Protecting Human Health and the Environment through

Rigorous, Cost-Effective Emission Standards for the Oil and Gas Industry

By 

Elizabeth Paranhos 

for 

Environmental Defense Fund & Wyoming Outdoor Council 

September 

2010 
TABLE OF CONTENTS 

I. INTRODUCTION............................................................................. 1 

II. BACKGROUND............................................................................... 7 

A. NATIONAL SCOPE OF OIL AND GAS DEVELOPMENT............. 7 

B. OIL AND GAS ACTIVITIES EMIT METHANE THAT CONTRIBUTES 

TO CLIMATE CHANGE AND GROUND-LEVEL OZONE 

POLLUTION....................................................................... 9 

1. Oil and Gas Activities Emit Significant Emissions of Methane 9 

2. Methane Emissions Contribute Directly to Climate Change...... 11

3. Methane Contributes Indirectly to Climate Change by Contributing 

 to Ground-Level Ozone Pollution...................................... 11

4. Methane Reductions Are A “Win/Win”.............................. 12

5. Climate Change is Advancing Rapidly............................... 13

C. OIL AND GAS ACTIVITIES EMIT VOC’S AND NOX THAT 

CONTRIBUTE TO GROUND-LEVEL OZONE POLLUTION......... 18

1. Ozone is Harmful to Human Health and Welfare.................. 18

2. Oil and Gas Activities Emit Significant Amounts of Ozone 

Precursors.................................................................. 19

D. OIL AND GAS ACTIVITIES EMIT AIR TOXIC POLLUTION....... 26

E. COST-EFFECTIVE TECHNOLOGIES ARE AVAILABLE TO REDUCE 

METHANE, VOCS AND AIR TOXICS....................................... 28

1. Use of Low or No-bleed Pneumatic Devices......................... 28

2. Well Completions......................................................... 30

3. Glycol Dehydrators...................................................... 31

4. Crude oil, Condensate and Produced Water Tanks................ 32

5. Production Fugitive Emission......................................... 35

6. Plunger Lifts and “Smart” Well Automation During Well 

Unloading................................................................. 35
7. Installation of BASO Valves on All Gas-Fired Heaters........... 36

8. Leak Detection and Repair at Compressor Stations in the 

Transmission and Storage Sectors.................................... 37

9. Replacing Compressor Rod Packing From Reciprocating 

Compressors............................................................... 37

10. Replacement of Wet Seals with Dry Seals on Wet Seal 

Centrifugal Compressors................................................ 38

III. EPA ADOPTION OF RIGOROUS, WELL-DESIGNED EMISSION STANDARDS 

FOR THE SUITE OF AIR POLLUTANTS DISCHARGED BY THE OIL AND GAS 

SECTOR WILL ACHIEVE VITAL PUBLIC HEALTH AND ENVIRONMENTAL 

PROTECTIONS. .............................................................................. 38

IV. CONCLUSION................................................................................. 44

V. APPENDIX A: Emissions Estimates and Projections: Key oil and gas producing 

basins in the Intermountain West and Gulf region .................................... A 

VI. APPENDIX B: Comparison of oil and gas air regulations federal, Wyoming, 

Colorado, Montana, Utah, and California ................................................ B 

LIST OF TABLES AND FIGURES 

Figure 1: Percent Contribution of Estimated Volatile Organic Compounds from Oil and 

Gas Exploration and Production Sources in the D.J., Piceance, North and South San Juan, 

Uinta and Wind River basins (2006)................................................................ 2 

Table 1: Barnett Shale 2009 HAP Emissions...................................................... 4 

Figure 2: Map of United States Natural Gas Shale Plays....................................... 8 

Figure 3: Percent Contribution of Estimated Volatile Organic Compounds from Oil and 

Gas Exploration and Production Sources in the D.J., Piceance, North and South San Juan, 

Uinta and Wind River basins (2012)............................................................... 21 

Table 2: Barnett Shale Peak Daily Summer Emissions of VOCs and NOx (tons per day) 24 

Figure 4: Oil and Natural Gas Production Sources of Methane Emissions.................. 29 
Protecting Human Health and the Environment through

Rigorous, Cost-Effective Emission Standards for the Oil and Gas Industry

I. INTRODUCTION 

 The production and development of crude oil and natural gas contributes significantly to 

air pollution that endangers human health and the environment. Activities in the natural gas 

exploration and production, storage, processing, transmission and distribution sectors and in the 

oil exploration and production sectors (cumulatively “oil and gas activities”) emit substantial 

amounts of volatile organic compounds (“VOCs”), oxides of nitrogen (“NOx”), methane 

(“CH4”) and hazardous air pollutants (“HAPs”). These airborne contaminants contribute to 

pollution associated with serious human health effects and adverse environmental consequences 

including ground-level ozone or “smog”, particulate pollution, toxic air pollution, climatedisrupting pollution, and the haze that obscures scenic vistas in national parks and wilderness 

areas. 

Emissions from the burgeoning Pinedale-Anticline natural gas field in Wyoming are the 

source of winter-time ozone exceedances which led the Governor of Wyoming to request that 

EPA designate Sublette County and parts of Sweetwater and Lincoln counties as 

“nonattainment” under the 2008 8-hour ozone national ambient air quality standard.1

 Appendix 

A details estimated and projected VOC and NOx emissions from some of the most significant 

sources in key oil and gas basins in the Intermountain West and Gulf region. The following 

chart graphically shows the most significant sources of VOC emissions in six major 

Intermountain West basins including the D.J., Piceance, South San Juan, North San Juan, Uinta 

and Wind River. 

 

1

 Letter to Ms. Carol Rushin, Acting Regional Administrator from Governor Dave Freudenthal (March 12, 2009). 

1 
Figure 1: Percent Contribution of Estimated Volatile Organic Compounds from Oil 

and Gas Exploration and Production Sources in the D.J., Piceance, North 

and South San Juan, Uinta and Wind River basins (2006). 

2006 WRAP VOC Emissions

Dehydrators, 14%

Well completions, 

11%

Well blowdowns, 

8%

Oil Tanks, 7%

Fugitives, 6%

Other, 10%

Pneumatic devices 

& pumps, 18%

Condensate tank, 

26%

 Sources of VOCs and NOx also produce significant amounts of methane which 

contributes to ground-level ozone pollution as well as climate change. 2

 Emissions from oil and 

gas activities account for the third largest source of U.S. methane emissions, contributing at least 

125.5 million metric tons of CO2 equivalent (“MMT CO2e”) in 2008 according to the most 

recent greenhouse gas inventory prepared by the U.S. Environmental Protection Agency.3

 The 

methane emissions are comparable to the greenhouse gas emissions emitted from roughly 33 

 

2

 Arlene M. Fiore et al., Characterizing the Tropospheric Ozone Response to Methane Emission Controls and the 

Benefits to Climate and Air Quality, Journal of Geophysical Research Vol. 113, at 1 (April 30 2008) (stating that 

“[I]n the presence of nitrogen oxides (NOx), tropospheric CH4 oxidation leads to the formation of O3); Aaron S. 

Katzenstein et al., Extensive Regional Atmospheric Hydrocarbon Pollution in the Southwestern United States, 21 

PNAS Vol. 100, 11975 (“The release of hydrocarbons into the atmosphere contributed to the photochemical ozone 

(O3) production, with related adverse health effects, reduction in plant growth, and climate change... Ch4 is 

by far the most abundant hydrocarbon in the atmosphere.”) 

3

 EPA 2010 Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2008 (March 2010), Table ES-2, 

http://www.epa.gov/climatechange/emissions/usinventoryreport.html. 

2 
coal-fired power plants.4

 The actual emissions however, are likely much larger as emissions 

underreporting is well documented by EPA. Specifically, during the development of EPA’s 

mandatory reporting of greenhouse gas rules for petroleum and natural gas systems, the Agency 

identified concerns with emissions accuracy for the following sources: (1) well venting for 

liquids unloading; (2) gas well venting during well completions; (3) gas well venting during well 

workovers; (4) crude oil and condensate storage tanks; (5) centrifugal compressor wet seal 

degassing venting; and (6) flaring. According to EPA, the emissions estimates for these sources 

“do not correctly reflect the operational practices of today” and, in fact, EPA believes “that 

emissions from some sources may be much higher than currently reported in the U.S. GHG 

Inventory.”5

 

Various sources including wells, compressor engines, glycol dehydrators and condensate 

tanks located at oil and gas exploration and production sites emit HAPs including benzene, a 

known carcinogen. For example, a recent inventory of HAP, VOC, NOx and greenhouse gas 

emissions in the Barnett Shale in Texas estimated the following HAP emissions in tons per day 

in 20096: 

 

4

 Calculated using EPA’s GHG Equivalencies Calculator, http://www.epa.gov/RDEE/energyresources/calculator.html#results. 

