (considering the
present value of costs and cost savings
using a 3 percent discount rate), and
reduce VOC emissions by 9,600 to
12,200 tpy.60
7. Royalty Provisions Governing New
Competitive Leases
Finally, the BLM proposes to revise
the regulations at 43 CFR 3103.3–1,
which govern royalty rates applicable to
onshore oil and gas leases, to make the
rule text parallel to the statutory text,
respond to findings and
recommendations in audits from the
GAO, and eliminate unnecessary
provisions in the existing regulations.
The proposed revisions would do
three principal things: (1) Make clear
that the royalty rate on all existing
leases would remain at the rate
59 RIA
60 RIA
at 74.
at 74.
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prescribed in the lease or in regulations
applicable at the time of lease issuance;
(2) Specify the fixed, statutory rate of
12.5 percent 61 for all noncompetitive
leases issued after the effective date of
the rule; and (3) Make the rule text
parallel to the corresponding MLA text
for competitive leases issued after the
effective date of the rule.62 The MLA
text provides the BLM the flexibility to
set royalty rates for these competitive
leases at or above 12.5 percent. By
contrast, the BLM’s existing royalty
regulation sets a flat rate of 12.5 percent
for all new competitive leases.63
Although the BLM does not currently
propose to raise royalty rates, the
proposed rule would allow the BLM to
set a royalty rate for oil and gas
produced from competitive oil and gas
leases issued after the effective date of
this rule of ‘‘not less than’’ 12.5 percent.
The BLM is not proposing any further
changes to the royalty provisions
governing new competitive oil and gas
wells,64 but we are requesting comment
on the use of a fluctuating royalty rate
to incentivize reductions in flaring from
new competitive leases. Further
information about this possible
approach is provided below in Section
V.C. of this preamble.
C. Summary of Costs and Benefits
1. Costs
Overall, assuming that the EPA
finalizes its concurrent 40 CFR part 60
subpart OOOOa rulemaking, the BLM
estimates that this proposed rule will
pose costs ranging from $125–161
million per year (using a 7 percent
discount rate) or $117–$134 million per
year (using a 3 percent discount rate)
over the next 10 years.65 These costs
would include engineering compliance
costs and the social cost of minor
additions of carbon dioxide to the
atmosphere, resulting from the on-site
or downstream use of gas that is newly
captured as a result of this proposed
rule.66 The engineering compliance
61 30
U.S.C. 226(c)(1).
U.S.C. 226(b)(1)(A).
63 43 CFR 3103.3–1(a)(1).
64 Note that the proposed rule would renumber
current 43 CFR 3103.3–1 (a)(2) and (3) but would
not otherwise change the content of those
provisions. Further, the proposed rule would not
alter 43 CFR 3103.3–1(b), (c), or (d). Those five
provisions are reprinted in this proposed rule solely
to clarify the proposed numbering of the revised
§ 3103.3–1, and for ease of reference. The BLM does
not intend to revise those provisions, nor to invite
comment on their content.
65 RIA at 127.
66 Some gas that would have otherwise been
vented would now be combusted on-site or
presumably downstream to generate electricity. As
described in the RIA, the estimated value of these
carbon additions would not exceed $30,000 in any
given year.
62 30
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costs presented do not include potential
cost savings from the recovery and sale
of natural gas (those savings are shown
in the summary of benefits).
If, for analytical purposes, we assume
that EPA does not finalize its concurrent
40 CFR part 60 subpart OOOOa
rulemaking, these requirements would
affect more sources and the costs would
be somewhat higher. Under that
scenario, the BLM estimates that this
rule will pose costs ranging from $139–
174 million per year (using a 7 percent
discount rate) or $131–147 million per
year (using a 3 percent discount rate)
over the next 10 years.67
In some areas, operators have already
undertaken, or plan to undertake,
voluntary actions to address gas losses.
To the extent that operators are already
in compliance with the requirements of
this proposed rule, the above estimates
overstate the likely impacts of the rule.
We expect that cost impacts on
individual operators would be small,
even for businesses with less than 500
employees. In the RIA, we estimate that
average costs for a representative small
operator would increase by about
$31,300–37,500, which would result in
an average reduction in profit margin of
0.087–0.104 percentage points in
2020.68
2. Benefits
We measure the benefits of the rule as
the cost savings that the industry would
receive from the recovery and sale of
natural gas and the environmental
benefits of reducing the amount of
methane (a potent GHG) and other air
pollutants released into the atmosphere.
As with the estimated costs, we expect
benefits on an annual basis. The
estimated benefits of the rule also
depend on whether the EPA finalizes its
40 CFR part 60 subpart OOOOa
rulemaking. Assuming that rule is in
effect, the BLM estimates that this rule
would result in monetized benefits of
$255–329 million per year (using a 7
percent discount rate to calculate the
present value of future annual cost
savings, and using model averages of the
social cost of methane with a 3 percent
discount rate) or $255–357 million per
year (using a 3 percent discount rate to
calculate the present value of future
annual cost savings, and using model
averages of the social cost of methane
with a 3 percent discount rate).69 We
estimate that the proposed rule would
reduce methane emissions by 164,000–
67 RIA
at 127.
at 159. These estimates rely on 2014
company data, use a 7% discount rate, and assume
the finalization of EPA’s 40 CFR part 60 subpart
OOOOa rulemaking.
69 RIA at 130.
68 RIA
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169,000 tpy, which we estimate to be
worth $180–253 million per year (this
social benefit is included in the
monetized benefit above). We estimate
that the proposed rule would reduce
VOC emissions by 391,000–411,000 tpy
(this benefit is not monetized in our
calculations).70
If, for purposes of analysis, we assume
that EPA does not finalize its 40 CFR
part 60 subpart OOOOa rulemaking, we
estimate that this proposed rule would
result in monetized benefits of $270–
354 million per year (using a 7 percent
discount rate to calculate the present
value of future annual cost savings and
using model averages of the social cost
of methane with a 3 percent discount
rate) or $270–384 million per year
(using a 3 percent discount rate to
calculate the present value of future
annual cost savings and using model
averages of the social cost of methane
with a 3 percent discount rate).71 We
estimate that the proposed rule would
reduce methane emissions by 176,000–
185,000 tpy, which we estimate to be
worth $193–277 million per year (this
social benefit is included in the
monetized benefit above). We estimate
that the proposed rule would reduce
VOC emissions by 400,000–423,000 tpy
(this benefit is not monetized in our
calculations).72
Adoption of the proposed rule would
also have numerous ancillary benefits.
These include improved quality of life
for nearby residents, who note that
flares are noisy and unsightly at night;
reduced release of VOCs, including
benzene and other hazardous air
pollutants; and reduced production of
nitrogen oxides (NOX) and particulate
matter, which can cause respiratory and
heart problems.
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3. Net Benefits
Overall, the BLM estimates that the
benefits of this rule outweigh its costs
by a significant margin. The BLM
expects net benefits ranging from $115–
188 million per year (using a 7 percent
discount rate) or $138–232 million per
year (using a 3 percent discount rate).
Specifically, assuming a 7 percent
discount rate, we estimate the following
annual net benefits:
• $115–130 million per year from
2017–2019;
• $155–156 million per year from
2020–2024; and
• $187–188 million per year from
2025–2026.
at 133–135.
at 130.
72 RIA at 133–135.
Assuming a 3 percent discount rate,
we estimate the annual net benefits
would be:
• $138–151 million per year from
2017–2019;
• $192–196 million per year from
2020–2024; and
• $231–232 million per year from
2025–2026.73
If, for purposes of analysis, we assume
that the EPA does not finalize the 40
CFR part 60 subpart OOOOa
rulemaking, we estimate the net benefits
of this proposed rule would be
somewhat higher, ranging from $119–
203 million per year (costs and costs
savings calculated using a 7 percent
discount rate) or $139–245 million per
year (costs and costs savings calculated
using a 3 percent discount rate).
4. Influence on Production
The proposed rule has a number of
requirements that are expected to
influence the production of natural gas,
NGLs, and crude oil from onshore
Federal and Indian oil and gas leases.
If 40 CFR part 60 subpart OOOOa is
finalized, we estimate the following
incremental changes in production,
noting the representative share of the
total U.S. production in 2014 for
context. We estimate additional natural
gas production, ranging from 11.7–14.5
Bcf per year (representing 0.04–0.05
percent of the total U.S. production in
2014), the productive use of an
additional 29–41 Bcf of natural gas,
which we estimate would be used to
generate 36–51 million gallons of NGL
per year (representing 0.08–0.11 percent
of the total U.S. production), and a
reduction in crude oil production
ranging from 0.6–3.2 million bbl per
year (representing 0.02–0.10 percent of
the total U.S. production). We also
expect 0.5 Bcf of gas to be combusted
on-site that would have otherwise been
vented. Combined, the capture or
combustion of gas represents 44–46
percent of the volume vented in 2013
and the capture and/or productive use
of the gas 41–60 percent of the volume
flared in 2013.74
If 40 CFR part 60 subpart OOOOa is
not finalized, we estimate additional
natural gas production ranging from 12–
15 Bcf per year (representing 0.04–0.06
percent of the total U.S. production), the
productive use of an additional 29–41
Bcf of natural gas, which we estimate
would be used to generate 36–51
million gallons of NGL per year
(representing 0.08–0.11 percent of the
total U.S. production), and a reduction
in crude oil production ranging from
0.6–3.2 million bbl per year
(representing 0.02–0.10 percent of the
total U.S. production). Separate from the
volumes listed above, we also expect 1
Bcf of gas to be combusted on-site that
would have otherwise been vented.
Combined, the capture or combustion of
gas represents 49–52 percent of the
volume vented in 2013 and the capture
and/or productive use of gas represents
41–60 percent of the volume flared in
2013.75
Since the relative changes in
production are expected to be small, we
do not expect that the proposed rule
would significantly impact the price,
supply, or distribution of energy.
5. Royalties
Assuming the EPA 40 CFR part 60
subpart OOOOa rulemaking is finalized,
we estimate that this proposed rule
would produce additional royalties of
$9–11 million per year (discounted at 7
percent) or $10–16 million per year
(discounted at 3 percent).76 If, for
purposes of analysis, we assume that the
EPA does not finalize the 40 CFR part
60 subpart OOOOa rulemaking, we
estimate that this proposed rule would
result in annual incremental royalties of
$9–11 million per year (discounted at 7
percent) or $11–17 million per year
(discounted at 3 percent).
II. Table of Contents
I. Executive Summary
A. Background
B. Summary of Proposal
1. Venting and Flaring
2. Leaks
3. Pneumatic Controllers and Pneumatic
Pumps
4. Storage Vessels
5. Well Maintenance and Liquids
Unloading
6. Reduction of Waste From Drilling,
Completion, and Related Operations
7. Royalty Provisions Governing New
Competitive Leases
C. Summary of Costs and Benefits
1. Costs
2. Benefits
3. Net Benefits
4. Royalties
II. Table of Contents
III. Public Comment Procedures
IV. Background
A. Overview
B. Impacts of Waste and Loss of Gas
C. Purpose of This Rule
D. Stakeholder Outreach
E. Existing BLM Regulations and
Requirements for Preventing Natural-Gas
Waste
F. Legal Authority
G. Concerns About Loss of Gas Identified
Through Oversight
H. Volumes of Lost Natural Gas
70 RIA
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76 RIA
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1. Data Sources on Lost Gas
2. Additional Information on Loss
Estimates
I. Examples of and Gaps in Existing WasteReduction and Related Efforts
1. State Activities
2. Voluntary Industry Efforts
3. EPA Air Quality Requirements
V. Discussion of the Proposed Rule
A. Measures To Reduce Waste
1. Venting or Flaring of Associated Gas
From Producing Oil Wells
2. Leaks
3. Pneumatic Controllers and Pneumatic
Pumps
4. Storage Vessels
5. Well Maintenance and Liquids
Unloading
6. Reduction of Waste From Drilling,
Completion, and Related Operations
7. Additional Opportunities To Reduce
Waste From Venting
B. Royalty-Free Use of Production
C. Royalty Rates on New Competitive
Leases
D. Record Keeping Requirements
E. Reporting and Information Availability
F. Planning Process
G. Facilities in Rights-of-Way
H. State or Tribal Variances
I. Section-by-Section Discussion
1. Section 3103.3–1
2. Section 3160.0–5
3. Section 3162.3–1
4. Subpart 3178—Royalty-Free Use of
Lease Production
5. Subpart 3179—Waste Prevention and
Resource Conservation
6. Flaring and Venting Gas During Drilling
and Production Operations
7. Gas Flared or Vented From Equipment
or During Well Maintenance Operations
8. Leak Detection and Repair
9. State or Tribal Variances
VI. Analysis of Impacts
A. Description of the Regulated Entities
1. Potentially Affected Entities
2. Affected Small Entities
B. Impacts of the Proposed Requirements
1. Overall Costs of the Rule
2. Overall Benefits of the Rule
3. Net Benefits of the Rule
4. Distributional Impacts
VII. Procedural Matters
A. Executive Order 12866, Regulatory
Planning and Review
B. Regulatory Flexibility Act and Small
Business Regulatory Enforcement
Fairness Act of 1996
C. Unfunded Mandates Reform Act of 1995
D. Executive Order 12630, Governmental
Actions and Interference With
Constitutionally Protected Property
Rights (Takings)
E. Executive Order 13132, Federalism
F. Executive Order 12988, Civil Justice
Reform
G. Executive Order 13175, Consultation
and Coordination With Indian Tribal
Governments
H. Paperwork Reduction Act
1. Overview
2. Summary of Proposed Information
Collection Requirements
3. Proposals Involving APDs and Sundry
Notices
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4. Other Proposed Information Collection
Activities
5. Burden Estimates
I. National Environmental Policy Act
J. Executive Order 13211, Actions
Concerning Regulations That
Significantly Affect Energy Supply,
Distribution, or Use
K. Clarity of the Regulations
L. Executive Order 13563, Improving
Regulation and Regulatory Review
VIII. Authors
III. Public Comment Procedures
If you wish to comment on the
proposed rule, you may submit your
comments by any one of several
methods specified (see ADDRESSES). If
you wish to comment on the
information collection requirements,
you should send those comments
directly to the OMB as outlined (see
ADDRESSES); however, we ask that you
also provide a copy of those comments
to the BLM.
Please make your comments as
specific as possible by confining them to
issues for which comments are sought
in this notice, and explain the basis for
your comments. The comments and
recommendations that will be most
useful and likely to influence agency
decisions are:
1. Those that are supported by
quantitative information or studies; and
2. Those that include citations to, and
analyses of, the applicable laws and
regulations.
The BLM is not obligated to consider
or include in the Administrative Record
for the rule comments received after the
close of the comment period (see DATES)
or comments delivered to an address
other than those listed (see ADDRESSES).
Comments, including names and
street addresses of respondents, will be
available for public review at the
address listed under ADDRESSES during
regular hours (7:45 a.m. to 4:15 p.m.),
Monday through Friday, except
holidays. Before including your address,
phone number, email address, or other
personal identifying information in your
comment, you should be aware that
your entire comment—including your
personal identifying information—may
be made publicly available at any time.
While you can ask us in your comment
to withhold your personal identifying
information from public review, we
cannot guarantee that we will be able to
do so.
IV. Background
A. Overview
The BLM’s onshore oil and gas
management program is a major
contributor to our nation’s oil and gas
production. The BLM manages more
than 245 million acres of land and 700
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million acres of subsurface estate,
comprising nearly a third of the nation’s
mineral estate. Domestic production
from over 100,000 Federal onshore oil
and gas wells accounts for 11 percent of
the Nation’s natural gas supply and 5
percent of its oil. In FY 2014, the ONRR
reported that operators produced 204.6
MMbbl of oil, 2 Tcf of natural gas, and
3.1 billion gallons of NGLs from onshore
Federal and Indian oil and gas leases.
The production value of this oil and gas
exceeded $27.2 billion and generated
approximately $3.1 billion in
royalties.77
Over the past decade, the United
States has experienced a dramatic
increase in natural gas and oil
production due to technological
advances, such as hydraulic fracturing
combined with directional drilling. This
boost in production has brought many
benefits in the form of expanded and
more secure domestic supplies, lower
prices, increased economic activity, and
greater royalty revenues for Federal,
State, and tribal governments.
At the same time, the American
public has not benefited from the full
potential of this increased production,
as it has been accompanied by
significant and growing quantities of
wasted natural gas. Between 2009 and
2014, operators on BLM-administered
leases wasted enough natural gas to
serve 5.1 million homes for 1 year,
according to data reported to ONRR.78
A sizeable quantity of natural gas is
flared or vented in the course of
exploration, development, and
production activities. Commonly used
well pad production equipment, such as
pneumatic controllers, are designed to
function by venting natural gas. Leaks
and other unintentional releases across
oil and gas operations account for
additional waste. As discussed in the
RIA, we estimate that in 2013, about 98
Bcf of natural gas was vented, flared, or
leaked from oil and gas production on
BLM-administered leases.79 This
represents about 3.4 percent of the total
production from BLM-administered
leases in that year (2,901 Bcf).80
This proposed rule aims to reduce
wasteful venting, flaring, and leaks of
natural gas from oil and natural gas
production activities on onshore Federal
and Indian leases. The rule would
update the BLM’s existing requirements
77 ONRR, Statistical Information, https://
statistics.onrr.gov/ReportTool.aspx using Sales
Year—FY2014—Federal Onshore—All States Sales
Value and Revenue for Oil, NGL, and Gas products
as of December 2, 2015.
78 Based on an estimate of 74 Mcf of gas used per
household per year. See footnote 2.
79 RIA at 3.
80 RIA at 111 (Appendix A–2).
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related to venting, flaring, and royaltyfree use of natural gas, which are over
3 decades old. The BLM proposes to
clarify the circumstances under which
operators may flare, or in very limited
circumstances vent, natural gas
produced in the course of exploration,
development, and production activities,
and we propose to expand the
circumstances under which flared or
vented natural gas would be subject to
royalties. The BLM also proposes other
reasonable measures to reduce wasteful
venting, flaring, and leaks of natural gas
from oil and gas operations on Federal
and Indian leases.
The BLM expects that these
regulations would benefit the public by
reducing waste of a public resource,
improving production accountability,
increasing natural gas supplies, and
increasing royalties received by Federal,
State, and tribal governments. In
addition, reducing venting and flaring
would reduce impacts on local
communities and the environment by
reducing emissions of air pollutants that
contribute to smog, particulate
pollution, and climate change.
B. Impacts of Waste and Loss of Gas
Natural gas is a valuable resource that
plays a significant role in the U.S.
economy and is critical to our energy
and national security. Gas that is flared,
vented, or leaked into the atmosphere
from production on BLM-administered
leases is a lost public or tribal resource
that is not available for productive use.
In addition, most of the lost gas is not
currently subject to royalties, which
compensate the public for the removal
of publicly owned resources and help
fund activities of States, localities, tribes
and the Federal Government. State
governments receive roughly half of the
12.5 percent royalty that the Federal
Government typically collects from
onshore oil and gas lessees. The BLM
estimates that if captured, the gas
presently lost from BLM-administered
leases would provide an additional $49
million in royalties each year to the
Federal Government, States, and
tribes.81
This waste of gas through flaring can
affect the quality of life for nearby
residents, who note that flares are noisy
and unsightly at night. Venting, flaring,
and leaks of gas also contribute to local,
regional, and global air pollution. VOCs
and hazardous air pollutants
(components of the gas, such as
benzene, toluene, ethylbenzene, and
xylene) are released into the atmosphere
when natural gas is released through
venting, flaring, or incomplete
81 RIA
at 3.
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combustion at a flare. VOCs combine
with sunlight and NOX, which are
created by burning fossil fuels, to form
ground-level ozone, or smog, which
causes a wide range of health effects.
Benzene and other components of
natural gas are also classified as
hazardous air pollutants, which are
known or suspected to cause cancer or
reproductive effects.82 Flaring of gas
produces NOX and particulate matter,
both of which can cause respiratory and
heart problems.83
Venting and leaks of natural gas in the
oil and gas production process also
contribute to climate change. Natural
gas is primarily composed of methane,
which is a potent GHG. Measured over
a 100-year time-frame, methane results
in more than 20 times more warming
than CO2, on a ton-per-ton basis. Over
a 20-year time-frame, methane is 86
times more potent than CO2, according
to the most recent report of the
Intergovernmental Panel on Climate
Change.84 Venting, flaring, and leaks
also produce CO2. As the President’s
Climate Action Plan recognizes,
reducing methane emissions can make
an important contribution to addressing
climate change.85
C. Purpose of This Proposed Rule
The purpose of this proposed rule is
to establish a comprehensive framework
to give operators on Federal and tribal
leases clear direction to minimize waste
and losses of natural gas. This proposed
rule is necessary because the BLM’s
existing requirements on venting and
flaring are more than 3 decades old, do
not reflect technological advances and
current scientific understanding, have
failed to deter rising losses of gas, fail
in some respects to provide clear
guidance to BLM staff and oil and gas
operators, and do not address leaks from
existing and new infrastructure.
This proposed rule would implement
statutory directives to avoid waste of oil
and gas resources. It would supplement
82 The
EPA has classified benzene as a known
human carcinogen and reproductive effects have
been reported at high exposures and observed in
animal studies. U.S. EPA, Benzene Hazard
Summary (online at: https://www3.epa.gov/
airtoxics/hlthef/benzene.html).
83 U.S. EPA, Nitrogen Dioxide; Health (online at:
https://www3.epa.gov/airquality/nitrogenoxides/
health.html); U.S. EPA, Particulate Matter; Health
(online at: https://www3.epa.gov/pm/health.html).
84 See Intergovernmental Panel on Climate
Change, Climate Change 2013: The Physical Science
Basis, Chapter 8, Anthropogenic and Natural
Radiative Forcing, at 714 (Table 8.7), available at
https://www.ipcc.ch/pdf/assessment-report/ar5/
wg1/WG1AR5_Chapter08_FINAL.pdf.
85 The President’s Climate Action Plan, https://
www.whitehouse.gov/sites/default/files/image/
president27sclimateactionplan.pdf. at 10–11 (June
2013)
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the BLM’s regulations contained in 43
CFR 3162.5 and 3162.7, to address
prevention of waste of produced natural
gas, use of produced oil and gas on a
royalty-free basis, and record keeping
requirements. It would also update and
replace NTL–4A,86 pertaining to venting
and flaring, unavoidably and avoidably
lost gas, and waste prevention. The
proposed rule would ensure that
operators use best practices that
minimize waste from new and existing
operations.
The BLM recognizes the importance
of ensuring that our requirements do not
subject operators to conflicting or
redundant requirements. In 2012, the
EPA adopted air pollution regulations
for certain activities in the oil and gas
production sector, and the EPA has
recently proposed further regulations in
that area, which would have the effect
of reducing loss of gas. In addition, in
response to growing concerns about
venting, flaring, and leakage of gas,
several States have adopted or are
considering regulations to address these
issues. The EPA regulations focus
largely on new sources, however, and
they are directed at pollution reduction,
not waste prevention, so they do not
address all opportunities to reduce
waste. Similarly, none of the States has
established a comprehensive set of
requirements addressing all of the
sources of lost gas that we are
considering here, and many States have
minimal requirements in this area. We
are committed to working closely with
State and tribal governments to ensure
that the BLM requirements are
coordinated with State and tribal
requirements to the extent possible. The
BLM requirements would not supersede
equally effective or more stringent State
and tribal requirements. We are also
working closely with the EPA to
coordinate our requirements, so that
operators are not faced with conflicting
or duplicative Federal mandates.
D. Stakeholder Outreach
Over several months of last year, the
BLM conducted a series of forums to
consult with tribal governments and
solicit stakeholder views to inform the
development of this proposed rule. We
held public meetings in Denver,
Colorado (March 19, 2014),
Albuquerque, New Mexico (May 7,
86 44 FR 76600 (1979). The U.S. Geological
Survey (USGS) issued regulations on these subjects
in NTL–4A. In the early 1980’s, the responsibility
for Federal onshore oil and gas operations was
transferred from the USGS to the Minerals
Management Service (MMS). In 1983, the Secretary
transferred the responsibility to the BLM. NTL–4A
has remained in force through the changes in
agency responsibility.
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2014), Dickinson, North Dakota (May 9,
2014), and Washington, DC (May 14,
2014).87 Each day, we held a tribal
outreach session in the morning and a
public outreach session in the
afternoon. At the Denver, Colorado, and
Washington, DC sessions, the tribal and
public meetings were live streamed to
allow for the greatest possible
participation by interested parties. The
tribal outreach sessions also served as
initial consultation with Indian tribes to
comply with Executive Order 13175,
Consultation and Coordination with
Indian tribal governments.
As part of our outreach efforts, the
BLM accepted informal comments
generated as a result of the public/tribal
outreach sessions through May 30, 2014.
A total of 29 unique comments were
received: 12 from the oil and gas
industry and trade associations, 6 from
NGOs representing 37 organizations, 2
from government officials or elected
representatives and 9 from private
citizens. Two hundred and sixty
comments from private citizens were
part of an email campaign.
In addition, the BLM has conducted
outreach to States with extensive oil and
gas production on BLM-administered
leases. We have carefully reviewed State
regulations and guidance, and we have
contacted State regulatory bodies that
oversee aspects of oil and gas
production to discuss their
requirements and practices. We look
forward to continued close interaction
with State and tribal regulators.
The proposed rule reflects input
gathered from the public meetings,
comments, and discussions with States
and tribes.
asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
E. Existing BLM Regulations and
Requirements for Preventing NaturalGas Waste
Venting, flaring, and royalty-free uses
of oil and natural gas on BLMadministered leases are currently
governed by NTL–4A, which was issued
by the U.S. Geological Survey on
December 27, 1979, before the BLM
assumed oversight responsibility for
onshore oil and gas development and
production. NTL–4A prohibits venting
or flaring of gas well gas, and it
prohibits venting or flaring of oil well
gas unless approved in writing by the
‘‘Supervisor.’’ 88 Both prohibitions are
subject to specified exemptions for
emergencies, certain equipment
malfunctions, certain well tests, and
vapors from storage vessels. With
respect to venting or flaring of oil well
gas, NTL–4A IV.B states:
The Supervisor may approve an
application for the venting or flaring of oil
well gas if justified either by the submittal of
(1) an evaluation report supported by
engineering, geologic, and economic data
which demonstrates to the satisfaction of the
Supervisor that the expenditures necessary to
market or beneficially use such gas are not
economically justified and that conservation
of the gas, if required, would lead to the
premature abandonment of recoverable oil
reserves and ultimately to a greater loss of
equivalent energy than would be recovered if
the venting or flaring were permitted to
continue or (2) an action plan that will
eliminate venting or flaring of the gas within
1 year from the date of application.89
Thus, the key criteria under this
provision in NTL–4A for approving
venting or flaring (and rendering it
royalty-free) are: (1) That the
expenditures for capture are ‘‘not
economically justified,’’ and they would
‘‘lead to the premature abandonment of
recoverable oil reserves’’; or (2) The
venting or flaring will be eliminated
within 1 year.90 NTL–4A IV.C also
provides that ‘‘(w)hen evaluating the
feasibility of requiring conservation of
the gas, the total leasehold production,
including both oil and gas, as well as
the economics of a field wide plan shall
be considered . . . in determining
whether the lease can be operated
successfully if it is required that the gas
be conserved.’’ 91
In addition, NTL–4A specifies the
circumstances under which an operator
owes royalties on oil and gas that is lost
from a lease. It provides that gas which
is ‘‘avoidably lost’’ is subject to
royalties. It defines ‘‘avoidably lost’’
production as produced gas that is
vented or flared without the ‘‘prior
authorization, approval, ratification, or
acceptance of the Supervisor,’’ or lost
due to: (1) Negligence; (2) Failure to
comply with lease terms, the operating
plan, orders or regulations; or (3) ‘‘(T)he
failure of the lessee or operator to take
all reasonable measures to prevent and/
or to control the loss.’’ 92 NTL–4A I
further provides that no royalty is due
for gas that is: (1) Used on the lease for
‘‘beneficial purposes’’; (2) Vented or
flared with the Supervisor’s prior
authorization or approval; (3) Vented or
flared pursuant to State rules or orders,
when such rules have been ratified or
accepted by the Supervisor; or (4)
Otherwise unavoidably lost, as
determined by the Supervisor.93
NTL–4A III. authorizes royalty-free
venting or flaring of gas ‘‘on a short-term
basis’’ without the need for approval
under specified circumstances,
including during: (1) Emergencies; (2)
Well purging and evaluation tests; and
(3) Initial production tests.94 Venting or
flaring is authorized during emergency
situations, such as equipment failures,
for up to 24 hours per incident and up
to 144 cumulative hours per lease per
month.95 NTL–4A III.B. authorizes
venting or flaring ‘‘(d)uring the
unloading or cleaning up of a well
during drillstem, producing, routine
purging, or evaluation tests, not
exceeding a period of 24 hours.’’ 96 In
addition, NTL–4A III.C. authorizes
venting or flaring during initial well
evaluation tests, for up to 30 days or up
to 50 million cubic feet (MMcf) of gas,
whichever occurs first.97 Finally, NTL–
4A II.C. provides that gas vapors that are
released from storage tanks or other lowpressure vessels are considered to be
unavoidably lost, and not subject to
royalties, unless the Supervisor
determines that their recovery is
warranted.98
Over the past 36 years since NTL–4A
was issued, technologies and practices
for oil and gas production have
advanced considerably. The
development of modern hydraulic
fracturing and horizontal drilling
techniques has been especially
significant. We also now have better
technologies for capturing and using gas
on-site, detecting leaks, powering
equipment, controlling vapors from
storage vessels, removing liquids from
gas wells, and many other aspects of
production. Not surprisingly, NTL–4A
neither reflects today’s best practices
and advanced technologies, nor is
particularly effective in requiring their
use to avoid waste. In addition, much of
NTL–4A relies on broad, generalized
directives. As these have been
implemented in the decades since NTL–
4A was issued, there has been ambiguity
and variation regarding the
circumstances under which venting or
flaring requires prior approval, the
circumstances under which venting or
flaring is approved, and the
circumstances under which royalties are
paid on vented and flared gas. There is
also some ambiguity regarding what
properly constitutes royalty-free on-site
use. All of these factors indicate the
need to update NTL–4A.
89 Ibid.
87 See
the BLM oil and gas program’s outreachevents page: https://www.blm.gov/wo/st/en/prog/
energy/public_events_on_oil.
88 44 FR 76600. (Dec. 27, 1979).
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94 Ibid.
90 Ibid.
95 Ibid.
91 Ibid.
96 Ibid.
92 44
97 Ibid.
FR at 76600. (Dec. 27, 1979).
93 Ibid.
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NTL–4A also includes a provision for
assessing the full value of avoidably lost
gas and gas that is vented or flared
without required approval.99 This
provision was subsequently overridden,
however, by the later-enacted
FOGRMA.100 Section 308 of FOGRMA
states, ‘‘Any lessee is liable for royalty
payments on oil or gas lost or wasted
from a lease site when such loss or
waste is due to negligence on the part
of the operator of the lease, or due to the
failure to comply with any rule or
regulation, order or citation issued
under this Act or any mineral leasing
law.’’ 101
NTL–4A’s ‘‘full value’’ policy has not
been enforced since FOGRMA’s
enactment. The proposed rule would
comply with FOGRMA Section 308 and
require payment of royalty, rather than
full value, on all oil and gas that is
avoidably lost.
F. Legal Authority
With this proposed rule, the BLM
aims to update the NTL–4A
requirements for venting, flaring, and
royalty-free uses of oil and natural gas
on BLM-administered leases. The BLM’s
general authority to issue this proposed
regulation derives from various statutes
applicable to onshore Federal lands and
minerals and Indian tribal and allotted
lands, principally the MLA, MLAAL,
FOGRMA, FLPMA, IMDA, IMLA, and
the Act of March 3, 1909.102
The MLA rests on the fundamental
principle that the public should benefit
from mineral production on public
lands.103 A primary instrument for
public benefit is the requirement that a
lessee return a portion of the proceeds
from production to the public through
the payment of royalties to Federal,
State, and tribal governments. For all
competitively issued leases on Federal
lands, the MLA requires a royalty ‘‘at a
rate of not less than 12.5 percent in
amount or value of the production
removed or sold from the lease.’’ 104 The
99 Ibid.
100 30
U.S.C. 1701 et seq.
U.S.C. 1756.
102 See footnote 4.
103 See, e.g., California Co. v. Udall, 296 F.2d 384,
388 (D.C. Cir. 1961) (noting that the MLA was
‘‘intended to promote wise development of . . .
natural resources and to obtain for the public a
reasonable financial return on assets that ‘belong’ to
the public’’). The Indian Mineral Leasing Act also
had the similar purpose of securing for Indian tribes
‘‘the greatest return on their property.’’ Kerr-McGee
v. Navajo Tribe of Indians, 731 F.2d 597, 601 n.3
(internal quotation mark omitted).
104 30 U.S.C. 226(b)(1)(A) and (c)(1); 30 U.S.C. 352
(applying that requirement to leases on acquired
land). The same royalty provision is included in the
lease instruments for leases of Indian tribal and
allotted lands under applicable regulations,
although that rate is set at no less than 16–2/3%,
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BLM is responsible for setting royalty
rates and determining the quantity of
produced oil and gas that is subject to
royalties under the terms and conditions
of a Federal lease. The MLA also
requires the BLM to: Ensure that lessees
‘‘use all reasonable precautions to
prevent waste of oil or gas developed in
the land’’; 105 regulate ‘‘all surfacedisturbing activities conducted pursuant
to any lease issued under (the
MLA)’’; 106 and ‘‘determine reclamation
and other actions as required in the
interest of conservation of surface
resources.’’ 107
In FLPMA, Congress declared it to be
the policy of the United States that the
BLM should manage the public lands
‘‘in a manner that will protect the
quality of scientific, scenic, historical,
ecological, environmental, air and
atmospheric, water resources, and
archeological values; . . . preserve and
protect certain public lands in their
natural condition; . . . provide food and
habitat for fish and wildlife; and . . .
provide for outdoor recreation and
human occupancy and use.’’ 108 In
addition, the BLM is required to manage
public lands under principles of
multiple use and sustained yield under
FLPMA, which include management of
the lands without permanent
impairment of the quality of the
environment.109 The definition of
‘‘multiple use’’ explicitly includes the
consideration of environmental
resources; ‘‘multiple use’’ means a
‘‘combination of balanced and diverse
resource uses that takes into account the
long-term needs of future generations
for renewable and nonrenewable
resources, including, but not limited to,
recreation, range, timber, minerals,
watershed, wildlife and fish, and
natural scenic, scientific, and historical
values.’’ 110 Further, the statutory
definition of ‘‘multiple use’’ constitutes
management in a ‘‘harmonious and
coordinated’’ manner ‘‘without
permanent impairment to the
productivity of the land and the quality
of the environment.’’ 111 Significantly,
FLPMA admonishes the Secretary to
consider ‘‘the relative values of the
resources and not necessarily . . . the
combination of uses that will give the
greatest economic return of the greatest
unit output.’’ 112 FLPMA also mandates
absent approval of the Secretary. 25 CFR 211.41,
212.41.
105 30 U.S.C. 225.
106 30 U.S.C. 226(g).
107 Ibid.
108 Ibid. 1701(a)(8).
109 43 U.S.C. 1702(c), 1732(a).
110 Ibid. (emphasis added).
111 Ibid. (emphasis added).
112 Ibid.
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that the Secretary, ‘‘(i)n managing the
public lands . . . shall, by regulation or
otherwise, take any action necessary to
prevent unnecessary or undue
degradation of the lands.’’ 113
The proposed rule would supplement
BLM onshore lease operations
regulations found at part 3160 of Title
43 of the Code of Federal Regulations
(CFR). The rule would apply to all BLMmanaged leases. The proposed rule
would also apply to business
agreements entered into by tribes (other
than Osage Tribe) and agreements under
the IMDA, as consistent with those
agreements and with principles of
Federal Indian law. Oil and gas
agreements entered into under the
IMDA may or may not provide for a
royalty; if they do, that royalty may or
may not be expressed as a percentage of
the production ‘‘removed or sold from
the lease.’’
The BLM’s authority to require
royalty payments derives from the
above-quoted provision in the MLA: ‘‘A
lease shall be conditioned upon the
payment of a royalty at a rate of not less
than 12.5 percent in amount or value of
the production removed or sold from the
lease.’’ 114 As established in several
judicial decisions, the phrase
‘‘production removed or sold from the
lease’’ exempts from royalty payments
production that is used on the lease for
lease operations.115 Thus, operators may
use oil or gas on the lease royalty-free
to support the productivity of the lease.
For example, a lessee may use produced
gas to power the production
infrastructure.
The proposed rule does not use the
terms ‘‘beneficial purpose’’ and
‘‘beneficial use,’’ which are used in
NTL–4A. Over the years, those terms
appear to have been applied
inconsistently within the BLM, creating
confusion for some in the industry
regarding when production may be used
royalty-free. Instead of referencing
beneficial purposes or use, the proposed
rule would directly address the royaltyfree treatment of various uses of lease
production, and would identify the
situations in which prior written BLM
approval would be required for royaltyfree treatment.
The BLM, through NTL–4A, has long
read the MLA to exempt from royalty
payments production that is
‘‘unavoidably lost’’ in the course of
production.116 Under NTL–4A, in
113 Ibid.
1732(b).
U.S.C. 226(b)(1)(A) (emphasis added).
115 See Marathon Oil Co. v. Andrus, 452 F. Supp.
548, 522–23 (D. Wyo. 1978); Gulf Oil Corp. v.
Andrus, 460 F. Supp. 15, 18 (C.D. Cal. 1978).
116 44 FR 76600.
114 30
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determining when production is
unavoidably versus avoidably lost, the
BLM has generally considered the
technical and economic feasibility of
preventing the loss of gas. Under NTL–
4A, the BLM deems a loss of gas
‘‘avoidable’’—and charges associated
royalties—if it determines that such loss
occurred as a result of: (1) Negligence on
the part of the lessee or operator; (2) The
failure of the lessee or operator to take
all reasonable measures to prevent and/
or to control the loss; and/or (3) The
failure of the lessee or operator to
comply fully with the applicable lease
terms and regulations, appropriate
provisions of the approved operating
plan, or the prior written orders of the
BLM.117 If, on the other hand, the loss
of gas is not the result of operator
negligence and results from certain
specified circumstances, such as
emergencies, well tests, and production
tests, or if the BLM determines that
venting from storage tanks is
‘‘warranted,’’ the BLM deems the loss
‘‘unavoidable’’ and does not charge
associated royalties.118 As discussed
below, however, the BLM has not
always been consistent in applying this
distinction between ‘‘unavoidably’’ and
‘‘avoidably’’ lost gas, creating significant
confusion for both operators and
regulators. The proposed rule seeks to
clarify the distinction, and thereby limit
the need for operators to submit, and
BLM to process, applications for
approval of royalty-free use of gas.
G. Concerns About Loss of Gas
Identified Through Oversight
Several oversight reviews have raised
concerns about waste of gas, found that
the BLM’s existing requirements
regarding venting and flaring are
insufficient, and have identified
concerns about royalty-free use of gas.
They recommended that the BLM
update its regulations and guidance on
royalty-free use and waste prevention.
These include reviews by the
Subcommittee on Royalty Management
of the Royalty Policy Committee (RPC),
which is a Federal advisory committee
to the Department of the Interior; the
Inspector General of the Department of
the Interior; and the GAO.
The RPC’s December 2007 report
entitled, Mineral Revenue Collection
from Federal and Indian Lands and the
Outer Continental Shelf, includes
specific recommendations to the BLM
and the former Minerals Management
Service (MMS (which was subsequently
divided into ONRR, the Bureau of
Ocean Energy Management (BOEM),
117 Ibid.
118 Ibid.
at 76,601.
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and the Bureau of Safety and
Environmental Enforcement.)) The
report emphasized the need for
enhanced verification of production
accountability, and it recommended that
the BLM update relevant pre-1983
(remnant U.S. Geological Survey and
MMS) rules. In recognition of those
needs, the BLM began a process to
implement the recommendations to
improve production accountability
oversight. This proposed rule—along
with other separately proposed rules
dealing with site security and oil and
gas measurement—responds to
recommendations in the RPC’s report. A
March 2010 report by the Department of
the Interior Inspector General also
recommended that the BLM clarify its
requirements for royalty-free use of
gas.119
In October 2010, the GAO issued a
report entitled, Federal Oil and Gas
Leases—Opportunities Exist to Capture
Vented and Flared Gas, Which Would
Increase Royalty Payments and Reduce
Greenhouse Gases. For this audit, the
GAO examined the amounts of natural
gas being vented and flared on Federal
oil and gas leases, and evaluated the
potential for additional capture of
natural gas using available technologies.
The GAO also evaluated what the
associated potential increases in royalty
payments and decreases in GHG
emissions would be from any additional
gas capture.
The GAO found that ‘‘around 40
percent of natural gas estimated to be
vented and flared on onshore Federal
leases could be economically captured
with currently available control
technologies.’’ 120 The GAO further
found that ‘‘Interior’s oversight efforts to
minimize these losses have several
limitations, including that its
regulations and guidance do not
address’’ new capture technologies and
some significant sources of lost gas.121
As the GAO noted, BLM guidance is
over 30 years old and does not address
venting and flaring reduction
technologies that have advanced since it
was issued, such as automated plunger
lift technologies that reduce the amount
of gas vented during liquid unloading
operations or low-bleed pneumatic
devices that can replace the functions of
high-bleed pneumatic devices.122
The GAO recommended that ‘‘to help
reduce venting and flaring of gas by
addressing limitations’’ in the
119 Department of the Interior, Inspector General,
BLM and MMS Beneficial Use Deductions (March
2010), https://www.doioig.gov/sites/doioig.gov/files/
2010-I-00171.pdf.
120 GAO–11–34, Oct. 2010, 2.
121 Ibid. at 34.
122 Ibid. at 27.
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regulations, the ‘‘BLM should revise its
guidance to operators to make it clear
that technologies should be used where
they can economically capture sources
of vented and flared gas, including gas
from liquid unloading, well
completions, pneumatic valves, and
glycol dehydrators.’’123 The GAO
further recommended that the BLM
should ‘‘assess the potential use of
venting and flaring reduction
technologies to minimize the waste of
natural gas’’ before production occurs,
and that the BLM should consider
expanded use of infrared cameras to
improve reporting and identify
opportunities to minimize lost gas.124
This proposed regulation responds to
these recommendations as well.
In addition, multiple public advocacy
organizations have recently raised
concerns about the waste of gas in oil
and gas production operations, and
recent State regulatory actions to reduce
venting and flaring indicate that some
States share these concerns as well.125
H. Volumes of Lost Natural Gas
1. Data Sources on Lost Gas
While concerns have been growing
over rising quantities of lost gas, there
is no single definitive estimate on the
volume of these losses from Federal and
Indian leases. One relevant source of
information for estimating the volumes
of waste is the Oil and Gas Operations
Report Part B (OGOR–B) that producers
from BLM-administered leases file each
month with ONRR to report quantities
of gas removed from their leases.
Another key source of information is the
EPA Inventory of Greenhouse Gas
Emissions and Sinks (2015) (‘‘EPA GHG
Inventory’’), which is an annual report
that estimates the total national GHG
emissions and removals associated with
human activities across the United
States. Additional information is drawn
from the EPA Greenhouse Gas Reporting
Program (GHGRP), which collects GHG
data from large emitting facilities,
suppliers of fossil fuels and industrial
gases that result in GHG emissions
when used. Additional emissions
quantification data was presented by
ICF in a publication entitled, Onshore
Petroleum and Natural Gas Operations
on Federal and Tribal Lands in the
United States.126 With respect to oil and
gas production, some of these sources
estimate releases of natural gas, while
123 Ibid.
at 34.
at 34.
125 See discussion in Section I.1 of this preamble.
126 ICF, Onshore Petroleum and Natural Gas
Operations on Federal and Tribal Lands in the
United States (June 2015) (SHORT FORM—ICF
2015).
124 Ibid.
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others estimate methane emissions.
Natural gas is primarily composed of
methane, however, and translating back
and forth between the two types of
estimates is a relatively straightforward
calculation.
The data collected by ONRR includes
operators’ estimates of gas vented and
flared-during production from each
Federal and Indian lease. These data do
not include any estimates of natural gas
lost through leaks, or from routine
operation of pneumatic devices, storage
vessels, compressors, or glycol
dehydrators (equipment that circulates
the chemical glycol in gas to absorb
moisture). In addition, the GAO found
that there is variation across BLM
offices as to whether operators must
report certain other types of natural gas
losses on their OGOR-Bs. Specifically,
operators varied in whether they
included quantities of vented or flared
gas where the BLM had authorized the
venting or flaring or where the
quantities were under the BLM’s
permissible limits. Operators are also
not always required to meter the
quantities of vented or flared gas
reported on their OGOR-Bs. Instead they
may use BLM-approved methods to
estimate the quantities to be reported.
So while the ONRR data are highly
relevant, they provide information about
a subset of gas wasted and there is some
uncertainty regarding the accuracy of
the estimates the data do include. In
reviewing these data, the GAO found
that they ‘‘likely underestimate venting
and flaring because they do not account
for all sources of lost gas.’’127
For purposes of this proposed rule,
ONRR provided the BLM with 6 years
of vented and flared volumes reported
on the OGOR-Bs. The data analyzed
included gas flared and vented from
both oil wells and gas wells from 2009
through 2014. During this period,
operators reported that they vented or
flared a total of 375 Bcf of natural gas,
or about 2.6 percent of the 14.6 Tcf of
natural gas that was produced from
BLM-administered leases from 2009
through 2014. This is enough natural
gas to supply about 5 million
households—or every household in the
States of Colorado, Montana, New
Mexico, Utah, and Wyoming—for 1
year.128 These data are reported by
operators on BLM-administered leases,
but the production is actually derived
from lands with various ownership
patterns. Of the vented and flared gas
reported to ONRR, 15.2 percent came
from wells extracting only Federal
127 GAO–11–34,
Oct. 2010.
U.S. Census Bureau Total Households
as of 2013 (latest data available).
128 Using
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minerals; 9.0 percent from Indian
ownership, and 75.8 percent from
mixed ownership (some combination of
Federal, Indian, fee (private) and State
land). While all of the natural gas flared
or vented from the Federal and Indian
lands categories originates from the
Federal and Indian mineral estates, only
a portion of the natural gas flared or
vented from the mixed ownership
category originates from the Federal and
Indian mineral estates.
Data in the EPA GHG Inventory can
be used to calculate a more complete
estimate of gas losses from venting and
leaks from BLM-administered leases,
which is discussed in more detail in the
Regulatory Impact Analysis (RIA) for
this rule. Using data from the GHG
Inventory, we estimate that about 167
Bcf of natural gas was released or vented
to the atmosphere from all U.S. onshore
oil and gas leases in 2013, the most
recent year for which estimates are
currently available. In that year,
production from Federal and Indian
leases accounted for 12.7 percent of the
U.S. natural gas production and 7.43
percent of the U.S. crude oil
production.129 Because we expect the
national emissions level to be generally
representative of what we would expect
on Federal and Indian lands, we derived
emissions estimates largely by applying
the Federal and Indian share of
production to the national emissions
estimate.130 The analysis of these data
sources indicates that roughly 22 Bcf of
natural gas was lost from BLMadministered leases through venting and
leaks in 2013.
In addition, the ONRR data indicate
that operators reported flaring 76 Bcf of
natural gas from BLM-administered
leases in 2013 (the most recent year for
which data are available). Of this, ONRR
estimates that about 44 Bcf was gas from
the Federal and Indian mineral estate
(as opposed to gas from State or private
mineral estates that is being extracted
through a well that is producing from a
mix of Federal, Indian, State or private
mineral estates).131
Thus, for purposes of this proposal,
our best estimate is that 98 Bcf of
natural gas was vented, leaked, or flared
from BLM-administered leases in
2013,132 of which 66 Bcf originated from
the Federal and Indian mineral
estates.133 The 66 Bcf of vented or flared
gas represents about 2.3 percent of total
129 Based on updated EIA production crossed
against ONRR Federal production data.
130 For additional detail on these calculations, see
RIA App. 7.
131 RIA at 19.
132 That is, 22 Bcf vented or leaked (per EPA GHG
Inventory data), and 76 Bcf flared (per ONRR data).
133 RIA at 3.
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Federal and Indian production from
these leases in 2013, and is enough gas
to supply almost 900,000 homes each
year.134 This is consistent with ICF’s
estimate that fugitive sources, vented
emissions and flared emissions from
Federal and Indian onshore leases
amounted to 66 Bcf of natural gas in
2013.
Based on available data, the problem
of natural gas loss on BLM-administered
leases is also growing. The total
amounts of annual reported flaring from
Federal and Indian leases increased by
109 percent from 2009 through 2013.135
During this period, reported volumes of
flared oil-well gas increased by 292
percent, while reported volumes of
flared gas-well gas decreased by 75
percent.136 The reduction in flaring at
gas wells coincides with the adoption of
EPA air pollution requirements limiting
emissions from gas wells hydraulically
fractured after August 2011.
Another indicator of the increase of
flaring on Federal and Indian lands is
the increase of applications to vent or
flare received by the BLM. In 2005, the
BLM received just 50 applications to
vent or flare gas. In 2011, the BLM
received 622 applications, and this
doubled again within 3 years to 1,248
applications in 2014. BLM field offices
indicate that most of the additional
applications were for flaring in New
Mexico, Montana, the Dakotas, and, to
a lesser extent, Wyoming.137
In addition to considering the
quantity of gas that is lost now, it is also
important to consider the potential
future quantities of lost gas, and to
evaluate the future sources of such
losses. One source of information on
this question is a study by ICF entitled,
Economic Analysis of Methane Emission
Reduction Opportunities in the U.S.
Onshore Oil and Natural Gas Industries,
issued in March 2014. The ICF Study
estimated methane emissions from
onshore oil and gas production in 2018
based on a 2011 baseline. It found that
absent regulation, emissions are
projected to grow 4.5 percent from 2011
through 2018, and almost 90 percent of
emissions in 2018 would come from
sources that were already operating
prior to 2012.138 Based on this
information, the BLM believes that it is
important for the proposal to address
waste from both new sources and
134 Based on an estimate of 74 Mcf of gas used
per household per year. See footnote 2.
135 RIA at 201.
136 Ibid.
137 BLM data extracted from AFMSS in response
to media inquiry, October 2014.
138 ICF 2014 Study.
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sources that already exist at the time of
the final rule.
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2. Additional Information on Loss
Estimates
The BLM developed the emissions
estimates discussed in the preamble and
RIA using the best data available at the
time. Some of the data produced by EPA
and ONRR, such as the EPA estimates
of the quantities of gas lost through
leaks, and emergency releases reported
to ONRR by the operators, rely on
emissions factors, which have been
developed by the EPA. These emissions
factors are usually based on
representative measured data and are
applied to activity data to calculate
estimated emissions. The ONRR relies
primarily on self-reporting by industry,
subject to agency audits.
Annually, EPA reviews new
information as it becomes available, and
the GHG Inventory continues to be
refined to reflect new information
available. For example, EPA notes the
availability of new data in its GHG
Inventory, including data and
information that are becoming available
through EPA’s GHGRP and external
studies, allowing EPA to re-evaluate and
make updates to GHG Inventory data, as
applicable.
Several recently completed academic
studies aim to improve our
understanding of the quantity of natural
gas and petroleum system emissions,
and more such studies are underway. In
general, there are two major types of
studies related to oil and gas GHG data:
So-called ‘‘bottom up’’ studies that
focus on measurement or quantification
of emissions from specific activities,
processes, and equipment (e.g., EPA’s
Greenhouse Gas Reporting Program data
and many of the series of studies being
conducted by the Environmental
Defense Fund, academic researchers,
and industry, discussed below), and
‘‘top down’’ studies that focus on
verification of estimates at the regional
scale through methods such as airborne
mass balance, atmospheric transport
models, and enhancement ratios with
well-constrained pollutants, along with
approaches such as inverse modeling
(e.g., National Oceanic and Atmospheric
Administration (NOAA) verification
studies), which measure atmospheric
levels of emissions and attempt to
allocate contribution among potential
sources. The first type of study can lead
to direct improvements to or verification
of inventory estimates. The second type
of study can provide general indications
of potential over- and under-estimates
in existing data. Several of these recent
studies are discussed below.
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An article published last year in the
peer-reviewed journal Science reviewed
20 years of technical literature on
natural gas emissions in the U.S. and
Canada and compared various
emissions estimates from top down (e.g.,
aircraft) and bottom up (e.g., inventory)
studies. The authors found that
inventories consistently underestimate
actual methane emissions.139 Similarly,
a study published in May 2014 by
researchers from NOAA and the
University of Colorado, Boulder,
estimated methane emissions from oil
and gas production areas using
atmospheric hydrocarbons gathered
while flying over the Denver-Julesberg
Basin. This study estimated that hourly
methane emissions from oil and gas
sources in that basin are three times
higher than would be expected based on
estimates derived from data reported
under the EPA GHGRP.140
Beginning in 2012, the Environmental
Defense Fund began working with about
100 universities, research institutions
and companies on a multi-pronged
scientific research effort to develop a
clearer picture of methane losses across
the U.S. natural gas supply chain.
Several studies from this effort, in
addition to the NOAA and Science
studies discussed above, are particularly
relevant to this rulemaking.
For example, researchers at the
University of Texas, Austin, in Phase 1
of their production studies, published in
September 2013, found that methane
emissions from equipment leaks and
pneumatic devices were larger than
previously thought.141 The study
focused on methane emissions at 190
sites (focusing on ongoing production
activity and well completion emissions)
operated by nine natural gas companies.
It also found that emissions from well
completions were smaller than
previously thought (apparently due to
the EPA’s requirement for reduced
emission completions, which can
reduce venting from well completions
by 99 percent).142 Phase II of the study,
which looked at wells operated by 10
139 A. R. Brandt et al., Methane Leaks from North
American Natural Gas Systems, Science, 733 (Feb.
14, 2014), https://www.sciencemag.org/content/343/
6172/733.full.
140 Gabrielle Petron et al., A new look at methane
´
and nonmethane hydrocarbon emissions from oil
and natural gas operations in the Colorado DenverJulesburg Basin, Journal of Geophysical Research:
Atmospheres, 6836 (June 3, 2014), https://
onlinelibrary.wiley.com/doi/10.1002/
2013JD021272/pdf.
141 David T. Allen et al., Measurements of
Methane Emissions at Natural Gas Production Sites
in the United States, 17768 (Oct. 2013), The
Proceedings of the National Academy of Sciences
of the United States of America, 17768 (Oct. 2013),
https://www.pnas.org/content/110/44/17768.full.pdf.
