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 Res ources 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 Pa pers Drastically Understate
Oil and Gas Methane Emissions .....................

................................................... ............. 5

C. If Oil and Gas Production Continues to Increase, th e Need for Action to Address
Methane Emissions Will Likewise Increase ..........

................................................... ...... 7

D. The Clean Air Act’s Section 111 Performance Standar ds 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 NSP S .................................. 10

C. Control Measures for Compressors Not Covered Under the 2012 NSPS: Anticipated Emission Reductions Based On Data Avail able to EPA In 2012 ............. 12

i. Methane Abatement Opportunities for Existing Recipr ocating Compressors ... 14

ii. Methane Abatement Opportunity for Existing Centrifu gal Compressors. ......... 17

iii. Methane Abatement Opportunity for New Compressors T hat 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 Inven tory 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 Substantia l, and Underestimated in
Available Data ....................................

................................................... ....................... 25

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

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

27

C. The Methane Abatement Potential from Controlling Em issions at High- and
Intermittent-Bleed PCs is Substantial .............

................................................... ........... 27

D. Control Costs to Convert Existing High-Bleed Pneuma tic Controllers to LowBleed Devices .....................................

................................................... ....................... 31

E. Device Classification Issue in the 2013 Prasino Gro up 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 Unloadi ng 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 Underestimat ed 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 Capt ure 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 ...........................

................................................... ......... 591 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 whi te papers regarding methane and VOC emissions in the oil and natural gas sector, releas ed April 15, 2014. We submit these comments on behalf of the Sierra Club, Natural Resources Def ense Council, Clean Air Task Force, and Earthworks (“Commenters”).

I. Introduction

EPA’s five white papers demonstrate that the oil an d 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, in cluding both existing and new or modified sources. Only through such an approach can EPA maxi mize the available reductions in methane
emissions from this sector and meet the Obama Admin istration’s climate goals.

Avoiding many of the impacts brought on by climate change will require dramatic reductions in greenhouse gas emissions, including methane. The In tergovernmental Panel on Climate Change (“IPCC”) recently affirmed that to avoid catastroph ic 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 annou nced in Copenhagen in 2009 and2

committed to in Cancun in 2010. 1 The most optimistic projections from EPA and the E nergy Information Administration (“EIA”) of the current t rajectory of U.S. greenhouse gas emissions in 2020 exceed the Administration’s target level by ov er 800 MMT CO 2 e 2 . Garnering all achievable methane reductions from the oil and gas sector is t herefore 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 f rom existing pollution levels that voluntary
measures will be insufficient.

Methane, an extremely potent climate change polluta nt, 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 (CO 2 e). 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 se ctor produces approximately 161.6 MMT of

CO 2 -equivalent in methane each year through venting an d 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 t he 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 acti on will have co-benefits outside of those related to climate change, as methane also causes harms dis tinct from those directly related to climate change—for example, methane increases smog-forming ozone, which negatively impacts human respiratory and cardiovascular health and damages c rops and vegetation. Additionally, methane is

1 See, e.g. , IPCC, Fifth Assessment Report, Working Group 3: Summary f or Policymakers (2014)
at 13 available at http://report.mitigation2014.org/spm/ipcc_wg3_ar5_s ummary-forpolicymakers_approved.pdf ; see also United States Department of State, Letter to Execut ive 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 imple mented by Parties included in Annex I to the Convention (June 7, 2011), available at http://unfccc.int/resource/docs/2011/sb/eng/inf01r0 1.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 ou t 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 Sink s: 1990-2012 (Apr. 2014) (“2014 Inventory”), Table ES-2 (estimating 567.3 Tg CO 2 e from CH 4 ), 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, ind icating 27 Tg (or million metric tons) of methane. In this comment, w e 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/ghgemiss ions/USGHG-Inventory-2014-Chapter-2-Trends.pdf

. 5 Id.3

emitted along with other smog- and particulate-form ing co-pollutants as well as hazardous
substances. Measures to reduce methane emissions fr om 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 gr eenhouse 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 publi c health and welfare. See 74 Fed. Reg. 66,496 (Dec. 15, 2009). The Supreme Court further c onfirmed 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 particul ar “categories of sources” that, in the Agency’s judgment, “caus[e], or contribut[e] significantly t o, 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 polluta nts emanating from sources in a listed
category. Id. This duty entails performance standards for both ne w sources under 111(b) and existing sources under 111(d). S ee 42 U.S.C. § 7411(b) and (d). 6

Although the Court in AEP v. Connecticut focused specifically on section 111 regarding CO 2 emissions from power plants, the logic of that hold ing extends to all industrial sources of GHG pollution, and the oil and gas sector is, like powe r plants, a listed source category that is already regulated under section 111. EPA acknowledged in th e 2012 rulemaking that the oil and gas sector emits significant levels of methane; as we d iscuss 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 Sec tions 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 revie w 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 stu dies summarized therein overwhelmingly affirm this conclusion. Specifically, these papers demonst rate that:

• Numerous sources of methane emissions in the oil an d 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 re duce these methane emissions; and

• Costs for these control technologies are reasonable

.

Accordingly, EPA can and must take action now to co ntrol methane emissions from oil and gas industry sources directly. As the IPCC has repeated ly admonished, acting now will be more effective and cheaper than acting later. 7

6 Under section 111(b), EPA issues direct regulation s of the new sources in the regulated category. Under 111(d), the agency provides mandato ry 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 e missions from the oil and gas sector in no way justifies EPA’s delay in regulating these emiss ions. As we discuss below, the studies cited in the white papers may differ in their exact estimate s of emissions from particular components, and studies using atmospheric measurements of methane ( which were generally not discussed in the white papers) provide significantly higher estimate s of total methane emissions from natural gas systems. Nevertheless, while there may be uncertain ty 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 signifi cant enough to warrant regulation under
section 111 and whether there are available technol ogies 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 m ost 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 muc h 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 GW P for methane, including fossil methane, of
21. This value has been out of date since 2001 9 and does not reflect the research that has been conducted in the intervening time. In addition, met hane 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 cos t of methane has not yet been developed, a peer-reviewed analysis by EPA economists recently e stimated 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 b y 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 particula r, since this paper’s publication, estimates of two inputs to this study—methane’s global warming poten tial and the social cost of carbon—have been revised dramatically upward. This study used I PCC’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-CO 2 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 increase d 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 comprehensi ve analysis of this issue conducted thus far, Sierra Club, NRDC, and other environmental organiza tions have commented elsewhere that even these SCC figures significantly underestimate the t rue 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 Pa pers 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 a verage 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 acc umulation 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 comp osition of atmospheric methane.

In the last two years, peer-reviewed publications u tilizing top-down techniques to estimate methane emissions from oil and gas, have proliferat ed, and these studies provide compelling evidence that the aggregate methane emission estima tes 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 na tural 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 Regulat ory Impact Analysis Under Executive
Order 12866

(Feb. 2010)), available at http://www.whitehouse.gov/sites/default/files/omb/i nforeg/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 12 866 (Nov. 2013) at 3, available at http://www.whitehouse.gov/sites/default/files/omb/a ssets/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 subseque nt years.

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

14 See Sierra Club, Comments on the Interagency Working Group’s (IWG) T echnical Support Document: Social Cost of Carbon (SCC) for Regulator y Impact Analysis Under Executive Order
12866 (Docket Not. OMB-2013-0007-0083) (Feb. 25, 2014), available at http://www.regulations.gov/#!documentDetail;D=OMB-2 013-0007-0083 ; EDF, NRDC, et al.

, Comments on the Interagency Working Group’s (IWG) T echnical Support Document: Social Cost of Carbon (SCC) for Regulatory Impact Analysis Unde r Executive Order 12866 (Docket No. OMB-2013-0007-0140) (Feb. 26, 2014), available at http://www.regulations.gov/#!documentDetail;D=OMB-2 013-0007-0140

.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 acr oss 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 emission s from all sources were 50% higher than the 2013 Inventory’s bottom-up estimate of emission s. They show that oil and gas emissions are a significant portion of the observed emissions not a ccounted for in EPA’s Inventory, and suggest that the actual leak rate is likely to be 3% or mor e. 16 The second, published by Adam Brandt, et al ., similarly concluded that EPA’s Inventory and oth er bottom-up estimates significantly underestimate methane emissions from oil and gas pr oduction. 17

These nationwide studies stand in agreement with at mospheric studies examining individual regions, which have found even higher methane emiss ions in the regions studied. Two studies of Colorado’s Denver-Julesberg Basin have concluded th at 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 met hane leak rates in Utah’s Uinta Basin, estimating escaped met hane at 9 ± 3% of total production. 19

What these top-down studies uniformly indicate is t hat 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’ c ited literature alone.

15 See, e.g. , Miller, S., et al.

, Anthropogenic emissions of methane in the United St ates

, Proceedings of the National Academy of Sciences (De c. 10, 2013) (“PNAS Study”), at 20,022,
available at http://calgem.lbl.gov/Miller-2013-PNAS-US-CH4-Emiss ions-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 acr oss 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%.

17 Brandt, A.R., et al.

, Methane Leaks from North American Natural Gas Syste ms , Science, Vol. 343, no. 6172 at pp. 733-735 (Feb. 14, 2014), available at http://www.novim.org/images/pdf/ScienceMethane.02.1 4.14.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/10.1002/2013JD02 1272/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 vente d in the studied and concluded more generally that “the methane source from natural gas systems i n Colorado is most likely underestimated by at least a factor of two.” Petron, et al.

, Hydrocarbon emissions characterization in the Color ado Front Range: A pilot study , 117:D4 J. Geophys. Res. Atmospheres 4304 (Feb. 21, 2012), abstract
available at http://onlinelibrary.wiley.com/doi/10.1029/2011JD01 6360/abstract

. 19 Karion, et al.