5

 EPA Technical Support Document for the proposed GHG Mandatory Reporting Rule, p. 23; See also EPA 

Mandatory Reporting of Greenhouse Gases: Petroleum and Natural Gas Systems; Proposed Rule, 75 Fed. Reg. 

18608, 18621 (April 12, 2010). 

6

 Al Armendariz, Ph.D., Emissions from Natural Gas Production in the Barnett Shale Area and Opportunities for 

Cost-Effective Improvements, 24 (Jan. 26, 2009). 

3 
Table 1: Barnett Shale 2009 HAP Emissions 

Source Tons per 

Day HAPs 

Compressor engine exhaust 3.6 

Condensate and oil tanks .60 

Production fugitives .62 

Well drilling and completions .49 

Gas processing .37 

Transmission fugitives* .67 

*Transmission fugitives include emissions produced by the movement of natural gas from wells 

to processing plants and from processing plants to compressor stations. 

EPA has established a limited number of emission standards under sections 111 and 112 

of the Clean Air Act that reduce a portion of the air pollution arising from oil and gas activities; 

these include emission standards that have not been updated in years to reflect modern pollution 

control technologies.7

 Further, a large number of sources and resulting air pollutants within the 

oil and gas industry remain uncontrolled at the federal level. A handful of western states, 

however, have implemented clean air policies to reduce air pollution from some of the most 

significant emission sources in the oil and gas industry. A comparison of the current federal and 

state regulatory framework as it applies to oil and gas activities is attached as Appendix B. 

 Wide-scale implementation of the policies currently in place at the state level has the 

 

7 “

Equipment Leaks of VOCs From Onshore Natural Gas Processing Plants”, 50 Fed. Reg. 26122 (June 24, 1985), 

“Onshore Natural Gas Processing SO2 Emissions”, 50 Fed. Reg. 40158; “Stationary Spark Ignition Internal 

Combustion Engines”, 73 Fed. Reg. 3568 (Jan. 18, 2008); “National Emission Standards for Hazardous Air 

Pollutants: Oil and Natural Gas Production and Natural Gas Transmission and Storage”, 64 Fed. Reg. 32610 (June 

17, 1999); “National Emission Standards for Hazardous Air Pollutants for Oil and Natural Gas Production 

Facilities”, 72 Fed. Reg. 26 (Jan. 3, 2007); “National Emission Standards for Hazardous Air Pollutants for Oil and 

Natural Gas Production Facilities, Stationary Reciprocating Internal Combustion Engines”, 73 Fed. Reg. 3568 (Jan. 

18, 2008); “National Emission Standards for Hazardous Air Pollutants for Oil and Natural Gas Production Facilities 

for Reciprocating Internal Combustion Engines”, 75 Fed. Reg. 9648 (March 3, 2010). 

4 
potential to produce meaningful air and public health benefits. Indeed, even greater clean air 

benefits can be achieved through the implementation of additional technologies and practices 

developed as part of EPA’s Natural Gas STAR program. In many instances, clean air measures 

involve best management practices and technologies that result in minimizing the volumes of 

natural gas lost, leaked or vented during the development and production process, resulting in 

health and environmental protections as well as cost savings from improved production 

efficiency. EPA estimates that as much as 300 billion cubic feet of natural gas (methane) is lost 

to the atmosphere in the United States each year. This equals over $1 billion in lost profits, 

assuming the relatively low average gas prices in April 2009.8

 Broad adoption of cost-effective 

methane reduction technologies has the potential to reduce current estimated methane emissions 

from oil and gas activities by approximately 41 MMT CO2e.9

 While companies must make an 

initial upfront investment to install methane capture or reduction technologies, the return on 

investment in many cases is quite short—sometimes months—and almost always within a single 

year. In 2008 companies that employed methane reduction technologies reported savings of 

more than $802 million in additional natural gas sales.10 

 

8

 Nathanial Gronewold, Greenwire, “Industry Spotlighting Efforts to Curb Fugitive Emissions”, May 19, 2009. 9

 U.S. EPA, Natural Gas STAR Program, available at http://www.epa.gov/gasstar/. Based on a thirty percent 

reduction from 2008 emission levels. 

10 EPA Natural Gas STAR, Accomplishments, available at 

http://www.epa.gov/gasstar/accomplishments/index.html, last visited December 14, 2009. 

5 
A recent study estimated methane losses during well 

completions, production, processing and transmission in 

the Barnett Shale alone were 13.1 Bcf/yr, or about 1 

percent of total gas production. At $3.50/Mcf, a low 

price that is conservative in estimating economic impacts; 

this amounts to $46 million per year in lost revenues for 

producers. 

Source: Al Armendariz, Ph.D., Emissions from Natural Gas Production in the 

Barnett Shale Area and Opportunities for Cost-Effective Improvements, 6 (Jan. 26, 

2009). 

This analysis examines the immense opportunity that greater implementation of costeffective technologies and best management practices provides to achieve significant air 

pollution reductions to protect human health and the environment. EPA has committed to 

review, and if appropriate revise, the New Source Performance Standards (“NSPS”) specific to 

natural gas plants and National Emission Standards for Hazardous Air Pollutants (“NESHAP”) 

for process vents on glycol dehydrators, storage vessels with the potential for flash emissions, 

and certain equipment located at gas processing plants in the Crude Oil and Natural Gas 

Production, Transmission and Storage major source categories.11 As part of that process we urge 

EPA to broaden the scope of federal clean air requirements to apply to a greater number of 

emissions sources and air pollutants within the oil and gas industry to ensure rigorous protections 

for human health and the environment under its existing authority in sections 111 and 112 of the 

Clean Air Act. To that end, we include here specific recommendations for the reduction of 

VOCs, methane and air toxics from discrete emission points in the oil and natural gas 

exploration, production, processing, storage and transmission sectors based on policies instituted 

 

11 Consent Decree, Wildearth Guardians et al. v. Lisa P. Jackson, 1:09-cv-00089 (CKK) (Feb 4, 2010). 

6 
or proposed at the state level or established technologies developed by industry in conjunction 

with EPA’s Natural Gas STAR program.12 

II. BACKGROUND 

A. NATIONAL SCOPE OF OIL AND GAS DEVELOPMENT 

Until recently, oil and gas activities have concentrated in certain pockets of the U.S. such 

as the Rocky Mountain states, Alaska and Texas. This is quickly changing, however, as 

technological developments such as horizontal drilling and hydraulic fracturing have made 

feasible the extraction of previously untapped unconventional resources located in difficult to 

reach geologic formations such as shales. As the following map shows, gas shales are located 

throughout the United States including in and around densely populated major metropolitan 

areas, important watersheds and environmentally sensitive areas. 

 

12 We do not include recommendations specific to NOx reductions here because EPA has recently revised the 

standards applicable to engines used in the oil and gas industry. Nevertheless, we include certain oil and gas NOx 

production emission estimates to provide a comprehensive picture of the significant contribution oil and gas 

activities make to air pollution. 

7 
Figure 2: Map of United States Natural Gas Shale Plays 

For example, the Barnett Shale in Texas lies just outside the Dallas Fort-Worth 

metropolitan area. The Barnett Shale has an area of approximately 5,000 square miles with total 

technically recoverable resources estimated at 44.8 trillion cubic feet (“Tcf”). Natural gas 

production in the Barnett has increased rapidly since 1999, and as of May 10, 2010, 13,902 oil 

and gas wells had been installed and another 3,333 wells were pending.13 Gas production in 

2009 was nearly 1.8 Tcf. 

The Haynesville shale, located east of the Barnett, has total technically recoverable 

resources estimated at 251 Tcf in an area that encompasses 9,000 square miles.14 Future 

development activity in the Haynesville could equal that in the Barnett if well productivity and 

 

13 Railroad Commission of Texas, “Barnett Shale Information”, 

http://www.rrc.state.tx.us/data/fielddata/barnettshale.pdf. 14 ENVIRON, Draft Report, Development of Emissions Inventories for Natural Gas Exploration and Production 

Activity in the Haynesville Shale, 15 (August 31, 2009). 

