UNITED STATES ENVIRONMENTAL PROTECTION AGENCY 

White Papers on 

Methane and VOC Emissions 

in the Oil and Natural Gas Sector 

) 

) 

) 

) 

) 

) 

Via email to oilandgas.whitepapers@epa.gov 

June 16, 2014 

Submitted on behalf of the Sierra Club, Natural Resources Defense Council, Clean Air Task 

Force, and Earthworks. 
Table of Contents 

I. Introduction ................................................................................................................. 1

II. Scientific and Legal Background ................................................................................ 4

A. Methane Is A Harmful Air Pollutant ....................................................................... 4

B. Atmospheric Measurements Indicate That the White Papers Drastically Understate 

Oil and Gas Methane Emissions ..................................................................................... 5

C. If Oil and Gas Production Continues to Increase, the Need for Action to Address 

Methane Emissions Will Likewise Increase ................................................................... 7

D. The Clean Air Act’s Section 111 Performance Standards Program .................... 7

i. Summary of EPA’s 2012 NSPS ............................................................................ 7

ii. Section 111 and Costs .......................................................................................... 8

III. Comments on the Compressor White Paper ............................................................... 9

A. Introduction .............................................................................................................. 9

B. Anticipated Emission Reductions from EPA’s 2012 NSPS .................................. 10

C. Control Measures for Compressors Not Covered Under the 2012 NSPS: 

Anticipated Emission Reductions Based On Data Available to EPA In 2012 ............. 12

i. Methane Abatement Opportunities for Existing Reciprocating Compressors ... 14

ii. Methane Abatement Opportunity for Existing Centrifugal Compressors. ......... 17

iii. Methane Abatement Opportunity for New Compressors That Were Not 

Regulated in the Final Rule for the 2012 NSPS. ...................................................... 20

D. Control Measures for Compressors Not Covered Under the 2012 NSPS: 

Anticipated Emission Reductions Based On 2014 Inventory Data. ............................. 21

E. Summary ................................................................................................................ 22

F. Responses to Charge Questions ............................................................................. 23

IV. Comments on Pneumatic Devices White Paper..................................................... 24

A. Introduction ........................................................................................................ 24

B. Emissions from Pneumatic Controllers are Substantial, and Underestimated in 

Available Data .............................................................................................................. 25

i. Emissions from PCs in the Oil and Gas Production Segments .......................... 25

ii. Emissions from PCs in the Natural Gas Transmission and Storage Segments.

 27

C. The Methane Abatement Potential from Controlling Emissions at High- and 

Intermittent-Bleed PCs is Substantial ........................................................................... 27

D. Control Costs to Convert Existing High-Bleed Pneumatic Controllers to LowBleed Devices ............................................................................................................... 31

E. Device Classification Issue in the 2013 Prasino Group Study .............................. 32

F. Summary ................................................................................................................ 34
G. Charge Questions for Reviewers ........................................................................ 34

V. Comments on the Liquids Unloading White Paper .................................................. 36

A. Emissions from Liquids Unloading ....................................................................... 37

B. Available Control Technologies ............................................................................ 40

C. Abatement of Emissions from Wells Currently Unloading with Blowdowns ....... 41

D. Abatement from Wells Already Using Plunger Lifts ......................................... 42

E. Responses to Charge Questions ............................................................................. 43

VI. Leaks ......................................................................................................................... 43

A. Critical Synthetic Conclusions ................................................................................ 45

i. Methane Emissions from Oil and Gas are Underestimated by the 2014 

Inventory, and Available Evidence Implicates Leaks ............................................... 45

B. Costs for LDAR Programs are Very Reasonable ............................................... 46

C. Charge Questions for Reviewers ............................................................................ 47

VI. Oil Wells ..................................................................................................................... 51

A. Oil Wells Produce Gas, Which Can Be Managed by Capture or Combustion ...... 51

B. Gas Emissions During Oil Well Completion ......................................................... 54

i. Oil Well Completion Emission Factor ............................................................... 54

ii. Oil Well Completion Activity Factor .................................................................. 56

iii. Oil Well Completion Control Technologies ................................................... 57

iv. Gas Emissions During Oil Well Production................................................... 59

v. Alternatives to Flaring ....................................................................................... 59
1 

UNITED STATES ENVIRONMENTAL PROTECTION AGENCY 

White Papers on 

Methane and VOC Emissions 

in the Oil and Natural Gas Sector 

) 

) 

) 

) 

) 

) 

Via email to oilandgas.whitepapers@epa.gov 

June 16, 2014 

Thank you for accepting these comments on EPA’s white papers regarding methane and VOC 

emissions in the oil and natural gas sector, released April 15, 2014. We submit these comments 

on behalf of the Sierra Club, Natural Resources Defense Council, Clean Air Task Force, and 

Earthworks (“Commenters”). 

I. Introduction 

EPA’s five white papers demonstrate that the oil and gas sector emits enormous amounts of 

harmful methane and that timely action by EPA could significantly curtail these emissions. Most 

importantly, the white papers support action by EPA directly regulating methane from this source 

category under Section 111 of the Clean Air Act, including both existing and new or modified 

sources. Only through such an approach can EPA maximize the available reductions in methane 

emissions from this sector and meet the Obama Administration’s climate goals. 

Avoiding many of the impacts brought on by climate change will require dramatic reductions in 

greenhouse gas emissions, including methane. The Intergovernmental Panel on Climate Change 

(“IPCC”) recently affirmed that to avoid catastrophic warming of 2° C or greater, the U.S. 

mustreduce total greenhouse gas emissions, relative to 2005, by at least 17% by 2020, 42% by 

2030, and 83% by 2050—targets President Obama announced in Copenhagen in 2009 and 
2 

committed to in Cancun in 2010.1 The most optimistic projections from EPA and the Energy 

Information Administration (“EIA”) of the current trajectory of U.S. greenhouse gas emissions in 

2020 exceed the Administration’s target level by over 800 MMT CO2e

2

. Garnering all achievable 

methane reductions from the oil and gas sector is therefore critical to reaching the initial 17% 

reduction target, and a necessary complement to the recent carbon dioxide standards for power 

plants towards this end. Furthermore, it is clear from existing pollution levels that voluntary 

measures will be insufficient. 

Methane, an extremely potent climate change pollutant, is the second most emitted greenhouse 

gas in the EPA’s 2014 Greenhouse Gas Inventory.This source, estimates that in 2012, the U.S. 

emitted 29.8 million tons of methane,3

 which EPA concludes represents 9% of total US 

greenhouse gas emissions in terms of carbon-dioxide equivalent (CO2e).4 The oil and gas 

industry, in turn, is among the nation’s top three industrial contributors to human-made climate 

pollution. According to the 2014 Inventory, this sector produces approximately 161.6 MMT of 

CO2-equivalent in methane each year through venting and leaking,5 making it the largest source 

of anthropogenic methane pollution in the U.S. 

Importantly, the actual impact of this pollution is much higher than indicated in the Inventory, 

which understates both the potency of methane and the amount of methane emitted by the oil and 

gas sector, as we explain below. Even accepting the Inventory’s figures, however, it is clear that 

direct regulation of methane is critical. Such action will have co-benefits outside of those related 

to climate change, as methane also causes harms distinct from those directly related to climate 

change—for example, methane increases smog-forming ozone, which negatively impacts human 

respiratory and cardiovascular health and damages crops and vegetation. Additionally, methane is 

 

1

See, e.g., IPCC, Fifth Assessment Report, Working Group 3: Summary for Policymakers (2014) 

at 13 available at http://report.mitigation2014.org/spm/ipcc_wg3_ar5_summary-forpolicymakers_approved.pdf; see also United States Department of State, Letter to Executive 

Secretary of United Nations Framework Convention on Climate Change Confirming US 

Copenhagen Targets, (Jan. 28, 2010), available at 

https://unfccc.int/files/meetings/cop_15/copenhagen_accord/application/pdf/unitedstatescphaccor

d_app.1.pdf, and United States Framework Convention on Climate Change, Compilation of 

economy-wide emission reduction targets to be implemented by Parties included in Annex I to 

the Convention (June 7, 2011), available at 

http://unfccc.int/resource/docs/2011/sb/eng/inf01r01.pdf. 

2

 This estimate was calculated from table 5-1 in the United States Climate Action Report, 

available at http://www.state.gov/e/oes/rls/rpts/car6/ and adjusted with global warming potentials 

from IPCC’s Fourth Assessment Report, in accordance with the “Key Parameters of the U.S. 

Economy-wide Emission Reduction Targets” spelled out in Table 1 of the First Biennial Report 

of the United States of America, available at 

http://www.state.gov/documents/organization/219039.pdf. 

3

 EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012 (Apr. 2014) (“2014 

Inventory”), Table ES-2 (estimating 567.3 Tg CO2e from CH4), available at

http://epa.gov/climatechange/Downloads/ghgemissions/US-GHG-Inventory-2014-ChapterExecutive-Summary.pdf. This table uses a 100-year methane GWP of 21, indicating 27 Tg (or 

million metric tons) of methane. In this comment, we express units in short tons unless otherwise 

specified. 27 million metric tons is equivalent to 29.8 million short tons. 

4

Id. at Table 2-1, available at http://www.epa.gov/climatechange/Downloads/ghgemissions/USGHG-Inventory-2014-Chapter-2-Trends.pdf. 

5

Id.
3 

emitted along with other smog- and particulate-forming co-pollutants as well as hazardous 

substances. Measures to reduce methane emissions from oil and gas systems will also help curb 

emissions of these co-pollutants. 

The last seven years have shown that the Clean Air Act is an appropriate and necessary means of 

reducing the threat of climate change by cutting greenhouse gas emissions. After the Supreme 

Court recognized in Massachusetts v. EPA, 549 U.S. 497, 528-29 (2007) that greenhouse gases 

are air pollutants covered under the Clean Air Act, EPA responded by determining that 

greenhouse gases, including methane, endanger public health and welfare. See 74 Fed. Reg. 

66,496 (Dec. 15, 2009). The Supreme Court further confirmed that section 111 of the Clean Air 

Act is an appropriate pathway to reduce greenhouse gas emissions from stationary sources. Am. 

Elec. Power Co. (“AEP”) v. Connecticut, 131 S.Ct. 2527, 2537-39 (2011). Noting that this 

section of the statute directs EPA to list particular “categories of sources” that, in the Agency’s 

judgment, “caus[e], or contribut[e] significantly to, air pollution which may reasonably be 

anticipated to endanger public health or welfare...”, the Court acknowledged in AEP that section 

111 requires “standards of performance” for pollutants emanating from sources in a listed 

category. Id. This duty entails performance standards for both new sources under 111(b) and 

existing sources under 111(d). See 42 U.S.C. § 7411(b) and (d).6

Although the Court in AEP v. Connecticut focused specifically on section 111 regarding CO2

emissions from power plants, the logic of that holding extends to all industrial sources of GHG 

pollution, and the oil and gas sector is, like power plants, a listed source category that is already 

regulated under section 111. EPA acknowledged in the 2012 rulemaking that the oil and gas 

sector emits significant levels of methane; as we discuss in these comments, reasonable cost 

controls are available to curb those emissions. For these reasons, EPA must set methane standards 

and guidelines for the oil and gas sector under Sections 111(b) and (d) of the Clean Air Act. 

Indeed, the urgent need for methane regulations was evident in information presented to the 

agency in 2011 and 2012, during its mandatory review of section 111 performance standards for 

the oil and gas industry that resulted in the 2012 NSPS for VOC emissions. The five white papers 

that EPA released in April of this year and the studies summarized therein overwhelmingly affirm 

this conclusion. Specifically, these papers demonstrate that: 

• Numerous sources of methane emissions in the oil and gas sector, including those for 

which the 2012 NSPS does not prescribe performance standards, are significant sources 

of methane emissions; 

• Available control technologies can substantially reduce these methane emissions; and 

• Costs for these control technologies are reasonable. 

Accordingly, EPA can and must take action now to control methane emissions from oil and gas 

industry sources directly. As the IPCC has repeatedly admonished, acting now will be more 

effective and cheaper than acting later.7

 

6

 Under section 111(b), EPA issues direct regulations of the new sources in the regulated 

category. Under 111(d), the agency provides mandatory emission guidelines that states then use 

to develop regulations for existing sources. 

7

See, e.g., IPCC, supra n. 1, at 13-14. 
4 

Uncertainty regarding the exact amount of methane emissions from the oil and gas sector in no 

way justifies EPA’s delay in regulating these emissions. As we discuss below, the studies cited in 

the white papers may differ in their exact estimates of emissions from particular components, and 

studies using atmospheric measurements of methane (which were generally not discussed in the 

white papers) provide significantly higher estimates of total methane emissions from natural gas 

systems. Nevertheless, while there may be uncertainty as to precisely how much methane the 

sector emits, there is no uncertainty on the issues EPA must resolve in setting section 111 

standards: whether the amount of methane is significant enough to warrant regulation under 

section 111 and whether there are available technologies to reduce these emissions at reasonable 

costs. 

For the reasons stated below, EPA must act, and act now, to propose section 111(b) and (d) 

standards and guidelines for methane emissions from (at a minimum) each of the sources 

discussed in the white papers. 

II. Scientific and Legal Background 

A. Methane Is A Harmful Air Pollutant 

Methane is a highly potent greenhouse gas: in its most recent climate assessment, the IPCC 

estimates that fossil methane has a 100-year global warming potential (GWP) of 36, meaning that 

one ton of methane warms the Earth’s climate as much as 36 tons of carbon dioxide over a 100-

year time period. For a twenty year time frame, the GWP of fossil methane is 87.8

 This estimate 

represents the current consensus of the scientific community based on the latest research. In 

contrast, EPA’s inventories still use a 100-year GWP for methane, including fossil methane, of 

21. This value has been out of date since 20019

 and does not reflect the research that has been 

conducted in the intervening time. In addition, methane is an ozone precursor;10 as such, it 

contributes to the formation of smog, which causes significant human health impacts (including 

asthma attacks, respiratory disease, heart attacks, and premature death) and can destroy crops and 

vegetation. 

Although a comprehensive estimate of the social cost of methane has not yet been developed, a 

peer-reviewed analysis by EPA economists recently estimated the figure at $880 per short ton for 

the year 2015, assuming an annual discount rate of 3%.11 This figure was derived using the same 

methodology as used for the estimates of the social cost of carbon (“SCC”), building on work 

developed over several years and recently updated by the Interagency Working Group on the 

Social Cost of Carbon. While this research presents an important starting point, subsequent 

research indicates that it is too low. In particular, since this paper’s publication, estimates of two

inputs to this study—methane’s global warming potential and the social cost of carbon—have 

been revised dramatically upward. This study used IPCC’s fourth assessment report’s estimates 

of methane’s global warming potential, but as noted above, the IPCC’s fifth assessment report 

 

8

IPCC, Climate Change 2013: The Physical Science Basis (Sept. 2013), Chapter 8, page 714, 

Table 8.7, available at https://www.ipcc.ch/report/ar5/wg1/. 

9

 IPCC’s Third Assessment report updated the 100-yr GWP for methane (to 23) in 2001, and it 

was subsequently updated, increasing each time, in 2007 and 2014. 

10 See 76 Fed. Reg. 52,738, 52,791 (Aug. 23, 2011). 

11 See Marten, A.L., and Newbold, S.C., Estimating the social cost of non-CO2 GHG emissions: 

Methane and nitrous oxide, 51 Energy Policy 957 (2012), attached as Ex. 1.
5 

increased the estimate of methane’s 100-year global warming potential by 44%.12 Similarly, in 

2013 the federal Interagency Working Group increased its estimates of the social cost of carbon, 

using the same 3% annual discount rate, by 50%.13 While the 2013 Interagency Working Group 

estimates of the SCC represent the most comprehensive analysis of this issue conducted thus far, 

Sierra Club, NRDC, and other environmental organizations have commented elsewhere that even 

these SCC figures significantly underestimate the true social cost of carbon, possibly by several 

orders of magnitude.14 For these reasons, the true social cost of methane likely exceeds the cited 

figure of $880 per short ton. 

B. Atmospheric Measurements Indicate That the White Papers Drastically Understate 

Oil and Gas Methane Emissions 

The studies reviewed in the white papers generally estimate aggregate emissions using “bottomup” methods. These methods use an estimate of the average emissions from an individual piece of 

equipment or individual event, such as a high-bleed pneumatic device or a well completion, and 

multiply that per-component value by an estimate of the total number of components or events of 

that type. A different method of estimating oil and gas sector methane emissions is a “top down” 

approach, where researchers measure the methane accumulation in the atmosphere in areas where 

oil and gas activity is occurring and then estimate the fraction of this methane attributable to 

emissions from oil and gas activity. For example, a researcher might measure methane 

concentrations upwind and downwind of gas activity and then subtract out the methane estimated 

to have been emitted from other sources. Certainty in source attribution has increased in recent 

years as scientists are better able to distinguish methane sources based on detected levels of cooccurring compounds such as ethane or isotopic composition of atmospheric methane. 

In the last two years, peer-reviewed publications utilizing top-down techniques to estimate 

methane emissions from oil and gas, have proliferated, and these studies provide compelling 

evidence that the aggregate methane emission estimates based on “bottom up” studies (such as 

those discussed in the white papers) underestimate oil and gas sector methane emissions by a 

significant margin. Two recent studies addressed natural gas’s lifecycle methane emissions 

 

12 Compare id. at 13 (citing Interagency Working Group on Social cost of Carbon, Technical 

Support Document: Social Cost of Carbon for Regulatory Impact Analysis Under Executive 

Order 12866 (Feb. 2010)), available at

http://www.whitehouse.gov/sites/default/files/omb/inforeg/for-agencies/Social-Cost-of-Carbonfor-RIA.pdf) with Interagency Working Group on Social Cost of Carbon, United States 

Government, Technical Support Document: Technical Update of the Social Cost of Carbon for 

Regulatory Impact Analysis Under Executive Order 12866 (Nov. 2013) at 3, available at 

http://www.whitehouse.gov/sites/default/files/omb/assets/inforeg/technical-update-social-cost-ofcarbon-for-regulator-impact-analysis.pdf. The 2013 estimates are 50% higher for emissions in

2010, with greater percentage increases in subsequent years. 

13 Id. at 16 (referencing IPCC AR4 GWPs). 

14 See Sierra Club, Comments on the Interagency Working Group’s (IWG) Technical Support 

Document: Social Cost of Carbon (SCC) for Regulatory Impact Analysis Under Executive Order 

12866 (Docket Not. OMB-2013-0007-0083) (Feb. 25, 2014), available at

http://www.regulations.gov/#!documentDetail;D=OMB-2013-0007-0083; EDF, NRDC, et al., 

Comments on the Interagency Working Group’s (IWG) Technical Support Document: Social Cost 

of Carbon (SCC) for Regulatory Impact Analysis Under Executive Order 12866 (Docket No. 

OMB-2013-0007-0140) (Feb. 26, 2014), available at

http://www.regulations.gov/#!documentDetail;D=OMB-2013-0007-0140.
6 

nationwide. The first, published by Scot M. Miller, et al., reviewed atmospheric measurements of 

methane and concluded that “[t]he US EPA recently [in the 2013 Greenhouse Gas Inventory] 

decreased its [methane] emission factors for fossil fuel extraction and processing by 25–30% (for 

1990–2011), but we find that [methane] data from across North America instead indicate the need 

for a larger adjustment of the opposite sign.”15 Specifically, Miller, et al. conclude that 

atmospheric measurements show that methane emissions from all sources were 50% higher than 

the 2013 Inventory’s bottom-up estimate of emissions. They show that oil and gas emissions are a 

significant portion of the observed emissions not accounted for in EPA’s Inventory, and suggest 

that the actual leak rate is likely to be 3% or more.16 The second, published by Adam Brandt, et 

al., similarly concluded that EPA’s Inventory and other bottom-up estimates significantly 

underestimate methane emissions from oil and gas production.17

These nationwide studies stand in agreement with atmospheric studies examining individual 

regions, which have found even higher methane emissions in the regions studied. Two studies of 

Colorado’s Denver-Julesberg Basin have concluded that during gas production alone (not 

including emissions from downstream segments of the industry - transmission and distribution), 

the gas leak rate was about 4%.18 The same team of researchers found even higher methane leak 

rates in Utah’s Uinta Basin, estimating escaped methane at 9 ± 3% of total production.19

What these top-down studies uniformly indicate is that the estimates of oil and gas methane 

emissions surveyed in the white papers are too low. This means, in turn, that action to address 

methane emissions is even more vital, and that the potential for total abatement is even greater 

than what would be supported by the white papers’ cited literature alone. 

 

15 See, e.g., Miller, S., et al., Anthropogenic emissions of methane in the United States, 

Proceedings of the National Academy of Sciences (Dec. 10, 2013) (“PNAS Study”), at 20,022, 

available at http://calgem.lbl.gov/Miller-2013-PNAS-US-CH4-Emissions-9J5D3GH72.pdf. 

16 Specifically, the paper states that in moving from the 2012 Inventory to the 2013 Inventory, 

EPA “decreased its CH4 emission factors for fossil fuel extraction and processing by 25–30% 

(for 1990–2011), but we find that CH4 data from across North America instead indicate the need 

for a larger adjustment of the opposite sign.” Id. The 2012 Inventory implied a leak rate of 

approximately 2.4%; a 25% increase brings the leak rate to 3%. 

17Brandt, A.R., et al., Methane Leaks from North American Natural Gas Systems, Science, Vol. 

343, no. 6172 at pp. 733-735 (Feb. 14, 2014), available at 

http://www.novim.org/images/pdf/ScienceMethane.02.14.14.pdf. 