, Methane emissions estimate from airborne measuremen ts 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.5081 1/abstract

. See also J. Tollefson, Methane leaks erode green credentials of natural ga s , Nature (Jan. 2, 2013), available at http://www.nature.com/news/methane-leaks-erode-gree n-credentials-of-natural-gas-1.12123

.7

C. If Oil and Gas Production Continues to Increase, th e 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 drill ing, have opened unconventional sources of hydrocarbons to development, such as shale gas, tig ht 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 Annu al 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 o n other options, including renewable energy (wind and solar), energy efficiency and others; how ever, 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 Standar ds Program

As mentioned above, section 111 of the Clean Air Ac t requires EPA to set technology-based “standards of performance” for listed “categories o f sources” of air pollution. 42 U.S.C. § 7411. Such standards of performance must

reflect[] the degree of emission limitation achieva ble through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any nonair quality hea lth and environmental impact and energy requirements) the Administrator determin es 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 standa rds for a particular source category are established, EPA “shall, at least every 8 years, re view 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 ca tegory; and 2) the availability of demonstrated

control measures. See, e.g. , 50 Fed. Reg. 36,959, 36,961 (Sept. 10, 1985) (mak ing negative
determination based on lack of demonstrated control technology); 75 Fed. Reg. 54,994–95 (Sept. 9, 2010) (making positive determination based on si gnificant emissions and existence of demonstrated control technology). S ee also Nat’l Lime Ass’n v. EPA , 627 F.2d at 426 n. 27 (discussing these factors). As such, EPA must regul arly (but no less often than every 8 years) review source categories to ensure that the existin g performance standards reflect the current and most innovative state of that industry’s technologi cal capabilities to reduce emissions from all pollutants.

i. Summary of EPA’s 2012 NSPS

Despite this charge, EPA stopped short when it fina lized revisions to the oil and gas sector’s NSPS in 2012. 40 C.F.R. §§ 60.5360-60.5430; s ee 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.xl sx

.8

was achievable considering the sector as a whole, c hoosing 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 metha ne emission sources that exist throughout the oil and gas sector. This approach resulted in two s ignificant omissions.

First, EPA’s 2012 NSPS omits sources in the transmi ssion and storage segment, where VOC emissions are low relative to methane because impur ities 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 unde r 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 req uired to set emission guidelines for VOCs under section 111(d), the 2012 NSPS omit all existi ng 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 thi s 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 instanc e, in Essex Chem. Corp. , 486 F.2d 427, 433 (D.C. Cir. 1973) (holding that section 111 standard s must be “reasonably reliable, reasonably efficient, and . . . reasonably . . . expected to s erve the interests of pollution control without becoming exorbitantly costly in an economic or envi ronmental 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 “grea ter 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 B SER] will be sustained unless the environmental or economic costs of using the techno logy 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 adoptin g methane controls such as those discussed in these comments. However, a variety of market condit ions disincentive or inhibit companies from maximizing the available opportunities to reduce me thane. These conditions include diverse ownership of the different parts of the system, own ership transfer of the gas moving through the system, higher rates of return from other investmen ts, lack of knowledge of best practices, lack of incentive by independent contractors, or a simple l ack of interest. Collectively, these factors result in a market failure with respect to methane, and re gulations must be established to prevent the resulting wasteful and harmful pollution. Ultimatel y, such actions will not only provide climate and other environmental and health benefits, but th ey 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 emi tters 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 separat ing 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 l eaks associated with their moving parts— shaft seals or rod packing systems, as described be low—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 m ore accurately considered fugitive emissions, which we address in our comments on the white paper concerning leaks.

Reciprocating compressors function by positive disp lacement, using a driveshaft and piston that move back and forth linearly to reduce the volume o f a quantity of gas and increase its pressure. To minimize gas leakage around the driveshaft, reci procating compressors include rod packing systems, which consist of a series of flexible ring s encased in metal cups to form a seal around the shaft. As rod packing systems age, component we ar reduces the effectiveness of the seal and more gas leaks into the atmosphere.

Centrifugal compressors are less common in the indu stry than reciprocating compressors, but are associated with higher emissions of methane and oth er 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 centrif ugal compressor is equipped with either wet seals or dry seals. Wet seals utilize circulating s treams of oil to lubricate the seal rings that abso rb high pressure gas, which is typically vented into t he atmosphere through a seal-degassing process. Dry seals, by contrast, consist of aerodynamic groo ves 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 operatin g and maintenance costs.

The 2012 NSPS included operational requirements for compressors of both types that are constructed or modified after August 23, 2011 and t hat are located between the wellpad and the point at which the natural gas enters the transmiss ion and storage segment. For centrifugal compressors equipped with wet seals, the rule requi res operators to achieve a 95% reduction in VOC emissions from seal leaks by installing a gas r ecovery system for the seal oil degassing

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

21 In its proposed rule, the agency considered requir ing 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 a s 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 cen trifugal compressors equipped with wet seals10

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 f rom reduced methane emissions, it did not directly target methane, nor did it cover any exist ing 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, t here remain substantial opportunities to reduce methane emissions from centrifugal and reciprocatin g compressors at a reasonable or even negative cost. In this analysis, we recommend a ser ies of measures that would significantly reduce seal leaks from oil and gas sector compresso rs. 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 centrifu gal compressors in the transmission and storage segment. Second, EPA must require operators to repl ace 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 wellh eads to gas distribution systems. Finally, EPA must require all existing wet seal centrifugal comp ressors in the oil and gas sector to be retrofitted either with dry seals or gas capture systems that d irect 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 dat a remains pertinent with regard to abatement opportunities for compressors, particularly for exi sting 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 a dvocate are similar regardless of whether one uses 2014 or 2011 Inventory data; in both cases, th ese 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 o pportunities available at existing reciprocal and existing compressors based on data from EPA’s 2 011 Inventory. Next, we examine the emission reductions that could be achieved by regul ating new compressors not covered under the 2012 NSPS, again using data available to EPA in 201 2. We then consider these total emission reduction figures in light of EPA’s most recent dat a from the 2014 Inventory. Finally, we respond to the charge questions included in EPA’s compresso r white paper.

B. Anticipated Emission Reductions from EPA’s 2012 NSP S

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 ac hieve equal or greater reductions by capturing the gas from seal oil degassing process and directing i t into compressor suction (or similarly utilize the gas through another mechanism).

22 EPA, Oil and Natural Gas Sector: Standards of Performanc e for Crude Oil and Natural Gas Production, Transmission, and Distribution: Backgro und Technical Support Document for Proposed Standards (July 2011) (hereafter, “TSD”) at 6-15 (Table 6-6) (showing data for11

centrifugal compressors with wet seals “located bet ween the wellhead and the point of custody transfer to the natural gas transmission and storag e segment.” 79 Fed. Reg. at 49,543 (40 C.F.R. § 60.5365(b)-(c)). Hence, the rule covers new recipro cating compressors in the gas production (gathering and boosting activities only; wellpad un its are not covered) and processing segments and new centrifugal compressors in the processing s egment (no new centrifugal compressors are anticipated for gathering and boosting). In additio n 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 in stalling 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 compresso rs, the agency calculated emission

reciprocating compressors); EPA, Oil and Natural Gas Sector: Standards of Performanc e for Crude Oil and Natural Gas Production, Transmission, and Distribution: Background Supplemental Technical Support Document for the Fin al New Source Performance Standards (April 2012) (hereafter, “Supplemental TSD”) at 6-2 (Table 6-3) (showing data for centrifugal compressors).

23 Id.

24 S ee Table 2, supra

. See also TSD at 6-15 (Table 6-6). Note that Table 6-6 erron eously lists 375 as the number of new reciprocating compressors annu ally in the processing segment. Elsewhere, the TSD makes clear that this figure is actually an ticipated 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 419 5,329

1,482

56

New Gas Processing Centrifugal Compressors 216.15 19.51

0.70

13

2,810

254

9

Subtotal 8,139 1,736

65 

### Commpressor Emissions Abatement Estimations from 2 012 NSPS

Equipment Type Emissions abated per compressor (tons/year) in 2012 Number of

New

Devices/Yr Total emissions abated

(tons/year) in 201212

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 r educe methane emissions from compressor seal leaks by approximately 8,139 tpy. This abatement fi gure 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 F ed. Reg. at 49,493. The final rule also exempts new reciprocating compressors on wellpads a nd 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 coul d 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 centrif ugal compressors with dry seals or gas capture systems, as well as routine replacement of rod pack ing 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 C ompressors Using Data Available to EPA During 2012 NSPS Rulemaking

Additionally, the 2012 NSPS did not apply to new re ciprocating 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 2 2,576 tpy. While this number is lower than the reduction opportunities from existing compresso rs, 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 re duction. 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/comp ressor) = $160/ton.

28 EPA estimated that no new centrifugal compressors were estimated at wellheads or for gathering and boosting activities in the coming yea r. See TSD at 6-7 (Table 6-4). Hence, we do
not consider emission reduction estimates from thos e 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 525,218

72,384

2,661 Equipment Type Emissions abated (tpy) 

### Emission Abatement Potential - Existing Compressor s13

would continue to compound each year as new equipme nt is installed, and the 22,576 tpy would compound to a substantial abatement total over time

.

As we explain in further detail below, these measur es can be achieved at new and existing compressors at a control cost ranging from $49–$1,0 53 per ton of methane depending on the segment and compressor, exclusive of profits from t he sale of captured fuel and operating and maintenance cost savings. Once these additional rev enues 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 f ollow, 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 doc uments 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 an d which the agency relied upon for most data points in that analysis.