142 Ibid, 17769–70.
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companies, found that for emissions
from liquids unloading and pneumatic
devices, a small percentage of sources
account for the majority of the
emissions from these categories.143
Nineteen percent of pneumatic devices
produced 95 percent of the emissions
that were attributable to the devices,
while 20 percent of wells that vented
during liquids unloading produced 65
to 83 percent of the emissions from
those sources.144 The study further
found that average emissions from
pneumatic controllers are higher than
EPA’s previous estimates, which are the
basis for the emissions factors used in
calculating gas waste.145
A February 2015 study from Colorado
State University, entitled Measurements
of Methane Emissions from Natural Gas
Gathering Facilities and Processing
Plants: Measurement Results,146 found
wide variations in the amount of
methane leaking at gathering and
processing facilities. Another study,
Analyzing Methane Emissions from
Upstream Oil and Gas Production
Operations,147 conducted by researchers
at the Houston Advanced Research
Center and the EPA, analyzed fence line
data on methane emissions at well
production sites. It found that
unpredictable events, such as
malfunctions and leaks, likely have a
strong influence on emissions rates.148
In addition, a recent study questions the
accuracy of the sampler used in the
University of Texas and other studies.
The new study, published in the journal
Energy Science & Engineering, asserts
that the University of Texas researchers
used a sampler that can fail under
certain conditions, leading to ‘‘severe’’
underreporting of natural gas
emissions.149 Other sources of
information also reinforce concerns
about the volumes of lost gas. In October
2014, an analysis of satellite
measurements from 2002–2012 by
143 David T. Allen et al., Methane Emissions from
Process Equipment at Natural Gas Production Sites
in the United States: Pneumatic Controllers, 636
(Dec. 9, 2014), Environmental Science and
Technology, available at https://pubs.acs.org/doi/
abs/10.1021/es5040156.
144 Ibid.
145 Ibid. at 638.
146 Austin L. Mitchell et al., Measurements of
Methane Emissions from Natural Gas Gathering
Facilities and Processing Plants: Measurement
Results, 3219 (Feb. 2015), Environmental Science
and Technology, available at https://pubs.acs.org/
doi/abs/10.1021/es5052809.
147 Birmur Guven et. al., Analyzing Methane
Emissions from Upstream Oil and Gas Production
Operations, (Nov. 2014).
148 Ibid.
149 Howard, Touche, University of Texas study
´
underestimates national methane emissions at
natural gas production sites due to instrument
sensor failure, Energy Science & Engineering (Aug.
4, 2015).
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scientists from the National Aeronautics
and Space Administration (NASA) and
the University of Michigan identified a
2,500-square-mile (about half the size of
the State of Connecticut) concentration
of methane located over the Four
Corners area in Arizona, Colorado, New
Mexico, and Utah.150 The study’s lead
author indicated that the emissions
likely come from natural gas production
and processing equipment (although not
from hydraulic fracturing, as much of
the data predates its upsurge) in the San
Juan Basin in New Mexico, which
produces natural gas from conventional
gas production, oil production, and
coalbed methane.151
On the other hand, another recent
study found that methane
measurements taken by aircraft in some
natural gas production basins track well
with the EPA’s GHG Inventory
estimates.152 Data indicate that
emissions from gas production activities
vary from basin to basin. This variation
may be due to characteristics of the
natural gas, the amount of natural gas
processing that is necessary, and the
condition of the natural gas gathering,
compression and transportation system.
Also, some of the older studies may
tend to overestimate current losses in
some respects, as recent EPA and State
regulations, as well as voluntary actions
by industry, have substantially reduced
the volumes of gas lost from some
sources, such as gas well completions.
Most recently, a new study by Zavala
et al., published in the Proceedings of
the National Academy of Sciences,
developed new techniques to reconcile
bottom up and top down estimates of
methane emissions from oil and gas
production in the Barnett Shale region
in Texas.153 This study found that in
this region, methane emissions from oil
and gas production and processing are
almost twice as high as would be
estimated based on the EPA GHG
Inventory, and are 3.5 times higher than
would be estimated based on EPA
GHGRP data.154 It further found that the
emissions from these sources in this
150 NASA news release, Oct. 9, 2014 available at
https://www.nasa.gov/press/2014/october/satellitedata-shows-us-methane-hot-spot-bigger-thanexpected/#.VLbQ0PnF9sE.
151 Ibid.
152 Jeff Peischl, T. B. Ryerson, K. C. Aikin, J. A.
de Gouw, J. B. Gilman, J. S. Holloway, B. M. Lerner,
R. Nadkarni, J. A. Neuman, J. B. Nowak, M. Trainer,
C. Warneke, D. D. Parrish, Quantifying atmospheric
methane emissions from the Haynesville,
Fayetteville, and northeastern Marcellus shale gas
production regions, Journal of Geophysical
Research: Atmospheres, 120 (5), pp. 2119–2139.
153 Zavala-Araiza et al., Reconciling divergent
estimates of oil and gas methane emissions,
Proceedings of the National Academy of Sciences,
vol. 112, no. 51, 15597–15602 (Dec. 22, 2015).
154 Ibid. at 15599.
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region are dominated by a relatively
small number of high emitters, with, at
any given time, 2 percent of the
facilities contributing half of the
emissions, and 10 percent contributing
90 percent of the emissions.155
The BLM expects that additional
studies will use bottom-up and topdown data comparisons to continue to
refine emissions estimates for these
sources. The presence, distribution, and
effect of super-emitters, which are often
defined as sources with exceptionally
high emissions as compared to similar
sources (essentially malfunctioning
equipment), is also being further
studied. Overall, these studies and
alternative sources of data suggest that
the BLM’s estimates of lost gas likely
underestimate, and potentially
substantially underestimate, the extent
of the problem.
I. Examples of and Gaps in Existing
Waste-Reduction and Related Efforts
1. State Activities
In developing the proposed rule, we
have consulted with State regulators
and reviewed State requirements related
to waste of oil and gas resources. Like
the MLA, most State laws and
regulations prohibit or encourage
prevention of waste of these resources.
But specific State requirements, and the
outcomes they produce, vary widely.
This variability reinforces the need for
this rule to update standards for oil and
gas operations on Federal and Indian
lands. In developing the proposed rule,
we also looked to some of the most
effective State approaches as models. In
particular, we have drawn on new
requirements recently adopted by
Colorado and North Dakota to address
rising rates of flaring, resource losses,
and other impacts. Below we summarize
how several States have approached
these issues.
(a) Alaska
The State of Alaska adopted
regulations in the 1970s to address high
rates of flaring.156 Since then, the State
has prohibited venting or flaring of gas
except in narrowly defined
circumstances: Testing a well before
regular production; fuel that maintains
a continuous flare; de minimis venting
of gas incidental to normal oil field
operations; and flaring or venting gas for
no more than 1 hour during an
emergency or operational upset.157 The
practical effect of this prohibition has
155 Ibid.
at 15600.
Administrative Code Title 20—Chapter
25 235, Gas Disposition, available at https://
doa.alaska.gov/ogc/Regulations/RegIndex.html.
157 Ibid.
156 Alaska
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been widespread reinjection of
associated gas into the field for
conservation and oil recovery
purposes.158 Alaska estimates that
roughly 0.4 percent of gas production is
flared, which is far lower than in most
other States.159
(b) Colorado
The State of Colorado has reduced
venting and flaring through air quality
regulations directed at emissions of
hydrocarbons and VOCs from the oil
and natural gas industry.160 The
Colorado Department of Public Health
and Environment, Air Quality Control
Commission has instituted regulations
similar in many ways to the EPA’s
existing NSPS for new and modified
hydraulically fractured gas wells and
gas processing facilities.161 The
Colorado regulation includes some
aspects of EPA’s NSPS, and expands on
the EPA standards in other areas. For
example, the Colorado rule requires
reduced emissions completions for most
oil and gas well completions and
recompletions, whereas EPA’s NSPS
currently applies only to hydraulically
fractured or refractured gas well
completions in developed gas fields.
Colorado has also adopted some
requirements that are independent of
the EPA NSPS. For instance, under the
reduced emissions completion process,
operators must minimize venting ‘‘to the
maximum extent practicable.’’ 162
In addition to requiring green
completions, Colorado’s rules: Establish
requirements for pneumatic
controllers;163 require a comprehensive
LDAR program;164 set standards for
liquids unloading;165 establish emission
standards for storage vessels;166 and
require storage tank emissions
management (STEM) plans, which
would identify strategies to minimize
emissions from storage vessels during
normal operations.167 BLM has several
memoranda of understanding with the
Colorado Oil and Gas Conservation
158 Telephone call with BLM staff and State of
Alaska, Oil and Gas Conservation Commission
(April 30, 2015).
159 Ibid.
160 Colorado Air Quality Control Commission
Regulations, Regulation 7, Control of Ozone via
Ozone Precursors and Control of Hydrocarbons via
Oil and Gas Emissions (Emissions of Volatile
Organic Compounds and Nitrogen Oxides).
161 For further information about EPA’s NSPS
standards for this source category, see Section IV.I.3
of this preamble below.
162 Colorado Air Quality Control Commission
Regulations, Regulation 7, 5 CCR 1001–9, Sections
XII, XVIII.
163 Ibid. at Section XVIII.
164 Ibid. at Section XVII.F.
165 Ibid. at Section XVII.H.
166 Ibid. at Sections XII.D–F; XVII.C.
167 Ibid. at Section XVII.C.2.
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Commission regarding permitting,
inspection, and enforcement relating to
oil and gas activities on BLM lands.168
(c) Montana
The State of Montana has had limits
on venting and flaring in place since the
1970s. Produced gas vented to the
atmosphere at a rate exceeding 20 Mcf
per day that continues for more than 72
hours must be burned.169 After
completion of a gas well, no gas may be
permitted to escape, except gas required
for periodic testing or cleaning of the
well bore.170 If, after well completion,
the operator intends to flare gas
production in excess of 100 Mcf per
day, the operator must obtain a variance
from the oil and gas board.171 The
operator must submit a production test
and a statement justifying the need for
a variance, including information such
as potential human exposure; relative
isolation of location; measures to restrict
public access to the location; low gas
volume; and low BTU content.172 The
board may elect to restrict production
until the gas is marketed or otherwise
beneficially used.173
(d) North Dakota
North Dakota has experienced a rapid
increase in oil production in recent
years. A byproduct of this development
is more natural gas being produced than
can be processed and transported to
market through existing pipeline
infrastructure. Without access to a
market, much of the associated natural
gas continues to be flared.
In March 2013, the North Dakota
Industrial Commission adopted a policy
to reduce flaring, and it followed this
with an enforceable order adopted in
July 2014 and modified in September
2015.174 The policy and order require
well operators to meet flaring reduction
targets according to a prescribed time
line.175 The gas capture requirements
for each operator include a target of
capturing at least 74 percent of
production by October 2014.176 The
target then rises over time to a target of
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168 The
MOUs are available at https://
cogcc.state.co.us/gov.html#/federal.
169 Administrative Rules of Montana, Section
36.22.1221(1).
170 Ibid. at 36.22.1219.
171 Ibid. at 36.22.1220(1–2).
172 Ibid. at 36.22.1221(2).
173 Ibid. at 36.22.1221(3).
174 North Dakota Industrial Commission Order
No. 24665 (July 1, 2014), available at https://www.
dmr.nd.gov/oilgas/or24665.pdf; North Dakota
Industrial Commission Order No. 24665 Policy/
Guidance Version 102215, available at https://www.
dmr.nd.gov/oilgas/GuidancePolicyNorthDakota
IndustrialCommissionorder24665.pdf.
175 Ibid.
176 Ibid.
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capturing at least 91 percent of
production by October 2020.177 The
operator may show compliance with the
target at each well, or on a field, county,
or statewide basis.178
North Dakota’s policy includes
additional requirements intended to
help operators reach the targets.179 One
component of the policy requires that
all applications for permits to drill be
accompanied by gas capture plans.180
The State’s goal is to ensure that options
for capturing any natural gas discovered
are fully evaluated before a well is
drilled. North Dakota also requires the
gas capture plan to be provided to
midstream processing companies so
they can plan accordingly.181
The policy provides for oil production
to be restricted from wells where the
operator does not meet the flaring
reduction targets.182 Production is
restricted to no more than 200 bbl of oil
per day for those wells capturing more
than 60 percent of the gas production,
but less than the applicable target
percentage.183 Production is restricted
to no more than 100 bbl of oil per day
from those wells capturing less than 60
percent of produced gas.
(e) Pennsylvania
In August 2013, the Pennsylvania
Department of Environmental Protection
issued guidance that exempted from
certain air quality permitting
requirements oil and gas exploration,
development, and production facilities
and associated equipment and
operations that implemented the
following: An LDAR program consistent
with relevant EPA regulations; VOC
emission controls on all storage tanks; a
2.7 tpy limit on VOC emissions from all
facility sources; certain limitations on
flaring activities; and hourly, daily,
seasonal, and annual limits on NOx
emissions.184
(f) Utah
The Utah Department of
Environmental Quality issued a General
Approval Order on June 5, 2014, that
applies to new and modified oil and gas
well sites and tank batteries. Among
other provisions, this order requires
pneumatic controllers to be low bleed or
177 Ibid.
178 Ibid.
179 Ibid.
180 Ibid.
181 Ibid.
182 Ibid.
183 Ibid.
184 Pennsylvania Department of Environmental
Protection, Air Quality, Air Quality Permit
Exemptions, https://www.elibrary.dep.state.pa.us/
dsweb/Get/Document-96215/275-2101-003.pdf
(August 10, 2013) at 8–11.
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route the emissions to a flare or capture
device; pneumatic pumps route
emissions to a flare or capture device;
and requires operators to inspect for
leaks at least annually, and more
frequently for sources with greater
throughput levels.185
(g) Wyoming
The Wyoming Department of
Environmental Quality adopted
regulations in June 2015, to reduce
emissions of VOCs from storage vessels,
pneumatic controllers, pneumatic
pumps, glycol dehydrators, and leaks in
the Upper Green River Basin
nonattainment area.186 Among other
things, the rule requires emissions from
vessels with uncontrolled VOC
emissions from flashing of 4 tpy or more
to be controlled by 98 percent,187
emissions from pneumatic pumps to be
controlled by 98 percent,188 high-bleed
pneumatic controllers to be replaced
with low-bleed controllers,189 and
operators to establish LDAR programs
with at least quarterly inspections.190
2. Voluntary Industry Efforts
The oil and gas industry has also
recognized concerns about the rising
quantities of flared and vented gas, and
has begun to take voluntary steps to
reduce gas losses. For example, oil and
gas companies developed the
technologies for green completions.191
Individual companies voluntarily use
some of the approaches proposed here
to reduce their natural gas losses
through venting, flaring, and leaks and
boost profitability.
Many of these efforts have been
initiated by companies participating in
Natural Gas STAR, a voluntary EPAindustry partnership program that
encourages oil and natural gas
companies to adopt cost-effective
technologies and practices that improve
operational efficiency and reduce
methane emissions. Twenty-six
companies in the production sector
currently participate in Natural Gas
STAR. Partners in this program have
185 State of Utah, Department of Environmental
Quality, Division of Air Quality, Approval Order:
General Approval Order for a Crude Oil and
Natural Gas Well Site and/or Tank Battery, DAQE–
AN1492500001–14 (June, 5, 2014).
186 Wyoming, Nonattainment Area Regulations
Ch. 8 (June 2015), available at https://soswy.state.wy.
us/Rules/RULES/9868.pdf.
187 Ibid. at Section 6(c)(i)(A).
188 Ibid. at Section 6(e).
189 Ibid. at Section 6(f).
190 Ibid. at Section 6(g).
191 See, e.g., EPA, Lessons Learned from Natural
Gas STAR Partners, Reduced Emissions
Completions for Hydraulically Fractured Natural
Gas Wells, available at https://www3.epa.gov/
gasstar/documents/reduced_emissions_
completions.pdf.
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pioneered some of what are now the
most widely-used, innovative
technologies and practices to reduce
methane emissions. These include green
completions for hydraulically fractured
wells, artificial lift systems for well
maintenance, pneumatic controllers and
pumps with no or low gas releases, and
infrared cameras for leak detection.
Natural Gas STAR partners from the oil
and gas production sector reported that
they achieved about 50 Bcf of methane
emissions reductions in 2013.192
To further encourage emissions
reductions from the oil and gas sector,
the EPA announced, in July 2015, a
voluntary program called the Natural
Gas STAR Methane Challenge, in which
companies would make ambitious
commitments to reduce methane
emissions and would track their
progress in achieving those
reductions.193
In addition, six oil and gas companies
have joined together to form the One
Future Coalition, which aims to
‘‘(e)nhance the energy delivery
efficiency of the natural gas supply
chain by limiting energy waste and by
achieving a methane ‘leak/loss rate’ of
no more than one percent.’’ 194 These
companies aim ‘‘to develop yearly,
sliding-scale emission intensity goals for
the entire value chain and each sector
within the value chain,’’ and use a
flexible approach to achieve
reductions.195
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3. EPA Air Quality Requirements
While EPA does not regulate waste of
oil and gas resources, certain air
pollution regulations applicable to the
oil and gas production sector have the
co-benefit of also reducing waste of
natural gas. Because the air pollutants
regulated by EPA are contained in
natural gas, many of the control options
for reducing emissions operate by
limiting the release (and hence loss) of
natural gas. To the extent that EPA rules
under the Clean Air Act address some
aspects of the waste issue, the BLM
intends to coordinate its requirements
with the EPA as far as possible, to
192 EPA Natural Gas STAR, Accomplishments,
https://www3.epa.gov/gasstar/accomplishments/
index.html.
193 EPA Natural Gas Star Methane Challenge,
Program Proposal, https://www3.epa.gov/gasstar/
methanechallenge/.
194 International Business Times, ‘‘Six Major Oil
and Gas Firms Agree to Cut Potent Methane
Emissions Ahead of UN Climate Change Summit,
(Sept. 23, 2014), https://www.ibtimes.com/six-majoroil-gas-firms-agree-cut-potent-methane-emissionsahead-un-climate-change-summit-1693517; https://
www.gastechnology.org/CH4/Documents/FijiGeorge-CH4-presentation-Sep2014.pdf.
195 Our Nation’s Energy (ONE) Future Coalition,
https://www.gastechnology.org/CH4/Documents/fijiGeorge-CH4-presentation-Sep2014.pdf.
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ensure that industry is not burdened by
duplicative or conflicting requirements.
The EPA rules will include both
standards that EPA adopted in 2012,
which are largely focused on natural gas
wells and infrastructure, and the 40 CFR
part 60 subpart OOOOa rulemaking,
which addresses additional categories of
new and modified sources in the oil and
gas production sector.
In 2012, EPA adopted NSPS to limit
the release of VOCs from new and
modified hydraulically-fractured natural
gas wells, certain new or modified
sources located at well sites, natural gas
processing plants, or natural gas
gathering and boosting stations.196
These standards require new
hydraulically fractured gas wells to use
a process termed a ‘‘reduced emission
completion’’ or ‘‘green completion’’ to
capture natural gas that would
otherwise be released in the wellcompletion process.197 EPA estimated
that this requirement reduces VOC
emissions from the hydraulic fracturing
process by 95 percent.198 EPA allows for
flaring instead of green completions for
new exploratory or delineation wells, on
the assumption that these types of wells
are generally not near pipeline
infrastructure to transport captured gas.
EPA also does not require green
completions for wells where there is not
sufficient pressure to route the gas to a
gathering line, instead allowing
operators to flare the gas that would
otherwise be released.
The 2012 standards also require
operators to use certain types of new
and modified equipment at natural gas
processing plants and gathering and
boosting stations. The standards limit
VOC emissions from centrifugal
compressors and establish maintenance
requirements for reciprocating
compressors.199 The standards also
apply to new and modified high-bleed
pneumatic controllers powered by
natural gas, which are defined as
pneumatic controllers that emit more
than 6 scf/hour.200 The standards limit
the bleed rate for pneumatic controllers
at well sites and gathering and boosting
stations to 6 scf/hour, and they require
zero VOC emissions from pneumatic
controllers located at processing
196 U.S. EPA, Oil and Natural Gas Sector: New
Source Performance Standards and National
Emission Standards for Hazardous Air Pollutants
Reviews; Final Rule, 77 FR 49490 (Aug. 16, 2012).
197 40 CFR 60.5375.
198 U.S. EPA, Overview of Final Amendments to
Air Regulations for the Oil and Natural Gas Sector,
Fact Sheet, available at https://www3.epa.gov/
airquality/oilandgas/pdfs/20120417fs.pdf.
199 40 CFR 60.5380; 40 CFR 60.5385.
200 40 CFR 60.5390.
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plants.201 In practice, this standard
requires operators to replace high-bleed
pneumatic controllers with low-bleed or
no-bleed devices. New, modified, and
reconstructed storage vessels at these
locations (including well sites) are also
covered by the 2012 requirements.202
They require new storage vessels with
VOC emissions of at least 6 tpy to
reduce those emissions by at least 95
percent.203 In addition, the 2012
standards strengthened existing leak
detection standards for natural gas
processing plants.204
On September 18, 2015, EPA
published a notice of proposed
rulemaking that proposes NSPS
standards to be codified as 40 CFR part
60 subpart OOOOa.205 The EPA
proposes to establish both methane and
VOC standards for several emission
sources not covered by the 2012 NSPS,
including hydraulically fractured oil
well completions, pneumatic pumps,
and fugitive emissions from well sites
and compressor stations. In addition,
the EPA proposed methane standards
for certain emission sources that are
currently regulated for VOCs but not for
methane, and proposed to extend VOC
standards and create methane standards
for equipment used widely in the
industry.206
In addition, the EPA proposed to
issue Control Technique Guidelines
(CTGs), which States could adopt in
nonattainment areas to reduce methane
emissions from existing sources in the
oil and gas production sector.207
4. Need for BLM Requirements
While the proposed EPA standards
are expected to reduce methane
emissions from certain new and
modified oil and gas production
facilities, they would not be sufficient to
meet the goals of BLM’s proposed rule
for several reasons. First, the proposed
EPA regulations do not include any
provisions to reduce flaring of
associated gas during normal
production operations. Second, even
with respect to the natural gas waste
from venting, the EPA regulations
would apply only to new and modified
sources, whereas this proposal would
reach existing sources as well. In States
that choose to adopt the CTGs, those
guidelines would apply to existing
sources, but the guidelines are designed
to reduce emissions in nonattainment
201 Ibid.
202 40
CFR 60.5395.
203 Ibid.
204 40
CFR 60.5400.
FR 56593, Sept. 18, 2015.
206 Ibid.
207 Ibid.
205 80
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areas, and very little oil and gas is
produced from BLM-administered
leases in such areas. Third, because the
EPA’s legal authorities differ from those
of the BLM, the proposed EPA
regulations do not cover all BLMregulated activities, such as well
maintenance and liquids unloading.
Similarly, of the States with extensive
oil and gas operations on BLMadministered leases, only one has
comprehensive requirements to reduce
flaring, and only one has comprehensive
statewide requirements to control losses
from venting and leaks. Moreover, State
regulations do not apply to BLMadministered oil and gas leases on
Indian lands, and States do not have a
statutory mandate to reduce waste of
Federal oil and gas.
In addition, the BLM has regulated oil
and gas operations on Federal and
Indian leases for decades to prevent
waste, conserve resources, and protect
public lands. The BLM has the
responsibility and experience to ensure
that these valuable public resources are
extracted in a safe manner, while
minimizing harm to local communities
and the environment and ensuring fair
returns to Federal taxpayers and tribes.
We have existing requirements that are
intended to serve these purposes, but
NTL–4A is over 3 decades old and is no
longer adequate in meeting these goals.
Thus, the proposed rule would update
NTL–4A, and would do so in
coordination with the concurrent EPA
rulemaking. In addition, the proposed
rule would make provision for State and
tribal programs that address flaring or
venting.
V. Discussion of the Proposed Rule
The proposed rule would require
operators to limit waste of gas through
flaring and venting, clarify the
situations in which flared gas would be
subject to royalties, conform the royalty
terms applicable to competitive leases
with the corresponding statutory
language, and clarify the on-site uses of
gas that are exempt from royalties. In
addition, the BLM is proposing to
require operators to record and report
information related to venting and
flaring of gas, and is taking comment on
how best to make this information more
available to the public. This section of
the preamble also includes a discussion
of how today’s proposal relates to the
planning process for lands subject to
BLM administration, although this rule
would not make any regulatory changes
to the planning process itself.
A. Measures To Reduce Waste
The BLM has identified several key
points in the production process where
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waste-prevention actions would be most
effective and least costly. Specifically,
we propose to focus on reducing waste
from the following: Flaring of associated
gas from producing oil wells; gas leaks
from equipment and facilities located at
the well site, as well as from
compressors located on the lease;
operation of high-bleed pneumatic
controllers and certain pneumatic
pumps; gas emissions from storage
vessels; well maintenance and liquids
unloading; and well drilling and
completions. Based on the available
data regarding methane emissions and
the numbers and types of sources of gas
losses from Federal and Indian leases,
we believe that these aspects of the
production process offer the best
opportunities for reducing waste.
To the extent that EPA completes
regulations that would have the effect of
reducing waste from these sources, the
BLM proposes to take EPA’s
requirements into account in finalizing
this proposed rule to avoid conflict or
burdensome duplication.
In addition, the BLM requests public
comments on the scope of this proposed
rule, including whether there are other
aspects of the production process that
might provide sufficient opportunities
for economical and cost-effective waste
reduction to warrant inclusion in this
regulation. We also request comment on
whether we could achieve additional
economical and cost-effective waste
reduction from any of the sources of
waste that we are addressing here. In
addition, we request comment on the
cost-effectiveness of the changes we are
proposing to each aspect of the
production process, taking into account
the full range of private and public
benefits achieved through waste
reduction. We also request comment on
how we could lower costs of the
measures that we are proposing here.
1. Venting or Flaring of Associated Gas
From Producing Oil Wells.
As discussed earlier in Section II.H. of
this preamble, operators currently vent
gas under some circumstances, and they
also flare large quantities of natural gas
that is produced at oil wells (commonly
called ‘‘associated gas’’ or ‘‘casinghead
gas’’). Operators have an economic
incentive to capture and sell the flared
gas, or to use it on-site. Nonetheless,
substantial flaring occurs under a
variety of circumstances.
(a) Quantities of Gas Vented or Flared
BLM analysis of ONRR data shows
that operators reported venting about 22
Bcf and flaring at least 76 Bcf of natural
gas from BLM-administered leases in
2013 (with about 44 Bcf estimated to be
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Federal and Indian minerals).208 Of that
total volume of flared gas, 71 Bcf was
flared oil-well gas while about 5 Bcf was
flared gas-well gas. Most of the flared
oil-well gas volume appears to be
associated gas flaring, with the balance
coming from other sources such as well
testing and emergency flaring. Flared
gas represents 2.6 percent of the total
gas production from BLM-administered
leases in 2013, enough to supply over 1
million households.209
According to ONRR data, 91 percent
of flared oil-well gas from BLMadministered leases occurred in three
States: North Dakota, South Dakota, and
New Mexico. In 2013, the volumes of
flared oil-well gas from BLMadministered leases in these States were
about 42 Bcf, 15 Bcf, and 8 Bcf,
respectively.210 The data also show that
these volumes have increased
dramatically since 2009, while oil
production increased in North Dakota
and either remained relatively constant
or declined in New Mexico and South
Dakota. For example, between 2009 and
2013, flared oil-well gas in New Mexico
increased by 2.3 percent, even as oil
production decreased by 3 percent, and
in South Dakota flaring increased by 1.3
percent even as oil production fell by 45
percent.211 Meanwhile, the increase in
oil-well gas flaring in North Dakota
appears to have tracked closely with the
increase in oil production (each
increased by roughly 350 percent over
that period).212
(b) Technologies To Address Flaring
The primary means to avoid flaring of
associated gas from oil wells is to
capture, transport, and process that gas
for sale, using the same technologies
that are used for natural gas wells.
While industry continues to reduce the
cost and improve the reliability of this
technology, it is long-established and
well understood. The capture and sale
of associated gas can pay for itself where
there is sufficient gas production
relative to costs of connecting to or
expanding existing infrastructure. The
costs of installing equipment and
pipelines for capture and transport can
range from $400,000 to $1 million per
mile for a 4-inch natural gas pipeline.213
In some cases, line capacity can be
208 RIA
at 3.
on an estimate of 74 Mcf of gas used
per household per year. See footnote 2.
210 RIA at 203.
211 Ibid.
212 Ibid.
213 Pipeline and Gas Journal, Billions Needed to
Meet Long-Term Natural Gas Infrastructure Supply,
Demands (April 2009) https://
pipelineandgasjournal.com/billions-needed-meetlong-term-natural-gas-infrastructure-supplydemands?page=4.
209 Based
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increased by adding more compressors
to boost pressure. Similarly, industry
has long used some of this gas on-site
to pneumatically control equipment or
fuel various types of equipment,
including such items as drilling rigs,
artificial lift equipment or heater/treater
equipment.
In addition, the recent increase in
flaring has encouraged entrepreneurs to
develop new technologies and
applications designed to capture smaller
amounts of gas and put them to
productive uses where building a
pipeline to connect to the market is
impractical. Companies are beginning to
experiment with and deploy several
technologies as potential alternatives to
the traditional pipeline systems that
capture associated gas. These include:
Separating out NGLs, which are often
quite valuable, and trucking them off
location; using the gas to run microturbines to generate power; and using
small integrated gas compressors to
convert the gas into CNG that can be
used on-site or trucked off location for
use as transportation fuel or conversion
to chemicals. In addition, there are other
promising and innovative approaches
that are either in development or in the
earlier stages of deployment.214
Natural gas contains hydrocarbons
that can exist in liquid phase without
being in a high pressure or low
temperature environment. These are
referred to as NGLs. Higher NGL
concentrations in a gas stream reflect
higher heating (Btu) value and a higher
combined commodity value when the
NGLs are separated from the remaining
gas stream. Although NGLs are typically
stripped and fractionated into their
various components (e.g., propane,
butane, etc.) at a gas processing plant,
well-site equipment capable of stripping
NGLs into a mixed liquid is available.
This technology is particularly
applicable in situations where high Btu
associated natural gas is being flared
due to lack of gas capture infrastructure.
The NGLs can be stripped from the gas
stream in the field and stored in tanks
at the well site. Trucks would transport
the stored NGLs to a gas processing
plant for sale. The remaining lower Btu
gas would continue to be flared, but
typically with a higher combustion
efficiency than mixed gas. Conservation
of the NGLs from a gas stream would
reduce waste, add energy to the
domestic supply, and increase royalty
payments to the Federal Government
and tribal governments.
214 See Carbon Limits (providing detailed
evaluation of new and emerging gas utilization
technologies).
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Facilities to condense natural gas into
LNG are more cost-effective at locations
with large amounts of flaring, as
relatively larger quantities of gas are
needed to offset the cost of the LNG
equipment. The surface area of well
sites may need to be expanded to
accommodate truck traffic and product
storage needs. Also, because associated
gas production drops off quickly at
hydraulically fractured oil wells, LNG
recovery is more likely to be costeffective if it is implemented when
production starts.
Micro-turbines that generate
electricity typically require
preprocessing of the associated gas to
minimize equipment maintenance
issues. Generating electricity can work
well if it is paired with NGL recovery,
as the NGL residue gas stream is well
suited as fuel for the generators.
However, scaling the generators to the
electricity demand that could be used
locally on the well pad complicates
their use. The generators may produce
more electricity than is needed on site,
but it may be too costly to connect to the
electric grid from a remote location, as
would be necessary to put the excess
electricity to productive use. The cost of
connecting to the electric grid depends,
among other things, on the distance of
the operation from the nearest electrical
distribution lines. Moreover, the
electricity produced for use on site
would be viewed as beneficial use, and
therefore the gas used to generate the
electricity would be royalty free. If the
electricity produced by a micro-turbine
is sold to the grid, however, it would
not be beneficial use and the gas used
to generate the electricity would not be
royalty free.
The CNG alternative technologies
show considerable promise in
effectively transporting associated gas to
a centrally located processing plant
while removing the higher value NGLs
for other productive uses. Well sites
may need to be expanded to
accommodate truck traffic and storage
needs, but not to the extent needed
under the LNG option. The on-site
equipment for CNG is smaller than for
LNG, and the size of the CNG operation
can also be more easily adjusted to meet
the associated gas decline over the life
of the well. However, limitations on the
amount and rate of natural gas capture/
compression on-site can limit
applicability of this technology.
Breakthroughs in compression
technology are increasing the range of
viable sites where CNG would be the
preferred alternative technology. This
technology could become sufficiently
attractive to reduce flaring to near zero
rates, according to companies offering
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these services. While these newer onsite technologies may not be suitable in
all situations, in many cases they could
provide a profitable alternative to using
traditional pipelines for capture and
sale as a way to reduce waste, and
operators should consider these
approaches in assessing the
opportunities to reduce waste from
venting and flaring.
In addition, there are a number of
technologies that can improve the
efficiency of flares and ensure that a
flare combusts as large a proportion of
the gas as possible. In particular,
automatic igniters can be used to ensure
that the flare is relit if the gas flow stops
intermittently.
(c) Factors Driving Flaring
In considering how to reduce flaring,
it is important to recognize that gas is
flared under a variety of circumstances,
some of which are unplanned or
unavoidable in the course of normal oil
and gas production. Emergencies can
occur through an unforeseen event, such
as a weather-related incident or an
accident that damages equipment
resulting in the loss of gas.
In other cases, operators flare gas
because they, and the midstream
processing companies that commonly
build and operate gas gathering and
processing infrastructure, do not yet
know whether there will be a sufficient
quantity of gas available to capture.
Thus, companies have not yet invested
in building gathering lines and
processing plants to capture and sell gas
for commercial use. For example, the
well may be an exploration or wildcat
well in a new field, far from existing
capture infrastructure, and it is not yet
known whether the field will produce
much gas. Similarly, in some fields, the
overall quantity of gas produced across
multiple wells is sufficiently small that,
even cumulatively, the wells do not
produce enough natural gas to offset the
costs of building pipeline infrastructure.
While flaring in these situations has
generally been considered unavoidable,
the BLM believes this assumption is
challenged by the development of the
alternative capture technologies
described above, which calls into
question whether it remains reasonable
to assume that there are no alternatives
to flaring when a field produces only a
small quantity of natural gas. The BLM
requests comment on this point. In
many instances, however, the decision
to flare large quantities of associated gas
is driven by an operator’s economic
calculation that the value of
immediately producing the oil
outweighs the value of the natural gas
that could be captured. In addition,
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inadequate maintenance or oversight
can result in avoidable waste of gas.
Two circumstances that result in
substantial ongoing or intermittent
flaring of associated gas on BLMadministered leases are: (1) Flaring in
areas with existing capture
infrastructure, but where the rate of
new-well construction is outpacing the
infrastructure capacity; and (2) Flaring
in areas where capture and processing
infrastructure has not yet been built out.
While the majority of associated gas
flaring on BLM-administered leases
occurs in the first situation, our
proposed approach to reducing flaring
addresses both circumstances.
The first situation occurs in areas that
have extensive natural-gas gathering
lines, which are connected to pipelines
leading to processing plants. However,
in many areas in recent years the rate of
oil development and the rapid rise in
quantities of associated gas have
overwhelmed the capacity of the
gathering lines and/or processing plants.
New wells (especially in shale
formations) often start out producing a
relatively large amount of oil and/or gas
at relatively high pressures, which then
declines rapidly over time. Thus, each
time a new oil well with associated gas
connected to the gathering system starts
production, it may increase the
pressures on the system above the
pressures generated by existing
producing wells, pushing those wells off
the gathering system. Operators of these
existing wells then must choose
between shutting in or throttling the
well, employing other technologies to
use the gas, reinjecting the gas, or
flaring. This is the situation in the
Permian basin in New Mexico, where
almost all of the producing wells are
connected to gas-gathering
infrastructure, but substantial flaring
still occurs due to inadequate capacity
or pressure restrictions in the pipelines
and/or processing plants. Much of the
flaring in the Bakken basin is also
driven by capacity constraints. In
reviewing applications to vent or flare
in North Dakota, the BLM found that out
of 1,292 applications to vent or flare
received between September 2012 and
August 2014, 887, or about 70 percent,
were from wells that were already
connected to a gas pipeline, but had
pipeline capacity or pressure
restrictions.215
Flaring also occurs in the second
situation identified above, when gas
capture infrastructure has not yet been
built out to a particular field or well,
215 Phone conversation with BLM, Planning and
Environmental Coordinator, Miles City, MT,
September 2014.
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even though the well is expected to
produce substantial quantities of gas. In
many instances, operators or midstream
processing companies plan to construct
gathering lines, but the rate of oil well
development outpaces the rate of
development of capture infrastructure.
In both situations, lack of adequate
planning and communication can result
in flaring. North Dakota’s recognition of
this cause of flaring led the State to
require an operator to provide an
affidavit at the well permitting stage
stating that the operator met with
gathering companies and informed them
of the operator’s expected well
development timing and production
levels.216
The BLM recognizes that in the
aggregate, operators do not want to
waste gas. It is a valuable commodity
that operators can sell for a profit. But
when the economic return on oil
production is substantially higher than
the economic return on gas production,
as it has been in recent years, there is
an economic incentive for individual
operators to focus on oil development at
the expense of gas-capture
infrastructure. Thus, operators may not
adequately plan and coordinate with
midstream companies, schedule oil well
development with gas capture capacity
in mind, build infrastructure, or
otherwise ensure adequate capacity. As
the GAO noted, even though it would be
profitable in many instances for a
company to make investments to reduce
venting and flaring, the operator may
choose to invest instead in a new well
that would be even more profitable.217
The GAO also identified a lack of
operator awareness of the available cost
savings, limited capital availability for
small companies, and institutional
inertia as reasons that companies fail to
capture the economic benefits of
investing in waste reduction
measures.218 In addition, operators
typically consider only the costs and
revenues of gas capture with respect to
their individual operation. But in many
instances, when costs and revenues are
evaluated across a larger area, such as a
group of wells that would share access
to a gas transmission line and
processing plant, gas capture that may
appear less economically attractive to an
individual operator may be more
economical if all of the wells in that
area were capturing and selling their
gas. This concept is recognized in the
existing requirements under NTL–4A,
216 Letter from North Dakota Oil and Gas Division
to Operators, Re: Gas Capture Plans Required on All
APD’s (May 8, 2014).
217 GAO–11–34 (Oct. 2010) at 24.
218 Ibid.
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which directs the Supervisor to consider
‘‘the economics of a field wide plan’’ in
evaluating the feasibility of requiring
capture.219
(d) Proposals To Reduce Waste From
Venting and Flaring
A focus on oil development rather
than gas capture may be a rational
decision for an individual operator, but
it does not account for the broader
impacts of venting and flaring,
including the costs to the public of
losing gas that would otherwise be
available for productive use, the loss of
royalties that would otherwise be paid
to States, tribes, and the Federal
Government on the lost gas, and the air
pollution and other impacts of gas
wasted through venting or flaring. A
single operator’s focus on its own
operations can also produce a skewed
assessment of the returns on investment
in capture infrastructure across an entire
area, where shared infrastructure may
lower costs relative to the returns from
the sale of gas.
Thus, a decision to vent or flare that
may make sense to the individual
operator may constitute an avoidable
loss of gas and unreasonable waste
when considered from a broader
perspective and across an entire field.
Further, as capture technologies
improve, the economics of capture are
improving for individual operators.
The BLM’s proposed approach would
reduce venting and flaring through a
combination of measures: Prohibiting
venting except in a narrow range of
circumstances; reducing flaring by
limiting the per-lease per-month rate of
flaring; requiring operators to submit gas
capture plans with their Applications
for Permits to Drill new wells; requiring
royalties on flared gas where
appropriate; and simplifying both
compliance with and administration of
the venting and flaring requirements.
The proposed rule would streamline the
current regulatory regime by
establishing thresholds and
presumptions that initially apply across
the board, but would maintain the
BLM’s ability to address individual
situations through case-by-case
determinations and exemptions where
warranted.
(i) Phasing Out Routine Venting
With respect to venting, the proposal
specifies that an operator must flare
rather than vent gas, except in four
specified circumstances: (1) When
flaring the gas is technically infeasible
(for example, because there is
insufficient volume of gas); (2) When
219 44
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the loss of gas is uncontrollable or
venting is necessary for the safety of
workers and others on the site; (3) When
the gas is leaking from a storage vessel
under circumstances that do not trigger
the flaring requirements of proposed
§ 3179.203; or (4) When the gas is
vented through operation of a natural
gas-activated pneumatic controller or
pneumatic pump that complies with the
equipment requirements of proposed
§ 3179.201. As a practical matter, the
BLM believes that the great majority of
associated gas routinely lost from oil
production wells is flared, rather than
vented, and the proposed prohibition on
venting would further reduce losses
through venting. Thus, the discussion
that follows generally references flaring,
which is the main focus of these
provisions.
The BLM is aware that venting may
occur at gas gathering lines due to
maintenance activities. We request
comment on whether the proposed
venting prohibition will sufficiently
address these maintenance emissions.
(ii) Limits on Rates of Flaring
The proposed requirements to reduce
flaring focus on the routine flaring of
associated gas from development oil
wells. Associated gas represents the
bulk of the current flared gas, and is
easier to capture than other flared gas.
To address this waste of gas, the BLM
proposes to establish a limit on the
average rate at which gas may be flared
of 1,800 Mcf per month per producing
well on a lease.
The BLM is proposing to retain the
current exemptions from royalties and
gas capture requirements for gas flared
in other specified situations, as long as
the operator has complied with the
proposed requirements to minimize
these losses. These exemptions include
gas lost in the normal course of well
drilling and well completion; well tests;
emergencies, as defined in the
regulations; and gas flared from
exploration or wildcat wells, or from
delineation wells (wells drilled to
define the boundaries of a mineral
deposit). As described in more detail
below, these exemptions represent
situations in which: (1) A well is least
likely to be connected to a pipeline, and
on-site capture technologies are least
likely to be economical; or (2) Flaring is
likely to be unavoidable or necessary for
safety.
(a) Proposed Per-Well Flaring Limit
As noted, the primary means by
which the BLM proposes to reduce
flaring is by limiting the average rate at
which gas may be flared to 1,800 Mcf/
month, per producing well on a lease.
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In essence, the BLM is proposing that,
subject to limited exceptions, very high
rates of flaring from a lease—that is,
rates above the proposed 1,800 Mcf/
month threshold—constitute
unreasonable waste under the MLA. As
discussed above, operators have
multiple avenues to reduce high levels
of flaring. One is to speed up connection
to pipelines, and another is to boost
compression to access existing pipelines
with capacity issues. BLM believes there
are also other options available to avoid
this waste. The economics of alternative
on-site capture technologies improve as
quantities of gas increase. Imposing a
limit on the overall rate of flaring on a
lease would provide operators an
incentive to implement these
technologies, where net costs are not
prohibitive, to allow the wells to
produce oil at the maximum rate.
Alternatively, an operator could slow
production sufficiently to stay below a
flaring limit. Slowing the rate of flaring
is likely to conserve gas overall because
less gas is lost before capture
infrastructure comes on line (or is
upgraded, in the case of a field with
insufficient capacity).
To select an appropriate numeric
limit for flaring, the BLM analyzed data
indicating the average flaring rates
across wells. The BLM used venting and
flaring data reported to ONRR by
operators of oil and gas leases on
Federal and Indian lands. For the
analysis, the BLM used the most recent
full fiscal year of available data—
records covering the time period from
October 1, 2013, through September 30,
2014. The BLM extracted from the
ONRR data 15,530 records that
document more than 76 Bcf of natural
gas flared from oil wells during the time
period. These records represent monthly
flared volumes on a lease or unit basis
from over 2,000 unique leases or units
that flared natural gas from Federal or
Indian mineral estates. As the number of
wells on a lease or unit that might
contribute to the monthly flaring
volume can affect the cost to capture,
the BLM further reviewed the BLM
Automated Fluid Minerals Support
System database for the number of total
active wells associated with the lease or
unit. With the number of active wells
linked to the lease or unit, the records
were sorted in order of increasing
average flare volume per month per
well.
These data indicate that in 2014:
• A 1,200 Mcf/month/well threshold
would have impacted about 20 percent
of the oil wells flaring associated gas,
which accounted for 91 percent of the
gas flared;
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• A 1,800 Mcf/month/well threshold
would have impacted about 16 percent
of the oil wells flaring associated gas,
which accounted for 87 percent of the
gas flared;
• An 2,400 Mcf/month/well threshold
would have impacted about 13 percent
of the oil wells flaring associated gas,
which accounted for 84 percent of the
gas flared;
• A 3,000 Mcf/month/well threshold
would have impacted about 11 percent
of the oil wells flaring associated gas,
which accounted for 81 percent of the
gas flared.220
While these are average flaring
volumes spread across all active wells,
they represent an approximation of how
oil well flaring is distributed across the
spectrum of activity.221 Operators have
full discretion in how they choose to
meet a rate-based flaring limit, with the
result that compliance strategies may
vary. For example, operators with wells
that are only slightly over the flaring
limit may choose to comply by slowing
the rate of production until either: (1)
The well is connected to pipeline
infrastructure; or (2) Well decline brings
the rate of gas production under the
flaring limit. In the first instance, the
over-the-limit quantity of gas would
ultimately be conserved—in fact, even
more gas might be conserved because
the operator is likely to capture all of
the gas that would otherwise have been
flared. In contrast, in the second
instance, the over-the-limit quantity of
gas would still be flared, just later in
time. Thus, there is substantial
uncertainty in analyzing the impact of a
flaring limit.
The BLM has analyzed the impacts of
alternative flaring limits by adopting
two simplifying assumptions. First, the
BLM assumed that all over-the-limit
quantities of gas would be captured
instead of flared (an assumption that
tends to overstate reductions in flaring);
second, the BLM assumed that operators
would comply only down to the level of
the flaring limit and not below (an
assumption that tends to understate
reductions in flaring). With these
competing assumptions in place, the
projected reductions in flaring that
might be achieved under different
numeric limits are:
• A 1,200 Mcf/month/producing well
threshold could conserve 80 percent of
the gas flared;
• An 1,800 Mcf/month/producing
well threshold could conserve 74
percent of the gas flared;
220 RIA
at 33–35.
supplied by ONNR.
221 Data
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• A 2,400 Mcf/month/producing well
threshold could conserve 69 percent of
the gas flared; and
• A 3,000 Mcf/month/producing well
threshold could conserve 65 percent of
the gas flared.
These estimates were generated for
the purpose of comparing alternative
options for the flaring limit; the
estimated overall impacts of the
proposed flaring limit, combined with
the effects on flaring of other elements
of the rule, are presented in Section
VI.B.4. of this preamble and Section
8.4.1. of the RIA. The BLM proposes in
§ 3179.6(b) to set a flaring limit of 1,800
Mcf per month per well, averaged over
all producing wells on a lease. We
believe this limit would effectively
maximize flaring reductions while
minimizing the number of affected
leases. This proposed limit is consistent
with Wyoming’s and Utah’s approaches:
Wyoming and Utah limit flaring from a
well to 60 Mcf/day and 1,800 Mcf/
month, respectively, unless the operator
obtains State approval of a higher
limit.222 As applied, the numeric limit
proposed by the BLM would be
somewhat less stringent than the State
limits, because operators would be able
to average flaring across all of the wells
on a lease, rather than being required to
meet the limit at each individual well.
This approach incorporates some of the
flexibility allowed by North Dakota,
where operators can show compliance
with the State’s flaring limits on a field,
county, or state-wide basis. In addition
to reducing waste of gas through flaring,
we believe this proposed approach
would give operators more clarity about
when they may flare, and reduce
administrative burdens for the BLM,
compared to the current approach to
obtaining approval for flaring under
NTL–4A. Operators would no longer
have to submit applications to obtain
approval for flaring from each
individual well, and the BLM would no
longer need to review and decide on
each of those requests. Currently, some
field offices receive hundreds of flaring
applications each year, and processing
these applications on a case-by-case
basis uses BLM resources that could be
used to process applications for permit
to drill, process right-of-way
applications, and conduct inspections,
among other activities.
222 Wyoming Operational Rules, Drilling Rules
Section Ch. 3, Section 39(b), available at https://
soswy.state.wy.us/Rules/RULES/9584.pdf (60 Mcf/
day); Utah R649–3–20, Gas Flaring or Venting
Section 1.1, available at (https://www.rules.utah.gov/
publicat/code/r649/r649-003.htm#T20 (1,800 Mcf/
mo.).
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(b) Phase-In of the Proposed Limit
The BLM recognizes that in the first
few years of the rule, it may be difficult
for operators to meet the newly
proposed flaring limit across all of their
existing operations, because operators of
oil wells drilled prior to the effective
date of this rule may not have planned
for gas capture. To assist these operators
in transitioning to the proposed flaring
limits, we propose to phase in those
limits over the first few years after the
effective date of the rule. Specifically,
we propose flaring limits of: 7,200 Mcf
per month per well on average across a
lease in the first 12 months in which the
regulations are in effect; 3,600 Mcf per
month per well on average across a lease
in the second 12 months in which the
regulations are in effect; and 1,800 Mcf
per month per well on average across a
lease thereafter. This approach of
phasing in the flaring limits is intended
to allow operators initially to focus their
resources on addressing wells with the
highest rates of flaring.
(c) Alternative Flaring Limits or
Renewable, 2-Year Exemption
Lessees that entered into Federal and
Indian leases prior to the imposition of
the proposed flaring limits (depending
on the location of their wells) may have
limited options for substantially
minimizing waste. As a result, the BLM
believes it is appropriate and necessary
to provide an exemption to ensure that
no lessee is entirely deprived of its
ability to develop an existing Federal or
Indian lease.
Thus, the BLM proposes in § 3179.7 to
provide existing lease holders with the
possibility of obtaining an exemption to
the applicable flaring limit. Specifically,
we propose to provide that an existing
lease holder may apply for an
alternative flaring limit or, under
specific circumstances, may qualify for
a renewable, 2-year exemption from the
flaring limit. These provisions are
intended to help existing operators
transition to the proposed regulatory
regime; operators on new leases would
have more flexibility to plan for gas
capture ahead of drilling, and thus
would not be eligible for either form of
exemption.
(i) Alternative Flaring Limits
The alternative flaring limit provision
would apply to any operator (operating
on an existing lease) that demonstrates,
to the BLM’s satisfaction, that the flaring
limit specified in the regulations would
impose such costs as to cause the
operator to cease production and
abandon significant recoverable oil
reserves under the lease.
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In making the determination of
whether a lease qualifies for an
alternative flaring limit, the BLM would
consider the costs of capture and the
costs and revenues of all oil and gas
production on the lease. For any
operator that made a sufficient showing,
the BLM would set an alternative flaring
limit. The BLM would aim to set this
alternative limit at the lowest level that
would not cause the operator to cease
production and abandon significant
recoverable oil reserves.
The proposed standard for approving
an alternative flaring limit is similar to
the existing standard in NTL–4A for
approving venting or flaring of oil well
gas. NTL–4A allows the BLM to approve
flaring if it is justified by data showing
that ‘‘the expenditures necessary to
market or beneficially use such gas are
not economically justified and that
conservation of the gas, if required,
would lead to the premature
abandonment of recoverable oil reserves
and ultimately to a greater loss of
equivalent energy than would be
recovered if the venting or flaring were
permitted to continue.’’ 223 Given the
substantial variation in how the BLM
has interpreted and applied this
standard, the BLM is proposing to
establish a refined formulation of this
test, to allow for a more uniform
interpretation going forward. In
particular, in some instances in the past,
even small net costs have been viewed
as meeting the test under NTL–4A, as
any net cost might theoretically cause
an operator to abandon a well earlier
than it otherwise would have. In light of
the BLM’s statutory obligation to reduce
waste of natural gas from venting,
flaring, and leaks, however, the BLM
believes that an operator must
demonstrate more than a negligible
economic impact in order to qualify for
an exemption from the flaring limit.
Thus, we propose to allow an
exemption only on a showing that the
net costs of compliance with the flaring
limit would be sufficient to cause the
operator to cease production and
abandon ‘‘significant’’ recoverable oil
reserves. The BLM requests comment on
this approach.
To make the proposed showing, an
operator would have to provide
information about the quantity of flaring
from the lease, projected costs of
capture (including an evaluation of onsite approaches), and projected prices
and returns on oil and gas production
from the lease. Where operators need to
project future costs and returns, the
projections would be required to cover
either the life of each lease or the next
223 NTL–4A,
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15 years, whichever is less. This is
similar to the information that NTL–4A
currently requires operators to provide
in a request for approval of flaring,
although the proposed regulations are
more specific. NTL–4A currently
requires an applicant for royalty-free
flaring to submit ‘‘all appropriate
engineering, geologic, and economic
data in support of the applicant’s
determination that conservation of the
gas is not viable from an economic
standpoint and if approval is not
granted to continue the venting or
flaring of the gas, that it will result in
the premature abandonment of oil
production and/or the curtailment of
lease development.’’ 224 Pursuant to this
language in NTL–4A and guidance from
individual BLM State offices, operators
generally give the BLM information on
projected oil and gas production,
revenue projections, costs, and returns
on investment under scenarios in which
the gas is and is not captured, although
the specific information submitted
varies between applicants and across
BLM field offices and States.
The BLM believes that requiring the
information specified in this proposal to
support a request for an alternative
flaring limit would not impose
substantial new paperwork burdens on
operators, given the information
currently required to be submitted
under NTL–4A. In addition, given the
rigor of the qualifying requirements, we
do not expect many lease holders to
apply for an alternative flaring limit,
further limiting the potential burden.
We request comment, however, on this
point.
(ii) Renewable, 2-Year Exemption
Unlike the alternative flaring limit,
the renewable exemption would provide
certain operators with a complete
exemption from the flaring limit, for a
period of 2 years. The BLM generally
prefers to assess the need for alternative
flaring limits on a case-by-case basis,
but we recognize that it may be more
efficient to grant a short-lived, acrossthe-board exemption to a small class of
operators that are: (1) Operating at
significant distances from gas
processing facilities, and (2) Generating
high volumes of associated gas, such
that capture and sale of the gas is
plainly infeasible with current
technologies.Thus, the proposed rule
identifies three criteria that an operator
must meet to qualify for an exemption
from the flaring limit. Specifically, the
BLM proposes that operations on an
existing lease would qualify for an
exemption from the flaring limit if: (1)
224 44
FR at 76600 (Dec. 27, 1979).