18 The 4% estimate is provided by the more recent of these studies, Petron, et al., A new look at 

methane and non-methane hydrocarbon emissions from oil and natural gas operations in the 

Colorado Denver-Julesburg Basin, 119:9 J. Geophys. Res. Atmospheres (June 3, 2014). abstract 

available at http://onlinelibrary.wiley.com/doi/10.1002/2013JD021272/abstract. This is 

consistent with an earlier study, by the same lead author, which estimated using top-down 

techniques that 2.3 to 7.7% of production was vented in the studied and concluded more generally 

that “the methane source from natural gas systems in Colorado is most likely underestimated by 

at least a factor of two.” Petron, et al., Hydrocarbon emissions characterization in the Colorado 

Front Range: A pilot study, 117:D4 J. Geophys. Res. Atmospheres 4304 (Feb. 21, 2012), abstract 

available at http://onlinelibrary.wiley.com/doi/10.1029/2011JD016360/abstract. 

19 Karion, et al., Methane emissions estimate from airborne measurements over a western United 

States natural gas field, 40:16 Geophysical Research Letters 4393 (Aug. 27, 2013), abstract 

available at http://onlinelibrary.wiley.com/doi/10.1002/grl.50811/abstract. See also J. Tollefson, 

Methane leaks erode green credentials of natural gas, Nature (Jan. 2, 2013), available at 

http://www.nature.com/news/methane-leaks-erode-green-credentials-of-natural-gas-1.12123. 
7 

C. If Oil and Gas Production Continues to Increase, the Need for Action to Address 

Methane Emissions Will Likewise Increase 

Over the course of the last decade, the development of new techniques to extract oil and gas, 

including hydraulic fracturing and horizontal drilling, have opened unconventional sources of 

hydrocarbons to development, such as shale gas, tight gas, and coalbed methane. As a result, gas 

and oil production have increased significantly in recent years. Some analysts anticipate a 

continuation of this trend; for example, EIA’s Annual Energy Outlook report for 2014 projects 

increases in production of both oil and natural gas in the coming decades.20 Our energy needs 

should instead be met through increasing reliance on other options, including renewable energy 

(wind and solar), energy efficiency and others; however, any increase in oil and natural gas 

production that does occur will only strengthen the need for EPA to stringently control methane. 

D. The Clean Air Act’s Section 111 Performance Standards Program 

As mentioned above, section 111 of the Clean Air Act requires EPA to set technology-based 

“standards of performance” for listed “categories of sources” of air pollution. 42 U.S.C. § 7411. 

Such standards of performance must 

reflect[] the degree of emission limitation achievable through the application of 

the best system of emission reduction which (taking into account the cost of 

achieving such reduction and any nonair quality health and environmental impact 

and energy requirements) the Administrator determines has been adequately 

demonstrated. 

Id. § 7411(a)(1). Congress’ intent behind section 111 performance standards was “to induce, to 

stimulate, and to augment the innovative character of industry in reaching for more effective, less 

costly systems to control air pollution.” Sierra Club v. Costle, 657 F.2d 298, 347 n.174 (D.C. Cir. 

1981 (quoting legislative history). Once the standards for a particular source category are 

established, EPA “shall, at least every 8 years, review and, if appropriate, revise such standards 

following the procedure required by [section 111(b)].” 42 U.S.C. § 7411(b)(1)(B). EPA has long 

interpreted this “appropriateness” determination to turn on only two factors: 1) the amount of 

emissions of a given pollutant from that sources category; and 2) the availability of demonstrated 

control measures. See, e.g., 50 Fed. Reg. 36,959, 36,961 (Sept. 10, 1985) (making negative 

determination based on lack of demonstrated control technology); 75 Fed. Reg. 54,994–95 (Sept. 

9, 2010) (making positive determination based on significant emissions and existence of 

demonstrated control technology). See also Nat’l Lime Ass’n v. EPA, 627 F.2d at 426 n. 27 

(discussing these factors). As such, EPA must regularly (but no less often than every 8 years) 

review source categories to ensure that the existing performance standards reflect the current and 

most innovative state of that industry’s technological capabilities to reduce emissions from all 

pollutants. 

i. Summary of EPA’s 2012 NSPS 

Despite this charge, EPA stopped short when it finalized revisions to the oil and gas sector’s 

NSPS in 2012. 40 C.F.R. §§ 60.5360-60.5430; see also 77 Fed. Reg. 49,489 (August 16, 2012). 

Namely, EPA failed to issue standards that reflect the maximum degree of methane reduction that 

 

20 EIA, Annual Energy Outlook (May 2014), Table 14: Oil and Gas Supply, available at

http://www.eia.gov/forecasts/aeo/excel/aeotab_14.xlsx.
8 

was achievable considering the sector as a whole, choosing instead to focus on VOC emissions 

and reductions and to consider methane only as a co-benefit of the VOC standards. The resulting 

regulations cover only a small portion of the methane emission sources that exist throughout the 

oil and gas sector. This approach resulted in two significant omissions. 

First, EPA’s 2012 NSPS omits sources in the transmission and storage segment, where VOC 

emissions are low relative to methane because impurities are removed during gas processing. For 

example, only new compressors located between the wellhead and the transmission and storage 

segment are covered by the rule. 40 C.F.R. §60.5365(b). Compressors located at a well site or 

anywhere in the transmission and storage segments, and all existing compressors regardless of 

location, are currently exempt from regulation under the 2012 NSPS. The final rule applies the 

same limitation on covered sources by location and segment for pneumatic controllers. Id. § 

60.5365(d). Second, because EPA arguably is not required to set emission guidelines for VOCs 

under section 111(d), the 2012 NSPS omit all existing equipment, which accounts for the vast 

majority of the sector’s methane pollution. 

ii. Section 111 and Costs 

Section 111(a)(1) directs EPA to “take into account” the cost of achieving reductions and any 

nonair quality health and environmental impacts and energy requirements when establishing 

performance standards for a category of sources. 42 U.S.C. § 7411(a)(1). Over several decades, 

the D.C. Circuit has fleshed out the meaning of this directive and determined that control costs 

must simply be “reasonable”—that is, they must not be “exorbitant” or too expensive for the 

industry to absorb in order to survive. For instance, in Essex Chem. Corp., 486 F.2d 427, 433 

(D.C. Cir. 1973) (holding that section 111 standards must be “reasonably reliable, reasonably 

efficient, and . . . reasonably . . . expected to serve the interests of pollution control without 

becoming exorbitantly costly in an economic or environmental way.” 486 F.2d at 433 (emphasis 

added). Similarly, in Portland Cement Association v. Train, 513 F.2d 506, 508 (D.C. Cir. 1975), 

the court upheld EPA’s interpretation that section 111’s cost inquiry functions as a safety valve to 

ensure that the costs an NSPS imposes are not “greater than the industry could bear and survive,” 

but would instead allow industry to “adjust” in a “healthy economic fashion to the end sought by 

the Act as represented by the standards prescribed.” See also Lignite Energy Council v. EPA, 198 

F.3d 930, 933 (D.C. Cir. 1999) (“EPA’s choice [of BSER] will be sustained unless the 

environmental or economic costs of using the technology are exorbitant.”). 

The measures we discuss below would not only easily meet section 111’s cost criteria, but would 

actually generate net profits for operators in most instances. Indeed, some industry actors are 

taking this issue seriously and voluntarily adopting methane controls such as those discussed in 

these comments. However, a variety of market conditions disincentive or inhibit companies from 

maximizing the available opportunities to reduce methane. These conditions include diverse 

ownership of the different parts of the system, ownership transfer of the gas moving through the 

system, higher rates of return from other investments, lack of knowledge of best practices, lack of 

incentive by independent contractors, or a simple lack of interest. Collectively, these factors result

in a market failure with respect to methane, and regulations must be established to prevent the 

resulting wasteful and harmful pollution. Ultimately, such actions will not only provide climate 

and other environmental and health benefits, but they will generate profits for the sector as a 

whole. 

In the sections that follow, we provide comments on each of the white papers in turn. As our 

analysis makes clear, direct regulation of existing sources of methane in the oil and gas industry, 

as well as new sources not covered in the 2012 NSPS rule, are not only warranted, but are critical. 
9 

Without these controls, a critical group of GHG emitters will remain unregulated and the threat of 

climate change will only increase. 

III. Comments on the Compressor White Paper 

A. Introduction 

Compressors are mechanical devices used in the oil and gas industry to increase the pressure of 

natural gas for several purposes, including separating higher molecular weight constituent 

(natural gas liquids) from raw gas and transporting gas across long distances. There are two main 

kinds of compressors that are used in the industry: reciprocating compressors and centrifugal 

compressors. Both kinds of devices experience gas leaks associated with their moving parts—

shaft seals or rod packing systems, as described below—and from static connections at other 

locations on the compressor. The former category we refer to as seal leaks, and we address those 

emissions in this section. The latter category is more accurately considered fugitive emissions, 

which we address in our comments on the white paper concerning leaks. 

Reciprocating compressors function by positive displacement, using a driveshaft and piston that 

move back and forth linearly to reduce the volume of a quantity of gas and increase its pressure. 

To minimize gas leakage around the driveshaft, reciprocating compressors include rod packing 

systems, which consist of a series of flexible rings encased in metal cups to form a seal around 

the shaft. As rod packing systems age, component wear reduces the effectiveness of the seal and 

more gas leaks into the atmosphere. 

Centrifugal compressors are less common in the industry than reciprocating compressors, but are 

associated with higher emissions of methane and other pollutants. These devices draw in lowpressure gas and increase its pressure by directing it through a rotating set of vanes or impellers. 

To reduce leaks, the rotating shaft of each centrifugal compressor is equipped with either wet 

seals or dry seals. Wet seals utilize circulating streams of oil to lubricate the seal rings that absorb 

high pressure gas, which is typically vented into the atmosphere through a seal-degassing process. 

Dry seals, by contrast, consist of aerodynamic grooves that create a thin layer of high-pressure 

gas that separates the rotating rings and creates a natural seal against gas leakage. Compressors 

with dry seals emit approximately 87% less methane from seal leaks than those with wet seals, 

and also save operators money due to lower operating and maintenance costs. 

The 2012 NSPS included operational requirements for compressors of both types that are 

constructed or modified after August 23, 2011 and that are located between the wellpad and the 

point at which the natural gas enters the transmission and storage segment. For centrifugal 

compressors equipped with wet seals, the rule requires operators to achieve a 95% reduction in 

VOC emissions from seal leaks by installing a gas recovery system for the seal oil degassing 

process.21 Centrifugal compressors with dry seals are not covered by the rule. For reciprocating 

 

21 In its proposed rule, the agency considered requiring dry seals at all new centrifugal 

compressors in the gas processing segment. However, the final rule permits operators to use wet 

seal compressors at processing facilities so long as it uses a gas recovery system and reduces 

methane emissions from seal leaks by 95%. See 79 Fed. Reg. 49,490, 49,523 (Aug. 16, 2012). 

The controls we advocate would require existing centrifugal compressors equipped with wet seals 
10 

compressors in those portions of the industry, the rule requires rod packing replacement either 

every 26,000 operating hours or every 36 months. 

While the 2012 NSPS will achieve some co-benefits from reduced methane emissions, it did not 

directly target methane, nor did it cover any existing compressors (i.e., those compressors 

constructed or modified before August 23, 2011) or new or modified compressors on wellpads or 

in the transmission and storage segment. As such, there remain substantial opportunities to reduce 

methane emissions from centrifugal and reciprocating compressors at a reasonable or even 

negative cost. In this analysis, we recommend a series of measures that would significantly 

reduce seal leaks from oil and gas sector compressors. First, EPA must regulate new compressors 

that were not covered under the final 2012 NSPS and require periodic rod packing replacements 

at new wellhead, transmission, and storage segment reciprocating compressors and either dry seal 

installation or gas capture systems at new centrifugal compressors in the transmission and storage 

segment. Second, EPA must require operators to replace rod packing systems periodically (i.e., 

every 36 months or every 26,000 operating hours) at all existing reciprocal compressors in all 

four segments of the oil and gas sector, from wellheads to gas distribution systems. Finally, EPA 

must require all existing wet seal centrifugal compressors in the oil and gas sector to be retrofitted

either with dry seals or gas capture systems that direct gas from seal oil degassing units and direct 

it to compressor suction or other beneficial use. 

The comments below are structured primarily around the 2011 Inventory to discuss abatement 

opportunities in line with the information EPA had when it proposed and developed the 2012 

NSPS. Because the data on compressor emissions has not qualitatively changed between 2012 

and today, our analysis based on 2011 Inventory data remains pertinent with regard to abatement 

opportunities for compressors, particularly for existing sources built prior to August 23, 2011. In 

addition, we also evaluate abatement opportunities from compressor seals in light of data from 

the 2014 Inventory as a point of comparison. As our analysis shows, the net emission reductions 

that can be achieved from the control measures we advocate are similar regardless of whether one 

uses 2014 or 2011 Inventory data; in both cases, these reductions are substantial. 

 

In the sections that follow, we provide an overview of EPA’s anticipated emission reductions 

from the 2012 NSPS. We then discuss the abatement opportunities available at existing reciprocal 

and existing compressors based on data from EPA’s 2011 Inventory. Next, we examine the 

emission reductions that could be achieved by regulating new compressors not covered under the 

2012 NSPS, again using data available to EPA in 2012. We then consider these total emission 

reduction figures in light of EPA’s most recent data from the 2014 Inventory. Finally, we respond 

to the charge questions included in EPA’s compressor white paper. 

B. Anticipated Emission Reductions from EPA’s 2012 NSPS 

EPA’s final 2012 NSPS set operational standards to reduce VOC at new compressor seal leaks by 

approximately 1,736 tpy.22 The rule requires control of all new reciprocating compressors and 

 

to be retrofitted with dry seals or systems that achieve equal or greater reductions by capturing the 

gas from seal oil degassing process and directing it into compressor suction (or similarly utilize 

the gas through another mechanism). 

22 EPA, Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas 

Production, Transmission, and Distribution: Background Technical Support Document for 

Proposed Standards (July 2011) (hereafter, “TSD”) at 6-15 (Table 6-6) (showing data for 
11 

centrifugal compressors with wet seals “located between the wellhead and the point of custody 

transfer to the natural gas transmission and storage segment.” 79 Fed. Reg. at 49,543 (40 C.F.R. § 

60.5365(b)-(c)). Hence, the rule covers new reciprocating compressors in the gas production 

(gathering and boosting activities only; wellpad units are not covered) and processing segments 

and new centrifugal compressors in the processing segment (no new centrifugal compressors are 

anticipated for gathering and boosting). In addition to VOC abatement, methane (8,139 tpy) and 

hazardous air pollutants (“HAP”) (65 tpy) emission reductions are expected as co-benefits to the 

rule, as shown in the summary table below.23

 

Table 1: Emissions Abatement Estimations from 2012 NSPS

Specifically, the final 2012 NSPS requires affected reciprocating compressors to replace rodpacking systems either after every 26,000 operating hours or after every 36 months. 79 Fed. Reg. 

at 49,544 (40 C.F.R. § 60.5385(a)(1)-(2)). Affected centrifugal compressors with wet seals must 

reduce VOC emissions from seal venting by 95% by installing a gas recovery system for the seal 

oil degassing process. 79 Fed. Reg. at 49,544 (40 C.F.R. § 60.5380(a)(1)-(2)). Alternatively, 

operators may avoid regulation under the 2012 NSPS by using dry seal centrifugal compressors, 

which are not considered affected facilities under the final rule. 79 Fed. Reg. at 49,500. 

Based on these requirements, EPA estimated that the final rule would reduce VOC emissions at 

419 affected reciprocating compressors by 1,482 tpy, along with co-benefits of 5,329 tpy methane 

and 56 tpy HAP.24 EPA estimated the control cost for these units at $273 to $877 per ton of VOC 

abated.25 For an estimated 13 affected centrifugal compressors, the agency calculated emission 

 

reciprocating compressors); EPA, Oil and Natural Gas Sector: Standards of Performance for 

Crude Oil and Natural Gas Production, Transmission, and Distribution: Background 

Supplemental Technical Support Document for the Final New Source Performance Standards

(April 2012) (hereafter, “Supplemental TSD”) at 6-2 (Table 6-3) (showing data for centrifugal 

compressors). 

23 Id.

24 See Table 2, supra. See also TSD at 6-15 (Table 6-6). Note that Table 6-6 erroneously lists 375 

as the number of new reciprocating compressors annually in the processing segment. Elsewhere, 

the TSD makes clear that this figure is actually anticipated at 209 new units per year. See, e.g., id.

at 6-7 (Table 6-4), 6-28, 6-29 (Table 6-13). 

25 TSD at 6-17 (Table 6-7). 

Methane VOC HAP Methane VOC HAP

New Gas Production (Gathering & Boosting) 

Reciprocating Compressors 6.84 1.90 0.07 210 1,437 400 15 

New Gas Processing Reciprocating Compressors 18.60 5.18 0.20 209 3,892 1,082 41 

Subtotal 5,329 419 1,482 56 

New Gas Processing Centrifugal Compressors 216.15 19.51 0.70 13 2,810 254 9 

Subtotal 1,736 8,139 65 

 Commpressor Emissions Abatement Estimations from 2012 NSPS

Equipment Type

Emissions abated per 

compressor (tons/year) in 2012

Number of 

New 

Devices/Yr

Total emissions abated 

(tons/year) in 2012
12 

reduction benefits at 254 tpy VOC with co-benefits of 2,810 tpy methane and 9 tpy HAP.26 The 

control cost for these units was estimated at $160 per ton of VOC abated.27

In total, EPA projected that the final rule would reduce methane emissions from compressor seal 

leaks by approximately 8,139 tpy. This abatement figure is relatively small because, as discussed 

earlier, the rule only applies to new and modified compressors—that is, compressors that are 

constructed or modified after August 23, 2011. 77 Fed. Reg. at 49,493. The final rule also 

exempts new reciprocating compressors on wellpads and in the transmission and storage 

segments, as well as new centrifugal compressors in the transmission and storage segments. 

Below, we discuss the emission reductions that could be achieved by controlling seal leak 

emissions at these devices. 

C. Control Measures for Compressors Not Covered Under the 2012 NSPS: Anticipated 

Emission Reductions Based On Data Available to EPA In 2012 

By requiring retrofits of existing wet seal centrifugal compressors with dry seals or gas capture 

systems, as well as routine replacement of rod packing systems at existing reciprocating 

compressors, EPA can achieve significantly greater reductions in methane emissions at a 

reasonable cost. Utilizing data available to EPA at the time of the 2012 NSPS rulemaking, we 

calculate the emission reduction opportunities from these measures at 525,218 tpy of methane, 

along with emission reduction co-benefits of 72,384 tpy VOC and 2,661 tpy HAP, as show in 

Table 2 below. 

Table 2: Abatement Opportunities from Existing Gas Sector Compressors Using Data Available 

to EPA During 2012 NSPS Rulemaking 

Additionally, the 2012 NSPS did not apply to new reciprocating compressors located at wellhead 

sites or in the transmissions and storage segments, nor to new centrifugal compressors in the 

transmission and storage segment.28 We estimate that a rule requiring control of seal emissions at 

these new units would reduce methane emissions by 22,576 tpy. While this number is lower than 

the reduction opportunities from existing compressors, it is important to keep in mind that it is a 

per-year estimate that only accounts for reductions in the first year of abatement. After the second 

year, emissions reductions would double, as the new, cleaner compressors installed in the first 

year would continue to emit less methane from seal leaks, and new compressors installed in the 

second year would add to the potential emissions reduction. These emission reduction benefits 

 

26 Supplemental TSD at 6-3 (Table 6-2). 

27 Id. at 6-2–6-3 (($3,132/compressor/yr)/(19.58 tpy/compressor) = $160/ton. 

28 EPA estimated that no new centrifugal compressors were estimated at wellheads or for 

gathering and boosting activities in the coming year. See TSD at 6-7 (Table 6-4). Hence, we do 

not consider emission reduction estimates from those kinds of units. 

Methane VOC HAP

Existing Reciprocating Compressors 292,267 33,102 1,203

Existing Centrifugal Compressors 232,950 39,282 1,459

Subtotal 72,384 525,218 2,661 

Equipment Type

Emissions abated (tpy)

Emission Abatement Potential - Existing Compressors
13 

would continue to compound each year as new equipment is installed, and the 22,576 tpy would 

compound to a substantial abatement total over time. 

As we explain in further detail below, these measures can be achieved at new and existing 

compressors at a control cost ranging from $49–$1,053 per ton of methane depending on the 

segment and compressor, exclusive of profits from the sale of captured fuel and operating and 

maintenance cost savings. Once these additional revenues are taken into account, the control costs 

for the measures would range from -$703 (that is, a net profit of $703 per ton of methane 

abatement) to +$821 per ton. In the sections that follow, we describe the abatement opportunities 

for seal emissions from existing oil and gas sector compressors. Our analysis uses the emission 

abatement factors that appear in the rulemaking documents for the 2012 NSPS and incorporates 

the activity counts and aggregate methane emissions data from EPA’s 2011 Inventory, which was 

available to EPA when it developed the 2012 NSPS and which the agency relied upon for most 

data points in that analysis. 

We note here that our calculations likely under-represent the true level of methane emissions 

from compressor seal leaks. This is because the most commonly used emission factors—

including those used by EPA in its GHG Inventories and in developing the 2012 NSPS, which we 

rely on in this report—almost certainly underestimate the amount of methane emitted at each 

compressor. For example, to estimate emissions from reciprocating compressors, EPA used the 

emission factors calculated in the 1996 EPA/GRI study.29 Yet a 2011 report by the University of 

Texas (“UT”) and URS Institute suggests that the true level of emissions from these devices may 

exceed the EPA/GRI study’s estimates by several orders of magnitude.30 The UT/URS study 

authors caution that their study used a smaller sample set than the EPA/GRI study, and that “there 

is not enough data to draw a definitive conclusion.” Accordingly, we do not rely on the UT/URS 

values in our analysis. Nevertheless, they indicate that emissions from gas sector compressors 

may well be much higher than either the EPA Inventory or the 2012 NSPS rulemaking materials 

presumed. For this reason, we assert that our estimates included herein are quite conservative. 

Additionally, for the 38,410 units listed as “small gathering compressors” in the production 

sector, the 2011 Inventory uses an extremely low emissions factor of around 2 tpy/compressor. 