8 
well economics prove to be comparable.15 If so, there could be 

over 10,000 active wells in the Haynesville by 2020.16 

The Fayetteville Shale, located in the Arkoma Basin of 

Northern Arkansas and eastern Oklahoma, is equal to the 

Haynesville in area. As of April 2009 there were 1,000 active 

wells producing 88.85 billion cubic feet (“Bcf”) of gas. It is 

estimated that there are 41.4 Tcf of technically recoverable 

resources in the Fayetteville.17

The Marcellus Shale is by far the largest of the domestic 

shale plays, spanning 95,000 square miles across six northeastern 

states. One estimate of the gas-in-place is 1,500 Tcf. Total 

technically recoverable resources are estimated to equal 

approximately 262 Tcf, but it is likely that this estimate will get 

revised upward as production in the shale increases. 

B. OIL AND GAS ACTIVITIES EMIT 

METHANE THAT CONTRIBUTES TO 

CLIMATE CHANGE AND GROUNDLEVEL OZONE POLLUTION 

1. Oil and Gas Activities Emit Significant 

 Emissions of Methane 

Oil and gas development is responsible 

for a host of other non-air quality 

related impacts. These impacts 

include: 

• surface disturbances in the 

form of additional roads, 

vehicles, heavy machinery 

and drilling waste that 

interfere with wildlife habitat 

and migration routes and 

impair recreational use and 

enjoyment of some of the 

nation’s most scenic and wild 

places; 

• significant water use which 

can strain limited water 

resources in arid or highlyallocated areas; 

• pollution of water resources 

including drinking water. 

National attention has recently focused 

on the highly controversial practice of 

hydraulic fracturing or “fracking.” 

Fracking involves injecting chemicals 

and water into natural gas shale 

formations in order to fracture the shale 

and release gas trapped in small 

fissures. In addition, fracking exposes 

underground aquifers and nearby wells 

to potential contamination from the 

numerous unknown chemicals used in 

the process. No one knows precisely 

which chemicals are used in fracking 

since the oil and gas industry obtained 

an exemption from the requirements of 

the Safe Drinking Water Act in 2005 

that would have required disclosure of 

the constituents used in hydraulic 

fracturing. The seriousness of the full 

suite of impacts associated with oil and 

gas activities merits close attention by 

national policy-makers including 

restoring the public’s right-to-know 

what chemicals are used in fracking. 

Emissions from oil and gas activities contribute significantly to atmospheric levels of 

methane. Current estimates, which are acknowledged to seriously under-estimate actual 

emissions, indicate that national oil and gas activities produced 125.5 MMT CO2e in 2008. 

Rough emissions estimates and projections prepared for key gas and oil producing states reflect 

 

15 Id. at 15. 16 Id. at 18. 17 U.S. DOE, Modern Shale Gas, Development in the United States, A Primer, 19 (April 2009). 

9 
this sector’s significant contribution to U.S. methane emissions. These inventories, prepared by 

the Center for Climate Studies (“CCS”), also likely underestimate emissions as they are also 

based on aggregate industry-average emission factors. Specific information related to industry 

activity such as the number of wells, gas processing plants and miles of pipeline is based on data 

obtained from the U.S. Energy Information Administration and American Gas Association’s 

annual publication, Gas Facts.18 

According to the CCS inventory for the state of Colorado, methane emissions from oil 

and gas activities accounted for 4.6% of Colorado’s total GHG emissions in 2000 and are 

expected to make up 5.1% by 2020.19 In Wyoming, oil and gas methane emissions are projected 

to total 6.3 MMT CO2e in 2020 or 9.7% of the state’s greenhouse gas emissions. This represents 

over a 50% increase from 2000 emissions of 2.8 MMT CO2e.20 In Montana natural gas 

production is projected to increase 74% from 2010 to 2020 assuming development of the state’s 

extensive untapped Bakken gas shale and coal-bed methane reserves.21 This would result in 

methane emissions from oil and gas activities more than doubling from 3.3% of the state’s total 

greenhouse gas emissions in 2000 to 7.2% in 2020. In Dallas Fort-Worth, Texas, total 

greenhouse gas emissions in 2009 from Barnett Shale activities, which include fugitive methane 

and combustion CO2 emissions, were anticipated to equal 33,000 tons per day of CO2 equivalent, 

 

18 CCS emissions estimates are based on “multiplying emissions-related activity levels (e.g.: miles of pipeline, 

number of compressor stations) by aggregate industry-average emission factors.” Specifically, methods for 

estimating methane emissions were based on EPA’s State Greenhouse Gas Inventory Tool, with reference to the 

Emissions Inventory Improvement Project. Projections are based on estimated consumption and projection levels. 

For example, Colorado projections assumed that natural gas production continued at a rate of 7.3% annually until 

2009 and then followed US DOE regional projections until 2020 which average 0.8% annual growth. These 

inventories necessarily contain a number of uncertainties and therefore provide only approximations of emissions. 

19 Center for Climate Studies, Colorado GHG Inventory and Reference Case Projections, 1990-2020 (October 2007), 

Appendix E. 

20 Center for Climate Studies, Wyoming GHG Inventory and Reference Case Projections, 1990-2020 (Spring 2007), 

E-7. 

21 Center for Climate Studies, Montana GHG Inventory and Reference Case Projections, 1990-2020 (Spring 2007), 

47. According to the U.S.G.S. the Bakken shale has 3.65 billion barrels of oil, 1.85 Tcf of natural gas and 148 

million bbls of natural gas liquids in technically recoverable resources. Modern Gas Shale, A Primer, supra note 17, 

at 13. 

10 
approximately equal to the expected greenhouse gas emissions from two 750 MW coal-fired 

power plants.22 

Continued development of U.S. shales and other nonconventional resources is likely to 

lead to an increase in the actual volume and relative contribution of methane emissions from oil 

and gas activities. According to the U.S. Department of Energy, shale and other unconventional 

natural gas development will continue to rise through 2030.23 

2. Methane Emissions Contribute Directly to Climate Change 

Methane’s direct contribution to climate change -- both in terms of its potency and its 

growing presence in the atmosphere -- underscore the importance of smart policy action to 

secure immediate emission reductions from oil and gas activities. Methane is an extremely 

potent greenhouse gas. Over a 100-year period, methane has a warming potential 21 times that 

of carbon dioxide. However, when viewed over the short-term (20 years), methane is 72 times 

more effective at trapping heat than the same molecule of CO2.

24 In addition, methane emissions 

are on the rise, having increased by 150% in the last two-hundred and fifty years. As a result of 

these increases we are currently experiencing the highest levels of atmospheric methane in the 

past 800,000 years.25 

 

3. Methane Contributes Indirectly to Climate Change by Contributing to 

Ground-Level Ozone Pollution 

Methane also contributes indirectly to climate change by contributing to the production of 

ground-level ozone.26 As explained in more detail below in section C.1., ground-level ozone is 

associated with a host of serious public health and environmental problems, including respiratory 

 

22 Armendariz, supra note 6, at 1. 23 U.S. DOE, Annual Energy Outlook 2010, Early Release Overview, 9 (December 2009). 

24 IPCC, 2007: Summary for Policymakers at 7.7, Climate Change 2007: The Physical Science Basis. Contribution 

of Working Group I to the Fourth Assessment Report of the Intergovernmental Panel on Climate Change (2007). 25 Nature, Paleoclimate: Windows on the Climate, available at 

http://www.nature.com/nature/journal/v453/n7193/full/453291a.html. 26 Fiore et al., and Katzenstein et al., supra note 2. 

11 
disease, premature death, and climate change. After carbon dioxide and methane, ground-level 

ozone is the third-largest contributor to global warming.27 Like methane, ozone levels are rising, 

having increased by 36% since pre-industrial times, much of which can be attributed to methane 

emissions.28 

4. Methane Reductions Are A “Win/Win” 

Reducing atmospheric levels of methane accomplishes the dual goal of combating 

climate change in the near term and reducing ozone pollution. As documented in an extensive 

scientific report by the U.S. Climate Change Science Program, methane reductions improve air 

quality by decreasing atmospheric levels of ozone: “[D]ecreases in methane emissions lead to 

reduced levels of lower atmospheric ozone, thereby improving air quality.”29 Indeed, one study 

on the relationship of methane emissions to ground-level ozone concludes that “tropospheric O3

[ozone] responds approximately linearly to changes in CH4 [methane] emissions over a range of 

anthropogenic emissions....”30 Another found that reducing global anthropogenic methane 

emissions by 20% beginning in 2010 would result in a decrease in maximum daily surface ozone 

concentrations by 1 part per billion (ppb), over an 8-hour average.31 The study predicted, based 

on epidemiological studies, this reduction in maximum ozone concentrations would prevent 

 

27 P. Forster, et al., 2007: Changes in Atmospheric Constituents and in Radiative Forcing. In: Climate Change 

2007: The Physical Science Basis. Contribution of Working Group I to the Fourth Assessment Report of the 

Intergovernmental Panel on Climate Change [Solomon, S., D. Qin, M. Manning, Z. Chen, M. Marquis, K.B. 