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The lease is not connected to a gas
pipeline; (2) The closest point on the
lease is located more than 50 straightline miles from the nearest gas
processing plant; and (3) The rate of
flaring or venting from the lease exceeds
the applicable flaring limit by at least 50
percent.
There are two reasons why the BLM
believes that meeting all three of these
criteria would be sufficient to
demonstrate that an operator on an
existing lease would be unlikely to be
able to meet the flaring limit with
today’s technologies. First, a 2015 study
by the entity Carbon Limits AS, titled
Improving Utilization of Associated Gas
in US Tight Oil Fields,225 suggests that
on-site capture is most cost-effective
within a 20–25 mile radius of gas
processing facilities.226 Existing leases
located more than 50 miles from such
facilities are thus unlikely to be able to
avail themselves of this technology.
(While leases located more than 25 but
less than 50 miles from gas processing
facilities might similarly find on-site
capture less cost-effective, that might
not always be the case. Those leases
could make a case-by-case showing
under the proposed provision for
alternative flaring limits.)
Second, while operators could
respond to the flaring limit by deferring
production, that is unlikely to be an
option for operators on existing leases
that are flaring more than 50 percent
above the applicable limit. For these
operators, reducing flaring below the
limit would require reducing
production by one-third or more. Thus,
the BLM believes that leases meeting
these distance and flaring rate criteria
should qualify for an automatic
exemption from the flaring limit.
To obtain the exemption, the BLM
proposes to require that an operator
submit a Sundry Notice with an
affidavit certifying that the lease meets
the specified criteria. The authorizing
officer would then have the opportunity
to verify the accuracy of the submission.
Because the circumstances supporting
an exemption may change over time, the
BLM proposes that the exemption
would extend for 2 years, and could be
renewed by the operator with
submission and BLM approval of a new
Sundry Notice.
(d) Request for Comments
To assist the BLM in finalizing the
proposed flaring limit, we request
comment on:
225 Hereinafter ‘‘Carbon Limits.’’ The study is
available at https://www.catf.us/resources/
publications/files/Flaring_Report.pdf.
226 Ibid. at 34.
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• The proposed 1,800 Mcf/month/
well limit on the quantity of flared gas;
• Whether the flaring limit should be
1,200 Mcf/month/well, which would
likely further reduce flaring, or 2,400
Mcf/month/well, which would likely
reduce compliance costs for operators,
but increase flaring above the amount
anticipated by the proposed rule;
• Operators’ likely response(s) to the
proposed 1,800 Mcf/month/well limit
(that is, the degree to which operators
would respond by deploying on-site
capture technologies, increasing capture
capacity, speeding connections to
pipelines, or slowing production, or
with some combination of those
responses);
• The proposal to phase-in the flaring
limits and the specific limits proposed
for year-one and year-two;
• The proposed provisions for
operators to obtain an alternative flaring
limit; and
• The proposed criteria for operators
to qualify for the renewable, 2-year
exemption, as well as the proposed 2year duration of the exemption and the
opportunity for renewal.
(iii) Waste Minimization Plans for
Applications for Permit To Drill
The BLM is also proposing that prior
to drilling a new development oil well,
an operator would have to evaluate the
opportunities and prepare a plan to
minimize waste of associated gas from
that well, and the operator would need
to submit this plan along with the APD.
The BLM proposes to amend
§ 3162.3–1 to require an operator to
submit along with its APD a plan to
minimize waste of gas from the well to
the degree reasonably possible. Failure
to submit a complete and adequate
waste minimization plan would be
grounds for denying or disapproving an
APD.
The plan must set forth a strategy for
how the operator will comply with the
proposed requirements to control waste
from venting, flaring, and leaks, and it
must explain how the operator plans to
capture associated gas upon the start of
oil production, or as soon thereafter as
reasonably possible. The waste
minimization plan must include
specified information, including:
Anticipated well completion timing;
anticipated gas production rates,
durations, and declines; a map and
information on the locations and
operators of nearby gas pipelines and
processing plants; proposed routes and
tie-in points; pipeline capacities,
throughputs, and expansion plans, if
known; an evaluation of opportunities
for alternative on-site capture
approaches, if pipeline transport is
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unavailable; and the volume and
percentage of produced gas that the
operator is currently flaring from wells
in the same field. In addition, the
operator must certify that it has
provided one or more midstream
processing companies with information
about its production plans, including
the anticipated completion dates and
gas production rates of the proposed
well or wells. We request comment on
whether the waste minimization plan
provisions should also require an
operator to identify the projected gas
production volumes that would be
moved by pipeline or by truck.
While the BLM is proposing to require
submission of a waste minimization
plan together with the APD, we are not
proposing to include the submitted plan
as an element of the APD or otherwise
to enforce the terms of the plan.
The BLM believes that requiring
submission of a waste minimization
plan would ensure that as an operator
plans a new well, the operator has the
information necessary to evaluate and
plan for gas capture. This requirement
would also ensure that the operator
provides this information to the
companies most likely to install and
operate the necessary gas capture
infrastructure—namely, midstream
processing companies operating in the
area. Both procedural steps are vitally
important to development of a robust
gas capture system for a new well.
As with development of an
environmental analysis under the
National Environmental Policy Act, the
BLM believe that significant progress
can be made by requiring that operators
take these procedural steps prior to
drilling. Further, the BLM believes that
making the elements of the plan
enforceable (for example, by
incorporating it in the APD) might
create an unintended incentive for
operators to understate the degree of
capture they anticipate achieving, or to
write a very general plan, with few
specifics. As a result, the BLM believes
more can be achieved by requiring
operators to develop a thorough and
practical plan prior to submitting their
Applications for Permits to Drill. The
plan requirement is intended to assist
operators in better preparing to comply
with the proposed flaring limits.
The information required by this
proposed provision is comparable to the
information North Dakota requires to be
included in the gas capture plan that
each operator must provide. North
Dakota requires that the gas capture
plan include: A detailed gas gathering
pipeline system location map
identifying the location of connections
to the gathering system and processing
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plants, as well as the names of gas
gatherers and locations of lines for each
gas gatherer in the vicinity; information
on the existing line to which the
operator proposes to connect, including
the maximum current capacity, current
throughput, and gas gatherer issues or
expansion plans for the area (if known);
a flowback strategy including the
anticipated date of first production, and
anticipated oil and gas rates and
duration; the amount of gas the
applicant is currently flaring; and
alternatives to flaring, including specific
alternate systems available for
consideration and the expected flaring
reductions if such plans are
implemented.227 North Dakota
regulators have identified the
requirement for gas capture plans as a
highly effective element of their
requirements to reduce flaring.228
(iv) Estimating or Measuring Quantities
of Flared or Vented Gas
Under proposed § 3179.8, the BLM
would require operators to report the
quantities of all flared and vented gas.
In determining the quantity of gas flared
or vented, operators either estimate the
volumes using engineering protocols or
measure the volumes with gas meters.
Meters generally produce more accurate
results, but are also more costly. Thus,
the BLM proposes to specify when
operators may estimate the volumes of
flared or vented gas, and when operators
must measure the quantities for
reporting purposes. Specifically, the
BLM proposes that when the combined
total of an operator’s flaring and venting
reaches least 50 Mcf of gas per day from
a flare stack or manifold, the operator
must measure rather than estimate the
volume lost (i.e., flared and/or vented)
from that flare stack or manifold.
The BLM believes that in calculating
small volumes of lost gas, any
additional accuracy provided by meters
may not justify their additional cost.
Accordingly, the proposed rule would
allow operators to estimate rather than
measure volumes of lost gas below 50
Mcf. The BLM proposes to require
measurement when gas losses are at
least 50 Mcf per day because as the
volume of gas flared nears 60 Mcf/day
it is effectively nearing the 1,800 Mcf/
month limit, and at that point accurate
measurement of that volume becomes
227 Letter from North Dakota Industrial
Commission, Department of Mineral Resources, Oil
and Gas Division to all Hearing Applicants, re Gas
Capture Plan Required Hearing Exhibit (Sept. 16,
2014).
228 Telephone Communication from North Dakota
Industrial Commission, Department of Mineral
Resources, Oil and Gas Division to BLM Staff, (May
13, 2015).
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increasingly important for compliance
and enforcement purposes. Moreover, as
the volumes of gas flared increase, the
economics of gas capture become more
favorable, and the importance of using
more refined data increases. We request
comment on this proposed approach.
(v) Costs and Benefits of These
Proposals
The requirement to meter flares is
estimated to pose compliance costs of
$7,500 per meter and operating costs of
about $500 per meter per year.
Assuming an equipment life of 10 years,
the cost per meter is about $1,570 per
year when costs are annualized using a
7 percent interest rate, or $1,380 per
year using a 3 percent interest rate. In
total, we estimate that the proposed
flare metering requirement would
impact 635 operations in 2017, with that
number increasing on an annual basis to
an estimated 1,175 operations in 2026.
We estimate compliance costs ranging
from $1.0–1.8 million per year when the
capital costs of equipment are
annualized with a 7 percent discount
rate or $0.9–1.6 million per year when
the capital costs of equipment are
annualized with a 3 percent discount
rate. Since these sources are not
addressed by the EPA’s proposed 40
CFR part 60 subpart OOOOa, the
estimated impacts of the requirements
are not influenced by that proposal.229
The requirement to limit gas flaring to
1,800 Mcf/month per average well on a
lease may result in a range of potential
benefits and costs depending on
operator response, commodity prices,
and the levels of flaring in future years.
Operators could choose to comply by
immediately using the excess gas on-site
or deploying on-site capture
technologies; they could briefly slow oil
production while they expand capture
capacity, where such expansion is costeffective; or they could defer some
portion of their production. We request
comment on the likely balance among
these response approaches, and the
likely volume and duration of any
partial deferment in oil production.
We considered this range of responses
in estimating the costs and benefits of
the flaring provisions, although we
recognize that these estimates are
subject to significant uncertainty, given
the uncertainty about operator response.
In designing the analysis, we looked at
data for leases in North Dakota and New
Mexico with respect to characteristics
that might influence an operator’s
choice of how to comply with the
flaring limits. Specifically, we identified
whether wells on the lease were
229 RIA
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connected to pipeline infrastructure, the
rate of flaring (specifically, whether the
rate was at least 50 percent above the
flaring limit, or whether the rate was
within 40 Mcf/day of the flaring limit),
and the distance from the nearest gas
processing plant (specifically whether
the well was more than 50 miles, less
than 20 miles, or between 20 and 50
miles from the nearest gas processing
plant) for each lease where these data
were available. We then constructed
eight possible operator response
scenarios based on combinations of
these characteristics. We evaluated how
operators in each scenario might
respond to the flaring limit (e.g., by
deferring production, conducting on-site
capture, or obtaining an exemption),
assigned costs for each type of response,
calculated the number of leases that
would fall into each response category,
and derived an estimate of overall costs.
The RIA provides additional detail on
our analysis.
We estimate that the proposed flaring
limits, including the 3-year phase-in
period, would affect an estimated 435–
885 leases in any given year. These
requirements could pose total costs of
about $32–68 million per year (7
percent discount rate) or $26–43 million
per year (3 percent discount rate).
Because these requirements would drive
additional capture of gas, the flaring
limits are also projected to pose total
cost savings (from the value of the
captured gas) of about $40–58 million
per year (7 percent discount rate) or
$40–64 million per year (3 percent
discount rate). We also estimate that
they would increase natural gas
production by 2.5–5.0 Bcf per year, and
increase NGL production by 36–51
million gallons per year. The net
benefits of these requirements are
estimated to range from negative $10 to
positive $8 million per year (7 percent
discount rate) or $13–30 million per
year (3 percent discount rate). Also, we
expect there would be additional
environmental benefits associated with
the productive use of the gas
downstream.230
(e) When Flared Gas Is Subject to
Royalties
Along with the other aspects of NTL–
4A, it is necessary to update the NTL–
4A provisions regarding the
applicability of royalties. As noted
above, this proposal would clarify the
determination of whether routine flaring
from a production well is considered an
avoidable waste of gas subject to
royalties. Requiring royalty payments on
wasted quantities of gas does not
230 RIA
at 60.
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compensate for all the harm to the
public from that waste, but it at least
ensures that the public does not lose the
royalty revenue they would have
received had the gas been put to
productive use.
The BLM is proposing in § 3179.4 to
maintain the general approach of NTL–
4A for distinguishing between avoidable
and unavoidable losses of gas. The
proposed rule would reduce regulatory
burden and confusion, however, by
providing additional and more specific
requirements, and it would modify the
NTL–4A approach with respect to
flaring from wells that are already
connected to gas capture infrastructure.
(i) Unavoidable Losses of Gas
The BLM proposes to determine that
a loss of gas is unavoidable if all of the
following four conditions are met. (1)
The operator has not been negligent; (2)
The operator has complied with all
applicable requirements; (3) The
operator has taken prudent and
reasonable steps to avoid waste; and (4)
The gas is lost from any of the following
specified operations or sources, subject
to the applicable limits or conditions
specified in the proposed regulations:
Emergencies; well drilling; well
completion and related operations;
initial production tests and subsequent
well tests; exploratory coalbed methane
well dewatering; leaks; venting from
conforming pneumatic devices in the
normal course of operation; evaporation
from storage vessels; and downhole well
maintenance and liquids unloading.
Where these losses result from flaring,
the BLM is proposing to establish
quantity and/or timing limits on gas that
may be flared royalty-free, such as the
definition of what is considered an
emergency and the limits on royalty-free
flaring for well testing. Beyond these
limits, continued losses would generally
be considered avoidable and subject to
royalties, except that, with respect to
testing, the BLM may approve an
operator’s request for royalty-free flaring
beyond the specified limits.
In addition, the BLM is proposing to
find a loss of gas unavoidable where
produced gas is flared from a well not
connected to gas capture infrastructure,
as long as the BLM has not otherwise
determined that the loss of gas is
avoidable, subject to the 1,800 Mcf/
month limit in § 3179.6. In some cases,
the effectiveness and affordability of onsite capture technology may mean that
an operator could avoid flaring gas from
a well not connected to capture
infrastructure. At this time, however,
on-site capture technology is not always
effective and affordable; thus, the BLM
is not proposing to find all flaring of
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associated gas from development wells
to be avoidable.
The specifics of the proposal with
respect to unavoidable losses depend on
the category of loss. With respect to
emergencies, NTL–4A currently
authorizes royalty-free flaring of gas
without approval from the BLM, but the
proposed rule would clarify and narrow
the scope of this exemption. As
proposed under § 3179.105, emergencies
result in infrequent and unavoidable
flaring (or venting), and they may
include failures of equipment located on
the lease, relief of abnormal system
pressures, or other unanticipated
conditions. Operators may flare under
this exemption for up to 24 hours per
incident, and for no more than three
emergencies per lease within a 30-day
period. The BLM proposes to clarify that
emergencies do not include: More than
three failures of the same equipment
within 365 days; failure to install
adequate equipment to capture the gas;
failure to limit production when the
production rate exceeds the capacity of
the related equipment; scheduled
maintenance (whether by the operator
or downstream facilities); or operator
negligence. The BLM believes that
repeated failure of the same piece of
equipment within a given span of time
indicates that the equipment is not
properly sized or may need to be
replaced, and that the operator should
have taken action to address the
problem. The BLM requests comment
on the specific failure frequencies over
a given time-period that would tend to
indicate avoidable incidents.
With respect to flaring during well
drilling and completion, the BLM
proposes under § 3179.101 that gas
produced during normal well drilling
operations and then flared would be
deemed unavoidably lost. Similarly,
under proposed § 3179.102, gas
produced during well completion and
post-completion drilling fluid recovery
or fracturing fluid recovery operations
would be deemed unavoidably lost
when flared, subject to a volume limit.
Under proposed § 3179.103, gas from
initial production testing may be flared
and deemed unavoidably lost until the
first of the following occurs: (1) The
operator has adequate reservoir
information for the well; (2) 30 days (90
for coal-bed methane dewatering) have
passed; (3) The operator has flared 20
MMcf of gas, including any gas flared
that was produced during well
completion and post-completion fluid
recovery; or (4) Production begins.
The 20 MMcf limit is lower than the
maximum volume of royalty-free flaring
authorized under NTL–4A (50 MMcf).
The BLM’s experience in the field
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indicates that adequate testing to
determine a well’s production capacity
can almost always be conducted within
the 20 MMcf volume threshold. The
current 50 MMcf threshold is seldom, if
ever, exceeded in actual well testing
operations. The BLM specifically seeks
comments on the amount of gas that
should be allowed to be flared royaltyfree during initial production testing.
Under proposed § 3179.104, during
well tests subsequent to the initial
production test, the operator may only
flare gas for 24 hours royalty free, unless
the BLM approves otherwise.
Operators would no longer need to
apply for approval of flaring under the
preceding conditions. Any gas flared in
excess of these limits, however, would
be deemed avoidably lost and subject to
royalties, except where the BLM
approved a request to extend the limits.
In addition, regardless of whether the
gas is subject to royalties, BLM also
proposes under § 3179.8 that the
operator must measure or estimate all
quantities of gas flared and vented,
including those that are deemed
unavoidably lost, and report these
quantities to ONRR.
(ii) Avoidable Losses of Gas
Under proposed § 3179.4(b), all losses
of gas not specifically found to be
unavoidable would be considered
avoidable. Proposed § 3179.5(a) would
subject all avoidably lost gas to
royalties. One key consequence of this
proposal is that royalties would apply to
associated gas flared from a
development well that is already
connected to capture infrastructure.
The BLM believes that where
operators are connected to capture
infrastructure, but are nevertheless
flaring, they have made an economic
choice to flare, and flaring in those
instances should not be considered an
unavoidable consequence of oil
production. Most flaring at wells
already connected to pipelines occurs
when wells are bumped off the pipeline
due to pressure or capacity constraints,
or when downstream equipment is
brought down for maintenance. Where
wells are already connected to gas
capture infrastructure, midstream
companies and operators have
presumably already found that gas
capture pays for itself. Nonetheless,
operators may choose to expand
production beyond the capacity of
existing capture infrastructure, or to do
so faster than capture infrastructure can
be expanded (where capacity issues can
be addressed with installation of
additional compression, the rate of
expansion is often in the operator’s
control). This may be a rational business
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decision for an operator, but with better
planning or more deliberate
development, both the oil and gas
resources could be developed without
waste.
Further, operators may be able to use
alternative on-site gas capture
equipment to put the gas to productive
use during any period in which gas
production exceeds transport capacity.
Similarly, when downstream equipment
is temporarily brought down for
maintenance, operators could curtail
production for a short period or use onsite capture equipment to avoid wasting
gas in the interim.
(f) Alternative and Additional
Approaches
The BLM considered, but did not
include in the proposed rule text, a
range of supplemental or alternative
approaches to the flaring limit and
royalty provisions described above. For
example, one alternative approach that
BLM considered for increasing capture
of associated gas was to rely solely on
royalties on flared gas to discourage
flaring. Under this approach, all flaring
of associated gas would be
presumptively subject to royalties.
Similar to the current standard under
NTL–4A, operators could then obtain an
exemption to the requirement to pay
royalties by showing that a requirement
to conserve the gas would cause the
operator to cease production and
abandon significant recoverable oil
reserves. To support such a claim, the
operator could be required to provide:
The projected costs of each technically
viable method of capturing and/or using
the gas (including, if applicable,
pipelines, removal of NGLs, CNG, LNG,
and electricity generation); the current
return on investment for the oil and gas
operation on the lease; the projected
return on investment for the oil and gas
operation if some or all of the gas were
captured; projected oil and gas prices
and production volumes; the location
and capacity of the closest pipelines;
and other relevant information. In
making the determination, the BLM
would consider the costs of capture, and
the costs and revenues of all oil and gas
production on the lease.
While market-based mechanisms,
such as royalty imposition, can be
highly effective policy instruments, and
we do propose to charge royalties on gas
flared above the 1,800 Mcf/month limit
because we believe flaring above that
level is avoidable, we do not believe
that royalties on flared gas alone would
curtail flaring. At current gas prices, oil
prices, and royalty rates, applying
royalties to flared gas does not provide
a sufficient incentive for operators to
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invest in gas capture to any appreciable
degree. This is evident in areas such as
Carlsbad, New Mexico, where most
operators are currently paying royalties
on associated gas that is flared, and in
spite of those payments, rates of flaring
have not changed appreciably since
2013. The BLM would not expect the
imposition of royalties at the current
royalty rate to lead to a significant
increase in gas capture as long as the
economic return on the oil production
is substantially higher than the
economic loss from the flared gas. The
BLM requests comments on this
conclusion.
A more significant royalty-based
approach to flaring would be to apply a
higher royalty rate to all production
from a lease on which the operator is
routinely flaring gas from development
wells. This concept is discussed in more
detail in Section V.C. of this preamble.
Another alternative to the proposed
approach to flaring would be to
distinguish between new and existing
wells. The current proposal applies the
same flaring requirements to both. The
BLM is, however, considering including
a complete prohibition on routine
flaring of associated gas from new
development wells. This approach
would shift the burden of flaring from
the public, which currently absorbs the
costs of flaring, to operators, which have
greater capacity to anticipate and plan
for capture infrastructure to be ready at
the time they shift from exploration to
development in a given field. The BLM
requests comment on this approach.
Finally, the BLM is requesting
comment on other innovative
approaches to reduce wasteful flaring
and determine when flaring should be
subject to royalties. In evaluating
alternative approaches suggested in
comments, we would consider a variety
of factors, including the approach’s
effectiveness in: Increasing gas capture;
reducing waste and compensating the
public through royalties; enhancing
regulatory clarity and transparency;
reducing uncertainty for operators;
minimizing inconsistency across BLM
offices; minimizing cost, paperwork,
and any other burdens on operators;
minimizing administrative burden on
the BLM; increasing overall practical
workability; and satisfying existing legal
authorities.
2. Leaks
(a) Estimates of Quantities of Gas
Leaked
As discussed in detail in the RIA,
using data from the EPA GHG Inventory,
we estimate that about 4.35 Bcf of
natural gas was lost in 2013 as a result
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of leaks or other fugitive emissions from
various components, including valves,
fittings, pumps, storage vessels and
compressors on well site operations on
BLM-administered leases.231 This
quantity of gas would supply nearly
60,000 homes each year.232
(b) Technologies and Practices To
Reduce Leaks
Multiple studies have found that once
leaks are detected, the vast majority of
them can be repaired at low enough cost
that the captured gas provides a positive
return to the operator. For example, the
Carbon Limits study found that 97
percent of the total leak rate could be
repaired with a positive return, even at
low producer gas prices of $3 per
Mcf.233 Further, over 90 percent of gas
leak emissions are from leaks that could
be repaired with less than a 1-year
payback period.234 Given that leak
repair is generally economical, the key
question is how the cost of leak
detection compares with the value of
the gas that could potentially be saved
by repairing leaks.
The term ‘‘Leak Detection and Repair’’
(LDAR) refers to both the practices and
programs that operators put in place to
inspect for and repair leaks, and the
specific technologies and methods the
operators use to detect leaks during
inspections. Recent technological
developments have reduced the cost of
leak detection while simultaneously
improving operators’ ability to detect
less obvious leaks. Traditional methods
coupled with new technology can also
be effective.
States are beginning to take advantage
of these new technologies. Colorado, for
example, requires instrument-based
emission monitoring as part of an LDAR
program that applies to well production
facilities and compressor stations.235
Also, Wyoming has regulations that
require operators in the Upper Green
River Basin nonattainment area to
develop LDAR programs if their
facilities emit more than an estimated 4
tons of VOCs each year.236
(i) Auditory, Visual, and Olfactory
(AVO) Method
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The AVO method consists of
physically inspecting the facilities—
231 RIA
at 19.
on an estimate of 74 Mcf of gas used
per household per year. See footnote 2.
233 Carbon Limits, 16.
234 Carbon Limits, 16.
235 Colorado Air Quality Control Commission
Regulations, Regulation 7, 5 CCR 1001–9, Section
XVII.F.
236 Wyoming Operational Rules, Drilling Rules
Section Ch. 8, Section 6(g), available at https://
soswy.state.wy.us/Rules/RULES/9868.pdf.
232 Based
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looking, listening, and smelling for
leaks. AVO inspections have
traditionally been the backbone of an
inspection program, and BLM
inspectors typically use this method
when inspecting well and facility sites.
The use of AVO inspections is most
effective in detecting obvious and
significant emissions-release events,
resulting in the cost-effective reduction
of high-volume leaks. The BLM believes
AVO is affordable for the many small
operators that only operate a few well
sites each. Costs associated with the
AVO method are largely for labor,
paying for qualified technicians and
their mileage to and from the well or
facility sites.237 AVO inspections are
not, however, very effective at catching
smaller or less obvious leaks, which can
be a source of significant wasted gas.
(ii) Portable Analyzers
Portable monitoring instruments or
portable analyzers detect hydrocarbon
leaks from individual pieces of
equipment. These analyzers may use
any of a variety of methods of detection,
including catalytic ionization, flame
ionization, photoionization, infrared
absorption, and combustion, and they
are generally used only to detect and
measure the quantity of a single
component of the vapor, such as
methane. These analyzers are sensitive
and can detect emissions at extremely
low concentration levels. Typical
portable analyzers range in cost from
$3,000–$12,000.238
One standard approach for using
portable analyzers is ‘‘Method 21,’’ the
EPA’s method for detecting VOC
emissions from leaking equipment.239
Method 21 provides the specifications
and performance criteria that must be
used under EPA’s regulations to detect
leaks using portable analyzers.
(iii) Optical Gas Imaging (Infrared
Camera)
A newer technology that operators
and inspectors are increasingly using for
leak detection is optical gas imaging
(OGI). OGI uses infrared detectors
(commonly called ‘‘infrared cameras’’)
to provide visual images of gas
emissions in real time. The OGI
instrument can be used to monitor a
wide range of oilfield equipment and its
effectiveness as a means for detecting
leaks is widely recognized.
OGI costs more than AVO approaches,
but it also detects more leaks, which can
result in additional gas savings. The
GAO noted that infrared cameras allow
237 API,
2014.
2014.
239 40 CFR part 60, App. A–7.
238 API,
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users to rapidly scan and detect vented
gas or leaks across wide production
areas. The GAO specifically
recommended that the BLM consider
the expanded use of infrared cameras,
where economical, to improve reporting
of emission sources and to identify
opportunities to minimize lost gas.240 In
its recent proposed rule, EPA also notes
the advantages of OGI compared to a
portable analyzer.241 Several studies
discussed in EPA’s white paper on leak
detection estimated that OGI can
monitor 1,875–2,100 components per
hour.242 In comparison, the average
screening rate using a portable analyzer
is roughly 700 components per day.243
Although EPA noted that these studies
may underestimate the amount of time
necessary to thoroughly monitor for
fugitive emissions using OGI
instruments, EPA stated that it still
believes that the use of OGI can reduce
the amount of time (and therefore the
cost) necessary to conduct fugitive
emissions monitoring, because multiple
fugitive emissions components can be
surveyed simultaneously.244
Infrared cameras have high capital
costs, and they also require calibration,
maintenance, and training. As a result,
while some operators purchase and
operate this equipment themselves,
others contract with specialized firms
for leak detection surveys using this
equipment. For example, the equipment
may cost from $85,000 to $100,000 or
more, with packages that include many
peripherals costing upwards of
$125,000. Batteries, chargers, and other
required peripherals can add $5,000 to
$10,000. Service provider rates may be
in the range of $500 per day to $2,000
per week, while annual service
contracts may range from $5,000 to
$10,000.245 Calculated on an individual
facility basis, another study found that
the average cost of hiring an external
service provider to conduct a leak
survey and provide a report is: $400 per
individual well site (with a single well);
$600 per single well battery, which
includes additional equipment on site;
$1,200 per multi-well battery; and
$2,300 per compressor station.246 The
BLM has also received information from
external service providers indicating
that costs can be substantially lower
than these, and we request comment on
this point.
240 GAO–11–34
(Oct. 2010) at 34.
FR 56593, 56634.
242 Ibid.
243 Ibid.
244 Ibid.
245 API, 2014.
246 Carbon Limits, 14, 32.
241 80
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Studies and some operators’
experiences indicate that LDAR
programs based on the use of infrared
cameras actually save operators money
overall, while substantially reducing
waste. For example, the Carbon Limits
study found that because leaks are not
evenly distributed across all facilities,
not every leak survey finds leaks and
saves money for the particular operator.
But when considered across a broader
set of facilities (such as those located on
BLM-administered leases or a set of
facilities owned by a single operator),
the study found that these programs
have either cost-neutral or positive
returns on average, depending on the
type of facility surveyed.
Specifically, the Carbon Limits study
found that for well sites and groups of
wells, about one-third of the facilities
had no detectable leaks, 7 percent had
leaks above 500 Mcf per year, and the
remainder had leaks of less than 500
Mcf per year. (To put this number into
perspective, a typical home uses 74 Mcf
of gas a year.247) For compressor
stations, roughly 10 percent had no
leaks, while almost 25 percent leaked at
500 Mcf per year or more.
When aggregated across a larger group
of facilities, rather than being evaluated
on a facility-by-facility basis, the Carbon
Limits study found that these infrared
camera leak surveys produce net cost
savings.248 Broken down by facility
type, it found that surveys at well sites
are cost-neutral measured on a ton of
avoided CO2-e basis, and that surveys at
compression stations produce net
savings. Specifically, on average, the net
present value (NPV) of applying LDAR
to an individual well site or well battery
was a loss of $35, assuming recovered
gas at $4 per Mcf. The average cost
saving across all compressor stations
surveyed was $3,376. Moreover, the
authors note that most of the facilities
in the study were Canadian facilities
that are already inspected for leaks
every 1 to 2 years, and thus the current
leak rates—and, consequently, proceeds
from repairs—at U.S. facilities without
leak inspection programs would be
expected to be higher.249
(iv) Continuous Emissions Monitoring
Systems and Other New Technologies
Another possibility for leak detection
is continuous emissions monitoring.
Continuous Emissions Monitoring
Systems (CEMS) are commonly used as
247 See
footnote 2.
Limits. The study increased the cost
estimates by 50 percent to account for the internal
costs to a firm of arranging for this work, and it
assumed a 7 percent discount rate and $4 per Mcf
value of gas.
249 Ibid.
248 Carbon
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a means of monitoring various
components of a large industrial
source’s emissions stream, including
oxygen, carbon monoxide and carbon
dioxide, for compliance with EPA or
State air emissions standards. More
recently, researchers have been
evaluating the possibility of adapting
the technology for use in identifying
leaks in and around oil and gas
operations.250 Due to the dispersed
nature of potential leaks within the area
of concern (compared to the
concentrated gases in a flue gas stream),
challenges remain in developing a
CEMS (standalone or mobile) that has
the requisite sensitivity to detect leaks
under a variety of atmospheric and field
conditions. One possibility is to use a
CEMS as an area monitor for fugitive
emissions, which would then alert the
operator for the need to use a more
focused leak detection device to
pinpoint the leak needing repair.
Research is continuing to determine if
CEMS could supplement or be a viable
alternative to current leak detection
instruments.
There is also extensive ongoing work
to develop other, more effective and less
costly advanced leak detection
technologies. For example, DOE
initiated an effort to advance methanesensing technologies through the
Advanced Research Projects Agency—
Energy (ARPA–E) MONITOR (Methane
Observation Networks with Innovative
Technology to Obtain Reductions)
program.251 In December 2014, this $30million, 3-year program announced
support for 11 new projects that are
developing low-cost, highly sensitive
systems that detect and measure
methane associated with the production
and transportation of oil and natural
gas.252
(iv) LDAR Programs
An effective LDAR program depends
not just on the technology used to detect
leaks, but also on the overall approach
an operator uses to inspect for leaks,
conduct preventative maintenance, and
repair leaks that are found. Two of the
largest operators in one of BLM’s field
offices conduct routine operations
checks, which typically use AVO
inspection methods. In addition to well
site inspections, a preventative
250 Briefing
from Dr. Bryan Wilson, Program
Director, Advanced Research Projects Agency—
Energy on O&G emission projects the agency is
funding, August 3, 2015.
251 ARPA–E, https://arpa-e.energy.gov/?q=arpa-eprograms/monitor.
252 Briefing from Dr. Bryan Wilson, Program
Director, Advanced Research Projects Agency—
Energy on O&G emission projects the agency is
funding, August 3, 2015.
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maintenance program is often used.
Adherence to a properly designed
preventive maintenance program
proactively minimizes equipment
failures and gas losses from leaks. In
general, a maintenance program may
consist of a variety of activities that are
applicable to operating location, type of
operations, and equipment used. An
operator will design the preventive
maintenance program that is most
suitable for the site. These efforts
include periodic inspection (AVO
inspection and general equipment
inspection on at least a monthly basis)
and service of components that are not
leaking, material selection appropriate
to service (i.e., alloys, gaskets, filters,
etc. that are wear and/or leak resistant),
active corrosion monitoring, the
application of corrosion and scale
inhibitors, use of maintenance records
to identify components at risk of failure,
and pre-emptive replacement of at-risk
equipment.253
For example, one major operator in
northwest New Mexico, which oversees
10,000 wells in the San Juan Basin, has
its lease operators visit each well site
each week.254 The visits are tracked
using GPS, which is installed in each
truck.255 According to the operator, any
leaks are fixed within days, new
facilities are leak-tested prior to
production, and most wells have
Remote Terminal Units installed, which
monitor gas flow rate and volume, static
pressure, differential pressure,
temperature, controller settings, plunger
arrivals/rod pump status/compressor
status and both oil and water tank
levels.256 The data flow via solarpowered telemetry at 1-minute
intervals. Alarms are triggered if there
are sudden pressure changes or tank
level drops, and a lease operator can be
dispatched to the well site to
investigate.257
(c) Proposals To Reduce Waste From
Leaks—Leak Detection and Repair
Programs
The BLM believes that LDAR
programs are a cost-effective means of
reducing waste of gas in the oil and gas
production process, based on the State
programs, studies, and findings
discussed above. Thus, the BLM is
253 API, June 13, 2014. Re: EPA VOC/Methane
White Paper on Oil and Natural Gas Sector Leaks.
Pages 7–9.
254 Phone conversation with Conoco Phillips on
San Juan Basin operation, February 2015.
255 Phone conversation with Conoco Phillips on
San Juan Basin operation, February 2015.
256 Phone conversations with Conoco Phillips and
WPX energy on San Juan Basin operations,
February 2015.
257 Ibid.
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proposing under §§ 3179.301 through
3179.305 to require that each operator
on a Federal or Indian lease institute an
LDAR program that meets specified
standards for detection methodology,
frequency, and leak repairs, and use this
program to inspect each of the
operator’s well sites and compressor
locations.
The BLM’s proposed approach,
outlined below, is similar to the
requirements adopted by Colorado and
Wyoming. EPA’s proposed regulations
to reduce methane emissions from the
oil and gas production sector also
include fugitive emission requirements,
which would apply to certain new and
modified oil and gas production
facilities. Specifically, the EPA’s
September 18, 2015 proposal, if
finalized, would require that new,
reconstructed, and modified well sites
and compressor stations conduct regular
(semi-annual, annual, or quarterly)
fugitive emissions surveys using optical
gas imaging technologies.258 As both
agencies have worked to develop their
proposed rules, we have shared
technical information and
communicated extensively. We share
the goal of aligning the final
requirements for LDAR in the two rules
to the maximum extent practicable. At
minimum, we would seek to ensure that
operators could develop a single LDAR
program that meets the requirements of
both agencies. We will continue to focus
on this issue over the course of the
rulemaking process, and we request
public comment on how best to achieve
this goal.
(i) LDAR Options in the Proposed Rule
The BLM proposes under § 3179.302
to require that operators use an
instrument-based approach to leak
detection. Advances in OGI leak
detection technology, in particular, now
allow for affordable detection of more,
smaller, and less accessible leaks,
compared to what would be identified
through a pure AVO approach. Both
Colorado and Wyoming require
operators to use an instrument-based
approach.259 In the EPA 40 CFR part 60
subpart OOOOa rulemaking, OGI is the
proposed technology for detecting
fugitive emissions.
The BLM believes that optical gas
imaging is currently the most effective
instrument for leak detection, but
infrared cameras may be more
expensive than portable analyzers,
which are also reasonably effective in
258 80
FR 56593, 56611–56614.
Air Quality Control Commission
Regulations, Regulation 7, 5 CCR 1001–9, Section
XVII.F.3; Wyoming Operational Rules, Drilling
Rules Section Ch. 8, Section 6(g).
certain situations. As infrared cameras
are used more commonly, and the
capacity to conduct infrared-based
surveys increases, the BLM believes that
the economics of this method will
become increasingly favorable for
identifying leaks at a wide variety of
operations. At present, however,
infrared cameras are most cost-effective
when used to inspect large numbers of
facilities. Thus, the BLM believes it is
appropriate to require an infrared
camera-based program for operators
with larger numbers of wells, and to
allow operators with fewer wells to use
portable analyzers instead.
The BLM also seeks to account for
advances in continuous emissions
monitoring technology, and also for
other advances in leak detection
technologies, which may result from
ongoing technology development efforts
such as the DOE ARPA–E MONITOR
program. We believe it is important to
ensure that operators be allowed to take
advantage of any new, more effective,
and less expensive technologies, as they
become available. Accordingly, the BLM
is proposing to require, under
§ 3179.302(b), that operators that have
500 or more wells within a BLM field
office jurisdiction must use one of the
following three approaches to LDAR: (1)
An optical gas imaging device like an
infrared camera; (2) A new, equally
advanced and effective monitoring
device, not yet developed and therefore
not listed in the rule text, which the
BLM would review and approve for use
by any operator; 260 or (3) A
comprehensive LDAR program,
approved by the BLM, that includes the
use of instrument-based monitoring
devices. The standard for approval of
options (2) and (3) would be a BLM
determination that the alternative
device or program meets or exceeds the
effectiveness for leak detection of an
optical gas imaging device used with the
frequency specified in proposed
§ 3179.303(a).
Operators with fewer than 500 wells
located within a single BLM field
office’s jurisdiction could use any of
these three LDAR approaches, but they
would also have the option of using a
portable analyzer device, such as a
catalytic oxidation, flame ionization,
infrared absorption or photoionization
device, operated according to
manufacturer specifications, and
assisted by AVO inspection.
The BLM requests comment on the
above LDAR proposal. In particular,
comments should address the
259 Colorado
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260 The BLM could provide notice to all operators
that it had found that a specified new technology
would satisfy these requirements.
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appropriateness of requiring the use of
optical gas imaging devices in some or
all circumstances. We request data and
comment on the appropriateness of
using the 500-well threshold to identify
those larger operators for whom the
economics of these devices may be more
favorable, whether optical gas imaging
is cost-effective for operators with a
smaller number of wells, and should
therefore be required for all operators.
Further, the BLM requests comment
on whether the above suite of options
for LDAR (three options for large
operators, four for smaller operators) is
reasonable to allow operators flexibility
to design and implement leak detection
programs that work for them, while still
setting sufficiently rigorous minimum
standards to ensure that all such
programs are comprehensive and
effective. In particular, we request
comment on whether the standard for
BLM approval of an alternative
approach (that it meets or exceeds the
effectiveness of an optical gas imaging
device used at the frequency specified
in proposed § 3179.303(a)) provides
sufficient guidance to the BLM, and
whether the standard would result in
adequate consistency across field
offices.
The BLM is also proposing under
§ 3179.302(a)(4) that operators who
choose to use portable analyzers would
be required to use them according to
manufacturers’ specifications. The
EPA’s Method 21, discussed above, is
one specific method for ensuring that
portable analyzers that are capable of
detecting fugitive emissions (or leaks)
are used in a manner that produces
accurate results. The BLM is not
proposing to require the use of Method
21. The BLM requests comments on: (1)
Whether this rule should require the use
of Method 21 if an operator chooses to
use a portable analyzer; (2) The
adequacy of manufacturers’ use
specifications to produce accurate
results regarding the presence or
absence of a leak; and (3) Whether there
are other use protocols for portable
analyzers that produce accurate results
for leak detection purposes.
The BLM also requests comment on
whether the regulations should include
a threshold volume of gas that will be
deemed a leak with respect to gas losses
detected by portable analyzers, and if
so, what that threshold volume should
be. In contrast to optical gas imaging,
portable analyzers are so sensitive that,
at the lowest measured levels, it may be
difficult to tell whether the analyzer is
detecting a leak or simply registering
background levels of the measured gas.
The BLM requests comment on whether
it should provide that a release of gas
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would be considered a leak if the
detected concentration were 500 ppm or
more above the measured background
levels. This would be consistent with
the EPA’s proposed approach, which
provides that a leak would be
considered repaired if a portable
analyzer, used according to Method 21,
indicates concentrations less than 500
ppm above background levels.
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(ii) Frequency of LDAR Inspections
Another key element of an effective
LDAR program is to define the
frequency of inspections. Colorado
bases its frequency-of-inspection
requirement on the level of estimated
uncontrolled emissions from storage
vessels or the potential to emit VOCs
from all facility components.261
Inspection frequency can vary from
monthly to annually depending on the
magnitude of the emissions.262
Wyoming simply requires quarterly
inspections.263
Multiple studies have found that a
relatively small percentage of facilities
are responsible for the majority of leaks
and for most of the wasted gas (this is
known as a ‘‘fat-tail’’ problem).264 If
some operators, in fact, experience
proportionally fewer leaks than others,
this would support allowing the
frequency of periodic screening to vary
depending on the operator’s past history
of leak detections. Based on experience
in the field, the BLM believes that there
are systematic differences among
operators’ leak rates, but we understand
that some recent studies indicate that
leak rates are random.265
Increasing survey frequency allows
more leaks to be found, but also
increases costs. Accordingly, the BLM
aims to establish an approach to survey
frequency that reduces the most waste at
the lowest cost. The Carbon Limits
study analyzed the impact of survey
frequency by analyzing over 400 annual
surveys.266 This study found that
annual or semi-annual (twice-yearly)
surveys generally resulted in net
benefits to the operator—the benefits of
leaks avoided exceeded the costs of the
surveys—whereas quarterly or more
regular surveys imposed net costs on the
operator—the costs of the frequent
261 Colorado Air Quality Control Commission
Regulations, Regulation 7, 5 CCR 1001–9 at Section
XVIII.F.3.
262 Ibid.
263 Wyoming, Nonattainment Area Regulations
Ch. 8 (June 2015), Section 6(g), available at
https://soswy.state.wy.us/Rules/RULES/9868.pdf.
264 See Zavala-Araiza, et al., Reconciling divergent
estimates of oil and gas methane emissions,
Proceedings of the National Academy of Sciences,
vol. 112, no. 51, at 15600 (Dec. 22, 2015
265 Ibid.
266 Carbon Limits.
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surveys outweighed the benefits of leaks
avoided. This study supports starting
with a frequency of annual or semiannual surveys. We request data and
comment on the data, methodology, and
analysis used in this study.
Thus, the BLM is proposing under
§ 3179.303 to require all operators to
conduct semi-annual surveys of their
sites—defined in proposed § 3179.303 to
mean a discrete area suitable for
inspection in a single visit and
containing wellhead equipment,
compressors, and facilities 267 (which
would include, for example, separators,
heater/treaters, and liquids unloading
equipment). If an operator finds no more
than two leaks at a site for two
consecutive inspections, it may change
to annual inspections at that site. If the
operator is inspecting semi-annually
and finds three or more leaks at a site
for two consecutive inspections, it must
inspect quarterly. The quarterly rate
would continue unless and until an
operator finds no more than two leaks
in two sequential inspections, at which
point it could revert back to twiceyearly inspections. On the other hand,
if the operator is inspecting semiannually and finds no more than two
leaks for two consecutive inspections,
the operator may reduce the frequency
of inspections to once per year, unless
and until it finds more than two leaks
for two consecutive inspections, which
would require it to revert back to semiannual inspections.
The BLM has proposed three or more
leaks at a site as the threshold for
increasing the frequency of inspections,
and two or fewer as the threshold for
decreasing the frequency of inspections,
as a possible way to distinguish between
sites with very little loss from leaks and
sites with more significant leak
problems. The BLM requests comment
on whether these are the appropriate
numbers of leaks to use as thresholds,
and if not, what the threshold levels
should be.
Once a leak is identified, the BLM
proposes under § 3179.304 that the
operator would be required to repair the
leak as soon as practicable, but no later
than 15 calendar days after discovery,
unless there is a good cause
necessitating a longer period. The BLM
believes that a ‘‘good cause’’ for a longer
period would be something that
267 Note that the BLM has proposed to define
‘‘facility’’ in part 3170 as ‘‘(1) A site and associated
equipment used to process, treat, store, or measure
production from or allocated to a Federal or Indian
lease, unit, or CA that is located upstream of or at
(and including) the approved point of royalty
measurement; and (2) A site and associated
equipment used to store, measure, or dispose of
produced water that is located on a lease, unit, or
CA.’’ 80 FR 40767 (July 13, 2015).
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prevents the operator from repairing the
leak within the 15 calendar day period
and that the operator could not
reasonably have prevented. Examples of
potential good cause for a longer period
include the unavailability of a needed
part or severe weather conditions that
prevent safe access to the site. Preferred
scheduling for maintenance would not
be an example of good cause for delay
in leak repair. If a delay in repair is
attributable to good cause, the operator
must notify the BLM of the cause and
must complete repairs within 15
calendar days after the cause of delay
ceases to exist. The BLM proposes to
require operators to verify the
effectiveness of a repair within 15
calendar days after completion using the
same leak detection method used to find
the leak.
The BLM proposes under § 3179.305
that operators be required to keep and
make available to inspectors records
documenting the dates of leak
inspections, the sites where any leaks
are found, and a description of each
leak. Operators would also need to
record when leaks were repaired, and
the dates and results of follow-up
inspections to verify the effectiveness of
the repairs.
The BLM is aware that some well sites
and compressor stations could be
subject to both the fugitive emission
requirements of the proposed EPA rule
and the requirements of the proposed
BLM rule. In addition to our request for
comments discussed above, regarding
further alignment of the BLM rule and
the EPA rule, we are proposing that an
operator may demonstrate to the BLM
that it is complying with the EPA LDAR
requirements in lieu of the BLM LDAR
requirements, for some or all of the
operator’s sites. We specifically request
comment on this element of the
proposal, including whether it would
help to reduce the compliance burden
on operators, whether it could
compromise program effectiveness in
any way, and whether it may present
challenges for BLM and EPA to
administer and enforce. The BLM
expects that the LDAR requirements
ultimately adopted by the EPA for new
and modified well sites would be as
effective in minimizing the volume of
gas lost through leaks as the final BLM
requirements, and we should be able to
confirm this expectation prior to
finalizing this proposed provision.
(iii) Possible Alternatives to the
Proposed LDAR Provisions
In addition to the BLM’s proposed
approach, we are taking comments on
other possible approaches to reducing
waste through LDAR requirements.
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These include variations on the
proposed approach, an alternative
approach suggested by a stakeholder,
and an alternative method of
establishing the inspection frequency.
One small variation on the proposed
LDAR approach would be to require that
LDAR inspections be conducted by
third parties. Requiring third parties to
conduct inspections could provide
additional assurance that surveys are
conducted effectively and produce
accurate results. While some operators
conduct their own inspections, many
already contract with third parties that
provide the equipment, trained
operators, and detailed reports. The
BLM acknowledges, however, that thirdparty contracting might in some
instances be more costly and might
prove unnecessary for operators that
have their own equipment and
substantial in-house expertise. A
variation on this option would require
periodic third party inspections as a
means of confirming the efficacy of an
operator’s internal leak detection
program, while still allowing most
inspections to be conducted in-house, if
an operator so chooses. For example, the
BLM could require that operators
contract with a third-party to perform at
least one annual or biannual inspection.
The BLM requests comments on these
options.
A second possible variation would be
to constrain approval of alternative leak
detection approaches. For example, the
BLM could limit authorization of
alternatives to new technologies and
devices, rather than new detection
programs. (That is, the final rule could
eliminate proposed § 3179.302(a)(3).)
Another approach would be to limit
authorization for an alternative leak
detection program under proposed
§ 3179.302(a)(3) to operators that
already have an effective program in
place as of the effective date of this rule.
That approach would reward operators
that proactively invest in leak detection,
but would require operators that do not
make that proactive investment to
comply with the standards established
in the regulation. The BLM requests
comment on these variations.
A third possible variation would be to
focus operators’ LDAR efforts on higher
production wells. For example, a
stakeholder suggested that the BLM
could require the development of an
LDAR program at those wells in the top
75 percent of an operator’s inventory, in
terms of production volume, and
address storage vessels separately.
Under this suggested approach, the
operator would be required to conduct
an initial survey of its top-producing
wells, and would then design an
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appropriate leak detection program,
with a specified frequency based on the
results of that survey.
Others have suggested modifying or
waiving the LDAR requirements for
stripper wells—a specific category of
low-yield wells producing 15 bbl of oilequivalent per day or less. In its 40 CFR
part 60 subpart OOOOa rulemaking, for
example, EPA proposed that new and
modified wells producing 15 bbl of oilequivalent per day or less be exempted
from the LDAR requirements, or
allowed to inspect less frequently, such
as annually or on a one-time basis.
Presumably, modifying the LDAR
requirements for stripper wells relies on
an assumption that the amount of
leaked methane correlates with well
production, and therefore frequent
LDAR is not a cost-effective means of
reducing methane emissions from lowproducing wells. In addition,
proponents of this approach assert that
LDAR requirements for marginal wells
would disproportionately impact small
businesses.
This rulemaking does not propose a
modified standard for stripper wells,
because 85 percent of oil wells and 73
percent of gas wells on Federal and
Indian leases meet the definition of
stripper wells.268
Thus, while reducing the frequency of
leak detection inspections for stripper
wells might decrease the costs of the
leak detection requirement, we believe
that approach would negate most of the
expected benefits of the LDAR
requirement for existing leases on
Federal and Indian lands.
Moreover, the factual record available
to the BLM indicates that requiring leak
detection at stripper wells would
produce significant gas savings. Recent
studies do not support the suggestion
that leak rate correlates with yield.
Rather, these studies suggest that even
low-yield wells can leak at significant
rates.269 Based on these studies, DOI
does not believe it is appropriate to
exclude low-yield wells from any
instrument-based inspection
requirement, or to allow those wells to
be inspected less frequently.
Establishing a separate standard for
stripper wells also would not align the
proposed BLM requirements with the
proposed EPA requirements. The EPA’s
standard for stripper wells applies only
268 U.S. Energy Information Administration.
United States Total 2009 Distribution of Wells by
Production Rate Bracket, available at https://
www.eia.gov/pub/oil_gas/petrosystem/us_
table.html.
269 See Zavala-Araiza et al., Reconciling divergent
estimates of oil and gas methane emissions,
Proceedings of the National Academy of Sciences,
vol. 112, no. 51, at 15600 (Dec. 22, 2015).
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to new or modified wells that come
online as stripper wells, not to wells
that initially produce at higher rates, but
eventually decline to stripper status.
Based on our experience in the field, we
believe that a very small number of
wells would qualify for a relaxed
standard under the EPA proposal. In our
experience, most new wells produce at
rates higher than 15 barrels-of-oilequivalent per day, because operators
are unlikely to invest in completing
newly drilled wells that produce at very
low rates.
Many of the stripper wells producing
from Federal and Indian leases are
existing wells that once produced at
higher rates, but have declined to
stripper status, and they therefore
would not qualify for the EPA’s LDAR
standards for stripper wells. Thus,
although the BLM recognizes the
importance of harmonizing this rule
with EPA’s proposed 40 CFR part 60
subpart OOOOa rulemaking,
establishing a different LDAR standard
for existing stripper wells on Federal or
Indian leases would not, in fact,
advance that goal.
Another alternative approach to the
proposed LDAR requirements would be
to retain all of the elements of the
proposed approach, except the basis for
setting the required frequency of
inspections. Specifically, rather than
having the frequency vary based on the
results of previous surveys, the
inspection frequency would be set based
on the type of facility being inspected.
As noted previously, Colorado uses this
method, with frequencies that range
from monthly to one-time, depending
on the type of facility and the level of
uncontrolled VOC emissions.
One simplification of the Colorado
approach would be to focus on sites
with vibrating equipment or storage
vessels. Industry stakeholders have
stated that they find most leaks at sites
with equipment that vibrates (e.g.,
compressors), and at sites with storage
vessels. Thus, requiring more frequent
inspections at sites with those
characteristics, and less frequent
inspections at other sites, might be a
way to increase the cost effectiveness of
the LDAR program by targeting
inspections to the sites most likely to
produce the largest losses through leaks.
A different simplification of
Colorado’s system would be to
distinguish between gas wells and oil
wells, requiring more frequent
inspections at gas wells and less
frequent inspections at oil wells. EPA’s
emissions factors indicate generally
higher volumes of fugitive emissions
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from gas wells, compared to oil wells.270
Assuming these emissions factors are
accurate, this indicates that focusing
more inspection resources on gas than
oil wells would identify and save a
relatively larger volume of gas at
roughly the same cost.
(iv) Requests for Comments on LDAR
Alternatives
The BLM requests comment on all of
the LDAR variations discussed above. In
particular, the BLM requests comment
on:
• The initial frequency of surveys;
• Requiring more frequent surveys,
such as quarterly;
• The concept of changing inspection
frequency depending on the operators’
record of past leaks;
• The triggers for increasing and
decreasing inspection frequency (e.g.,
whether finding a certain number of
leaks is the appropriate trigger for
changing inspection frequency); and
• Whether the frequency of
inspections should be the same across
all of the sites on a lease, and if so, how
to operationalize that requirement.
In connection with any comments
related to modifying the inspection
frequency for stripper wells, the BLM
specifically requests submission of data
regarding the relationship between well
production and levels of leaked
methane from a well site. The BLM also
requests comment on whether it should
require gas wells to be inspected
quarterly and oil wells annually. While
there is substantial uncertainty in the
cost-benefit analysis of these provisions,
with certain simplifying assumptions,
the analysis indicates that this
alternative approach could increase net
benefits, compared to the proposed
approach. As detailed in the RIA, the
projected annual net benefits for a semiannual inspection requirement for all
wells range from $19–48 million, with
the range largely depending on the year,
compared to annual net benefits of $3–
43 million (again largely depending on
the year) with quarterly inspections for
gas wells and annual inspections for oil
wells.271
In addition, the BLM requests
comment on simply requiring semiannual or quarterly inspections for all
well sites, facilities, and compressor
stations subject to the LDAR
requirements, with no mechanism to
increase or decrease inspection
frequency based on how many leaks are
found. A quarterly inspection
requirement would track the Wyoming
approach for the Upper Green River
270 80
FR 56593, 56635.
at 113.
271 RIA
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Basin. Requiring semi-annual or
quarterly inspections for all sites would
reduce the potential confusion of
inspection frequencies that vary over
time and across an operator’s well sites.