This amounts to around 0.2 tpy/compressor attributable to seal leaks, assuming (as we do) that 

9.8% of these units’ emissions are caused by seals. This figure, derived from the measurement of 

emissions from a single wellpad compressor in the 1996 EPA/GRI study, is approximately 57 

times less than the Inventory’s emission factor for “large gathering compressors.” Although it is 

nearly certain that the 0.2 tpy/compressor figure drastically under-represents the true value for 

these units, we have not altered that figure when calculating emissions from existing compressors 

in the production sector.31 Even with this added layer of conservatism, our data shows significant 

 

29 See EPA and GRI, Methane Emissions from the Natural Gas Industry, Volume 2: Technical 

Report (June 1996), available at 

http://www.epa.gov/gasstar/documents/emissions_report/2_technicalreport.pdf. 

30 See URS Corporation and University of Texas, Natural Gas Industry Methane Emission Factor 

Improvement Study Final Report (Dec. 2011), at 37-38, available at 

http://www.utexas.edu/research/ceer/GHG/files/FReports/XA_83376101_Final_Report.pdf. 

31 In calculating control costs for existing units and potential abatement from new wellhead 

compressors, however, we revised the emission control factor that EPA used for wellhead units, 

which also derived from the 1996 EPA/GRI study. We discuss this in more detail on pages 16-17 

below. 
14 

emission reduction potential at reasonable cost from the measures we discuss, and EPA must act 

promptly to adopt these or equivalent measures. 

i. Methane Abatement Opportunities for Existing Reciprocating Compressors 

EPA’s 2011 Inventory estimated that 48,46932 reciprocating compressors were operating in the 

U.S. oil and gas sector in 2009. Additional compressors were added between that year and August 

23, 2011, the cut-off date for existing sources, so this number is a conservative estimate. The 

2011 Inventory estimated sector-wide methane emissions from these devices totaling 1,601,862 

tons33 (75.56 Bcf)34 for 2009. This total includes emissions not only from reciprocating seals, but 

from fugitives as well—that is, leaks occurring at other locations on the compressor apart from 

seals. These data are presented in Table 3 below. 

Table 3: Activity Counts and Aggregate Emission Estimates at Oil and Gas Sector 

Reciprocating Compressors- All Emissions

We observe here that existing data for methane emissions from reciprocating compressors in the 

production sector likely dramatically underestimate the true emissions from these sources. As 

Table 3 shows, the 2011 Inventory estimated that emissions from reciprocating compressors in 

this segment are only 2.6 tons/compressor/year, whereas emission rates for such compressors in 

the other segments range from approximately 86 to 163 tons/compressor/year. There is no 

explanation for this wide disparity, and we contend that the emission estimates for the production 

segment are extremely conservative as a result. 

 

32 EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks (1990-2009) (Apr. 15, 2011) 

(hereafter, “2011 Inventory”), Annex 3, Tables A-120 through A-122 (34,930 production 

segment compressors + 4,876 processing segment compressors + 8,663 transmission and storage 

segment compressors = 48,469 reciprocating compressors in the oil and gas sector). 

33 See id. (82.45 Gg production + 383.77 Gg processing + 769.26 Gg transmission + 217.72 Gg 

storage = 1453.2 Gg sector wide; 1453.2 Gg *1,000 MT/Gg * 1.1023 tons/MT = 1,601,862 tons 

of methane emissions per year from seal leaks at oil and gas sector reciprocating compressors). 

34 To convert methane weight to volume, we used a standard conversion factor of .0212 tons/Mcf, 

which EPA used in the 2011 Inventory. (Hence, 1,601,862 tons * 1 Mcf per .0208 tons * 1 Bcf 

per 1,000,000 Mcf = 75.56 Bcf). 

Methane VOC HAP

Existing Production Reciprocating Compressors 34,930 90,885 25,266 954

Existing Gas Processing Reciprocating Compressors 4 423,030 ,876 117,602 4,442 

Existing Transmission Reciprocating Compressors 7,1 847,955 97 23,488 678 

Existing Storage Reciprocating Compressors 1,466 239,993 6,648 192 

Subtotal 1,601,862 48,469 173,004 6,266 

Equipment Type

Emissions (tons/year) in 2009

VOC and HAP emission estimates were computed using conversion factors from EPA 2011 TSD, Page 6-2.

 Existing Compressor Emission Estimates - Not Regulated by 2012 NSPS

Number of 

Devices
15 

Using data from the 1996 EPA/GRI Study, we estimated the portion of total methane emissions 

attributable to seal leaks, then multiplied the total emissions from reciprocating compressors by 

this factor to produce an estimate of emissions from seal leaks alone.35 We estimated 

reciprocating compressor emissions due to seal leaks alone to be approximately 10% in the 

production segment, 28% in the processing segment, 24% in the transmission segment, and 18% 

in the storage segment. In our analysis of EPA’s white paper on leaks/fugitive emissions, we 

address the remainder of the methane emissions from compressors, which occur due to leaks from 

a device’s static components. We estimated methane emissions attributable to reciprocating 

compressor seal leaks to be 368,887 tpy, as shown in Table 4 below. 

Table 4: Activity Counts and Aggregate Emission Estimates at Oil and Gas Sector 

Reciprocating Compressors- Seal Leaks Only

As EPA recognized in the 2012 NSPS, methane emissions from reciprocating compressor seal 

leaks can be reduced substantially by replacement of worn-out rod packing systems on a periodic 

basis. The agency reports that newly installed packing typically leaks 11-12 scfh, whereas worn 

packing has been reported to leak up to 900 scfh.36 In these cases, replacing packing before 

serious wear occurs can reduce emissions by 90-95%. However, depending on the degree of 

wear, and compressor maintenance history, emission reduction improvements would be less than 

90-95% for the average compressor. Periodic replacements of rod packing materials is also good 

operating and maintenance protocol: operators that carefully monitor and replace compressor rod 

packing systems on a routine basis can conserve additional gas for sale that would otherwise have 

been leaked and reduce piston rod wear, both of which increase profit. 

As part of the 2012 NSPS rulemaking, EPA estimated the total amount of methane leaked and the 

amount of abatement that could be achieved from reciprocating compressors in each segment 

based upon the rule’s requirements that rod packing systems be replaced every 36 months or 

 

35 GRI/EPA, Methane Emissions from the Natural Gas Industry (June 1996), Volume 8: 

Equipment Leaks, Table 4-8 (Production), Table 4-14 (Processing), Table 4-17 (Transmission) 

and Table 4-24 (Storage), available at

http://www.epa.gov/gasstar/documents/emissions_report/2_technicalreport.pdf. 

36 EPA, Lessons Learned from Natural Gas STAR Program, Reducing Methane Emissions From 

Compressor Rod Packing Systems (Oct. 2006), at 1, available at 

http://www.epa.gov/gasstar/documents/ll_rodpack.pdf. 

Seal Leak 

% of Total Methane VOC HAP

Existing Production Reciprocating Compressors 34,93 9.8% 8,903 0 2,475 93 

Existing Gas Processing Reciprocating Compressors 4 27.9% 117,996 ,876 32,803 1,239 

Existing Transmission Reciprocating Compressors 7,1 23.6% 199,955 97 5,539 160 

Existing Storage Reciprocating Compressors 1,466 17.5% 42,033 1,164 34 

Subtotal 368,887 48,469 41,981 1,526 

Equipment Type

Emissions (tons/year) in 2009

VOC and HAP emission estimates were computed using conversion factors from EPA 2011 TSD, Page 6-2.

 Existing Compressor Emission Estimates - Not Regulated by 2012 NSPS (Seal Leaks Only)

Number of 

Devices
16 

every 26,000 operating hours. The agency calculated abatement opportunities of 63.2%37 for 

devices in the production segment, approximately 80% for those in the both the processing and 

transmission segments, and 77.3% in the storage segment.38 These estimates were for new 

compressors; leak rates for existing compressors are likely higher. We applied the 2012 NSPS 

abatement potential factors to each segment to compute a total methane reduction of 292,267 tpy 

from seal leaks at existing reciprocating compressors, along with co-benefits of 33,102 tpy in 

VOC abatement and 1,203 tpy in HAP abatement. 

Table 5: Total Abatement Opportunities from Seal Leaks at Existing Oil and Gas Sector 

Reciprocating Compressors

We observe here that the GHG Inventory presents aggregated data for production segment 

reciprocating compressors without providing specific information for wellpad devices. Therefore, 

our estimates for existing units do not offer breakdown figures for wellpad devices and gathering 

and boosting devices, but instead present data for production segment compressors in the 

aggregate. However, in its TSD for the 2012 NSPS, EPA calculated separate cost estimates for 

emission controls at wellpad compressors and gathering and boosting compressors, even while it 

declined to regulate the latter devices in its final rule. The agency’s cost estimate for controlling 

wellhead reciprocating compressors amounted to $15,802 per ton of methane. By contrast, the 

agency estimated control costs of $244, $76, $77, and $104 for reciprocating compressors at 

gathering and boosting, processing, transmission, and storage facilities, respectively (exclusive of 

savings from conserved gas). 

EPA’s estimated control cost of $15,802 per ton of methane at wellhead reciprocating 

compressors patently overestimates the true cost of controlling emissions at these units. It is 

based on an emission abatement factor (or emission control factor) of just 0.158 tons of methane 

 

37 This figure combines data in the TSD for both reciprocating compressor types listed for the 

production segment—wellhead units and gathering and boosting units. We took this approach 

because it is not clear in EPA’s Inventory for either 2011 or 2014 which production sector 

compressors are wellhead units and which are gathering and boosting units. Hence, we derived an 

abatement percentage based on data for all production sector compressors—wellhead and 

gathering/boosting units alike—and applied that to the aggregated data for all production sector 

devices listed in the Inventory. 

38 TSD at 6-10 (Table 6-5), 6-15 (Table 6-6). The abatement percentages for each segment were 

calculated by dividing the abatement opportunity figures presented in Table 6-6 by the baseline 

aggregate emission figures presented in Table 6-5. 

Methane VOC HAP

Existing Production Reciprocating Compressors 63.2% 1,564 5,625 59 

Existing Gas Processing Reciprocating Compressors 79.9% 94,281 26,210 990

Existing Transmission Reciprocating Compressors 80.0% 159,888 4,429 128 

Existing Storage Reciprocating Compressors 77.3% 32, 900 473 26 

Subtotal 33,102 292,267 1,203 

Equipment Type % Emissions abated (tons/year)

Abatement

Emission Abatement Potential - Rod Packing Replacement at Existing Reciprocating 

Compressors
17 

per year for each wellhead reciprocating compressor.

39 This control factor of .158 tpy per device 

is substantially less than those factors used for any other reciprocating compressor in the oil and 

gas sector (which range from 6.84 to 21.70 tons of methane per year per compressor) and derives 

from measurements from a single four-cylinder compressor in the 1996 EPA/GRI Study. By 

using a control factor that substantially underestimates the methane emissions reduction potential 

for these sources, the agency arrives at a cost figure that is far higher than the true control costs 

for such devices. 

We urge EPA to remedy this problem by conducting a study of emissions wellhead reciprocating 

compressors, which are poorly characterized by the current data. However, in lieu of recent and 

comprehensive data, we have attempted to estimate a more accurate cost estimate for controlling 

wellpad reciprocating compressors than the figure EPA cites in its TSD, even while EPA’s 

Inventory does not provide us with the data to estimate total emissions or abatement factors from 

these units. To be conservative, we considered the range of emission control factors for 

reciprocating units based on reported values for other segments of the oil and gas industry. As 

noted above, these values ranged from 6.84 to 21.70 tons of methane per year per compressor. 

We selected the lowest emission control factor of 6.84, and, to add another layer of conservatism 

into our estimate, we reduced this number by an additional 50% to arrive at an emission control 

factor of 3.42 tons of methane per year per compressor. 

Based on these control factors, we calculate a revised control cost of $742 for wellhead 

reciprocating compressors. When cost savings from conserved gas sales are taken into account, 

this figure drops to $497 per ton. Accounting for conserved gas revenues, the control cost for 

gathering and boosting reciprocating compressors drops to $12, and for processing sector units, 

the control cost is -$156, a net profit. 

ii. Methane Abatement Opportunity for Existing Centrifugal Compressors. 

Based on data from EPA’s 2011 Inventory, we estimate that 1,39740 wet seal centrifugal 

compressors were operating in the U.S. oil and gas sector in 2009. Additional compressors were 

added between 2009 and August 23, 2011, the effective date of the 2012 NSPS, so again, this 

estimate is conservative. The 2011 Inventory estimates that these units emitted 546,338 tons of 

methane in 2009, as illustrated in Table 6 below. 

Table 6: Activity Counts and Aggregate Emission Estimates at Oil and Gas Sector Centrifugal 

Compressors

 

39 Id. at 6-15 (Table 6-6). 

40 2011 Inventory, Annex 3, Tables A-121 through A-122 (646 processing segment units + 667 

transmission segment units + 84 storage segment units = 1,397 wet seal centrifugal compressors 

sector-wide). Although these tables included emissions data for centrifugal compressors at 

liquefied natural gas (“LNG”) storage and import stations, they do not specify whether they are 

wet seal or dry seal compressors. Accordingly, we do not include those data in our estimates. In 

any event, aggregate methane emissions from wet seal centrifugal compressors in this sector are 

almost certainly higher than our estimates suggest. 
18 

To arrive at the estimate of 535,237 tons of methane emitted, we used emission factors of 51,370 

scfd per compressor in the processing segment, 50,222 scfd per compressor in the transmission 

segment, and 45,441 scfd per compressor in the storage segment. These emission factors appear 

in EPA’s 2011 Inventory41 and are based on calculations from a study conducted by ICF 

International in 2009.42 They are conservative compared to EPA’s Natural Gas STAR report, 

which indicates that wet seal emissions are more typically in the range of 40 to 200 scfm (57,600 

to 288,000 scfd), as compared to dry seals that emit 0.5 to 3 scfm (720 to 4,320 scfd), or 1 to 6 

scfm (1,440 to 8,640 scfd) for a two-seal system.43 Using the higher range of emission factors 

cited in EPA’s Natural Gas STAR report would substantially increase this emission estimate, so 

our analysis is conservative in this regard as well. 

The 2009 ICF study also provided detailed breakdowns of the specific sources of emissions at 

centrifugal compressors in each segment of the oil and gas industry. According to these 

breakdowns, seal leaks accounted for 58.3% of emissions from wet seal centrifugal compressors 

in the processing segment, 41.0% of emissions from units in the transmission sector, and 33.9% 

of emissions from units in the storage sector.44 Using these percentages, we reduced the 2011 

Inventory’s aggregate emission figures for wet seal centrifugal compressors in order to estimate 

the emissions attributable specifically to wet seal leaks. Table 7 illustrates these calculations.. 

 

41 Id.

42 The results of this study are summarized in a memo prepared by ICF, attached as Ex. 2. 

43 EPA, Lessons Learned from Natural Gas STAR Partners: Replacing Wet Seals with Dry Seals 

in Centrifugal Compressors (Oct. 2006), at 3, available at 

http://www.epa.gov/gasstar/documents/ll_wetseals.pdf. 

44 See Ex. 4 at 4-5. 

Methane VOC HAP

Existing Wet Seal Centrifugal Compressors (Processing) 646 257,245 71,514 2,701

Existing Wet Seal Centrifugal Compressors 

(Transportation) 259,531 667 7,189 208 

Existing Wet Seal Centrifugal Compressors (Storage) 84 29,563 819 24

Subtotal 546,338 1,397 79,522 2,932 

 Existing Compressor Emission Estimates - Not Regulated by 2012 NSPS

Equipment Type

Emissions (tons/year) in 2009

VOC and HAP emission estimates were computed using conversion factors from EPA 2011 TSD, Page 6-2.

Number of 

Devices
19 

Table 7: Aggregate Emission Estimates at Oil and Gas Sector Wet Seal Centrifugal 

Compressors- Seal Leaks Only

In the TSD for the 2012 NSPS, EPA provided baseline estimates for emissions from centrifugal 

compressors with wet and dry seals, respectively.45 Comparing these figures, we calculate a perunit 87.4% methane abatement potential by requiring existing wet seal compressors in the 

processing, transportation, and storage segments to be retrofitted with dry seals.46 This abatement 

percentage reflects data for new compressors; leaks from existing compressors would likely be 

higher, and the abatement potential higher as well. Reports of control effectiveness for seal oil 

gas capture systems have also been higher than 87%.47 We then applied the 87.4% abatement 

potential to each segment’s emissions to compute a total methane reduction potential of 477,589 

tpy from centrifugal compressors, along with co-benefits of 69,541 tpy in VOC emission 

reductions and 2,240 tpy in HAP emission reductions. 

Table 8: Total Emission Reduction Opportunities at Oil and Gas Sector Centrifugal 

Compressors

EPA estimated the control cost for dry seals on centrifugal compressors in the processing, 

transmission and storage segments to be $14 to 25 per ton of methane abated, without accounting 

for savings from recovered gas and reduced operating and maintenance costs.48 Taking these 

 

45 TSD at 6-5 (Table 6-3). 

46 Id. (1 – (28.6 tpy/228 tpy) = .874; 1 – (15.9 tpy/126 ypu) = .874). 

47 See, e.g., BP and BGE, Centrifugal Compressor Wet Seals Seal Oil De-Gassing & Control, 

presented at 2014 Natural GasSTAR Annual Implementation Workshop,(May 2014) at 19, 

available at

http://www.epa.gov/gasstar/documents/workshops/2014_AIW/Experiences_Wet_Seal.pdf (BP 

measured control effectiveness of over 99% on degassing unit employed on a high pressure 

compressor). 

48 Based off data from Sections 6.3, 6.4 and 6.6 of the 2012 TSD at 6-1 to 6-3 ($40,720 (total 

annual cost for wet seal compressors) / 2,810 tpy methane = $14 per ton of methane abated). For 

Methane VOC HAP

Existing Wet Seal Centrifugal Compressors (Processing) 58% 149,970 41,692 1,575

Existing Wet Seal Centrifugal Compressors (Transmission) 41% 106,483 2,950 85

Existing Wet Seal Centrifugal Compressors (Storage) 34% 10,010 277 8

Subtotal 44,919 266,463 1,668 

Existing Centrifugal Compressors-- Emissions Attributable to Wet Seal Leaks

Equipment Type Seal Leak 

% of Total

Emissions abated (tons/year)

Methane VOC HAP

Existing Wet Seal Centrifugal Compressors (Processing) 87% 131,158.25 36,461.99 1,377.16 Existing Wet Seal Centrifugal Compressors 

(Transportation) 87% 93,045.52 2,577.36 74.44 

Existing Wet Seal Centrifugal Compressors (Storage) 87% 8,746.71 242.28 7.00 

Subtotal 39,282 232,950 1,459 

Equipment Type

Emission Abatement Potential - Replace Wet Seals with Dry Seals

% 

Abatement

Emissions abated (tons/year)
20 

savings into account, our recommended measures would result in a net profit of $206 per ton of 

methane abated in the processing segment. 49 Because transmission and storage facilities do not

typically own the gas in their facilities, we did not calculate the cost for these segments that 

includes the revenue from conserved gas. 

iii. Methane Abatement Opportunity for New Compressors That Were Not 

Regulated in the Final Rule for the 2012 NSPS. 

In the final 2012 NSPS, EPA did not set operational standards requiring emission controls for 

compressors located at oil and gas wellheads.50 EPA concluded that such controls were not 

necessary because VOC emissions were typically low at these locations.51 Methane emissions, 

however, are significant at wellhead compressors, and any regulatory approach that specifically 

targets methane should require emission controls at these units. 

EPA estimated a total of 6,000 new wellhead reciprocating compressors installed each year, with 

aggregate seal leak emissions of 947 tpy methane, 263 tpy VOC, and 9.91 tpy HAP.52 As 

discussed above, EPA’s methane emission reduction factor of 0.158 tpy/unit for wellhead 

reciprocating compressors is drastically lower than the agency’s estimates for similar 

reciprocating compressors in other segments of the industry and significantly underestimates 

emissions from wellhead compressors. Accordingly, for the reasons described above, we instead 

use a revised emission reduction factor of 3.42 tpy/compressor for these units. Based on EPA’s 

estimates of 6,000 new wellhead reciprocating compressors each year, control measures for these 

units will reduce methane emissions by 20,520 tpy, with co-benefit reductions of 3,131 tpy VOC 

and 115 tpy HAP. As discussed on page 16 and 17 above, these measures entail a control cost of 

$742 per ton of methane abated without accounting for revenues from captured gas sales and 

$497 per ton when considering these savings. 

Additionally, EPA’s 2012 NSPS did not cover new compressors (either reciprocating or 

centrifugal units) located in the transmission and storage segments. The agency again concluded 

that VOC emissions were typically low at these locations, and that it needed additional time to 

consider cost-effective standards for them.53 Once more, however, it is evident that methane 

emissions from these locations are significant and can be controlled with cost-effective measures. 

EPA estimated that there are 199 new reciprocating compressors installed each year in the 

transmission segment, with a corresponding emission reduction potential of 423 tpy methane, 

11.7 tpy VOC, and 0.35 tpy HAP.54 For a rule requiring periodic replacement of rod packing 

systems at transmission segment units, EPA calculated a control cost of $77 per ton of methane 

 

the transmission and storage cost ($25), we used the relative emissions abatement for wet seals 

compressors in the 2011 TSD at 6-24 (Table 6-10). 

49 Id.

50 77 Fed. Reg. at 49,543. 

51 Id. at 49,498. 

52 TSD at 6-15 (Table 6-6). The agency estimated that no new centrifugal compressors would be 

installed anywhere in the oil and gas production sector, including at wellhead sites. 

53 77 Fed. Reg. at 49,498, 49,523. 