We note here that our calculations likely under-rep resent the true level of methane emissions from compressor seal leaks. This is because the mos t 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 underestima te 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 stu dy. 29 Yet a 2011 report by the University of Texas (“UT”) and URS Institute suggests that the tr ue level of emissions from these devices may exceed the EPA/GRI study’s estimates by several ord ers of magnitude. 30 The UT/URS study authors caution that their study used a smaller sam ple 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 Invento ry or the 2012 NSPS rulemaking materials presumed. For this reason, we assert that our estim ates 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 em issions factor of around 2 tpy/compressor. This amounts to around 0.2 tpy/compressor attributa ble 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 1 996 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 d rastically under-represents the true value for these units, we have not altered that figure when c alculating emissions from existing compressors in the production sector. 31 Even with this added layer of conservatism, our da ta shows significant

29 See EPA and GRI, Methane Emissions from the Natural Ga s Industry, Volume 2: Technical Report (June 1996), available at http://www.epa.gov/gasstar/documents/emissions_repo rt/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/FRepo rts/XA_83376101_Final_Report.pdf

. 31 In calculating control costs for existing units an d potential abatement from new wellhead compressors, however, we revised the emission contr ol 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 fro m the measures we discuss, and EPA must act promptly to adopt these or equivalent measures.

i. Methane Abatement Opportunities for Existing Recipr ocating Compressors

EPA’s 2011 Inventory estimated that 48,469 32 reciprocating compressors were operating in the U.S. oil and gas sector in 2009. Additional compres sors 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 emissi ons from these devices totaling 1,601,862

tons 33 (75.56 Bcf) 34 for 2009. This total includes emissions not only f rom 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 emis sions 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 em issions from reciprocating compressors in this segment are only 2.6 tons/compressor/year, whe reas emission rates for such compressors in the other segments range from approximately 86 to 1 63 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 Sink s (1990-2009) (Apr. 15, 2011) (hereafter, “2011 Inventory”), Annex 3, Tables A-12 0 through A-122 (34,930 production segment compressors + 4,876 processing segment comp ressors + 8,663 transmission and storage segment compressors = 48,469 reciprocating compress ors 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 M T/Gg * 1.1023 tons/MT = 1,601,862 tons of methane emissions per year from seal leaks at oi l and gas sector reciprocating compressors).

34 To convert methane weight to volume, we used a sta ndard 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 ,876 423,030

117,602

4,442

Existing Transmission Reciprocating Compressors 7,1 97 847,955

23,488

678

Existing Storage Reciprocating Compressors 1,466 239,993

6,648

192

Subtotal 48,469

1,601,862

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 Regul ated by 2012 NSPS

Number of

Devices15

Using data from the 1996 EPA/GRI Study, we estimate d the portion of total methane emissions attributable to seal leaks, then multiplied the tot al emissions from reciprocating compressors by this factor to produce an estimate of emissions fro m seal leaks alone. 35 We estimated reciprocating compressor emissions due to seal leak s 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 wh ite 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 i n 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 emissio ns from reciprocating compressor seal leaks can be reduced substantially by replacement o f worn-out rod packing systems on a periodic basis. The agency reports that newly installed pack ing 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 replace ments 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 add itional gas for sale that would otherwise have been leaked and reduce piston rod wear, both of whi ch 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 rec iprocating 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_repo rt/2_technicalreport.pdf

. 36 EPA, Lessons Learned from Natural Gas STAR Program, Redu cing 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 0 9.8% 8,903 2,475

93

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

1,239

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

160

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

34

Subtotal 48,469

368,887 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 Regul ated by 2012 NSPS (Seal Leaks Only)

Number of

Devices16

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 seg ment. 38 These estimates were for new compressors; leak rates for existing compressors ar e likely higher. We applied the 2012 NSPS abatement potential factors to each segment to comp ute a total methane reduction of 292,267 tpy from seal leaks at existing reciprocating compresso rs, 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 agg regated data for production segment reciprocating compressors without providing specifi c information for wellpad devices. Therefore, our estimates for existing units do not offer break down 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, E PA calculated separate cost estimates for emission controls at wellpad compressors and gather ing and boosting compressors, even while it declined to regulate the latter devices in its fina l 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, a nd $104 for reciprocating compressors at gathering and boosting, processing, transmission, a nd 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 reci procating 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 eith er 2011 or 2014 which production sector compressors are wellhead units and which are gather ing and boosting units. Hence, we derived an abatement percentage based on data for all producti on 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 aba tement percentages for each segment were calculated by dividing the abatement opportunity fi gures 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% 5,625 1,564

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, 473 900

26
Subtotal 292,267

33,102

1,203 Equipment Type Emissions abated (tons/year) %

Abatement Emission Abatement Potential - Rod Packing Replace ment at Existing Reciprocating Compressors17

per year for each wellhead reciprocating compressor

. 39 This control factor of .158 tpy per device is substantially less than those factors used for a ny 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 compr essor in the 1996 EPA/GRI Study. By using a control factor that substantially underesti mates the methane emissions reduction potential for these sources, the agency arrives at a cost fig ure 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 E PA cites in its TSD, even while EPA’s Inventory does not provide us with the data to esti mate 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 ot her 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 add itional 50% to arrive at an emission control factor of 3.42 tons of methane per year per compres sor.

Based on these control factors, we calculate a revi sed control cost of $742 for wellhead reciprocating compressors. When cost savings from c onserved gas sales are taken into account, this figure drops to $497 per ton. Accounting for c onserved gas revenues, the control cost for gathering and boosting reciprocating compressors dr ops to $12, and for processing sector units, the control cost is -$156, a net profit.

ii. Methane Abatement Opportunity for Existing Centrifu gal Compressors.

Based on data from EPA’s 2011 Inventory, we estimat e that 1,397 40 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 effecti ve date of the 2012 NSPS, so again, this estimate is conservative. The 2011 Inventory estima tes 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-12 2 (646 processing segment units + 667 transmission segment units + 84 storage segment uni ts = 1,397 wet seal centrifugal compressors sector-wide). Although these tables included emissi ons data for centrifugal compressors at liquefied natural gas (“LNG”) storage and import st ations, they do not specify whether they are wet seal or dry seal compressors. Accordingly, we d o not include those data in our estimates. In any event, aggregate methane emissions from wet sea l centrifugal compressors in this sector are almost certainly higher than our estimates suggest.18

To arrive at the estimate of 535,237 tons of methan e emitted, we used emission factors of 51,370 scfd per compressor in the processing segment, 50,2 22 scfd per compressor in the transmission segment, and 45,441 scfd per compressor in the stor age segment. These emission factors appear in EPA’s 2011 Inventory 41 and are based on calculations from a study conduct ed by ICF
International in 2009. 42 They are conservative compared to EPA’s Natural Ga s STAR report, which indicates that wet seal emissions are more ty pically in the range of 40 to 200 scfm (57,600 to 288,000 scfd), as compared to dry seals that emi t 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 substa ntially increase this emission estimate, so our analysis is conservative in this regard as well

.

The 2009 ICF study also provided detailed breakdown s 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 emiss ions 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: Rep lacing Wet Seals with Dry Seals in Centrifugal Compress ors (Oct. 2006), at 3, available at http://www.epa.gov/gasstar/documents/ll_wetseals.pd f

. 44 See Ex. 4 at 4-5. Methane VOC HAP

Existing Wet Seal Centrifugal Compressors (Processi ng) 646 257,245 71,514 2,701 Existing Wet Seal Centrifugal Compressors (Transportation) 667 259,531

7,189

208

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

Subtotal 1,397

546,338

79,522

2,932 Existing Compressor Emission Estimates - Not Regul ated 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

Devices19

Table 7 : Aggregate Emission Estimates at Oil and Gas Secto r 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-ben efits 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 cen trifugal compressors in the processing, transmission and storage segments to be $14 to 25 p er ton of methane abated, without accounting for savings from recovered gas and reduced operatin g 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 y pu) = .874).

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

, presented at 2014 Natural GasSTAR Annual Implementa tion 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 degas sing unit employed on a high pressure compressor).

48 Based off data from Sections 6.3, 6.4 and 6.6 of t he 2012 TSD at 6-1 to 6-3 ($40,720 (total annual cost for wet seal compressors) / 2,810 tpy m ethane = $14 per ton of methane abated). For Methane VOC HAP
Existing Wet Seal Centrifugal Compressors (Processi ng) 58% 149,970 41,692 1,575 Existing Wet Seal Centrifugal Compressors (Transmis sion) 41% 106,483 2,950 85 Existing Wet Seal Centrifugal Compressors (Storage) 34% 10,010 277 8
Subtotal 266,463

44,919

1,668 Existing Centrifugal Compressors-- Emissions Attrib utable to Wet Seal Leaks

Equipment Type Seal Leak

% of Total Emissions abated (tons/year)

Methane VOC HAP

Existing Wet Seal Centrifugal Compressors (Processi ng) 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 232,950

39,282

1,459 Equipment Type Emission Abatement Potential - Replace Wet Seals w ith Dry Seals

%

Abatement Emissions abated (tons/year)20

savings into account, our recommended measures woul d 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 n ot calculate the cost for these segments that includes the revenue from conserved gas.

iii. Methane Abatement Opportunity for New Compressors T hat 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, a nd any regulatory approach that specifically targets methane should require emission controls at these units.

EPA estimated a total of 6,000 new wellhead recipro cating compressors installed each year, with aggregate seal leak emissions of 947 tpy methane, 2 63 tpy VOC, and 9.91 tpy HAP. 52 As discussed above, EPA’s methane emission reduction f actor 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, f or 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 compr essors 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 abo ve, these measures entail a control cost of $742 per ton of methane abated without accounting f or revenues from captured gas sales and $497 per ton when considering these savings.

Additionally, EPA’s 2012 NSPS did not cover new com pressors (either reciprocating or centrifugal units) located in the transmission and storage segments. The agency again concluded that VOC emissions were typically low at these loca tions, 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 p acking systems at transmission segment units, EPA calculat ed a control cost of $77 per ton of methane

the transmission and storage cost ($25), we used th e 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 se ctor, 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 com pressors will be installed each year in the natural gas storage segment, with a correspo nding 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 s eal 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 in stalled 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 esti mated the control cost of regulating these units at $97 per ton of methane reduced, with a pro fit of $703 per ton when accounting for reduced operating and maintenance costs. 58

Table 9 : Emission Reduction Opportunities at New Compresso rs Not Regulated Under EPA’s
2012 NSPS

Notably, these abatement figures account only for t he first year that controls would be required at new compressors. After the second year, the total e ffective 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 equipmen t 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 emissio ns (including both seal leaks and fugitives)

55 Id. at 6-17 (Table 6-7). Because transmission and stor age 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 Compressor s** 110.00 3.06

0.09

14

1,546

43

1.3

Subtotal 22,576 3,188

117

*Emission Estimates from EPA 2011 TSD, Table 6-6, P age 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 an d Storage. The category labeled Transmission and Storage is the Processing Segment. Emission Abatement Compounds Each Year

Potential Emission Abatement from New Compressors N ot 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 (in cluding both wet and dry devices) at 632,194
tpy 61 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—thes e emissions amount to nearly 43.5 million metric tons per year CO 2 e. 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 CO 2 e 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% reducti on of seal leak emissions at existing reciprocating compressors and 87% reduction at exis ting wet-seal centrifugal compressors), we
calculate that the recommended measures would reduc e seal leak emissions from existing compressors by 537,479 tpy. Table 10 below breaks d own 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 av ailable 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+773,2 94+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 rec iprocating 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 com pressors).