Tracking the required frequency for
each discrete leak inspection site could
be burdensome and prone to error and
confusion. Requiring quarterly
inspections would also maximize the
gas savings from avoided leaks,
although it would have higher costs
than the other approaches discussed
here. As with setting different
frequencies for gas and oil wells, this
approach would not track with the
EPA’s LDAR requirements, assuming
that the EPA finalizes its proposed
approach.
The BLM also requests comment on
the approach of focusing the LDAR
requirement on sites with vibrating
equipment or storage tanks, perhaps by
requiring a one-time inspection of all
sites, but quarterly inspections of sites
with such equipment. Would that
approach successfully target sites that
are most prone to significant leaks?
Would it reduce costs for operators?
And finally, could it readily be
enforced?
Finally, the BLM notes that many of
these LDAR approaches deviate from
EPA’s proposed approach. The BLM
requests comment on the importance
and implications of aligning BLM and
EPA LDAR requirements.
(v) Costs of the LDAR Provisions
Assuming that the EPA finalizes its 40
CFR part 60 subpart OOOOa
rulemaking, then the BLM expects that
its proposed requirements would affect
up to 36,700 existing wellsites, and pose
total costs of about $69–70 million per
year (using 7 percent and 3 percent
discount rates). These requirements are
also projected to result in cost savings
of about $12–15 million per year (7
percent discount rate) or $15–17 million
per year (3 percent discount rate),
increase gas production by 3.9 Bcf per
year, and reduce VOC emissions by
18,600 tpy. We estimate they would
reduce methane emissions by 67,000
tpy, producing monetized benefits of
$73 million per year in 2017–2019, $87
million per year in 2020–2024, and $100
million in 2025 and 2026. Thus, we
estimate that these provisions would
result in net benefits of $19–21 million
per year in 2017–2019, $31–35 million
per year in 2020–2024, and $43–48
million in 2025 and 2026.272 We request
data and comment on whether this
analysis fully captures the benefits of
272 RIA
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identifying and fixing high-volume
leaks.
If, for analytical purposes, we assume
a baseline in which EPA does not
finalize its proposed LDAR
requirements, we estimate the following
impacts from our proposed LDAR
requirements. We project that the
proposed requirements would affect up
to about 37,000–38,000 wellsites per
year, and pose total costs of about $70–
71 million per year (using 7 percent and
3 percent discount rates). These
requirements are also projected to result
in cost savings of about $12–18 million
per year (using 7 percent and 3 percent
discount rates), increase gas production
by 3.9–4.0 Bcf per year, and reduce VOC
emissions by 19,000 tpy. We estimate
they would reduce methane emissions
by 68,000 tpy, producing monetized
benefits of $75 million per year in 2017–
2019, $88 million per year in 2020–
2024, and $102 million in 2025 and
2026. Thus, we estimate that these
provisions would result in net benefits
of $19–21 million per year in 2017–
2019, $30–35 million per year in 2020–
2024, and $43–48 million in 2025 and
2026.273
As noted, some operators reportedly
already have leak detection programs in
place. To the extent that these operators
currently have LDAR programs that are
approved by the BLM, the actual
impacts of this proposal would be lower
than these estimates.
3. Pneumatic Controllers and Pneumatic
Pumps
Pneumatic controllers are automated
instruments that control certain
processes or conditions, such as liquid
level, pressure, and temperature in oil
and gas production, treatment, storage,
and handling operations. Pneumatic
controllers are operated by gas pressure,
and the gas is emitted from the device
when the device is active. Some types
of controllers ‘‘bleed’’ gas continuously
as part of their normal operations, while
others emit gas intermittently. While
these controllers can operate using any
pressurized gas, for the purposes of this
proposed rule, the term pneumatic
controller means an instrument that is
operated by natural gas pressure and
emits natural gas.
Pneumatic pumps of different
varieties are commonly used in oil and
gas production and treating operations.
For example, gas-assist glycol
dehydrator pumps are used to circulate
glycol in dehydrators. Chemical
injection pumps are used to pump
chemicals down a well to facilitate
production or into a pipeline to prevent
273 RIA
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freezing. Diaphragm pumps are used to
move larger volumes of liquids, such as
to circulate heat trace medium at well
sites during cold winter conditions, or
to pump out sumps. Similar to
pneumatic controllers, pneumatic
pumps can operate on gas pressure and
emit that same gas from the pump. For
the purposes of this proposed rule, the
term pneumatic pump means a pump
that is operated by natural gas pressure
and emits natural gas.
asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
(a) Estimates of Gas Released From
Pneumatic Controllers and Pneumatic
Pumps
As described in the RIA, using data
from the EPA GHG Inventory, we
estimate that about 5.4 Bcf of natural gas
was lost in 2013 from pneumatic
controllers on BLM-administered
leases.274 That volume includes releases
from high bleed continuous controllers,
low bleed continuous controllers, and
intermittent controllers. Using
prevalence data from the EPA and an
analysis of EPA GHGRP data conducted
by ICF, we estimate that there are 18,150
high bleed pneumatic controllers on
BLM-administered leases, or about 19
percent of the total number of
pneumatic controllers on these leases.
In addition, using data from the EPA’s
GHG Inventory, we estimate that about
2.5 Bcf of natural gas was lost in 2013
from pneumatic pumps on BLMadministered leases. That volume
includes releases from chemical
injection pumps, diaphragm pumps,
and gas-assist glycol dehydrator pumps.
(b) Technologies To Reduce Quantities
of Gas Released From Pneumatic
Controllers and Pneumatic Pumps
Pneumatic controllers and pneumatic
pumps are common equipment at well
site facilities. For well sites without
electrical service, gas pressure is used as
a ready energy source to operate this
equipment. There are several options for
minimizing the amount of natural gas
that is used and emitted from existing
controllers and pneumatic pumps,
which bear a range of associated cost
and practicality considerations.
As discussed earlier in § III.I.3, in the
existing EPA NSPS rule (40 CFR part 60
subpart OOOO) for the oil and gas
sector, the EPA established an emissions
rate of 6 scf/hour as the upper limit for
new and replacement pneumatic
controllers (pneumatic controllers
meeting this standard are referred to as
‘‘low-bleed’’ pneumatic controllers).275
The EPA NSPS requires new and
replacement natural-gas-operated
274 RIA
275 40
at 18.
CFR 60.5390.
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pneumatic controllers at natural gas
well sites and gathering and boosting
stations to meet the 6 scf/hour limit,
unless a higher bleed rate is necessary
for safety or to perform the designed
function. The EPA NSPS requirement
does not currently apply to intermittent
pneumatic controllers nor to pneumatic
pumps, but the EPA’s proposed 40 CFR
part 60 subpart OOOOa rulemaking
would extend to new or modified
pneumatic pumps.276
Existing high-bleed controllers can
generally be replaced with models that
use and emit less natural gas. For most
applications, low-bleed controllers are
available and make suitable
replacements for high-bleed controllers.
At facilities with a gas sales line, the
replacement cost of low-bleed
controllers is generally rapidly offset by
gas savings. ICF identified replacement
of high-bleed pneumatic controllers
with low-bleed pneumatic controllers as
one of the most cost-effective options for
reducing methane. Specifically, ICF
estimated that the replacement would
save industry $2.65 per Mcf of avoided
methane emissions.277
The State of Colorado has prohibited
use of ‘‘high bleed’’ pneumatic
controllers, with limited exemptions.278
Colorado adopted the existing EPA
NSPS standards for new pneumatic
controllers, prohibiting operators from
installing new ‘‘high bleed’’ controllers,
and the State required operators to
replace all existing high bleed
controllers with low-bleed or no-bleed
controllers by May 1, 2015.279 The
operator may request an exception on
the grounds that use of a high-bleed
controller is needed for safety or process
purposes. As of April 2015, however,
the State had not received a single
request to use or keep high bleed
controllers under this provision.280
In May of this year, the State of
Wyoming adopted regulations that
require operators in the Upper Green
River Basin to replace high-bleed
pneumatic controllers with low-bleed
controllers by January 1, 2017.281
276 80
FR 56593, 56610.
economic analysis, at 4–4 (base case
assumed $4/Mcf price for recovered gas and a 10
percent discount rate/cost of capital).
278 Colorado Air Quality Control Commission
Regulations, Regulation 7, 5 CCR 1001–9, Section
XVIII, available at https://www.colorado.gov/
pacific/sites/default/files/5-CCR-1001-9_0.pdf.
279 Ibid. at Section XVIII.C.2.
280 Email from Daniel Bon, Air Quality Planner,
Planning and Policy, Air Pollution Control
Division, Colorado Department of Public Health and
Environment, to Alexandra Teitz, BLM (April 27,
2015).
281 Wyoming, Nonattainment Area Regulations
Ch. 8 (June 2015), Section 6(f), available at https://
soswy.state.wy.us/Rules/RULES/9868.pdf.
277 ICF
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Another option that is available in
some situations is adding electrical
service (power line, generator, or solar
array) and replacing pneumatic
controllers and/or pneumatic pumps
with electric or compressed air
controllers and pumps, which do not
release any natural gas. Where electrical
service is available, existing pneumatic
controllers and pneumatic pumps could
be operated by the addition of a
compressed air system. Installing a
compressed air system would involve
adding a compressor and tubing to
connect each controller and pump to the
system. Alternatively, pneumatic
controllers and pneumatic pumps could
be replaced by electric models. At
facilities with a gas sales line, the cost
of replacing electric controllers and
operating the power system would be at
least partially offset by sale of the gas
that would otherwise have been vented
through operation of the pneumatic
controllers and pneumatic pumps.
Natural gas could be used to generate
electricity to operate electronic
controllers; based on the typical number
of controllers at a well site and the
energy requirements of controllers,
however, the BLM does not believe this
is the most efficient means of
completing the operational objective.
One of the more common applications
of this approach is to use solar powered
electric controllers and pumps to
replace individual pneumatic
controllers and pneumatic pumps
without replacing the power system for
the whole facility. Solar pumps are
often used to replace pneumatic
chemical injection pumps, in particular.
Chemical injection pumps are smaller
pumps that inject chemicals into a
pipeline to, e.g., to inhibit freezing, and
they do not require as much power as
larger pumps used in other applications.
The EPA’s Natural Gas STAR program
cites the costs to replace a pneumatic
pump with a solar-charged electric
pump as about $2,000. Operating costs
are minimal, and the lifespans of the
solar panels and electric motors are up
to 15 and 5 years, respectively. The EPA
estimates potential annual natural gas
savings of 183 Mcf per pneumatic pump
replaced—a volume that would have a
sales value of $732 (at $4/Mcf).282
A third option for reducing gas losses
from pneumatic controllers and
pneumatic pumps is to add a lowpressure collection system that would
capture the natural gas emitted from
pneumatic controllers and pneumatic
282 U.S. EPA, Office of Air Quality Planning and
Standards, Oil and Natural Gas Sector Pneumatic
Devices Report for Oil and Natural Gas Sector
Pneumatic Devices Review Panel (April 2014) at 53.
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pumps and either combust it or repressure and route it into the natural gas
sales stream.
The State of Wyoming has adopted
regulations that require pneumatic
pumps used in the Upper Green River
Basin to destroy or capture emissions or
be replaced by zero-emission solar-,
electric-, or air-driven pumps by January
1, 2017.283
(c) Proposals To Reduce Waste From
Pneumatic Controllers and Pneumatic
Pumps
The BLM believes that replacing highbleed pneumatic controllers with lowor no-bleed controllers is a cost-effective
way to reduce waste of natural gas. In
most cases, this is projected to increase
operators’ net profits. We have heard
from one company that has already
voluntarily replaced all of its high-bleed
pneumatic controllers because it found
that the new equipment more than paid
for itself within 3 to 6 months.284 Given
the EPA requirements for new
pneumatic controllers and the fact that,
on average, this waste-reduction
measure would save companies money,
the BLM believes that continued
reliance on high-bleed pneumatic
controllers leads to avoidable waste of
public resources, except in limited
situations.
Under proposed § 3179.201, the BLM
would require operators to replace all
pneumatic controllers that have bleed
rates greater than 6 scf/hour with lowbleed or no-bleed pneumatic controllers
within 1 year of the effective date of the
final rule. This rule would apply only
to pneumatic controllers that are not
subject to the EPA regulations at 40 CFR
60.5360 through 60.5390. We request
comment on whether 1 year is an
appropriate amount of time for
compliance, and whether we should
include interim deadlines for the
replacement requirement such that
operators must replace certain
percentages of their pneumatic
controllers within specified timeframes.
In § 3179.201(b), the BLM is
proposing several exemptions to the
replacement requirement. Like the
existing EPA NSPS, this proposed rule
would allow an exception to the
maximum emission rate for a pneumatic
controller when the operator
demonstrates, and the BLM concurs,
that a higher emission rate is necessary
for response time, safety, and positive
actuation. The proposed rule would also
provide for an exception from the
283 Wyoming, Nonattainment Area Regulations
Ch. 8 (June 2015), Section 6(e), available at https://
soswy.state.wy.us/Rules/RULES/9868.pdf.
284 Phone conversation with Conoco Phillips on
San Juan Basin operation, February 2015.
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replacement requirement if the
requirement would cause the operator to
cease production and abandon
significant recoverable oil reserves
under the lease. In making this
determination, the BLM would consider
the costs of capture, and the costs and
revenues of all oil and gas production
on the lease.
In addition, under proposed
§ 3179.201(c), the BLM would allow an
operator to retain a high-bleed
pneumatic controller for up to 3 years
from the effective date of the final rule,
if the well or facility served by the
controller has an estimated remaining
productive life of no more than 3 years
from the effective date of the final rule.
The BLM believes the 3-year threshold
represents the typical payback period
for a replacement controller, given an
average-cost replacement device,
average reduction in waste gas, and an
average value for the recovered gas. We
request comment on whether this
extension is needed and whether it
would meaningfully reduce costs for
operators with wells and facilities with
remaining productive lives less than 3
years from the effective date of this rule.
We also request comment on whether
providing this extension would increase
waste of gas and make implementation
of the replacement requirement more
difficult, as the actual remaining
productive life of a well or facility may
be longer than projected. We note that
neither Colorado nor Wyoming provides
for such an extension.
We estimate that the proposed
pneumatic controller requirements
would impact up to about 15,600
existing low-bleed pneumatic devices,
and pose total costs of about $6 million
per year (using a 7 percent discount
rate) or $5 million per year (using a 3
percent discount rate). Because the sale
of recovered gas is expected to offset the
engineering costs of new controllers, the
BLM expects that compliance with the
pneumatic controller requirements
would increase gas production by 2.9
Bcf per year, result in cost savings to the
industry of about $9–11 million per year
(using a 7 percent discount rate) or $11–
12 million per year (using a 3 percent
discount rate). On net, we project that
the industry would save $3–5 million
per year (using a 7 percent discount
rate) or $6–7 million per year (using a
3 percent discount rate) under these
requirements. These requirements are
also projected to reduce methane
emissions by 43,000 tpy, producing
monetized benefits of $48 million per
year in 2017–2019, $56 million per year
in 2020–2024, and $65 million in 2025
and 2026. The resulting net benefits
(including the cost savings from the
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value of the gas) would be $53–68
million per year (using a 7 percent
discount rate) or $54–73 million per
year (using a 3 percent discount rate),
along with a reduction in VOC
emissions of about 200,000 tpy.285
For pneumatic chemical injection
pumps, the BLM believes that in many
instances the function performed by
such a pump could be performed by a
zero-emissions pump (typically solar)
instead. The BLM believes that the
replacement costs in these situations are
relatively modest and would be at least
partially offset by the value of the saved
gas. Where a zero-emissions pump
could not perform the function, but a
flare is available on-site, the cost of
routing the gas from either a chemical
injection pump or a diaphragm pump to
a flare is expected to be quite small.
Thus, the BLM is proposing under
§ 3179.202 to require the operator either:
(1) To replace a pneumatic chemical
injection or diaphragm pump with a
zero-emissions pump; or (2) To route
the pneumatic chemical injection or
diaphragm pump to a flare. Under
proposed § 3179.202(c), an operator
would be exempt from this requirement
if it demonstrates, and the BLM concurs,
that: (1) There is no existing flare device
on site, or routing to such a device is
technically infeasible; and (2) A zeroemission pump is not a viable
alternative because a pneumatic pump
is necessary based on functional needs.
An operator would also be exempt if the
operator demonstrates, and the BLM
concurs, that replacing the pneumatic
pump(s) would impose such costs as to
cause the operator to cease production
and abandon significant recoverable oil
reserves under the lease. This rule
would apply only to pneumatic pumps
that are not subject to the EPA
regulations. As with pneumatic
controllers, the BLM proposes that
operators must replace pneumatic
pumps or route to a flare device, subject
to this proposed section, within 1 year
of the effective date of the rule, or
within 3 years of the effective date of
the rule if the pneumatic pump serves
a well or facility with an estimated
remaining productive life of 3 years or
less. We request comment on whether
this extended time-period for
replacement is needed or whether a
shorter time-period would be sufficient.
In Wyoming, pneumatic pump
replacement is now required by
regulation by January 1, 2017.286
285 RIA
at 78.
286 Wyoming,
Nonattainment Area Regulations
Ch. 8, Section 6(e) (June 2015), available at https://
soswy.state.wy.us/Rules/RULES/9868.pdf.
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If the EPA finalizes its concurrent 40
CFR part 60 subpart OOOOa
rulemaking, the BLM estimates that the
proposed requirements would impact
up to 8,775 existing pumps, posing total
costs of about $2.5 million per year.
They would also increase gas
production by 0.46 Bcf per year and
result in cost savings of about $1.5–1.9
million per year (7 percent discount
rate) or $1.75–2.15 million per year (3
percent discount rate). In addition, they
are projected to reduce methane
emissions by about 16,000 tpy,
producing monetized benefits of $18
million per year in 2017–2019, $21
million per year in 2020–2024, and $24
million in 2025 and 2026. This would
result in net benefits of $17 million per
year in 2017–2019, $20 million per year
in 2020–2024, and $23 million in 2025
and 2026, as well as reducing VOC
emissions by about 4,000 tpy.287
Assuming, for purposes of analysis,
that EPA does not finalize the 40 CFR
part 60 subpart OOOOa rulemaking, the
BLM estimates that the pneumatic
pump requirements would affect up to
about 8,775 existing pumps and about
75 new pumps per year, posing total
costs of about $2.5–2.7 million per year
(using 7 percent and 3 percent discount
rates). They would also increase gas
production by 0.5 Bcf per year and
result in cost savings of about $1.5–2.2
million per year (using 7 percent and 3
percent discount rates).
In addition, they are projected to
reduce methane emissions by about
16,000–17,000 tpy, producing
monetized benefits of $18 million per
year in 2017–2019, $22 million per year
in 2020–2024, and $26 million in 2025
and 2026. This would result in net
benefits of $17 million per year in 2017–
2019, $21–22 million per year in 2020–
2024, and $25 million in 2025 and 2026,
as well as reducing VOC emissions by
about 4,000 tpy.288
We request comment on the
practicality and costs of replacing
pneumatic chemical injection and
diaphragm pumps with solar pumps or
routing the pump exhaust to a flare that
is already installed on-site, including
whether 1 year is an appropriate amount
of time for compliance.
Unlike pneumatic chemical injection
and diaphragm pumps, the BLM has not
identified a cost-effective means to
reduce gas releases from gas-assist
glycol dehydrator pumps at sites that
are not connected to the electric grid,
and thus we are not proposing any
requirements to reduce gas losses from
gas-assist glycol dehydrator pumps. The
287 RIA
288 RIA
at 82.
at 81.
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BLM requests comment, however, on
whether there are additional measures
that could further reduce gas lost from
pneumatic pumps.
4. Storage Vessels
Storage vessels are ubiquitous in oil
and gas production. Crude oil and
condensate storage vessels are designed
to hold a slight back-pressure. When the
pressure in the vessel exceeds the backpressure—due to fluids being added or
an increase in temperature of the vessel
contents—vapors are allowed to escape,
thereby equalizing the pressure inside
the vessel. Released vapors are a lost
source of energy and revenue, and they
also represent a safety and health
concern for on-site workers. In addition,
these vapors, which may contain
methane, ethane, and a variety of VOCs,
contribute to local air pollution
problems. The significance of vapor
loss, in terms of energy losses, revenue
losses, safety risks and environmental
impacts, depends upon the volume and
composition of the released vapors.
New, modified, and reconstructed
storage vessels used in oil and natural
gas production, natural gas processing,
and natural gas transmission and storage
are already subject to emissions limits
under the EPA NSPS, which requires
that individual storage vessels with
potential to emit VOC emissions equal
to or greater than 6 tpy achieve at least
a 95 percent reduction in VOC
emissions.289 The EPA standards also
provide that if a storage tank that
initially emitted at least 6 tpy of VOCs
now emits less than 4 tpy without
considering any emission controls in
place for a period of 12 consecutive
months, emission controls are not
required if the operator monitors
regularly to ensure that emissions do
not exceed 4 tpy.290 Unmodified storage
vessels that were in place as of August
23, 2011, are currently allowed to vent
vapors uncontrolled, unless subject to
State controls.291 EPA requires operators
to determine the VOC emission rate
within 30 days, and storage vessels must
have a cover and closed vent system
that meets specifications.292
Colorado requires the capture or
combustion of vapors from storage
vessels with a capacity to emit 6 tpy
VOC or more.293 The control equipment
must reduce hydrocarbons by 95
percent, or by 98 percent if the operator
289 40
6653
uses a combustion device.294 Storage
vessels that require emission control
systems are also subject to increased
monitoring, and Colorado requires
operators to develop STEM plans.295
In the Upper Green River Basin,
Wyoming requires that when VOC
emissions from vessels or glycol
dehydrators are at least 4 tpy, the
operator must reduce those emissions
by 98 percent.296
(a) Estimates of Quantities of Gas Lost
From Storage Vessels
The quantity of gas released from
condensate and storage vessels depends
on the throughput volumes of those
vessels and how much gas is lost for a
given volume of throughput. These loss
rates vary depending on whether the
vessel is controlled or uncontrolled and
on the region of the country in which
it is located. We estimate that 2.77 Bcf
of natural gas was lost in 2013 from
storage vessels venting on Federal and
Indian lands.297 These estimates were
calculated using data from the 2015
GHG Inventory and the share of natural
gas and crude oil production coming
from Federal and Indian lands.
(b) Technologies and Practices To
Reduce Gas Losses From Storage Vessels
Storage vessel vapors can be
controlled by routing them to a flare or
combustor, or by installing a VRU,
which collects and compresses the
vapors and returns them to the vessel or
into a natural gas sales line.
Where a well facility is equipped with
a flare pit or flare stack, tank vapors
could be routed to that flare device.
With a properly designed manifold,
these flare devices can meet the 95
percent emission control standard
established in the current EPA NSPS.298
Combustors are enclosed devices that
efficiently combust tank vapors by
ensuring an optimal mix of air and
flammable vapor entering the
combustion chamber. Combustors meet
the 95 percent emission control
standard established in the existing EPA
NSPS. Combustors can be sized for a
specific volume of natural gas/vapors, or
can be operated in series to
accommodate a wide volume range.
Combustors are not dependent on other
equipment or operating conditions and
therefore have wide applicability.
In proposing the existing NSPS rule,
EPA estimated that the average
operating cost of a flare device (which
CFR 60.5395.
290 Ibid.
294 Ibid.
291 Ibid.
295 Ibid.
292 40
CFR 60.5395, 60.5415–5416.
293 Colorado Air Quality Control Commission
Regulations, Regulation 7, 5 CCR 1001–9, Section
XVII.C.
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296 Wyoming Operational Rules, Drilling Rules
Section Ch. 8, Section 6(d).
297 RIA at 18.
298 40 CFR part 60 subpart OOOO.
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includes both flares and combustors) is
$8,900 per year, assuming that a flare
device is already in place at the
facility.299
VRUs meet the 95 percent emission
control standard established in the EPA
NSPS, and because the vapors are
captured, there are no combustion
emissions. Applicability of VRUs is
limited by a number of conditions.
VRUs require a power source, and a gas
line must be available into which the
controlled vapors can be directed. Due
to their relatively high cost of operation
(which EPA estimated at $18,900 per
year in proposing its 2012 NSPS
rule300), the economic viability of a VRU
as a storage tank emission control
device depends on high production
throughput. In other words, net VRU
costs rise as production volumes
decline.
(c) Proposals To Minimize Vapor Losses
From Storage Vessels
Under proposed § 3179.203, the BLM
would address gas losses from storage
vessels that are not covered by the EPA
standards for new and modified storage
vessels—or, by and large, existing,
unmodified storage vessels. The BLM
believes that reducing venting from
existing storage vessels with higher rates
of venting is a reasonably cost-effective
means of reducing gas losses. We also
believe that rather than establishing new
and separate standards for venting from
existing vessels, it would be easier for
operators to comply if we require
existing vessels on Federal and Indian
leases to meet the same standards that
already apply to new, rebuilt, and
modified vessels on those leases.
The aim of this proposed rule is to
reduce waste of whole gas.
Nevertheless, the BLM believes that it
may be appropriate to express the
requirements for storage vessels as a
VOC standard (as a proxy) rather than
a whole gas standard, as EPA and
Colorado do. There is no uniform
conversion factor to translate a VOC
standard like that established by EPA
and Colorado into a whole gas standard.
The ratio of VOCs leaked to
hydrocarbons leaked depends on the
makeup of the gas in the particular
vessel. We propose to adopt the same
standard that EPA applies to new
storage vessels. Specifically, the BLM
proposes to require, under
§ 3179.203(c), that VOC emissions from
existing vessels with VOC emissions
equal to or greater than 6 tpy be routed
to a combustion device, continuous
flare, or sales line. Under proposed
299 76
FR 52738 (Aug. 23, 2011).
300 Ibid.
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§ 3179.203(d), these requirements would
no longer apply if the uncontrolled VOC
emissions fall below 4 tpy for 12
months. This proposed lower bound
addresses the fact that well production,
and hence gas losses from vessels, are
expected to decline over time, and it is
less cost-effective to require control of
lower volumes of tank venting. The 6
tpy and 4 tpy thresholds are consistent
with EPA regulations.301
We request comments on the
approach of applying EPA’s new source
threshold to existing storage vessels, to
facilitate efficient compliance for the
industry.
The proposed 6 tpy threshold tracks
Colorado’s standard for new storage
vessels.302 The threshold is somewhat
less stringent than Wyoming’s
requirements, which apply to facilities
with VOC emissions of 4 tpy or more
and extend to glycol dehydrators, which
the BLM does not propose to
regulate.303 The BLM also requests
comment on applying a more stringent
threshold consistent with Wyoming’s
requirements.
The BLM estimates that the proposed
requirements would affect about 300
existing storage vessels on BLMadministered leases, and pose total costs
of about $6 million per year (using 7
percent and 3 percent discount rates).304
We project that these requirements
would increase gas production by 0.04
Bcf per year, resulting in cost savings of
about $0.1—0.2 million per year (using
7 percent and 3 percent discount rates).
They would also reduce methane
emissions by 7,000 tpy, producing
monetized benefits of $8 million per
year in 2017–2019, $9 million per year
in 2020–2024, and $11 million in 2025
and 2026. Overall, we estimate that
these provisions would result in net
benefits of $2 million per year in 2017–
2019, $3–4 million per year in 2020–
2024, and $5 million in 2025 and 2026,
and reduce VOC emissions by 32,500
tpy.305
5. Well Maintenance and Liquids
Unloading
Over time, as well pressure in a
natural gas well drops, liquids often
start accumulating at the bottom of the
well, which can then slow or halt gas
production. Operators must remove or
‘‘unload’’ the liquids to maintain or
restore production. Some of the
301 40
CFR 60.5395.
Air Quality Control Commission
Regulations, Regulation 7, 5 CCR 1001–9, Section
XVII.C.
303 Wyoming Operational Rules, Drilling Rules
Section Ch. 8, Section 6(d).
304 RIA at 95.
305 Ibid.
302 Colorado
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methods used for liquids unloading can
release substantial quantities of natural
gas into the environment. In particular,
operators sometimes allow the bottom
hole pressure to increase and then vent
or ‘‘blow down’’ or ‘‘purge’’ the well.
(a) Estimates of Quantities of Gas Lost
Through Well Maintenance and Liquids
Unloading
The amount of gas lost through
liquids unloading varies substantially
across regions, and also depends on
whether wells are equipped with
plunger lifts. We estimate that 3.26 Bcf
of natural gas was lost in 2013 during
liquids unloading operations on Federal
and Indian lands, with 1.1 Bcf lost from
wells with plunger lifts and 2.16 Bcf lost
from wells without plunger lifts.306
These estimates were calculated using
data from the GHG Inventory, including
the regional prevalence of wells with
and without plunger lifts, and emissions
factors for each. We chose to calculate
emissions using a bottom-up approach
for this emissions source because the
prevalence of liquids unloading with
and without plunger lifts and the
emissions factors for each vary across
regions. We then applied the prevalence
and emissions factors to the number of
producing gas wells on Federal and
Indian lands as of January 1, 2014.
(b) Technologies and Practices To
Reduce Gas Losses From Well
Maintenance and Liquids Unloading
Technological developments have
reduced the need for operators to
unload liquids by venting a well to the
atmosphere. Many companies use
automated systems that rely on well
pressure or timers to unload liquids
using plunger lifts. More recent
technology allows companies to use
well data to optimize liquids unloading,
a technique sometimes called ‘‘smart’’
automation. These ‘‘smart’’ systems
reduce unnecessary unloading events
and can dramatically cut venting from
liquids unloading. For example,
according to the Natural Gas STAR
Report in 2006, BP reported installing
plunger lifts with smart automated
control systems on approximately 2,200
wells, which resulted in annual savings
of 900 Mcf per well.307 For a $12
million capital investment, BP realized
a $6 million total annual savings.308
Automated systems, whether ‘‘smart’’ or
more conventional, are particularly
useful for wells located in remote areas,
typical of BLM lands, as they help
306 RIA
at 128–129.
PowerPoint presentation found at
https://www3.epa.gov/gasstar/documents/
workshops/fortworth-2006/gremillion.pdf.
308 Ibid.
307 EPA
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maintain the well even when operators
are not present.
Advanced reservoir-energy
management and optimized liquidsunloading management can reduce the
frequency of well venting and the
quantity of resulting emissions. These
management practices can reduce
venting from wells with or without
plunger lifts. There are a wide variety of
artificial lift systems to unload gas
wells, which may be applied based on
the specific mechanical conditions of
the well and the conditions of the
reservoir. Some of these methods are
described below.
One method that can be effective
when a well first exhibits signs of liquid
loading is to temporarily shut-in the
well to allow the pressure to increase.
The well is then cycled on at a high rate
to unload the well. This method is
inexpensive, but as pressures in the well
decline, it becomes less effective.
Using surfactants (or soap injection) is
another option. With this method, a
foaming agent is injected in the casing/
tubing annulus by a chemical pump on
a timer. The gas bubbling through the
soap-water solution creates gas-water
foam, which is more easily lifted to the
surface for water removal. Capital and
startup costs to install soap launchers
range from $500–$3,880 per well.309
Another option is to change the
tubing in a well to smaller diameter
‘‘velocity strings.’’ Much like a
narrowing in a river, these smaller
diameter strings result in a higher fluid
velocity at any given volumetric flow
rate, and as a result these strings
provide higher liquid lift capabilities.
As reservoir pressure decreases,
however, this method is less effective
because of the increased friction in the
smaller diameter tubing. Capital and
installation costs provided from
industry range from $7,000–$64,000 per
well.310 Other operators use
compression to reduce flowing
operating pressure, thus reducing
flowing bottomhole pressure, which
increases inflow from the reservoir. This
is a means of achieving higher well-bore
velocities. Compression can be used in
conjunction with other artificial lift
methods.
A plunger lift is used in conjunction
with a lower-flowing tubing pressure
(compression) and intermittent flow
(shut-in cycle/smart automation) to lift
liquids. Plungers have a wide operating
range, but require a minimum gas-liquid
ratio, so they are not appropriate for all
309 EPA, Natural Gas STAR Program, 2011,
https://www3.epa.gov/gasstar/documents/ll_
options.pdf.
310 Ibid.
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applications. Plungers are most
successful in low volume gas wells (e.g.,
30 bbl of liquid or less per day). The
capital, installation and startup cost of
a plunger lift is estimated at $1,900–
$7,800,311 but it can reach as high as
$20,000.312 Adding a smart automation
system is estimated to cost $4,700–
$18,000.313
Another alternative is a gas lift, which
is used to raise gas velocity in the
production tubing by injecting gas down
the space between the tubing and
surrounding casing and combining it
with gas from the reservoir to assist in
lifting liquid accumulations. Gas lift
typically requires additional
compression and piping at the surface.
The additional compression would
either be electrical- or natural-gas
powered, adding to emissions,
complexity, reliability, and operating
costs. Also, gas lift is limited to those
reservoir/well combinations that are
configured in such a way that the gas
injected down the well will flow up the
well-bore and not simply dissipate into
the formation.
Finally, operators may also use
artificial lifts (e.g., rod pumps, beam lift
pumps, pumpjacks, and downhole
separator pumps). Downhole pumps
require an external power source to
operate in order to remove the liquid
buildup from the well tubing. Capital
and installation costs (including
location preparation, well clean out,
artificial lift equipment, and pumping
unit) is estimated at $41,000–$62,000
per well.314
Besides these measures to reduce gas
losses, operators may also minimize the
impact of well purging by flaring rather
than venting the released gas through
use of a mobile flare, but it can be
difficult to separate purged gas from
purged liquids.
Colorado allows an operator to vent
during unloading of liquids from the
wellbore only after the operator has
unsuccessfully attempted to unload
liquids without venting.315 To minimize
venting associated with liquids
unloading, Colorado also requires an
311 EPA (2014). Oil and Natural Gas Sector
Liquids Unloading Process; Report for Oil and
Natural Gas Sector Liquids Unloading Process
Review Panel. April 2014. Available at https://
www3.epa.gov/airquality/oilandgas/pdfs/
20140415liquids.pdf, p. 16.
312 ICF International (2014) Economic Analysis of
Methane Emission Reduction Opportunities in the
U.S. Onshore Oil and Natural Gas Industries, March
(2014), p.p. 3–17.
313 EPA, Natural Gas STAR Program (2011).
https://www3.epa.gov/gasstar/documents/ll_
options.pdf.
314 Ibid.
315 Colorado Air Quality Control Commission
Regulations, Regulation 7, 5 CCR 1001–9, Sections
XVII.
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6655
operator representative to remain on site
during the unloading event.316 The
EPA’s proposed 40 CFR part 60 subpart
OOOOa rulemaking requests comment
on ‘‘nationally applicable technologies
and techniques that reduce methane and
VOC emissions’’ during liquids
unloading, but the EPA does not believe
it has sufficient data to propose a
standard for unloading events.317
(c) Proposals To Reduce Waste From
Well Maintenance and Liquids
Unloading
Recent technological developments
allow liquids to be unloaded with
minimal loss of gas. The BLM believes
that it is reasonable to expect operators
to use these available technologies to
minimize gas losses, and we believe that
failure to minimize losses of gas from
liquids unloading should be deemed
avoidable waste subject to royalties.
Under proposed § 3179.204, except in
specified circumstances, the BLM
would prohibit new wells from
unloading liquids by simply purging the
well. While the BLM believes that the
alternative technologies discussed above
now generally make well-purging
unnecessary, some of these alternatives
are less costly to plan and install at the
design stage, and they are therefore
more appropriate for new than for
existing wells. In addition, some
options, such as installing an automated
plunger lift, may make less sense at a
well that is already nearing the end of
its productive life. Thus, the BLM is
proposing to limit the prohibition on
well purging to new wells drilled after
the effective date of this rule. We
request comment on whether we should
also prohibit well purging at existing
wells.
In addition, under proposed
§ 3179.204(c), the BLM would require
specified best management practices to
minimize venting from liquids
unloading at both new and existing
wells. Specifically, the BLM proposes to
require that the operator be on-site
during well purging events for
monitoring and reporting, unless the
operator uses an automatic control
system. Note that automatic control
systems may vent more or less
depending on the setting. We request
comment on whether BLM should also
require that wells with automatic
control systems optimize the automatic
settings so as to minimize venting.
Also, the BLM proposes under
§§ 3179.204(d) and (e) to require that
operators maintain certain records to
document liquids unloading events.
316 Ibid.
317 80
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This would allow the BLM to verify
compliance, and it would provide
additional information on the amounts
of gas lost through these activities on
Federal and Indian lands. We are
seeking comments on the appropriate
level and extent of required
recordkeeping in the proposed rule, as
well as other aspects of this approach to
reducing waste from well maintenance
and liquids unloading.
We estimate that there are currently
about 8,500 operating gas wells where
gas is vented during liquids unloading.
Of those wells, we estimate that about
6,950 wells (or 82 percent) are equipped
with plunger lifts, while 1,550 wells (or
18 percent) are not.318 The proposed
requirements would impact the 1,550
wells that are not equipped with
plunger lifts, as well as any of the wells
equipped with plunger lifts that lack
automation (a number the BLM cannot
accurately estimate at this time). In
addition to the 8,500 wells currently
venting during liquids unloading, there
is the potential that a number of
additional, producing gas wells will
develop liquids accumulation issues in
the future. Depending on how the
operator removes the liquids from the
wellbore, those wells could potentially
be impacted by the requirements.
Under the proposed rule, we expect
most new wells would use plunger lifts
for liquids unloading, except where
those lifts are technically infeasible or
unduly costly. Plunger lifts are already
used widely,319 suggesting that under
many circumstances their benefits—in
terms of increased gas recovery, slowed
declines in production, and improved
well productivity—exceed their costs.
The proposed rule would require
monitoring and reporting if the operator
does not use an automated system, to
minimize the venting and loss of gas
during liquids unloading to the
minimum amount necessary to bring the
well back into production. The operator
may choose to install an automated
system and avoid the monitoring and
reporting requirements altogether. Both
approaches are likely to reduce venting
or loss of gas, but we are unable to
estimate annual incremental
production, royalty, or emissions
reductions because we cannot
accurately predict how many operators
318 RIA
at 216.
to the 2015 GHG Inventory, 13
percent of the gas wells nationwide vent to the
atmosphere during liquids unloading, and of those,
more than 60 percent lack plunger lifts. RIA at 216.
In the Rocky Mountain region, however, where over
90 percent of the gas wells on Federal and Indian
lands are located, plunger lifts are far more common
than elsewhere in the country. RIA at 217.
319 According
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will choose to install an automated
system.
We do not anticipate that the
additional monitoring requirements
would substantially increase burdens on
operators, because the available data
indicate that average vent times are
relatively short. In the Rocky Mountain
region, for example, one industry survey
indicates that wells without plunger
lifts vent for an average of 1.76 hours.320
The BLM does not expect that requiring
operators to remain at the well site for
such short periods would impose a
significant financial burden.
Since the gas wells that encounter
liquids accumulation problems
generally do so after well production
starts to decline, the timing of any
future impacts of this rule is also
uncertain. The EPA’s Natural Gas STAR
Program has shown, however, that
investing in liquids removal processes
at the start of a well’s decline is more
successful than making similar
investments later in the productive life
of the well. This suggests that it is
reasonable to apply a more stringent
requirement for new wells drilled after
the effective date of this rule, as we have
proposed, but we specifically request
comment on this point.
There are a range of costs for various
alternatives to uncontrolled liquids
unloading. The annualized cost of a
plunger lift is estimated to be $1,845–
$2,816 using a 7 percent discount rate
or $1,788–$2,587 using a 3 percent
discount rate. The annualized cost of a
‘‘smart’’ (or automated) plunger lift is
estimated to be $2,471–$4,520 using a 7
percent discount rate or $2,303–$3,900
using a 3 percent discount rate. All
estimates are in 2012 dollars and are
based on an equipment life of 10
years.321
We note that these cost estimates do
not include sales of the recovered gas.
The EPA Natural Gas STAR program
information indicates that operators that
install plunger lifts may experience
increases in production from two
effects—the capture of gas that would
otherwise have been vented, and
improvements in well performance due
to the operation of the lifts. The gains
are well-specific, but the Natural Gas
STAR partners found that the additional
sales of gas generally offset the costs of
the lifts.322
Overall, based on the experiences of
the Natural Gas STAR Program partners,
320 RIA at 217. Source is Shires & Lev-on analysis
of API/ANGA survey data.
321 RIA at 85.
322 EPA Natural Gas STAR, Lessons Learned from
Natural Gas STAR Partners, available at https://
www3.epa.gov/gasstar/documents/ll_
plungerlift.pdf.
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we would expect that the boost in well
productivity and the sale of recovered
gas associated with the use of plunger
lifts and other well-maintenance
equipment would pay for the capital
costs of purchasing and installing the
equipment. We request comments on
this point, both in general, and
specifically with respect to the proposed
prohibition on the use of well purging
to unload liquids from new wells.
We estimate that the proposed liquids
unloading requirements would affect up
to about 1,550 existing wells and about
25 new wells per year, posing total costs
of about $6 million per year (using a 7
percent discount rate) or $5–6 million
per year (using a 3 percent discount
rate). We project that the requirements
would increase gas production by
roughly 2 Bcf per year, resulting in cost
savings of about $7–8 million per year
(using a 7 percent discount rate) or $7–
10 million per year (using a 3 percent
discount rate). In addition, these
requirements are projected to reduce
methane emissions by 30,000 to 34,000
tpy, producing monetized benefits of
$33–34 million per year in 2017–2019,
$41–43 million per year in 2020–2024,
and $50–51 million in 2025 and 2026.
Overall, we estimate that these
provisions would produce net benefits
of $35–52 million per year (using a 7
percent discount rate for costs and cost
savings) or $35–55 million per year
(using a 3 percent discount rate for costs
and cost savings), and reduce VOC
emissions by about 136,000 to 156,000
tpy.323
6. Reduction of Waste From Drilling,
Completion, and Related Operations
Substantial quantities of gas can be
lost during drilling, completion, and
refracturing (often referred to as
‘‘workover’’) operations. As explained
in the RIA, we estimate that in 2013, up
to 2.08 Bcf of natural gas was lost from
these operations on BLM-administered
leases. Of this, we estimate that
completion emissions from
hydraulically fractured oil wells
accounted for 1.4 Bcf of the loss, while
all other completions accounted for
about 0.7 Bcf of the loss.324
As discussed above, the EPA requires
new hydraulically fractured and
refractured gas wells to undergo green
completions to capture or flare gas that
otherwise would be released during
drilling and completion operations. On
September 18, 2015, the EPA proposed
to extend these requirements to new
hydraulically fractured and refractured
323 RIA
324 RIA
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oil wells.325 If the EPA finalizes that
proposal, it appears likely that all new
hydraulically fractured or refractured oil
and gas wells, other than wildcat and
delineation wells, would be required to
capture or flare the gas produced from
these drilling operations. Nonetheless,
the BLM believes that it is appropriate
for the BLM to adopt its own
requirements to minimize the waste of
gas during well drilling and well
completion and post-completion
operations at conventional and
hydraulically fractured and refractured
wells. The BLM has an independent
statutory obligation to minimize waste
of oil and gas resources on BLMadministered leases. As proposed, we
expect that the BLM waste requirements
for well drilling, and completions at
both conventional and hydraulically
fractured wells would apply to a
broader set of wells than the EPA
proposal would cover. Finally, if the
EPA finalizes a rule regulating
hydraulically fractured and refractured
oil wells, the BLM anticipates that any
operator subject to both sets of
requirements (i.e., an operator
completing a hydraulically fractured oil
well) could satisfy both agencies’
requirements by either capturing or
flaring the gas that would otherwise be
released. The BLM is coordinating
closely with the EPA on the agencies’
proposals, and the BLM expects to
ensure that our final requirements
would not impose additional burdens
on an operator that complied with any
EPA requirements on well completions.
Proposed § 3179.101 would generally
require operators to capture or flare gas
generated during drilling operations.
Alternatively, the operator could inject
the gas or use it for production
purposes. We estimate that the rule
would apply to up to about 3,000 wells
per year, and would contribute to the
BLM’s overall effort to comprehensively
address associated gas venting and
flaring during all phases of oil and gas
production. Based on our experience in
the field, the BLM believes, however,
that most operators are already diverting
and flaring much of the gas from drilling
operations as a matter of safety and
operating practice, under Onshore Oil
and Gas Order No. 2. As such, we do not
estimate significant costs associated
with this requirement.
Proposed § 3179.102 would similarly
require operators to capture or flare gas
generated during well completions and
well fracturing or refracturing
operations. Alternatively, the operator
may inject the gas or use it for
production purposes.
We believe that the compliance costs
associated with a requirement to flare
gas would be minimal, especially for
hydraulically fractured oil wells, where
the equipment needed to flare is
commonly already on site. We believe
that operators generally direct (or may
easily direct) the gas coming off of the
separator to a flare pit. If this is
infeasible, then the operator would
likely bring a combustor to the site for
the duration of the completion or direct
the gases to a combustor that it would
have on site to fulfill other regulatory
requirements.
If the EPA finalizes its 40 CFR part 60
subpart OOOOa rulemaking, as we
expect, then as a practical matter, this
rule’s completion requirements will
only impact conventional well
completions, because the EPA will
regulate completions of new and
modified hydraulically fractured oil and
gas wells. We estimate that the BLM
rule would impact between 115–150
completions per year and pose costs to
the industry of less than $430,000 per
year. There would be only de minimis
anticipated incremental production,
incremental royalty, and emissions
reductions.326
If, for purposes of analysis, we assume
that EPA does not finalize its 40 CFR
part 60 subpart OOOOa rulemaking, the
BLM estimates that these provisions
would affect about 1,250 to 1,575
completions per year and pose total
costs of about $8–12 million per year
(using a 7 percent discount rate) or $12
million per year (using a 3 percent
discount rate). We further estimate that
these provisions would increase gas
production by 0.5 to 0.6 Bcf per year,
resulting in cost savings of about $2
million per year (using a 7 percent
discount rate) or $2–3 million per year
(using a 3 percent discount rate). This
would also reduce methane emissions
by 11,500 to 14,500 tpy, producing
monetized benefits of $13 million per
year in 2017–2019, $16–18 million per
year in 2020–2024, and $21–22 million
in 2025 and 2026. Overall, under this
scenario, these provisions are estimated
to produce net benefits of $3–15 million
per year (considering the present value
of costs and cost savings using a 7
percent discount rate) or $3–13 million
per year (considering the present value
of costs and cost savings using a 3
percent discount rate), and reduce VOC
emissions by 9,600 to 12,200 tpy.327
325 80
CFR 60.5380–5385.
CFR 60.5380.
330 40 CFR 60.5385.
at 74.
327 Ibid.
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7. Additional Opportunities To Reduce
Waste From Venting
The BLM requests comment on
whether there are additional
opportunities to reduce waste from
venting through reasonable and costeffective measures. For example, there
are several categories of sources
discussed in the EPA white papers and
ICF studies on venting that this proposal
does not currently address, including
gas-assist glycol dehydrator pumps,
intermittent bleed pneumatic devices,
compressor stations (with respect to
specific interventions that could be
required), glycol dehydrators, and
pipeline venting. The proposal does not
currently extend to these sources for one
of two reasons: Either we do not believe
that the source commonly occurs on
BLM-administered leases, or we are still
reviewing possible approaches to reduce
venting from the source. We solicit
additional information on these points,
and also request comments on whether
any of these sources should be
addressed (or addressed differently) in
the final rule.
The EPA and various studies have
identified operational losses (in
addition to leaks) from compressors as
significant sources of methane
emissions, and the EPA NSPS rule
establishes requirements for new and
modified centrifugal wet seal
compressors and reciprocating
compressors.328 Specifically, that rule
requires compressors with wet seals to
reduce VOC emissions by 95 percent,
which can be met through flaring or gas
capture.329 The EPA rule also requires
operators of reciprocating compressors
to replace the rod packing systems every
26,000 hours of operation or every 36
months, and requires initial
performance testing and reporting.330
The BLM has not proposed to adopt
similar requirements for operational
losses from existing compressors on
BLM-administered leases, as we believe
that these losses from compressors are
not a significant source of waste on
those leases. We request comment on
whether adopting similar requirements
for existing compressors would
significantly reduce waste of gas from
BLM-administered leases in a
reasonable and cost-effective manner.
In addition, the BLM requests
comment on whether the rule should
require operators to use automatic
igniters on their flares and other
combustion devices, and if so, under
what circumstances those should be
required. The proposed provisions on
328 40
326 RIA
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well drilling, § 3179.101, and
completions, § 3179.102, include
requirements for the associated flare
device to be equipped with an
automatic igniter, as we believe that
these activities involve more sporadic
gas releases, such that an automatic
igniter could be helpful in avoiding
venting. However, we request comment
on whether there are other situations
under which automatic igniters should
be required, and if so, what deadline
should be imposed for the retrofit. For
example, the State of Colorado requires
that all combustion devices used to
control emissions of hydrocarbons be
equipped with automatic igniters, and
the State gave operators 2 years (until
May 1, 2016) to retrofit existing
combustion devices.331
Other approaches to address venting
from flare malfunctions include
requiring operators to install
malfunction alarms with remote
notification systems, and/or to use
enclosed combustors rather than open
flares. We request comment on whether
the BLM should include these
requirements as well.
In addition, the BLM requests
comment on whether we should require
flares to achieve a specified level of
performance in eliminating venting, and
if so, what level. Under the 2012 NSPS
rules, EPA requires 95 percent control of
VOCs from vessels and other sources,
and operators may use flares to meet
this standard.332 To the extent that
operators do so, the flares must achieve
at least a 95 percent removal efficiency
for VOCs. Colorado and Wyoming both
require combustion devices used to
control hydrocarbons from vessels and
other sources to achieve at least a 98
percent ‘‘design destruction efficiency’’
or ‘‘destruction removal efficiency’’ for
VOCs.333
B. Royalty-Free Use of Production
As noted above in Section III.F of this
preamble, the MLA’s reference to
applying royalties to production
‘‘removed or sold from the lease’’ has
long been interpreted to allow for both
royalty-free ‘‘unavoidable’’ losses of gas
(see discussion above in Section
IV.A.1.e of this preamble), and royaltyfree on-site use of gas production
(discussed here). For example, operators
commonly combust a portion of the
produced oil or gas to run production
331 Colorado
Air Quality Control Commission
Regulations, Regulation 7, 5 CCR 1001–9, Sections
XII.C.1.e, XVII.B.2.d.
332 40 CFR part 60, subpart OOOO.
333 Colorado Air Quality Control Commission
Regulations, Regulation 7, 5 CCR 1001–9, Section
XVII.G; Wyoming Operational Rules, Drilling Rules
Section Ch. 8, Section 6(c)(1)(A).
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equipment, such as to power artificial
lift equipment and drilling rigs, or to
heat, separate, or dehydrate production.
Operators also use gas pressure to
activate pneumatic controllers and
pneumatic pumps. This royalty
exemption for on-site use is not
unlimited, however, as the requirement
to prevent waste limits royalty-free onsite use to reasonable uses that are not
wasteful. Today’s proposal would
clarify the scope of the royalty
exemption for on-site use and resolve
ambiguities that have arisen under
NTL–4A.
Specifically, subpart 3178 of the
proposed rule would identify the oil
and gas uses that would qualify for
royalty-free treatment and explain
related requirements. In addition,
proposed § 3178.8 would specify how
an operator must determine and report
royalty-free volumes. Among other
issues, the proposed rule addresses the
following:
• Use of produced oil or gas at
locations beyond the boundary of the
producing lease, unit or communitized
area (CA);
• Use of produced oil or gas to power
equipment that the operator does not
own; and
• The practice of ‘‘hot oiling,’’ in
which oil used in the operation is not
consumed.
To prevent unreasonably high royaltyfree use, we considered proposing a
limit, in the form of a maximum volume
or maximum percentage of production.
We concluded, however, that it is too
difficult to identify specific volume or
production percentage thresholds that
would appropriately distinguish
between reasonable and unreasonable
quantities of on-site use. Instead, the
proposed rule would directly address
the royalty-free treatment of various
uses of lease production and identify
the situations in which prior written
BLM approval would be required for
royalty-free treatment of production
used.
The proposed rule states that
qualifying royalty-free uses must be for
operations and production purposes,
including placing oil and gas into
marketable condition. The lessee
ordinarily bears the responsibility for
placing oil and gas into marketable
condition at no cost to the lessor.334
334 See, e.g., 30 CFR 1206.55 (Indian oil);
1206.106 (Federal oil); 1206.152(i) and 1206.153(i)
(Federal gas); 1206.172(e)(3)(iii)(B) and 1206.174(h)
(Indian gas); Devon Energy Corp. v. Kempthorne,
551 F.3d 1030 (D.C. Cir. 2008); Amoco Production
Co. v. Watson. 410 F.3d 722 (D.C. Cir. 2005);
Amerada Hess Corp. v. Dep’t. of the Interior, 170
F.3d 1032 (10th Cir. 1999); Mesa Operating Limited
Partnership. v. Dep’t. of the Interior, 931 F.2d 318
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When a particular operation involved in
placing the oil and gas into marketable
condition is performed on the
producing lease, unit participating area
(PA), or CA, and the operator has met
all other requirements, however, it is an
appropriate royalty-free use. The
production used in that operation is not
royalty-bearing because the production
is not removed from the lease, unit, or
CA.335
C. Royalty Rates on New Competitive
Leases
In addition to clarifying the scope of
the royalty exemption for on-site use
and resolving ambiguities that have
arisen under NTL–4A, the BLM also
proposes to conform its regulatory
provisions governing royalty rates for
new competitive leases to the
corresponding rate provisions in the
MLA. The MLA directs the BLM to set
the royalty rate for all new
competitively-issued leases ‘‘at a rate of
not less than 12.5 percent in amount or
value of the production removed or sold
from the lease.’’ 336 Despite the inherent
flexibility of this statutory language, the
BLM’s existing royalty regulation sets a
flat rate of 12.5 percent for all new
competitive leases.337 The proposed
rule would adopt the statutory language,
with the result that the ‘‘base’’ royalty
rate on competitive oil and gas leases
issued after the effective date of this rule
would be ‘‘not less than’’ 12.5 percent.
As noted, this proposed change would
align the BLM’s royalty authority with
that delegated by Congress. In addition,
the change would also respond to
concerns expressed by the GAO and
others about the adequacy of the BLM’s
onshore oil and gas fiscal system. In
2007 and 2008, the GAO released two
reports addressing the United States’ oil
and gas fiscal system. The first report
compared oil and gas revenues received
by the Federal Government to the
revenues that foreign governments
receive from the development of their
public oil and gas resources.338 That
report concluded that the United States’
oil and gas ‘‘take’’ is among the lowest
in the world.339 The second report,
which focused on whether the
Department of the Interior receives a fair
(5th Cir. 1991); Shoshone and Arapaho Tribes v.