Averyt, M.Tignor and H.L. Miller (eds.)]. Cambridge University Press, Cambridge, United Kingdom and New 

York, NY, USA at 152, available at http://ipcc-wg1.ucar.edu/wg1/Report/AR4WG1_Print_Ch02.pdf. 28 U.S. EPA, TECHNICAL SUPPORT DOCUMENT FOR ENDANGERMENT ANALYSIS FOR GREENHOUSE 

GAS EMISSIONS UNDER THE CLEAN AIR ACT, Sixth Order Draft, 14 (June 21, 2008); Kirk R. Smith, et al, 

Health and Climate Change, PUBLIC HEALTH BENEFITS OF STRATEGIES TO REDUCE GREENHOUSE 

GAS EMISSIONS: HEALTH IMPLICATIONS OF SHORT-LIVED GREENHOUSE POLLUTANTS, 4 (Nov. 25, 

2009). In addition to methane, NOx emissions from fossil-fuel burning is a primary contributor to rising 

atmospheric ozone levels. 

29 Hiram Levy II et al., U.S. CLIMATE CHANGE SCIENCE PROGRAM SYNTHESIS AND ASSESSMENT 

PRODUCT 3.2, CLIMATE PROJECTIONS BASED ON EMISSIONS SCENARIOS FOR LONG-LIVED AND 

SHORT-LIVED RADIATIVELY ACTIVE GASES AND AEROSOLS 64 (Sept. 2008). 

30 Fiore et al., supra note 2, at 1. 31 West J. Jason et al., Global Health Benefits of Mitigating Ozone Pollution with Methane Emissions Controls, 

PROCEEDINGS OF THE NATIONAL ACADEMY OF SCIENCES, Vol. 103, at 3988 (Mar. 16, 2006). 

12 
about 30,000 premature deaths from all causes in 2030 and approximately 370,000 premature 

deaths between 2010 and 2030.32 

In addition, reducing methane emissions is a highly effective way to reduce levels of 

atmospheric greenhouse gases over the next few decades. Both methane and ozone are shortlived greenhouse gases; methane emissions last ten to twelve years in the atmosphere while 

ozone lasts only weeks to months. For these reasons, a number of prominent health and 

scientific experts have delineated a two-pronged climate approach that calls for reductions of 

methane as well as CO2. According to such experts, “[A]ggressive policies directed towards 

carbon dioxide reduction, although necessary for the long term, are by themselves insufficient to 

reduce the rate of warming in the next few decades because of the long atmospheric lifetime of 

this gas. Thus, governments will need to reduce warming from short-lived greenhouse gas 

pollutants when considering climate change mitigation policies.” 33

5. Climate Change is Advancing Rapidly 

The impacts caused by unprecedented atmospheric levels of greenhouse gases are 

happening at an alarmingly rapid pace. A recent report by the U.S. Global Change Research 

Program demonstrates that impacts already are occurring today across the United States, 

threatening human health, our natural resources and important economic industries. These, and 

future projected impacts, include: 

• Impacts to Human Health: All Americans face increased health threats due to 

climate change. Heat waves, which are among the top causes of deaths due to 

 

32 Id. at 3992. 33 Kirk R. Smith, et al, supra note 28, at 4. See also Hiram Levy II et al., supra note 29, at 64 (finding that “both 

[the] direct methane and indirect ozone decreases lead to reduced global warming.”) and Stacy C. Jackson, “Parallel 

Pursuit of Near-Term and Long-Term Climate Mitigation”, 326 SCIENCE 526 (Oct. 23, 2009). 

13 
natural hazards, are likely to increase in “frequency, severity, and duration.” 34 

The number of heat-wave related deaths in Chicago is projected to double or 

quadruple by 2050, and increase by two, three, five or seven times in Los 

Angeles, depending on various emissions scenarios.35 Importantly, the number of 

deaths likely to occur due to rising temperatures is projected to outweigh any 

reduction in cold-weather related deaths due to warming temperatures.36 

Currently, 158 million people live in areas with air quality that fails to meet 

national health-based standards.37 This number is expected to rise as warmer 

temperatures are associated with increased air pollution, especially ozone. Days 

when ozone levels have reached unhealthy levels for all people are expected to 

increase by 68% by mid-century in eastern cities under constant emissions.38 

EPA recently concluded that “climate change has the potential to produce 

significant increases in near-surface O3 concentrations throughout the United 

States.”39 Increased wildfires will also contribute to deteriorating air quality, 

especially in the West.40 Severe precipitation events are likely to strain urban 

sewer and stormwater systems beyond their capacities, threatening drinking water 

and recreational beach goers.41 In Chicago, the frequency of such events is likely 

 

34 U.S. Global Change Research Program, CLIMATE CHANGE IMPACTS OF THE UNITED STATES, THE 

POTENTIAL CONSEQUENCES OF CLIMATE VARIABILITY AND CHANGE, 91 (2009). 

http://downloads.globalchange.gov/usimpacts/pdfs/climate-impacts-report.pdf. 35 Id. 36 Id. 37 Id. at 92. 38 Id. at 94. 

39 U.S. EPA, ASSESSMENT OF THE IMPACTS OF GLOBAL CHANGE ON REGIONAL U.S AIR QUALITY: 

A SYNTHESIS OF CLIMATE CHANGE IMPACTS ON GROUND LEVEL OZONE, xxiii (April 2009). 40 U.S. Global Change Research Program,, supra note 34, at 95. 41 Id. at 94. 

14 
to increase by 50 to 120% by the end of the century.42 Diseases carried by food, 

water and animals such as West Nile, Giardia, Rocky Mountain spotted fever and 

Salmonella are likely to increase due to warmer temperatures and floods.43 

• Impacts to Coastal Areas: Sea levels are expected to rise three to four feet this 

century, increasing the risk of flooding in portions of Boston, New York and New 

Orleans.44 Non-native species are already threatening marine ecosystems such as 

the San Francisco bay fishery that provide important economic benefits to the Bay 

Area region.45 Marine species and coral reefs, already under threat from pollution 

and over-fishing, are likely to suffer greater losses from the weakening effects of 

ocean acidification and warmer temperatures. Long-standing economic 

foundations of many local communities, such as the Maine lobster and Northeast 

Cod, are likely to experience significant setbacks as these species shift north in 

search of cooler waters. 

• Impacts to the Northeast: Inhabitants of the Northeast are likely to experience 

greater and longer heat-waves, deteriorating air quality, increased droughts, and a 

decline in traditional agricultural economies. The residents of Boston, New York, 

Philadelphia and other eastern sea-board cities are likely to experience 

approximately 30 days or more of temperatures over 100 degrees Fahrenheit 

during summertime under a higher emissions forecast.46 At the same time, air 

quality in these cities is expected to deteriorate, aggravating conditions that can 

lead to cardiac and pulmonary diseases and disorders. Droughts lasting one to 

 

42 Id. at 95. 43 Id. at 96 44 Id. at 150. 45 Id. at 151. 46 Id. at 107. 

15 
three months are projected to occur in the Catskills and Adirondacks.47 

Vermont’s maple syrup and the Northeast dairy industry are projected to 

experience severe economic declines as maple trees shift north and cattle contend 

with warmer temperatures that decrease productivity and fertility.48 

• Impacts to the Southwest and Western United States: The Southwest and Western 

United States are already experiencing an increase in droughts, forest fires, pest 

outbreaks, and declining air quality. Reduced snowpack, earlier snowmelt and 

decreased summer flows are placing additional strains on the region’s overallocated water resources. Large swaths of native forest are being lost to the pine 

and spruce beetles whose populations have thrived during the unusually warmer 

winters of the last decades. Over 1.5 million acres of lodgepole pine in Colorado, 

and significant numbers of pinion pine in the Southwest have been lost to beetle 

and other insect outbreaks caused by warmer weather and droughts.49 Warmer 

temperatures, in combination with land-use patterns, have led to more favorable 

conditions for fires which are projected to increase and spread more rapidly. 