54 TSD at 6-15 (Table 6-6). 
21 

reduced.55 EPA also estimated that nine new reciprocating compressors will be installed each year 

in the natural gas storage segment, with a corresponding emissions reduction potential of 87 tpy 

methane, 2.4 tpy VOC, and 0.07 tpy.56 EPA estimated costs of $104 per ton of methane to control 

emission from these units. 57

 

The agency also declined to regulate rule new wet seal centrifugal compressors in the 

transmission and storage segments in the final 2012 NSPS. Using the TSD’s emission factors, as 

well as its assumption that 14 new units will be installed per year, we estimate that 1,546 tpy 

methane could be reduced by requiring dry seals or gas capture systems at these compressors, as 

well as 43 tpy VOC and 1.3 tpy HAP. The agency estimated the control cost of regulating these 

units at $97 per ton of methane reduced, with a profit of $703 per ton when accounting for 

reduced operating and maintenance costs.58 

Table 9: Emission Reduction Opportunities at New Compressors Not Regulated Under EPA’s 

2012 NSPS

Notably, these abatement figures account only for the first year that controls would be required at 

new compressors. After the second year, the total effective emissions reductions would double, as 

the new, cleaner compressors installed in the first year would continue to emit less than the units 

that would otherwise have been installed. With each additional year, these emission reduction 

benefits would continue to compound as new equipment is installed and the cleaner devices 

installed before that year continue to operate. 

D. Control Measures for Compressors Not Covered Under the 2012 NSPS: Anticipated 

Emission Reductions Based On 2014 Inventory Data. 

EPA’s compressor white paper provides industry-wide compressor activity counts and associated 

methane emissions from EPA’s most recent inventory for 2014, covering the years 1990 to 2012. 

This 2014 Inventory estimates total methane emissions (including both seal leaks and fugitives) 

 

55 Id. at 6-17 (Table 6-7). Because transmission and storage system operators do not own the 

natural gas they transport and store, respectively, there are no cost savings associated with the 

sale of conserved gas in these segments. 

56 Id. at 6-15 (Table 6-6). 

57 Id. at 6-17 (Table 6-7). 

58 Id. at 6-22 (Table 6-9). 

Methane VOC HAP Methane VOC HAP

New Wellhead Reciprocating Compressors* 3.42 0.0439 0.00165 6,000 20,520 3,131 114.9

New Transmission Reciprocating Compressors* 21.70 0.600 0.0178 199 423 11.7 0.35 

New Storage Reciprocating Compressors* 21.80 0.060 0.0179 9 87 2.4 0.07 

New Transmission and Storage Centrifugal Compressors** 110.00 3.06 0.09 14 1,546 43 1.3 

Subtotal 3,188 22,576 117 

*Emission Estimates from EPA 2011 TSD, Table 6-6, Page 6-15. Wellhead methane factor was adjusted to 3.42 instead of .158 as explained in text 

**Emission Estimates from EPA 2011 TSD, Table 6-8, p. 6-20. Note there is a typo in the EPA table. The category labeled Storage, included Transmission and Storage. The category labeled 

Transmission and Storage is the Processing Segment.

Emission Abatement Compounds Each Year

Potential Emission Abatement from New Compressors Not Regulated by 2012 NSPS

Equipment Type Emission control factor (tpy/unit) Number of new 

devices/Yr

Emissions abated (tpy)
22 

from existing reciprocating compressors at of 1,651,368 short tons per year (“tpy”)59 in 2012, 

reflecting an existing device count of 50,244.60 The 2014 Inventory also estimates total methane 

emissions from existing centrifugal compressors (including both wet and dry devices) at 632,194 

tpy61 based on a total device count of 1,801.62 Accounting for existing reciprocal and centrifugal

compressors together, the 2014 Inventory estimated a total of 2,283,562 tpy of methane from 

these sources for 2012. Using EPA’s 100-year global warming potential (“GWP”) for methane of 

21—a highly conservative value, as noted above—these emissions amount to nearly 43.5 million 

metric tons per year CO2e. The up-to-date GWP figures currently recommended by the 

International Panel on Climate Change (“IPCC”)63 paint an even more dramatic picture, 

tabulating natural gas sector compressor emissions at over 74 million and 180 million metric tons 

per year CO2e on a 20- and 100-year basis, respectively. 

Using data on the 2014 Inventory as a baseline, and applying the emission reduction factors that 

we computed based on earlier data (a 63-80% reduction of seal leak emissions at existing 

reciprocating compressors and 87% reduction at existing wet-seal centrifugal compressors), we 

calculate that the recommended measures would reduce seal leak emissions from existing 

compressors by 537,479 tpy. Table 10 below breaks down these reduction estimates for existing 

reciprocating and centrifugal compressors. 

Table 10: Abatement Opportunities from Existing Gas Sector Compressors (2014 Inventory 

Data)

This total aligns with our conservative estimate of 525,218 tpy in methane emission abatement 

from existing compressors based on data that was available to EPA at the time of the 2012 NSPS 

rulemaking. 

E. Summary 

 

59 CWP at 20 (Table 3-9) (70,859+15,400+442,634+773,294+150,225+40,147+5,552 =1,498,111 

MT * 1.1023 tons/MT = 1,651,368 tpy). 

60 Id. (35,930+136+5,624+7,235+1,012+270+37) = 50,244 reciprocating compressors. 

61 Id. (237,724+43,937+232,826+14,972+22,347+6,532+13,766+1,419 =573,523 MT * 1.1023 

tons/MT= 632,194 tpy). 

62 Id. (658+248+659+66+70+29+64+7 = 1,801 centrifugal compressors). 

63 The IPCC’s most recent GWP figures for methane from fossil sources are 36 on a 100-year 

basis and 87 on a 20-year basis when accounting for carbon-climate feedback effects. See IPCC, 

Fifth Assessment Report: The Physical Science Basis (2013), at 714, Table 8-7, available at 

http://www.climatechange2013.org/images/report/WG1AR5_Chapter08_FINAL.pdf. 

Methane VOC HAP

Existing Reciprocating Compressors 304,576 37,128 1,356 

Existing Centrifugal Compressors 232,903 45,617 1,695

Subtotal 82,745 537,479 3,051 

Emission Abatement Potential - Existing Compressors

Equipment Type

Emissions abated (tpy)
23 

We conclude that, in total, the control measures we advocate will reduce methane emissions from 

existing gas sector compressors by 525,218 to 537,479 tpy and from new compressors by 22,576 

tpy. As indicated earlier, we believe that these estimates are conservative in light of the very low 

emission factors EPA used in the 2011 Inventory; actual emissions may in fact be much higher, 

as the 2011 URS/UT study implies. 

We used very conservative assumptions as described above to avoid debate about the significance 

of uncertainty in emission estimates and to avoid any reasonably identifiable possibility of 

overstating seal leak emissions from compressors. Even with these conservative assumptions, the 

recommended measures are warranted, as they reduce substantial amounts of emissions of 

methane, VOC, and HAPs, while either imposing minimal costs or generating a profit. Forgoing 

these conservative assumptions would result in substantially lower costs and higher methane 

capture rates, only strengthening the case for immediate regulation of these sources. 

Moreover, we used data that either appeared in EPA’s TSD for the 2012 NSPS or was available 

to the agency at that time in order to emphasize that EPA already has data available and compiled 

that shows that available pollution controls are cost-effective, feasible, and will reduce harmful 

pollution of methane and other pollutants substantially. We recommend that EPA simply update 

the existing TSD materials from 2012 to focus on methane and include new activity and cost data, 

then issue a rule that includes the measures we have recommended herein. 

Lastly, we propose several additional approaches to methane regulation to supplement those we 

have already discussed. First, we support EPA’s consideration of requiring piston rod 

replacement or realignment/refitting at reciprocal compressors on a periodic basis. We urge the 

agency to include this requirement in a final rule to optimize methane abatement. Second, in our 

discussion above, we recommend that operators be required to retrofit existing wet seal 

centrifugal compressors with gas capture systems that direct gas from seal oil degassing systems 

to compressor suction (or other beneficial use), or with dry seal systems. Finally, EPA must not 

delay a methane control rule that captures the majority of emissions by requiring the proven 

technologies adopted for some compressors under the 2012 NSPS while gathering data on other 

options. A rule including the recommended measures must be implemented as soon as possible 

while EPA explores other opportunities to reduce emissions from natural gas sector compressors. 

F. Responses to Charge Questions 

• Question 1: We have presented summaries above on the quantity of emissions of 

methane (and other pollutants) from natural gas compressors. These estimates, as we 

have noted, use emissions data from EPA’s 2012 and 2014 Inventories, as well as the 

data and analyses that were used to develop those Inventories. We have noted that some 

data sources suggest that actual emissions from compressor seal leaks may be much 

higher than the Inventories indicate, but have not adjusted the EPA’s figures to reflect 

those alternate data sources. We there believe this is a very conservative analysis 

We are not aware of any studies suggesting that emissions from compressor seal leaks are 

overestimated in the Inventories. 

In general, the dataset for emissions from compressor seal leaks is fairly strong, with a 

number of studies confirming that emissions are substantial over the years. The exception 

is for compressors on wellpads, where all analyses cite a single measurement of a single 

compressor. We have highlighted this problem in multiple places in our comments. 
24 

• Questions 2 – 5: In a general sense, we believe that the white paper adequately 

characterized studies on emissions, the range of technologies for capturing emissions, 

emissions reductions from those technologies, and capital and operating costs for those 

technologies. 

• Questions 6 – 8: We are not aware of emission capture technologies that were not 

described in the white paper, specific limitations on replacing wet seals with dry seals, or 

any limitation on the use of gas capture systems for wet seal compressors. 

• Question 9: Gas capture systems are generally applicable to wet seals compressors. A 

recent report by BP describe these systems as “[s]imple, broadly flexible, and reliable.”64

Costs for these systems are low, and down time for installation is short. The design and 

operating principles of wet-seals centrifugal compressors are such that simple 

installations, using minimal moving parts and a simple critical orifice approach to 

manage pressures, can route gas from degassing drums to compressor suction.65

• Questions 10 and 11: We have no information on these matters. 

• Question 12: Studies coordinated by EDF of emissions from natural gas gathering and 

processing facilities and natural gas transmission and storage facilities are underway. To 

our knowledge, the study of gathering and processing facilities will not differentiate 

emissions from compressor vents (the study will measure emissions from the entire 

facility). However, it is possible that this research may provide insight on emissions from 

compressors. 

We do not know of any current studies to measure emissions from compressor seals. 

IV. Comments on Pneumatic Devices White Paper 

A. Introduction 

Pneumatic equipment in the oil and gas industry uses pressurized gas to create mechanical action. 

In our comments, we focus specifically on pneumatic controllers, although the general category 

of pneumatic equipment also includes Kimray pumps. Pneumatic controllers, or “PCs,” are 

automated instruments that control various process conditions of natural gas, such as liquid level, 

pressure, pressure difference, and temperature. Many PCs in the oil and gas sector use pressurized 

natural gas as their energy source and vent some quantity of that gas into the atmosphere in 

normal operation. These devices include continuously emitting devices (either high-bleed or lowbleed PCs), snap-acting or intermittent devices (which emit gas in periodic releases), and nobleed devices, which are self-contained units that release gas to downstream pipelines rather than 

into the atmosphere. PCs that are powered by some source other than pressurized natural gas, 

such as electricity, solar power, or instrument air, also do not vent gas into atmosphere. 

This section provides an analysis of control measures requiring operators to replace existing highbleed and intermittent-bleed PCs with low-bleed devices. Our calculations demonstrate that these 

 

64 See supra, n.47. 

65 Id. 
25 

measures would achieve over 507,000 tpy of methane emission abatement at a control costs 

ranging from $25 to $208 per ton exclusive of savings from capture gas sales and reduced 

operating costs. Accounting for these revenues and savings, the measures described below would 

generate annual savings to operators in oil and gas production ranging from $270 to over $1000 

depending on the type of PC at issue. 

In this discussion that follows, we first characterize the emissions from PCs according to the best 

data available, and then assess the degree of abatement that can be achieved along with the 

potential cost of those measures. Next, we canvass flag a number of important considerations 

with regard to the Prasino Group’s 2013 study of PC emissions in British Columbia. Finally, after 

summarizing our findings, we address the charge questions included in EPA’s pneumatic devices 

white paper. 

B. Emissions from Pneumatic Controllers are Substantial, and Underestimated in 

Available Data 

EPA’s white paper for pneumatic devices includes recent methane emission estimates ranging 

from 962,637 short tons per year (“tpy”) (based on data from EPA’s Greenhouse Gas Reporting 

Program (“GHGRP,” or “reporting program”))66 to 1,125,369 tpy (based on estimates in EPA’s 

2014 GHG Emission Inventory).67 The GHGRP estimate reflects only of a subset of industry 

data, since only facilities with calculated emissions over the reporting threshold are required 

report to emissions. Further, in the gas and oil production sector, only devices at wellpads are 

required to report emissions; PCs located at gathering and boosting facilities do not report data to 

the GHGRP. However, while the GHGRP data underestimates the true emissions from oil and gas 

sector PCs, it is nonetheless much more accurate than the 2014 Inventory estimates of PC 

emissions in the oil and gas production segments, as discussed in more detail below. 

Additionally, unlike the 2014 Inventory, the GHGRP reports emissions separately for high-, 

intermittent-, or low-bleed PCs. Below, we explain how we derive our estimates for PC emissions 

from the oil and gas production segments, on the one hand, and from gas transmission and 

storage, on the other hand. 

i. Emissions from PCs in the Oil and Gas Production Segments 

Because PC emissions from oil production and gas production are combined in the GHGRP, we 

consider these sources together and treat them as one segment for the purpose of our analysis. 

GHGRP data make very clear that the 2014 Inventory significantly underestimates PC emissions 

from oil and gas production. The 2014 Inventory reports PC emissions from oil and gas 

production at 848,244 tons of methane (net) in 2012. By contrast, the GHGRP data shows 

estimates emissions from onshore oil and gas production PCs at 949,327 tons in 2012. As noted 

above, GHGRP data only captures a subset of emissions from these segments, but for the 

facilities that do report emissions to the GHGRP, data for PC emissions are superior to those 

reported in the 2014 Inventory. 

 

66 EPA, White Paper on Oil and Natural Gas Sector Pneumatic Devices (April 2014) 

(“Pneumatics White Paper”) at 20 (Table 2-7). Here, and throughout these comments, we convert 

metric tons from the white paper to short tons for the sake of consistency across all segments of 

our analysis. 

67 Id. at 14 (Table 2-3). 
26 

Both the GHGRP and the Inventory use the same emissions factors to calculate aggregate PC 

emissions: each study traces back to the 1996 EPA/GRI for those values. However, the other 

factors used to calculate aggregate emissions—that is, activity data (e.g., the number of PCs of 

each type) and the percentage of methane in the composition of emitted gas—are certainly 

superior in the GHGRP, where each reporter counts controllers and uses its own gas composition 

data to calculate emissions. Furthermore, GHGRP data represent a far bigger sample of U.S. 

facilities than the activity data sampling used by the authors of EPA/GRI study, and is, of course, 

more current by over a decade and a half. Likewise, the use of actual gas composition by 

individual firms will be more accurate than any estimate based on an average composition by 

NEMS region, the method used in the EPA/GRI study and the 2014 Inventory. For these reasons, 

it is clear that GHGRP data is more accurate than the Inventory’s estimates for the subset of 

wellpad PCs that report emissions through the reporting program. That the GHGRP is more 

accurate while capturing only a subset of emissions, and reports higher emissions from 

production PCs than does the 2014 Inventory, highlights the fact that the 2014 Inventory 

significantly underestimates these emissions. 

In 2103, a group of researchers led by David Allen at the University of Texas found that actual 

PC emissions are 29 percent and 270 percent higher than the GHGRP’s emission factors for 

intermittent-bleed and low-bleed PCs, respectively.68 The measurements in this University of 

Texas report (which we refer to hereafter as Allen, et al.) are much more current those that appear 

in the 1996 EPA/GRI study, which provide the basis for the GHGRP emissions factors. 

Moreover, Allen, et al. measured emissions from over 300 PCs,69 while the EPA/GRI study 

measured only around 60 units.70 Hence, for these two reasons, we consider the Allen, et al.

emissions factors to be more accurate than those listed in the 1996 EPA/GRI study. Since 

GHGRP data can be separated into emissions for high-bleed, intermittent-bleed, and low-bleed 

PCs, we can then correct these data using the more accurate emissions factors from Allen, et al. 

by increasing the emissions from intermittent-bleed and low-bleed PCs by 29 percent and 270 

percent, respectively. After this adjustment, total emissions from wellpad PCs that report 

emissions to the GHGRP were 1,255,865 tons of methane in 2012, 48% higher than the value 

from the 2014 Inventory. Table 11 below illustrates our revised estimates. 

Table 11: Oil and Gas Production PC Emissions Reported to GHGRP for 2012 and Corrected 

with Allen, et al.’s Emissions Factors 

Bleed type Emissions 

(Tons CH4) 

Emission Factors 

(scfh) 

Emissions (Tons 

CH4) 

GHGRP 

Reported 

GHGRP

71

Allen 

et al.

72

GHGRP Corrected 

 

68 See Allen, et al., Measurements of methane emissions at natural gas production sites in the 

United States, Proceedings of the National Academy of Sciences 110:44 (Oct. 29, 2013) at 

17,768-17,773, available at http://www.pnas.org/content/110/44/17768.full.pdf+html

(supplemental appendices and tables available at

http://www.pnas.org/content/suppl/2013/09/11/1304880110.DCSupplemental/sapp.pdf). 

69 See Allen, et al., supplemental appendices and tables, Table S2-1.

70 See EPA/GRI, Methane Emissions from the Natural Gas Industry, Vol. 12: Pneumatic Devices 

(June 1996), Section 4.1.2, available at

http://www.epa.gov/gasstar/documents/emissions_report/12_pneumatic.pdf. 

71 40 C.F.R. Pt. 98, subpart W, Table W-1A. 

72 Allen, et al,. supporting information at S-31. 
27 

Low 45,113 1.39 5.1 165,521 

Intermittent 644,295 13.5 17.4 830,425 

High 259,918 37.3 - 259,918 

TOTAL 949,327 1,255,865 

ii. Emissions from PCs in the Natural Gas Transmission and Storage Segments. 

While the 2014 Inventory reports 275,005 tons of methane emissions from PCs in the natural gas 

transmission and storage segments, only 13,310 tons were reported to the GHGRP. As discussed 

above, only larger facilities report emissions to the GHGRP; as such, we assume that the GHGRP 

is underestimating emissions from transmission and storage PCs, since controllers in those 

segments tend to be located at facilities that fall below the GHGRP threshold. Of the two reports, 

the 2014 Inventory value is likely the more accurate estimate of emissions from transmission and 

storage PCs, since the GRI/EPA study on which it was based was designed to estimate emissions 

from PCs nationwide, rather than simply a subset of PCs that covers larger emitters only. 

However, unlike the 2014 Inventory, the GHGRP data allows for emissions estimates based on 

each bleed type of PC. Accordingly, while we use the Inventory data as the starting point to 

estimate emissions from PCs in these segments, we rely on the GHGRP’s ratios of different 

bleed-types to apportion the percentage of those emissions attributable to each type of device. 

C. The Methane Abatement Potential from Controlling Emissions at High- and 

Intermittent-Bleed PCs is Substantial 

The pneumatics white paper does not include total methane abatement estimates, but only 

estimates of total emissions from PCs in each segment and estimates of abatement potentials for 

individual devices. Below, we present a methodology that calculates a methane abatement 

potential of approximately 508,000 tons from emission controls at high- and intermittent-bleed 

PCs. The estimates are shown in the table on the following page, and we describe below section 

assumptions we used in our abatement computations. 

EPA’s 2012 subpart 2012 NSPS required VOC emission controls for PCs at all new oil and gas 

production and gas processing facilities. The agency estimated emission control benefits of 

25,273 tpyVOC, with co-benefits of 90,910 tpy methane and 954 tpy HAPS.73 EPA estimates in 

its TSD that the rule would cover 13,647 devices per year.74 However, the agency declined to 

issue a concurrent or subsequent rule regulating emissions from existing high-bleed devices, 

which currently amount to some 428,000 tons per year.75

The final NSPS rule also did not apply to intermittent-bleed (“IB”) PCs, which EPA did not 

discuss in detail in the pneumatics white paper despite annual emissions of around 830,000 tons 

from existing devices.76 Continuous bleed controllers (including low-bleed units) and IB devices 

serve similar, and in many cases identical, purposes. The American Petroleum Institute (“API”) 

 

73 EPA, Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas 

Production, Transmission, and Distribution: Background Technical Support Document for 

Proposed Standards (July 2011) (hereafter, “TSD”) at 5-25 (Table 5-12). 

74 Id.

75 See Table 12, infra.

76 See Table 13, infra.
28 

has stated that “[a]chieving a bleed rate of < 6 SCF/hr [i.e., the average vent rate required of new, 

continuous-bleed controllers] with an intermittent vent pneumatic controller is quite reasonable 

since you eliminate the continuous bleeding of a controller.”77 PCs emitting less than 6 scfh 

(including both continuous-bleed and IB devices) can serve many of the functions of higheremitting intermittent devices, which could therefore be replaced with low-bleed controllers. There 

are many applications for PCs, as well as a wide variety of parameters for controller design, such 

as pressure, extreme temperature performance, response time, flow rate, corrosiveness of fluids, 

and more. As such, there are many controllers of both continuous-bleed and IB design on the 

market, including many emitting below 6 scfh.78 Indeed, the emissions factor for IBs in natural 

gas transmission is 2.35 scfh,79 well below 6 scfh. 