63 The IPCC’s most recent GWP figures for methane fro m 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/WG1A R5_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 537,479

82,745

3,051 

### Emission Abatement Potential - Existing Compressor s

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 537,4 79 tpy and from new compressors by 22,576 tpy. As indicated earlier, we believe that these es timates are conservative in light of the very low emission factors EPA used in the 2011 Inventory; ac tual 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 a ny reasonably identifiable possibility of overstating seal leak emissions from compressors. E ven with these conservative assumptions, the recommended measures are warranted, as they reduce substantial amounts of emissions of methane, VOC, and HAPs, while either imposing minim al costs or generating a profit. Forgoing these conservative assumptions would result in subs tantially lower costs and higher methane capture rates, only strengthening the case for imme diate 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 th at EPA already has data available and compiled that shows that available pollution controls are co st-effective, feasible, and will reduce harmful pollution of methane and other pollutants substanti ally. We recommend that EPA simply update the existing TSD materials from 2012 to focus on me thane and include new activity and cost data,
then issue a rule that includes the measures we hav e recommended herein.

Lastly, we propose several additional approaches to methane regulation to supplement those we have already discussed. First, we support EPA’s con sideration 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 re quired to retrofit existing wet seal centrifugal compressors with gas capture systems th at 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 majo rity 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 em issions 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 com pressors. 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 I nventories. We have noted that some data sources suggest that actual emissions from com pressor 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 emi ssions from compressor seal leaks are
overestimated in the Inventories.

In general, the dataset for emissions from compress or seal leaks is fairly strong, with a number of studies confirming that emissions are sub stantial 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 mul tiple places in our comments.24

• Questions 2 – 5: In a general sense, we believe that the white pape r adequately characterized studies on emissions, the range of te chnologies for capturing emissions, emissions reductions from those technologies, and c apital 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 fo r wet seal compressors.

• Question 9: Gas capture systems are generally applicable to we t seals compressors. A recent report by BP describe these systems as “[s]i mple, 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 compr essors are such that simple installations, using minimal moving parts and a sim ple critical orifice approach to manage pressures, can route gas from degassing drum s to compressor suction. 65

• Questions 10 and 11: We have no information on these matters.

• Question 12 : Studies coordinated by EDF of emissions from natu ral gas gathering and processing facilities and natural gas transmission and storage facilities are underway. To our knowledge, the study of gathering and processin g facilities will not differentiate emissions from compressor vents (the study will mea sure emissions from the entire facility). However, it is possible that this resear ch may provide insight on emissions from

compressors.

We do not know of any current studies to measure em issions from compressor seals.

IV. Comments on Pneumatic Devices White Paper

A. Introduction

Pneumatic equipment in the oil and gas industry use s 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. Man y PCs in the oil and gas sector use pressurized natural gas as their energy source and vent some qu antity of that gas into the atmosphere in normal operation. These devices include continuousl y emitting devices (either high-bleed or lowbleed PCs), snap-acting or intermittent devices (wh ich 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 s ource 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 measur es requiring operators to replace existing highbleed and intermittent-bleed PCs with low-bleed dev ices. 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 savin gs 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 character ize the emissions from PCs according to the best data available, and then assess the degree of abate ment 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 que stions included in EPA’s pneumatic devices white paper.

B. Emissions from Pneumatic Controllers are Substantia l, and Underestimated in
Available Data

EPA’s white paper for pneumatic devices includes re cent 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 in dustry data, since only facilities with calculated emissio ns over the reporting threshold are required report to emissions. Further, in the gas and oil pr oduction sector, only devices at wellpads are required to report emissions; PCs located at gather ing and boosting facilities do not report data to the GHGRP. However, while the GHGRP data underestim ates the true emissions from oil and gas sector PCs, it is nonetheless much more accurate th an the 2014 Inventory estimates of PC emissions in the oil and gas production segments, a s 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 on e hand, and from gas transmission and storage, on the other hand.

i. Emissions from PCs in the Oil and Gas Production Se gments

Because PC emissions from oil production and gas pr oduction are combined in the GHGRP, we consider these sources together and treat them as o ne 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 rep orts 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 produc tion PCs at 949,327 tons in 2012. As noted above, GHGRP data only captures a subset of emissio ns from these segments, but for the facilities that do report emissions to the GHGRP, d ata for PC emissions are superior to those reported in the 2014 Inventory.

66 EPA, White Paper on Oil and Natural Gas Sector Pne umatic 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 emiss ions factors to calculate aggregate PC emissions: each study traces back to the 1996 EPA/G RI 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 com position of emitted gas—are certainly superior in the GHGRP, where each reporter counts c ontrollers and uses its own gas composition data to calculate emissions. Furthermore, GHGRP dat a 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 est imate based on an average composition by NEMS region, the method used in the EPA/GRI study a nd the 2014 Inventory. For these reasons,
it is clear that GHGRP data is more accurate than t he Inventory’s estimates for the subset of wellpad PCs that report emissions through the repor ting 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, highli ghts 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 Alle n, et al.
emissions factors to be more accurate than those li sted 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 metha ne 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 G HGRP for 2012 and Corrected with Allen, et al .’s Emissions Factors Bleed type Emissions

(Tons CH 4 ) Emission Factors

(scfh) Emissions (Tons

CH 4 )

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+h tml (supplemental appendices and tables available at http://www.pnas.org/content/suppl/2013/09/11/130488 0110.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 In dustry, Vol. 12: Pneumatic Devices (June 1996), Section 4.1.2, available at http://www.epa.gov/gasstar/documents/emissions_repo rt/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 me thane 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 t he 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 accurat e estimate of emissions from transmission and storage PCs, since the GRI/EPA study on which it wa s 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 th e Inventory data as the starting point to estimate emissions from PCs in these segments, we r ely on the GHGRP’s ratios of different bleed-types to apportion the percentage of those em issions attributable to each type of device.

C. The Methane Abatement Potential from Controlling Em issions at High- and
Intermittent-Bleed PCs is Substantial

The pneumatics white paper does not include total m ethane abatement estimates, but only estimates of total emissions from PCs in each segme nt 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 emissi on controls at high- and intermittent-bleed
PCs. The estimates are shown in the table on the fo llowing 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 agenc y estimated emission control benefits of 25,273 tpyVOC, with co-benefits of 90,910 tpy metha ne and 954 tpy HAPS. 73 EPA estimates in its TSD that the rule would cover 13,647 devices pe r year. 74 However, the agency declined to issue a concurrent or subsequent rule regulating em issions from existing high-bleed devices, which currently amount to some 428,000 tons per yea r. 75

The final NSPS rule also did not apply to intermitt ent-bleed (“IB”) PCs, which EPA did not discuss in detail in the pneumatics white paper des pite 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, purpose s. The American Petroleum Institute (“API”)

73 EPA, Oil and Natural Gas Sector: Standards of Performanc e for Crude Oil and Natural Gas Production, Transmission, and Distribution: Backgro und 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 SC F/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 co ntroller.” 77 PCs emitting less than 6 scfh (including both continuous-bleed and IB devices) ca n serve many of the functions of higheremitting intermittent devices, which could therefor e be replaced with low-bleed controllers. There are many applications for PCs, as well as a wide va riety of parameters for controller design, such as pressure, extreme temperature performance, respo nse time, flow rate, corrosiveness of fluids, and more. As such, there are many controllers of bo th 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 ha ve been included in the 2012 NSPS rule but

was not. 80 We conservatively estimated that 95% of existing h igh-bleed PCs could be replaced
with low-bleed PCs. While EPA’s Natural Gas STAR Pr ogram 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 devic es is feasible. Colorado required operators to replace existing high-bleed controllers in the urba n 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 proc ess 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-b leed devices can be replaced with lowbleed units. 85 We use this estimate for oil and natural gas produ ction 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 Reso urces Defense Council, Earthworks Oil And Gas Accountability Project And Wildearth Gu ardians, available at ftp://ft.dphe.state.co.us/apc/aqcc/REBUTTAL%20STATE MENTS,%20EXHIBITS%20&%20AL T%20PROPOSAL%20REVISIONS/Conservation%20Group/Conse rvation%20Groups%20- %20REB%20Exhibits.pdf

. 78 For discussion of low-bleed devices, including som e specific low-bleed devices, see EPA, Lessons Learned from Natural Gas STAR Partners: Opt ions 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, Cle an 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 at29

In its March 2014 report co-authored with EDF, ICF International estimated that 75% of intermittent-bleed PCs in oil and gas production fu nction as dump valves on separators at well sites and did not recommend replacing these PCs wit h 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 PC s. 87 For the natural gas transmission and storage segments, IB PCs emit at a very low rate, a nd we do not consider replacing them in these

calculations.

We used the best available emissions factors for PC s of each bleed type 88 to estimate the potential emissions abatement from replacing high- and interm ittent-bleed PCs with low-bleed PCs. To estimate emissions from PCs in oil and gas producti on, 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 an d assume that the portion of emissions originating from each bleed type is the same as ind icated in the GHGRP data.

The resulting potential abatement is shown in the t ables 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 meth ane depending on the segment and type of pneumatic controller being replaced, without accoun ting for profits from the sale of captured gas or reduced operating and maintenance costs. If capt ured gas sales and operating cost reductions are included, economic attractiveness of these meas ures improves; in fact, in most cases, the control measures will generate positive cash flow f or operators. The tables that follow illustrate the emission abatement potential from these control measures.

Table 12 : Emission Abatement Potential of Converting PCs fr om High-Bleed to Low-Bleed

Industry Segment Current

EmissionsFrom 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%2 0ANALYSIS%20&%20EXHIBITS/CD PHE%20Cost-Benefit%20Analysis_Final.pdf

. 86 EDF/ICF International, Economic Analysis of Methane Emission Reduction Opp ortunities 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 a nd natural gas production, we used the Allen, et al . emissions factors (5.1 and 17.4 scfh, respectivel y). For other PCs, we used the GHGRP emissions factor (37.3 scfh for high-bleeds i n petroleum and natural gas production; ).