Important winter snow industries are likely to experience shorter seasons in 

higher elevation areas, while resorts in lower elevations may cease to exist 

entirely. Cultivation of certain crops, like California’s apricots, almonds, walnuts 

and olives that require a certain number of cold days and nights, will become 

increasingly difficult and/or expensive.50 

 

47 Id. 48 Id. at 108. 

49 Id. at 82. 50 Id. at 134. 

16 
• Impacts to Alaska. Alaska has warmed at more than twice the rate of the rest of 

the United States and temperatures are projected to continue to increase by 

anywhere between 5 and 13 degrees Fahrenheit by the end of the century. Sea ice 

and permafrost are disappearing, causing species displacement and significant 

economic harms. Key fisheries, such as the pollack, halibut and snow crab, have 

already begun migrating further from existing ports and processing infrastructure 

and are expected to continue to do so as the location, timing and composition of 

their food source changes due to retreating ice.51 It is estimated that the repairs to 

crumbling infrasture due to permafrost melt will cost between $3.6 and $6.1 

billion by 2030.52 Lakes in the National Wildlife Refuges that provide important 

habitat and native hunting grounds are disappearing.53 Alaska has lost over 2.5 

million acres of white spruce to the spruce beetle. Some of the worst wild fires on 

record occurred in 2004 and 2005, burning large swatches of the state and causing 

significant degradation to the air quality in the city of Fairbanks.54 

• Impacts to Ecosystems. Natural ecosystems are most vulnerable to climate 

change impacts as their ability to adapt to the rapid pace of warming is limited. 

Infectious diseases, wildfires, pest outbreaks and invasive species are likely to 

increase with climate change. Many plants and animals have begun their 

migrations north and to higher elevations but it is unlikely that most species will 

be able to adapt quickly enough. Northwest salmon and wild trout are likely to 

 

51 Id. at 144. 52 Id. at 142. 53 Id. at 141. 54 Id. 

17 
decline by anywhere from 40 to 90 percent in certain places.55 For certain 

species already living at the boundary of their habitat, such as the pika, grizzly 

bear and bighorn sheep, the invasion by low-land species is likely to cause 

significant resource conflict.56 Many species will be lost, as is already starting to 

be seen in parts of the Arctic and Alaska. It is estimated that the Alaskan polar 

bear population will be gone within 75 years along with two-thirds of the world’s 

polar bear population by 2050.57 

C. OIL AND GAS ACTIVITIES EMIT VOC’S AND NOX THAT 

CONTRIBUTE TO GROUND-LEVEL OZONE POLLUTION. 

1. Ozone is Harmful to Human Health and Welfare 

Oil and gas activities emit significant amounts of VOCs, NOx and methane that 

contribute to local, regional and global background ground-level ozone pollution. Ozone has 

been linked with a number of serious public health impacts. Adverse effects that have been 

observed in controlled exposure and field/panel studies include respiratory effects (e.g., reduced 

pulmonary function), among healthy individuals, as well as children and adults with asthma, 

exposed acutely for 1-8 hours to the current health-based standard while physically active.58 

Sensitive individuals are affected at concentrations substantially below the current standard.59 A 

number of studies have confirmed that ozone exposure is associated with premature mortality.60 

Higher temperatures are likely to exacerbate ozone air pollution and related health problems.61 

 

55 Id. at 87. 56 Id. at 86. 57 Id. at 85. 58 U.S. EPA, National Center for Environmental Assessment-RTP Office, Office of Research and Development, 

2006 Air Quality Criteria for Ozone and Related Photochemical Oxidants, February 2006. 

59 Id. 60 Bell ML, Peng RD, Dominici F. 2006, The Exposure-response Curve for Ozone and Risk of Mortality and 

the Adequacy of Current Ozone Regulations, 114 Environ. Health Perspect., 532-536; Bell ML, McDermott A, 

Zeger SL, Samet JM, Dominici F., 2004. Ozone and Short-term Mortality in 95 U.S. Urban Communities, 1987-

18 
Ozone pollution also threatens the ecological health of natural resources such as National 

Parks, forests and important agricultural commodities. EPA recently proposed a distinct ozone 

standard aimed at reducing the harmful welfare effects caused by ozone’s deleterious impacts on 

vegetation, forests and agricultural crops.62 According to EPA, impacts associated with ozone 

pollution include: reduced root and tree growth; increased rates of senescence; decreased plant 

vitality and a greater susceptibility to disease and infestation; and visible leaf damage.63 Loss of 

forests may also exacerbate climate change because trees act as natural carbon sinks, absorbing 

carbon dioxide emissions through the process of photosynthesis, thereby reducing the amount of 

greenhouse gases in the atmosphere.64 

Currently, two-thirds of our National Parks suffer from ozone pollution that can harm the 

park’s natural resources.65 Ozone levels are significant or increasing in a number of parks and in 

remote areas near significant oil and gas activity such as Rocky Mountain National Park, Mesa 

Verde, Glacier and in rural parts of Wyoming, Colorado and New Mexico.66 

2. Oil and Gas Activities Emit Significant Amounts of Ozone 

Precursors 

Inventories prepared in key oil and gas basins across the Intermountain West and Gulf 

region demonstrate that oil and gas activities are a significant source of tropospheric ozone 

pollution. See Appendix A for a summary of VOC and NOx emissions from six basins in the 

 2000, JAMA, 292(19): 2372-2378; Levy JI, Chemerynski SM, Sarnat JA. 2005, Ozone Exposure and Mortality: An 

Empiric Bayes Metaregression Analysis, Epidemiol, 16(4):458-468. 61 Kirk R. Smith, et al., supra note 28, at 2. 62 U.S. EPA, Proposed Rule, National Ambient Air Quality Standards for Ozone, 75 Fed. Reg. 2938 (January 19, 

2010). 

63 Id. 64 Id.; See also Zack Parsons and Steven Arnold, Colorado Department of Health and Environment, Ozone 

Transport in the West: An Exploratory Study (July 2004), available at 

http://www.cdphe.state.co.us/ap/down/ozonetransport.pdf at 9. 65 National Park Service, AIR QUALITY IN NATIONAL PARKS, 2008 ANNUAL PERFORMANCE AND 

PROGRESS REPORT, 1 (Sept. 2009). 

66 Id. at 12; see also Colorado OGCC Cost-benefit and regulatory analysis for Rule 805, at 3. 

19 
west and the Haynesville Shale in Texas and Louisiana. Information on emissions from the 

Barnett Shale is provided separately below. Emissions information for the Marcellus Shale is 

not yet available. Such information is urgently needed however as development of this massive 

shale is marching forward rapidly. 

The Western Regional Air Partnership (“WRAP”), in conjunction with the Independent 

Petroleum Association of Mountain States, conducted an updated inventory of oil and gas 

exploration and production NOx and VOC emissions across six basins in Colorado, Wyoming, 

Utah and New Mexico.67 The inventory estimated 2006 baseline emissions using information 

related to well activity and production data obtained from participating oil and gas companies 

operating in each basin and state regulatory databases. The inventories project 2010 or 2012 

emissions based on anticipated rates of production activity provided by participating oil and gas 

companies and historical production trends. Projected emissions take into consideration federal 

and state “on-the-books” regulations that apply to oil and gas exploration and production 

activities.68 These inventories provide information on basin-wide exploration and production 

NOx and VOC emissions as well as emissions from specific oil and gas sources. Although 

limited in geographic scope, the WRAP data is an informative tool for policy decisions as it 

helps identify significant sources of ozone precursors in the oil and gas exploration and 

production sectors. 

 

67 Initially the project was intended to encompass all oil and gas basins in Utah, Montana, Wyoming, Colorado, New 

Mexico and North Dakota. To date, inventories for six basins have been completed. VOC emissions from the North 

San Juan Basin in Colorado are not included here as they are considerably smaller due to the small amount of 

drilling still occurring, and the low VOC content of produced gas from the predominant resource in the basin, coalbed methane. For more information see ENVIRON, Development of Baseline 2006 and Midterm 2012 Emissions 

from Oil and Gas Activity in the North San Juan Basin, 21 (Sept. 1, 2009). All WRAP inventories cited herein are 

available at http://www.wrapair.org/forums/ogwg/PhaseIII_Inventory.html. 68 For example, projected emissions for CO’s D.J. basin take into consideration NSPSs for all new nonroad engines, 

nonroad diesel fuel sulfur standards and tier 1-4 standards for drill rigs as well as CO’s rules for glycol dehydrators 

and condensate tanks contained in Regulation 7. ENVIRON, Development of 2010 Oil and Gas Emissions 

Projections for the Denver-Julesburg Basin, 17 (April 30, 2008). 

20 
As graphically depicted in the pie chart below, the data from the WRAP inventories 

indicate that glycol dehydrators, condensate tanks and pneumatic devices account for the 

majority of projected VOCs at exploration and production sites. Well completions are a 

significant source of 2006 emissions (11%) but their share of total VOC emissions decreases by 

2012. Engines used to power compressors are the primary source of NOx. Emissions from drill 

rigs are also a significant source of NOX emissions during oil and gas field development, with 

environmental impact statements prepared by the Bureau of Land Management for gas fields in 

Wyoming such as the Pinedale Anticline field showing NOx emissions from drill rigs are the 

largest source of NOx emissions. 