Our estimates herein are focused on the additional methane abatement potential that can be 

achieved by converting existing oil and gas sector high-bleed and intermittent-bleed PCs to lowbleed devices, a control requirement that should have been included in the 2012 NSPS rule but 

was not.80 We conservatively estimated that 95% of existing high-bleed PCs could be replaced 

with low-bleed PCs. While EPA’s Natural Gas STAR Program Partners reports that 

approximately 80% of high-bleed PCs can be replaced or retrofitted with low-bleed devices,81

experience in the Denver-Julesburg (“D-J”) Basin in Colorado suggests that replacing nearly 

100% of high-bleed controllers with low-bleed devices is feasible. Colorado required operators to 

replace existing high-bleed controllers in the urban portions of the D-J Basin in 2009.82 The rule 

contained provisions allowing operators to keep high-bleed controllers in service if they showed 

that doing so was necessary for “safety and/or process purposes.”83 No operator requested such an 

exemption,84 and there is no evidence in the record that these requirements have caused any 

operational problems. Accordingly, we use Colorado Department of Public Health and the 

Environment’s (“CDPHE”) estimate that 95% of high-bleed devices can be replaced with lowbleed units.85 We use this estimate for oil and natural gas production PCs and natural gas 

transmission and storage PCs. 

 

77 API, Technical Review of Pneumatic Controllers by David Simpson, P.E. (October 14, 2011), 

cited in Rebuttal Statement Of The Sierra Club, Natural Resources Defense Council, Earthworks 

Oil And Gas Accountability Project And Wildearth Guardians, available at 

ftp://ft.dphe.state.co.us/apc/aqcc/REBUTTAL%20STATEMENTS,%20EXHIBITS%20&%20AL

T%20PROPOSAL%20REVISIONS/Conservation%20Group/Conservation%20Groups%20-

%20REB%20Exhibits.pdf. 

78 For discussion of low-bleed devices, including some specific low-bleed devices, see EPA, 

Lessons Learned from Natural Gas STAR Partners: Options For Reducing Methane Emissions 

From Pneumatic Devices In The Natural Gas Industry (Oct. 2006) at 2, available at

http://epa.gov/gasstar/documents/ll_pneumatics.pdf.

79 40 C.F.R. Pt. 98, subpart W, Table W-3. 

80 As discussed on pages 29-30 below, data available to EPA at the time of the 2012 NSPS 

rulemaking supported regulations for existing PCs. 

81 EPA, supra n. 78, at 2. 

82 See 5 C.C.R. § 1001-9 XVIII (2009), available at 

https://www.sos.state.co.us/CCR/GenerateRulePdf.do?ruleVersionId=2772&fileName=5%20CC

R%201001-9. 

83 Id. § 1001-9 XVIII.C.3 (2009). 

84 Email from Daniel Bon, CDPHE, to David McCabe, Clean Air Task Force, 1 November 2013, 

attached hereto as Ex. 3. 

85 Colorado Air Quality Control Commission, Cost-Benefit Analysis for Proposed Revisions to 

AQCC Regulations No. 3 and 7 (Feb. 2, 2014), at 32, available at 
29 

In its March 2014 report co-authored with EDF, ICF International estimated that 75% of 

intermittent-bleed PCs in oil and gas production function as dump valves on separators at well 

sites and did not recommend replacing these PCs with lower-emitting devices.86 To set a lower 

limit to our calculated abatement potential, we use this figure to estimate that 25% IB units in the 

production sector can be replaced with low-bleed PCs.87 For the natural gas transmission and 

storage segments, IB PCs emit at a very low rate, and we do not consider replacing them in these 

calculations. 

We used the best available emissions factors for PCs of each bleed type88 to estimate the potential 

emissions abatement from replacing high- and intermittent-bleed PCs with low-bleed PCs. To 

estimate emissions from PCs in oil and gas production, we use the figures from the GHGRP as 

adjusted by the emissions factors from Allen, et al., as well as the percentage breakdown between 

bleed types from the GHGRP data. For emissions from PCs in natural gas transmission and 

storage, we use the data from the 2014 Inventory and assume that the portion of emissions 

originating from each bleed type is the same as indicated in the GHGRP data. 

 

The resulting potential abatement is shown in the tables below. In summary, we compute an 

emission control benefit of 507,286 tpy of methane, with co-benefits of 96,115 tpy of VOC 

emissions and 3,198 tons per year of HAP emissions.89 The control cost of these measures ranges 

from approximately $25 to$208 per short ton of methane depending on the segment and type of 

pneumatic controller being replaced, without accounting for profits from the sale of captured gas 

or reduced operating and maintenance costs. If captured gas sales and operating cost reductions 

are included, economic attractiveness of these measures improves; in fact, in most cases, the 

control measures will generate positive cash flow for operators. The tables that follow illustrate 

the emission abatement potential from these control measures. 

Table 12: Emission Abatement Potential of Converting PCs from High-Bleed to Low-Bleed 

Industry 

Segment 

Current 

Emissions 

From HighBleed 

Controllers 

Highbleed 

emissions 

Lowbleed 

emissions 

Percent 

of HighBleed 

converted 

to LowBleed 

Emissions 

Abated Percent 

Emissions 

Abated 

tpy scf/hour/ 

device 

 scf/hour/ 

device tpy 

 

ftp://ft.dphe.state.co.us/apc/aqcc/COST%20BENEFIT%20ANALYSIS%20&%20EXHIBITS/CD

PHE%20Cost-Benefit%20Analysis_Final.pdf. 

86 EDF/ICF International, Economic Analysis of Methane Emission Reduction Opportunities in 

the U.S. Onshore Oil and Natural Gas Industries (March 2014) at 3-15, available at 

http://www.edf.org/sites/default/files/methane_cost_curve_report.pdf. 

87 We note that it may not be necessary to replace an IB PC with a continuously emitting lowbleed device – the replacement can be intermittent bleed so long as it emits no more than a lowbleed device (6 scfh). 

88 For low- and intermittent-bleed PCs in petroleum and natural gas production, we used the 

Allen, et al. emissions factors (5.1 and 17.4 scfh, respectively). For other PCs, we used the 

GHGRP emissions factor (37.3 scfh for high-bleeds in petroleum and natural gas production; ). 

89 The ratio of methane to VOC and HAP is based on the values in the 2012 TSD at 5-25 (Table 

5-12). 
30 

Oil and Gas 

Production 259,918 37.3 5.1 95% 213,161 82% 

Gas Transmission 

& Storage 167,754 18.2 1.37 95% 147,370 88% 

Totals90 360,531 84% 

Table 13: Emission Abatement Potential of Converting PCs from Intermittent-Bleed to Low-Bleed 

Industry 

Segment 

Current 

Emissions 

From Int.-

Bleed 

Controllers 

Int.-bleed 

emissions 

Lowbleed 

emissions 

Percent 

converted 

to LowBleed 

Emissions 

Abated Percent 

Emissions 

Abated 

tpy scf/hour/ 

device 

 scf/hour/ 

device tpy 

Oil and Gas 

Production 830,425 17.4 5.1 25% 146,756 18% 

Table 14: Overall Emission Abatement Potential from PC Control Measures (tons per year)

Emissions Type

Current Methane 

Emissions 

Overall 

Abatement 

Percent 

Methane 

Abatement 

VOC 

Abatement 

HAP 

Abatement 

tpy tpy 

Oil and Gas 

Production 

Segments 1,255,865 29% 359,916 91,944 3,428 

Transmission 

and Storage 

Segment 275,005 54% 147,370 4,171 126 

Totals 1,530,870 33% 507,286 96,115 3,554 

By controlling 95% of high-bleed PCs and 25% of IB PCs, over 507,000 tpy of methane pollution 

can be avoided, or about one-third of methane from all types of PCs. 

 

90 We do not address PCs in the gas processing segment due to very low emissions. 
31 

D. Control Costs to Convert Existing High-Bleed Pneumatic Controllers to Low-Bleed 

Devices 

The cost to replace a high-bleed and intermittent-bleed pneumatic controllers with low-bleed 

controller is very modest. Here, we estimate the cost for retrofitting an existing PC with a new PC 

by considering the full cost of the replacement controller. Our estimate is conservative because 

we assume in all cases that the existing higher emitting controller would have continued operating 

for another ten years, the full lifetime of the new device. We do not account for the fact that a 

portion of the higher-emitting devices will have already reached the end of their useful lives by 

the time the replacement is required. 

Very recently, the CDPHE estimated the cost of replacing high-bleed controllers in this manner.91

Based on labor and equipment costs of $1,420 per device replaced, CDPHE calculated a 

replacement cost of $169/yr/device, assuming that costs were annualized over fifteen years at a 

5% interest rate.92 ICF cited industry feedback in reporting that the total replacement cost per 

device could be as high as $3000.93 As an upper limit, we annualize the ICF figure over10 years 

at a 7% interest rate to arrive at an annual control cost of $427/yr/device. These equipment costs 

bracket EPA’s estimate in the OOOO TSD of $2,554 for a new low-bleed controller.94 In some 

cases, the cost can be as low as $700 per new controller,95 although the estimates we present in 

the table below use CDPHE’s $1,420 per device (or $169/year) figure as the lower bound. These 

costs apply to replacing either a high-bleed or intermittent-bleed PC with a new low-bleed device. 

EPA’s NSPS estimated that converting from a high-bleed PC to a low-bleed controller would 

reduce methane emissions by 6.65 tpy for devices in the production and processing segment and 

2.96 tpy for devices in the transmission and storage segments.96 We calculate the methane 

emissions abatement for replacing an IB PC with a low-bleed PC to be 2.28 tpy per device based 

on the emission factors cited in Allen, et al. Without considering the increased revenue could 

obtain by selling gas that would have otherwise been vented, the control measures described 

above have very reasonable abatement costs of $25 to $208 per ton of methane, depending on the 

industry segment and the type of controller being replaced. Table 15 below provides these cost 

control figures. These costs per ton of methane abatement are well below the harm to society 

caused by a ton of methane emissions, which EPA economists recently estimated at $970 per 

metric ton (or $879 per short ton).97

Table 15: Abatement Costs for Pneumatic Controller Replacement

 

91 This analysis was not described in the white papers. 

92 Colorado Air Quality Control Commission, supra n. 85, at 32. 

93 EDF/ICF International, supra n. 86, at 3-16. 

94 TSD at 5-14. 

95EPA and Occidental Oil & Gas Corporation, Methane Recovery from Pneumatic Devices, Vapor 

Recovery Units and Dehydrators (Oct. 6, 2005) at 8, available at

https://www.globalmethane.org/documents/events_oilgas_20051006_methanerec_pd_vru_dehy.p

df. 

96 TSD at 5-6 (Table 5-2). Using the emissions factors from Allen, et al. would result in slightly 

smaller emissions abatement from high-bleed replacement. 

97 See Marten, supra n. 17. 
32 

Switch from High- to 

Low-Bleed Pneumatic 

Controllers 

Annual Cost per 

Device 

Methane reduced 

per component 

Abatement Cost 

($/short ton) 

Low 

($/year) 

High 

($/year) ton / year Low High 

Oil and Gas Production 

$169 $427 

6.65 $25.41 $64.21 

Transmission and Storage 2.96 $57.09 $144.26 

Switch from 

Intermittent- to LowBleed Pneumatic 

Controllers 

Annual Cost per 

Device 

Methane reduced 

per component 

Abatement Cost 

($/short ton) 

Low 

($/year) 

High 

($/year) ton / year Low High 

Oil and Gas Production $169 $427 2.28 $82.44 $208.29 

When accounting for increased revenue from sales of conserved gas that would otherwise have 

been emitted, CDPHE analysis shows that replacing high-bleed controllers with low-bleed 

controllers has a negative annual cost (a saving of over $1,000 per year, assuming a gas price of 

$3.50/Mcf).98 We note that these revenues would be available to operators in oil and gas 

production only, since operators of transmission and storage facilities do not own the gas they 

transport or store. For production segment operators, the payback period for this replacement is 

about 14 months. For replacement of an IB controller with a low bleed controller, using the cost 

figures from the CDPHE analysis but adjusting for the smaller emissions reductions and 

additional revenues for this case, we calculate net savings of approximately $270 based on the 

CDPHE’s estimates. 

Using more conservative cost and the revenues from the resale of captured gas and reduction in 

operating costs, we still find that conversion from high-bleed to low-bleed devices results in net 

savings for production segment operators. The 2014 ICF report concluded the conversion from a 

high-bleed controller to a low-bleed controller, even at a cost of $3,000 per device, resulted in an 

overall savings: “Although there are lower cost estimates from Gas STAR and vendors, this 

measure assumed a cost of $3,000 per replacement based on industry comments. Both options 

yield a greater than 90% reduction. This yields a reduction cost of ‐$3.08/Mcf of methane for 

replacement of high bleed pneumatics . . . .”99

E. Device Classification Issue in the 2013 Prasino Group Study 

The Prasino Group’s 2013 study of emissions from pneumatic controllers is described in the 

pneumatics white paper. However, the white paper description of the study omits a few key 

aspects of the Prasino study. While the 2012 NSPS rulemaking, GHGRP, and calculations 

underlying the 2014 Inventory all use an emissions factor for high-bleed PCs of 37.3 scf/h natural 

gas, the Prasino study reports that a “generic high-bleed controllers” actually emits only 9.2 

scf/h.100 Yet the white paper fails to note that Prasino includes a number of PCs in that were 

 

98 Colorado Air Quality Control Commission, supra n. 85, at 32-33. 

99 EDF/ICF International, supra n. 86, at 3-16. 

100 Pneumatic Controller White Paper at 24 (Table 2-9). 
33 

designed to emit below 6 scf/h—and thus considered low-bleed units– but were actually emitting 

at some level above 6 scf/h: 

Devices that were determined to be high bleeding (i.e. bleed rate >0.17 m3/hr [6 

scf/h]) were grouped together in the analysis. If the calculated mean bleed rate 

was larger than the threshold, the device was included in the analysis, and if the 

calculated mean bleed rate was smaller than the threshold, the device was 

excluded from the analysis for determining a generic bleed rate. Certain 

controllers that are considered low-bleeding according to WCI or manufacturer 

specifications actually bled above the low bleed threshold and were therefore 

included in the analysis.101 

The Prasino Group study results raise an important problem: PCs designed to emit less than 6 

scf/h are considered low-bleed PCs but may, in fact, emit more in real operations in the field due 

to factors such as excess wear, installation with incorrect supply pressure, etc. The Prasino results 

show that this problem can be common. For example, the Prasino measurements show that the 

Fisher 2680 and L2 level controllers, which have manufacturer specified bleed rates well below 

the threshold rate of 6 scf/h, both emit gas at average rates significantly higher than the threshold.

Prasino measured 32 Fisher 2680 units, which have a specified bleed rate of 0.04 m3/h (1.4 scf/h), 

and found average bleed rates of 0.268 m3/h (9.5 scf/h).102 They also measured 48 Fisher L2 

controllers, which have a specified bleed rate of 0.06 m3/h (2.1 scf/h), and found average bleed 

rates of 0.264 m3/h (9.3 scf/h).103

While the excess pollution from these controllers is a significant concern,104 a large body of 

evidence, including the 1996 GRI/EPA study and GasSTAR data and reports,105 shows that 

emissions from high-bleed controllers are typically much higher than these rates.106 Indeed, the 

manufacturers’ specifications for high-bleed PCs listed in the Prasino study show that many highbleed units are designed to emit at far higher rates.107 The problem of excessively high emissions 

from PCs that are designed to emit at very high rates should not be obscured or made to appear 

less severe by averaging emissions from low-bleed controllers emitting excessively alongside 

high-bleed controllers. 

 

101 Prasino Group, Final Report For Determining Bleed Rates for Pneumatic Devices in British 

Columbia (Dec. 18, 2013), at 15, available at http://scek.ca/sites/default/files/ei-2014-01-finalreport20140131.pdf. 

102 Id. at 14, 30. 

103 Id. 

104 We note that the same phenomenon is apparent in the data from Allen, et al., which reported 

that low-bleed PCs were venting 5.1 scf/h, 270% more gas than EPA’s emissions factors predict. 

The average emissions from low-bleed unit is only slightly below the 6 scf/h threshold, strongly 

suggesting that a significant number of the low-bleed PCs measured by Allen, et al. were emitting 

at rates greater than 6 scf/h. 

105 See, e.g., http://www.epa.gov/gasstar/tools/recommended.html#pneumatics. 

106 For example, third party verification of emissions of 18–22 scf/h was measured for 148 

controllers from three manufacturers in a high-bleed controller retrofit project by Chesapeake 

Energy registered with the American Carbon Registry. See

http://americancarbonregistry.org/mount_acr/acr/carbon-registry/projects/chesapeake-mizerpneumatic-retrofit-project/CHES-PNEU-2011-03-31.pdf (hereafter “Chesapeake retrofit project”) 

at 31. 

107 See Prasino Group, supra n. 101, at Appendix A. 
34 

Because of the design of the Prasino study, it is not appropriate to consider it when evaluating the 

merits of replacing high-bleed PCs with low-bleed PCs. Namely, Prasino included PCs in their 

results that would not be targeted by a typical effort to replace high-bleed PCs. However, the 

Prasino study does highlight the issue of excess emissions from low-bleed PCs. For example, as 

we have discussed, the study showed that the actual emissions from Fisher 2680 and L2 level 

controllers are 6.7 and 4.4 times higher than their specified values. The excess pollution from 

these devices suggests that EPA should also be evaluating technologies to replace PCs that bleed 

any amount of natural gas into the atmosphere, such as electronic devices. We discuss this further 

in our response to the white paper’s charge questions. 

Finally, we note that Section 2.3.4 of the Prasino Group Study includes a useful discussion of the 

errors, uncertainty, and biases involved in developing this lower emission factor.108 Factors that 

may have contributed to a lower emission factor include back pressure on the control device 

imposed by the meter used to measure emissions and exclusion bias from non-random sampling 

location choice, since permission was required by operators to conduct testing. This could have 

resulted in directed sampling in areas with less high-bleed devices. 

F. Summary 

Using existing data from the GHGRP and the EPA’S 2014 GHG Inventory, we calculate a 

methane abatement opportunity of 507,286 tpy from replacing high- and intermittent-bleed 

pneumatic controllers with low-bleed pneumatic controllers in specified segments of the oil and 

gas industry. The cost of this abatement varies between segments and for difference pneumatic 

controller types, but all of the measures are cost-effective using current technology, and 

abatement for PCs in oil and gas production generate net profits for operators due to potential 

revenue from conserved gas sales. 

Additionally, we support EPA’s consideration of measures that would require operators to replace 

continuous bleed controllers with zero-bleed PCs, units powered by instrument air, or solar 

powered systems wherever technically feasible. However, EPA must not delay developing and 

implementing a methane control rule that would require the measures described in our analysis 

while the agency gathers data on these other options. EPA must immediately move forward with 

rulemaking that requires replacement of all high-bleed controllers with zero-bleed controllers 

when feasible and with low-bleed controllers where technically possible, and, as a second and 

separate rulemaking step, examine the incremental cost and feasibility of replacing all continuous 

bleed controllers with zero-bleed devices, instrument air controllers, or electronically-powered 

systems. 

G. Charge Questions for Reviewers 

1. The white paper did not adequately describe the Prasino Group study from 2013. As 

explained above, this study averages together emissions from low-bleed PCs that emit 

methane at rates greater than their operationally specified rates with emissions from highbleed controllers, which typically emit at rates much higher than those observed at even 

the worst performing low-bleed PCs in the study. As such, the Prasino study, while 

raising important issues, is not appropriate for evaluating emissions of high-bleed 

 

108 See id. at Section 2.3.4. 
35 

controllers as that term is typically used, nor is it appropriate for quantifying the benefits 

of replacing high-bleed controllers with lower-emitting devices. 

2. The variation in measured emissions from PCs across different studies is due in part to 

inconsistent definitions of PC bleed types. For instance, we have described how the 

Prasino study included a significant number of low-bleed PCs emitting at rates higher 

than those specified by manufacturers in their “high-bleed” dataset. This approach lowers 

their average emissions rate for “high bleed controllers” significantly. 

3. The white paper described a variety of technologies available to reduce emissions, but 

described some too narrowly. For example, electronic control instrumentation is 

described in section 3.1.4. While solar cells may provide an excellent source of electrical 

power for this type of instrumentation, other options include grid power, which may be 

close at hand given the development of oil and gas in populated areas in recent years, and 

power from thermoelectric generators109 or small onsite gas generators. Furthermore, 

retrofit kits are available to reduce emissions from some high-bleed PCs.110 These options 

are not described in the white paper, and the agency should evaluate their availability and 

efficacy. 

4. As explained above, we believe that non-emitting technologies such as zero-bleed 

controllers, instrument air devices, and electronically control systems should be required 

whenever they are feasible. The reports that emissions from low-bleed controllers are 

higher than expected from manufacturer specifications (the Prasino Group study) and 

broad emissions factors (Allen, et al.) reinforce the need to examine non-emitting 

technologies. However, as stated above, EPA must not delay a methane control rule that 

captures the majority of emissions from oil and gas sector PCs while gathering data on 

these non-emitting options. EPA must immediately move forward with rulemaking to 

replace high-bleed controllers with low-bleed units while encouraging or requiring nonemitting options where feasible. 

5. While we cannot comment on the prevalence of different types of pneumatic controllers 

and non-emitting technologies in the field, or on the particular activities that require the 

use of high-bleed PCs, we reiterate that the industry response to the 2009 Colorado rules 

demonstrates that applications truly requiring high-bleed PCs are quite rare indeed. While 

the 2009 rules allowed operators to request an exemption from the retrofit requirement, 

not a single exemption request was received by CDPHE. 

6. We have no response to this charge question at this time. 

7. We have no response to this charge question at this time. 

8. Given the abundant fuel available at oil and gas facilities and the wide variety of natural 

gas- powered compressors and generators available on the market, instrument air systems 

could easily be developed to match the compressed air requirements of any facility at a 

reasonable cost. However, the great bulk of emissions from pneumatic valve and 

controller systems come from the controllers themselves, as opposed to actuators. Given 

 

109 See, e.g., http://en.wikipedia.org/wiki/Thermoelectric_generator#Uses. 

110 For example, Mizer valves used in the Chesapeake retrofit project. See Chesapeake retrofit 

project at 9.
36 

the advances in electronics, electronic control systems should be considered for many PC 

applications, and may be more appropriate and result in lower emissions than instrument 

air systems for many applications given very low power requirements of electronics. In 

spite of this, EPA and the Natural GasSTAR program have not summarized the state of 

this technology for many years. We strongly urge them promptly to do so. 