Hodel, 903 F.2d 784 (10th Cir. 1990).
335 See Plains Exploration & Production Co., 178
IBLA 327, 335–336, 341–343 (2010).
336 30 U.S.C. 226(b)(1)(A) (emphasis added); see
also 30 U.S.C. 352 (applying the Section 226 royalty
provisions to leases on acquired land).
337 43 CFR 3103.3 1(a)(1).
338 GAO, Oil and Gas Royalties: A Comparison of
the Share of Revenue Received from Oil and Gas
Production by the Federal Government and Other
Resource Owners, GAO 07 676R, May 2007.
339 GAO–07–676R at 2.
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return on the resources it manages, cited
the ‘‘lack of price flexibility in royalty
rates,’’ and the ‘‘inability to change
fiscal terms on existing leases,’’ in
support of a finding that the United
States could be foregoing significant
revenue from the production of onshore
Federal oil and gas resources.340 Based
on that finding, the second GAO report
recommended that the U.S. Congress
direct the Secretary of the Interior to
convene an independent panel to
review the Federal oil and gas fiscal
system and establish procedures for
periodic evaluation of the system going
forward.
Congress did not act on the
recommendation in the second GAO
report, but the Department nevertheless
undertook its own review. Specifically,
the BLM and the BOEM contracted with
the consulting firm Information
Handling Services’ Cambridge Energy
Research Associates (IHS CERA) for a
comparative assessment of the fiscal
systems applicable to certain Federal,
State, private, and foreign oil and gas
resources (‘‘IHS CERA Study’’).341 The
IHS CERA Study identified four factors
amenable to comparison: Government
take, internal rate of return, profitinvestment ratio, and progressivity.342
The IHS CERA Study also considered
measures of revenue risk and fiscal
system stability. Overall, the IHS CERA
Study found that, as of the time of the
study, the Federal Government’s fiscal
system and overall take, in aggregate,
were in the mainstream both nationally
and internationally. Even within
specific geographic regions, however,
the IHS CERA Study estimated a wide
range of government take, and its
authors acknowledged that take varies
with a variety of factors, including
commodity prices, reserve size,
reservoir characteristics, resource
location, and water depth. As a result,
the IHS CERA Study’s authors favored
a sliding-scale royalty system, because a
sliding-scale royalty is more progressive
than a fixed-rate royalty, and can also
respond to changes in commodity
market conditions.
In addition to the IHS CERA Study,
the BLM also reviewed a separate study
conducted by industry, the ‘‘Van Meurs
340 GAO–08–691
at 6.
I. (2011). Comparative Assessment of
the Federal Oil and Gas Fiscal Systems. U.S.
Department of the Interior, Bureau of Ocean Energy
Management, OCS Study, BOEM 2011–xxx,
available at https://www.energy.senate.gov/public/
index.cfm/files/serve?File_id=d174971c-4682-4d96b194-a85fa2b86774.
342 A ‘‘progressive’’ royalty rate refers to a rate
that increases with the quantity of the resource
being sold.
341 Agalliu,
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Study.’’ 343 The Van Meurs Study
looked at a range of jurisdictions and
regions across North America and
provided a comparison of the oil and
gas fiscal systems on Federal, State, and
private lands throughout the United
States and the provinces in Canada. The
Van Meurs Study suggested that as of
2011, Federal Government take on
Federal lands was generally lower than
the corresponding take on State or
private lands. The Van Meurs Study
also made several recommendations to
State and Federal Governments in the
United States and Canada, including
that governments apply different fiscal
terms to oil leases than to gas leases,
based on the differing prices of oil and
gas at the time the report was published.
In 2013, the GAO issued another
report identifying specific actions for
the Department to take to ensure that
the Federal Government receives a fair
return on the resources it manages for
the American public.344 The GAO
acknowledged that actions had been
taken in response to its prior
recommendations, but remained
concerned that the Department had not
taken steps to change its onshore royalty
rate regulations to provide flexibility
with respect to fiscal terms for oil and
gas leases.345
In April 2015, as an initial response
to these various studies and reports, the
BLM published an Advance Notice of
Proposed Rulemaking (ANPR) to solicit
public comments and suggestions that
might be used to update the BLM’s
regulations related to royalty rates,
annual rental payments, minimum
acceptable bids, and other financial
measures.346 In preparing the ANPR, the
BLM gathered information about royalty
rates charged by States and private
mineral holders for oil and gas activities
on State and private lands, and
compared those rates to rates charged
for Federal oil and gas resources. The
data showed that the royalty rates
charged on private and State lands range
from 12.5 to 25 percent, and that the
average rate assessed exceeds 16.67
percent.347
The comment period on the ANPR
closed on June 19, 2015. BLM received
82,074 comments, many of which were
form letters, including thousands of
343 PFC Energy, Van Meurs Corporation, and
Rodgers Oil & Gas Consulting (2011). World Rating
of Oil and Gas Terms: Volume 1—Rating of North
American Terms for Oil and Gas Wells with a
Special Report on Shale Plays.
344 GAO, Oil and Gas Resources—Actions Needed
for Interior to Better Ensure a Fair Return, GAO–
14–50, (Dec. 2013), 11.
345 Ibid. At 23.
346 80 FR 22148 (April 21, 2015).
347 80 FR at 22151–52 (April 21, 2015).
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comments from NGOs. In addition to
the NGO comments, individual
companies and industry trade groups,
including the American Petroleum
Institute, Independent Petroleum
Association of America, and Western
Energy Alliance, submitted comments
on behalf of their members. Most of the
comments focused on lease fiscal
terms—royalty rates, rentals, and
minimum bids.
With respect to royalty rates,
comments ran the gamut from
supporting increases to opposing any
such changes. Commenters supporting
changes to the BLM’s royalty rate
regulations noted that the regulations
are decades old and set a rate that is
generally lower then rates for
comparable State and private land
leases. These commenters expressed
concerns about whether, in light of
these facts, the BLM is obtaining a fair
return for the American taxpayer from
Federal oil and gas leases. A number of
these commenters suggested that the
BLM should, at a minimum, increase
the onshore royalty rate to match the
rate currently set by BOEM offshore
(18.75 percent). Other commenters
suggested that royalty rates should be
increased in order to account for the
social and environmental costs of oil
and gas development.
Many commenters took the opposite
view, however, opposing any changes in
royalty rates and arguing that higher
regulatory costs, operating costs, and
uncertainty on Federal lands justify
royalty rates lower than those on State
and private lands. These commenters
also asserted that any increase in royalty
rates for Federal oil and gas leases
would lead to an overall decrease in
government revenue by discouraging
exploration and development of Federal
oil and gas resources.
Finally, some commenters offered
input on alternate royalty rate
structures, focusing in particular on
sliding scale systems. Some commenters
encouraged the BLM to consider such a
system, especially a sliding scale based
on market price or regional location.
Other commenters were opposed to a
sliding scale approach, due to perceived
implementation challenges and
uncertainty in reporting. These
commenters also questioned the
appropriateness of setting up a royalty
regime in which the Federal
Government shares with investors some
of the risk of fluctuating gas and oil
prices. Overall, most individual
commenters appeared to agree generally
with giving BLM the flexibility to
change fiscal terms at the lease sale
stage, rather than fixing royalty rates by
rule.
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Based on the GAO’s repeated
recommendations, the IHS CERA Study,
the royalty rate data collected by the
BLM, and the comments received in
response to the ANPR—and in light of
the volatile nature of oil and gas
markets—the BLM has determined that
its regulations should provide for
maximum flexibility to adjust royalty
rate terms for new competitively issued
oil and gas leases. Accordingly, this
proposed rule would revise the existing
regulations to track statutory authority.
The BLM does not currently
anticipate increasing the base royalty
rate for new competitively issued leases
above 12.5 percent. Before making such
a change, the BLM would announce the
change prior to the effective date, and
would provide for a public comment
period. Any proposed change would be
based on relevant factors, potentially
including an assessment of comparable
onshore State and private fiscal systems,
and an assessment of the proposed
impacts of the change on Federal
revenue, on production from Federal
lands, and on demand for Federal oil
and gas leases relative to State and
private leases.
The BLM requests input on this
proposed change to the royalty
provisions. In particular, commenters
should address the merits of the
proposed change to conform to statutory
language, suggest the proper factors for
the BLM to consider if and when it
decides to adjust royalty rates for new
competitive leases, and evaluate the
adequacy of the public process outlined
above.
At present this is the only change the
BLM proposes to make to its royalty
regulations. The BLM is, however,
considering a provision that would
allow royalty rates on new
competitively issued leases to vary after
the first year, based on the lease holder’s
record of routine flaring of associated
gas from the lease during the previous
year. Implementation of such a royalty
‘‘adder’’ provision would involve a
‘‘look back’’ at each lease holder’s
venting and flaring activity over a 12month period. On October 1st of each
year, a lease holder would evaluate its
record of routine flaring of associated
gas from the lease over the prior 12month period. If a lease holder flared
above a de minimis threshold for at least
6 months of that 12-month period, then
its royalty rate for the subsequent
calendar year would increase by some
increment (for example, 4 percent). In
all other cases, the royalty rate would
remain at, or revert to, the base rate
specified in the lease.
To make this idea more concrete,
suppose the BLM finalizes the proposed
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changes to the existing royalty
provisions in 43 CFR 3103.3–1(a)(1) and
(2), detailed below in the section-bysection analysis (Discussion of the
Proposed Rule, V.I.1.) and laid out in
the proposed regulation text.348 In that
case, the additional regulatory language
implementing a royalty adder could take
the following form:
1. Amend § 3103.3–1(a)(2) to add the
following subparagraphs:
(iii) An additional 4 percent above the
base rate on all competitively-issued
leases for any calendar year in which
the operator reported above-threshold
flaring of associated gas during at least
six of the 12 months preceding October
1st;
(iv) The threshold flaring rate for
purposes of paragraph (iii) is 300 Mcf/
month multiplied by the number of
wells on the lease that produced for at
least 10 days during the month.
(v) For communitized or unitized
leases, the threshold flaring rate for
purposes of paragraph (iii) is 300 Mcf/
month multiplied by the sum of the
number of stand-alone wells on the
lease and the number of wells on each
agreement from which the lease is
receiving an allocation. To be counted,
each well must have produced for at
least 10 days during the relevant month.
The flaring volume used to assess
exceedance of the threshold will be
determined using the same allocation
formula that each agreement uses to
allocate production to the lease under
consideration.
In this illustrative regulatory text, the
royalty ‘‘adder’’ is 4 percent, and the
threshold, de minimis flaring rate that
would trigger application of the adder is
300 Mcf/producing well/month (or
approximately 10 Mcf/producing well/
day). Assuming the current base rate of
12.5 percent, a lease holder would
continue to pay 12.5 percent for any
year in which routine flaring of
associated gas from its lease did not
exceed the threshold rate during at least
six of the 12 months preceding October
1st. On the other hand, any lease holder
that reported above-threshold flaring of
associated gas during at least 6 months
of a calendar year would be obligated to
pay a 16.5 percent royalty rate on all oil
and gas production removed or sold
from the lease during the subsequent
calendar year. The rate would then
revert back to 12.5 percent, for any year
in which the lease holder reported at- or
below-threshold flaring of associated gas
during at least 6 of the 12 months
preceding October 1st. Note that the
16.5 percent rate would be less than the
average royalty rate that lease holders
348 See
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currently pay on oil and gas production
removed or sold from onshore State and
private leases (16.67 percent).349 As
noted previously, this provision, if
adopted in the final rule, would apply
only to new competitively issued leases
issued after the effective date of the rule,
and would not apply to existing leases.
The purpose of the royalty adder
provision would be: (1) To create an
incentive for bidders to consider the
availability of gas capture infrastructure
and the proximity of gas processing
facilities as attributes that add
significant value to Federal oil
development leases; and (2) To create an
incentive for Federal lease holders to
plan for gas capture prior to or in
conjunction with the development of oil
wells.
The BLM requests comment on both
the concept and the implementation of
the royalty adder. Would a royalty adder
accomplish the purposes outlined
above? If so, is the structure suggested
above appropriate? Does a 4 percent
adder provide adequate incentive to
lease holders to plan for gas capture at
the same time they plan for oil
development? Is a threshold rate of 10
Mcf/producing well/day (or 300 Mcf/
producing well/month) over 6 months
of the previous calendar year an
appropriately de minimis rate to trigger
the adder? Is an annual ‘‘look back’’
mechanism that focuses on production
over the 12 months prior to October 1
workable given how oil and gas
production volumes, and flaring levels,
are currently reported to ONRR, or
would a different 12-month period be
easier to implement? Would there be a
simpler and/or more effective way to
implement a royalty adder concept?
D. Record Keeping Requirements
The BLM is proposing to require
operators to keep records documenting
their compliance with several
provisions of this rule. Under proposed
§ 3179.8, for example, operators would
need to estimate or measure all volumes
of gas vented or flared, and report those
volumes under applicable ONRR
reporting requirements. This includes
flaring of associated gas, and flaring that
occurs during well drilling (proposed
§ 3179.101), well completions (proposed
§ 3179.102), initial production testing
(proposed § 3179.103), and subsequent
well testing (proposed § 3179.104). With
respect to venting and flaring during
emergencies (proposed § 3179.105), the
BLM is proposing to require the
operator also to estimate and report to
the BLM on a Sundry Notice the
volumes flared or vented beyond
349 80
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specified timeframes. We are also
soliciting comment on the most efficient
and least burdensome means to make
appropriate data available to the public.
In addition, with respect to venting
during well maintenance and liquids
unloading under proposed § 3179.204,
the BLM is proposing to require
operators to keep records on the cause,
date, time, and duration of each venting
event, as well as estimates of the
quantities released. The BLM is also
proposing to require operators to keep
records on the dates, equipment
covered, monitoring methods used, and
results of the leak inspections required
under proposed § 3179.305, as well as
the dates that repairs are attempted,
completed, and confirmed. We request
comment on whether operators should
be required to provide this information
in an annual report, consistent with
Colorado’s requirements.350
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E. Reporting and Information
Availability
Currently, relatively little information
on waste from venting and flaring at
specific sites is directly provided to the
public. The public may request
information held by the BLM and ONRR
through a request under the Freedom of
Information Act (FOIA), but this can be
more time-consuming and costly than
accessing information publicly posted
on Web sites.
Under existing § 3162.3–1(g), upon
receiving an Application for a Permit to
Drill (APD) on Federal lands, the BLM
must post information for public
inspection for at least 30 days before
taking action. The information includes:
(1) The company/operator name; (2) The
well name/number; (3) The well
location; and (4) Maps of the affected
lands. The information must be posted
in the local office of the BLM and in the
appropriate surface managing agency
office, if other than the BLM. Some BLM
field offices also make this information
available on their Web sites. The BLM
has been working to upgrade its systems
for accepting and processing APDs and
Sundry Notices. The new APD
acceptance process will allow the BLM
to more easily post general information
about those APDs to the Internet for
public notice purposes.
With respect to venting and flaring, in
some situations, such as emergencies,
the operator is not currently required to
provide any information to the BLM. In
other situations, such as when BLM
approval is required, operators typically
350 Colorado Air Quality Control Commission
Regulations, Regulation 7, 5 CCR 1001–9 at Section
XVII.H.1.c. and XVII.F.8 for proposed §§ 3179.204
and 3179.305 respectively.
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file a Sundry Notice requesting the
approval. When the BLM approves or
disapproves the request, the BLM
notifies the company. Neither the
Sundry Notice nor the BLM disposition
is currently posted, although to the
extent that the information is not
confidential business information, it
would be available to the public through
a FOIA request. Likewise, although
operators are currently required to
report gas vented and flared to ONRR on
a lease or agreement basis, this
information is currently only available
to the public through a FOIA request.
This information also does not include
quantities of gas released through leaks
or during routine operation of
equipment, such as pneumatic devices.
In recent years, there has been strong
and growing public interest in venting
and flaring at oil and gas operations. In
particular, the public has been calling
for more complete, reliable, and
available information on the quantities
of natural gas vented and flared from
BLM-administered leases. The BLM
believes it is appropriate for the public
to have access to information on venting
and flaring from BLM-administered
leases. The BLM also wants to be as
responsive to reasonable public requests
as possible given resource constraints.
Since at least a portion of the data on
venting and flaring is already reported
to and available from ONRR, the BLM
believes that the least burdensome
approach to increasing data access
would be to expand the information that
must be reported to ONRR. The goal
would be to ensure that all quantities of
gas vented and flared that ONRR
requires to be reported are reported on
ONRR’s Oil and Gas Operations Report
(OGOR), form ONRR–4054. Thus, the
BLM proposes in §§ 3179.8 and
3179.204 to clarify the reporting
requirements to ensure that operators
report to ONRR measurements or
estimates of all volumes of gas vented or
flared. The BLM requests comment on
this proposal and whether operators
should report any additional
information on losses of gas, such as
from storage vessels or pneumatic
controllers and pneumatic pumps.
Several other categories of information
may also generate public interest. For
example, the proposed rule would
require operators to provide significant
new information related to plans for
disposition of associated gas at the APD
phase. In addition, there is already
public interest in industry requests for
approvals to flare and BLM responses. If
this proposal is finalized, the BLM
expects that there would be far fewer
applications for alternative flaring limits
compared to the current level of
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requests for approval to flare, but that
there still might be substantial public
interest in the applications for
alternative flaring limits that BLM
would receive.
To ensure transparency about the use
of public resources, the BLM is
considering ways to make these kinds of
information publicly available online,
where appropriate, without requiring
interested members of the public to
submit FOIA requests. The BLM
requests comment on the types of data
that are most useful to the public, the
types of data that operators believe
should remain private, and the most
efficient and least burdensome
approaches to making appropriate data
available to the public. The BLM
recognizes, however, that it must
balance this interest in open
government with the need to protect
operators’ confidential business
information, and with the substantial
administrative burden and costs of
posting large amounts of information
online.
F. Planning Process
During public outreach for the venting
and flaring rule, multiple stakeholders
asked the BLM to address the waste
issue not only through requirements
under the MLA, but also through the
BLM’s land-use planning and
environmental review processes.
Pointing to the BLM’s authorities under
FLPMA, procedural statutes such as the
National Environmental Policy Act
(NEPA), and DOI policies such as the
Secretarial Orders that address climate
change,351 these commenters asked the
BLM to use landscape-scale planning
tools to complement the MLA waste
prevention provisions.
These stakeholders recommended that
the BLM integrate the waste prevention
provisions of the MLA with the
planning and management framework
informed by FLPMA and NEPA.
Commenters specifically suggested that
the BLM develop a new rule requiring
field offices to integrate waste
prevention into planning and
management. More broadly, the
stakeholders asked the BLM to ‘‘craft its
rule to make full use of its ‘front end’
planning and management tools’’ to
prevent oil and natural gas waste.352
They highlighted tools that allow the
BLM to plan, manage for, and review
the impacts of proposed actions before
351 See, e.g., Secretarial Order Nos. 3289 (Sept. 14,
2009) (updated by Amendment No. 1, Feb. 22,
2010) and 3226 (Jan. 19, 2001).
352 Letter from the Western Environmental Law
Center (WELC) et al. to Secretary Sally Jewell, DOI,
Jan. 27, 2014, p. ii and Attached Core Principles,
pp. 23–24 (hereinafter WELC Jan. 27 Letter).
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issuing leases or approving oil and gas
development projects, in contrast to the
‘‘back end’’ application of specific
technologies or practices to such
projects.353 For example, these
commenters suggested that by providing
information to inform oil and gas
development decisions, BLM
inventories of the resource and other
values of specific lands prepared under
FLPMA Section 201(a) 354 could
facilitate implementation and
enforcement of the venting and flaring
rule. They further suggested that by
providing for public involvement, ‘‘front
end’’ tools would facilitate public
transparency and accountability and
help to identify unexpected
opportunities to prevent methane waste
(such as in NEPA alternatives
analyses).355
Among other tools, these stakeholders
suggested that resource management
plans (RMP) offer an opportunity to
ensure ‘‘orderly and efficient’’ oil and
gas development by governing the scale,
pace, and nature of exploration,
development, and production, and by
facilitating the construction of necessary
infrastructure for routing captured gas to
processing and storage facilities.356
They also encouraged the BLM to use
master leasing plans (MLP) ‘‘to establish
front-end waste prevention goals’’ when
planning for oil and gas development in
a defined area and to identify specific
best management practices or mitigation
measures to prevent waste.357 These
stakeholders argued that these and other
tools would enable the BLM to ‘‘prevent
methane waste at a broad basin- or fieldlevel scale.’’ 358
In addition, these stakeholders asked
the BLM to use NEPA reviews to
prevent methane waste. For example,
they encouraged the BLM to consider
methane waste from all sources in its
NEPA analyses, including when
considering alternatives and mitigation
measures and when analyzing
cumulative impacts.359 These
stakeholders also asked that the BLM
‘‘expressly coordinate its planning and
353 Letter from WELC et al. to Secretary Sally
Jewell, DOI, May 30, 2014, Attached Comments, p.
11, n. 6 (hereinafter WELC May 30 Letter).
354 43 U.S.C. 1711(a).
355 WELC Jan. 27 Letter, p. 23.
356 WELC Jan. 27 Letter, pp. 23–24; see also Letter
from WELC and Clean Air Task Force to Director
Neil Kornze, BLM, Dec. 5, 2014, pp. 2 and 4
(hereinafter WELC Dec. 5 Letter).
357 WELC Jan. 27 Letter, p. 24.
358 WELC May 30 Letter, pp. 11–12.
359 WELC Jan. 27 Letter, pp. 20–21; WELC May
30 Letter, pp. 21–22; WELC Dec. 5 Letter, p. 4
(urging the BLM to consider and require
technologies and practices to prevent waste that are
deemed reasonable in the context of basin- or fieldspecific conditions).
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management efforts with Federal, State,
and local agencies that regulate
downstream activities, as well as with
industry segments responsible for
downstream activities’’ to ensure that
methane waste prevention actions are
effective.360
Similarly, in evaluating opportunities
for the BLM to reduce venting and
flaring of gas, the GAO found that the
agency does not as a general matter
assess options for reducing venting and
flaring in advance of oil and gas
production. The GAO pointed out that
there are two phases in advance of
production where the BLM could assess
venting and flaring reduction options—
during the environmental review phase
and when the operator applies to drill
a new well. The GAO found, however,
that the BLM largely fails to take
advantage of these opportunities to
reduce methane waste, instead using its
pre-production authority solely to
ensure that air quality standards are not
violated. The GAO recommended that
the BLM assess the potential use of
venting and flaring reduction
technologies to minimize the waste of
natural gas in advance of production
wherever applicable.361
The BLM is considering the integrated
approach suggested by the commenters.
The BLM agrees that the land use
planning and NEPA processes are
important to sound oil and gas
development on Federal land. Flaring
sometimes results from development of
oil wells in advance of gas capture
infrastructure. In other cases, flaring
occurs when existing gas capture and
processing infrastructure is inadequate,
or when operators find flaring easier or
less costly than connecting to existing
gas capture infrastructure. Part of the
solution to flaring, therefore, is to align
the timing of well development with
that of capture and processing
infrastructure development, and to
create incentives for operators to
capture rather than flare.
The land use planning and NEPA
review processes could be used to
achieve these improvements, but the
BLM does not intend to make any
changes to BLM land use planning
regulations (43 CFR subparts 1601 and
1610) or to any BLM planning or NEPA
guidance as part of this rulemaking.
This proposed rule focuses on the
requirements that apply to operators as
they develop wells and produce oil and
gas from lands under Federal leases (43
CFR chapter II, subparts 3178 and 3179).
The regulatory changes under
360 WELC
Jan. 27 Letter, p. 20.
34.
361 GAO–11–34,
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consideration in this rulemaking are
limited to these provisions.
G. Facilities in Rights-of-Way
In response to the BLM’s solicitation
of stakeholder views, various
stakeholders also submitted comments
urging the BLM to address not only
losses of natural gas from BLMadministered leases, but also losses of
natural gas from facilities located in
rights-of-way granted by the BLM on
Federal and Indian land. As of FY 2014,
the BLM had over 33,700 approved
rights-of-way in place under the
MLA.362 Facilities located in rights-ofway include gas gathering and
transmission pipelines and
compressors, which are used to
maintain pressure in the pipelines. Of
these, it appears that compressors are
likely to be the largest source of natural
gas losses. Further, it appears that losses
from sources located on rights-of-way
could be addressed through available
technologies and practices, such as
LDAR programs.
In evaluating the merits of the
stakeholders’ suggestion, the BLM
believes that relevant considerations
include, among others: The quantity of
gas lost from these sources, the costs
and feasibility of technologies to reduce
waste of gas from these sources, and the
administrative burden of doing so.
Based on the currently available
information, the BLM believes that there
are only a small number of sources of
lost gas on BLM-managed rights-of-way,
and that these sources do not contribute
significantly to the problem of waste.
The BLM analyzed potential losses from
compressors, as the likely largest
sources of loss located on BLM-managed
rights-of-way. There are an estimated
386 compressors located on BLMmanaged rights-of-way, and most of
these are believed to be small
compressors used for gathering systems
(as opposed to the larger compressors
used for transmission pipelines). Using
EPA GHG Inventory data on emissions
from small compressors, the
compressors located in BLMadministered rights-of-way are
estimated to release approximately 47
MMcf of natural gas per year. This
quantity of gas is several orders of
magnitude smaller than the on-lease
sources of losses on which this proposal
focuses—not surprising given that the
number of compressors located on BLMadministered rights-of-way is only about
4 percent of the total number of small
compressors in the Rocky Mountain
region (9,260), and emissions from these
362 BLM Public Land Statistics, 2014 Table 3–4,
column (c), Mineral Leasing Act.
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compressors only total about 1 percent
of small compressor emissions in the
U.S. according to the latest GHG
Inventory.363 Given the limited impact
of these rights-of-way facilities, and the
fact that the BLM can already reach the
facilities’ emissions via conditions on
rights-of-way, we are not proposing to
address these facilities in this
rulemaking. We request comment on
this approach.
H. State or Tribal Variances
Several States and tribes have worked
to address concerns about venting and
flaring from oil and gas production, and
others are considering action on this
front. The BLM believes that it is
important to include in this rule a
provision for recognizing highly
effective State or tribal requirements
that reduce flaring and/or venting as
much as, or more than, the proposed
rule. Under proposed § 3179.401, such
State or tribal provisions could, upon
BLM approval, apply in place of a
provision or provisions of subpart 3179.
To apply for a variance, a State or tribe
would have to: Identify the specific
provisions of the BLM requirements for
which the variance is requested;
identify the specific State or tribal
regulation that would serve as a
substitute; explain why the variance is
needed; and demonstrate how that
regulation would serve the purposes of
the supplanted BLM requirements.
The relevant BLM State Director
would review a State or tribal variance
request and assess whether the State or
tribal regulation meets or exceeds the
requirements of the BLM provisions for
which the State or tribe sought a
variance. The proposed rule would
retain the BLM’s authority to rescind a
variance or modify any condition of
approval in a variance.
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I. Section-by-Section Discussion
1. § 3103.3–1 Royalty on Production
The proposed revisions to § 3103.3–
1(a)(1) and (2) do four things: (1)
Remove two provisions of the existing
regulations that are no longer necessary
(§ 3103.3–1(a)(1)(i) and (ii)); (2) Specify
that the rate on all leases existing at the
time the rule becomes effective would
remain at the rate ‘‘prescribed in the
lease or in applicable regulations at the
time of lease issuance’’; (3) Specify the
statutory rate of 12.5 percent for all
noncompetitive leases issued after the
effective date of the final rule; and (4)
Conform the regulatory regime for
363 BLM analysis of EPA GHG Inventory data
applied against the estimated number of
compressors located on BLM-managed ROW
authorizations.
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competitive leases issued after the
effective date of the rule to the regime
envisioned by the MLA, which specifies
that the royalty rate for all new
competitively issued leases be set ‘‘at a
rate of not less than 12.5 percent.’’ 364
2. § 3160.0–5 Definitions
This proposed amendment to
§ 3160.0–5 would delete a definition of
‘‘avoidably lost’’ that by its terms
applies to part 3160. A definition of
‘‘avoidably lost’’ is no longer needed for
part 3160, and this definition would be
superseded by the provisions in
proposed subparts 3178 and 3179
governing when the loss of oil or gas is
avoidable. In particular, proposed
§ 3179.4 delineates when the loss of oil
or gas is avoidable or unavoidable.
3. § 3162.3–1 Drilling Applications
and Plans
This proposed section describes the
requirements for drilling applications
and plans, including specifying the
information that an operator must
provide with an APD. We propose to
amend this section to require that when
submitting an APD for a development
oil well, an operator must also submit
a waste minimization plan, which
would not be part of the APD, and the
execution of which would not be
enforceable. The waste minimization
plan would have to include information
regarding: The pipeline infrastructure
location and capacity in the area of the
well or wells; the anticipated timing,
quantity, and production decline curve
of oil and gas production from the well
or wells; a gas pipeline system location
map showing the operator’s wells, gas
pipelines, gas processing plant(s), and
proposed routes for connection to the
pipeline; certification that the operator
has provided one or more midstream
processing companies with information
about the operator’s production plans,
including the anticipated completion
dates and gas production rates of the
proposed well or wells; the volume and
percentage of produced gas the operator
is currently flaring or venting from wells
in the same field and any wells within
a 20-mile radius of that field; and an
evaluation of opportunities for
alternative on-site capture approaches,
if pipeline transport is unavailable.
4. Subpart 3178—Royalty-Free Use of
Lease Production
(a) § 3178.1 Purpose
This proposed section states that the
purpose of the subpart is to address
circumstances in which oil and gas
produced from Federal and Indian
364 See
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6663
leases may be used royalty-free. This
subpart would supersede those parts of
NTL–4A pertaining to oil or gas used for
‘‘beneficial purposes.’’
(b) § 3178.2 Scope of This Subpart
This proposed section specifies which
leases, agreements, tracts, facilities, and
gas lines are covered by this subpart.
The proposed section also states that the
term ‘‘lease’’ in this subpart includes
IMDA agreements as consistent with
those agreements and with principles of
Federal Indian law—an edit intended to
enhance the clarity and brevity of these
provisions.
(c) § 3178.3 Production on Which
Royalty Is Not Due
This proposed section would set forth
the general rule that royalty is not due
on oil or gas that is produced from a
lease or CA and used for operations and
production purposes (including placing
oil or gas in marketable condition) on
the same lease or CA without being
removed from the lease or CA.
This section also addresses a similar
issue with respect to unit PAs—that is,
the productive areas on a unit. Units
often include different PAs composed of
multiple leases with varied ownership.
This section would therefore limit the
royalty-free use of gas from a particular
PA to uses that are made on the same
unit, to support production from the
same unit PA. The reason for this
limitation is to prevent excessive use of
royalty-free gas by prohibiting a unit
operator from using royalty-free
production from one PA to power
operations on, or treat production from,
another PA on the same unit, to the
benefit of different owners and to the
detriment of the public interest.
Proposed § 3178.5 would qualify the
general provisions of proposed § 3178.3
by listing specific operations for which
prior written BLM approval would be
required for royalty-free use.
(d) § 3178.4 Uses of Oil or Gas on a
Lease, Unit, or CA That Do Not Require
Prior Written BLM Approval for
Royalty-Free Treatment of Volumes
Used
This proposed section identifies uses
of produced oil or gas that would not
require prior written BLM approval for
royalty-free treatment. The uses listed in
this section involve standard and
routine production and related
operations. In addition, proposed
paragraph (b) clarifies that the
authorization to use production without
payment of royalties is limited to the
amount of fuel reasonably necessary to
perform the operation on the lease using
appropriately sized equipment. This
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ensures that royalty-free on-site use
remains subject to the requirement to
avoid waste of the resource.
While the royalty-free uses proposed
here are generally similar to the uses
identified in the definition of
‘‘beneficial purposes’’ in NTL–4A, this
rulemaking would clarify which uses
warrant royalty-free treatment. This
proposed rule would not address some
uses that are defined as royalty-free
under ONRR provisions, such as the
royalty-free use of residue gas to fuel gas
plant operations as provided in 30 CFR
1202.151(b). In addition, this proposed
section would clarify that hot oil
treatment is an accepted on-lease use of
produced crude oil that does not require
prior approval to be royalty-free. In this
treatment, oil is not consumed as fuel.
Rather, after the oil is pumped back into
the well to stimulate production, it is
produced again. Although the use of
produced crude oil for hot oil
treatments on the producing lease, unit,
or CA has historically been understood
by the BLM and by operators as a
royalty-free use, it is not specifically
addressed in NTL–4A.
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(e) § 3178.5 Uses of Oil or Gas on a
Lease, Unit, or CA That Require Prior
Written BLM Approval for Royalty-Free
Treatment of Volumes Used
This proposed section identifies uses
of oil or gas that would require prior
written BLM approval to be deemed
royalty-free. The aim of this section is
three-fold: (1) To ensure that the BLM
retains discretion to grant royalty-free
use where the BLM deems the use to be
consistent with the MLA’s royalty
requirement for oil or gas that is
produced and then removed from the
lease and sold; (2) To increase
uniformity in the administration of the
royalty-provisions by specifying
circumstances that warrant particular
BLM attention; and (3) To ensure the
BLM’s awareness of unusual uses that
risk the loss or waste of oil and gas.
For two of the identified uses, existing
regulations already require BLM
approval before the operator may
conduct the operation. For all of the
identified uses, operators would be
required to submit a Sundry Notice
requesting BLM approval to conduct
royalty-free activities.
The potentially royalty-free uses
identified in this section are as follows:
• Using oil as a circulating medium
in drilling operations. This use is
expressly described as royalty-free
under NTL–4A. Because using produced
oil as a circulating medium is rare and
creates a possibility of loss, the proposal
would require that the BLM evaluate
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each request and approve the request in
writing only when appropriate.
• Injecting gas produced from a lease,
unit PA, or CA into the same lease, unit
PA, or CA to increase the recovery of oil
or gas. An operator must also obtain
BLM approval for this use under
existing regulations at 43 CFR 3162.3–
2. The substance of this provision
would not change from NTL–4A.
• Using oil or gas that was removed
from the pipeline at a location
downstream of the approved facility
measurement point (FMP), provided
that both removal and use occur on the
lease, unit, or CA. The BLM anticipates
that these situations would be quite rare
because the tap that operators use to
extract and measure gas is generally
upstream of the FMP.
• Using produced gas for operations
on the lease, unit PA, or CA, after it is
returned from off-site treatment or
processing to address a particular
physical characteristic of the gas.
Physical characteristics that might
preclude initial use of gas in lease
operations and necessitate off-lease
treatment or processing include an
unusually high concentration of
hydrogen sulfide, or the presence of
inert gases or liquid fractions that limit
the gas’s utility as a fuel. The operator
would bear the burden of establishing
the necessity of off-lease treatment; the
BLM typically would not approve, as a
royalty-free use, return of production to
the lease for use in operations necessary
to put production into marketable
condition.
• Any other type of use that is
consistent with proposed § 3178.3, but is
not specifically identified in proposed
§ 3178.4. This provision would clarify
that the BLM retains discretion to
consider approving royalty-free use
under circumstances that are not now
anticipated.
(f) § 3178.6 Uses of Oil or Gas Moved
Off the Lease, Unit, or CA That Do Not
Require Prior Written Approval for
Royalty-Free Treatment of Volumes
Used
This proposed section identifies two
circumstances in which royalty-free use
of oil or gas that has been moved off the
lease, unit, or CA would be permitted
without prior BLM approval.
The first situation is where an
individual lease, unit, or CA includes
non-contiguous areas, and oil or gas is
piped directly from one area of the
lease, unit, or CA to another area where
it is used, without oil or gas being added
to or removed from the pipeline, even
though the oil or gas crosses lands that
are not part of the lease, unit, or CA.
Under this proposed section, the BLM
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would consider such production as not
having been ‘‘removed from the lease.’’
This would provide the lessee or
operator the same opportunity for
royalty-free use as if the lease, unit, or
CA were one contiguous parcel. The
second situation is where a well is
directionally drilled, and the wellhead
is not located on the producing lease,
unit, or CA, but produced oil or gas is
used on the same well pad for
operations and production purposes for
that well. In such situations, the
proposed rule would allow for royaltyfree use at the well pad because, as the
IBLA noted in Plains Exploration &
Production Co., ‘‘(t)he gas (is) not
produced (extracted from the ground)
until after it (has) crossed the lease line.
Production and removal from the lease
are both requisite to triggering the
royalty obligation. . . . Thus, gas used
in wellhead production operations
would be regarded as used for the
benefit of the lease.’’ 365
(g) § 3178.7 Uses of Oil or Gas Moved
Off the Lease, Unit, or CA That Require
Prior Written Approval for Royalty-Free
Treatment of Volumes Used
This proposed section would address
the royalty treatment of oil or gas used
in operations conducted off the lease,
unit, or CA. When production is
removed from the lease, unit, or CA, it
becomes royalty-bearing unless
otherwise provided. This principle is
reflected in paragraph (a) of this
proposed section, which would provide
that with only limited exceptions,
royalty is owed on all oil or gas used in
operations conducted off the lease, unit,
or CA (referred to here as ‘‘off-lease
royalty-free use’’).
Paragraph (b) of this proposed section
identifies circumstances in which,
despite the principle articulated in
paragraph (a), the BLM would consider
approving off-lease royalty-free use.
These include situations in which the
operation is conducted using equipment
or at a facility that is located off the
lease, unit, or CA (under an approved
permit or plan of operations, or at the
agency’s request) because of
engineering, economic, resource
protection, or physical accessibility
considerations. For example, a
compressor that otherwise would have
been located on a lease may be sited off
the lease because the topography of the
lease is not conducive to equipment
siting. To be approved for off-lease
royalty-free use, the operation would
also have to be conducted upstream of
the approved FMP. This proposed
365 Plains Exploration & Production Co., 178
IBLA 327, 341 n.16 (2010).
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paragraph reflects the BLM’s policy to
encourage operators to reduce the
amount of surface disturbance
associated with oil and gas exploration
and development projects. In some
cases, centralizing production facilities
at a location off the lease may serve that
objective.
Paragraph (c) would require the
operator to obtain BLM approval for offlease royalty-free use via a Sundry
Notice containing the information
required under proposed section 3178.9
of this subpart. The BLM anticipates
that generally such approval would be
appropriate only in some of the
situations in which the BLM also
approves measurement at a location off
the lease, unit, or CA, or when the BLM
has granted approval to commingle
production off the lease, unit, or CA,
and to allocate production back to the
producing properties.
Paragraph (d) of this proposed section
would clarify that approval of off-lease
measurement or commingling under
other regulatory provisions does not
constitute approval of off-lease royaltyfree use. An operator or lessee must
expressly request, and submit its
justification for, approval of off-lease
royalty-free use.
Paragraph (e) of this proposed section
addresses circumstances in which
equipment located on a lease, unit, or
CA also treats production from other
properties that are not unitized or
communitized with the property on
which the equipment is located. Unless
the BLM approves off-lease royalty-free
use in such situations, an operator could
report as royalty-free only that portion
of the oil or gas used that is properly
allocable to the share of production
contributed by the lease, unit or CA on
which the equipment is located.
NTL–4A does not include a provision
that specifically addresses approving
off-lease royalty-free use. Such approval
is required, however, under ONRR
regulations, which provide, ‘‘All gas
(except gas unavoidably lost or used on,
or for the benefit of, the lease, including
that gas used off-lease for the benefit of
the lease when such off-lease use is
permitted by the BOEMRE or BLM, as
appropriate) produced from a Federal
lease to which this subpart applies is
subject to royalty.’’ 366 The proposed
section would add clarity and
consistency in implementation.
(h) § 3178.8 Measurement or
Estimation of Royalty-Free Volumes
This proposed section specifies that
an operator must measure or estimate
the volume of royalty-free gas used in
366 30
CFR 1202.150(b) (emphasis added).
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operations upstream of the FMP. In
general, the operator would be free to
choose whether to measure or estimate,
with the exception that the operator
must in all cases measure under the
applicable oil or gas measurement
regulations: (1) The volume of royaltyfree oil used in operations on the lease,
unit, or CA; and (2) The volume of
royalty-free gas removed from the
product downstream of the FMP and
used in operations on the lease, unit, or
CA. If oil is used on the lease, unit or
CA, it is most likely to be removed from
a storage tank on the lease, unit or CA.
Thus, this proposed section would also
require the operator to document the
removal of the oil from the tank.367
For both oil and gas, the operator
would have to report the volumes
measured or estimated, as applicable,
under ONRR requirements.
(i) § 3178.9 Requesting Approval of
Royalty-Free Treatment When Approval
Is Required
This proposed section describes how
to request BLM approval of royalty-free
use when prior-approval is required
under proposed § 3178.5 or proposed
§ 3178.7. NTL–4A is silent with respect
to application procedures. This
proposed section would require the
operator to submit a Sundry Notice
containing specified information, which
is necessary for the BLM to determine
if approval is appropriate. The
information would include a
description of the operation to be
conducted, the measurement or
estimation method, the volume
expected to be used, the basis for an
estimate (if applicable), and the
proposed disposition of the oil or gas
used.
(j) § 3178.10 Facility and Equipment
Ownership
This proposed section clarifies that
although the operator would not be
required to own the equipment in which
production is used royalty-free, the
operator is responsible for all
authorizations, production
measurements, production reporting,
and other applicable requirements.
5. Subpart 3179—Waste Prevention and
Resource Conservation
(a) § 3179.1 Purpose
This proposed section states that the
purpose of subpart 3179 would be to
implement the statutes relating to
prevention of waste from Federal and
Indian (other than Osage Tribe) leases,
conservation of surface resources, and
management of the public lands for
367 80
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multiple use and sustained yield. The
proposed section also provides that
subpart 3179 would supersede those
parts of NTL–4A that pertain to flaring
and venting of produced gas,
unavoidably and avoidably lost gas, and
waste prevention.
(b) § 3179.2 Scope of This Subpart
This proposed section specifies which
leases, agreements, tracts, facilities, and
gas lines are covered by this subpart.
The proposed section also states that the
term ‘‘lease’’ in this subpart includes
IMDA agreements as consistent with
those agreements and with principles of
Federal Indian law—an edit intended to
enhance the clarity and brevity of these
provisions.
(c) § 3179.3 Definitions and Acronyms
This proposed section contains
definitions for 13 terms that are used in
subpart 3179: ‘‘Accessible component’’;
‘‘capture’’ and ‘‘capture infrastructure’’;
‘‘component’’; ‘‘development oil well’’
and ‘‘development gas well’’; ‘‘gas-to-oil
ratio’’; ‘‘gas well’’; ‘‘liquid
hydrocarbon’’; ‘‘liquids unloading’’;
‘‘lost oil or lost gas’’; ‘‘storage vessel’’;
and ‘‘volatile organic compounds.’’
Some defined terms have a particular
meaning in this proposed rule. Other
defined terms may be familiar to many
readers, but we include their definitions
in the proposed regulatory text to
enhance the clarity of the rule.
(d) § 3179.4 Determining When the
Loss of Oil or Gas Is Avoidable or
Unavoidable
This proposed section describes the
circumstances under which lost oil or
gas would be classified as ‘‘unavoidably
lost.’’ ‘‘Avoidably lost’’ oil or gas would
then be defined as oil or gas that is not
unavoidably lost.
NTL–4A defined the terms ‘‘avoidably
lost’’ and ‘‘unavoidably lost,’’ but the
definitions are general and could be
applied inconsistently. The descriptions
in the proposed rule are intended to
enhance clarity and consistency by
listing specific operations and sources
that produce gas that the BLM would
deem ‘‘unavoidably lost,’’ as long as an
operator has not been negligent, has not
violated laws, regulations, lease terms or
orders, and has taken prudent and
reasonable steps to avoid waste.
The rule would also define as
‘‘unavoidably lost’’ any produced gas
that is vented or flared from a well that
is not connected to gas capture
infrastructure, if the BLM has not
determined that the loss of gas through
such venting or flaring is otherwise
avoidable. To be deemed ‘‘unavoidably
lost,’’ this produced gas would have to
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comply with the limits of proposed
§ 3179.6.
Finally, this proposed section would
define ‘‘avoidably lost’’ oil or gas as lost
oil or gas that does not meet this
section’s definition of ‘‘unavoidably
lost.’’
(e) § 3179.5 When Lost Production Is
Subject to Royalty
This proposed section would
reemphasize the distinction that is the
foundation of NTL–4A: Royalties are
due on all avoidably lost oil or gas, but
not on unavoidably lost oil or gas. This
section further provides that if oil
becomes waste oil through operator
negligence, the operator would owe
royalties on the waste oil, but absent
negligence, waste oil would be royaltyfree.
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(f) § 3179.6 When Flaring or Venting Is
Prohibited
This proposed section would require
operators to flare all gas that is not
captured, except under certain limited
circumstances. Operators would be
allowed to vent gas if flaring is
technically infeasible—for example if
the volumes of gas are too small to
operate a flare, or if the gas is not
readily combustible. Operators would
also be allowed to vent gas in an
emergency, when the loss of gas is
uncontrollable or venting is necessary
for safety. In addition, this proposed
section would authorize venting of gas
from pneumatic devices, and from
storage vessels, as long as flaring of that
gas is not required under other
provisions of this proposed subpart.
This proposed section would impose
an overall limit of 1,800 Mcf per month
per well, averaged over all of the
producing wells on a lease, on all
venting or flaring from development oil
wells, unless the BLM approves an
alternative volume limit under proposed
§ 3179.7. This limit would phase in over
the first 3 years that the rule is in effect,
such that the flaring limit in year 1
would be 7,200 Mcf/well/month,
averaged over all of the producing wells
on a lease, the limit in year 2 would be
3,600 Mcf/well/month on average, and
the limit in year 3 and thereafter would
be 1,800 Mcf/well/month, again on
average.
(g) § 3179.7 Alternative Limits on
Venting and Flaring
This proposed section would apply
only to leases issued before the effective
date of this regulation. It would allow
the BLM to approve a higher limit on
venting and flaring for a well, in place
of the applicable limit specified in
proposed § 3179.6, if the operator
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demonstrates, and the BLM agrees, that
the limit would impose such costs as to
cause the operator to cease production
on the lease and abandon significant
recoverable oil reserves. In making this
determination, the BLM would consider
the costs of capture, and the costs and
revenues of all oil and gas production
on the lease. To demonstrate the need
for an alternative limit, the operator
would have to submit through a Sundry
Notice: (1) Information regarding the
operator’s wells under the lease that
produce Federal or Indian gas,
including identifying information, and
levels of gas production, venting and
flaring for each well; (2) Maps showing
the lease area, well and pipeline
locations, capture, flaring and venting
status of wells, and distances to
pipelines; (3) Information on pipeline
capacity and the operator’s cost
projections for gas capture infrastructure
and alternative methods of
transportation that do not require
pipelines; and (4) The operator’s
projections of oil and gas prices, oil and
gas production volumes, costs, revenues
and royalty payments from the
operator’s oil and gas operations on the
lease over the lesser of 15 years or the
remaining period in which the operator
will produce from the Federal or Indian
lease, unit, or CA. As provided in
paragraph (c) of this proposed section,
the BLM would aim to set the lowest
alternative flaring limit that would not
cause the operator to cease production
and abandon significant recoverable oil
reserves under the lease.
In addition, this proposed section
would exempt wells on a lease from the
applicable flaring limit for a renewable
2-year period if the operator certifies
that the following conditions apply: (1)
The lease, unit, or CA is not connected
to a gas pipeline; (2) The lease is more
than 50 straight-line miles from the
nearest gas processing plant; and (3) The
rate gas flaring from the lease is 50
percent or more greater than the
applicable flaring limit in proposed
§ 3179.6. An operator would have to
submit a Sundry Notice to the BLM,
certifying in an affidavit that it meets
the conditions for the exemption.
(h) § 3179.8 Measuring and Reporting
Volumes of Gas Vented and Flared From
Wells
This proposed section would require
operators to estimate (using estimation
protocols) or measure (using a metering
device) all flared and vented gas,
whether royalty-bearing or royaltyfree.368
368 Estimation in this instance involves the use of
known well or reservoir information such as
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This proposed section further
provides that operators must measure
rather than estimate the flared and
vented volumes when the operator is
flaring 50 Mcf or more of gas per day
from a flare stack or manifold, based on
estimated volumes.
This proposed section would not
specify how to measure gas when
measurement is required. Onshore Oil
and Gas Orders Nos. 4 and 5, which are
currently undergoing revision, contain
standards for measuring royalty-bearing
oil and gas, respectively.369
This proposed section would also
require operators to report all volumes
vented or flared under applicable ONRR
reporting requirements.
(i) § 3179.9 Determinations Regarding
Royalty-Free Venting or Flaring
This proposed section would provide
for a transition for operators that are
operating under existing approvals for
royalty-free flaring or venting, as of the
effective date of the rule. Those
operators could continue to flare or vent
royalty-free, and/or to flare or vent
above the applicable flaring limit, for 90
days after the effective date of the rule.
After 90 days, those operators would
become subject to all the provisions of
the final rule, including both the royalty
provisions and the flaring limit.
Further, this proposed section would
clarify that nothing in this subpart alters
the royalty-bearing status of flaring that
occurred prior to [EFFECTIVE DATE OF
FINAL RULE], nor the BLM’s authority
to determine that status and collect
appropriate back-royalties.
(j) § 3179.10 Other Waste Prevention
Measures
This proposed section would clarify
that nothing in this subpart alters the
BLM’s existing authority under the MLA
to limit the volume of production from
a lease, or to delay action on an APD to
minimize the loss of associated gas.370
Specifically, if production from a new
well would force an existing producing
well already connected to the pipeline
to go offline, then notwithstanding the
periodic well tests or a well’s gas to oil ratio to
estimate a well’s gas production rate. For example,
if a production flow test is conducted monthly on
a well, one might presume the well continued
producing gas at the tested rate for the entire
month. Similarly, if a well has a gas to oil ratio that
is uniform over time, the operator could estimate
the rate of gas production based on the measured
rate of oil production and the gas to oil ratio. Gas
volume estimation using these protocols is suitable
for reporting flared gas volumes in many cases.
369 For oil: Onshore Oil and Gas Order No. 4,
III(C), III(D), and III(E); for gas: Onshore Oil and Gas
Order No. 5, III(C) and III(D). More information can
be found at https://www.blm.gov/wo/st/en/prog/
energy/oil_and_gas/onshore_oil_and_gas.html.
370 30 U.S.C. 187; 30 U.S.C. 225.
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requirements in 3179.6 and 3179.7, the
BLM could limit the volume of
production from the new well for a
period of time, while gas pressures from
the new well stabilize. In addition, the
BLM could delay action on an APD or
approve it with conditions related to gas
capture and production levels. The BLM
could suspend the lease under 43 CFR
3103.4–4 if the lease associated with the
APD is not in producing status.
(k) § 3179.11 Coordination With State
Regulatory Authority
This proposed section addresses
certain ‘‘mixed ownership’’ situations,
in which a single well may produce oil
and gas from Federal and/or Indian
mineral interests, and non-Federal, nonIndian mineral interests. This proposed
section would provide that to the extent
that any BLM action to enforce a
prohibition, limitation, or order under
this subpart adversely affects
production of oil or gas from nonFederal and non-Indian mineral
interests, the BLM would coordinate on
a case-by-case basis with the State
regulatory authority with jurisdiction
over that non-Federal and non-Indian
production. This is consistent with
current practice, in which the BLM and
State regulators coordinate closely in
regulating and enforcing requirements
that apply to operators producing from
Federal or Indian and non-Federal nonIndian mineral interests.
6. Flaring and Venting Gas During
Drilling and Production Operations
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(a) § 3179.101
Well Drilling
This proposed section would require
gas that reaches the surface as a normal
part of drilling operations to be used or
disposed of in one of four specified
ways: (1) Captured and sold; (2) Flared
at a flare pit or stack with an automatic
igniter; (3) Used in the lease operations;
or (4) Injected. Under the proposal, gas
may not be vented except under the
narrow circumstances specified in
proposed § 3179.6(a).
The proposed section also addresses
gas that is lost as a result of loss of well
control. If there is a loss of well control,
the BLM would determine whether it
was due to operator negligence, and if
so, the BLM will notify the operator in
writing. Gas lost as a result of a loss of
well control would be classified as
unavoidably lost and royalty-free,
unless the loss of well control was due
to operator negligence, in which case it
would be avoidably lost and subject to
royalties.
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(b) § 3179.102 Well Completion and
Related Operations
This proposed section would address
gas that reaches the surface during well
completion and post-completion
recovery of drilling, fracturing, or refracturing. It would apply the same
requirements and exceptions for use,
sale, or disposal as proposed for well
drilling operations under proposed
§ 3179.101. In lieu of compliance with
the requirements of this proposed
section, an operator may demonstrate to
the BLM that it is in compliance with
the requirements for control of gas from
well completions established under 40
CFR part 60 subpart OOOOa.
Volumes flared under this proposed
section would be reported to ONRR as
directed in proposed § 3179.106 of this
subpart.
(c) § 3179.103
Testing
Initial Production
This proposed section would clarify
when gas may be flared, royalty-free or
otherwise, during a well’s initial
production test. It provides that gas may
be flared royalty-free during initial
production testing for up to 30 days or
20 MMcf of flared gas, whichever occurs
first. Volumes flared under proposed
§ 3179.102(a)(2) during well completion
would count towards the 20 MMcf limit.
Under this section, royalty-free flaring
would end when production begins.
Paragraph (b) of this proposed section
would allow the BLM to approve
royalty-free flaring during a longer
testing period of up to 60 days, if there
are well or equipment problems or a
need for additional testing to develop
adequate reservoir information.
Paragraph (c) would allow a 90- rather
than 30-day period for royalty-free
flaring, during the variable and timeintensive dewatering and initial
evaluation of exploratory coalbed
methane well. In addition, the BLM
could approve up to two extensions of
90 days each to allow for more time to
dewater a coalbed methane well. The
operator would have to transmit a
request for a longer test period under
paragraph (b) or (c) of this proposed
section through a Sundry Notice. Under
any of these circumstances,
notwithstanding an extension of the test
period, the well would be still subject
to the 20 MMcf limit on flared gas.
Volumes vented or flared under this
proposed section would be reported to
ONRR as directed in proposed § 3179.8
of this subpart.
(d) § 3179.104
Subsequent Well Tests
The proposed requirement in this
section is essentially the same as NTL–
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4A’s requirement regarding subsequent
well tests. It would limit royalty-free
flaring during production tests after the
initial production test to 24 hours,
unless the BLM approves or requires a
longer test period. The operator must
transmit its request for a longer test
period through a Sundry Notice.