Figure 3: Percent Contribution of Estimated Volatile Organic Compounds from 

Oil and Gas Exploration and Production Sources in the D.J., 

Piceance, North and South San Juan, Uinta and Wind River basins 

(2012). 

2012 WRAP VOC Emissions

Dehydrators, 15%

Well completions, 

5%

Well blowdowns, 

6%

Oil Tanks, 8%

Fugitives, 7%

Other, 10%

Pneumatic devices 

& pumps, 23%

Condensate tank , 

26%

21 
For example, in the Piceance basin in Colorado, venting from initial well completions 

and blowdowns, and emissions from glycol dehydrators and pneumatic devices make up 60% of 

the total 2012 emissions. Of these, venting from initial completions is the most significant 

source, accounting for 23% of total VOC emissions.69 The remainder of emissions comes from 

condensate tanks (14%), glycol dehydrators (8%), pneumatic pumps/devices (8%), compressor 

engines (5%) and other fugitive sources (4%). Compressor engines emitted an estimated 5,705 

tons of NOx in 2006 (46% of total NOx emissions) and are projected to emit 6,497 tons in 2012 

(64% of total NOx emissions).70 Notably, in 2006, oil and gas exploration and production 

activities were the single largest anthropogenic source of VOCs in Garfield County, totaling an 

estimated 27,464 tons and comprising 37% of emissions.71 

Large condensate tanks and pneumatic devices are projected to account for the largest 

share of VOCs in Colorado’s DJ basin in 2010 (45% and 17% respectively) in 2010.72 The most 

significant source of NOx emissions are compressor engines which accounted for 55% of total 

NOx emissions in 2006 and are projected to account for 52% in 2010.73 

Oil and gas production in the South San Juan basin in New Mexico has been declining 

since the mid-1990s and is projected to remain flat though 2012. While total VOC emissions 

from oil and gas activities in this basin are expected to decrease from 60,697 Tpy in 2006 to 

55,705 Tpy in 2012, these oil and gas discharges represent a major source of VOCs. NOx 

 

69 ENVIRON, Development of 2010 Oil and Gas Emissions Projections for the Piceance Basin, 46 (January 21, 

2009). The projections do not include potential reductions that may occur due to the implementation of COGCC 

rules for the control of odors from oil and gas activities that took effect in 2009. 

70 Id. at 47. 71 Garfield County Public Health, Air Quality Management in Garfield County, Colorado’s Most Active Energy 

Development Region, 7 (Oct. 22, 2009). 

72 Development of 2010 Oil and Gas Emissions Projections for the Denver-Julesburg Basin, supra note 69, at 21. 73 Id. at 22; ENVIRON, Development of Baseline 2006 Emissions From Oil and Gas Activity in the DenverJulesburg Basin, 29 (April 30, 2008). 

22 
emissions are projected to rise slightly from 38,788 to 39,774.74 Venting from blowdowns is 

projected to be the largest source of VOC emissions, accounting for 23% of total 2012 VOC 

emissions, followed by emissions from dehydrators (20%) and venting from initial completions 

(17%).75 NOx emissions from compressor engines are projected to account for 85% of all 2012 

emissions, equaling 34,212 tons.76 

Emissions from oil and natural gas production in the Uinta basin in Utah are projected to 

rise significantly from 71,546 Tpy of VOCs and 13, 093 Tpy of NOx in 2006 to 127, 495 Tpy of 

VOCs and 16,547 Tpy of NOx in 2012 consistent with an increase in production.77 Emissions 

from glycol dehydrators and flashing emissions from condensate and oil tanks are projected to 

make up to 57% of the total VOC emissions in the Uinta basin in 2012.78 Drill rigs are projected 

to be the largest source of NOx emissions, followed closely by compressor engines.79 

In the only basin inventoried for WY to date, the Wind River basin, pneumatic devices 

account for the largest percentage of VOC emissions (53% in 2006 and 59% in 2012), followed 

by venting from blowdowns (17% in 2006 and 15% in 2012).80 Emissions from compressor 

engines account for the vast majority of NOx emissions (71% in 2006 and 63% in 2012), 

followed by those from drill rigs (12% in 2006 and 16% in 2012).81 While not available yet, 

 

74 ENVIRON, Final Report, Development of Baseline 2006 Emissions From Oil and Gas Activity in the South San 

Juan Basin, 44 (Nov. 25, 2009); ENVIRON, Development of 2010 Oil and Gas Emissions Projections for the South 

San Juan Basin, 26 (Dec. 8, 2009). 

75 Development of 2010 Oil and Gas Emissions Projections for the South San Juan Basin, Id. at 24. 76 Id. at 26. 77 ENVIRON, Final Report, Development of Baseline 2006 Emissions From Oil and Gas Activity in the Uinta 

Basin, 39-40 (March. 25, 2009); ENVIRON, Development of 2010 Oil and Gas Emissions Projections for the Uinta 

Basin, 51-52 (March 25, 2009). 

78 Development of 2010 Oil and Gas Emissions Projections for the Uinta Basin, Id. at 46. 79 Id. at 51. 80 ENVIRON, Final Report, Development of Baseline 2006 Emissions From Oil and Gas Activity in the Wind River 

Basin, ES-4 (July 14, 2010); ENVIRON, Development of 2012 Oil and Gas Emissions Projections for the Wind 

River Basin, 24 (July 2010). 

81 Development of Baseline 2006 Emissions From Oil and Gas Activity in the Wind River Basin, Id. at 32; 

Development of 2012 Oil and Gas Emissions Projections for the Wind River Basin Id. at 34. 

23 
emissions from the massive gas fields in the Green River Basin in Wyoming are undoubtedly 

significant and the same is true for Wyoming’s Powder River Basin. 

Inventories prepared in basins outside the WRAP region also demonstrate the significant 

emissions associated with oil and gas exploration and production and transmission activities. A 

recent analysis of air emissions associated with natural gas and oil production in the Barnett 

Shale area found them to be comparable to the combined emissions from all the cars and trucks 

in the metropolitan area and several times higher than total emissions from the Dallas-Fort Worth 

area’s airports.82 The following chart demonstrates peak summertime daily emissions (tons per 

day) in 2009 from sources in the Barnett Shale. 83 

Table 2: Barnett Shale Peak Daily Summer Emissions of VOCs and NOx (tons per day) 

*Transmission fugitives include emissions produced by the movement of natural gas from wells 

to processing plants and from processing plants to compressor stations. 

Sources VOC NOx 

Condensate and oil tanks 146 0 

Production fugitives 26 0 

Well drilling and 

completions 

21 5.5 

Gas processing 15 0 

Transmission fugitives* 28 0 

Compressor engine exhaust 19 46 

VOC emissions in the Haynesville shale are predicted to range from approximately 12 to 

29 tons per day (“Tpd”) in 2012 to 19 to 69 Tpd in 2020 depending on the pace of 

 

82 Armendariz, supra note 6, at 24. 83 Id. at 25. 

24 
development.84 The low growth development scenario assumed that no new drill rigs were 

added to the region’s drill count in 2009 (95 rigs in the shale). The aggressive scenario assumed 

the addition of 25 drill rigs each year, capped at 200, which is consistent with the historical pace 

of growth in the Barnett Shale between 2001-2009. The moderate scenario assumed a growth 

rate one half of the aggressive scenario (12 new drill rigs per year). The analysis projected 

natural gas production for each scenario based on the anticipated number of new active wells 

drilled by each additional rig (assuming that each rig drills a total of 5.8 wells a year, with a 

success rate of 55%) and well productivity rates based on typical well production in the shale. 

NOx and VOC emissions were estimated for each scenario using standard emissions factors.85 

The 2012 NOx emissions are estimated to be 60.64, 81.72, or 139.84 Tpd in 2012 under 

low, moderate, and high development scenarios, respectively.86 By 2020 these numbers are 

projected to increase to approximately 63, 127, and 267 Tpd. 87 Moderate development of the 

shale results in an additional 120 Tpd of NOx in northeast Texas and northwest Louisiana. This 

is equal to approximately half of the NOx emissions from all source categories (oil and gas and 

other) emitted in 2012 in the five Texas counties that comprise the Haynesville Shale.88 

According to the inventory, “if the development of the Haynesville Shale proceeds at even a 

relatively slow pace, emissions from exploration and production activities will be sufficiently 

large that their potential impacts on ozone levels in Northeast Texas should be evaluated.”89

 

84 Development of Emissions Inventories for Natural Gas Exploration and Production Activity in the Haynesville 

Shale, supra note 14, at Table 22, 45. 85 Id. at 13-19. 86 Id. at Table 22, 56. 87 Id. at Table 23, 60. 88 Id. at 63. 