9. We are aware that EDF and the University of Texas are currently studying methane 

emissions from PCs in the oil and gas sector. We are not aware of other ongoing research 

on this particular issue apart from this. 

V. Comments on the Liquids Unloading White Paper 

The vast majority of gas wells co-produce liquids, including both hydrocarbons and water. As gas 

wells age, gas rates decline and gas velocity up the well declines to the point that it cannot lift 

these liquids, which then accumulate in the wellbore. Liquid loading can impair gas production 

rates or arrest gas flow completely. Once the accumulated liquids are removed from the wellbore, 

there is less backpressure on the gas formation, allowing gas flow to resume, or resume at a 

higher rate. For this reason, gas well operators have been voluntarily investing in methane 

abatement technology for many years, with the primary goal of improving gas well production 

performance.111

Liquids accumulation is an extremely common occurrence, and liquids unloading is 

correspondingly a common practice. In comments on the 2011 NSPS proposal, the American 

Petroleum Institute asserted that all gas wells producing 90 Mcf of gas (15 BOE or less) or less 

per day “are either impaired by liquids accumulation or are using a deliquification method to 

produce.”112 In that comment, API relied on 2009 EIA data to conclude that 73% of all gas wells, 

or 338,056 wells, fell into this category.113 In 2012, API and ANGA surveyed 59,648 wells and, 

on the basis of this survey, concluded that in 2011, 268,609 wells, or 55% of all gas wells, 

proactively unloaded liquids114

. 

Liquids can be unloaded through a variety of techniques. Most basically, the well can be simply 

vented, sometimes referred to as a “blowdown.” A typical operating configuration has produced 

fluids flowing from the well into pressurized surface equipment. To unload through venting, the 

 

111 There are hundreds of Oil and Gas Sector technical publications written on methods to 

increase gas production by optimizing gas well deliquification. Many of these publications 

include economic assessments of improved profitability. The most efficient location to access 

these publications is the OnePetro online library of technical literature for the oil and gas 

exploration and production (“E&P”) industry. OnePetro at www.onepetro.org. OnePetro contains 

172 technical publications on gas well deliquification and 846 technical publications on liquids 

unloading, 780 papers on plunger lifts, and hundreds of other papers on other artificial lift 

methods for gas wells. 

112 American Petroleum Institute (API), Comments to U.S. EPA on Docket ID No. EPA-HQ-OAR2010-0505 (Nov. 30, 2011), available at http://www.regulations.gov/#!documentDetail;D=EPAHQ-OAR-2010-0505-4266. 

113 Id. (citing http://www.eia.doe.gov/pub/oil_gas/petrosystem/us_table.html). 

114 API/ANGA. Characterizing Pivotal Sources of Methane Emissions from Natural Gas 

Production Summary and Analysis of API and ANGA Survey (Sept. 21, 2012), available at 

http://www.api.org/~/media/Files/News/2012/12-October/API-ANGA-Survey-Report.pdf. 
37 

well is instead allowed to flow to a pit or tank at atmospheric pressure, removing back-pressure 

from the surface equipment. The increased pressure differential between the formation and the 

surface allows more gas to flow at a higher velocity and push accumulated liquids out of the well. 

A more sophisticated approach is to use a plunger lift. A plunger lift is a simple and common 

artificial lift method used to efficiently lift liquid out of a well to optimize gas well production 

rates. Use of plunger lift systems can also produce a co-benefit of methane abatement. The main 

practical advantage of the plunger lift system is that it does not require electricity, and so can be 

installed at well sites that do not have power. A plunger lift system is powered by the natural gas 

pressure that builds up in the casing tubing annulus. Installation of a plunger lift generally 

increases gas production by 10%. Plunger lift performance can be improved through smart 

automation, which can bring the production increase up to 20%. The API/ANGA study estimates 

that of the 268,609 wells that underwent liquids unloading in 2011, 28,863 vented, 174,743 used 

plunger lifts, and 65,003 used other artificial lift methods.115

Plunger lifts are only one of many available artificial lift technologies—numerous additional 

systems can be used as well, including: 

• Pumping techniques, such as progressing cavity pumps, hydraulic pumps, beam pumps, 

and electric submersible pumps 

• Chemical methods, such as soap sticks 

• Gas lift 

• Velocity tubing 

• Compression 

A. Emissions from Liquids Unloading 

Liquids unloading through venting or plunger lifts can emit significant methane, VOC, and other 

pollutants. Emissions are inevitable for simple blowdowns. For plunger lifts, although 

API/ANGA data indicates that the majority of plunger lift installations (79%) have no 

emissions,116 21% are operated in a way that still releases appreciable pollution. The white paper 

summarizes the API/ANGA data on liquids unloading emissions together with two other 

estimates of national unloading emissions: the 2014 GHG Inventory and the 2013 GHG reporting 

rule data. The 2014 Inventory and GHGRP emission factor estimates, however, are informed by 

the API/ANGA data.117 The white paper also discusses the evidence Allen et al. collected about 

unloading emissions through direct measurement of several wells. 

Table 16: Summary of Liquid Unloading Methane Emissions 

API/ANGA GHGIe GHGRPd Allen 

# Wells with Unloading Emissions (total) 65,669 60,810 58,663

plunger lift 36,806 23,503 32,252

 

115 API/ANGA at 13-14. 

116 API/ANGA estimate that 174,743 wells have plunger lifts, API/ANGA at 13, but that only 

36,806 wells of these wells have emissions associated with unloading, id. at 14. 

117 See footnote “b,” Liquids Unloading White Paper, Table 2-4. The GHGI incorporates region 

specific emission factors; differences between GHGI and API/ANGA activity factors for each 

region lead to different nationwide averages for activity factors here. 
38 

venting 28,863 37,307 26,411

Total Unloading Methane Emissions 

(short tons per year) 

352,366 301,554 304,651.5

Methane Emissions per well (avg, all wells 

w/emissions), tpy 

5.37b4.96b5.19b6.39

Methane Emissions per plunger lift well with 

emissions, engineering estimate, tpy 

a

5.58 4.1

Methane Emissions per vented well, engineering 

estimate, tpy 

a

4.6 3.4

Methane Emissions per well, direct 

measurement, tpy 

 12.4c6.39

a

 API/ANGA do not separate emissions for plunger lifts from emissions from vented wells. 

b

 Total estimated emissions divided by number of wells. 

c

 Different wells than those for which engineering estimates provided. The GHGI does not 

specify which wells were directly measured. 

d Data derived from Liquids Unloading Whitepaper Table 2-2 

e Data derived from Liquids Unloading Whitepaper Table 2-4; emission factors estimates for 

plunger lift and venting wells are weighted averages of the emission factors given for the six 

regions. 

Although these estimates differ at the margins, they reveal general trends: 

• Total methane emissions from unloading exceed 300,000 tpy. The 2014 Inventory, which 

had the lowest estimate of total emissions, concluded that, as summarized by the white 

paper, “liquids unloading emissions in 2012 were 14% of overall methane emissions 

from the natural gas production segment.” 

• Roughly 60,000 wells have unloading emissions annually. 

• Approximately half of these wells use plunger lifts and the other half vent. 

• Average methane emissions for wells that emit are roughly 5 tpy. 

• Average emissions for wells that emit despite using plunger lifts are higher than average 

emission from wells that unload using blowdowns. This does not suggest that plunger 

lifts fail to reduce emissions: operators are more likely to have voluntarily installed 

plunger lifts on high-producing and high-emitting wells where uncontrolled emissions 

would be much higher than the average emission with plunger lifts installed reported 

here. 

Several of the marginal differences in these estimates are to be expected. As we have explained 

elsewhere, the GHGRP data should, as it does, include fewer wells than the 2014 Inventory, 

given that the GHGRP only collects data from large sources. 

While the API/ANGA, 2014 Inventory, and GHGRP data are in broad agreement, there are many 

reasons why all three data sets are likely to be conservative. First, the API/ANGA, 2014 

Inventory, and (to a large extent) GHGRP emission factor estimates rely largely on engineering 

calculations, but it is notable that the GHGRP data derived from direct measurements is higher 

than that derived from engineering calculations. 

Second, the survey data underlying emission factor estimates in the API/ANGA and 2014 

Inventory is markedly lower than data underlying EPA’s previous estimates, and EPA has not 

explained why the data underlying these former estimates is no longer relevant. Although the 

API/ANGA study’s activity factor estimates are based on a survey of nearly 60,000 wells 
39 

covering 18 basins, the study’s emission factor estimates rest on data from 5,327 wells that vent 

during unloading, from an unknown number of basins.118 Prior to the API/ANGA study, EPA 

estimated emission factors for wells that vent during unloading on the basis of prior data from 

2,219 venting wells (2,200 wells in the San Juan Basin and 19 wells in Big Piney, Wyoming) 

regarding frequency of blowdowns, or venting, and engineering calculations of emissions per 

blowdown.119 Using these inputs, the 2011 Inventory estimated an emission factor of 27.2 tons 

per year per liquid unloading event—over five times the API/ANGA estimated emission factor.120

Although San Juan and Big Piney data encompassed only half the number of wells used in the 

API/ANGA study, it appears that this data could be used in conjunction with data from the 5,327 

wells in the API/ANGA study. EPA should also request that API/ANGA provide location data for 

the 5,327 wells used to determine the emissions factor in the API/ANGA study, so that any 

geographic differences may be analyzed. 

Third, the API/ANGA data may reflect reporting bias and not be representative of all U.S. gas 

well emissions. There is not sufficient information in the survey to confirm that data selected by 

2012 API/ANGA members for calculation of the emission factor estimate provides an accurate 

representation for liquids unloading emissions across the United States for all wells that have 

unloading emissions. The API/ANGA estimates are based on data volunteered by API/ANGA 

members. Little information was made publicly available about the survey methods, which 

companies reported data, or whether the data is representative of nationwide emissions. 

Accordingly, estimates derived from this self-reported data are likely biased towards lower 

emissions and thus conservative. 

Finally, the API/ANGA data makes it very clear that liquids unloading emissions can be 

extremely high in some basins. Since liquids unloading emits raw gas, which is often rich in 

VOC and has significant amounts of HAP, this can affect air quality in regions with dense gas 

production. For example, one respondent to the API/ANGA survey reported emissions in the 

Rocky Mountain region of over 6 million cubic feet of gas per well in 2011. Using EPA’s 

standard ratios of VOC and HAP to methane for raw gas, this suggests that VOC and HAP 

emissions were 18.5 tons of VOC and 1.34 tons of HAP per well per year. Given the high 

concentration of wells in some areas (and the tendency for wells for a single operator to be 

 

118 API and ANGA, Characterizing Pivotal Sources of Methane Emissions from Unconventional 

Natural Gas Production, Summary and Analysis of API and ANGA Survey Responses, Final 

Report, (Updated Sept. 21, 2012), Table 6, page 14, Liquids Unloading Emission Estimation 

Based on Survey Data. 5,327 wells is the sum of the well counts for plunger-equipped wells that 

vent and non-plunger-equipped wells that vent. This total number of wells is also found by 

totaling the well counts listed in Tables C-1 through C-4 in Appendix C of the report. API and 

ANGA previously released a “Final Version” of this report which only listed 5,276 wells in 

Tables C-1 through C-4. Some entries in the tables in the previous version were removed in the 

later version; other entries absent in the earlier version appeared for the first time in the later 

version. No explanation is given for the changes in the data between the two versions. 

119 EPA, Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry: 

Background Technical Support Document (Nov. 2010), pp. 89-90, available at 

http://www.epa.gov/climate/ghgreporting/documents/pdf/2010/Subpart-W_TSD.pdf. EPA’s 

previous estimate was based on reports of emissions from 2,200 wells in the San Juan Basin and 

19 wells in Big Piney (Wyoming). 

120 This represents the weighted average of “Well Clean Ups (LP Gas Wells)” data from each 

reporting region. See EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks (1990-2009), 

(Apr. 15, 2011), Annex 3, pages A-149 to A-153. 
40 

geographically grouped for logistical purposes), this suggests that emissions can be very high in 

some regions. In the extreme case in the API data, a single operator reported emissions of over 

187 million cubic feet of gas in a single year in the Midcontinent region, which implies 568 tons 

of VOC and 41 tons of HAP.121

B. Available Control Technologies 

Plunger lifts avoid venting by removing liquid from the well before liquid loads reach levels that 

“kill” the well and halt gas production. If a plunger lift is not operated optimally, however, liquid 

sufficient to kill the well can eventually accumulate despite the presence of the plunger lift, and in

these cases, the well can be vented for a short period of time to generate the differential pressure 

needed to resume well liquid removal. 

These intermittent periods of venting can be avoided by optimizing operation of the plunger lift, 

typically with an automated controller. Automated controllers also enhance plunger lift 

performance by monitoring wellhead parameters such as tubing and casing pressure, sales line 

pressure, flow rate, and plunger travel time to minimize manual well venting when the plunger 

lift is overloaded. Automated controllers can be made “smart” to monitor and better time 

automation, producing further emission reductions and increases in well production. 

There are numerous other artificial lift methods that are also common, easy to install and operate, 

and can achieve high methane abatement efficiencies. These methods include: installation of 

smaller diameter tubing (velocity string), use of compression, foam, hydraulic pumps, beam 

pumps, gas lift, electric submersible pumps, progressive cavity pumps, among other methods.122

The white paper omits discussion of several of these methods of liquids unloading, notably gas 

lift. Gas lift re-injects produced gas to reduce bottom-hole pressure and increase gas production 

rate to lift liquids. Gas lift has several advantages over other lift methods, including that it can be 

used in highly deviated wells.123 Gas lift has primarily been used in offshore wells, but is growing 

in popularity for onshore applications. EPA should consider gas lifts as one of many viable liquid 

removal technologies. 

Finally, we note that, if venting during liquids unloading cannot be eliminated using plunger lifts 

with smart automation (see below), EPA should consider requiring operators to capture or, as a 

last resort, flare gas that would otherwise be vented. When liquids are being brought to the 

surface they must be handled in tanks and there are means, such as vapor recovery units, to 

capture gas that would otherwise be vented from tanks during loading operations. 

Several liquids unloading technologies are already prevalent. According to API/ANGA, over 75 

percent of wells that unload are able to do so with no unloading emissions: 

 

121 Calculations based on data listed in API/ANGA data tables. See Petition for Reconsideration 

submitted by Peter Zalzal, Attorney, Environmental Defense Fund on behalf of the Clean Air 

Council, et al. regarding Oil and Gas Sector: New Source Performance Standards and National 

Emission Standards for Hazardous Air Pollutants Reviews, at 5-6, available at

http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2010-0505-4575. 

122 Id.

123 See, e.g. Lea, J. F., Nickens, H. V., & Wells, M., Gas well deliquification (2011), Gulf 

Professional Publishing.; Lea, J.F, and Dunham, C.L. Artificial Lift Advances Address 

Challenges, Trends In Gas Well Deliquification, The American Oil & Gas Reporter (2009).
41 

Table 17: API/ANGA Estimates of Unloading Utilization124

# 

of Wells 

% (of all wells 

that unload) 

Wells with plunger lifts and no emissions 137,937 51.4 

Wells with other artificial lifts and no emissions 65,003 24.2 

Wells with plunger lifts that have unloading emissions 36,806 13.7 

Wells that blowdown/vent to unload 28,863 10.7 

Thus, according to API/ANGA data, available technology allows liquids unloading without any 

emissions from venting the well. Wells that unload using blowdowns can apply these 

technologies to significantly reduce, if not eliminate, their emissions. Moreover, many wells that 

currently emit despite using plunger lifts may lack smart automated controllers or other 

optimizations that would further reduce emissions; adding smart controllers to wells that lack 

them is likely to significantly reduce emissions. 

C. Abatement of Emissions from Wells Currently Unloading with Blowdowns 

The most common, effective control option for wells currently unloading using blowdowns is 

installation of plunger lifts with smart automation. 

Capital costs for a relatively routine plunger lift installation can range from $1,900 to $10,400 per 

well. Costs at the upper end include some amount of remediation for wells, though some wells 

will require higher investment.125 Smart automation can increase the total installation cost to 

$7,600 to $28,000 per well.126 Annualizing the capital cost over 5 years at 7%, and including 

annual maintenance costs of $700 to $1,300 per well,

127 produces a total annualized cost per 

plunger lift of $1,300 to $3,800 per well per year. The yearly cost for a lift with smart automation 

(same equipment lifetime and maintenance costs) would range from $2,600 to $8,200 per well. 

Natural Gas Star partners have reported that plunger lifts decrease gas venting by an average of 

600 Mcf per year per well.128 This translates to a methane abatement cost of between $91 and 

$300 per short ton of methane, not including the added revenue from selling gas not vented. For 

plunger lifts with smart automation, reported abatement ranges from 800 to 1,460 Mcf per year 

per well,129 for abatement costs of between $92 and $540 per short ton, again neglecting the 

revenue from selling the gas instead of venting it. 

If revenue from additional gas sales is included, plunger lifts with or without smart automation 

quickly become profitable, though the former is much more so. The gas captured through 

emissions abatement provides some revenue—including the value of this gas, at $4 per Mcf, 

plunger lifts alone have net abatement costs of -$96 to $110 per short ton of methane, and plunger 

lifts with smart automation have net abatement costs of -$120 to $330 per short ton of methane. 

Far greater revenues are realized by increased well production and prolonged well life. 

 

124 2012 API/ANGA Survey, p. 13-14. 

125 Lessons Learned – Plunger Lifts at 3-4. 

126 Additional costs for smart automation are from Lessons Learned – Fluid Options, Exhibit 9. 

127 Lessons Learned – Plunger Lifts at 4 

128 Id.at 1. 

129 Lessons Learned – Fluid Options at 1. 
42 

Increased production can be substantial (hundreds of Mcf per day for some wells), but will vary 

between wells based on well production and age.130 Furthermore, plunger lifts can reduce 

maintenance and labor costs by reducing the need for well maintenance (such as blowing liquids 

out of the well manually, but also down-hole work to repair damage to wells from the effects of 

long-term liquids build-up). These savings can easily exceed $10,000 per well per year.131 The 

combination of these savings and the increased revenue from increased production can make the 

economic benefits of plunger lift installation very significant.132

Thus, it is likely that most, if not all, unloading emissions from wells using blowdowns could be 

abated using plunger lifts or other artificial lift methods. Using a conservative assumption of only 

90% control and the 2014 Inventory data, the total abatement potential is 154,451 tpy of methane. 

D. Abatement from Wells Already Using Plunger Lifts 

For wells that already have plunger lifts installed but that still have emissions, emissions can 

often be reduced by subsequent installation of smart automation. As explained above, smart 

automation provides significant emission reduction beyond use of plunger lifts that are manually 

operated or simply timed to operate on a fixed period. The API/ANGA data indicates that 79% of 

wells using plunger lifts are able to do so without any liquids unloading emissions. If this is 

correct, it is likely that many of the remaining wells could reduce or eliminate their emissions by 

installing smart automation or similar optimization. 

The Natural Gas STAR data summarized above indicate that adding smart automation provides 

an additional 200 to 860 Mcf per well per year of methane abatement beyond the average 

abatement from use of plunger lifts alone.133 200 Mcf, the bottom of this range, is equivalent to 

4.16 tpy. This reinforces API/ANGA’s indication that optimized plunger lifts can completely 

eliminate emissions, as the 200 to 860 Mcf abatement potential encompasses much of the range 

of estimated emissions for wells with plunger lifts. More conservatively, other industry data 

indicates that smart automation can halve emissions from a well with a plunger lift. BP showed 

that 50% reductions could be achieved on approximately 2,200 wells.134

 

Natural Gas Star partners estimate that the cost of adding smart automation is between $5,700 and 

$17,600.135 In an industry report specifically looking at the benefits of adding smart automation to 

wells, Marathon estimated the cost of a smart automatic controller at $11,000: $5,000 for the 

 

130 Lessons Learned – Plunger Lifts. 

131 See, e.g., id. at 9. 

132 See, e.g., Marathon Oil Company and the Independent Petroleum Association of Mountain 

States, Plunger Lifts and Smart Automation, EPA Natural Gas STAR, Producers Technology 

Transfer Workshop (2008), available at http://www.epa.gov/gasstar/documents/workshops/2008-

tech-transfer/denver3.pdf. 

133 Lessons Learned – Fluid Options at 1. 

134 Pure Automation, Inc., Smart Automation of Plunger Lift Systems, Exploring the Benefits of 

Plunger Automation and Advanced Optimization Technologies (2010). See also Methane to 

Markets, Reduced Emission Completions/Plunger Lift and Smart Automation, Oil & Gas 

Subcommittee Technology Transfer Workshop, January 2009. 

135 Lessons Learned – Plunger Lifts and Lessons Learned – Fluid Options. These values are the 

differences in minimum and maximum prices between plunger lift installation with and without 

smart automation. 
43 

automatic controller and $6,000 for the cost of installing the smart controller upgrade.136 Using 

this figure and annualizing over ten years at a 7% interest rate, this suggests that smart 

automation can reduce emissions from wells with plunger lifts that still vent at an abatement cost 

of at most $380 per ton of methane. 

We note that the data surveyed in the white paper does not indicate what fraction (if any) of wells 

that emit despite using plunger lifts already have smart automated controllers installed. Thus, it is 

difficult to estimate the total methane abatement that could be achieved by installing smart 

automated controllers on wells that lack them. If none of these wells have smart automated 

controllers, a 50% reduction in liquids unloading emissions from these wells represents a 65,573 

to greater than 66,117 tpy reduction, using 2014 Inventory and GHGRP data, respectively.137 If 

we instead use the 4.16 tpy abatement figure indicated by Natural Gas STAR data, and the counts 

of 23,503 to 36,806 wells with plunger lifts with emissions (2014 Inventory and API/ANGA, 

respectively), this provides an abatement potential of 97,772 to 153,112 short tons of methane per 

year. 