89 The ratio of methane to VOC and HAP is based on th e 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%

Totals 90 360,531 84%

Table 13 : Emission Abatement Potential of Converting PCs fr om 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 Cont rol 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 segmen t due to very low emissions.31

D. Control Costs to Convert Existing High-Bleed Pneuma tic Controllers to Low-Bleed
Devices

The cost to replace a high-bleed and intermittent-b leed pneumatic controllers with low-bleed controller is very modest. Here, we estimate the co st for retrofitting an existing PC with a new PC by considering the full cost of the replacement con troller. Our estimate is conservative because we assume in all cases that the existing higher emi tting 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 al ready reached the end of their useful lives by the time the replacement is required.

Very recently, the CDPHE estimated the cost of repl acing high-bleed controllers in this manner. 91 Based on labor and equipment costs of $1,420 per de vice replaced, CDPHE calculated a replacement cost of $169/yr/device, assuming that c osts 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 ove r10 years
at a 7% interest rate to arrive at an annual contro l cost of $427/yr/device. These equipment costs bracket EPA’s estimate in the OOOO TSD of $2,554 fo r a new low-bleed controller. 94 In some cases, the cost can be as low as $700 per new contr oller, 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 int ermittent-bleed PC with a new low-bleed device.

EPA’s NSPS estimated that converting from a high-bl eed 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 storag e segments. 96 We calculate the methane emissions abatement for replacing an IB PC with a l ow-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 bee n vented, the control measures described above have very reasonable abatement costs of $25 t o $208 per ton of methane, depending on the industry segment and the type of controller being r eplaced. Table 15 below provides these cost control figures. These costs per ton of methane aba tement are well below the harm to society caused by a ton of methane emissions, which EPA eco nomists recently estimated at $970 per metric ton (or $879 per short ton). 97

Table 15 : Abatement Costs for Pneumatic Controller Replacem ent

91 This analysis was not described in the white paper s.

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.

95 EPA 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_oilg as_20051006_methanerec_pd_vru_dehy.p
df

. 96 TSD at 5-6 (Table 5-2). Using the emissions factor s from Allen, et al. would result in slightly smaller emissions abatement from high-bleed replace ment.

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 $20 8.29

When accounting for increased revenue from sales of conserved gas that would otherwise have been emitted, CDPHE analysis shows that replacing h igh-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 an d storage facilities do not own the gas they transport or store. For production segment operator s, the payback period for this replacement is about 14 months. For replacement of an IB controlle r with a low bleed controller, using the cost figures from the CDPHE analysis but adjusting for t he 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, ev en at a cost of $3,000 per device, resulted in an overall savings: “Although there are lower cost est imates from Gas STAR and vendors, this measure assumed a cost of $3,000 per replacement ba sed on industry comments. Both options yield a greater than 90% reduction. This yields a r eduction cost of

‐ $3.08/Mcf of methane for replacement of high bleed pneumatics . . . .” 99

E. Device Classification Issue in the 2013 Prasino Gro up Study

The Prasino Group’s 2013 study of emissions from pn eumatic controllers is described in the pneumatics white paper. However, the white paper de scription of the study omits a few key aspects of the Prasino study. While the 2012 NSPS r ulemaking, 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 inc ludes 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 m 3 /hr [6 scf/h]) were grouped together in the analysis. If t he calculated mean bleed rate was larger than the threshold, the device was inclu ded in the analysis, and if the
calculated mean bleed rate was smaller than the thr eshold, the device was excluded from the analysis for determining a generi c bleed rate. Certain controllers that are considered low-bleeding accord ing to WCI or manufacturer specifications actually bled above the low bleed th reshold 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 i ncorrect 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 ma nufacturer specified bleed rates well below the threshold rate of 6 scf/h, both emit gas at ave rage rates significantly higher than the threshold. Prasino measured 32 Fisher 2680 units, which have a specified bleed rate of 0.04 m 3 /h (1.4 scf/h), and found average bleed rates of 0.268 m 3 /h (9.5 scf/h). 102 They also measured 48 Fisher L2 controllers, which have a specified bleed rate of 0 .06 m 3 /h (2.1 scf/h), and found average bleed
rates of 0.264 m 3 /h (9.3 scf/h). 103

While the excess pollution from these controllers i s a significant concern, 104 a large body of evidence, including the 1996 GRI/EPA study and GasS TAR 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 li sted in the Prasino study show that many highbleed units are designed to emit at far higher rate s. 107 The problem of excessively high emissions from PCs that are designed to emit at very high rat es should not be obscured or made to appear less severe by averaging emissions from low-bleed c ontrollers emitting excessively alongside high-bleed controllers.

101 Prasino Group, Final Report For Determining Bleed Rates for Pneuma tic Devices in British
Columbia (Dec. 18, 2013), at 15, available at http://scek.ca/sites/default/files/ei-2014-01-final

report20140131.pdf

. 102 Id. at 14, 30.

103 Id.

104 We note that the same phenomenon is apparent in th e data from Allen, et al. , which reported that low-bleed PCs were venting 5.1 scf/h, 270% mor e gas than EPA’s emissions factors predict. The average emissions from low-bleed unit is only s lightly below the 6 scf/h threshold, strongly suggesting that a significant number of the low-ble ed 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#p neumatics

. 106 For example, third party verification of emissions of 18–22 scf/h was measured for 148 controllers from three manufacturers in a high-blee d controller retrofit project by Chesapeake Energy registered with the American Carbon Registry

. See http://americancarbonregistry.org/mount_acr/acr/car bon-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 n ot appropriate to consider it when evaluating the merits of replacing high-bleed PCs with low-bleed P Cs. Namely, Prasino included PCs in their results that would not be targeted by a typical eff ort to replace high-bleed PCs. However, the Prasino study does highlight the issue of excess em issions 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 eval uating 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 questio ns.

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 develop ing this lower emission factor. 108 Factors that may have contributed to a lower emission factor inc lude 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 o perators to conduct testing. This could have resulted in directed sampling in areas with less hi gh-bleed devices.

F. Summary

Using existing data from the GHGRP and the EPA’S 20 14 GHG Inventory, we calculate a methane abatement opportunity of 507,286 tpy from r eplacing high- and intermittent-bleed pneumatic controllers with low-bleed pneumatic cont rollers in specified segments of the oil and gas industry. The cost of this abatement varies bet ween 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 generat e net profits for operators due to potential revenue from conserved gas sales.

Additionally, we support EPA’s consideration of mea sures that would require operators to replace continuous bleed controllers with zero-bleed PCs, u nits powered by instrument air, or solar powered systems wherever technically feasible. Howe ver, EPA must not delay developing and implementing a methane control rule that would requ ire the measures described in our analysis while the agency gathers data on these other option s. EPA must immediately move forward with rulemaking that requires replacement of all high-bl eed 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 c ost and feasibility of replacing all continuous bleed controllers with zero-bleed devices, instrume nt air controllers, or electronically-powered
systems.

G. Charge Questions for Reviewers

1. The white paper did not adequately describe the Pra sino Group study from 2013. As explained above, this study averages together emiss ions from low-bleed PCs that emit methane at rates greater than their operationally s pecified rates with emissions from highbleed controllers, which typically emit at rates mu ch 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 ev aluating 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-emit ting devices.

2. The variation in measured emissions from PCs across different studies is due in part to inconsistent definitions of PC bleed types. For ins tance, 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 “hig h-bleed” dataset. This approach lowers their average emissions rate for “high bleed contro llers” significantly.

3. The white paper described a variety of technologies available to reduce emissions, but described some too narrowly. For example, electroni c control instrumentation is described in section 3.1.4. While solar cells may p rovide an excellent source of electrical power for this type of instrumentation, other optio ns 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 generators 109 or small onsite gas generators. Furthermore,
retrofit kits are available to reduce emissions fro m some high-bleed PCs. 110 These options are not described in the white paper, and the agenc y should evaluate their availability and efficacy.

4. As explained above, we believe that non-emitting te chnologies such as zero-bleed controllers, instrument air devices, and electronic ally control systems should be required whenever they are feasible. The reports that emissi ons from low-bleed controllers are higher than expected from manufacturer specificatio ns (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 no t 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 mo ve 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 differ ent types of pneumatic controllers and non-emitting technologies in the field, or on t he particular activities that require the use of high-bleed PCs, we reiterate that the indust ry 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 exem ption from the retrofit requirement, not a single exemption request was received by CDPH E.

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 fa cilities and the wide variety of natural gas- powered compressors and generators available o n the market, instrument air systems could easily be developed to match the compressed a ir requirements of any facility at a reasonable cost. However, the great bulk of emissio ns from pneumatic valve and controller systems come from the controllers themse lves, as opposed to actuators. Given

109 See, e.g.

, http://en.wikipedia.org/wiki/Thermoelectric_generat or#Uses

. 110 For example, Mizer valves used in the Chesapeake r etrofit project. See Chesapeake retrofit project at 9.36 the advances in electronics, electronic control sys tems should be considered for many PC applications, and may be more appropriate and resul t in lower emissions than instrument air systems for many applications given very low po wer 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 th em promptly to do so.

9. We are aware that EDF and the University of Texas a re currently studying methane emissions from PCs in the oil and gas sector. We ar e 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 th e well declines to the point that it cannot lift these liquids, which then accumulate in the wellbor e. Liquid loading can impair gas production rates or arrest gas flow completely. Once the accum ulated liquids are removed from the wellbore, there is less backpressure on the gas formation, al lowing gas flow to resume, or resume at a higher rate. For this reason, gas well operators ha ve been voluntarily investing in methane abatement technology for many years, with the prima ry goal of improving gas well production performance. 111

Liquids accumulation is an extremely common occurre nce, and liquids unloading is correspondingly a common practice. In comments on t he 2011 NSPS proposal, the American Petroleum Institute asserted that all gas wells pro ducing 90 Mcf of gas (15 BOE or less) or less per day “are either impaired by liquids accumulatio n or are using a deliquification method to produce.” 112 In that comment, API relied on 2009 EIA data to co nclude 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 liquids 114

.