Volumes vented or flared under this
proposed section would be reported to
ONRR as directed in proposed § 3179.8
of this subpart.
(e) § 3179.105
Emergencies
This proposed section would provide
that an operator may flare or vent
royalty-free during a temporary, shortterm, infrequent, and unavoidable
emergency.
Paragraph (b) would limit royalty-free
emergency flaring or venting to a
maximum of 24 hours per incident, for
a maximum of three incidents per lease,
unit, or CA per 30-day period. Together,
these limits restrict monthly flaring or
venting to a maximum of 72 hours.
The proposed rule would further
clarify that more than three failures of
the same equipment within any 365-day
period, and failures that result from
improperly sized, installed, or
maintained equipment, would not
constitute an emergency. Similarly, the
proposed rule would also exclude from
the definition of ‘‘emergency’’ any
equipment failure caused by operator
negligence.
In addition, this proposed section
would clarify that scheduled
maintenance does not constitute an
emergency, even when it is outside of
the operator’s control. For example, the
fact that a downstream gas processing
plant goes down for maintenance would
not constitute an emergency that allows
an operator to flare royalty-free.
Volumes vented or flared under this
proposed section would be reported to
ONRR as directed in proposed § 3179.8
of this subpart.
7. Gas Flared or Vented From
Equipment or During Well Maintenance
Operations
(a) § 3179.201 Equipment
Requirements for Pneumatic Controllers
This proposed section would address
gas losses from pneumatic controllers.
Paragraph (a) identifies the pneumatic
controllers that would be subject to the
requirements of this section: Pneumatic
controllers that use natural gas
produced from a Federal or Indian lease,
or from a unit or CA that includes a
Federal or Indian lease, if the controllers
have a continuous bleed rate greater
than 6 scf/hour (‘‘high-bleed’’
controllers) and are not covered by EPA
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regulations that prohibit the new use of
high-bleed pneumatic controllers (40
CFR 60.5360 through 60.5390).
Paragraph (b) of the proposed section
would require pneumatic controllers
subject to the requirement to be
replaced with controllers having a bleed
rate of no more than 6 scf/hour. Under
paragraph (c), operators would be
required to replace the controllers
within 1 year from the effective date of
the final rule, or within 3 years from the
effective date of the rule, if the well or
facility served by the controller has an
estimated remaining productive life of 3
years or less. Under paragraph (d),
operators would also be required to
ensure that pneumatic controllers are
functioning within the manufacturers’
specifications.
This proposed section also provides
several exceptions to the replacement
requirement. An operator would not be
required to replace a controller if a highbleed controller is necessary to perform
the needed function. For example,
replacement might not be required if a
low-bleed controller would not provide
a timely response, which would lead to
greater waste or create a safety hazard.
Likewise, replacement would not be
required if the controller is routed to a
flare, or if the operator demonstrates,
and the BLM concurs, that replacing the
pneumatic controllers on the lease
would impose such costs as to cause the
operator to cease production and
abandon significant recoverable oil
reserves under the lease.
(b) § 3179.202 Requirements for
Pneumatic Chemical Injection Pumps or
Pneumatic Diaphragm Pumps
This proposed section would
establish requirements for operators
with pneumatic chemical injection
pumps or pneumatic diaphragm pumps
that use natural gas produced from a
Federal or Indian lease, or from a unit
or CA that includes a Federal or Indian
lease, except those pneumatic pumps
covered under EPA regulations at 40
CFR part 60, subpart OOOO. The
proposed section would require
operators to replace pneumatic pumps
covered by this proposed section with a
zero-emissions pump or route the
pneumatic pump to a flare, no later than
1 year after these rules are effective.
The proposed section also provides
for exceptions to the replacement
requirement. An operator would not be
required to replace a pneumatic pump
if a zero-emissions pump would be
insufficient to perform the pneumatic
pump’s function, and an operator would
not be required to route a pneumatic
pump to a flare if no flare device were
available on site. Replacement or
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routing to a flare is also not required if
the operator demonstrates, and the BLM
concurs, that the cost of replacing the
pneumatic pumps on the lease or
routing them to a flare would impose
such costs as to cause the operator to
cease production and abandon
significant recoverable oil reserves
under the lease.
In addition, as proposed for
pneumatic controllers and based on the
same rationale, this proposed section
would provide that if the estimated
remaining productive life of the well or
facility is 3 years or less, the operator
would be allowed to replace the
pneumatic controller no later than 3
years from the effective date of the
regulation, rather than within 1 year.
The proposed section would also
require that pneumatic pumps function
within manufacturers’ specifications.
(c) § 3179.203 Crude Oil and
Condensate Storage Vessels
This proposed section addresses gas
vented from an oil or condensate storage
vessel (or a battery of storage vessels)
that contains production from a Federal
or Indian lease, or from a unit or CA that
includes a Federal or Indian lease. The
proposed section would require
operators to route all gas vapor from
covered storage vessels or batteries to a
combustion device or continuous flare,
or to a sales line. Operators would be
required to meet this requirement no
later than 6 months after the rule
becomes effective.
A storage vessel would be subject to
this proposed section if the vessel is not
covered under EPA regulations at 40
CFR part 60 subpart OOOO, and if it has
a rate of total VOC emissions equal to
or greater than 6 tpy. Operators would
be required to determine the rate of
emissions from the storage vessel within
60 days after this rule is effective, and
within 30 days after adding a new
source of production to a storage vessel.
This proposed section would not
apply if the total VOC emissions rate
from the storage vessel declines to 4 tpy
in the absence of controls for 12
consecutive months, or if the operator
demonstrates, and the BLM concurs,
that the cost of replacing the pneumatic
pumps on the lease or routing them to
a flare would impose such costs as to
cause the operator to cease production
and abandon significant recoverable oil
reserves under the lease.
(d) § 3179.204 Downhole Well
Maintenance and Liquids Unloading
This proposed section would
establish requirements for venting and
flaring during downhole well
maintenance and liquids unloading. It
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would require the operator to use
practices for such operations that
maximize the recovery of gas for sale,
and to flare gas that is not recoverable,
unless the practices or flaring are
technically infeasible or unduly costly.
The proposed rule would also prohibit
liquids unloading by well purging (as
defined in the section) for wells drilled
after the effective date of this rule,
except when the operator is returning
the well to production following a well
workover or following a shut-in of more
than 30 days.
For existing wells, before the operator
purges a well for the first time after the
effective date of this section, the BLM is
proposing that the operator must
document that purging is the only
technically or economically feasible
method of unloading liquids from the
well. In addition, during any liquids
unloading by well purging, an operator
would be required to be present on site
to ensure that any venting to the
atmosphere is limited to what is
necessary, unless the operator uses an
automated control system that limits the
venting event to the minimum
necessary. This proposed section would
require the operator to maintain records
of the date and duration of each venting
event and to make those records
available to the BLM upon request.
Under this proposal, the operator
would be required to notify the BLM by
Sundry Notice within 10 days after the
first liquids unloading by well purging
after the effective date of the rule.
Operators would also be required to
notify the BLM by Sundry Notice if the
cumulative duration of well purging
events for a well exceeds 24 hours
during any production month, or if the
estimated volume of gas vented in the
process exceeds 75 Mcf during any
production month.
Paragraph (g) would require operators
to report volumes vented during
downhole maintenance and liquids
unloading to ONRR.
8. Leak Detection and Repair
(a) § 3179.301
Operator Responsibility
This proposed section would apply to
all oil or gas wells that produce gas from
a Federal or Indian lease, or from a unit
or CA that includes a Federal or Indian
lease. The section would obligate
operators to inspect all equipment,
equipment components, facilities (such
as separators, heater/treaters, and
liquids unloading equipment), and
compressors located on the lease, unit,
or CA for leaks. Operators would be
required to conduct the inspections
during production operations, and to fix
any leaks found.
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The proposed requirement would not
apply to centralized compressors,
owned by a pipeline company, which
the operator of the Federal or Indian
lease, unit, or CA does not lease or
operate, and for which the operator has
no direct control over maintenance and
operation. In addition, operators would
have the option to demonstrate to the
BLM in a Sundry Notice that, in lieu of
complying with these requirements for
LDAR for some or all of their equipment
and facilities, the operator is complying
with LDAR requirements established by
the EPA under 40 CFR part 60 subpart
OOOOa for the same equipment and
facilities. Under the proposed rule, the
BLM’s LDAR requirements would apply
to operators that are covered by 40 CFR
part 60, but do not meet that rule’s
production thresholds, and are therefore
exempt from performing LDAR under
that rule. The BLM seeks comment on
whether such operators should also be
exempt from this rule’s LDAR
requirements.
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(b) § 3179.302 Approved Instruments
and Methods
This proposed section would
prescribe the types of instruments and
monitoring methods that an operator
must use to inspect for leaks.
Specifically, operators could use: (1) An
optical gas imaging device such as an
infrared camera; (2) An alternative,
equally advanced monitoring device,
not listed in the proposed rule, which
is approved by the BLM for use by any
operator; or (3) A comprehensive
program, approved by the BLM, that
includes the use of instrument-based
monitoring devices or continuous
emissions monitoring. Large operators
that have 500 or more wells within the
jurisdiction of a single BLM field office
would have only these three choices for
detecting leaks. Smaller operators,
however, would have a fourth choice:
To use a portable analyzer device,
operated according to manufacturer
specifications, and assisted by AVO
inspection.
(c) § 3179.303 Leak Detection
Inspection Requirements for Natural Gas
Wellhead Equipment, Facilities, and
Compressors
This proposed section would require
operators to conduct initial site
inspections within specified timeframes
after the effective date of the rule. The
proposed section would define ‘‘site’’ as
a discrete area containing wellhead
equipment, facilities, and compressors,
which is suitable for inspection in a
single visit.
The proposed section would require
the operator initially to conduct site
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inspections twice a year. The inspection
frequency would be subject to change
based on whether leaks are detected in
two consecutive inspections, according
to the following provisions:
• Case one: If the operator detects no
more than two leaks at the site
inspected, in each of two consecutive
semi-annual inspections, the operator
could shift to conducting less frequent,
annual inspections.
• Case two: If the operator detects
three or more leaks at the site inspected,
in each of two consecutive semi-annual
inspections, the operator would have to
shift to more frequent, quarterly
inspections.
The proposed section also specifies
that the inspection frequency would
revert back to semi-annually if: (1) In
case one, the operator detects three or
more leaks in two subsequent,
consecutive annual inspections; or (2) In
case two, the operator detects no more
than two leaks in two subsequent,
consecutive, quarterly inspections.
Paragraph (b) of this proposed section
would authorize the BLM to approve an
alternative leak detection device,
program, or method, if the BLM finds
that the alternative would meet or
exceed the effectiveness of the required
approach. The operator would have to
transmit a request for an alternative leak
detection device, program, or method
through a Sundry Notice.
Under paragraph (c), an operator
would not be required to inspect
components that are not accessible.
(d) § 3179.304 Repairing Leaks
This proposed section would require
operators to repair leaks within 15
calendar days of discovery of the leak,
unless there is good cause for repair to
take longer. The proposed rule would
require the operator to notify the BLM
if this occurs and to complete the repair
within 15 calendar days after the cause
of the delay ceases to exist. The rule
would also require the operator to
conduct a follow-up inspection to verify
the effectiveness of the repair, using the
same method used to detect the leak,
within 15 calendar days after the repair
and to make additional repairs within
15 calendar days if the previous repair
was not effective. The repair and followup process would have to be followed
until the repair is effective. The BLM
would not consider an inspection to
verify the effectiveness of a repair to be
a periodic inspection under proposed
§ 3179.303.
(e) § 3179.305 Leak Detection
Inspection Recordkeeping
This proposed section would require
operators to maintain records of LDAR
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6669
inspections and repairs, including dates,
locations, methods, where leaks were
found, dates of repairs, and dates of
follow-up inspections. These records
would have to be made available to the
BLM upon request.
9. State or Tribal Variances
(a) § 3179.401 State or Tribal Requests
for Variances From the Requirements of
This Subpart
This proposed section would create a
variance procedure, under which the
BLM could grant a State or tribe’s
request to have a State or tribal
regulation apply in place of a provision
or provisions of this subpart. The
variance request would have to: (1)
Identify the specific provisions of the
BLM requirements for which the
variance is requested; (2) Identify the
specific State or tribal regulation that
would substitute for the BLM
requirements; (3) Explain why the
variance is needed; and (4) Demonstrate
how the State or tribal regulation would
satisfy the purposes of the relevant BLM
provisions. The BLM State Director
would review a State or tribal variance
request. To approve a request, the BLM
State Director would have to determine
that the State or tribal regulation meets
or exceeds the requirements of the
provision(s) for which the State or tribe
sought the variance, and that the State
or tribal regulation is consistent with
the terms of the affected Federal or
Indian leases and applicable statutes.
Paragraph (b) would specify that the
decision on a variance request is not
subject to administrative appeal under
43 CFR part 4. Paragraph (c) would
clarify that a variance granted under this
proposed section would not constitute a
variance from provisions of regulations,
laws, or orders other than proposed
subpart 3179. Paragraph (d) would
reserve the BLM’s authority to rescind a
variance or modify any condition of
approval in a variance.
VI. Analysis of Impacts
A. Description of the Regulated Entities
1. Potentially Affected Entities
Entities that would be directly
affected by the proposed rule would
include most, if not all, entities
involved in the exploration and
development of oil and natural gas on
Federal and Indian lands. According to
AFMSS data (as of March 27, 2015),
there are up to 1,828 entities that
currently operate Federal and Indian
leases.371 We believe that these 1,828
371 The actual number is expected to be slightly
lower due to duplicate entries.
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entities would be most affected by the
proposed rule, in addition to entities
currently involved with drilling and
support activities, and any entities that
become involved in the future.
The potentially affected entities are
likely to fall within one of the following
industries, identified by the North
American Industry Classification
System (NAICS) codes:
• NAICS Code 21111 ‘‘Oil and Gas
Extraction’’
• NAICS Code 213111 ‘‘Drilling Oil and
Gas Wells’’
• NAICS Code 213112 ‘‘Support
Activities’’
Table 35 of the RIA displays 2011
data from the U.S. Census Bureau,
which reveal a number of characteristics
about the entities that operate within
these industries.372 First, the table
identifies the total number of entities
within each industry and the number of
entities with less than 500 employees
and the number of entities with 500 or
more employees. Next, the table
identifies the total employment within
each industry and the combined
employment for entities with less than
500 employees and the combined
employment for entities with 500 or
more employees. Third, the table shows
the total annual payroll for each
industry and the combined annual
payroll for entities with less than 500
employees and the combined annual
payroll for entities with 500 or more
employees.
Based on these data, in 2011, there
were 6,628 entities directly involved in
extraction of oil and gas in the United
States, 2,041 entities involved in the
drilling of wells, and 8,119 entities
providing other support functions.
Therefore, the approximately 17,000
entities associated with developing, and
producing of domestic oil and gas 373
represent an upper bound estimate of
the operators that could potentially be
affected by this rulemaking.
2. Affected Small Entities
The Small Business Administration
(SBA) has developed size standards to
carry out the purposes of the Small
Business Act and those size standards
can be found in 13 CFR 121.201. For
mining, including the extraction of
crude oil and natural gas, the SBA
defines a small entity as an individual,
372 Calendar year 2011 is the most recent data
available from the U.S. Census Bureau that includes
detailed employment data. Entities primarily
involved in the support of mining activities on a
contract basis were not included in this count.
373 U.S. Census Bureau data does not readily
differentiate between the number of firms involved
in oil development and production activities versus
gas development and production.
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limited partnership, or small company,
at ‘‘arm’s length’’ from the control of
any parent companies, with fewer than
500 employees. For entities drilling oil
and gas wells, the threshold is also 500
employees. For entities involved in
support activities, the standard is
annual receipts of less than $38.5
million. Of the 6,628 domestic firms
involved in oil and gas extraction, 99
percent (or 6,530) had fewer than 500
employees. There are another 2,041
firms involved in drilling. Of those
firms, 98 percent of those firms had
fewer than 500 employees.
To estimate a percentage for firms
involved in oil and gas support
activities we reference Table 36 of the
RIA, which provides the NAICS
information for firms involved in oil
and gas support activities based on the
size of receipts. The most recent data
available from the U.S. Census Bureau
for establishment/firm size based on
receipts is for 2007. Of the 5,880 firms
in oil and gas support activities in 2007,
97 percent had annual receipts of less
than $35 million.374
Based on this national data, the
preponderance of entities involved in
developing oil and gas resources are
small entities as defined by the SBA. As
such, a substantial number of small
entities may potentially be affected by
the proposed rule.
B. Impacts of the Proposed
Requirements
1. Overall Costs of the Rule 375
We analyzed the overall costs of the
rule if the EPA finalizes the 40 CFR part
60 subpart OOOOa rulemaking, and also
if the EPA does not finalize that
rulemaking. As explained above, we
expect more significant costs and
benefits of the rule for the first few
years, during which some operators
would have to add or improve gascapture capability, and some would also
have to replace existing equipment. The
BLM expects this transitional period to
last for the first few years, after which
the compliance requirements of the rule
would be significantly reduced, as
would any benefits associated with
increased capture and sale of gas that
would otherwise have been vented or
flared.
Overall, assuming that the EPA
finalizes its concurrent 40 CFR part 60
subpart OOOOa rulemaking, the BLM
estimates that this rule will pose costs
ranging from $125–161 million per year
374 U.S. Census Bureau does not provide receipt
data that allow a break at the $38.5 million
threshold as defined by SBA. As such, the 97
percent figure is a slight underestimate.
375 RIA at 81–90.
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(using a 7 percent discount rate) or
$117–1 34 million per year (using a 3
percent discount rate) over the next 10
years.376 These costs include
engineering compliance costs and the
social cost of minor additions of carbon
dioxide to the atmosphere.377 The
engineering compliance costs presented
do not include potential cost savings
from the recovery and sale of natural gas
(those savings are shown in the
summary of benefits).
If, for analytical purposes, we assume
that EPA does not finalizes its
concurrent 40 CFR part 60 subpart
OOOOa rulemaking, these requirements
would affect more sources and the costs
would be somewhat higher. Under that
scenario, the BLM estimates that this
rule will pose costs ranging from $139—
174 million per year (using a 7 percent
discount rate) or $131–147 million per
year (using a 3 percent discount rate)
over the next 10 years.378
In some areas, operators have already
undertaken, or plan to undertake,
voluntary actions to address gas losses.
To the extent that operators are already
in compliance with the requirements of
this proposed rule, the above estimates
overstate the likely impacts of the rule.
2. Overall Benefits of the Rule 379
The potential benefits of the rule
include the additional production of
resources from Federal and Indian
leases; reductions in venting, flaring,
and GHG emissions; and increased
opportunities for royalties.
We measure the benefits of the rule as
the cost savings that the industry would
receive from the recovery and sale of
natural gas and the projected
environmental benefits of reducing the
amount of GHG and other air pollutants
released into the atmosphere. As with
the estimated costs, we expect benefits
on an annual basis.
The estimated benefits of the rule also
depend on whether the EPA finalizes its
40 CFR part 60 subpart OOOOa
rulemaking. Assuming that rule is in
effect, the BLM estimates that this rule
would result in monetized benefits of
$255–329 million per year (using a 7
percent discount rate to calculate the
present value of future annual cost
savings and using model averages of the
social cost of methane with a 3 percent
discount rate) or $255–357 million per
year (using a 3 percent discount rate to
376 RIA
at 127.
gas that would have otherwise been
vented would now be combusted on-site or
presumably downstream to generate electricity. The
estimated value of the carbon additions do not
exceed $21,000 in any given year.
378 RIA at 127.
379 RIA at 85–90.
377 Some
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calculate the present value of future
annual cost savings and using model
averages of the social cost of methane
with a 3 percent discount rate).380 We
estimate that the proposed rule would
reduce methane emissions by 164,000–
169,000 tpy, which we estimate to be
worth $180–253 million per year (this
social benefit is included in the
monetized benefit above). We estimate
that the proposed rule would reduce
VOC emissions by 391,000–411,000
(this benefit is not monetized in our
calculations).381
If, for purposes of analysis, we assume
that EPA does not finalize its 40 CFR
part 60 subpart OOOOa rulemaking, we
estimate that this proposed rule would
result in monetized benefits of $270–
354 million per year (using a 7 percent
discount rate to calculate the present
value of future annual cost savings and
using model averages of the social cost
of methane with a 3 percent discount
rate) or $270–384 million per year
(using a 3 percent discount rate to
calculate the present value of future
annual cost savings and using model
averages of the social cost of methane
with a 3 percent discount rate).382 We
estimate that the proposed rule would
reduce methane emissions by 176,000–
185,000 tpy, which we estimate to be
$193–277 million per year (this social
benefit is included in the monetized
benefit above). We estimate that the
proposed rule would reduce VOC
emissions by 400,000–423,000 (this
benefit is not monetized in our
calculations).383
The proposed rule will also have
numerous ancillary benefits. These
include improved quality of life for
nearby residents, who note that flares
are noisy and unsightly at night;
reduced release of VOCs, including
benzene and other hazardous air
pollutants; and reduced production of
NOx and particulate matter, which can
cause respiratory and heart problems.
3. Net Benefits of the Proposed Rule
Overall, the BLM estimates that the
benefits of this rulemaking outweigh its
costs by a significant margin. The BLM
expects net benefits ranging from $115–
188 million per year (using a 7 percent
discount rate) or $138–232 million per
year (using a 3 percent discount rate).
Specifically, assuming a 7 percent
discount rate, we estimate the following
annual net benefits:
• $115–130 million per year from
2017–2019;
at 130.
at 133–135.
382 RIA at 130.
383 RIA at 133–135.
• $155–156 million per year from
2020–2024; and
• $187–188 million per year from
2025–2026.
Assuming a 3 percent discount rate,
we estimate the annual net benefits
would be:
• $138–151 million per year from
2017–2019;
• $192–196 million per year from
2020–2024; and
• $231–232 million per year from
2025–2026.384
If, for purposes of analysis, we assume
that the EPA does not finalize the 40
CFR part 60 subpart OOOOa
rulemaking, we estimate the net benefits
of this proposed rule would be
somewhat higher, ranging from $119
million to $203 million per year (costs
and costs savings calculated using a 7
percent discount rate) or $139 million to
$245 million per year (costs and costs
savings calculated using a 3 percent
discount rate).
4. Distributional Impacts
(a) Energy Systems 385
The proposed rule has a number of
requirements that are expected to
influence the production of natural gas,
NGLs, and crude oil from onshore
Federal and Indian oil and gas leases.
If subpart OOOOa were not finalized,
we estimate the following incremental
changes in production, noting the
representative share of the total U.S.
production in 2014 for context. We
estimate additional natural gas
production ranging from 12–15 Bcf per
year (representing 0.04–0.06 percent of
the total U.S. production), the
productive use of an additional 29–41
Bcf of natural gas, which we estimate
would be used to generate 36–51
million gallons of NGL per year
(representing 0.08–0.11 percent of the
total U.S. production), and a reduction
in crude oil production ranging from
0.6–3.2 million bbl per year
(representing 0.02–0.10 percent of the
total U.S. production). Separate from the
volumes listed above, we also expect 1
Bcf of gas to be combusted on-site that
would have otherwise been vented.
Combined, the capture or combustion of
gas represents 49–52 percent of the
volume vented in 2013 and the capture
and/or productive use of gas represents
41–60 percent of the volume flared in
2013.386
If the EPA finalizes subpart OOOOa,
we estimate slightly less additional
natural gas production, ranging from
11.7–14.5 Bcf per year (representing
380 RIA
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0.04–0.05 percent of the total U.S.
production in 2014), and the same
amount of additional NGL production
and reduced crude oil production as
presented above. We also expect 0.5 Bcf
of gas to be combusted on-site that
would have otherwise been vented.
Combined, the capture or combustion of
gas represents 44–46 percent of the
volume vented in 2013 and the capture
and/or productive use of the gas 41–60
percent of the volume flared in 2013.387
Since the relative changes in
production are expected to be small, we
do not expect that the proposed rule
would significantly impact the price,
supply, or distribution of energy.
(b) Royalties 388
The rule is expected to increase
natural gas production from Federal and
Indian leases, and likewise, is expected
to increase annual royalties to the
Federal Government, tribal
governments, States, and private
landowners. For requirements that
would result in incremental gas
production, we calculate the additional
royalties based on that production.
When considering the deferment of
production that could result from the
rule’s flaring limit, we calculate the
incremental royalty as the difference in
the net present value of the royalty
received 1 year later (using 7 percent
and 3 percent discount rates) and the
value of the royalty received now.
If subpart OOOOa is not finalized, we
estimate that the rule would result in
additional royalties of $9–11 million per
year (discounted at 7 percent) or $11–
17 million per year (discounted at 3
percent). If the EPA finalizes subpart
OOOOa, we estimate additional
royalties of $9–11 million per year
(discounted at 7 percent) or $10–16
million per year (discounted at 3
percent).
Royalty payments are recurring
income to Federal or tribal governments
and costs to the operator or lessee. As
such, they are private transfer payments
that do not affect the total resources
available to society. An important but
sometimes difficult problem in cost
estimation is to distinguish between real
costs and transfer payments. While
transfers should not be included in the
economic analysis of the benefits and
costs of a regulation, they may be
important for describing distributional
effects.
(c) Small Businesses 389
387 RIA
381 RIA
at 140.
at 94–95.
389 The BLM conducted an Initial Regulatory
Flexibility Analysis, RIA at 154–166.
384 RIA
at 67.
385 RIA at 92–93.
386 RIA at 140.
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The BLM identified up to 1,828
entities that currently operate Federal
and Indian leases. The vast majority of
these entities are small business, as
defined by the SBA. We estimated a
range of potential per-entity costs, based
on different discount rates and
scenarios. Those per-entity compliance
costs are presented in RIA.
Recognizing that the SBA defines a
small business for oil and gas producers
as one with fewer than 500 employees,
a definition that encompasses many oil
and gas producers, the BLM looked at
company data for 26 different smallsized entities that currently hold BLMmanaged oil and gas leases. The BLM
ascertained the following information
from the companies’ annual reports to
the U.S. Securities and Exchange
Commission (SEC) for 2012 to 2014.
From data in the companies’ 10–K
filings to the SEC, the BLM was able to
calculate the companies’ profit
margins 390 for the years 2012, 2013 and
2014. We then calculated a profit
margin figure for each company when
subject to the average annual cost
increase associated with this rule. For
simplicity, we used the average perentity cost increase figures of $31,400
and $37,600 which roughly represent
the middle of the range of potential perentity costs assuming the EPA finalizes
and does not finalize subpart OOOOa,
respectively. Both figures include
compliance costs and cost savings,
calculated using a 7 percent discount
rate.
For these 26 small companies, a perentity compliance cost increase of
$31,400 would result in an average
reduction in profit margin of 0.087
percentage points (based on the 2014
company data) and a per entity cost
increase of $37,600 would result in an
average reduction in profit margin of
0.105 percentage points (also based on
the 2014 company data). The full detail
of this calculation is available in the
RIA.
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(d) Employment 391
Executive Order 13563 states, ‘‘Our
regulatory system must protect public
health, welfare, safety, and our
environment while promoting economic
growth, innovation, competitiveness,
and job creation.’’ 392 An analysis of
employment impacts is a standalone
analysis and the impacts should not be
390 The profit margin was calculated by dividing
the net income by the total revenue as reported in
the companies’ 10–K filings.
391 RIA at 148.
392 Executive Order 13563, Improving Regulation
and Regulatory Review (Jan. 18, 2011).
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included in the estimation of benefits
and costs.
The proposed rule is not expected to
materially impact the employment
within the oil and gas extraction,
drilling, and support industries. As
noted previously, the anticipated
additional gas production volumes
represent only a small fraction of the
U.S. natural gas production volumes.
Additionally, the annualized
compliance costs represent only a small
fraction of the annual net incomes of
companies likely to be impacted.
Therefore, we believe that the proposed
rule would not alter the investment or
employment decisions of firms or
significantly adversely impact
employment.
The proposed requirements would
require the one-time installation or
replacement of equipment and the
ongoing implementation of an LDAR
program, both of which would require
labor to comply.
(e) Impacts on Tribal Lands 393
This section presents the costs,
benefits, net benefits, and incremental
production associated with operations
on Indian leases, as well as royalty
implications for tribal governments.
If, as we expect, the EPA finalizes 40
CFR part 60 subpart OOOOa, we
estimate that the proposed rule would
pose costs ranging from $17–$23 million
per year (using a 7 percent discount
rate) or $16–18 million per year (using
a 3 percent discount rate).394
Projected benefits from the proposed
rule’s operation on Indian lands range
from $31–39 million per year (using a 7
percent discount rate to calculate the
present value of future annual cost
savings and using model averages of the
social cost of methane with a 3 percent
discount rate) or $31–43 million per
year (using a 3 percent discount rate to
calculate the present value of future
annual cost savings and using model
averages of the social cost of methane
with a 3 percent discount rate).395
Net benefits from operation of the rule
on leases on Indian lands range from
$11–20 million per year (using a 7
percent discount rate to calculate the
present value of future annual cost
savings and using model averages of the
social cost of methane with a 3 percent
discount rate) or range from $15–27
million per year (using a 3 percent
discount rate to calculate the present
value of future annual cost savings and
using model averages of the social cost
at 148–150.
at 148.
395 Ibid.
of methane with a 3 percent discount
rate).396
For impacts on production from
leases on Indian lands, the rule is
projected to result in additional natural
gas production ranging from 1.1–1.5 Bcf
per year; the productive use of an
additional 4.5–6.4 Bcf of natural gas,
which we estimate would be used to
generate 5.6–8.0 million gallons of NGL
per year; and a reduction in crude oil
production ranging from 0.1–0.5 million
bbl per year.397 We further estimate that
the proposed rule would reduce
methane emissions from leases on
Indian lands by 20,000 tpy, and would
reduce VOC emissions by 48,000–
51,000 tpy.398
We estimate additional royalties from
leases on Indian lands of $1.1–1.6
million per year (discounted at 7
percent) or $1.1–1.8 million per year
(discounted at 3 percent). See previous
explanation about how the royalty
estimates were derived.
If we assume for analytical purposes
that the EPA does not finalize 40 CFR
part 60 subpart OOOOa, we estimate
that the proposed rule would pose costs
ranging from $20–25 million per year
(using a 7 percent discount rate) or from
$18–21 million per year (using a 3
percent discount rate).
Projected benefits from the proposed
rule’s operation on Indian lands range
from $35–46 million per year (using a 7
percent discount rate to calculate the
present value of future annual cost
savings and using model averages of the
social cost of methane with a 3 percent
discount rate) or $35–50 million per
year (using a 3 percent discount rate to
calculate the present value of future
annual cost savings and using model
averages of the social cost of methane
with a 3 percent discount rate).
Net benefits from operation of the rule
on leases on Indian lands range from
$13–24 million per year (using a 7
percent discount rate to calculate the
present value of future annual cost
savings and using model averages of the
social cost of methane with a 3 percent
discount rate) or range from $17–31
million per year (using a 3 percent
discount rate to calculate the present
value of future annual cost savings and
using model averages of the social cost
of methane with a 3 percent discount
rate).
With respect to production from
leases on Indian lands, the rule is
projected to result in additional natural
gas production ranging from 1.6–2.1 Bcf
per year; the productive use of an
393 RIA
396 Ibid.
394 RIA
397 RIA
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additional 4.5–6.4 Bcf of natural gas,
which we estimate would be used to
generate 5.6–8.0 million gallons of NGL
per year; and a reduction in crude oil
production ranging from 0.1–0.5 million
bbl per year. We further estimate that
the proposed rule would reduce
methane emissions from leases on
Indian lands by 22,000–23,000 tpy, and
would reduce VOC emissions by
50,000–53,000 tpy.
We estimate additional royalties from
leases on Indian lands of $1.4–1.9
million per year (discounted at 7
percent) or $1.4–2.1 million per year
(discounted at 3 percent). See previous
explanation about how the royalty
estimates were derived.
VII. Procedural Matters
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A. Executive Order 12866, Regulatory
Planning and Review 399
Executive Order 12866 requires
agencies to assess the benefits and costs
of regulatory actions, and, for significant
regulatory actions, submit a detailed
report of their assessment to the OMB
for review. A rule is deemed significant
under Executive Order 12866 if it may:
(a) Have an annual effect on the
economy of $100 million or more or
adversely affect in a material way the
economy, a sector of the economy,
productivity, competition, jobs, the
environment, public health or safety, or
State, local, or tribal governments or
communities;
(b) Create a serious inconsistency or
otherwise interfere with an action taken
or planned by another agency;
(c) Materially alter the budgetary
impact of entitlements, grants, user fees,
or loan programs or the rights and
obligations of recipients thereof; or
(d) Raise novel legal or policy issues
arising out of legal mandates, the
President’s priorities, or the principles
set forth in the Executive Order.
The Office of Management and Budget
has determined that this proposed rule
is a significant regulatory action because
it may have an annual effect on the
economy of $100 million or more and
because it may raise novel legal or
policy issues arising out of legal
mandates and the President’s priorities.
This proposed rule would limit flaring
of associated gas from oil wells, and it
would require operators to take actions
to reduce gas losses through venting and
leaks.
399 RIA
at 167.
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B. Regulatory Flexibility Act and Small
Business Regulatory Enforcement
Fairness Act of 1996 400
The Regulatory Flexibility Act as
amended by the Small Business
Regulatory Enforcement Fairness Act
(SBREFA) generally requires an agency
to prepare a regulatory flexibility
analysis of any rule subject to notice
and comment rulemaking requirements
under the Administrative Procedure
Act, unless the head of the agency
certifies that the rule would not have a
significant economic impact on a
substantial number of small entities.401
Congress enacted the RFA to ensure that
government regulations do not
unnecessarily or disproportionately
burden small entities. Small entities
include small businesses, small
governmental jurisdictions, and small
not-for-profit enterprises.
The BLM reviewed the Small
Business Administration (SBA) size
standards for small businesses and the
number of entities fitting those size
standards as reported by the U.S.
Census Bureau in the Economic Census.
The BLM concludes that the vast
majority of entities operating in the
relevant sectors are small businesses as
defined by the SBA. As such, the rule
would likely affect a substantial number
of small entities. The BLM believes,
however, that the proposed rule would
not have a significant economic impact
on a substantial number of small
entities. The screening analysis
conducted by BLM estimates the
average reduction in profit margin for
small companies will be just a fraction
of one percentage point, which is not a
large enough impact to be considered
significant.
Although it is not required, the BLM
nevertheless has chosen to prepare an
initial regulatory flexibility analysis for
this proposed rule.402 There are several
factors driving this decision. First,
although the projected costs are
expected to be quite small, as a
percentage of a typical firm’s annual
profits, there is significant uncertainty
associated with these costs. There is a
combination of factors contributing to
the uncertainty associated with the costs
of this rule. These factors include
limited data, a wide range of possible
variation in commodity prices over
time, and a variety of possible
compliance options, particularly with
respect to the flaring requirements. In
addition, the BLM is taking comment on
a wide range of alternatives to some of
400 RIA
at 167–168.
U.S.C. 601–612. The exception is found in
5 U.S.C. 605(b).
402 See RIA, section 9.
401 5
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6673
the proposed requirements, and some of
these alternatives could affect the costs
of the rule if the BLM were to adopt
them in the final rule. This further
enhances the uncertainty regarding the
cost projections for the rule. Second,
there is no question that if the costs of
the rule for affected entities were
economically significant, the BLM
would be required to prepare an IRFA
for the rule, given that the rule will
affect a substantial number of small
entities.
Thus, given the unique circumstances
present in this rulemaking, the BLM
believes it is prudent, and potentially
helpful to small entities, to prepare an
IRFA at this stage in the rulemaking. We
do not believe this decision should be
viewed as a precedent for preparing an
IRFA in other rulemakings, and we may
choose not to prepare a final regulatory
flexibility analysis for the final rule, if
our best estimate at that time is that the
final rule would not have a significant
economic effect on a substantial number
of small entities.
C. Unfunded Mandates Reform Act of
1995
Under the Unfunded Mandates
Reform Act (UMRA), agencies must
prepare a written statement about
benefits and costs prior to issuing a
proposed rule that includes any Federal
mandate that is likely to result in
aggregate expenditure by State, local,
and tribal governments, or by the
private sector, of $100 million or more
in any 1 year, and prior to issuing any
final rule for which a proposed rule was
published.
This proposed rule does not contain
a Federal mandate that may result in
expenditures of $100 million or more by
State, local, and tribal governments, in
the aggregate, or by the private sector in
any 1 year. Thus, the proposed rule is
also not subject to the requirements of
Section 205 of UMRA.
This proposed rule is also not subject
to the requirements of Section 203 of
UMRA because it contains no regulatory
requirements that might significantly or
uniquely affect small governments. It
contains no requirements that apply to
such governments, nor does it impose
obligations upon them.
D. Executive Order 12630,
Governmental Actions and Interference
With Constitutionally Protected Property
Rights (Takings)
Under Executive Order 12630, the
proposed rule would not have
significant takings implications. A
takings implication assessment is not
required. The proposed rule would
establish a limited set of standards
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under which gas can be flared or vented,
and under which an operator can use oil
and gas on a lease, unit, or
communitized area for operations and
production purposes, without paying
royalty.
Oil and gas operators on BLMadministered leases are subject to lease
terms that expressly require that
subsequent lease activities be conducted
in compliance with applicable Federal
laws and regulations. The proposed rule
is consistent with the terms of those
Federal leases and is authorized by
applicable statutes. Thus, the proposed
rule is not a governmental action
capable of interfering with
constitutionally protected property
rights, it would not cause a taking of
private property, and it does not require
further discussion of takings
implications under this Executive
Order.
E. Executive Order 13132, Federalism
The proposed rule would not have a
substantial direct effect on the States,
the relationship between the national
government and the States, or the
distribution of power and
responsibilities among the levels of
government. It would not apply to
States or local governments or State or
local government entities. Therefore, in
accordance with Executive Order 13132,
the BLM has determined that this
proposed rule does not have sufficient
Federalism implications to warrant
preparation of a Federalism Assessment.
asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
F. Executive Order 12988, Civil Justice
Reform
This proposed rule would comply
with the requirements of Executive
Order 12988. Specifically, this
rulemaking: (a) Meets the criteria of
section 3(a) requiring that all regulations
be reviewed to eliminate errors and
ambiguity and be written to minimize
litigation; and (b) Meets the criteria of
section 3(b)(2) requiring that all
regulations be written in clear language
and contain clear legal standards.
G. Executive Order 13175, Consultation
and Coordination With Indian Tribal
Governments
In accordance with Executive Order
13175, the BLM has evaluated this
rulemaking and determined that it
would not have substantial direct effects
on federally recognized Indian tribes.
Nevertheless, on a government-togovernment basis we initiated
consultation with tribal governments
that the proposed rule may affect.
In 2014, the BLM conducted a series
of forums to consult with tribal
governments to inform the development
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of this proposal. We held tribal outreach
sessions in Denver, Colorado (March 19,
2014), Albuquerque, New Mexico (May
7, 2014), Dickinson, North Dakota (May
9, 2014), and Washington, DC (May 14,
2014).403 At the Denver and
Washington, DC sessions, the tribal
meetings were live-streamed to allow for
the greatest possible participation by
tribes and others. The tribal outreach
sessions served as initial consultation
with Indian tribes to comply with
Executive Order 13175. We look
forward to continuing close interaction
with tribal regulators as we proceed
through this rulemaking process.
H. Paperwork Reduction Act
1. Overview
The Paperwork Reduction Act
(PRA) 404 provides that an agency may
not conduct or sponsor, and a person is
not required to respond to, a ‘‘collection
of information,’’ unless it displays a
currently valid control number.
Collections of information include any
request or requirement that persons
obtain, maintain, retain, or report
information to an agency, or disclose
information to a third party or to the
public.405
This proposed rule contains
information collection requirements that
are subject to review by OMB under the
PRA. In accordance with the PRA, the
BLM is inviting public comment on
proposed new information collection
requirements for which the BLM is
requesting a new OMB control number.
As discussed below, some provisions
of the proposed rule would involve
some of the information collection
activities that OMB has approved under
Control Number 1004–0137, Onshore
Oil and Gas Operations (43 CFR part
3160) (expiration date January 31, 2018).
The information collection activities
in this proposed rule are described
below along with estimates of the
annual burdens. Included in the burden
estimates are the time for reviewing
instructions, searching existing data
sources, gathering and maintaining the
data needed, and completing and
reviewing each component of the
proposed information collection
requirements.
The information collection request for
this proposed rule has been submitted
to OMB for review in accordance with
the PRA. A copy of the request may be
obtained from the BLM by electronic
mail request to Tim Spisak at tspisak@
403 More info can be found at: https://
www.blm.gov/wo/st/en/prog/energy/public_events_
on_oil.html
404 44 U.S.C. 3501–3521.
405 44 U.S.C. 3502(3); 5 CFR 1320.3(c).
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blm.gov or by telephone request to 202–
912–7311. You may also review the
information collection request online at:
https://www.reginfo.gov/public/do/
PRAMain.
The BLM requests comments on the
following subjects:
• Whether the collection of
information is necessary for the proper
functioning of the BLM, including
whether the information will have
practical utility;
• The accuracy of the BLM’s estimate
of the burden of collecting the
information, including the validity of
the methodology and assumptions used;
• The quality, utility, and clarity of
the information to be collected; and
• How to minimize the information
collection burden on those who are to
respond, including the use of
appropriate automated, electronic,
mechanical, or other forms of
information technology.
If you want to comment on the
information collection requirements of
this proposed rule, please send your
comments directly to OMB, with a copy
to the BLM, as directed in the
ADDRESSES section of this preamble.
Please identify your comments with
‘‘OMB Control Number 1004–XXXX.’’
OMB is required to make a decision
concerning the collection of information
contained in this proposed rule between
30 to 60 days after publication of this
document in the Federal Register.
Therefore, a comment to OMB is best
assured of having its full effect if OMB
receives it by March 9, 2016.
2. Summary of Proposed Information
Collection Requirements
• Title: Waste Prevention, Production
Subject to Royalties, and Resource
Conservation (43 CFR parts 3160 and
3170).
• Forms: Form 3160–5, Sundry
Notices and Reports on Wells.
• OMB Control Number: This is a
new collection of information.
• Description of Respondents:
Holders of Federal and Indian (except
Osage Tribe) oil and gas leases, those
who belong to federally approved units
and CAs, and are parties to IMDA oil
and gas agreements.
• Respondents’ Obligation: Required
to obtain or retain a benefit.
• Frequency of Collection: On
occasion and monthly.
• Abstract: This proposed rule would
update standards to reduce wasteful
venting, flaring, and leaks of natural gas
from onshore wells located on Federal
and Indian oil and gas leases, units and
CAs.
• Estimated Total Annual Burden
Hours: 42,350 hours.
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• Estimated Total Non-Hour Cost:
None.
3. Proposals Involving APDs and
Sundry Notices
asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
(a) Plan to Minimize Waste of Natural
Gas (Form 3160–3) (43 CFR 3162.3–1(j))
This proposed rule would add a new
paragraph (j) to 43 CFR 3162.3–1 that
would require a plan to minimize waste
of natural gas when submitting an APD
for a development oil well. This
information would be in addition to the
APD information that the BLM already
collects under OMB Control Number
1004–0137. The required elements of
the waste minimization plan are listed
at paragraphs (j)(1) through (j)(7).
(b) Request for Prior Approval for
Royalty-Free Uses On-Lease or Off-Lease
(43 CFR 3178.5, 3178.7, and 3178.9)
Under proposed § 3178.5, submission
of a Sundry Notice (Form 3160–5)
would be required to request prior
written BLM approval for royalty-free
treatment of volumes used for the
following uses:
• Using oil as a circulating medium
in drilling operations;
• Injecting gas that an operator
produces from a lease, unit participating
area (PA), or communitized area (CA)
into the same lease, unit PA, or CA for
the purpose of increasing the recovery
of oil or gas (including gas that is cycled
in a contained gas-lift production
system), subject to an approval under 43
CFR 3162.3–2 to conduct the gas
injection;
• Using oil or gas that an operator
removes from the pipeline at a location
downstream of the facility measurement
point (FMP), if removal and use both
occur on the lease, unit, or CA;
• Using gas initially removed from a
lease, unit PA, or CA for treatment or
processing because of particular
physical characteristics of the gas,
where the gas is returned to the lease,
unit, or CA for lease operations; and
• Any other type of use of produced
oil or gas for operations and production
purposes pursuant to proposed § 3178.3
that is not identified in proposed
§ 3178.4.
Under proposed § 3178.7, submission
of a Sundry Notice (Form 3160–5)
would be required to request prior
written BLM approval for off-lease
royalty-free uses in the following
circumstances:
• The equipment or facility in which
the operation is conducted is located off
the lease, unit, or CA for engineering,
economic, resource-protection, or
physical-accessibility reasons; and
• The operations are conducted
upstream of the FMP.
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Under proposed § 3178.9, the
following information would be
required in a request for prior approval
of royalty-free use under § 3178.5, or for
prior approval of off-lease royalty-free
use under § 3178.7:
• A complete description of the
operation to be conducted, including
the location of all facilities and
equipment involved in the operation
and the location of the FMP;
• The method of measuring the
volume of oil, or measuring or
estimating the volume of gas, that the
operator expects will be used in the
operation, and the volume expected to
be used;
• If the volume expected to be used
will be estimated, the basis for the
estimate (e.g., equipment manufacturer’s
published consumption or usage rates);
and
• The proposed disposition of the oil
or gas used (e.g., whether gas used
would be consumed as fuel, vented
through use of a gas-activated
pneumatic controller, returned to the
reservoir, or some other disposition).
(c) Request for Approval of Alternative
Volume Limits (43 CFR 3179.7)
Proposed § 3179.7 would apply only
to leases issued before the effective date
of the final rule. It would provide that
an operator may seek BLM approval of
venting and flaring in excess of the
applicable limit under proposed
§ 3179.6. Using a Sundry Notice, the
operator would be required to show that
the applicable limit would impose such
costs as to cause the operator to cease
production and abandon significant
recoverable oil reserves under the lease.
To support this showing, the operator
would be required to submit the
following information:
• Information regarding the operator’s
wells under the lease that produce
Federal or Indian gas, including:
Æ The name, number, and location of
each well, and the number of the lease,
unit, or CA with which it is associated;
Æ The depths and names of producing
formations;
Æ The gas production level of each of
the operator’s wells for the most recent
production month for which
information is available; and
Æ The volumes of gas being vented
and flared from each of the operator’s
wells;
• Map(s) showing:
Æ The entire lease, unit, or CA and
the surrounding lands to a distance and
on a scale that shows the field in which
the well is or will be located (if
applicable), and all pipelines that could
transport the gas from the well;
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Æ All of the operator’s producing oil
and gas wells, which are producing
from Federal or Indian leases, (both on
Federal or Indian leases and on other
properties) within the map area;
Æ Identification of all of the operator’s
wells within the lease from which gas
is flared or vented, and the location and
distance of the nearest gas pipeline(s) to
each such well, with an identification of
those pipelines that are or could be
available for connection and use; and
Æ Identification of all of the operator’s
wells within the lease from which gas
is captured;
• Data that show pipeline capacity
and the operator’s projections of the cost
associated with installation and
operation of gas capture infrastructure
and alternative methods of
transportation that do not require
pipelines;
• The operator’s projections of gas
prices, gas production volumes, gas
quality (i.e., heating value and H2S
content), revenues derived from gas
production, and royalty payments on
gas production over the next 15 years or
the life of each of the operator’s leases,
units, or CAs, whichever is less; and
• The operator’s projections of oil
prices, oil production volumes, costs,
revenues, and royalty payments from
the operator’s oil and gas operations
within the lease over the lesser of the
next 15 years or the anticipated
remaining period in which the operator
will produce from the Federal or Indian
lease, unit, or CA.
(d) Certification in Support of
Exemption From Volume Limits (43
CFR 3179.7(d))
Proposed § 3179.7(d) would apply
only to leases issued before the effective
date of the final rule. It would authorize
an operator to provide a certification in
support of a renewable, 2-year
exemption from volume limits (instead
of an alternative limit requested under
proposed § 3179.7(b)). The certification
would consist of a Sundry Notice with
an affidavit verifying that all of the
following terms and conditions are met:
• The lease, unit, or CA is not
connected to a gas pipeline;
• The closest point on the lease, unit,
or CA is located more than 50 straightline miles from the nearest gas
processing plant; and
• In the most recent production
month, the lease, unit or CA flared or
vented at an average rate that exceeds by
at least 50 percent the applicable flaring
limit specified in § 3179.6.
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(e) Well Completion and Related
Operations (43 CFR 3179.102(b))
• Proposed § 3179.102(a) would
require gas that reaches the surface
during well completion and related
operations to be:
Æ Captured and sold;
Æ Directed to a flare pit or flare stack
equipped with an automatic igniter to
combust any flammable gasses, subject
to the volumetric limitations in
proposed § 3179.103(a)(3);
Æ Used in operations on the lease,
unit, or CA; or
Æ Injected.
• Paragraph (b) would authorize an
operator to demonstrate to the BLM on
a Sundry Notice that it is in compliance
with requirements for control of gas
from well completions established
under 40 CFR part 60, in lieu of
compliance with the requirements of
paragraph (a).
(f) Initial Production Testing Request for
Extension (43 CFR 3179.103)
• Proposed § 3179.103 would allow
gas to be flared royalty-free during a
well’s initial production testing until:
Æ The operator determines that it has
obtained adequate reservoir information
for the well;
Æ 30 days have passed since the
beginning of the production test;
Æ The operator has flared 20 million
MMcf of gas; or
Æ Production begins.
The BLM may extend the period for
royalty-free testing, but only if the
operator requests such an extension by
submitting a Sundry Notice.
asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
(g) Subsequent Well Tests Request for
Extension (43 CFR 3179.104)
Proposed § 3179.104 would limit
royalty-free flaring during production
tests after the initial production test to
24 hours, unless the BLM approves or
requires a longer test period. The
operator would be allowed to request for
longer test period by submitting a
Sundry Notice.
Reporting of Emergency Venting and
Flaring Beyond Specified Timeframes
(43 CFR 3179.105)
(h) Reporting of Emergency Venting or
Flaring Beyond Specified Timeframes
(43 CFR 3179.105)
Proposed § 3179.105 would allow an
operator to flare or vent gas royalty-free
during a temporary, short-term,
infrequent, and unavoidable emergency
for up to 24 hours per incident, and for
no more than 3 emergencies within any
30-day period. The operator would be
required to report on a Sundry Notice
any volumes of gas flared or vented
beyond those specified timeframes.
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(i) Pneumatic Controller Report (43 CFR
3179.201(b) and (c))
Proposed § 3179.201 addresses gas
losses from pneumatic controllers that
are not covered by EPA regulations at 40
CFR 60.5360 through 60.5390. The
proposed section would require
operators to replace pneumatic
controllers that have continuous bleed
rates that are greater than 6 scf/hour
with lower-bleed models within 1 year
after the effective date of the final rule.
Paragraph (b) would provide an
exception to this requirement if the
operator submits a Sundry Notice to the
BLM showing that:
• A pneumatic controller with a bleed
rate greater than 6 scf/hour is required
based on functional needs;
• The pneumatic controller exhaust is
routed to a flare device; or
• The replacement of a pneumatic
controller would impose such costs as
to cause the operator to cease
production and abandon significant
recoverable oil reserves under the lease.
Paragraph (c) would provide an
exception to the replacement
requirement if the operator submits a
Sundry Notice showing that a
pneumatic controller with a bleed rate
greater than 6 scf/hour serves a well or
facility has an estimated remaining
productive life of 3 years or less. The
operator would also be required to
replace the device no later than 3 years
from the effective date of the rule,
absent a showing that replacement
would impose costs as to cause the
operator to cease production and
abandon significant recoverable oil
reserves under the lease.
(j) Pneumatic Pump Report (43 CFR
3179.202)
Proposed § 3179.202 would require
operators to replace pneumatic pumps
not covered under EPA regulations with
zero-emissions pumps or route the
pump exhaust to a flare device within
1 year after the effective date of the final
rule. Paragraph (c) would provide an
exception to this requirement if the
operator makes a showing on a Sundry
Notice, and the BLM agrees, that:
• A pneumatic pump is required
based on functional needs, described in
the Sundry Notice, and there is no
existing flare device on site or routing
to such a device is technically
infeasible; or
• The installation of a zero-emissions
pump would impose such costs as to
cause the operator to cease production
and abandon significant recoverable oil
reserves under the lease and there is no
existing flare device on site or routing
to such a device is technically
infeasible.
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Paragraph (d) would provide an
exception to the replacement
requirement if the operator submits a
Sundry Notice showing that a
pneumatic pump serves a well or
facility that has an estimated remaining
productive life of 3 years or less. The
operator would also be required to
replace the device no later than 3 years
from the effective date of the rule,
absent a showing that replacement
would impose costs as to cause the
operator to cease production and
abandon significant recoverable oil
reserves under the lease.
(k) Crude Oil and Condensate Storage
Vessels (43 CFR 3179.203(c))
Proposed § 3179.203 would require
operators to route all tank vapor gas
from storage vessels and batteries to a
combustion device or continuous flare,
or to a sales line, unless the operator
submits an economic analysis in a
Sundry Notice and the BLM agrees with
that economic analysis. Paragraph (c)
would require that the operator
demonstrate in the Sundry Notice that
compliance would impose such costs as
to cause the operator to cease
production and abandon significant
recoverable oil reserves. Operators
would be required to submit this
information no later than 6 months after
the rule becomes effective.
(l) Downhole Well Maintenance and
Liquids Unloading—Documentation and
Reporting (43 CFR 3179.204(a) and (d))
Proposed § 3179.204 would pertain to
downhole well maintenance and liquids
unloading operations. Paragraph (a)
would require operators to use practices
that maximize the recovery of gas for
sale and to flare gas that is not
recovered. It would also require
operators to document, before purging a
well for the first time, a discovery that
compliance with these requirements
would be technically infeasible or
unduly costly. Paragraph (d) would
require that documentation to be
included as part of a Sundry Notice
submitted to the BLM within 10
calendar days after the first liquids
unloading event by well purging
conducted after the effective date of
proposed § 3179.204.