89 Id. at 1. 

25 
D. OIL AND GAS ACTIVITIES EMIT AIR TOXIC POLLUTION 

Oil and gas exploration activities emit a number of hazardous air pollutants known to 

cause cancer or other non-cancer health impacts. According to EPA, oil and gas production 

emits benzene, toluene, ethylbenzene, and xylenes as well as n-hexane.90 Long-term exposure to 

benzene can cause cancer as well as blood disorders, and reproductive and developmental 

disorders. Exposure to benzene, as well as toluene, ethylbenzene, and xylenes also causes a host 

of non-cancer effects such as respiratory tract irritation, irritation to the skin, eyes, nose and 

throat, neurological problems, dizziness and headaches. 

Many of the same sources that emit methane, NOx and VOCs also emit hazardous air 

pollutants. Studies conducted at various locations in Texas, Colorado and Wyoming have 

identified elevated levels of HAPs at exploration and production sites. For example, in the 

Barnett Shale, peak summertime HAP emissions were estimated to equal 17 Tpd in 2009. 91 

Condensate tanks were the primary sources, emitting 11 Tpd, followed by compressor engine 

exhaust (3.6 Tpd). Fugitive emissions from production and transmission sources, as well as gas 

processing, well drilling, completion and hydraulic fracturing contributed the remainder.92 

In March, 2010 the Texas Council on Environmental Quality (“TCEQ”) measured 

benzene at levels above TCEQ’s short term, health based comparison level of 180 parts per 

billion (ppb) at two exploration and production sites in the Barnett Shale in Wise County, 

Texas.93 Air samples collected as part of a study by residents of the town of DISH, Texas 

located within the Barnett Shale, confirmed the presence of certain HAPs including benzene, 

 

90 U.S. EPA, Outdoor Air-Industry, Business and Home Oil and Natural Gas Production-Additional Information, 

http://www.epa.gov/air/community/details/oil-gas_addl_info.html#activity2. 

91 Armendariz, supra note 6, at Table 21-2, 24. 

92 Id. Production fugitives include emissions from components on wells such as casing heads, fittings, valves, and 

pneumatic devices. 

93 Railroad Commission of Texas, Notice to Oil, Gas & Pipeline Operators Regarding Air Emissions (March 2010). 

26 
carbon disulfide, carbonyl sulfide, naphthalene, and xylene at concentrations in excess of TCEQ 

short-term and long-term effects screening levels.94 

 Air monitoring conducted by Garfield County, Colorado reveals similar levels of 

ambient HAPs near exploration and production sites. Garfield County is home to the majority of 

oil and gas development in the Piceance basin. In response to 171 complaints regarding odors 

related to oil and gas operations, the County conducted an ambient air quality study to evaluate 

exposure to air toxics between 2005 and 2007.95 The study identified 15 chemicals of potential 

concern in the collected samples including benzene, ethylbenzene, toluene, and m, p-Xylene. 

Benzene cancer and non-cancer risks were highest in the oil and gas areas. At one oil and gas 

site (the “Brock site”) the cancer risk was slightly above the upper-end of EPA’s acceptable 

range of 1 to 100 excess cancers per million individuals exposed. The high-end, short-term noncancer hazards for benzene exposures also exceeded EPA’s acceptable levels.96 A subsequent 

risk assessment, based on the 2005-2007 air monitoring and supplemented by air modeling, 

indicated that benzene emissions from well completions, dehydration units and condensate tanks 

pose a cancer risk. According to the risk assessment, benzene emissions from uncontrolled 

flowback during well completions, dehydration units and condensate tanks pose the most 

significant cancer threats.97

 

94 Earthworks’ Oil and Gas Accountability Project, Health Survey Results of Current and Former DISH/Clark, 

Texas Residents, 13 (December 2009), http://townofdish.com/objects/DishTXHealthSurvey_FINAL_hi.pdf. 95 Air Resources Specialists, Inc., Air Quality Management in Garfield County: Colorado’s Most Active Energy 

Development Region, 19 (Oct. 22, 2009). Pursuant to this study the County collected monthly 24-hour samples and 

quarterly samples from eight oil and gas sites, four urban sites and two background rural sites between 2005-2007. 

96 Raj Goyal, Air Toxic Inhalation: Overview of Screening-Level Health Risk Assessment for Garfield County, slide 

27 (June 17, 2008), http://www.garfield-county.com/index.aspx?page=1334. 97 Teresa Coons, Ph.d. and Russell Walker, “Community Health Risk Analysis of Oil and Gas Industry Impacts in 

Garfield County”, xv. The risk assessment considered exposure to modeled benzene emissions based on sampling 

results over a 70-year period. It concluded that well emissions pose the greatest threat over this time-period but that 

exposure to emissions from glycol dehydrators and condensate tanks is more likely over seventy years. 

27 
Numerous HAPs have also been identified in the ambient air in and around the PinedaleAnticline gas field in Sublette County, Wyoming. For example, recent air quality monitoring 

identified benzene at one monitor at levels higher than the Agency for Toxic Substances and 

Disease Registry’s acute inhalation minimal risk level.98 Wyoming is currently developing a 

risk assessment associated with emissions from sources in the Pinedale-Anticline gas fields. 

 

E. COST-EFFECTIVE TECHNOLOGIES ARE AVAILABLE TO 

REDUCE METHANE, VOCS AND AIR TOXICS. 

Nationwide implementation of oil and gas pollution controls will result in strengthened 

protection of human health and the environment from serious air pollutants as well as valuable 

energy savings that translate into more natural gas available to consumers, increased taxable 

revenue available to states or localities, and greater profits for gas companies. The following is a 

list of some of the most cost-effective technologies or practices that are available today. 

1. Use of Low or No-bleed Pneumatic Devices. 

 Pneumatic devices are used throughout the production, processing and transmission of 

natural gas, and the production of crude oil, to automatically operate valves and control pressure, 

gas flow, temperature or liquid levels.99 As the following chart illustrates, pneumatic devices 

account for the largest percentage of natural gas production fugitive emissions—nearly 4 times 

as much as the other leading causes of emissions. 

98 Sublette County, Air Toxics Inhalation Project, 4th Quarter Data Summaries 2009, E-6. Ambient levels of 

Benzene at one monitor were 38.31 μg/m3. The ATSDR acute inhalation MLR for benzene is 20 μg/m3. 

99 See U.S. EPA, Lessons Learned from Natural Gas STAR Partners, “Options for Reducing Methane Emissions 

from Pneumatic Devices in the Natural Gas Industry”, available at 

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

28 
Figure 4: Oil and Natural Gas Production Sources of Methane Emissions 

Source: EPA, http://www.epa.gov/gasstar/basic-information/index.html

 

 In addition, pneumatic devices contribute to ozone pollution. For example, WRAP 

inventories of VOC emissions from oil and gas exploration and production activities in the 

Colorado D.J. and the Utah Uinta basins project that pneumatic devices will account for 17% and 

20% of all VOC exploration and production emissions in 2010 and 2012, respectively.100

 Pneumatic devices are designed to vent natural gas. However, some bleed or vent at rates 

significantly lower than others yet still achieve the same overall performance. Replacing high 

with low or no-bleed pneumatic devices results in significant gas savings and has a payback 

 

100 Development of 2010 Oil and Gas Emissions Projections for the Denver-Julesburg Basin, supra note 72, at 21; 

Development of 2010 Oil and Gas Emissions Projections for the Uinta Basin, supra note 78, at 46. 

29 
period of less than one year.101 This practice has saved natural gas operators $61.2 million and 

as much as 20.4 Bcf of methane gas to date.102

 

 

 Colorado requires that all new, replaced or repaired pneumatic devices at production 

facilities must be low or no-bleed.103 In addition, all pneumatic controllers at exploration and 

production sites, upstream natural gas compressor stations, natural gas drip stations and gas 

processing plants located in an ozone nonattainment or attainment/maintenance areas must have 

VOC emissions equal to or less than a low-bleed controller.104 All new pneumatic controllers 

and existing pneumatic controllers located at a modified facility in the state of Wyoming must be 

low or no-bleed or route discharge streams to a closed loop system.105 

2. Well Completions 

 Well completion activities are another significant source of methane, VOCs and HAPs 

including benzene.106 One cost-effective way to significantly decrease well emissions is to use 

portable or permanent equipment to recover, rather than release through venting or flaring, 

natural gas during the final well drilling process (“green or reduced emission completions”). 