Liquids can be unloaded through a variety of techni ques. Most basically, the well can be simply vented, sometimes referred to as a “blowdown.” A ty pical operating configuration has produced fluids flowing from the well into pressurized surfa ce 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 deli quification. Many of these publications include economic assessments of improved profitabil ity. The most efficient location to access these publications is the OnePetro online library o f technical literature for the oil and gas exploration and production (“E&P”) industry. OnePet ro at www.onepetro.org . OnePetro contains 172 technical publications on gas well deliquificat ion and 846 technical publications on liquids unloading, 780 papers on plunger lifts, and hundred s 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_t able.html ).

114 API/ANGA. Characterizing Pivotal Sources of Methane Emissions from Natural Gas Production Summary and Analysis of API and ANGA Sur vey (Sept. 21, 2012), available at http://www.api.org/~/media/Files/News/2012/12-Octob er/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 velocit y and push accumulated liquids out of the well.

A more sophisticated approach is to use a plunger l ift. A plunger lift is a simple and common artificial lift method used to efficiently lift liq uid 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 t hat it does not require electricity, and so can be installed at well sites that do not have power. A p lunger lift system is powered by the natural gas pressure that builds up in the casing tubing annulu s. Installation of a plunger lift generally increases gas production by 10%. Plunger lift perfo rmance 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 un loading in 2011, 28,863 vented, 174,743 used plunger lifts, and 65,003 used other artificial lif t methods. 115

Plunger lifts are only one of many available artifi cial lift technologies—numerous additional systems can be used as well, including:

• Pumping techniques, such as progressing cavity pump s, 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 blo wdowns. For plunger lifts, although API/ANGA data indicates that the majority of plunge r lift installations (79%) have no emissions, 116 21% are operated in a way that still releases appr eciable pollution. The white paper summarizes the API/ANGA data on liquids unloading e missions 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 fa ctor 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 s everal wells.

Table 16 : Summary of Liquid Unloading Methane Emissions

API/ANGA GHGI e GHGRP d 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 associat ed 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 ac tivity 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 5.37 b 4.96 b 5.19 b 6.39

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 12.4 c 6.39

a API/ANGA do not separate emissions for plunger lif ts from emissions from vented wells.

b Total estimated emissions divided by number of wel ls.

c Different wells than those for which engineering e stimates provided. The GHGI does not specify which wells were directly measured.

d Data derived from Liquids Unloading Whitepaper Tabl e 2-2

e Data derived from Liquids Unloading Whitepaper Tabl e 2-4; emission factors estimates for plunger lift and venting wells are weighted average s of the emission factors given for the six regions.

Although these estimates differ at the margins, the y reveal general trends:

• Total methane emissions from unloading exceed 300,0 00 tpy. The 2014 Inventory, which had the lowest estimate of total emissions, conclud ed 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 annua lly.

• Approximately half of these wells use plunger lifts and the other half vent.

• Average methane emissions for wells that emit are r oughly 5 tpy.

• Average emissions for wells that emit despite using plunger lifts are higher than average emission from wells that unload using blowdowns. Th is 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 w ells where uncontrolled emissions would be much higher than the average emission with plunger lifts installed reported

here.

Several of the marginal differences in these estima tes are to be expected. As we have explained elsewhere, the GHGRP data should, as it does, inclu de 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 co nservative. First, the API/ANGA, 2014 Inventory, and (to a large extent) GHGRP emission f actor 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 EP A’s previous estimates, and EPA has not explained why the data underlying these former esti mates is no longer relevant. Although the API/ANGA study’s activity factor estimates are base d on a survey of nearly 60,000 wells39

covering 18 basins, the study’s emission factor est imates 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 duri ng unloading on the basis of prior data from 2,219 venting wells (2,200 wells in the San Juan Ba sin and 19 wells in Big Piney, Wyoming) regarding frequency of blowdowns, or venting, and e ngineering calculations of emissions per
blowdown. 119 Using these inputs, the 2011 Inventory estimated a n 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 on ly 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 reques t that API/ANGA provide location data for the 5,327 wells used to determine the emissions fac tor 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 emissi on factor estimate provides an accurate representation for liquids unloading emissions acro ss the United States for all wells that have unloading emissions. The API/ANGA estimates are bas ed on data volunteered by API/ANGA members. Little information was made publicly avail able about the survey methods, which companies reported data, or whether the data is rep resentative of nationwide emissions. Accordingly, estimates derived from this self-repor ted 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 unloa ding emits raw gas, which is often rich in VOC and has significant amounts of HAP, this can af fect 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 g as, this suggests that VOC and HAP
emissions were 18.5 tons of VOC and 1.34 tons of HA P per well per year. Given the high concentration of wells in some areas (and the tende ncy 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, Liqui ds 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 throu gh 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 P etroleum and Natural Gas Industry: Background Technical Support Document (Nov. 2010), pp. 89-90, available at http://www.epa.gov/climate/ghgreporting/documents/p df/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 Clea n Ups (LP Gas Wells)” data from each reporting region. See EPA, Inventory of U.S. Greenhouse Gas Emissions and Sink s (1990-2009), (Apr. 15, 2011), Annex 3, pages A-149 to A-153.40

geographically grouped for logistical purposes), th is 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 t he 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 plung er lift is not operated optimally, however, liquid sufficient to kill the well can eventually accumula te despite the presence of the plunger lift, and in these cases, the well can be vented for a short per iod of time to generate the differential pressure needed to resume well liquid removal.

These intermittent periods of venting can be avoide d by optimizing operation of the plunger lift, typically with an automated controller. Automated c ontrollers 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 min imize manual well venting when the plunger
lift is overloaded. Automated controllers can be ma de “smart” to monitor and better time automation, producing further emission reductions a nd increases in well production.

There are numerous other artificial lift methods th at 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 c ompression, foam, hydraulic pumps, beam pumps, gas lift, electric submersible pumps, progre ssive cavity pumps, among other methods. 122

The white paper omits discussion of several of thes e methods of liquids unloading, notably gas lift. Gas lift re-injects produced gas to reduce bo ttom-hole pressure and increase gas production rate to lift liquids. Gas lift has several advantag es over other lift methods, including that it can b e 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 un loading cannot be eliminated using plunger lifts with smart automation (see below), EPA should consi der requiring operators to capture or, as a last resort, flare gas that would otherwise be vent ed. 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 tan ks 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 S ource Performance Standards and National Emission Standards for Hazardous Air Pollutants Rev iews , at 5-6, available at http://www.regulations.gov/#!documentDetail;D=EPA-H Q-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 Utilization 124

#
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 emissi ons 36,806 13.7

Wells that blowdown/vent to unload 28,863 10.7

Thus, according to API/ANGA data, available technol ogy allows liquids unloading without any emissions from venting the well. Wells that unload using blowdowns can apply these technologies to significantly reduce, if not elimin ate, 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 Unloadi ng 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 installati on cost to $7,600 to $28,000 per well. 126 Annualizing the capital cost over 5 years at 7%, a nd 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) wou ld range from $2,600 to $8,200 per well.

Natural Gas Star partners have reported that plunge r lifts decrease gas venting by an average of 600 Mcf per year per well. 128 This translates to a methane abatement cost of bet ween $91 and $300 per short ton of methane, not including the ad ded revenue from selling gas not vented. For plunger lifts with smart automation, reported abate ment ranges from 800 to 1,460 Mcf per year per well, 129 for abatement costs of between $92 and $540 per sh ort ton, again neglecting the revenue from selling the gas instead of venting it.

If revenue from additional gas sales is included, p lunger lifts with or without smart automation quickly become profitable, though the former is muc h 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 -$9 6 to $110 per short ton of methane, and plunger

lifts with smart automation have net abatement cost s 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 Les sons 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 o f 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 fo r well maintenance (such as blowing liquids out of the well manually, but also down-hole work t o repair damage to wells from the effects of long-term liquids build-up). These savings can easi ly exceed $10,000 per well per year. 131 The combination of these savings and the increased reve nue 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 smar t 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 peri od. 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 we lls 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 m ethane abatement beyond the average abatement from use of plunger lifts alone. 133 200 Mcf, the bottom of this range, is equivalent t o 4.16 tpy. This reinforces API/ANGA’s indication tha t optimized plunger lifts can completely eliminate emissions, as the 200 to 860 Mcf abatemen t 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 approximat ely 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 autom atic 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 Techno logies (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 Learne d – Fluid Options. These values are the differences in minimum and maximum prices between p lunger lift installation with and without
smart automation.43

automatic controller and $6,000 for the cost of ins talling 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 plu nger 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 d oes 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 t hat could be achieved by installing smart
automated controllers on wells that lack them. If n one of these wells have smart automated controllers, a 50% reduction in liquids unloading e missions from these wells represents a 65,573 to greater than 66,117 tpy reduction, using 2014 In ventory and GHGRP data, respectively. 137 If we instead use the 4.16 tpy abatement figure indica ted by Natural Gas STAR data, and the counts of 23,503 to 36,806 wells with plunger lifts with e missions (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 t he data sources for liquids unloading discussed in the white paper.

• Question 4: As noted above, the white paper did not discuss th e use of gas lift to remove liquids from wells.

• Questions 11 and 12: We have raised this issue above. If venting emiss ions 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 c omponents at oil and natural gas facilities, such as tanks, hatches, meters, flanges, valves, connect ors, regulators, etc., emitted over 2.4 million short tons of methane in 2012, according to EPA’s n ationwide estimates in the 2014 U.S. Greenhouse Gas Inventory (2014 Inventory). We incl ude here leaks from wellpads (natural gas and petroleum), gathering compressor stations, proc essing 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 t he emission factor derived from engineering estimates, ignoring the higher average emissions re ported 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 facto r 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 t he mitigation approach described below is appropriate for all of these facilities. 138 As evidenced by independent research described bel ow, 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 E PA’s White Paper, Oil and Natural Gas Sector Leaks, clearly show that substantial mitigation of methan e emissions from leaking components is achievable at reasonable costs to pro ducers 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 pr ograms 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 cost s derived from these analyses. One important exception (Carbon Limits, 2013) directly assessed c osts associated with LDAR programs independent of any general estimate of facility lea k 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 v ery reasonable costs. As described below, the Carbon Limits analysis shows that monthl y 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 emission s, and the availability of LDAR programs at a reasonable cost, EPA must address methane emis sions from leaks and require facility operators to regularly conduct instrument-based lea k detection surveys and repair the leaks that
are identified.