4. Other Proposed Information
Collection Activities
(a) Downhole Well Maintenance and
Liquids Unloading—Notice of Excessive
Duration or Volume (43 CFR
3179.204(e)
Proposed § 3179.204 would pertain to
downhole well maintenance and liquids
unloading operations. Paragraph (e)
would require an operator to notify the
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BLM in a Sundry Notice within 14 days
if the cumulative duration of well
purging events for a well exceeds 24
hours during any production month, or
if the estimated gas volume vented in
liquids unloading by well purging
operations for a well exceed 75 Mcf
during any production month.
(b) Leak Detection Inspection and
Repair
Proposed §§ 3179.301 through
3179.305 would include information
collection activities pertaining to the
detection and repair of gas leaks during
production operations. The following
activities would require operators to
submit a Sundry Notice:
• Proposed § 3179.301(e) would
allow an operator to satisfy the
requirements of proposed §§ 3179.301
through 3179.305 for some or all of the
equipment or facilities on a given lease
by demonstrating to the BLM on a
Sundry Notice that the operator is
complying with EPA requirements
established pursuant to 40 CFR part 60
with respect to such equipment or
facilities.
• Proposed § 3179.303(b) would
allow an operator to submit a Sundry
Notice requesting authorization to
detect gas leaks using an alternative
device, program, or method.
• Proposed § 3179.304(a) would
require an operator to repair any leak
not associated with normal equipment
operation no later than 15 calendar days
after discovery. In the event of a delay
beyond 15 calendar days, paragraph (b)
of this section would require the
operator to submit a Sundry Notice
showing good cause.
5. Burden Estimates
The following table details the
estimated annual burdens of activities
that would involve APDs and Sundry
Notices, the use of which has been
authorized under Control Number
1004–0137.
PROPOSALS INVOLVING APDS AND SUNDRY NOTICES ESTIMATED HOUR BURDENS
Type of response
Number of
responses
Hours per
response
Total Hours
(column B ×
column C)
A.
B.
C.
D.
Plan to Minimize Waste of Natural Gas, 43 CFR 3162.3–1, Form 3160–3 ...............................
Request for Prior Approval for Royalty-Free Uses On-Lease or Off-Lease, 43 CFR 3178.5,
3178.7, and 3178.9, Form 3160–5 ..........................................................................................
Request for Approval of Alternative Volume Limits, 43 CFR 3179.7(b), Form 3160–5 .............
Certification in Support of Exemption from Volume Limits, 43 CFR 3179.7(d), Form 3160–5 ..
Well Completion and Related Operations, 43 CFR 3179.102(b), Form 3160–5 ........................
Initial Production Testing Request for Extension, 43 CFR 3179.103, Form 3160–5 .................
Subsequent Well Tests Request for Extension, 43 CFR 3179.104, Form 3160–5 ....................
Reporting of Emergency Venting and Flaring Beyond Specified Timeframes, 43 CFR
3179.105, Form 3160–5 ...........................................................................................................
Pneumatic Controller Report, 43 CFR 3179.201(b) and (c), Form 3160–5 ...............................
Pneumatic Pump Report, 43 CFR 3179.202, Form 3160–5 .......................................................
Crude Oil and Condensate Storage Vessels, 43 CFR 3179.203(c), Form 3160–5 ...................
Downhole Well Maintenance and Liquids Unloading—Documentation and Reporting, 43 CFR
3179.204(a) and (d), Form 3160–5 .........................................................................................
Downhole Well Maintenance and Liquids Unloading—Notification of Excessive Duration or
Volume, 43 CFR 3179.204(e) ..................................................................................................
Form 3160–5 ...............................................................................................................................
Leak Detection—Compliance with EPA Regulations, 43 CFR 3179.301(e), Form 3160–5 .......
Leak Detection—Request to Use and Alternative Device, Program, or Method, 43 CFR
3179.303(b), Form 3160–5 ......................................................................................................
Leak Detection—Notification of Delay in Repairing Leaks, 43 CFR 3179.304(a), Form 3160–5
2,000
The following table details the annual
estimated hour burdens for the rest of
4,000
50
185
15
5
5
5
8
16
16
2
2
2
400
2,960
240
10
10
10
25
200
250
100
2
2
8
8
50
400
2,000
800
5,000
1
5,000
120
500
1
8
120
4,000
200
100
40
1
8,000
100
8,760
Totals ....................................................................................................................................
2
........................
28,100
the proposed information collection
activities in this rule.
ESTIMATED ANNUAL HOUR BURDENS FOR OTHER IC ACTIVITIES
Number of
responses
Hours per
response
Total Hours
(column B ×
column C)
A.
asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Type of response
B.
C.
D.
Downhole Well Maintenance and Liquids Unloading—Recordkeeping, 43 CFR 3179.204(c) ...
Leak Detection—Inspection Recordkeeping, 43 CFR 3179.305 ................................................
5,000
52,000
0.25
.25
1,250
13,000
Totals ....................................................................................................................................
57,000
........................
14,250
I. National Environmental Policy Act
The BLM has prepared a draft
environmental assessment (EA) to
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determine whether issuance of this
proposed regulation pertaining to oil
and gas waste prevention and royalty
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clarification would constitute a ‘‘major
Federal action significantly affecting the
quality of the human environment’’
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asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
under section 102(2)(C) of the National
Environmental Policy Act (NEPA).406
The BLM believes that, for the most
part, the proposed rule would benefit
the environment by reducing emissions
of methane (a potent GHG), VOCs
(which contribute to smog), and
hazardous air pollutants such as
benzene (a known carcinogen). In
addition, the proposed rule would
reduce light pollution and other impacts
from flaring. The rule may also have
indirect and minor to negligible adverse
environmental impacts, primarily due to
land disturbance from increased or
accelerated construction of gas pipelines
and compressors and/or increased truck
traffic on existing disturbed surfaces
from the increased use of mobile
capture technology. In the aggregate, the
beneficial impacts of the proposed rule
are expected to dwarf its adverse
impacts. Further, the BLM anticipates
that any new gathering lines would be
subject to additional environmental
review based on submission of a Sundry
Notice or a FLPMA Title V right-of-way
application prior to construction.
During the public comment period for
the proposed rule, we will consider any
new information we receive that may
inform our analysis of the potential
environmental impacts of the rule. A
copy of the draft EA can be viewed at
www.regulations.gov (use the search
term 1004–AE14, open the Docket
Folder, and look under Supporting
Documents) and at the address specified
in the ADDRESSES section.
J. Executive Order 13211, Actions
Concerning Regulations That
Significantly Affect Energy Supply,
Distribution, or Use
Under Executive Order 13211,
agencies are required to prepare and
submit to OMB a Statement of Energy
Effects for significant energy actions.
This statement is to include a detailed
statement of ‘‘any adverse effects on
energy supply, distribution, or use
(including a shortfall in supply, price
increases, and increase use of foreign
supplies)’’ for the action and reasonable
alternatives and their effects.
Section 4(b) of Executive Order 13211
defines a ‘‘significant energy action’’ as
‘‘any action by an agency (normally
published in the Federal Register) that
promulgates or is expected to lead to the
promulgation of a final rule or
regulation, including notices of inquiry,
advance notices of proposed
rulemaking, and notices of proposed
rulemaking: (1)(i) that is a significant
regulatory action under Executive Order
12866 or any successor order, and (ii) is
406 42
U.S.C. 4332(2)(C).
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likely to have a significant adverse effect
on the supply, distribution, or use of
energy; or (2) that is designated by the
Administrator of (OIRA) as a significant
energy action.’’
Since the compliance costs for this
rule would represent such a small
fraction of company net incomes, we
believe that the rule is unlikely to
impact the investment decisions of
firms. Also, any incremental production
of gas estimated to result from the rule’s
enactment would constitute a small
fraction of total U.S. production, and
any potential and temporary deferred
production of oil would likewise
constitute a small fraction of total U.S.
production. For these reasons, we do
not expect that the proposed rule would
significantly impact the supply,
distribution, or use of energy. As such,
the rulemaking is not a ‘‘significant
energy action’’ as defined in Executive
Order 13211.
reduce burdens and maintain flexibility
and freedom of choice for the public
where these approaches are relevant,
feasible, and consistent with regulatory
objectives. E.O. 13563 emphasizes
further that regulations must be based
on the best available science and that
the rulemaking process must allow for
public participation and an open
exchange of ideas. We have developed
this proposed rule in a manner
consistent with these requirements.
K. Clarity of the Regulations
Executive Order 12866 requires each
agency to write regulations that are
simple and easy to understand. We
invite your comments on how to make
these proposed regulations easier to
understand, including answers to
questions such as the following:
• Are the requirements in the
proposed regulations clearly stated?
• Do the proposed regulations contain
technical language or jargon that
interferes with their clarity?
• Does the format of the proposed
regulations (grouping and order of
sections, use of headings, paragraphing,
etc.) aid or reduce their clarity?
• Would the regulations be easier to
understand if they were divided into
more (but shorter) sections?
• Is the description of the proposed
regulations in the SUPPLEMENTARY
INFORMATION section of this preamble
helpful in understanding the proposed
regulations? How could this description
be more helpful in making the proposed
regulations easier to understand?
Please send any comments you have
on the clarity of the regulations to the
address specified in the ADDRESSES
section.
43 CFR Part 3100
L. Executive Order 13563, Improving
Regulation and Regulatory Review
Executive Order 13563 reaffirms the
principles of E.O. 12866 while calling
for improvements in the nation’s
regulatory system to promote
predictability, to reduce uncertainty,
and to use the best, most innovative,
and least burdensome tools for
achieving regulatory ends. The
executive order directs agencies to
consider regulatory approaches that
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VIII. Authors
The principal authors of this rule are:
Timothy Spisak and James Tichenor of
the BLM Washington Office; Eric Jones
of the BLM Moab, Utah Field Office;
and David Mankiewicz of the BLM
Farmington, New Mexico Field Office;
assisted by Faith Bremner of the staff of
the BLM’s Regulatory Affairs Division.
List of Subjects
Government contracts, Mineral
royalties, Oil and gas reserves, Public
lands-mineral resources, Reporting and
recordkeeping requirements, Surety
bonds.
43 CFR Part 3160
Administrative practice and
procedure, Government contracts,
Indians-lands, Mineral royalties, Oil and
gas exploration, Penalties, Public
lands—mineral resources, Reporting
and recordkeeping requirements.
43 CFR Part 3170
Administrative practice and
procedure, Flaring, Government
contracts, Incorporation by reference,
Indians-lands, Mineral royalties,
Immediate assessments, Oil and gas
exploration, Oil and gas measurement,
Public lands—mineral resources,
Reporting and recordkeeping
requirements, Royalty-free use, Venting.
Dated: January 21, 2016.
Janice M. Schneider,
Assistant Secretary, Land and Minerals
Management.
For the reasons set out in the
preamble, the Bureau of Land
Management proposes to amend 43 CFR
parts 3100 and 3160 and add new
subparts 3178 and 3179 to new 43 CFR
part 3170 as follows:
PART 3100—ONSHORE OIL AND GAS
LEASING
1. Revise the authority citation for part
3100 to read as follows:
■
Authority: 25 U.S.C. 396d and 2107; 30
U.S.C. 189, 306, 359 and 1751; 43 U.S.C.
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1732(b), 1733, and 1740; and the Energy
Policy Act of 2005 (Pub. L. 109–58).
2. Revise § 3103.3–1 to read as
follows:
■
§ 3103.3–1
Royalty on production.
(a) Royalty on production will be
payable only on the mineral interest
owned by the United States. Royalty
must be paid in amount or value of the
production removed or sold as follows:
(1) For leases issued on or before
[EFFECTIVE DATE OF THE FINAL
RULE], the rate prescribed in the lease
or in applicable regulations at the time
of lease issuance;
(2) For leases issued after [EFFECTIVE
DATE OF THE FINAL RULE]:
(i) 121⁄2 percent on all noncompetitive
leases; and
(ii) A base rate of not less than 121⁄2
percent on all competitive leases,
exchange and renewal leases, and leases
issued in lieu of unpatented oil placer
mining claims under § 3108.2–4;
(3) 16 2⁄3 percent on noncompetitive
leases reinstated under § 3108.2–3 plus
an additional 2 percentage-point
increase added for each succeeding
reinstatement; and
(4) The rate used for royalty
determination that appears in a lease
that is reinstated or that is in force for
competitive leases at the time of
issuance of the lease that is reinstated,
plus 4 percentage points, plus an
additional 2 percentage points for each
succeeding reinstatement.
(b) Leases that qualify under specific
provisions of the Act of August 8, 1946
(30 U.S.C. 226(c) may apply for a
limitation of a 121⁄2 percent royalty rate.
(c) The average production per well
per day for oil and gas will be
determined pursuant to 43 CFR 3162.7–
4.
(d) Payment of a royalty on the
helium component of gas will not
convey the right to extract the helium.
Applications for the right to extract
helium shall be made under 43 CFR part
16.
PART 3160—ONSHORE OIL AND GAS
OPERATIONS
3. The authority citation for part 3160
continues to read as follows:
asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
■
Authority: 25 U.S.C. 396d and 2107; 30
U.S.C. 189, 306, 359, and 1751; and 43 U.S.C.
1732(b), 1733, and 1740.
§ 3160.0–5
[Amended]
4. Amend § 3160.0–5 by removing the
definition of ‘‘Avoidably lost.’’
■ 5. Amend § 3162.3–1 by adding
paragraph (j) to read as follows:
■
§ 3162.3–1
Drilling applications and plans.
*
*
*
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(j) When submitting an Application
for Permit to Drill an oil well, the
operator must also submit a plan to
minimize waste of natural gas from that
well. The waste minimization plan must
accompany, but would not be part of,
the Application for Permit to Drill. The
waste minimization plan must set forth
a strategy for how the operator will
comply with the requirements of 43 CFR
subpart 3179 regarding control of waste
from venting, flaring and leaks, and
must explain how the operator plans to
capture associated gas upon the start of
oil production, or as soon thereafter as
reasonably possible. Failure to submit a
complete and adequate waste
minimization plan is grounds for
denying or disapproving an Application
for Permit to Drill. The waste
minimization plan must include the
following information:
(1) The anticipated completion date of
the proposed well(s);
(2) The anticipated gas production
rates of the proposed well(s);
(3) A gas pipeline system location
map of sufficient detail, size, and scale
as to show the field in which the
proposed well will be located, and all
existing gas pipelines within 20 miles of
the well. The map should also contain:
(i) The name and location of the gas
processing plant(s) closest to the
proposed well(s), and of the intended
destination processing plant, if
different;
(ii) The location and name of the
operator of each gas pipeline within 20
miles of the proposed well;
(iii) The proposed route and tie-in
point that connects or could connect the
subject well to an existing gas pipeline;
(4) Information on the gas pipeline to
which the operator plans to connect,
including:
(i) Maximum current daily capacity of
the pipeline;
(ii) Current throughput of the
pipeline;
(iii) Anticipated daily capacity of the
pipeline at the anticipated date of first
gas sales from the proposed well;
(iv) Anticipated throughput of the
pipeline at the anticipated date of first
gas sales from the proposed well;
(v) Certification that the operator has
provided one or more midstream
processing companies with information
about the operator’s production plans,
including the anticipated completion
dates and gas production rates of the
proposed well or wells; and
(vi) Any plans known to the operator
for expansion of pipeline capacity for
the area that includes the proposed
well.
(5) A description of anticipated
production, including:
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6679
(i) The anticipated date of first
production;
(ii) The expected oil and gas
production rates and duration from the
proposed well. If the proposed well is
on a multi-well pad, the plan should
include the total expected production
for all wells being completed;
(iii) The expected production decline
curve of both oil and gas from the
proposed well; and
(iv) The expected Btu value for gas
production from the proposed well.
(6) The volume and percentage of
produced gas the operator is currently
flaring or venting from wells in the same
field and any wells within a 20-mile
radius of that field; and
(7) An evaluation of opportunities for
alternative on-site capture approaches,
if pipeline transport is unavailable.
PART 3170—ONSHORE OIL AND GAS
PRODUCTION
6. The authority citation for part 3170,
which was proposed to be added on July
13, 2015 (80 FR 40768), continues to
read as follows:
■
Authority: 25 U.S.C. 396d and 2107; 30
U.S.C. 189, 306, 359, and 1751; and 43 U.S.C.
1732(b), 1733, and 1740.
7. Add subparts 3178 and 3179 to part
3170, which was proposed to be added
on July 13, 2015 (80 FR 40768), to read
as follows:
■
Subpart 3178—Royalty-Free Use of Lease
Production
Sec.
3178.1 Purpose.
3178.2 Scope.
3178.3 Production on which a royalty is
not due.
3178.4 Uses of oil or gas on lease, unit, or
CA that do not require prior written BLM
approval for royalty-free treatment of
volumes used.
3178.5 Uses of oil or gas on a lease, unit,
or CA that require prior written BLM
approval for royalty-free treatment of
volumes used.
3178.6 Uses of oil or gas moved off the
lease, unit, or CA that do not require
prior written approval for royalty-free
treatment of volumes used.
3178.7 Uses of oil or gas moved off the
lease, unit, or CA that require prior
written approval for royalty-free
treatment of volumes used.
3178.8 Measurement or estimation of
royalty-free volumes.
3178.9 Requesting approval of royalty-free
treatment when approval is required.
3178.10 Facility and equipment
ownership.
Subpart 3179—Waste Prevention and
Resource Conservation
Sec.
3179.1 Purpose.
3179.2 Scope.
3179.3 Definitions and acronyms.
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3179.4 Determining when the loss of oil or
gas is avoidable or unavoidable.
3179.5 When lost production is subject to
royalty.
3179.6 When flaring or venting is
prohibited.
3179.7 Alternative limits on venting and
flaring.
3179.8 Measuring and reporting volumes of
gas vented and flared from wells.
3179.9 Determinations regarding royaltyfree venting or flaring.
3179.10 Other waste-prevention measures.
3179.11 Coordination with State regulatory
authority.
Flaring and Venting Gas During Drilling and
Production Operations
3179.101 Well drilling.
3179.102 Well completion and related
operations.
3179.103 Initial production testing.
3179.104 Subsequent well tests.
3179.105 Emergencies.
Gas Flared or Vented From Equipment
During Well Maintenance Operations
3179.201 Equipment requirements for
pneumatic controllers.
3179.202 Requirements for pneumatic
chemical injection pumps or pneumatic
diaphragm pumps.
3179.203 Crude oil and condensate storage
vessels.
3179.204 Downhole well maintenance and
liquids unloading.
Leak Detection and Repair (LDAR)
3179.301 Operator responsibility.
3179.302 Approved instruments and
methods.
3179.303 Leak detection and inspection
requirements for natural gas wellhead
equipment, facilities, and compressors.
3179.304 Repairing leaks.
3179.305 Leak detection inspection
recordkeeping.
State or Tribal Variances
3179.401 State or tribal requests for
variances from the requirements of this
subpart.
asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
§ 3178.1
Purpose.
The purpose of this subpart is to
address the circumstances under which
oil or gas produced from Federal and
Indian leases may be used royalty-free
in operations on the lease, unit, or
communitized area (CA). This subpart
supersedes those portions of Notice to
Lessees and Operators of Onshore
Federal and Indian Oil and Gas Leases
(NTL–4A), 44 FR 76600 (December 27,
1979), pertaining to oil or gas used for
beneficial purposes.
§ 3178.2
Scope.
(a) This subpart applies to:
(1) All onshore Federal and Indian
(other than Osage Tribe) oil and gas
leases, units, and CAs, except as
otherwise provided in this subpart;
(2) Indian Mineral Development Act
(IMDA) oil and gas agreements, unless
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specifically excluded in the agreement
or unless the relevant provisions of this
subpart are inconsistent with the
agreement;
(3) Leases and other business
agreements and contracts for the
development of tribal energy resources
under a Tribal Energy Resource
Agreement entered into with the
Secretary, unless specifically excluded
in the lease, other business agreement,
or Tribal Energy Resource Agreement;
(4) Committed State or private tracts
in a federally approved unit or
communitization agreement defined by
or established under 43 CFR subpart
3105 or 43 CFR part 3180;
(5) All onshore wells, tanks,
compressors, and other facilities located
on a Federal or Indian lease or a
federally approved unit or CA; and
(6) All gas lines located on a Federal
or Indian lease or federally approved
unit or CA that are owned or operated
by the operator of the lease, unit, or
communitization agreement.
(b) For purposes of this subpart, the
term ‘‘lease’’ also includes IMDA
agreements.
§ 3178.3 Production on which royalty is
not due.
(a) To the extent specified in
§§ 3178.4 and 3178.5, royalty is not due
on:
(1) Oil or gas that is produced from a
lease or CA and used for operations and
production purposes (including placing
oil or gas in marketable condition) on
the same lease or CA without being
removed from the lease or CA; or
(2) Oil or gas that is produced from a
unit PA and used for operations and
production purposes (including placing
oil or gas in marketable condition) on
the unit, for the same unit PA, without
being removed from the unit.
(a) For the uses described in § 3178.5,
the operator must obtain prior written
BLM approval for the volumes used for
operational and production purposes to
be royalty free.
§ 3178.4 Uses of oil or gas on a lease, unit,
or CA that do not require prior written BLM
approval for royalty-free treatment of
volumes used.
(a) Uses of produced oil or gas for
operations and production purposes
that do not require prior written BLM
approval for the used volumes to be
treated as royalty free under § 3178.3
are:
(1) Use of fuel to power artificial lift
equipment;
(2) Use of fuel to power equipment
used for enhanced recovery;
(3) Use of fuel to power drilling rigs;
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(4) Use of gas to actuate pneumatic
controllers or operate pneumatic pumps
at production facilities;
(5) Use of fuel to heat, separate, or
dehydrate production;
(6) Use of fuel to compress gas to
place it in marketable condition; and
(7) Use of oil that an operator
produces from a lease, unit, or CA and
pumps into a well on the same lease,
unit, or CA to clean the well and
improve production, e.g., hot oil
treatment. The operator must document
the removal of the oil from the tank or
pipeline under Onshore Oil and Gas
Order No. 3 (Site Security), or any
successor regulation.
(b) The volume to be treated as royalty
free must not exceed the amount of fuel
reasonably necessary to perform the
operational function, using equipment
of appropriate capacity.
§ 3178.5 Uses of oil or gas on a lease, unit,
or CA that require prior written BLM
approval for royalty-free treatment of
volumes used.
(a) Uses that require prior written
approval from the BLM before the
production used may be treated as
royalty free under § 3178.3 include: (1)
Using oil as a circulating medium in
drilling operations;
(2) Injecting gas that an operator
produces from a lease, unit PA, or CA
into the same lease, unit PA, or CA for
the purpose of increasing the recovery
of oil or gas (including gas that is cycled
in a contained gas-lift production
system), subject to an approval under
3162.3–2 of this title to conduct the gas
injection;
(3) Using oil or gas that an operator
removes from the pipeline at a location
downstream of the Facility
Measurement Point (FMP), if removal
and use both occur on the lease, unit, or
CA;
(4) Using gas initially removed from a
lease, unit PA, or CA for treatment or
processing because of particular
physical characteristics of the gas,
where the gas is returned to the lease,
unit, or CA for lease operations; and
(5) Any other type of use of produced
oil or gas for operations and production
purposes pursuant to § 3178.3 that is not
identified in § 3178.4.
(b) (1) The operator must obtain BLM
approval to conduct activities under
paragraph (a) of this section by
submitting a Form 3160–5, Sundry
Notices and Reports on Wells (Sundry
Notice) containing the information
required under § 3178.9.
(2) With respect to uses under
paragraph (a)(3) of this section, the
operator must measure the volume of oil
or gas used in accordance with Onshore
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Oil and Gas Orders No. 4 (oil) and 5
(gas) as applicable, or other successor
regulations.
(3) With respect to uses under
paragraph (a)(4) of this section, the
operator must measure any gas returned
to the lease, unit, or CA under such an
approval in accordance with Onshore
Oil and Gas Order No. 5 or other
successor regulations.
(c) If the BLM disapproves a request
for royalty-free treatment for volumes
used under this section, the operator
must pay royalties for the gas used
beginning on the date the operator was
required to request approval under
paragraph (a) of this section.
§ 3178.6 Uses of oil or gas moved off the
lease, unit, or CA that do not require prior
written approval for royalty-free treatment
of volumes used.
Oil or gas used after being moved off
the lease, unit, or CA may be treated as
royalty free without prior written BLM
approval only if the use meets the
criteria under § 3178.4 and when:
(a) Oil or gas is piped along a logical
route, based on existing access,
topography, land ownership or other
similar characteristic, directly from one
area of the lease, unit, or CA to another
area of the same lease, unit, or CA
where it is used without oil or gas being
added to or removed from the pipeline
while crossing lands that are not part of
the lease, unit, or CA; or
(b) A well is directionally drilled and
the wellhead is not located on the
producing lease, unit, or CA, and oil or
gas is used on the same well pad for
operations and production purposes for
that well.
asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
§ 3178.7 Uses of oil or gas moved off the
lease, unit, or CA that require prior written
approval for royalty-free treatment of
volumes used.
(a) Except as provided in § 3178.6(b)
and paragraph (b) of this section, royalty
is owed on all oil or gas used in
operations conducted off the lease, unit,
or CA.
(b) The BLM may grant prior written
approval to treat oil or gas used in
operations conducted off the lease, unit,
or CA as royalty free (referred to as offlease royalty-free use) if the use meets
one or more of the criteria listed in
§ 3178.5(a) and if:
(1) The equipment or facility in which
the operation is conducted is located off
the lease, unit, or CA for engineering,
economic, resource-protection, or
physical-accessibility reasons; and
(2) The operations are conducted
upstream of the FMP.
(c) The operator must obtain BLM
approval under paragraph (b) of this
section by submitting a Sundry Notice
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containing the information required
under § 3178.9.
(d) Approval of measurement or
commingling off the lease, unit, or CA
under other regulations does not
constitute approval of off-lease royaltyfree use. The operator or lessee must
expressly request, and submit its
justification for, approval of off-lease
royalty-free use.
(e) If equipment or a facility located
on a particular lease, unit, or CA treats
oil or gas produced from properties that
are not unitized or communitized with
the property on which the equipment or
facility is located, in addition to treating
oil or gas produced from the lease, unit,
or CA on which the equipment or
facility is located, the operator may
report as royalty free only that portion
of the oil or gas used as fuel that is
properly allocable to the share of
production contributed by the lease,
unit, or CA on which the equipment is
located, unless otherwise authorized by
the BLM under this section.
§ 3178.8 Measurement or estimation of
royalty-free volumes.
(a) The operator must measure or
estimate the volumes of royalty-free gas
used in operations upstream of the FMP.
(b) The operator must measure all gas
that is removed from the product stream
downstream of the FMP and used in
operations on the lease, unit, or CA (or
off the lease, unit, or CA if the BLM
approves such use), using the
measurement procedures in Onshore Oil
and Gas Order No. 5 or other successor
regulation.
(c) The operator must measure the
volume of oil used in operations on the
lease, unit, or CA (or off the lease, unit,
or CA if the BLM approves such use)
using the measurement procedures in
Onshore Oil and Gas Order No. 4 or
other successor regulation. The operator
must also document removal of such oil
from the tank or pipeline.
(d) Each of the volumes required to be
measured or estimated, as applicable,
under this subpart, must be reported by
the operator following applicable ONRR
reporting requirements.
§ 3178.9 Requesting approval of royaltyfree treatment when approval is required.
To request written approval of
royalty-free use when required under
§ 3178.5, or of off-lease royalty-free use
under § 3178.7, the operator must
submit a Sundry Notice that includes
the following information:
(a) A complete description of the
operation to be conducted, including
the location of all facilities and
equipment involved in the operation
and the location of the FMP;
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(b) The volume of oil or gas that the
operator expects will be used in the
operation, and the method of measuring
or estimating that volume;
(c) If the volume of gas expected to be
used will be estimated, the basis for the
estimate (e.g., equipment manufacturer’s
published consumption or usage rates);
and
(d) The proposed disposition of the
oil or gas used (e.g., whether gas used
would be consumed as fuel, vented
through use of a gas-activated
pneumatic controller, returned to the
reservoir, or some other disposition).
§ 3178.10 Facility and equipment
ownership.
The operator is not required to own or
lease the equipment or facility that uses
oil or gas royalty free. The operator is
responsible for obtaining all
authorizations, measuring production,
reporting production, and all other
applicable requirements.
Subpart 3179—Waste Prevention and
Resource Conservation
§ 3179.1
Purpose.
The purpose of this subpart is to
implement and carry out the purposes
of statutes relating to prevention of
waste from Federal and Indian (other
than Osage Tribe) leases, conservation
of surface resources, and management of
the public lands for multiple use and
sustained yield. This subpart supersedes
those portions of Notice to Lessees and
Operators of Onshore Federal and
Indian Oil and Gas Leases (NTL–4A), 44
FR 76600 (December 27, 1979),
pertaining to, among other things,
flaring and venting of produced gas,
unavoidably and avoidably lost gas, and
waste prevention.
§ 3179.2
Scope.
(a) This subpart applies to:
(1) All onshore Federal and Indian
(other than Osage Tribe) oil and gas
leases, units, and CAs, except as
otherwise provided in this subpart;
(2) IMDA oil and gas agreements,
unless specifically excluded in the
agreement or unless the relevant
provisions of this subpart are
inconsistent with the agreement;
(3) Leases and other business
agreements and contracts for the
development of tribal energy resources
under a Tribal Energy Resource
Agreement entered into with the
Secretary, unless specifically excluded
in the lease, other business agreement,
or Tribal Energy Resource Agreement;
(4) Committed State or private tracts
in a federally approved unit or
communitization agreement defined by
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or established under 43 CFR subpart
3105 or 43 CFR part 3180;
(5) All onshore wells, tanks,
compressors, and other facilities located
on a Federal or Indian lease or a
federally approved unit or CA; and
(6) All gas lines located on a Federal
or Indian lease or federally approved
unit or CA that are owned or operated
by the operator of the lease, unit, or
communitization agreement.
(b) For purposes of this subpart, the
term ‘‘lease’’ also includes IMDA
agreements.
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§ 3179.3
Definitions and acronyms.
As used in this subpart, the term:
Accessible component means a
component that can be reached, if
necessary, by safe and proper use of
portable ladders or by built-in ladders
and walkways. Accessible components
also include components that can be
reached by the safe use of an extension
on a monitoring probe.
Capture means the physical
containment of natural gas for
transportation to market or productive
use of natural gas, and includes
reinjection and royalty-free on-site uses
pursuant to subpart 3178.
Capture infrastructure means any
pipelines, facilities, or other equipment
(including temporary or mobile
equipment) used to capture, transport,
or process gas. Capture infrastructure
includes, but is not limited to,
equipment that compresses or liquefies
natural gas, removes natural gas liquids,
or generates electricity from gas.
Component means any piece of
equipment that has the potential to leak
gas and can be tested in the manner
described in §§ 3179.301 through
3179.305 of this subpart.
Development oil well or development
gas well means a well drilled to produce
oil or gas, respectively, from an
established field in which hydrocarbons
have been discovered and are being
produced at a profit or expected profit.
For purposes of this subpart, the BLM
will determine when a well is a
development oil well or development
gas well in the event of a disagreement
between the BLM and the operator.
Gas-to-oil ratio (GOR) means the ratio
of gas to oil in the production stream
expressed in standard cubic feet of gas
per barrel of oil.
Gas well means a well for which the
energy equivalent of the gas produced,
including its entrained liquefiable
hydrocarbons, exceeds the energy
equivalent of the oil produced. Unless
more specific British thermal unit (Btu)
values are available, a well with a gasto-oil ratio greater than 6 thousand
cubic feet (Mcf) of gas per barrel of oil
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is a gas well. Except where gas has been
re-injected into the reservoir, a mature
oil well would not be reclassified as a
gas well even after normal production
decline has caused the GOR to increase
beyond 6 Mcf of gas per barrel of oil.
Liquid hydrocarbon means chemical
compounds of hydrogen and carbon
atoms that exist as a liquid under the
temperature and pressure at which they
are measured. The term is used to refer
to oil, condensate, liquefied petroleum
gas (LPG), liquefied natural gas (LNG),
and natural gas liquids (NGL).
Liquids unloading means the removal
of an accumulation of liquid
hydrocarbons or water in the wellbore
of a completed gas well.
Lost oil or lost gas means produced oil
or gas that escapes containment, either
intentionally or unintentionally, or is
flared before being removed from the
lease, unit, or CA, and cannot be
recovered.
Storage vessel means a crude oil or
condensate storage tank or battery of
tanks that vents, or is designed to vent,
to the atmosphere during normal
operations.
Volatile organic compounds (VOC)
has the same meaning as defined in 40
CFR 51.100(s).
§ 3179.4 Determining when the loss of oil
or gas is avoidable or unavoidable.
For purposes of this subpart:
(a) ‘‘Unavoidably lost’’ oil or gas
means lost oil or gas where the operator
has not been negligent, and has
complied fully with applicable laws,
lease terms, regulations, provisions of a
previously approved operating plan, or
other written orders of the BLM,
including:
(1) Produced oil or gas that is lost
from the following operations or sources
and cannot be recovered in the normal
course of operations, where the operator
has taken prudent and reasonable steps
to avoid waste:
(i) Well drilling;
(ii) Well completion and related
operations;
(iii) Initial production tests, subject to
the limitations in § 3179.103;
(iv) Subsequent well tests, subject to
the limitations in § 3179.104;
(v) Exploratory coalbed methane well
dewatering;
(vi) Emergencies, subject to the
limitations in § 3179.105;
(vii) Evaporation from storage vessels;
(viii) Downhole well maintenance;
(ix) Liquids unloading;
(x) Leaks; and
(xi) Releases from pneumatic
controllers and pumps; or
(2) Produced gas that is flared or
vented from a well that is not connected
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to gas capture infrastructure, absent a
BLM determination that the loss of gas
through such venting or flaring is
otherwise avoidable, subject to the
limitations in § 3179.6.
(b) ‘‘Avoidably lost’’ oil or gas means
lost oil or gas that is not unavoidably
lost as defined in paragraph (a) of this
section.
§ 3179.5 When lost production is subject
to royalty.
(a) Royalty is due on:
(1) All avoidably lost oil or gas; and
(2) Waste oil that became waste
through operator negligence.
(b) Royalty is not due on:
(1) Unavoidably lost oil or gas; and
(2) Waste oil that did not become
waste through operator negligence.
§ 3179.6 When flaring or venting is
prohibited.
(a) The operator must flare rather than
vent any gas that is not captured except:
(1) When flaring the gas is technically
infeasible, such as when the gas is not
readily combustible or the volumes are
too small to flare;
(2) Under emergency conditions when
the loss of gas is uncontrollable or
venting is necessary for safety, subject to
§ 3179.105;
(3) When § 3179.203 does not require
the combustion or flaring of gas vapors
from storage vessels; or
(4) When the gas is vented through
operation of a natural gas-activated
pneumatic controller or pump.
(b) Except as provided in § 3179.7, an
operator must not flare or vent gas in
excess of the following amounts,
representing the total volume of gas
flared or vented over a production
month from all development oil wells
on a lease, unit, or CA, divided by the
number of development oil wells
contributing production for at least 10
days during that month:
(1) 7,200 Mcf, for each month during
the period from [EFFECTIVE DATE OF
FINAL RULE] until [1 YEAR AFTER
EFFECTIVE DATE OF FINAL RULE];
(2) 3,600 Mcf, for each month during
the period from [1 YEAR AFTER
EFFECTIVE DATE OF FINAL RULE]
until [2 YEARS AFTER EFFECTIVE
DATE OF FINAL RULE]; and
(3) 1,800 Mcf, for each month
thereafter.
§ 3179.7
flaring.
Alternative limits on venting and
(a) With respect to leases issued
before the effective date of this
regulation, the BLM may approve an
alternative rate-based limit on venting
and flaring from a lease, unit, or CA that
is flaring at a rate that exceeds the
applicable limit under § 3179.6, if the
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operator demonstrates, and the BLM
agrees, that the applicable limit under
§ 3179.6 would impose such costs as to
cause the operator to cease production
and abandon significant recoverable oil
reserves under the lease.
(b) To support such a demonstration,
the operator must submit a Sundry
Notice that includes the following
information:
(1) Information regarding the
operator’s wells under the lease that
produce Federal or Indian gas,
including:
(i) The name, number, and location of
each well, and the number of the lease,
unit, or CA with which it is associated;
(ii) The depths and names of
producing formations;
(iii) The gas production level of each
of the operator’s wells for the most
recent production month for which
information is available; and
(iv) The volumes of gas being vented
and flared from each of the operator’s
wells;
(2) Map(s) showing:
(i) The entire lease, unit, or CA and
the surrounding lands to a distance and
on a scale that shows the field in which
the well or wells are or will be located
(if applicable), and all pipelines that
could transport the gas from the well or
wells;
(ii) All of the operator’s producing oil
and gas wells, which are producing
from Federal or Indian leases (both on
Federal or Indian leases and on other
properties) within the map area;
(iii) Identification of all of the
operator’s wells within the lease from
which gas is flared or vented, and the
location and distance of the nearest gas
pipeline(s) to each such well, with an
identification of those pipelines that are
or could be available for connection and
use; and
(iv) Identification of all of the
operator’s wells within the lease from
which gas is captured;
(3) Data that show pipeline capacity
and the operator’s projections of the cost
associated with installation and
operation of gas capture infrastructure
and alternative methods of
transportation that do not require
pipelines;
(4) The operator’s projections of gas
prices, gas production volumes, gas
quality (i.e., heating value and H2S
content), revenues derived from gas
production, and royalty payments on
gas production over the next 15 years or
the life of the operator’s lease, unit, or
CA, whichever is less; and
(5) The operator’s projections of oil
prices, oil production volumes, costs,
revenues, and royalty payments from
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the operator’s oil and gas operations
within the lease over the lesser of:
(i) The next 15 years; or
(ii) The anticipated remaining period
in which the operator will produce from
the Federal or Indian lease, unit, or CA.
(c) In establishing an alternative
volume limit on venting and flaring
under this section, the BLM will aim to
set the limit at the lowest level that the
BLM determines, considering the
information identified in paragraph (b)
of this section, will not cause the
operator to cease production and
abandon significant recoverable oil
reserves under the lease.
(d) Instead of an alternative limit
under paragraph (a) of this section, a
lease issued before the effective date of
this regulation will receive a renewable,
2-year exemption from the applicable
flaring limit specified in § 3179.6 if the
authorizing officer verifies that all of the
following terms and conditions are met:
(i) The lease, unit, or CA is not
connected to a gas pipeline;
(ii) The closest point on the lease,
unit, or CA is located more than 50
straight-line miles from the nearest gas
processing plant;
(iii) In the most recent production
month, the lease, unit or CA flared or
vented at an average rate that exceeds by
at least 50 percent the applicable flaring
limit specified in § 3179.6; and
(iv) The operator submits to the BLM
a Sundry Notice with an affidavit
certifying that it meets the conditions in
paragraphs (d)(i) through (iii) of this
section.
§ 3179.8 Measuring and reporting volumes
of gas vented and flared from wells.
(a) The operator must estimate or
measure all volumes of gas vented or
flared from wells, and report those
volumes under applicable ONRR
reporting requirements, including 30
CFR part 1210.
(b) The operator may choose whether
to estimate or measure such volumes,
except that measurement is required:
(1) If the operator estimates that the
volume of gas vented or flared from a
flare stack or manifold equals or exceeds
50 Mcf per day; or
(2) If the BLM determines and informs
the operator that the additional accuracy
offered by measurement is necessary for
effective implementation of this subpart.
§ 3179.9 Determinations regarding royaltyfree venting or flaring.
(a) Approvals to flare or vent royalty
free, and/or to flare or vent at a level
above the 7,200 Mcf per month limit in
§ 3179.6(b)(1), which are in effect as of
the effective date of this rule, will
continue in effect until [90 DAYS
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6683
AFTER EFFECTIVE DATE OF THE
FINAL RULE].
(b) The provisions of this subpart do
not affect any determination made by
the BLM before or after [EFFECTIVE
DATE OF FINAL RULE], with respect to
the royalty-bearing status of flaring that
occurred prior to [EFFECTIVE DATE OF
FINAL RULE].
§ 3179.10 Other waste prevention
measures.
(a) If production from an oil well
newly connected to a gas pipeline
results or is expected to result in one or
more producing wells already
connected to the pipeline being forced
off the line, the BLM may exercise
existing authority to limit the
production level from the new well
until the pressure of gas production
from the new well stabilizes at levels
that allow transportation of gas from all
wells connected to the line.
(b) If gas capture capacity is not yet
available on a given lease, the BLM may
exercise existing authority to delay
action on the APD for that lease, or
approve the APD with conditions for gas
capture or limitations on production. If
the lease for which the APD is
submitted is not yet producing, the BLM
may direct or grant a lease suspension
under 43 CFR 3103.4–4.
§ 3179.11 Coordination with State
regulatory authority.
To the extent that any BLM action to
enforce a prohibition, limitation, or
order under this subpart adversely
affects production of oil or gas that
comes from non-Federal and non-Indian
mineral interests, the BLM will
coordinate, on a case-by-case basis, with
the State regulatory authority having
jurisdiction over the oil and gas
production from the non-Federal and
non-Indian interests.
Flaring and Venting Gas During
Drilling and Production Operations
§ 3179.101
Well drilling.
(a) Except as provided in § 3179.6(a)
of this subpart, gas that reaches the
surface as a normal part of drilling
operations must be:
(1) Captured and sold;
(2) Directed to a flare pit or flare stack
equipped with an automatic igniter to
combust any flammable gasses;
(3) Used in operations on the lease,
unit, or CA; or
(4) Injected.
(b) If gas is lost as a result of loss of
well control, the BLM will make a
determination of whether the loss of
well control is due to operator
negligence. Such gas is avoidably lost if
the BLM determines that the loss of well
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control is due to operator negligence.
The BLM will notify the operator in
writing when it makes a determination
that gas was lost due to operator
negligence.
§ 3179.102 Well completion and related
operations.
(a) Except as provided in § 3179.6(a),
gas that reaches the surface during well
completion and post-completion,
drilling fluid recovery, or fracturing or
refracturing fluid recovery operations
must be:
(1) Captured and sold;
(2) Directed to a flare pit or flare stack
equipped with an automatic igniter to
combust any flammable gasses, subject
to the volumetric limitations in
§ 3179.103(a)(3);
(3) Used in operations on the lease,
unit, or CA; or
(4) Injected.
(b) In lieu of compliance with the
requirements of paragraph (a) of this
section, an operator may demonstrate to
the BLM on a Sundry Notice that it is
in compliance with the requirements for
control of gas from well completions
established under 40 CFR part 60,
subpart OOOOa.
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§ 3179.103
Initial production testing.
(a) Gas flared during a well’s initial
production test is royalty-free under
§§ 3179.4(a)(1)(iii) and 3179.5(b) of this
subpart until one of the following
occurs:
(1) The operator determines that it has
obtained adequate reservoir information
for the well;
(2) 30 days have passed since the
beginning of the production test, except
as provided in paragraph (b) and
paragraph (c) of this section;
(3) The operator has flared 20 million
cubic feet (MMcf) of gas, when volumes
flared under this section are combined
with volumes flared under
§ 3179.102(b); or
(4) Production begins.
(b) The BLM may extend the period
specified in paragraph (a)(2) not to
exceed an additional 60 days, based on
testing delays caused by well or
equipment problems or if there is a need
for further testing to develop adequate
reservoir information.
(c) During the dewatering and initial
evaluation of an exploratory coalbed
methane well, the 30-day period
specified in paragraph (a)(2) of this
section is extended to 90 days. The BLM
may approve up to two extensions of
this evaluation period, of up to 90 days
each.
(d) The operator must submit its
request for a longer test period under
paragraph (b) or (c) of this section using
a Sundry Notice.
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§ 3179.104
Subsequent well tests.
During well tests subsequent to the
initial production test, the operator may
flare gas for no more than 24 hours
royalty free under §§ 3179.4(a)(1)(iv)
and 3179.5(b) of this subpart, unless the
BLM approves or requires a longer
period. If the operator requests a longer
period, it must submit a Sundry Notice.
§ 3179.105
Emergencies.
(a) An operator may flare or, if flaring
is not feasible given the emergency, vent
gas royalty-free under § 3179.6(a) of this
subpart during a temporary, short-term,
infrequent, and unavoidable emergency.
(b) The operator may flare or vent gas
royalty free for up to 24 hours per
incident (unless the BLM extends the
period), and for no more than three
emergencies for a lease, unit, or CA
within any 30-day period.
(c) The following do not constitute
emergencies under this section:
(1) More than 3 failures of the same
equipment within any 365-day period;
(2) The operator’s failure to install
appropriate equipment of a sufficient
capacity to accommodate the volume of
gas being produced;
(3) Failure to limit production when
the production rate exceeds the capacity
of the related equipment, pipeline, or
gas plant, or exceeds sales contract
volumes of oil or gas;
(4) Scheduled maintenance; or
(5) Operator negligence.
(d) The operator must estimate and
report to the BLM on a Sundry Notice
the volumes flared or vented beyond the
timeframes specified in paragraph (b) of
this section.
Gas Flared or Vented From Equipment
or During Well Maintenance
Operations
§ 3179.201 Equipment requirements for
pneumatic controllers.
(a) A pneumatic controller that uses
natural gas produced from a Federal or
Indian lease, or from a unit or CA that
includes a Federal or Indian lease, is
subject to this section if the pneumatic
controller:
(1) Has a continuous bleed rate greater
than 6 standard cubic feet (scf) per hour;
and
(2) Is not subject to 40 CFR 60.5360
through 60.5390.
(b) The operator must replace a
pneumatic controller subject to this
section with a pneumatic controller
having a bleed rate of 6 scf per hour or
less within the timeframes set forth in
paragraph (c) of this section, unless:
(1) The operator notifies the BLM
through a Sundry Notice that use of a
pneumatic controller with a bleed rate
greater than 6 scf per hour is required
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based on functional needs described in
the Sundry Notice, that may include,
but are not limited to, response time,
safety, and positive actuation;
(2) The operator notifies the BLM
through a Sundry Notice that the
pneumatic controller exhaust is routed
to a flare device; or
(3) The operator notifies the BLM
through a Sundry Notice and
demonstrates, and the BLM agrees,
based on the information identified in
§ 3179.7(b), that replacement of a
pneumatic controller subject to
paragraph (a)(1)(i) of this section would
impose such costs as to cause the
operator to cease production and
abandon significant recoverable oil
reserves under the lease.
(c) The operator must replace the
pneumatic controller(s) no later than 1
year after the effective date of this
section as required under paragraph (b)
of this section, except that if the well or
facility that the pneumatic controller
serves has an estimated remaining
productive life of 3 years or less from
the effective date of this section, the
operator must notify the BLM through a
Sundry Notice and replace the
pneumatic controller no later than 3
years from the effective date of this
section.
(d) The operator must ensure
pneumatic controllers are functioning
within manufacturers’ specifications.
§ 3179.202 Requirements for pneumatic
chemical injection pumps or pneumatic
diaphragm pumps.
(a) A pneumatic chemical injection or
pneumatic diaphragm pump is subject
to this section if it:
(1) Uses natural gas produced from a
Federal or Indian lease, or from a unit
or CA that includes a Federal or Indian
lease; and
(2) Is not subject to 40 CFR part 60,
subpart OOOOa.
(b) The operator must replace a
pneumatic pump subject to this
paragraph with a zero-emissions pump
or route the pump to a flare device
within the timeframes set forth in
paragraph (d) of this section.
(c) The requirement in paragraph (b)
of this section does not apply if:
(1) The operator notifies the BLM
through a Sundry Notice that:
(i) Use of a pneumatic pump is
required based on functional needs,
described in the Sundry Notice; and
(ii) There is no existing flare device
on site or routing to such a device is
technically infeasible; or
(2) The operator submits a Sundry
Notice to the BLM that:
(i) Provides an economic analysis that
demonstrates, and the BLM agrees,
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based on the information identified in
§ 3179.7(b), that installation of a zeroemissions pump(s) would impose such
costs as to cause the operator to cease
production and abandon significant
recoverable oil reserves under the lease;
and
(ii) Demonstrates to the BLM that
there is no existing flare device on site
or routing to such a device is technically
infeasible.
(d) The operator must replace the
pneumatic pump(s) or connect to a flare
device no later than 1 year after the
effective date of this section, except that
if the well or facility that the pneumatic
pump serves has an estimated
remaining productive life of 3 years or
less from the effective date of this
section, the operator must notify the
BLM through a Sundry Notice and
replace the pneumatic pump no later
than 3 years from the effective date of
this section.
(e) The operator must ensure
pneumatic pumps are functioning
within manufacturers’ specifications.
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§ 3179.203 Crude oil and condensate
storage vessels.
(a) A crude oil or condensate storage
vessel is subject to this section if the
vessel:
(1) Contains production from a
Federal or Indian lease, or from a unit
or CA that includes a Federal or Indian
lease;
(2) Is not subject to 40 CFR part 60,
subpart OOOO; and
(3) Has a rate of total VOC emissions
equal to or greater than 6 tons per year
(tpy).
(b) The operator must determine the
rate of emissions from the storage vessel
within 60 days after the effective date of
this section, and within 30 days after
any new source of production is added
to the tank.
(c) No later than 6 months after the
effective date of this section, the
operator must route all tank vapor gas
from a storage vessel that is subject to
this section to a combustion device or
continuous flare, or to a sales line
unless the operator submits an
economic analysis to the BLM through
a Sundry Notice that demonstrates, and
the BLM agrees, based on the
information identified in § 3179.7(b),
that compliance with this requirement
would impose such costs as to cause the
operator to cease production and
abandon significant recoverable oil
reserves under the lease.
(d) If the rate of total uncontrolled gas
release from a storage vessel declines to
4 tpy or less for any continuous 12
month period, the requirements of this
section no longer apply.
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§ 3179.204 Downhole well maintenance
and liquids unloading.
Leak Detection and Repair (LDAR)
(a) During downhole well
maintenance and liquids unloading
operations, the operator must use
practices that maximize the recovery of
gas for sale and must flare gas not
recovered except where such practices
or flaring are technically infeasible or
unduly costly. Before the operator
purges a well for the first time after the
effective date of this section, the
operator must document that other
methods are technically infeasible or
unduly costly, and provide that
information as part of the Sundry Notice
required under paragraph (d) of this
section.
(b) For wells drilled after the effective
date of this section, the operator may
not conduct liquids unloading by well
purging, except where the operator is
returning a well to production following
a well workover or following a shut-in
for more than 30 days.
(c) For any liquids unloading by well
purging, the operator must:
(1) Be present on-site throughout the
event to ensure that any venting to the
atmosphere is limited to no more than
what is practically necessary, unless the
operator uses an automatic control
system that relies on real-time pressure
or flow, timers, or other well data to
minimize venting;
(2) Record the cause, date, time,
duration, and estimated volume of each
venting event; and
(3) Maintain the liquids unloading
records for the period required under
§ 3162.4–1 of this title and make them
available to the BLM, upon request.
(d) The operator must notify the BLM
by Sundry Notice within 10 calendar
days after the first liquids unloading
event by well purging conducted after
the effective date of this section. This
requirement applies to each well the
operator operates.
(e) The operator must notify the BLM
by Sundry Notice, within 14 calendar
days, if:
(1) The cumulative duration of well
purging events for a well exceeds 24
hours during any production month; or
(2) The estimated volume of gas
vented in liquids unloading by well
purging operations for a well exceeds 75
Mcf during any production month.
(f) For purposes of this section, ‘‘well
purging’’ means blowing accumulated
liquids out of a wellbore by gas pressure
where the gas is vented to the
atmosphere.
(g) Total estimated volumes vented as
a result of downhole well maintenance
and liquids unloading during the
production month must be included in
volumes reported to ONRR as vented.
§ 3179.301
PO 00000
Frm 00071
Fmt 4701
Sfmt 4702
Operator responsibility.
(a) The requirements of §§ 3179.301
through 3179.305 of this subpart apply
to all wells that produce natural gas
from a Federal or Indian lease, or from
a unit or CA that includes a Federal or
Indian lease, including oil wells that
also produce natural gas.
(b) The operator is responsible, as
prescribed in §§ 3179.302 and 3179.303
of this subpart, to inspect for gas leaks
on the following:
(1) All equipment and equipment
components at the wellhead;
(2) All facilities that the operator
operates; and
(3) All compressors located on the
lease, unit, or CA that the operator
owns, leases, or operates.
(c) All leak inspections must occur
during production operations.
(d) The operator must fix the leaks as
prescribed in §§ 3179.304 and 3179.305
of this subpart. See 43 CFR 3162.5–1 for
responsibility to repair oil leaks.
(e) An operator may satisfy the
requirements of §§ 3179.301 through
3179.305 for some or all of the
equipment or facilities on a given lease
by demonstrating to the BLM on a
Sundry Notice that the operator is
complying with LDAR requirements
established under 40 CFR part 60,
subpart OOOOa with respect to such
equipment or facilities.
§ 3179.302
methods.
Approved instruments and
(a) The operator must use one or more
of the following instruments or
monitoring methods to detect leaks:
(1) An optical gas imaging device;
(2) A monitoring device not listed in
this section, which is approved by the
BLM for use by any operator, under
§ 3179.303(b) of this subpart;
(3) A comprehensive program,
approved by the BLM under
§ 3179.303(b) of this subpart, that
includes the use of instrument-based
monitoring devices; or
(4) A portable analyzer device capable
of detecting leaks, such as catalytic
oxidation, flame ionization, infrared
absorption or photoionization devices,
operated according to manufacturer
specifications, and assisted by audio,
visual, and olfactory inspection.
(b) If an operator operates 500 or more
wells within the jurisdiction of a single
BLM field office, the operator may only
use one or more of the methods
identified in paragraph (a)(1), (2), or (3)
of this section to detect leaks.
E:\FR\FM\08FEP2.SGM
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Federal Register / Vol. 81, No. 25 / Monday, February 8, 2016 / Proposed Rules
§ 3179.303 Leak detection inspection
requirements for natural gas wellhead
equipment, facilities, and compressors.
(a) Except as provided below or
otherwise authorized in paragraph (b) of
this section, the operator must inspect at
least semi-annually for leaks the
wellhead equipment, facilities, and
compressors identified in § 3179.301(b)
of this subpart. For purposes of
§§ 3179.301 through 3179.305, the term
‘‘site’’ means a discrete area containing
wellhead equipment, facilities, and
compressors, which is suitable for
inspection in a single visit.
If the operator inspects
And in two consecutive inspections the operator
The operator
(1)
(2)
(3)
(4)
Detects
Detects
Detects
Detects
Must
Must
Must
Must
Semi-annually ........................
Annually .................................
Semi-annually ........................
Quarterly ................................
no more than 2 leaks at the site inspected ......................
3 or more leaks at the site inspected ...............................