E. Responses to Charge Questions 

• Question 1: Above, we have provided comments and critique of the data sources for 

liquids unloading discussed in the white paper. 

• Question 4: As noted above, the white paper did not discuss the use of gas lift to remove 

liquids from wells. 

• Questions 11 and 12: We have raised this issue above. If venting emissions from 

liquids unloading cannot be eliminated with plunger lifts (including smart automation) 

and the other technologies discussed here, EPA must consider requiring “end of pipe” 

controls to prevent emissions of methane. Given the availability of VRUs to capture 

emissions from working and flash losses from tanks and direct this gas, that would 

otherwise be vented or flared, EPA should consider whether VRUs could be used to 

effectively capture emissions that would otherwise be vented. If that is somehow 

infeasible, EPA should consider whether flaring is appropriate for liquids unloading 

emissions. 

VI. Leaks 

Leaks (i.e., unintentional emissions) from static components at oil and natural gas facilities, such 

as tanks, hatches, meters, flanges, valves, connectors, regulators, etc., emitted over 2.4 million 

short tons of methane in 2012, according to EPA’s nationwide estimates in the 2014 U.S. 

Greenhouse Gas Inventory (2014 Inventory). We include here leaks from wellpads (natural gas 

and petroleum), gathering compressor stations, processing plants, transmission compressor 

 

136 Marathon Oil Company and the Independent Petroleum Association of Mountain States, supra 

n.136. 

137 The GHGRP figure is conservative in that it uses the emission factor derived from engineering 

estimates, ignoring the higher average emissions reported in the GHGRP from wells that directly 

measured emissions. The API/ANGA data does not lend itself to a 50% reduction estimate 

because API/ANGA provided neither an emission factor nor a total emission estimate for plunger 

lift wells with methane emissions. 
44 

stations, and aboveground centralized facilities in the natural gas distribution sector, as all of 

these facilities can leak methane excessively and the mitigation approach described below is 

appropriate for all of these facilities.138 As evidenced by independent research described below, 

these figures clearly underestimate leaks from U.S. oil and gas facilities by a significant margin. 

Cost analyses, some of which are described in the EPA’s White Paper, Oil and Natural Gas 

Sector Leaks, clearly show that substantial mitigation of methane emissions from leaking 

components is achievable at reasonable costs to producers through mandatory leak detection and 

repair (LDAR) programs. However, it is notable that these analyses used estimates of leaks from 

these facilities that are consistent with the 2014 Inventory and the information used to create that 

document. It is notable that the costs for LDAR programs these analyses present are reasonable 

despite the fact that, as described below, there is abundant evidence that leak emissions actually 

are significantly higher than reported in the 2014 Inventory. Since the emissions abated by 

LDAR programs will be higher than calculated, based on the 2014 inventory, the actual 

abatement costs will clearly be lower than the costs derived from these analyses. One important 

exception (Carbon Limits, 2013) directly assessed costs associated with LDAR programs 

independent of any general estimate of facility leak rates. The Carbon Limits analysis was 

designed in a very conservative yet robust manner, as described below, yet still supports the fact 

that LDAR programs can be implemented at reasonable costs. 

As shown below, LDAR programs reduce emissions at very reasonable costs. As described 

below, the Carbon Limits analysis shows that monthly LDAR programs costs $1,180 per ton of 

methane abated at compressor stations and $840 per ton at well facilities. Colorado’s estimates of 

the overall costs of their “tiered” program, where facilities with smaller potential leak emissions 

have less frequent LDAR surveys, are less, and data submitted by industry suggests real costs are 

lower yet. 

Given the harm caused by excessive methane emissions, and the availability of LDAR programs 

at a reasonable cost, EPA must address methane emissions from leaks and require facility 

operators to regularly conduct instrument-based leak detection surveys and repair the leaks that 

are identified. 

Our comments for the leaks white paper are structured as follows. 

In Section A, we describe critical synthetic conclusions from reports described in the white paper 

– and reports that it does not describe – that inform key questions on emissions and costs of 

abatement addressed by the white paper. These conclusions are: 1) a large body of published 

research shows that not only are methane emissions from oil and gas are higher than reported in 

the 2014 Inventory, but analysis of the nature of natural gas emissions strongly suggests that leaks 

are important contributors to additional methane emissions that are not included in the 

inventory’s estimates; and 2) that LDAR program costs are very reasonable. 

In Section B, we provide specific comments, clarifications, and corrections for the leaks white 

paper. 

 

138 This figures, and figures below on abatement of leaks, include emissions listed as “Fugitives” in the

USGHGI, in addition to leaks from static components on compressors, which the USGHGI does not 

separate from venting of leaks through seals on compressor shafts and rods. Venting of leaks from seals on 

shafts and rods is discussed in the Compressors White Paper. 
45 

In Section C, we provide answers to some of the Charge Questions for Reviewers. 

A. Critical Synthetic Conclusions 

i. Methane Emissions from Oil and Gas are Underestimated by the 2014 

Inventory, and Available Evidence Implicates Leaks 

As discussed in part II.B above, a number of top-down studies have been published since 2000. A 

study by Brandt et al., published this past winter in Science reviewed over a dozen of these 

studies. Brandt et al. conclude that “measurements at all scales show that official inventories 

consistently underestimate actual [methane] emissions, with the [natural gas] and oil sectors as 

important contributors.”139 The inventories’ underestimate is substantial. Brandt et al. estimate 

that the 2013 Inventory140 underestimates methane emissions from all U.S. sources by 25 – 75%, 

and show that oil and natural gas systems must account for much of this underestimate. Brandt’s 

central estimate for the methane emissions not reported in the 2013 Inventory, 14 Tg per year,141

is almost twice as large as the 2014 Inventory figure for all methane emissions from both oil 

production and natural gas systems, 7.7 Tg/y. While it is certainly possible that other sectors aside 

from oil production and natural gas systems also emit more methane then the Inventory reports, it 

is certain (due to measurements in oil and gas producing regions, and isotopic and chemical 

analysis of the observed methane and other hydrocarbons present in the air) that oil and gas 

systems contribute significantly to these unaccounted-for methane emissions. For example, a 

study published since the Brandt et al. review was completed reported that 2012 methane 

emissions from oil and gas operations in Colorado’s Denver-Julesberg basin were almost three 

times higher than predicted by the 2014 Inventory.142

It is very likely that leaks account for a significant portion of the excess methane emissions from 

oil and gas facilities. As noted by Brandt et al., analysis of individual leak measurements from oil 

and gas facilities consistently shows skewed distributions with a very small numbers of sources 

having highly disproportionate emissions, thus accounting for a large percentage of total 

emissions. For example, the Clearstone II study referenced in the white paper found that 58% of 

the identified fugitive emissions from over 75,000 components at five gas plants was emitted by a 

total of just 50 leaks and compressor seals.143 It is very likely that studies such as the GRI/EPA

(1996) study have sample sizes too small to sufficiently represent the emissions from these high 

emitters.144 Furthermore, the Correlation Approach used by the GRI/EPA study will often be 

inaccurate for very high emitters because Method 21 screening instruments will be unable to 

measure the levels beyond a certain value (i.e., “peg,” a term used because the needle on an 

 

139 A.R. Brandt et al., (2014) “Methane Leaks from North American Natural Gas Systems,” Science, 343, 

733, available at http://www.novim.org/images/pdf/ScienceMethane.02.14.14.pdf. 

140 Brandt et al. used the 2013 Inventory, the latest version of the Inventory available in final form at the 

time their analysis was performed, as the basis of their comparison. The 2014 Inventory reduced EPA’s 

estimate of emissions from natural gas systems, so the underestimation of methane emissions documented

by Brandt et al. has actually become slightly more severe. 

141 See Brandt et al., (2014), at figure 2. 

142 G. Pétron et al., (2014) “A new look at methane and non-methane hydrocarbon emissions from oil and 

natural gas operations in the Colorado Denver-Julesburg Basin,” J. Geophys. Res. Atmos. 119, 

doi:10.1002/2013JD021272.

143 See Clearstone II study, Table 2. 

144 Brandt et al. (2014). 
46 

analog meter would hit a peg on the top of the scale). If that occurs, the default values for 

emissions correlating with pegged screening values will be inaccurate and thus the GRI/EPA 

study likely underestimates these emissions. 

B. Costs for LDAR Programs are Very Reasonable 

The leaks white paper does not adequately describe some of the recent analysis of the costs 

associated with abating emissions of methane and other air pollutants with LDAR programs. 

While the leaks white paper does describe the study by Carbon Limits, “Quantifying CostEffectiveness of Systematic Leak Detection and Repair Programs Using Infrared Cameras,”145

important aspects of the study design and results were not described. 

The Carbon Limits study was conducted using a database of detected leak sizes and repair costs 

from surveys conducted by two firms that provide LDAR survey services to the oil and gas 

sector. It is important to note that these surveys were predominantly repeat surveys. The facilities 

had been subject to rules (in Canada) requiring LDAR survey for some years. The rules allow use 

of OGI, and in general operators use OGI for surveys. As a result, the leak rates found during the 

survey were lower than would be found during surveys of most facilities in the U.S. where LDAR 

programs have either not been required under state or federal rules146 or implemented voluntarily. 

Accordingly, the volume of methane emissions abatement calculated from these surveys is less 

than it would be in an area without LDAR programs in place. As such, the costs per ton of 

pollution mitigation presented by the Carbon Limits report are overestimates of the true cost per 

ton of avoided pollution from LDAR programs more generally speaking. 

Nevertheless, the costs presented in the report are still very low. For less-frequent surveys, the 

value of conserved gas is larger than the cost of the surveys and repairs, so the abatement cost is 

negative (meaning the facility owner earns more money from increased sales than it spends). For 

more frequent surveys, which are appropriate for larger facilities and justified to prevent 

emissions, costs are positive but still very reasonable. 

 

Table 18: Emissions net abatement cost ($ / metric ton) of LDAR programs 

Facility Type 

Survey Frequency 

Annual Semiannual Quarterly Monthly 

 Cost of Leak Detection and Repair per tonne of VOC abatement 

Gas plant -256 -108 187 1,365 

Compressor station -287 45 708 3,357 

Well site & well battery -429 -148 412 2,647 

 Cost of Leak Detection and Repair per tonne of CO2e abatement 

Gas plant -6.3 -2.7 4.6 34 

 

145 The leaks white paper cites a pre-publication version of the Carbon Limits study that was posted online 

in late 2013. The Carbon Limits study has since been finalized and is available at 

http://www.carbonlimits.no/PDF/Carbon_Limits_LDAR.pdf 

146 With the exception of gas processing plants, where NSPS Subparts KKK and OOOO do require LDAR 

for facilities installed after 1984. 
47 

Compressor station -4.5 0.71 11 52 

Well site & well battery -5.9 -2.0 5.7 37 

The leaks white paper also omits several relevant analyses of the cost-effectiveness of LDAR 

programs that were entered into the record during deliberations over Colorado’s new regulations 

on emissions of methane and volatile organic compounds (VOC) from oil and natural gas 

facilities. The Colorado Department of Public Health and Environment (CDPHE) estimated that 

the rule, which requires LDAR at frequencies determined by the potential emissions from a 

facility, would have a cost for compressor stations of $474 per short ton of methane and ethane 

emissions abatement and $994 per short ton of VOC emissions abatement.147 Estimated costs for 

tiered LDAR at wellpads are $805 per short ton of methane and ethane emissions abatement and 

$1259 per short ton of VOC emissions abatement.148 CDPHE also provided data on the costs of 

inspections and repairs that are quite similar to the cost data reported by Carbon Limits.149

Additionally, CDPHE found that repair costs are less than the value of the gas that is conserved 

by the repairs, consistent with the results of the Carbon Limits study.150

 

Several oil and gas producers supported Colorado’s rule,151 submitting data based on their own 

experience performing LDAR surveys during the rulemaking process. These data demonstrate 

that firms are able to perform LDAR surveys for even lower costs than were reported in the 

Carbon Limits study. 

Facility Type 

Cost per Inspection 

Carbon Limits Anadarko Petroleum 

Corporation152

Noble Energy 

Incorporated153

Compressor Station $2,300 $1,250 – $5,150 

Multi well batteries $1,200 

Single well batteries $600 $450 - $800 $263 - $431 

Well site $400 

C. Charge Questions for Reviewers 

• Question 1. We have addressed this question above in Part VI.B with specific comments 

on the white paper. 

 

147 Cost-Benefit Analysis, Submitted Per § 24-4-103(2.5), C.R.S. Table 33 (hereafter “Colorado CostBenefit Analysis”). Available at: 

ftp://ft.dphe.state.co.us/apc/AQCC/COST%20BENEFIT%20ANALYSIS%20&%20EXHIBITS/CDPHE%

20Cost-Benefit%20Analysis_Final.pdf

148 Id, table 35. 

149 Id, pages 17-27. 

150 Id, pages 21-22. 

151 Finley, Bruce. “Colorado pitches new rules to cut oil and gas industry air pollution,” The Denver Post, 

11/18/2013. (available at: http://www.denverpost.com/environment/ci_24548337/proposed-colorado-airpollution-regs-clamp-down-oil). 

152ftp://ft.dphe.state.co.us/apc/aqcc/PRESENTATIONS/Noble%20Energy%20Inc%20&%20Anadarko%20

Petroleum%20Corporation/Anadarko.pdf 

153ftp://ft.dphe.state.co.us/apc/aqcc/PRESENTATIONS/Noble%20Energy%20Inc%20&%20Anadarko%20

Petroleum%20Corporation/Noble.pdf 
48 

• Question 2. As the white paper describes, emissions estimates for the GRI/EPA study, 

which is the basis for most of the emissions information in the inventories, were made 

using the Correlation Approach. Furthermore, the correlation equations used were 

derived from measurements carried out at facilities such as refineries, processing plants, 

and oil and gas production facilities. It is not clear that these correlation equations are 

appropriate for natural gas facilities that may operate at different temperatures and 

pressures, and that handle fluids of different properties (such as viscosity) than oil 

refineries. 

Modern leak quantification techniques, such as the Hi-Flow sampler used in the Carbon 

Limits study, Allen et al., and the Fort Worth AQ Study, offer a far more direct 

quantification of leak emissions and should be used to estimate emissions whenever 

possible. 

As noted in section one of these comments, it is disappointing that the leaks white paper 

fails to describe or acknowledge the large body of work that demonstrates that methane 

emissions from oil and gas facilities are substantially higher than estimated in the 2014 

Inventory and indicates that leaks compose a significant fraction of those additional 

emissions. 

• Question 3. The direct emissions quantification methods described in this paper, such as 

using a Hi-Flow sampler, can be used at oil and gas production facilities, as well as at gas 

gathering, processing, and transmission facilities. In addition, they can also be used at 

aboveground natural gas distribution facilities, such as city gates, metering and regulating 

stations. It is disappointing that EPA has, without explanation, not discussed the 

substantial leaks from those facilities in this white paper. Such emissions amount to 

420,000 tons of methane per year, according to the 2014 Inventory, not including leaks 

from underground pipelines or customer meters. 

As we have noted above, the indirect Correlation Approach may be less applicable at 

some facilities, particularly if correlation equations were derived with data from facilities 

handling different fluids under different conditions. Direct measurements are preferred. 

From conversations with representatives from industry, with LDAR service firms, and 

from public discussion during the process to develop and consider the recently passed oil 

and gas regulations in Colorado, it is very clear that the OGI method is the dominant 

methodology in use by industry today, and is used successfully at a wide range of 

facilities, as has been documented by GasSTAR. 

• Question 4. As concern has risen over the identified harm to air quality from emissions 

from oil and gas facilities, particularly in the western U.S., researchers have responded 

with a range of measurements and studies of emissions from this sector. As described 

above in Part VI.A, these studies have consistently indicated that emissions are higher 

than reported in the inventories, and therefore that the damage from these emissions to 

climate and air quality is more substantial than indicated by the inventories. 

Numerous studies that will improve our understanding of emissions of VOC and methane 

from oil and gas facilities are currently underway or planned. However, it is critical to 

note that the record establishes that even based solely on estimates from the 2014 

Inventory, substantial emissions from leaks can be mitigated at reasonable costs 
49 

using LDAR surveys. It is challenging to quantify precise emissions from this sector, but 

it is abundantly clear that they are excessively large and can be reduced affordably. EPA 

must not delay measures to reduce emissions on the basis of continued efforts to 

study emissions. 

We are aware of a number of studies underway or planned to quantify emissions. For 

example, studies are underway across the industry to quantify emissions from particular 

facility types or components/processes, such as the studies of wellpad emissions, 

processing plants and gathering facilities that are coordinated by Environmental Defense 

Fund. The University of Wyoming is currently deploying the OTM 33A methodology 

developed by EPA, described in section 2.9 of the white paper, to measure emissions 

from significant numbers of wellpads to understand the distribution of their emission 

rates. And, the University of Colorado and partners are planning extensive measurements 

in the Denver/Julesberg basin this summer. 

These studies will improve the understanding of emissions from oil and gas operations, 

but will not perfect it. Given the clear data indicating that leak emissions are substantial 

and can be controlled at a very reasonable cost, EPA must move forward now to address 

the excessive emissions from leaks. 

• Question 5. The predominant reason the emissions vary widely from facility to facility 

is the variability in the management approach of the facility operators. As discussed 

above in section one, super-emitters are a critical source of excess emissions. 

Consider this data presented in and calculated from the Clearstone II study of emissions 

from gas processing plants: 

Plant 

Component 

count for 

plant 

Fugitive 

Emissions 

(Mcf/day) 

Value of 

Leaking 

Gas* 

Leaks from 

top 10 leaks 

(Mcf/day) 

Fraction of 

leaks from 

top 10 leaks 

Leaks / 

plant 

throughput 

(%) 

Component 

leak 

frequency 

(%) 

1 22290 271 $757,000 78 29% 0.05

2 12330 23 $75,600 13 57% 0.01 0.74

3 18353 117 $613,000 53 45% 0.09

4 16687 69 $194,000 60 87% 0.15 1.34

5 4778 423 $1,297,000 317 75% 0.48 9.31

*Based on the price of gas at time of the surveys ($7.15/MCF). 

The very high emissions from Plant 5 illustrate that some facility operators choose not to 

properly address leaks at their facilities, despite the substantial value of product that they 

lose by neglecting to do so. Plant 5 did handle sour gas, which creates more corrosive 

conditions, but so did Plant 4, which had a leak rate less than one-third of Plant 5 and a 

leak frequency (fraction of components leaking) about seven times lower than Plant 5. 
50 

Other factors certainly contribute to the leak rate of these facilities. As operations get 

more complex (for example, handling oil and gas as opposed to simply dry gas), 

component counts increase and leaks may therefore increase. Nevertheless, the 

overriding factor is clearly the attention of operators to reduce leaks. 

• Question 6. This paper identified all technologies we know of in use operationally in the 

oil and gas sector to identify leaks. As noted above, OGI is currently the dominant 

method to identify leaks, and has been shown to be affordable and very effective. 

• Question 7. As mentioned above, OGI is currently the dominant method to identify 

leaks, and has been shown to be affordable and very effective. OGI identifies over 90% 

of the leaks that can be identified using Method 21 techniques such as the TVA, for 

example.154 CDPHE found that the costs of using OGI to survey a facility for leaks are 

roughly half of the costs of using Method 21,155 while Clearstone II found that OGI 

screening is about three times faster than Method 21, as noted in the leaks white paper. 

Finally, OGI has advantages in the screening of components that are challenging to 

access, and for screening surfaces, such as pipe runs and tanks, for corrosion leaks. 

• Question 8. As noted above, OGI is currently the dominant method to identify leaks, to 

our knowledge, across segments of the natural gas industry. One exception is in 

distribution, where the vehicle-based sensors discussed in section 3.1.4 are in use for 

monitoring and LDAR, but this is focused on detecting leaks from underground pipelines. 

We are not aware of routine use of other methods, with the exception of Method 21 

approaches where required (newer gas processing plants, principally). 

• Question 9. Industry is currently performing LDAR surveys in some geographic areas at 

frequencies ranging from annual to monthly. Annual surveys are performed at wells 

under Alberta regulations, and at new or modified well facilities in Pennsylvania and 

parts of Wyoming, for example. Some companies have instituted annual LDAR with OGI 

as a voluntary measure. To achieve greater emissions reductions, LDAR is performed as 

frequently as monthly by some firms in Wyoming.156 

Given the damage caused by air emissions from oil and gas facilities, annual LDAR will 

be too infrequent for many facilities. We support the tiered approach taken in the recent 

Colorado regulations, where the frequency of instrumental LDAR was based on the 

potential leak emissions from the site. However, the Colorado regulations allow smaller 

well production sites to only perform LDAR a single time. Any leaks that arise after the 

single LDAR survey will not be found under the regulation and may continue 

indefinitely. Given the large emissions possible from single super-emitters, and the very 

large number of small facilities, this exemption from regular LDAR for small facilities is 

not appropriate. 

 

154 Based on Clean Air Task Force and Environmental Defense Fund analysis of data from the Ft. Worth 

AQ Study. 

155 Colorado Cost-Benefit Analysis at 20. 

156 For example, Encana monitors 170 well production facilities in Wyoming’s Jonah field monthly with 

OGI. See 

ftp://ft.dphe.state.co.us/apc/aqcc/PRESENTATIONS/Encana%20Oil%20&%20Gas%20USA%20%28Enca

na%29/Encana%20REB%20Presentation.pdf. 
51 

• Question 10. Ambient / mobile monitoring is an exciting technology that may enable far 

more frequent monitoring of oil and gas facilities for leaks at reasonable cost. However, 

the methodologies for these technologies as research techniques in the field are still being 

worked out. Efficacy varies with weather (especially wind), site layout, and context. It is 

not clear how they could be deployed in some locations, such as very hilly or wooded 

areas, or sites near buildings. Furthermore, it is not at all clear how compliance with an 

LDAR survey requirement using ambient / mobile monitoring could be assured. There 

would be many ways to avoid identifying actual leaks using these methods. 