Our comments for the leaks white paper are structur ed as follows.

In Section A, we describe critical synthetic conclu sions from reports described in the white paper – and reports that it does not describe – that inform key questions on emissions a nd costs of abatement addressed by the white paper. These concl usions 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 n atural gas emissions strongly suggests that leaks are important contributors to additional methane em issions that are not included in the inventory’s estimates; and 2) that LDAR program cos ts are very reasonable.

In Section B, we provide specific comments, clarifi cations, and corrections for the leaks white

paper.

138 This figures, and figures below on abatement of le aks, 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 com pressor shafts and rods. Venting of leaks from sea ls on shafts and rods is discussed in the Compressors Whi te Paper.45

In Section C, we provide answers to some of the Cha rge Questions for Reviewers.

A. Critical Synthetic Conclusions

i. Methane Emissions from Oil and Gas are Underestimat ed by the 2014 Inventory, and Available Evidence Implicates Leaks

As discussed in part II.B above, a number of top-do wn 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 th at official inventories consistently underestimate actual [methane] emissio ns, with the [natural gas] and oil sectors as important contributors.” 139 The inventories’ underestimate is substantial. Bra ndt et al. estimate that the 2013 Inventory 140 underestimates methane emissions from all U.S. sou rces by 25 – 75%, and show that oil and natural gas systems must acco unt for much of this underestimate. Brandt’s central estimate for the methane emissions not repo rted in the 2013 Inventory, 14 Tg per year, 141
is almost twice as large as the 2014 Inventory figu re 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 em it more methane then the Inventory reports, it is certain (due to measurements in oil and gas prod ucing regions, and isotopic and chemical analysis of the observed methane and other hydrocar bons present in the air) that oil and gas systems contribute significantly to these unaccount ed-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 signific ant portion of the excess methane emissions from oil and gas facilities. As noted by Brandt et al ., analysis of individual leak measurements from oi l and gas facilities consistently shows skewed distri butions with a very small numbers of sources having highly disproportionate emissions, thus acco unting for a large percentage of total emissions. For example, the Clearstone II study ref erenced 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 suffici ently 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 Natura l 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 th e 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 hy drocarbon emissions from oil and natural gas operations in the Colorado Denver-Jules burg 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 scal e). 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 ot her air pollutants with LDAR programs.

While the leaks white paper does describe the study by Carbon Limits, “Quantifying CostEffectiveness of Systematic Leak Detection and Repa ir Programs Using Infrared Cameras,” 145
important aspects of the study design and results w ere not described.

The Carbon Limits study was conducted using a datab ase of detected leak sizes and repair costs from surveys conducted by two firms that provide LD AR 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 LDA R survey for some years. The rules allow use of OGI, and in general operators use OGI for survey s. As a result, the leak rates found during the survey were lower than would be found during survey s of most facilities in the U.S. where LDAR programs have either not been required under state or federal rules 146 or implemented voluntarily. Accordingly, the volume of methane emissions abatem ent calculated from these surveys is less than it would be in an area without LDAR programs i n 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 ge nerally 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 t he surveys and repairs, so the abatement cost is negative (meaning the facility owner earns more mon ey from increased sales than it spends). For more frequent surveys, which are appropriate for la rger facilities and justified to prevent emissions, costs are positive but still very reason able.

Table 18: Emissions net abatement cost ($ / metric ton) of LD AR 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 tonn e of CO2e abatement
Gas plant -6.3 -2.7 4.6 34

145 The leaks white paper cites a pre-publication vers ion of the Carbon Limits study that was posted onli ne in late 2013. The Carbon Limits study has since be en finalized and is available at http://www.carbonlimits.no/PDF/Carbon_Limits_LDAR.p df

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 a nalyses of the cost-effectiveness of LDAR programs that were entered into the record during d eliberations over Colorado’s new regulations on emissions of methane and volatile organic compou nds (VOC) from oil and natural gas facilities. The Colorado Department of Public Heal th and Environment (CDPHE) estimated that the rule, which requires LDAR at frequencies determ ined 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 e missions abatement. 147 Estimated costs for tiered LDAR at wellpads are $805 per short ton of m ethane 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 t he cost data reported by Carbon Limits. 149
Additionally, CDPHE found that repair costs are les s 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 rulem aking process. These data demonstrate that firms are able to perform LDAR surveys for eve n lower costs than were reported in the Carbon Limits study.

Facility Type Cost per Inspection

Carbon Limits Anadarko Petroleum Corporation 152 Noble Energy Incorporated 153 Compressor Station $2,300 $1,250 – $5,150 Multi well batteries $1,200 $450 - $800 $263 - $431 Single well batteries $600 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%2 0ANALYSIS%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 Pos t, 11/18/2013. (available at: http://www.denverpost.com/environment/ci_24548337/p roposed-colorado-airpollution-regs-clamp-down-oil ).

152 ftp://ft.dphe.state.co.us/apc/aqcc/PRESENTATIONS/No ble%20Energy%20Inc%20&%20Anadarko%20 Petroleum%20Corporation/Anadarko.pdf

153 ftp://ft.dphe.state.co.us/apc/aqcc/PRESENTATIONS/No ble%20Energy%20Inc%20&%20Anadarko%20 Petroleum%20Corporation/Noble.pdf48

• Question 2. As the white paper describes, emissions estimates f or the GRI/EPA study,
which is the basis for most of the emissions inform ation in the inventories, were made using the Correlation Approach. Furthermore, the c orrelation equations used were
derived from measurements carried out at facilities such as refineries, processing plants, and oil and gas production facilities. It is not cl ear that these correlation equations are appropriate for natural gas facilities that may ope rate at different temperatures and pressures, and that handle fluids of different prop erties (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 dir ect quantification of leak emissions and should be used to estimate emissions whenever possible.

As noted in section one of these comments, it is di sappointing 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 substanti ally higher than estimated in the 2014 Inventory and indicates that leaks compose a signif icant 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, su ch 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 whi te 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 Ap proach may be less applicable at some facilities, particularly if correlation equati ons were derived with data from facilities handling different fluids under different condition s. Direct measurements are preferred.

From conversations with representatives from indust ry, with LDAR service firms, and from public discussion during the process to develo p and consider the recently passed oil and gas regulations in Colorado, it is very clear t hat the OGI method is the dominant methodology in use by industry today, and is used s uccessfully at a wide range of facilities, as has been documented by GasSTAR.

• Question 4. As concern has risen over the identified harm to ai r quality from emissions from oil and gas facilities, particularly in the we stern U.S., researchers have responded with a range of measurements and studies of emissio ns 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 tha t the damage from these emissions to climate and air quality is more substantial than in dicated by the inventories.

Numerous studies that will improve our understandin g 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 es timates from the 2014 Inventory, substantial emissions from leaks can be mitigated at reasonable costs49 using LDAR surveys . It is challenging to quantify precise emissions f rom this sector, but it is abundantly clear that they are excessively la rge 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 pla nned to quantify emissions. For example, studies are underway across the industry t o 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 deploy ing the OTM 33A methodology developed by EPA, described in section 2.9 of the w hite 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 emi ssions from oil and gas operations, but will not perfect it. Given the clear data indi cating that leak emissions are substantial and can be controlled at a very reasonable cost, EP A must move forward now to address
the excessive emissions from leaks.

• Question 5. The predominant reason the emissions vary widely fr om facility to facility is the variability in the management approach of th e 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 tha t 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 sou r gas, which creates more corrosive conditions, but so did Plant 4, which had a leak ra te less than one-third of Plant 5 and a leak frequency (fraction of components leaking) abo ut 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 i ncrease. Nevertheless, the overriding factor is clearly the attention of opera tors to reduce leaks.

• Question 6. This paper identified all technologies we know of i n use operationally in the oil and gas sector to identify leaks. As noted abo ve, 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 m ethod 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 2 1, as noted in the leaks white paper. Finally, OGI has advantages in the screening of com ponents that are challenging to access, and for screening surfaces, such as pipe ru ns and tanks, for corrosion leaks.

• Question 8. As noted above, OGI is currently the dominant metho d to identify leaks, to our knowledge, across segments of the natural gas i ndustry. One exception is in distribution, where the vehicle-based sensors discu ssed in section 3.1.4 are in use for monitoring and LDAR, but this is focused on detecti ng leaks from underground pipelines. We are not aware of routine use of other methods, w ith the exception of Method 21 approaches where required (newer gas processing pla nts, principally).

• Question 9. Industry is currently performing LDAR surveys in so me geographic areas at frequencies ranging from annual to monthly. Annual surveys are performed at wells under Alberta regulations, and at new or modified w ell facilities in Pennsylvania and parts of Wyoming, for example. Some companies have instituted annual LDAR with OGI as a voluntary measure. To achieve greater emission s reductions, LDAR is performed as frequently as monthly by some firms in Wyoming. 156

Given the damage caused by air emissions from oil a nd gas facilities, annual LDAR will be too infrequent for many facilities. We support t he tiered approach taken in the recent Colorado regulations, where the frequency of instru mental LDAR was based on the potential leak emissions from the site. However, th e 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 regu lation and may continue indefinitely. Given the large emissions possible fr om single super-emitters, and the very large number of small facilities, this exemption fr om regular LDAR for small facilities is not appropriate.

154 Based on Clean Air Task Force and Environmental De fense 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 f acilities in Wyoming’s Jonah field monthly with

OGI. See ftp://ft.dphe.state.co.us/apc/aqcc/PRESENTATIONS/En cana%20Oil%20&%20Gas%20USA%20%28Enca na%29/Encana%20REB%20Presentation.pdf.51

• Question 10. Ambient / mobile monitoring is an exciting technolo gy that may enable far more frequent monitoring of oil and gas facilities for leaks at reasonable cost. However, the methodologies for these technologies as researc h techniques in the field are still being worked out. Efficacy varies with weather (especiall y wind), site layout, and context. It is not clear how they could be deployed in some locati ons, 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 moni toring could be assured. There would be many ways to avoid identifying actual leak s using these methods.