3 or more leaks at the site inspected ...............................
no more than 2 leaks at the site inspected ......................
(b) The BLM may approve an
alternative leak detection device,
program, or method under
§ 3179.302(a)(2) or 3179.302(a)(3) of this
subpart, if the BLM finds that the
alternative would meet or exceed the
effectiveness for leak detection of the
approach specified in §§ 3179.302(a)(1)
and 3179.303(a) of this subpart. The
operator must submit its request for an
alternative leak detection device,
program, or method of this section
through a Sundry Notice.
(c) The operator is not required to
inspect or monitor a component that is
not an accessible component.
asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
§ 3179.304
Repairing leaks.
(a) The operator must repair any leak
not associated with normal equipment
operation as soon as practicable, and in
no event later than 15 calendar days
after discovery, unless good cause exists
for repair requiring a longer period.
(b) If delay in repair beyond 15
calendar days is attributable to good
cause, the operator must notify the BLM
of the cause by Sundry Notice and must
complete repairs within 15 calendar
days after the cause of delay ceases to
exist.
(c) Not later than 15 calendar days
after completion of a repair, the operator
must verify the effectiveness of the
repair through a follow-up inspection
using the same method used to detect
the leak.
(d) If the repair is not effective, the
operator must complete additional
repairs within 15 calendar days, and
conduct follow-up inspections and
repairs until the leak is repaired.
(e) A follow-up inspection to verify
the effectiveness of repairs does not
constitute an inspection for purposes of
§ 3179.303.
VerDate Sep<11>2014
18:16 Feb 05, 2016
Jkt 238001
§ 3179.305 Leak detection inspection
recordkeeping.
The operator must maintain the
following records for the period
required under § 3162.4–1 of this title
and make them available to the BLM
upon request:
(a) For each inspection required under
§ 3179.303 of this subpart,
documentation of:
(1) The date of the inspection;
(2) The site where the inspection was
conducted; and
(3) The equipment or facility
inspected;
(b) The monitoring method(s) used to
determine the presence of leaks;
(c) A list of components on which
leaks were found and a description of
each leak;
(d) The date of first attempt to repair
each leak and, if necessary, any
additional attempt to repair the leak;
(e) The date each leak was repaired;
and
(f) The date and result of the followup inspection(s) required under
§ 3179.304 paragraph (c) or (d) of this
subpart.
State or Tribal Variances
§ 3179.401 State or tribal requests for
variances from the requirements of this
subpart.
(a)(1) At the request of a State (for
Federal land) or a tribe (for Indian
lands), the BLM State Director may
grant a variance from any individual
provision of this subpart that would
apply to all Federal leases, units, or CAs
within a State or to all tribal leases,
units, or CAs within that tribe’s lands,
or to specific fields or basins within the
State or that tribe’s lands, if the BLM
PO 00000
Frm 00072
Fmt 4701
Sfmt 9990
inspect
inspect
inspect
inspect
at
at
at
at
least
least
least
least
annually.
semi-annually.
quarterly.
semi-annually.
finds that the variance would meet the
criteria in paragraph (b) of this section.
(2) A State or tribal variance request
must:
(i) Identify the provision(s) of this
subpart from which the State or tribe is
requesting the variance;
(ii) Identify the State or tribal
regulation(s) or rule(s) that would be
applied in place of the provision(s) of
this subpart;
(iii) Explain why the variance is
needed; and
(iv) Demonstrate how the State or
tribal requirement would satisfy the
requirement of the particular provision
from which the State or tribe is
requesting the variance.
(b) The BLM State Director, after
considering all relevant factors, may
approve the request for a variance, or
approve it with one or more conditions,
only if the BLM determines that the
State or tribal regulation or rule meets
or exceeds the requirements of the
provision(s) from which the State or
tribe is requesting the variance, and is
consistent with the terms of the affected
Federal or Indian leases and applicable
statutes. The decision to grant or deny
the variance will be in writing and is
within the BLM’s discretion. The
decision on a variance request is not
subject to administrative appeal under
43 CFR part 4.
(c) A variance from any particular
requirement of this rule does not
constitute a variance from provisions of
other regulations, laws, or orders.
(d) The BLM reserves the right to
rescind a variance or modify any
condition of approval.
[FR Doc. 2016–01865 Filed 2–5–16; 8:45 am]
BILLING CODE 4310–84–P
E:\FR\FM\08FEP2.SGM
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]]>Agencies
[Federal Register Volume 81, Number 25 (Monday, February 8, 2016)]
[Proposed Rules]
[Pages 6615-6686]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2016-01865]
[[Page 6615]]
Vol. 81
Monday,
No. 25
February 8, 2016
Part II
Department of the Interior
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Bureau of Land Management
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43 CFR Parts 3100, 3160, and 3170
Waste Prevention, Production Subject to Royalties, and Resource
Conservation; Proposed Rule
Federal Register / Vol. 81 , No. 25 / Monday, February 8, 2016 /
Proposed Rules
[[Page 6616]]
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DEPARTMENT OF THE INTERIOR
Bureau of Land Management
43 CFR Parts 3100, 3160, and 3170
[15X.LLWO300000.L13100000.NB0000]
RIN 1004-AE14
Waste Prevention, Production Subject to Royalties, and Resource
Conservation
AGENCY: Bureau of Land Management, Interior.
ACTION: Proposed rule.
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SUMMARY: The Bureau of Land Management (BLM) is proposing new
regulations to reduce waste of natural gas from venting, flaring, and
leaks during oil and natural gas production activities on onshore
Federal and Indian leases. The regulations would also clarify when
produced gas lost through venting, flaring, or leaks is subject to
royalties, and when oil and gas production used on site would be
royalty-free. These proposed regulations would be codified at new 43
CFR subparts 3178 and 3179. They would replace the existing provisions
related to venting, flaring, and royalty-free use of gas contained in
the 1979 Notice to Lessees and Operators of Onshore Federal and Indian
Oil and Gas Leases, Royalty or Compensation for Oil and Gas Lost (NTL-
4A), which are over 3 decades old.
DATES: Send your comments on this proposed rule to the BLM on or before
April 8, 2016. The BLM is not obligated to consider any comments
received after this date in making its decision on the final rule.
As explained later, the proposed rule would establish new
information collection requirements that must be approved by the Office
of Management and Budget (OMB). If you wish to comment on the
information collection requirements in this proposed rule, please note
that the OMB is required to make a decision concerning the collection
of information contained in this proposed rule between 30 and 60 days
after publication of this document in the Federal Register. Therefore,
a comment to the OMB on the proposed information collection
requirements is best assured of having its full effect if the OMB
receives it by March 9, 2016.
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-AE14. Personal or messenger
delivery: 20 M Street SE., Room 2134LM, Washington, DC 20003. Federal
eRulemaking Portal: https://www.regulations.gov. Follow the instructions
at this Web site.
Comments on the information collection burdens: Fax: Office of
Management and Budget (OMB), Office of Information and Regulatory
Affairs, Desk Officer for the Department of the Interior, fax 202-395-
5806. Electronic mail: OIRA_Submission@omb.eop.gov. Please indicate
``Attention: OMB Control Number 1004-XXXX,'' regardless of the method
used to submit comments on the information collection burdens. If you
submit comments on the information collection burdens, you should
provide the BLM with a copy, at one of the addresses shown earlier in
this section, so that we can summarize all written comments and address
them in the final rule preamble.
FOR FURTHER INFORMATION CONTACT: Eric Jones at the BLM Moab Field
Office, 82 East Dogwood Ave., Moab, UT 84532, or by telephone at 435-
259-2117; or Timothy Spisak at the BLM Washington Office, 20 M Street
SE., Room 2134LM, Washington, DC 20003, or by telephone at 202-912-
7311. For questions relating to regulatory process issues, contact
Faith Bremner at 202-912-7441.
Persons who use a telecommunications device for the deaf (TDD) may
call the Federal Information Relay Service (FIRS) at 1-800-877-8339 to
contact these individuals during normal business hours. FIRS is
available 24 hours a day, 7 days a week to leave a message or question
with these individuals. You will receive a reply during normal business
hours.
SUPPLEMENTARY INFORMATION:
I. Executive Summary
A. Background
This proposed regulation aims to reduce the waste of natural gas
from mineral leases administered by the BLM. This gas is lost during
oil and gas production activities through flaring or venting of the
gas, and equipment leaks. While oil and gas production technology has
advanced dramatically in recent years, the BLM's requirements to
minimize waste of gas have not been updated in over 30 years. The
Mineral Leasing Act of 1920 (MLA) requires the BLM to ensure that
lessees ``use all reasonable precautions to prevent waste of oil or gas
developed in the land . . . .'' 30 U.S.C. 225. The BLM believes there
are economical, cost-effective, and reasonable measures that operators
should take to minimize waste, which will enhance our nation's natural
gas supplies, boost royalty receipts for American taxpayers, tribes,
and States, and reduce environmental damage from venting and flaring.
The BLM's onshore oil and gas management program is a major
contributor to our nation's oil and gas production. The BLM manages
more than 245 million acres of land and 700 million acres of subsurface
estate, making up nearly a third of the nation's mineral estate.
Domestic production from over 100,000 Federal onshore oil and gas wells
accounts for 11 percent of the Nation's natural gas supply and 5
percent of its oil. In Fiscal Year (FY) 2014, operators produced 204.6
million barrels (bbl) of oil, 2 trillion cubic feet (Tcf) of natural
gas, and 3.1 billion gallons of natural gas liquids (NGLs) from onshore
Federal and Indian oil and gas leases. The production value of this oil
and gas exceeded $27.2 billion and generated approximately $3.1 billion
in royalties.\1\
---------------------------------------------------------------------------
\1\ Office of Natural Resources Revenue (ONRR), Statistical
Information, https://statistics.onrr.gov/ReportTool.aspx using Sales
Year--FY2014--Federal Onshore--All States Sales Value and Revenue
for Oil, NGL, and Gas products as of December 2, 2015.
---------------------------------------------------------------------------
Over the past decade, the United States has experienced a dramatic
increase in oil and natural gas production due to technological
advances, such as hydraulic fracturing combined with directional and/or
horizontal drilling. This boost in production has brought many benefits
in the form of expanded and more secure domestic oil and gas supplies,
lower oil and gas prices, increased economic activity, and greater
royalty revenues for Federal, State and tribal governments. At the same
time, the American public has not benefited from the full potential of
this increased production, due to the flaring, venting, and leakage of
significant quantities of gas during the production process. According
to data reported to the Office of Natural Resources Revenue (ONRR),
Federal and Indian onshore lessees and operators lost 375 billion cubic
feet (Bcf) of natural gas between 2009 and 2014--enough gas to serve
about 5.1 million households for a year, assuming 2009 usage levels.\2\
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\2\ The Energy Information Administration (EIA), Trends in U.S.
Residential Natural Gas Consumption, https://www.eia.gov/pub/oil_gas/natural_gas/feature_articles/2010/ngtrendsresidcon/ngtrendsresidcon.pdf (reporting that in 2009, U.S. residential
consumption was approximately 74 Mcf per household with natural gas
service).
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Flaring, venting, and leaks waste a valuable resource that could be
put to productive use, and deprive American taxpayers, tribes, and
States of royalty revenues. In addition, the wasted gas may harm local
communities and
[[Page 6617]]
surrounding areas through visual and noise impacts from flaring, and
regional and global air pollution problems of smog, particulate matter,
toxic air pollution (such as benzene, a carcinogen) and climate change.
The primary constituent of natural gas is methane, and increases in gas
wasted through venting, flaring or leaks contribute to increases in
atmospheric methane levels. Methane is an especially powerful
greenhouse gas (GHG), with climate impacts roughly 25 times those of
CO2, if measured over a 100-year period, or 86 times those
of CO2, if measured over a 20-year period.\3\ Thus, measures
to conserve gas and avoid waste may significantly benefit local
communities, public health, and the environment.
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\3\ See Intergovernmental Panel on Climate Change, Climate
Change 2013: The Physical Science Basis, Chapter 8, Anthropogenic
and Natural Radiative Forcing, at 714 (Table 8.7), available at
https://www.ipcc.ch/pdf/assessment-report/ar5/wg1/WG1AR5_Chapter08_FINAL.pdf.
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The BLM oversees oil and gas activities under the authority of a
variety of laws, including the MLA, the Mineral Leasing Act for
Acquired Lands of 1947 (MLAAL), the Federal Oil and Gas Royalty
Management Act (FOGRMA), the Federal Land Policy and Management Act of
1976 (FLPMA), the Indian Mineral Leasing Act of 1938 (IMLA), the Indian
Mineral Development Act of 1982 (IMDA), and the Act of March 3,
1909.\4\ In particular, the MLA requires the BLM to ensure that lessees
``use all reasonable precautions to prevent waste of oil or gas
developed in the land . . . .'' \5\ This proposal would replace current
requirements related to flaring, venting, and royalty-free use of
production, which are contained in NTL-4A; amend the BLM's oil and gas
regulations at 43 CFR part 3160; and add new subparts 3178 and 3179. It
would apply to all Federal and Indian (other than Osage Tribe) onshore
oil and gas leases as well as leases and business agreements entered
into by tribes (including IMDA agreements), as consistent with those
agreements and with principles of Federal Indian law.\6\
---------------------------------------------------------------------------
\4\ Mineral Leasing Act, 30 U.S.C. 188-287; Mineral Leasing Act
for Acquired Lands, 30 U.S.C. 351-360; Federal Oil and Gas Royalty
Management Act, 30 U.S.C. 1701-1758; Federal Land Policy and
Management Act of 1976, 43 U.S.C. 1701-1785; Indian Mineral Leasing
Act of 1938, 25 U.S.C. 396a-g; Indian Mineral Development Act of
1982, 25 U.S.C. 2101-2108; Act of March 3, 1909, 25 U.S.C. 396.
\5\ 30 U.S.C. 225.
\6\ Key statutes underpinning this proposed regulation contain
exceptions for the Osage Tribe. Specifically, the Osage Tribe is
excepted from the application of both the Indian Mineral Leasing Act
and the Federal Oil and Gas Royalty Management Act, 25 U.S.C. 396f;
43 U.S.C. 1702(3), 1702(4). The leasing of Osage Reservation lands
for oil and gas mining is subject to special Bureau of Indian
Affairs regulations contained in 43 CFR part 226.
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Several oversight reviews, including reviews by the Inspector
General of the Department of the Interior and the Government
Accountability Office (GAO), have raised concerns about waste of gas,
found that the BLM's existing requirements regarding venting and
flaring are insufficient, expressed concerns about the ``lack of price
flexibility in royalty rates,'' \7\ and identified concerns about
royalty-free use of gas. These reports recommended that the BLM update
its regulations to address waste prevention, afford flexibility in rate
setting, and clarify policies regarding royalty-free, on-site use of
oil and gas. With respect to waste, the GAO found that ``around 40
percent of natural gas estimated to be vented and flared on onshore
Federal leases could be economically captured with currently available
control technologies.'' \8\ The GAO recommended that the BLM reduce
venting and flaring of gas by revising its regulations ``to make it
clear that technologies should be used where they can economically
capture sources of vented and flared gas, including gas from liquid
unloading, well completions, pneumatic valves, and glycol
dehydrators.'' \9\ The GAO further recommended that the BLM consider
expanded use of infrared cameras to identify opportunities to minimize
lost gas.\10\
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\7\ GAO, Oil and Gas Royalties: The Federal System for
Collecting Oil and Gas Revenues Needs Comprehensive Reassessment,
GAO-08-691, September 2008, 6.
\8\ GAO, Federal Oil and Gas Leases: Opportunities Exist to
Capture Vented and Flared Natural Gas, Which Would Increase Royalty
Payments and Reduce Greenhouse Gases, GAO-11-34, (Oct. 2010), 2.
\9\ Ibid. at 34.
\10\ Ibid. at 34.
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This proposed rule would align the BLM's royalty rate for new
competitive Federal oil and gas leases with the regime envisioned by
the MLA, which specifies ``a rate of not less than 12.5 percent in
amount or value of the production removed or sold from the lease.''
\11\ In addition, the proposed rule would update the BLM's existing
NTL-4A requirements related to venting, flaring, and royalty-free use
of natural gas from onshore Federal and Indian leases. Under NTL-4A,
operators must apply to the BLM on a case-by-case basis for approval to
flare royalty-free, based on economic criteria. We propose to reduce
the need for case-by-case applications by clarifying when flared or
vented natural gas is subject to royalties. Further, with respect to
venting and flaring of natural gas, we propose to: Prohibit venting,
except in certain limited circumstances; limit the rate of routine
flaring at development oil wells; \12\ require operators to detect and
repair leaks; and mandate reductions in venting from: Pneumatic
controllers and pneumatic pumps that operate by releasing natural gas;
storage vessels; activities to unload liquids from a well; and well
drilling, completion, and testing activities. Finally, the proposed
rule would require operators to submit gas capture plans with their
Applications for Permits to Drill new wells.
---------------------------------------------------------------------------
\11\ 30 U.S.C. 226(b)(1)(A) (emphasis added); see also 30 U.S.C.
352 (applying the MLA's leasing provisions to leases on acquired
land).
\12\ ``Development oil well'' or ``development gas well'' means
a well drilled to produce oil or gas, respectively, from an
established field in which hydrocarbons have been discovered and
from which they are being produced at a profit or expected profit.
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The BLM has engaged in substantial stakeholder outreach in the
course of developing this proposal. In 2014, the BLM conducted a series
of forums to consult with tribal governments and solicit stakeholder
views to inform the development of this proposed rule, with public
meetings (some of which were livestreamed) in Colorado, New Mexico,
North Dakota, and Washington, DC. \13\ For each forum, we held a tribal
outreach session in the morning and a public outreach session in the
afternoon. We also accepted informal comments generated as a result of
the public/tribal outreach sessions. Since those meetings, we have
continued to consult with stakeholders throughout the rule development
process, including numerous meetings and calls with State
representatives, individual companies, trade associations, and non-
governmental organizations (NGOs). We have also received and considered
many reports, peer-reviewed studies, and letters from stakeholders
providing information and views on what the BLM should propose.
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\13\ Further information can be found at the BLM oil and gas
program's outreach-events page: https://www.blm.gov/wo/st/en/prog/energy/public_events_on_oil.html.
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The BLM conducted additional outreach with States where there is
extensive oil and gas production from BLM-administered leases. We have
carefully reviewed State regulations and guidance and consulted with
State regulatory bodies that oversee aspects of oil and gas production
to discuss their requirements and practices. The BLM intends to
continue close interaction with State and tribal regulators.
The BLM is not the only entity to recognize the need to reduce
flaring and
[[Page 6618]]
venting from oil and gas production activities. Domestically, the
Environmental Protection Agency (EPA) and a few individual States have
been active in this area, as have some oil and gas producers. In 2012,
for example, the EPA adopted Clean Air Act new source performance
standards (NSPS) for certain activities in the oil and gas production
sector. These regulations target reductions of volatile organic
compounds (VOCs) and have the effect of reducing venting and leaks. The
EPA recently proposed regulations to amend the 2012 NSPS for the oil
and natural gas source category by setting standards for both methane
and VOCs for certain equipment, processes and activities across this
source category (40 CFR part 60 subpart OOOOa rulemaking).\14\ This EPA
proposal would have the effect of further reducing gas losses through
venting and leaks.
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\14\ EPA, Oil and Natural Gas Sector: Emission Standards for New
and Modified Sources, Proposed Rule, 80 FR 56593 (Sept. 18, 2015).
For further information about EPA's existing and proposed NSPS
standards for this source category, see Section IV.I.3 of this
preamble below.
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In addition, several States with BLM-administered lands and mineral
interests have acted in this area. Colorado has adopted comprehensive
statewide regulations to limit emissions of VOCs from venting and leaks
from oil and gas production activities.\15\ The Colorado regulations
require operators to implement leak detection and repair (LDAR)
programs, replace high-bleed pneumatic controllers with low-bleed
pneumatic controllers, and control emissions from storage vessels,
among other things. Wyoming has adopted similar comprehensive
regulations that apply in the Upper Green River Basin, a
``nonattainment area'' where air quality does not meet national ozone
standards adopted by the EPA under the Clean Air Act.\16\ North Dakota
has also adopted an innovative program to phase down flaring by
operators across the State, requiring 91 percent gas capture by
2020.\17\ Pennsylvania has issued guidance that exempts oil and gas
facilities from certain air quality permitting requirements if they
implement changes to reduce gas loss, such as developing an LDAR
program, reducing VOC emissions from storage vessels, and limiting
flaring activity.\18\
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\15\ Colorado Air Quality Control Commission Regulations,
Regulation 7, 5 CCR 1001-9, Sections XII, XVII, XVIII, available at
https://www.colorado.gov/pacific/sites/default/files/5-CCR-1001-9_0.pdf.
\16\ Wyoming, Nonattainment Area Regulations Ch. 8 (June 2015),
available at https://soswy.state.wy.us/Rules/RULES/9868.pdf.
\17\ North Dakota Industrial Commission Order 24665 Policy
Guidance Version 102215, available at https://www.dmr.nd.gov/oilgas/GuidancePolicyNorthDakotaIndustrialCommissionorder24665.pdf.
\18\ Pennsylvania Department of Environmental Protection, Air
Quality Permit Exemptions (Aug. 10, 2013), available at https://www.elibrary.dep.state.pa.us/dsweb/Get/Document-96215/275-2101-003.pdf, at 8-11.
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The oil and gas industry has also taken voluntary actions to reduce
flaring and venting. Many of these efforts have been initiated by
companies participating in Natural Gas STAR, a voluntary EPA-industry
partnership program that encourages oil and natural gas companies to
adopt cost-effective technologies and practices that improve
operational efficiency and reduce methane emissions. Twenty-six
companies in the production sector currently participate in Natural Gas
STAR, and they reported that they achieved about 50 Bcf of methane
emissions reductions in 2013.\19\ To further encourage emissions
reductions from the oil and gas sector, the EPA announced, in July
2015, a voluntary program called the Natural Gas STAR Methane
Challenge, in which companies would make ambitious commitments to
reduce methane emissions and would track their progress in achieving
those reductions.\20\ In addition, six oil and gas companies have
joined together to form the One Future Coalition, which aims to
``(e)nhance the energy delivery efficiency of the natural gas supply
chain by limiting energy waste and by achieving a methane `leak/loss
rate' of no more than one percent.'' \21\
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\19\ EPA Natural Gas STAR Accomplishments, available at https://www3.epa.gov/gasstar/accomplishments/.
\20\ EPA Natural Gas Star Methane Challenge, Program Proposal,
available at https://www3.epa.gov/gasstar/methanechallenge/.
\21\ Maria Galluci, Six Major Oil & Gas Firms Agree To Cut
Potent Methane Emissions Ahead Of UN Climate Change Summit,
International Business Times, Sept. 23, 2014, https://www.ibtimes.com/six-major-oil-gas-firms-agree-cut-potent-methane-emissions-ahead-un-climate-change-summit-1693517; https://www.gastechnology.org/CH4/Documents/Fiji-George-CH4-presentation-Sep2014.pdf; One Future: Our Nation's Energy, 1, 6 (Sept. 2014),
https://www.gastechnology.org/CH4/Documents/Fiji-George-CH4-presentation-Sep2014.pdf.
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Given these activities, it is important to ensure that updated BLM
requirements do not subject operators to conflicting or redundant
requirements. Thus, in addition to our outreach to States, we are
coordinating closely with the EPA as it works to finalize its 40 CFR
part 60 subpart OOOOa rulemaking.
The ongoing EPA and State regulatory activities do not, however,
obviate the need for the BLM, in its role as a public land manager, to
update its requirements governing flaring, venting, and leaks to ensure
that the public's resources and assets are not wasted and are developed
in a manner that provides for long term productivity and
sustainability. First, the BLM has an independent legal responsibility,
and a proprietary interest as a land manager, to oversee oil and gas
production activities on Federal and Indian leases. The BLM has
requirements in place, but as independent reviews have pointed out, the
existing requirements pre-date, and thus do not account for,
significant technological developments. Updating and clarifying the
regulations will make them more effective, more transparent, and easier
to understand and administer, and will reduce operators' compliance
burdens in some respects. The BLM must ensure that it has modern,
effective requirements to govern oil and gas operations on BLM-
administered leases. Second, as a practical matter, neither the EPA nor
State regulations adequately address the issue of waste of gas from
BLM-administered leases. The EPA regulations are directed at air
pollution reduction, not waste prevention; they focus largely on new
sources; and they do not address all avenues for reducing waste (for
example, they do not impose flaring limits for associated gas).
Similarly, no State has established a comprehensive set of requirements
addressing all three avenues for waste--flaring, venting, and leaks--
and only a few States have significant requirements in even one of
these areas. It is wholly within the BLM's statutory authority to
address flaring, venting, and leaks in its capacity as a land manager
with a responsibility to ensure the longevity and long term
productivity of public lands and resources, including gas resources.
Part I.B. of this preamble, below, offers a summary of the proposed
rule's provisions, benefits, and costs, and parts V and VI of this
preamble provide more detail about those provisions (part V) and
impacts (part VI). Overall, the BLM estimates that the benefits of this
rule would outweigh its costs by a significant margin. Under certain
assumptions, for example, the rule is expected to produce net benefits
ranging from $115 million to $188 million per year (assuming the EPA
finalizes 40 CFR part 60 subpart OOOOa and calculating costs and cost
savings using a 7 percent discount rate) or from $138 million to $232
million per year (assuming the EPA finalizes 40 CFR part 60 subpart
OOOOa and calculating costs
[[Page 6619]]
and cost savings using a 3 percent discount rate).\22\
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\22\ BLM, Economic Impact and Regulatory Threshold Analysis for
43 CFR 3178 (Royalty Free Use of Production) and 43 CFR 3179
(Venting and Flaring Requirements) (2015) (hereinafter RIA) at 7.
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B. Summary of Proposal
The proposed rule would require operators to take various actions
to reduce waste of gas, establish clear criteria for when flared gas
would qualify as waste and therefore be subject to royalties, and
clarify the on-site uses of gas that are exempt from royalties. The BLM
has identified several key points in the oil and gas production process
where waste-prevention actions would be most effective and least
costly. Specifically, we propose to focus on reducing waste from the
following aspects of the production process: Flaring of associated gas
from development oil wells; gas leaks from equipment and facilities
located at the well site, as well as from compressors located on the
lease; operation of high-bleed pneumatic controllers and certain
pneumatic pumps; gas emissions from vessels; downhole well maintenance
and liquids unloading; and well drilling and completions. The following
discussion summarizes the proposed requirements applicable to each of
these aspects of the production process.
These requirements would impose annual costs and yield annual
benefits, but both costs and benefits are expected to vary over time.
Over the first few years, compliance activity (and associated costs and
gas savings) would likely be highest. During this time, some operators
would have to add or improve gas-capture capability, and some would
have to replace existing equipment. After these transitional years, we
expect that both compliance activities and gas savings from this rule
would be significantly reduced.
1. Venting and Flaring
In 2013, operators vented about 22 Bcf and flared at least 76 Bcf
of natural gas from BLM-administered leases.\23\ The 2013 flaring
estimate, a 109 percent increase from 2009 levels,\24\ represents 2.6
percent of the total production from BLM-administered leases in that
year (2,901 Bcf) \25\ and sufficient gas to supply over 1 million
households.\26\ Of this, roughly 71 Bcf came from oil wells.\27\
Analysis of data supplied by the ONRR suggests that most of this was
routine flaring of associated gas from development oil wells (as
opposed to flaring during exploration, well testing, and emergencies).
Over 90 percent of this flaring occurred in North Dakota, South Dakota,
and New Mexico.\28\
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\23\ RIA at 119-120.
\24\ RIA 119.
\25\ RIA at 111 (Appendix A-2).
\26\ See footnote 2 (assuming 2009 usage levels).
\27\ RIA at 33.
\28\ RIA at 122 (Appendix A-8, Table 4).
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The BLM is proposing to prohibit venting of natural gas, except
under certain conditions, including in emergencies, as would be defined
in the regulations.\29\ With respect to flaring, the BLM proposes to
limit the rate of routine flaring of associated gas from development
oil wells and retain the current exemptions from gas capture
requirements and royalties for gas flared in other situations, as long
as the operator has complied with the proposed requirements to minimize
such losses. These exemptions include gas lost in the normal course of
well drilling and well completion; well tests; emergencies, as would be
defined in the regulations; \30\ and gas flared from exploration or
wildcat wells, or delineation wells (wells drilled to define the
boundaries of a mineral deposit).
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\29\ See proposed 43 CFR 3179.105.
\30\ Ibid.
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The primary alternative to flaring associated gas from oil wells is
to capture, transport, and process that gas for sale, using the same
technologies that are used for natural gas production. The capture and
sale of associated gas is viable where there is sufficient gas
production to offset the costs of connecting to or expanding existing
pipeline infrastructure. In addition, technologies for capturing and
using gas without a pipeline are becoming increasingly available. This
capture infrastructure may include: Separating out NGLs or liquefying
the natural gas (LNG), allowing the resulting liquids to be trucked off
location; converting the gas into compressed natural gas (CNG) for use
on-site or to be trucked off location; and using the gas to run micro-
turbines to generate power for use on-site or for sale back to the
grid.
Gas is flared under a variety of circumstances. Some circumstances,
such as emergencies, can occur unplanned in the course of oil and gas
production. Further, in a new field, operators and the midstream
processing companies that commonly build and operate gas gathering and
processing infrastructure may not have sufficient information about how
much gas will be produced to invest in building gathering lines and
processing plants. In other instances, however, operators may decide to
focus on near-term oil production rather than investing in the gas
capture and transmission infrastructure that would be necessary to
realize a profit from the associated gas.
On BLM-administered leases, two situations result in substantial
flaring of associated gas. In some areas, there is capture
infrastructure, but the rate of new well construction is outpacing the
infrastructure capacity. This accounts for the majority of flaring on
BLM-administered leases. In other areas, capture and processing
infrastructure has not yet been built out.
Currently, under NTL-4A, operators must seek BLM approval to flare
on a case-by-case basis, with limited exceptions. Operators must
provide economic data with each request, demonstrating that requiring
the gas to be captured would ``lead to the premature abandonment of
recoverable oil reserves and ultimately to a greater loss of equivalent
energy than would be recovered'' if the flaring were approved. This
approach results in a substantial amount of paper-work, but does not
significantly limit flaring, as BLM has commonly, although not always,
approved these requests.
The BLM proposes to simplify, clarify, and strengthen its approach
to reducing flaring by establishing clear parameters for when routine
flaring from development wells is allowed, and by setting a limit on
the rate of flaring from individual wells. As a general matter,
operators would no longer have to obtain permission for flaring on a
case-by-case basis, provided they stay within the proposed prescribed
limit.
Specifically, we propose to limit routine flaring of associated gas
from development wells to 1,800 thousand cubic feet (Mcf) per month per
well, averaged across all of the producing wells on a lease. This limit
is similar to requirements in Wyoming and Utah, which limit flaring to
60 Mcf/day and 1,800 Mcf/month, respectively, unless the operator
obtains State approval of a higher limit.\31\ The BLM estimates that
this limit would reduce flaring by up to 74 percent, although there is
substantial uncertainty regarding this estimate. The BLM proposes to
retain the authority to allow higher rates of flaring in specific
circumstances, where adhering to the proposed flaring limit would
impose such costs as to cause the operator to cease production and
abandon significant recoverable oil reserves under the lease. In making
this
[[Page 6620]]
determination, the BLM would consider the costs of capture, and the
costs and revenues of all oil and gas production on the lease. Further,
the BLM proposes to create a 2-year renewable exemption from the
flaring limit, available only for certain existing leases that are
located a significant distance from gas processing facilities and
flaring at a rate well above the proposed flaring limit. Holders of
these leases have, until now, had no prior notice of the proposed
flaring limit. Given the significant distance from these leases to the
nearest gas capture facilities, and the leases' high rates of gas
flaring, operators at these sites might have few options to meet the
proposed flaring limit other than shutting in the wells. The BLM
anticipates the number of leases eligible for this 2-year exemption
would decline over time, as production of oil and associated gas from
existing leases naturally declines.
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\31\ Wyoming Operational Rules, Drilling Rules Section Ch. 3,
Section 39(b), available at https://soswy.state.wy.us/Rules/RULES/9584.pdf (60 Mcf/day); Utah R649-3-20, Gas Flaring or Venting
Section 1.1, available at (https://www.rules.utah.gov/publicat/code/r649/r649-003.htm#T20 (1,800 Mcf/mo.).
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The BLM proposes to phase in the flaring limit over the first 2
years after the rule becomes effective, in recognition of the fact that
some wells are flaring at rates considerably higher than 1,800 Mcf/
month, not all wells will be able to use on-site capture technologies,
and connecting to gas pipeline infrastructure may take some time. We
propose that in the first year after the effective date of the rule,
the flaring limit per well, averaged across all of the producing wells
on a lease, would be 7,200 Mcf/month. In the second year, it would be
3,600 Mcf/month. The 1,800 Mcf/month limit would apply beginning in the
third year of the rule.
The BLM is also proposing that prior to drilling a new development
oil well, an operator would have to evaluate the opportunities and
prepare a plan to minimize waste of associated gas from that well, and
the operator would need to submit this plan along with the Application
for Permit to Drill or Reenter (APD). The BLM proposes to require
submission of a plan with specific content, to ensure that operators
have carefully considered and planned for gas capture prior to
drilling.
In addition to these requirements to reduce flaring, the BLM
proposes to update existing royalty provisions by more specifically
defining when a loss of gas would be considered ``unavoidable'' and
royalty-free, and when it would be considered ``avoidable'' and subject
to royalties. A loss of gas would be deemed unavoidable when an
operator has complied with all applicable requirements and taken
prudent and reasonable steps to avoid waste, and the gas is lost from
any of the following specified operations or sources, subject to limits
specified in the proposed regulations: Emergencies; well drilling, well
completion and related operations; initial production tests and
subsequent well tests; exploratory coalbed methane well dewatering;
leaks; venting from pneumatic devices in the normal course of
operation; evaporation from storage vessels; and downhole well
maintenance and liquids unloading. A loss of gas would also be deemed
unavoidable when gas is flared (or, in limited circumstances, vented)
from a well that is not connected to gas capture infrastructure,
provided the BLM has not otherwise determined that the loss of gas is
avoidable, pursuant to the provisions of the 1,800 Mcf/month limit in
Sec. 3179.6. All losses of gas not specifically found to be
unavoidable would be considered avoidable and subject to royalties.
Thus, royalties would apply to associated gas flared from a development
well that is already connected to capture infrastructure. Under these
circumstances, operators have made an economic choice to flare, and
that flaring should not be considered an unavoidable consequence of oil
production.
Currently, there is a backlog of requests for approval to flare
royalty-free pending with the BLM. By establishing clear categories for
avoidable and unavoidable losses, and thus clarifying when gas may be
flared without payment of royalties, the BLM aims to reduce the number
of applications for approval to flare royalty-free and thereby reduce
the burden on both operators and the BLM. The BLM could then use these
administrative resources to process applications for permit to drill
and right-of-way applications, and to conduct inspections, among other
activities.
The costs and benefits of the flaring provisions are as follows.
First, the rule proposes to require the metering of flared volumes when
gas flaring meets or exceeds 50 Mcf/day for a flare stack or manifold.
We estimate compliance costs ranging from $1.0-1.8 million per year
when the capital costs of equipment are annualized with a 7 percent
discount rate, or $0.9-1.6 million per year when the capital costs of
equipment are annualized with a 3 percent discount rate.\32\
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\32\ RIA at 69.
For purposes of this analysis, we present costs and benefits
using discount rates of 7% and 3% to annualize the costs of capital
investments. OMB Circular A-94 (Revised) ``Guidelines and Discount
Rates for Benefit-Cost Analysis of Federal Programs,'' https://www.whitehouse.gov/omb/circulars_a094/, directs agencies to conduct
baseline analyses using a discount rate of 7%, which ``approximates
the marginal pretax rate of return on an average investment in the
private sector in recent years.'' It also recommends that agencies
show sensitivity of the discounted net present value and other
outcomes using additional discount rates. The BLM chose to use a
second discount rate of 3%, because the literature suggests that
there is a divergence between private discount rates (considered by
firms or industry) and social discount rates (considered by
society), with private rates exceeding social rates. Further, it is
common for regulatory impact analyses to analyze outcomes using a 3%
discount rate, particularly for the environmental benefits of
proposed regulations.
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We estimate that the proposed flaring limits, including the 3-year
phase-in period would affect an estimated 435-885 leases in any given
year. These requirements could pose total costs of about $32-68 million
per year (7 percent discount rate) or $26-43 million per year (3
percent discount rate). Because these requirements would drive
additional capture of gas, the flaring limits are also projected to
pose total cost savings (from the value of the captured gas) of about
$40-58 million per year (7 percent discount rate) or $40-64 million per
year (3 percent discount rate). We also estimate that they would
increase natural gas production by 2.5-5.0 Bcf per year, and increase
NGL production by 36-51 million gallons per year. The net benefits of
these requirements are estimated to range from negative $10 to positive
$8 million per year (7 percent discount rate) or $13-30 million per
year (3 percent discount rate).\33\
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\33\ RIA at 60.
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2. Leaks
One significant source of the 22 Bcf of gas vented from Federal and
Indian leases in 2013 is leakage. The BLM estimates that up to 4.35 Bcf
of natural gas was lost in 2013 as a result of leaks or other fugitive
emissions at operations on BLM-administered leases.\34\ Multiple
studies have found that once leaks are detected, the vast majority can
be repaired with a positive return to the operator. In addition, both
Colorado and Wyoming (for part of the State) have recently adopted LDAR
requirements for oil and gas production,\35\ and EPA has adopted and
proposed additional LDAR requirements for certain new and modified oil
and gas production sources.\36\
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\34\ RIA at 3.
\35\ Colorado Air Quality Control Commission Regulations,
Regulation 7, 5 CCR 1001-9, Section XVII.F; Wyoming, Nonattainment
Area Regulations Ch. 8, Section 6(g) (June 2015), available at
https://soswy.state.wy.us/Rules/RULES/9868.pdf.
\36\ Standards of Performance for Crude Oil and Natural Gas
Production, Transmission and Distribution, 60 CFR subpart OOOO; 80
CFR 56593, 56660-56698.
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The BLM believes that LDAR programs are a cost-effective means of
[[Page 6621]]
reducing waste in oil and gas production. We are proposing to require
operators to use an instrument-based approach to leak detection.
Operators would be required initially to conduct semi-annual
inspections at their well sites and compressor locations. If an
operator finds no more than 2 leaks at a facility for two consecutive
inspections, the operator may change to annual inspections at that
facility. If the operator finds more than 2 leaks at a facility for two
consecutive inspections, the operator must inspect for leaks quarterly.
If an operator that is required to inspect for leaks quarterly finds no
more than 2 leaks at a given facility in two sequential inspections,
the operator could then change back to semi-annual inspections, and so
forth. Once a leak is identified, the BLM proposes that the operator
would be required to repair the leak as soon as practicable, but no
later than 15 calendar days after discovery, absent good cause.
Operators would have to verify the effectiveness of a repair within 15
calendar days of the repair, using the same method used to detect the
leak. Operators would also be required to keep records documenting the
dates and results of leak inspections, repairs, and follow-up
inspections.
The costs and benefits of the BLM's proposed LDAR requirements
depend on the rest of the regulatory landscape. Assuming that the EPA
finalizes its 40 CFR part 60 subpart OOOOa rulemaking for new and
modified sources,\37\ then the BLM expects that its proposed
requirements would impact up to 36,700 existing wellsites, and pose
total costs of about $69-70 million per year (using 7 percent and 3
percent discount rates). These requirements are also projected to
result in cost savings of about $12-15 million per year (7 percent
discount rate) or $15-17 million per year (3 percent discount rate),
increase gas production by 3.9 Bcf per year, and reduce VOC emissions
by 18,600 tons per year (tpy). We estimate they would reduce methane
emissions by 67,000 tpy, producing monetized benefits of $73 million
per year in 2017-2019, $87 million per year in 2020-2024, and $100
million in 2025 and 2026. Thus, we estimate that these provisions would
result in net benefits of $19-21 million per year in 2017-2019, $31-35
million per year in 2020-2024, and $43-48 million in 2025 and 2026.\38\
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\37\ The RIA includes a broader discussion of the estimates of
the costs and benefits of this proposed rule if the EPA does not
finalize its 40 CFR part 60 subpart OOOOa rulemaking, but the
preamble omits some of those estimates to simplify the discussion.
EPA's proposed requirements would apply to wells that are new,
``modified,'' or ``reconstructed'' after September 18, 2015. See 40
CFR 60.14 and 60.15 for EPA's definitions of ``modification'' and
``reconstruction.''
\38\ RIA at 109.
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If, for analytical purposes we assume a baseline in which EPA does
not finalize its proposed LDAR requirements, we estimate the following
impacts. We project that the proposed LDAR requirements would affect up
to about 37,000-38,000 wellsites per year, and pose total costs of
about $70-71 million per year (using 7 percent and 3 percent discount
rates). These requirements are also projected to result in cost savings
of about $12-18 million per year (using 7 percent and 3 percent
discount rates), increase gas production by 3.9-4.0 Bcf per year, and
reduce VOC emissions by 19,000 tpy. We estimate these proposed
requirements would also reduce methane emissions by 68,000 tpy,
producing monetized benefits of $75 million per year in 2017-2019, $88
million per year in 2020-2024, and $102 million in 2025 and 2026. Thus,
we estimate that these proposed provisions would result in net benefits
of $19-21 million per year in 2017-2019, $30-35 million per year in
2020-2024, and $43-48 million in 2025 and 2026.\39\
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\39\ RIA at 108-109.
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These estimates represent the maximum likely impact. As noted
previously, some operators currently have LDAR programs. This analysis
accounts for existing State requirements in Colorado, Utah, and
Wyoming, but it does not account for existing (voluntary or required)
LDAR activities conducted by operators outside of those States. If we
accounted for these existing activities, then the costs, emissions
reductions, incremental production, and royalty estimates resulting
from this proposed rule would be less than those shown.
3. Pneumatic Controllers and Pneumatic Pumps
Pneumatic controllers and pneumatic pumps are operated by gas
pressure and emit gas as part of their normal operations. We estimate
that on BLM-administered leases in 2013, about 5.4 Bcf of natural gas
was lost from pneumatic controllers, and about 2.5 Bcf was lost from
all pneumatic pumps.\40\ Further, we estimate that the proposed rule
would impact up to 15,600 high bleed pneumatic controllers (pneumatic
controllers with bleed rates of more than 6 standard cubic feet per
hour (scf/hour)) on BLM-administered leases.\41\ A recent study by the
consulting firm ICF International (ICF) identified replacement of high-
bleed pneumatic controllers with low-bleed pneumatic controllers
(pneumatic controllers with bleed rates of 6 scf/hour or less) as one
of the most inexpensive options for reducing methane, estimating that
it would actually save industry $2.65 per Mcf of avoided methane
emissions.\42\
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\40\ RIA at 3.
\41\ RIA at 78.
\42\ ICF International, Economic Analysis of Methane Emission
Reduction Opportunities in the U.S. in the Onshore Oil and Natural
Gas Industries, 4-4 (Mar. 2014), available at https://www.edf.org/sites/default/files/methane_cost_curve_report.pdf (ICF 2014 Study)
(base case assumed $4/Mcf price for recovered gas and a 10 percent
discount rate/cost of capital).
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EPA generally prohibits the use of new high-bleed pneumatic
controllers,\43\ and Colorado and Wyoming (in part of the State) have
required replacement of existing high-bleed pneumatic controllers with
low-bleed pneumatic controllers.\44\ The State of Wyoming has
regulations that require pneumatic pumps used in the Upper Green River
Basin to destroy or capture emissions or be replaced by zero-emission
solar-, electric-, or air-driven pumps by January 1, 2017.\45\
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\43\ 40 CFR 60.5390.
\44\ Colorado Air Quality Control Commission Regulations,
Regulation 7, 5 CCR 1001-9, Section XVIII; Wyoming, Nonattainment
Area Regulations Ch. 8, Section 6(f) (June 2015), available at
https://soswy.state.wy.us/Rules/RULES/9868.pdf.
\45\ Wyoming, Nonattainment Area Regulations Ch. 8, Section 6(e)
(June 2015), available at https://soswy.state.wy.us/Rules/RULES/9868.pdf.
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The BLM is proposing to require operators to replace high-bleed
pneumatic controllers with low-bleed or no-bleed pneumatic controllers
within 1 year of the effective date of the final rule. This requirement
would apply only to pneumatic controllers that are not subject to EPA
regulations. The BLM also proposes exceptions to this requirement,
including where the operator demonstrates, and the BLM concurs, that
replacing the controller(s) would impose such costs as to cause the
operator to cease production and abandon significant recoverable oil
reserves under the lease. In making this determination, the BLM would
consider the costs of capture, and the costs and revenues of all oil
and gas production on the lease.
We estimate that the proposed pneumatic controller requirements
would impact up to about 15,600 existing low-bleed pneumatic devices,
and pose total costs of about $6 million per year (capital costs
annualized using a 7 percent discount rate) or $5 million per year
(capital costs annualized using a 3 percent discount rate). Because the
sale of recovered gas is expected to offset the engineering costs of
new controllers, the BLM expects that
[[Page 6622]]
compliance with the pneumatic controller requirements would increase
gas production by 2.9 Bcf per year, result in cost savings to the
industry of about $9-11 million per year (using a 7 percent discount
rate) or $11-12 million per year (using a 3 percent discount rate). On
net, we project that the industry would save $3-5 million per year
(using a 7 percent discount rate) or $6-7 million per year (using a 3
percent discount rate) under these requirements. These requirements are
also projected to reduce methane emissions by 43,000 tpy, producing
monetized benefits of $48 million per year in 2017-2019, $56 million
per year in 2020-2024, and $65 million in 2025 and 2026. The resulting
net benefits of $53-68 million per year (using a 7 percent discount
rate for costs and cost savings) or net benefits of $54-73 million per
year (using a 3 percent discount rate for costs and cost savings),
along with a reduction in VOC emissions of about 200,000 tpy.\46\
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\46\ Regulatory Impact Analysis (RIA) at 78.
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For pneumatic pumps, the BLM is proposing to require the operator
to either: (1) Replace a pneumatic chemical injection or diaphragm pump
with a zero-emissions pump; or (2) Route the pneumatic chemical
injection or diaphragm pump to a flare. This requirement would apply
only to pneumatic pumps that are not subject to EPA regulations. In
addition, an operator would be exempt from this requirement if it
demonstrates, and the BLM concurs, that: (1) There is no flare already
available on-site or routing to a flare device is technically
infeasible; and (2) A zero-emission pneumatic pump is not a viable
alternative to perform the required function. An operator would also be
exempt if the operator demonstrates and the BLM concurs that replacing
the pneumatic pump(s) would impose such costs as to cause the operator
to cease production and abandon significant recoverable oil reserves
under the lease. In making this determination, the BLM would consider
the costs of capture, and the costs and revenues of all oil and gas
production on the lease.
If the EPA finalizes its concurrent 40 CFR part 60 subpart OOOOa
rulemaking, the BLM estimates that these requirements would impact up
to 8,775 existing pumps, posing total costs of about $2.5 million per
year. They would also increase gas production by 0.46 Bcf per year and
result in cost savings of about result in cost savings of $1.5-1.9
million per year (7 percent discount rate) or $1.75-2.15 million per
year (3 percent discount rate). In addition, they are projected to
reduce methane emissions by about 16,000 tpy, producing monetized
benefits of $18 million per year in 2017-2019, $21 million per year in
2020-2024, and $24 million in 2025 and 2026. This would result in net
benefits of $17 million per year in 2017-2019, $20 million per year in
2020-2024, and $23 million in 2025 and 2026, as well as reducing VOC
emissions by about 4,000 tpy.\47\
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\47\ RIA at 82.
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Assuming, for purposes of analysis, that EPA does not finalize the
40 CFR part 60 subpart OOOOa rulemaking, the BLM estimates that the
pneumatic pump requirements would affect up to about 8,775 existing
pumps and about 75 new pumps per year, posing total costs of about
$2.5-2.7 million per year (using 7 percent and 3 percent discount
rates). They would also increase gas production by 0.5 Bcf per year and
result in cost savings of about $1.5-2.2 million per year (using 7
percent and 3 percent discount rates). In addition, they are projected
to reduce methane emissions by about 16,000-17,000 tpy, producing
monetized benefits of $18 million per year in 2017-2019, $22 million
per year in 2020-2024, and $26 million in 2025 and 2026. This would
result in net benefits of $17 million per year in 2017-2019, $21-22
million per year in 2020-2024, and $25 million in 2025 and 2026, as
well as reducing VOC emissions by about 4,000 tpy.\48\
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\48\ RIA at 81.
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4. Storage Vessels
Vapors released from storage vessels are a lost source of energy
and revenue, present safety concerns, and contribute to local air
pollution and climate change. We estimate that 2.77 Bcf of natural gas
was lost in 2013 from storage tank venting on Federal and Indian
lands.\49\ Of that volume, we estimate that 1.82 Bcf was lost from
storage vessels used in natural gas production and 0.95 Bcf of gas was
lost from storage vessels used in oil production.\50\
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\49\ RIA at 3.
\50\ RIA at 19.
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Tank vapors can be controlled by routing them to a flare or
combustor, or by installing a vapor recovery unit (VRU). New and
modified vessels used in oil and gas production are already subject to
EPA emissions limits, which require that individual storage vessels
with VOC emissions equal to or greater than 6 tpy achieve at least a 95
percent reduction in VOC emissions from baseline levels. Colorado and
part of Wyoming have similar, somewhat more stringent, requirements for
storage vessels.\51\
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\51\ Colorado Air Quality Control Commission Regulations,
Regulation 7, 5 CCR 1001-9, Sections XII.D-F; XVII.C; Wyoming,
Nonattainment Area Regulations Ch. 8, Section 6(c) (June 2015),
available at https://soswy.state.wy.us/Rules/RULES/9868.pdf.
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The BLM proposes to address gas losses from existing storage
vessels, which are not covered by the EPA standards. The BLM believes
that reducing venting from existing storage vessels, which have higher
rates of venting, is a reasonably cost-effective means of reducing gas
losses. Rather than establishing new and separate standards for venting
from existing vessels, we have been informed by operators that it would
be easier to comply if we simply require existing vessels on BLM-
administered leases to meet standards that are the same as the EPA
standards that already apply to new and modified vessels on those
leases. Additionally, there does not appear to be a uniform conversion
factor that we could use to translate the VOC standards established by
EPA, Colorado, and Wyoming to a whole gas standard. Depending on the
content of a vessel, the same quantity of gas released from the vessel
may contain different quantities of VOCs. Thus, even though the BLM is
concerned about loss of all hydrocarbons from vessels, not just loss of
VOCs, we propose to use VOCs as a proxy for whole gas, and thus to
apply the control requirement to existing vessels with at least 6 tpy
of VOCs, using the same applicability threshold as EPA and
Colorado.\52\ (Wyoming also uses VOC emissions to determine
applicability, but has a lower threshold.\53\)
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\52\ 40 CFR 60.5395; Colorado Air Quality Control Commission
Regulations, Regulation 7, 5 CCR 1001-9, Section XVII.C.
\53\ Wyoming, Nonattainment Area Regulations Ch. 8, Section
6(c)(i)(a) (June 2015), available at https://soswy.state.wy.us/Rules/RULES/9868.pdf.
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The BLM proposes to require that operators route VOC emissions from
existing storage vessels subject to these requirements to combustion
devices, continuous flares, or sales lines within 6 months after the
effective date of the rule. The BLM would grant an exception to this
requirement if the operator submits an economic analysis
demonstrating--and the BLM agrees--that compliance would impose such
costs as to cause the operator to cease production and abandon
significant recoverable oil reserves under the lease. In making this
determination, the BLM would consider the costs of capture, and the
costs and revenues of all oil and gas production on the lease.
Consistent with the EPA requirements for new vessels,
[[Page 6623]]
these requirements would no longer apply if the uncontrolled VOC
emissions fall below 4 tpy for 12 months.
The BLM estimates that the proposed requirements would affect about
300 existing storage vessels on BLM-administered leases, and pose total
costs of about $6 million per year (using 7 percent and 3 percent
discount rates).\54\ We project that these requirements would increase
gas production by 0.04 Bcf per year, resulting in cost savings of about
$0.1-0.2 million per year (using 7 percent and 3 percent discount
rates). They would also reduce methane emissions by 7,000 tpy,
producing monetized benefits of $8 million per year in 2017-2019, $9
million per year in 2020-2024, and $11 million in 2025 and 2026.
Overall, we estimate that these provisions would result in net benefits
of $2 million per year in 2017-2019, $3-4 million per year in 2020-
2024, and $5 million in 2025 and 2026, and reduce VOC emissions by
32,500 tpy.
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\54\ RIA at 95.
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5. Well Maintenance and Liquids Unloading
Over time, as pressure in a natural gas well drops, liquids often
start accumulating at the bottom of the well, impeding gas production.
Operators often remove or ``unload'' the liquids, but depending on the
method, this process can release substantial quantities of natural gas
into the environment. In particular, operators may allow the bottom-
hole pressure to increase and then vent or ``blow down'' or ``purge''
the well. We estimate that 3.26 Bcf of natural gas was lost in 2013
during liquids unloading operations on Federal and Indian lands.\55\
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\55\ RIA at 3.
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There are a wide variety of methods for liquids unloading, and
technological developments, such as automated plunger lifts, now allow
liquids to be unloaded with minimal loss of gas. The BLM believes that
it is reasonable to expect operators to use these available
technologies to minimize gas losses, and we believe that failure to
minimize losses of gas from liquids unloading now constitutes waste.
For wells drilled after the effective date of the rule, the BLM is
proposing to prohibit unloading liquids by simply purging the well
(except in specified circumstances). The BLM believes that it is less
costly to avoid purging altogether at new wells than at existing wells.
In addition, the BLM is proposing to require specified best management
practices to minimize venting from liquids unloading at both new and
existing wells. Specifically, the operator would be required to be on-
site during well purging events, unless the well has an automatic
control system, and the operator would also be required to document
liquids unloading events. This would allow the BLM to verify
compliance, and it would provide additional information on the amounts
of gas lost through these activities on Federal and Indian lands.
We estimate that the proposed liquids unloading requirements would
affect up to about 1,550 existing wells and about 25 new wells per
year, posing total costs of about $6 million per year (capital costs
annualized using a 7 percent discount rate) or $5-6 million per year
(capital costs annualized using a 3 percent discount rate). We project
that they would increase gas production by roughly 2 Bcf per year,
resulting in cost savings of about $7-8 million per year (using a 7
percent discount rate) or $7-10 mil