• Question 11. The Carbon Limits study was able to directly compare the costs of 

repairing leaks to the value of the gas conserved by doing so, using real data from 

thousands of surveys, finding that the net present value of repairing the leak is almost 

always positive. CDPHE made a similar finding using a different methodology and data. 

LDAR survey cost is low but the Carbon Limits study, and other data, suggest that when 

LDAR is performed at reasonable frequencies (quarterly or monthly), the total LDAR 

program does have positive, but reasonable, costs. 

• Question 12. The most critical goal of LDAR programs must be to reduce emissions 

from leaks, rather than quantifying them. We believe that it is not necessary under the 

NSPS program to require that the size of leaks be quantified (in concentration or 

volume), since it will often be faster and far simpler to simply fix them. Records should 

be kept of the existence of leaks, so that regulators can verify compliance and so that 

facility operators can identify equipment that is leaking repeatedly to address root causes. 

However, operators that repair leaks immediately or within a period of a few days should 

not be required to quantify leaks. 

Any leaks that are not repaired within a few days must be measured to ensure that 

damage from the ongoing leak is quantified, and so that regulators can consider those 

emissions when evaluating any request for an exemption from repair requirements due to 

claims of infeasibility, etc. 

• 13. We believe that LDAR technology will advance substantially in the future and are 

aware of public and private efforts to promote this development. This is exciting since 

new technology may enable far more frequent, and even continuous, monitoring of oil 

and gas facilities for leaks at reasonable cost. Regulations / Regulators should ensure that 

new technologies can be adopted to improve environmental performance once they are 

demonstrated. Even under very optimistic assumptions, use of these more advanced 

methods and technologies is several years away, and given the proven, low-cost 

performance of technologies such as OGI, EPA must not delay addressing leaks from oil 

and gas facilities in anticipation of some future technology. 

VI. Oil Wells 

A. Oil Wells Produce Gas, Which Can Be Managed by Capture or Combustion 

Oil wells produce oil, natural gas, and formation water. The amount of gas that is 

produced along with the oil is a function of the reservoir type and depth, 
52 

hydrocarbon type, well age, and the pressure and temperature changes that occur as 

the oil and gas reach the surface processing equipment. Gas oil ratios will increase 

over time as wells age. As is true of natural gas generally, gas produced in 

association with oil wells is primarily methane, but includes VOCs and some other 

chemicals as well. 

Oil reservoirs are classified according to fluid type (heavy oil, black oil, and volatile 

oil), with lighter oils having higher gas-oil ratios.157 Dry gas wells do not produce 

associated liquids at the surface (although very few wells produce truly dry gas). 

Table 19: Associated Gas Volumes per SPE Handbook 

Initial Dissolved Gas Oil Ratio (scf/bbl) 

Min Max 

Heavy Oil 0 200 

Black Oil 200 900 

Volatile Oil 900 3,500 

Retrograde Gas Condensate 3,500 30,000 

Wet Gas 30,000 100,000 

This gas is brought to the surface during all stages of production, including 

completion, recompletion, and operation of an oil well. For every stage, gas can be 

dealt with in one of three ways: it can be vented, combusted, or captured. Venting 

releases methane into the atmosphere, causing harmful pollution as well as creating 

potentially explosive vapor levels. To flare, gas is routed away from the well 

operations to a combustion device that burns the gas. Flaring destroys methane, 

VOC, and many other pollutants, and resolves the explosive vapor problem. Flaring 

also generates air, light, and noise pollution, and creates economic waste by 

combusting gas that could otherwise be collected and sold. Capture is therefore 

generally the most preferable option. Captured gas can be routed to a pipeline and 

marketed, used productively onsite, or re-injected into the formation. 

 

157 Lake, L., Petroleum Engineering Handbook, Society of Petroleum Engineers, 2007, Volume V(B), 

Table 9.1, V-897. 
53 

While flaring is preferable to venting, EPA should take all available steps to limit 

both. Many other regulators have led the way, adopting regulations to limit both 

venting and flaring of gas associated with oil production. For example: 

• Colorado Rule 912 prohibits unnecessary or excessive venting or flaring 

from a well. Flaring may be required if necessary to protect public health, 

safety and welfare.158

• Montana requires VOC vapors (including methane) greater than 500 British 

Thermal Units (BTUs) per cubic foot from wellhead equipment with the 

potential to emit 15 tons per year or greater, to be routed to a control device 

(such as a flare), or to a pipeline for sale.159

• Alaska requires operators to minimize amount of gas vented and flared to 

only that needed to handle an emergency, operational upset, or safety 

situation, and requires the amounts of vented and flared gas to be 

tracked.160 

• Internationally, the Global Gas Flaring Reduction Partnership found that 

“Many regulatory regimes (e.g., Alberta (Canada) and the United Kingdom) 

require each operator to make an economic evaluation of all the available 

associated gas utilization options, and to utilize the gas whenever gas 

utilization is shown to be economic. Only if all available options can be 

shown to be sufficiently uneconomic then the gas may be flared or, if 

unavoidable, vented. In Alberta (Canada), uneconomic means projects with 

Net Present Values less than minus 50,000 Canadian dollars.”161

These regulators have demonstrated that emission of associated gas can be 

controlled, but most states do not have analogous regulations. Other states, such as 

North Dakota, have not taken sufficient action to address venting and flaring, with 

extensive emissions as a result. As the materials discussed in the white papers show, 

existing regulations have not solved the problem. 

 

158 Colorado Oil and Gas Commission, Rule 912. 

159 Montana Administrative Rules § 17.8.1711. 

160 Alaska Oil and Gas Conservation Commission, Alaska Administrative Code 20 AAC § 25.235(d). 

161 Global Gas Flaring Reduction Partnership, Guidance on Upstream Flaring and Venting Policy and 

Regulation, March 2009. 
54 

B. Gas Emissions During Oil Well Completion 

As summarized in the whitepaper, recent studies indicate significant emissions from 

oil well completion. 

i. Oil Well Completion Emission Factor 

Table 20: Summary of Oil Well Completion Emissions (corrected) 

Study 

Average Uncontrolled Methane Emissions 

(short tons/completion) 

ERG/ECR (7 day flowback) 24 

ERG/ECR (3 day flowback) 7.7 

EDF/Stratus Analysis of HDPI (Eagle Ford) 27.2 

EDF/Stratus Analysis of HDPI (Wattenberg) 10.5 

EDF/Stratus Analysis of HDPI (Bakken) 19.8 

EDF/Stratus Analysis of HDPI (weighted 

average) 17.3 

EDF analysis of GHGRP data 24 

Allen 213.3 

Brandt et al. (Eagle Ford) 100.2 

Brandt et al. (Bakken) 34.4 

Brandt et al. (Permian) 34.3 

This table corrects the one included on page 44 of the oil whitepaper, which listed 

metric ton values for Brandt et al. but short tons for the other studies.162 We have 

 

162 We further note that in discussing Brandt et al. on page 19, the whitepaper uses the incorrect 

conversion factor of 1 metric ton = 1.02311 short tons. The correct ratio is 1:1.102311. The short ton
55 

also included the weighted average from the EDF/Stratus analysis and the estimate 

from the EDF analysis of GHG reporting program data.

163 

The values given by these studies are conservative in many regards. 

The ERG/ECR authors identify three oddities in their data set, “The net effect of 

[which] is that the average daily gas production values may be skewed low.”164 An 

additional factor not identified by the authors is that the study uses a narrow 

definition of “oil wells,” including only wells with a gas to oil ratio of less than 

12,500 scf/barrel.165 In general, wells with higher gas to oil ratios will have higher 

completion emissions. This is particularly pertinent here, because there may be 

many wells that are not “oil wells” for purposes of the ERG/ECR study but that also 

are not “gas wells” within the scope of the 2012 NSPS. The 2012 NSPS only regulates 

emissions from completion of “gas wells.” Gas wells are defined as “onshore well[s] 

drilled principally for production of natural gas.”166 While we contend that the 

definition of a gas well should be interpreted broadly, we note that Texas, Alaska, 

and New Mexico (for example) use a gas to oil ratio of 100,000 scf/bbl as the 

dividing line between gas and oil wells.167,168,169 Thus, there are many wells that are 

likely to have high completion emissions, that are excluded from the ERG/ECR 

study, but that might not be regulated under the 2012 NSPS. 

Similarly, the summary data provided for Allen et al. is only for three of the four 

surveyed wells with a gas to oil ratio under 12,500 scf/barrel. 

The EDF/GHGRP is conservative insofar as it is derived from GHGRP data; the 

GHGRP and Allen et al. studies are conservative for the reasons stated on in part V.A 

above. 

Finally, we consider EDF/Stratus and Brandt et al. to be conservative in their 

assumption that during completion, oil and gas production gradually increases until, 

 

values in Table 3-7 are derived using this improper value. This appears to be a typographic error, 

however, as the whitepaper appears to have used the correct ratio elsewhere. 

163 Summarized in the EDF/Stratus analysis. EDF, Comments on “Draft Inventory of U.S. Greenhouse 

Gas Emissions and Sinks: 1990–2012,” available at 

http://blogs.edf.org/energyexchange/files/2014/03/EDF-Comments-Draft-2014-GHGInventory_031014.pdf. 

164 A-5. 

165 A-3. 

166 NSPS Subpart OOOO, § 60.5430. 

167 Oil and Gas Division, Texas Administrative Code, Title 16, Chapter 3, Rule § 3.79. 

168 Alaska Oil and Gas Conservation Commission, Definitions, Alaska Admin. Code Title. 20, § 25.990 

defines and oil well as well that produces predominantly oil at a gas-oil ratio of 100,000 scf/bbl or 

lower, unless on a pool-by-pool basis the commission establishes another ratio. 

169 Oil and Gas, New Mexico Administrative Code Title 19, Chapter 15, January 2013. Regulations 

define an oil well as “a well capable of producing oil and that is not a gas well as defined in Paragraph 

(6) of Subsection G of 19.15.2.7 NMAC. A gas well is defined as a well with a GOR of 100,000 scf/bbl. 
56 

on the final day of completion, production hits the well’s initial production rate. 

Brandt et al. assume a linear increase in production over 9 days of completion; 

EDF/Stratus assume non-linear ramp up of 7-10 days, equal to 3 days of production. 

Wells typically hit their highest levels of production during completion and 

production then declines; thus, assuming that production peaks only on the last day 

of completion is conservative. 

We also note that these values are consistent with what would be expected based 

gas oil ratios and production. For example, Allen et al. observed production of an 

average of 1,713 barrels per completion from the four < 12,500 scf/barrel wells in 

the study.170 At 1,713 barrels per completion, even for a well with a gas oil ratio in 

the for black oil range (550 scf/barrel), and using the 2011 TSD’s estimate that the 

gas produced from oil wells is 46.7% methane, one would still expect to 9.2 tons of 

methane to be produced. 

Recompletion emissions will likely vary according to many factors including 

reservoir drive mechanism, gas production and decline rate, method of 

recompletion, and others. Very little data exists on recompletion emissions. Notably, 

the gas-oil ratio increases as oil wells age and evolving stimulation methods can 

result in recompletions that significantly boost production. We therefore support 

the use of completion emission factors as an estimate of recompletion emissions. 

In light of these studies, it is clear that the oil well completion and recompletion 

emission factors used in the OOOO TSD and the GHGI are too low. The OOOO TSD 

estimated only 0.0074 and 0.0011 tons of methane per oil well completion and 

recompletion, respectively.171 The OOOO TSD estimate was therefore more than one 

thousand times lower than the lowest estimate summarized in the whitepapers. The 

2014 GHGI emission factor for completions, 0.0141 tons of methane per event, is 

also clearly not applicable to hydraulically fractured wells. 

ii. Oil Well Completion Activity Factor 

ERG estimates 5,754 uncontrolled oil well completions in 2011.172 EDF estimates 

hydraulic fracturing completions of 15,753 oil wells in 2012, with 43% of those, 

6,773, being uncontrolled.173 The 2011 OOOO TSD estimated hydraulic fracturing of 

12,193 new oil wells.174 

 

170 Whitepaper Table 3-6. 

171 2011, NSPS Subpart OOOO, TSD, at Table 4-6, Page 4-21 (estimating that a flare with 95% control 

efficiency could achieve emission reductions of 0.007 and 0.001 tons per event). 

172 Note that the whitepaper misquotes the ERG activity factor on page 13, indicating 5274 

uncontrolled completions. The correct figure is used elsewhere, and all calculations appear to reflect

the correct value. 

173 http://blogs.edf.org/energyexchange/files/2014/03/EDF-Co-producing-Wells-Whitepaper.pdf at 

8. 

174 2011, NSPS Subpart OOOO, TSD, at Table 4-4, Page 4-13. 
57 

It is therefore plain that uncontrolled oil well completion emissions represent a 

significant source of methane. ERG estimates 44,306 to 138,096 tons of emissions. 

Brandt et al. estimate 122,733 tons from oil well completion in just three basins. 

EDF’s analysis of GHGRP data estimates 162,570 tons of methane from uncontrolled 

oil well completions in 2012.175 Finally, EDF/Stratus estimates 272,270 tons of 

uncontrolled oil well completion emissions in 2012.

Although data on recompletions is less available, even under the whitepaper’s 

estimate of 0.5% of all oil wells being refractured every year, refracturing 

represents a significant source of additional emissions. 

iii. Oil Well Completion Control Technologies 

Completion emissions can be easily abated. As recognized by the whitepapers, there 

are two primary control technologies: reduced emission completions and flares. 

Both can achieve 95% control efficiencies.176 Thus, even under the conservative 

assumptions above, the abatement potential for oil well completions is well over 

100,000 tons of methane per year. 

This abatement can be achieved at reasonable costs. Reduced emission completions 

are the more expensive, but still reasonable, option. The 2011 TSD estimated that a 

reduced emission completion cost $29,713 and achieved a 95% control efficiency.177

The minimum, median, and maximum estimates of per-completion emissions we 

provide above are 7.7, 24, and 213.3 tons of methane. These respectively entail 

control costs of $4,061, $1,303, and $146 per ton of methane, without considering 

offsetting revenue from captured gas. If captured gas is sold at $4/Mcf, then costs 

fall to $2,581/ton in the 7.7 ton case, and reduced emission completions turn an 

immediate profit in the other cases. 

Of course, a more sophisticated analysis would recognize that both cost of reduced 

emission completion equipment and the tonnage of methane at issue correlate with 

completion time. As summarized by the whitepaper, the cost of a reduced emission 

completion depends on whether the needed equipment is already on-site and the 

length of time the equipment is needed for. Here, we use the per-day costs of a 

reduced emission completion from the whitepaper. As noted above, the estimates of 

emission volumes are already conservative. An additional reason why the high perday cases are conservative is that it is unlikely that the per-day cost will increase 

 

175 Summarized in http://blogs.edf.org/energyexchange/files/2014/03/EDF-Co-producing-WellsWhitepaper.pdf at 8 

176 Allen et al. observed higher efficiencies for reduced emission completions--97.8% to 98.8%. 

Whitepaper at 18. 

177 EPA, Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas 

Production, Transmission, and Distribution, Background Technical Support Document for Proposed 

Standards (April 2012), Pp. 5-2,3. Available at 

http://www.epa.gov/airquality/oilandgas/pdfs/20120418tsd.pdf.
58 

linearly for longer completion periods. That is, the longer that wells in a formation 

take to complete, the greater the likelihood that reduced emission completion 

equipment will be available nearby, and the greater potential economy of scale. 

Study Tim

e 

Avg. 

CH4 

REC cost 

(low) 

$ per 

ton 

REC cost 

(high) 

$ per 

ton 

ERG/ECR 7 24 5,642 235.08 52,402 2,183.4

2 

ERG/ECR 3 7.7 2,418 314.03 22,458 2,916.6

2 

EDF/Stratus Analysis of 

HDPI (Eagle Ford)178 8.5 19.8 6,851 346.01 63,631 3,213.69 

EDF/Stratus Analysis of 

HDPI (Wattenberg) 8.5 27.2 6,851 251.88 63,631 2,339.38 

EDF/Stratus Analysis of 

HDPI (Bakken) 8.5 10.5 6,851 652.48 63,631 6,060.1 

EDF/Stratus Analysis of 

HDPI (weighted average) 8.5 17.3 6,851 396.01 63,631 3,678.09 

Allen179 3 213.3 2,418 11.34 22,458 105.29 

Brandt et al. (Eagle Ford) 9 100.2 7,254 72.4 67,374 672.4 

Brandt et al. (Bakken) 9 34.4 7,254 210.87 67,374 1958.55

Brandt et al. (Permian) 9 34.3 7,254 211.49 67,374 1964.26

Finally, for one more interpretation of the data, we note that EDF/Stratus found that 

costs of emission reduction using reduced emission completions remain reasonable 

even for median, rather than average, wells.180 

The other control option is flaring. In the technical support document for the 2012 

NSPS, EPA estimated this cost, for oil well completions, at $3,523 per well. 181 Like 

 

178 EDF/Stratus state that they assumed 7 to 10 days of completion; we use 8.5 as the average. 

179 Average of four oil wells studied. Whitepaper at 18 

180 
59 

reduced emission completion, combustion is generally at least 95% effective. For 

the range of emission estimates provided above, combustion provides control costs 

of $482 to $17 per ton. 

iv. Gas Emissions During Oil Well Production 

GHGRP data shows that emissions of methane from venting of associated gas were 

90,000 tons in 2011 and 175,000 tons in 2012.182 Most of this venting is 

“casinghead gas venting” from older oil wells. These reported emissions, which are 

a lower limit of national emissions since smaller producers do not report emissions 

to the GHGRP, are considerably larger than the “stripper well” emissions in the 

USGHGI (14,200 tons of methane in 2011). It is not known why the reported 

emissions vary so significantly between 2011 and 2012. We agree it may be possible 

to provide additional estimates of associated gas emissions using gas to oil ratios or 

other reporting.183 Refining these estimates need not precede regulation of these 

emissions, however. 

v. Alternatives to Flaring 

For both completion and production emissions, the preferred alternative control for 

associated gas is capture. Typically, gas that is captured during oil well completions 

and production is transported to processing plants in gathering pipelines. When 

wells are isolated or other issues limit the capacity of gathering systems, other 

technologies can make it feasible to utilize associated gas locally or get it to market 

for beneficial use. 

The Oil White Paper references several technologies that can be used as alternatives 

to flaring: natural gas liquid recovery, natural gas reinjection, and electricity 

generation for on-site use. Natural gas reinjection may be viable, although additional 

research and testing may be needed to scale up this option for unconventional 

reservoirs. 

The White Paper also excluded two important technologies that can be used at well 

pads to reduce flaring: 

• Compressed natural gas (CNG) trucking – compressing associated gas at wellsites 

and trucking to consumers, processors, gathering systems, etc. 

• Electric power generation for sale to grid. 

 

181 2011, NSPS Subpart OOOO, TSD, at Table 4-6, Page 4-21. 

182 Some portion of this is due to methane emissions from flares of associated gas (due to incomplete 

combustion). 

183 See Whitepaper at 20-21. 
60 

Natural gas liquid recovery, compressed natural gas (CNG) trucking, electricity 

generation for on-site use, and electric power generation for sale to grid are all 

mature technologies, having been deployed commercially more than once in tight oil 

developments. These technologies can also be scaled up or down depending on the 

size of the development. Finally, many of the technologies are portable: they can be 

moved from well to well. For example, a technology can be deployed at a well in the 

first few months, when gas production is very high, and dismantled or scaled down 

once a pipeline is in place and can handle the full volume of production from the 

well. These solutions represent practices that are feasible today at costs that are not 

prohibitive. 

Even if capture for on-site use or in gathering pipelines is infeasible or EPA 

otherwise chooses not to require it, flaring remains a much better alternative than 

venting from a pollution perspective. A Federal Implementation Plan (FIP) for the 

Fort Berthold Indian Reservation (FBIR) reports that flaring requirements for 

associated gas during production have an abatement cost for VOC of $10-$17 per 

ton.184 Using the OOOO ratio of methane to VOC for oil well completions and 

recompletions,185 methane abatement costs would be $9 - $16 per ton. 

However, we note that flaring is still an inherently wasteful process which produces 

large amounts of carbon dioxide, nitrogen oxides, particulate matter including black 

carbon, and other pollutants. Flares' flames can be extinguished by weather or 

interruptions in flow, and even if auto-igniters are required (they are not in many 

jurisdictions) the emissions from flares that go out for periods of time during 

operations should be considered. 

Alternatives to flaring, such as gathering systems and the alternative approaches 

identified in the white paper and above, must be considered for any well before 

routine flaring is considered. Further, flaring, which produces voluminous pollution, 

should not be allowed simply because an alternative to flaring has a net cost for a 

well operator. EPA must consider these alternatives to flaring as systems of 

pollution control, and compare the net cost of installing these alternatives as a 

means of abating the pollution that the flare would produce. 

Respectfully submitted, 

Joanne Spalding 

Nathan Matthews 

Andres Restrepo 

Sierra Club 

 

184 TSD for FBIR FIP, table 4. Available at http://www.regulations.gov/#!documentDetail;D=EPAR08-OAR-2012-0479-0004. 

185 From OOOO RIA (2011), table 3-3. 
61 

85 Second St., 2nd Fl. 

San Francisco, CA 94105 

joanne.spalding@sierraclub.org

 

David McCabe 

Darin Schroeder 

Lesley Fleischman 

Clean Air Task Force 

18 Tremont St, Ste. 530 

Boston, MA 02108 

dmccabe@catf.us

 

Meleah Geertsma 

Briana Mordick 

Vignesh Gowrishankar 

Natural Resources Defense Council 

20 N. Wacker Drive, Suite 1600 

Chicago, IL 60606 

mgeertsma@nrdc.org

Bruce Baziel 

Earthworks 

P.O. Box 1102 

Durango, CO 81302 

bruce@earthworksaction.org