• Question 11. The Carbon Limits study was able to directly compar e the costs of repairing leaks to the value of the gas conserved b y 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 (quarte rly 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 believ e that it is not necessary under the NSPS program to require that the size of leaks be q uantified (in concentration or volume), since it will often be faster and far simp ler to simply fix them. Records should be kept of the existence of leaks, so that regulato rs can verify compliance and so that facility operators can identify equipment that is l eaking 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 m ust 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 exempt ion from repair requirements due to claims of infeasibility, etc.

• 13. We believe that LDAR technology will advance substa ntially 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 ev en continuous, monitoring of oil and gas facilities for leaks at reasonable cost. R egulations / Regulators should ensure that new technologies can be adopted to improve environm ental performance once they are demonstrated. Even under very optimistic assumptio ns, 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 n ot delay addressing leaks from oil and gas facilities in anticipation of some future t echnology.

VI. Oil Wells

A. Oil Wells Produce Gas, Which Can Be Managed by Capt ure or Combustion



### Oil wells produce oil, natural gas, and formation w ater. The amount of gas that is produced along with the oil is a function of the re servoir type and depth,52



### hydrocarbon type, well age, and the pressure and te mperature changes that occur as the oil and gas reach the surface processing equipm ent. Gas oil ratios will increase over time as wells age. As is true of natural gas g enerally, gas produced in association with oil wells is primarily methane, bu t includes VOCs and some other
chemicals as well.

Oil reservoirs are classified according to fluid ty pe (heavy oil, black oil, and volatile oil), with lighter oils having higher gas-oil ratio s. 157 

### Dry gas wells do not produce associated liquids at the surface (although very fe w 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 stage s of production, including completion, recompletion, and operation of an oil w ell. 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 harmf ul pollution as well as creating potentially explosive vapor levels. To flare, gas i s routed away from the well operations to a combustion device that burns the ga s. Flaring destroys methane, VOC, and many other pollutants, and resolves the ex plosive vapor problem. Flaring also generates air, light, and noise pollution, and creates economic waste by combusting gas that could otherwise be collected an d 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, adopt ing regulations to limit both venting and flaring of gas associated with oil prod uction. For example:

• Colorado Rule 912 prohibits unnecessary or excessiv e venting or flaring from a well. Flaring may be required if necessary t o protect public health, safety and welfare. 158



### • Montana requires VOC vapors (including methane) gre ater than 500 British Thermal Units (BTUs) per cubic foot from wellhead e quipment with the potential to emit 15 tons per year or greater, to b e 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, operationa l upset, or safety situation, and requires the amounts of vented and flared gas to be

tracked. 160



### • Internationally, the Global Gas Flaring Reduction P artnership found that “Many regulatory regimes (e.g., Alberta (Canada) an d the United Kingdom) require each operator to make an economic evaluatio n of all the available associated gas utilization options, and to utilize the gas whenever gas utilization is shown to be economic. Only if all av ailable options can be shown to be sufficiently uneconomic then the gas ma y be flared or, if unavoidable, vented. In Alberta (Canada), uneconomi c 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 r egulations. Other states, such as North Dakota, have not taken sufficient action to a ddress venting and flaring, with

extensive emissions as a result. As the materials d iscussed 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 ind icate 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 t ons. The correct ratio is 1:1.102311. The short ton55



### also included the weighted average from the EDF/Str atus 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 thei r data set, “The net effect of [which] is that the average daily gas production va lues 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 wit h a gas to oil ratio of less than 12,500 scf/barrel. 165 

### In general, wells with higher gas to oil ratios wi ll have higher completion emissions. This is particularly pertinen t 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 NS PS. 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 broa dly, 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 20 12 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 deri ved 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 prod uction 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, Comme nts on “Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990–2012,” available at http://blogs.edf.org/energyexchange/files/2014/03/E DF-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, T itle 16, Chapter 3, Rule § 3.79.

168 Alaska Oil and Gas Conservation Commission, Defini tions, Alaska Admin. Code Title. 20, § 25.990 defines and oil well as well that produces predomin antly oil at a gas-oil ratio of 100,000 scf/bbl or lower, unless on a pool-by-pool basis the commissio n 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 Paragr aph (6) of Subsection G of 19.15.2.7 NMAC. A gas well i s 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 productio n 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 product ion during completion and production then declines; thus, assuming that produ ction 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 e t al. observed production of an average of 1,713 barrels per completion from the fo ur < 12,500 scf/barrel wells in the study. 170 

### At 1,713 barrels per completion, even for a well w ith 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 w ould still expect to 9.2 tons of methane to be produced.

Recompletion emissions will likely vary according t o many factors including reservoir drive mechanism, gas production and decli ne rate, method of recompletion, and others. Very little data exists o n recompletion emissions. Notably, the gas-oil ratio increases as oil wells age and ev olving stimulation methods can result in recompletions that significantly boost pr oduction. We therefore support the use of completion emission factors as an estima te 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 pe r oil well completion and recompletion, respectively. 171 

### The OOOO TSD estimate was therefore more than one

thousand times lower than the lowest estimate summa rized in the whitepapers. The 2014 GHGI emission factor for completions, 0.0141 t ons of methane per event, is also clearly not applicable to hydraulically fractu red wells.

ii. Oil Well Completion Activity Factor



### ERG estimates 5,754 uncontrolled oil well completio ns in 2011. 172 

### EDF estimates hydraulic fracturing completions of 15,753 oil well s in 2012, with 43% of those, 6,773, being uncontrolled. 173 

### The 2011 OOOO TSD estimated hydraulic fracturing o f 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 0.0 07 and 0.001 tons per event).

172 Note that the whitepaper misquotes the ERG activit y factor on page 13, indicating 5274 uncontrolled completions. The correct figure is use d elsewhere, and all calculations appear to reflect

the correct value.

173 http://blogs.edf.org/energyexchange/files/2014/03/E DF-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 co mpletion 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 c ompletion 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, e ven under the whitepaper’s estimate of 0.5% of all oil wells being refractured every year, refracturing represents a significant source of additional emiss ions.

iii. Oil Well Completion Control Technologies



### Completion emissions can be easily abated. As recog nized by the whitepapers, there are two primary control technologies: reduced emiss ion 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, optio n. The 2011 TSD estimated that a reduced emission completion cost $29,713 and achiev ed a 95% control efficiency. 177 

### The minimum, median, and maximum estimates of per-c ompletion emissions we provide above are 7.7, 24, and 213.3 tons of methan e. These respectively entail control costs of $4,061, $1,303, and $146 per ton o f methane, without considering offsetting revenue from captured gas. If captured g as 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 reco gnize that both cost of reduced emission completion equipment and the tonnage of me thane 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, w e 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 addit ional reason why the high perday cases are conservative is that it is unlikely t hat the per-day cost will increase

175 Summarized in http://blogs.edf.org/energyexchange/files/2014/03/E DF-Co-producing-WellsWhitepaper.pdf

at 8

176 Allen et al. observed higher efficiencies for redu ced emission completions--97.8% to 98.8%. Whitepaper at 18.

177 EPA, Oil and Natural Gas Sector: Standards of Perf ormance for Crude Oil and Natural Gas Production, Transmission, and Distribution, Backgro und Technical Support Document for Proposed Standards (April 2012), Pp. 5-2,3. Available at http://www.epa.gov/airquality/oilandgas/pdfs/201204 18tsd.pdf.58



### linearly for longer completion periods. That is, th e longer that wells in a formation take to complete, the greater the likelihood that r educed 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 3,213.6

9

EDF/Stratus Analysis of HDPI (Wattenberg) 8.5 27.2 6,851 251.88 63,631 2,339.3

8

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 3,678.0

9

Allen 179 

### 3 213.3 2,418 11.34 22,458 105.29

Brandt et al. (Eagle Ford) 9 100.2 7,254 72.4 67,37 4 672.4

Brandt et al. (Bakken) 9 34.4 7,254 210.87 67,374 1 958.55

Brandt et al. (Permian) 9 34.3 7,254 211.49 67,374 1964.26

Finally, for one more interpretation of the data, w e 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 technic al support document for the 2012 NSPS, EPA estimated this cost, for oil well complet ions, at $3,523 per well. 181 

### Like

178 EDF/Stratus state that they assumed 7 to 10 days o f completion; we use 8.5 as the average.

179 Average of four oil wells studied. Whitepaper at 1 8

18059



### reduced emission completion, combustion is generall y at least 95% effective. For the range of emission estimates provided above, com bustion provides control costs of $482 to $17 per ton.

iv. Gas Emissions During Oil Well Production

GHGRP data shows that emissions of methane from ven ting 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. The se reported emissions, which are a lower limit of national emissions since smaller p roducers do not report emissions to the GHGRP, are considerably larger than the “str ipper 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 20 12. We agree it may be possible to provide additional estimates of associated gas e missions using gas to oil ratios or other reporting. 183 

### Refining these estimates need not precede regulati on of these emissions, however.

v. Alternatives to Flaring



### For both completion and production emissions, the p referred alternative control for associated gas is capture. Typically, gas that is c aptured during oil well completions and production is transported to processing plants in gathering pipelines. When wells are isolated or other issues limit the capaci ty of gathering systems, other technologies can make it feasible to utilize associ ated 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 ga s 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 technol ogies that can be used at well pads to reduce flaring:

• Compressed natural gas (CNG) trucking – compressi ng associated gas at wellsites and trucking to consumers, processors, gathering sy stems, 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 f rom 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 gene ration for sale to grid are all mature technologies, having been deployed commercia lly 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 techn ologies 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 pip elines is infeasible or EPA otherwise chooses not to require it, flaring remain s a much better alternative than venting from a pollution perspective. A Federal Imp lementation Plan (FIP) for the Fort Berthold Indian Reservation (FBIR) reports tha t 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 we ll completions and recompletions, 185 

### methane abatement costs would be $9 - $16 per ton.

However, we note that flaring is still an inherentl y wasteful process which produces large amounts of carbon dioxide, nitrogen oxides, p articulate matter including black carbon, and other pollutants. Flares' flames can be extinguished by weather or interruptions in flow, and even if auto-igniters ar e required (they are not in many jurisdictions) the emissions from flares that go ou t 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 co nsidered for any well before routine flaring is considered. Further, flaring, wh ich 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