EPA estimates $176 million (25.2 Bcf) of natural gas can be recovered annually using green 

completions.107 Devon Energy, an operator in the Barnett Shale, reported the capture of 10.7 Bcf 

of gas between 2004 and 2009 through the use of “reduced emissions completions.” In 2007 

101 U.S. EPA, Lessons Learned from Natural Gas STAR Partners, “Options for Reducing Methane Emissions from 

Pneumatic Devices in the Natural Gas Industry”, http://www.epa.gov/gasstar/documents/ll_pneumatics.pdf. EPA 

defines a high-bleed device as one that releases natural gas in excess of 50 Mcf a year. 102 Id. 103 CO Regulation 7, XVIII; Colorado Oil and Gas Conservation Commission rule 805(b)(2)(E). 104 CO Regulation 7, XVIII.C. Upstream means upstream of natural gas processing plants. 105 Wyoming Oil and Gas Production Facilities, Chapter 6, Section 2 Permitting Guidance (March 2010) (“WY 

Revised March 2010 Guidance”), http://deq.state.wy.us/aqd/oilgas.asp. 106 For example, venting from well completions and re-completions are projected to account for 26% of VOC 

emissions in 2012 from the Piceance basin in Colorado and emissions from well completions and drilling were 

responsible for 21 tons per day of VOCs in 2009 in the Barnett Shale. Development of 2010 Oil and Gas Emissions 

Projections for the Piceance Basin, supra note 69, at 21; and Armendariz, supra note 6, at 25. 107 U.S. EPA,“Opportunities for Methane Emissions Reductions from Natural Gas Production.” Producer’s 

Technology Transfer Workshop, 8 June 2006, available at 

http://www.epa.gov/gasstar/documents/workshops/midland-2006/gremillion.pdf. 

30 
alone, Devon claimed it prevented the release of over 6.4 Bcf of methane, generating an 

additional $38 million in revenue from increased sales of natural gas.108

 Colorado currently requires the use of green completions on all oil and gas production 

wells unless not technically and economically feasible.109 Wyoming has required the use of 

green completions in the Jonah-Pinedale Anticline Development Area (“JPAD”) since 2007 and 

has recently expanded this requirement to all areas of concentrated oil and gas development 

(concentrated development areas or “CDA”s) in the state.110 Montana requires that VOC vapors 

greater than 200 British thermal units per cubic foot from wellhead equipment with the potential 

to emit 15 tpy or greater be routed to a capture or control device such as a pipeline or flare.111

3. Glycol Dehydrators 

 Glycol dehydrators are widely used in the production, processing and transmission of 

natural gas to remove excess water from the gas. As part of the de-watering process, methane is 

vented to the atmosphere. EPA estimates that glycol dehydrators vent approximately 1 Bcf of 

methane to the atmosphere annually as well as significant amounts of HAPs and VOCs.112 A 

number of technologies are available to reduce emissions from glycol dehydrators including 

installing flash tank separators, reducing the glycol circulation rate and using electric pumps 

instead of gas-assisted pumps.113

 

108 Devon press release, November 12, 2008. 

109 Final Rule, Colorado Oil and Gas Conservation Commission, § 805(b). 110 WY Revised March 2010 Guidance, supra note 106, at 15. 111 MT Admin. Rules § 17.8.1711. This rule applies to all oil and gas facilities that have the potential to emit 25 

Tpy of a regulated air pollutant, including HAPs. Oil and gas facilities include wells and associated equipment used 

to produce, treat, separate or store oil, natural gas, or other liquids produced by the well. MT Ann. Code (2009) § 

75-2-103. 

112 For example, dehydrators are expected to contribute 24% of all VOC emissions from exploration and production 

activities in the Uinta basin in 2012 and 11% of VOC emissions in the Piceance basin. Development of 2010 Oil 

and Gas Emissions Projections for the Uinta Basin, supra note 78, at 53 and Development of 2010 Oil and Gas 

Emissions Projections for the Piceance Basin, supra note 69, at 46. 113 U.S. EPA, Lessons Learned from Natural Gas STAR Partners, “Optimize Glycol Circulation and Install Flash 

Tank Separators in Glycol Dehydrators”, 1, available at http://www.epa.gov/gasstar/documents/ll_flashtanks3.pdf. 

31 
 In Colorado, oil and gas operators must control actual, uncontrolled VOC emissions of 15 

Tpy or more from vents on glycol dehydrators (individual units or the aggregate emissions from 

all dehydrators at a site) located at all oil and gas exploration and production operations, natural 

gas compressor stations, drip stations or gas processing plants by 90%.114 More stringent 

requirements apply to glycol dehydrators located within a one-quarter mile of a public place in 

Garfield, Mesa and Rio Blanco counties in the Piceance basin. Operators in these areas must 

control emissions of VOCs by 90% from all dehydrators with a potential to emit 5 Tpy of 

VOCs.115 

Wyoming requires control of HAPs and VOCs by at least 98% at all new and existing 

dehydration units operating in the Jonah-Pinedale Anticline Development Area regardless of 

total actual or potential emissions.116 All new and existing dehydrators in concentrated areas of 

development and statewide must control HAPs and VOCs by 98% upon the first date of 

production. Controls may be removed after one year if emissions equal to or less than 6 Tpy and 

units are equipped with still vent condensers.117 

4. Crude Oil, Condensate and Produced Water Tanks 

 Field crude oil, condensate and produced water storage tanks used in the production, 

storage and transmission of natural gas and in oil production are another significant source of 

methane, VOCs and HAPs.118 Flash emissions occur during the transfer of liquids from 

 

114 CO Regulation 7, XII.H. 115 Final Rule, Colorado Oil and Gas Conservation Commission, § 805(b). 116 WY Revised March 2010 Guidance, supra note 106, at 37. 117 Alternatively, upon production units must be equipped with reboiler still vent condensers and glycol flash 

separators. If, after 30 days, potential VOCs > 8 Tpy, operators must install combustion controls capable of 

reducing emissions by 98%. After one year, combustion units may be removed if total potential VOC emissions < 8 

Tpy. 

118 For example, peak 2009 summertime VOC emissions from condensate and oil tanks in the Barnett Shale reached 

146 tons per day, comprise 33% of projected 2012 VOC emissions in the Uinta basin and 45% of projected 2010 

VOC emissions in the D.J. basin. Armendariz, supra note 6, at 25; Development of 2010 Oil and Gas Emissions 

32 
separation equipment to atmospheric storage tanks. Breathing or standing losses occur when 

vapors are evaporated or displaced from tanks due to rising liquid level and changes in 

temperature.119 Installation of vapor recovery units can capture approximately 95% of methane 

vapors (as well as other air pollutants) from storage tanks, save operators up to $260,060 per 

year, and has a payback of three months.120 

 Wyoming requires that VOC emissions from condensate, oil and produced water tanks 

located at new or modified facilities in the Jonah-Pinedale Anticline Development Area and 

concentrated areas of development must control flash emissions upon the first date of production 

regardless of the amount of emissions. These facilities may remove controls after one year if 

emissions are less than 8 Tpy of VOCs. Statewide, new and modified facilities must control 

VOC flash emissions equal to or greater than 10 Tpy by 98% upon FDOP and may remove 

controls after one year if emissions are less than 8 Tpy.121

 Colorado currently requires the control by 95% of VOC emissions from condensate, 

crude oil and produced water tanks with a potential to emit 5 Tpy of VOCs that are located 

within a one-quarter mile of a public place in Garfield, Mesa and Rio Blanco counties in the 

Piceance basin.122 Owners or operators of condensate tanks whose cumulative actual 

uncontrolled VOC emissions are equal to or greater than 30 Tpy located at exploration and 

production sites within ozone nonattainment areas and nonattainment/maintenance areas must 

 Projections for the Uinta Basin, supra note 78, at 53; Development of 2010 Oil and Gas Emissions Projections for 

the Denver-Julesburg Basin, supra note 72, at 20. 

119 U.S. EPA, Lessons Learned from Natural Gas STAR Partners, “Installing Vapor Recovery Units on Crude Oil 

Storage Tanks” 1, available at http://www.epa.gov/gasstar/documents/ll_final_vap.pdf. 120 Id. 121 Note that the emission threshold for the application of this requirement differs depending on an individual tank’s 

location. For example, all tanks located in the Pinedale-Anticline Development Area must control emissions upon 

production, regardless of the amount of emissions. Tanks located in Concentrated Development Areas with 

potential and actual emissions of 8 Tpy must comply with specified emissions limitations whereas other tanks 

located statewide need only install control technologies if potential emissions equal 10 Tpy or more and actual 

emissions equal or exceed 8 Tpy. WY Revised March 2010 Guidance, supra note 105, at 18, 11, 5. 122 Final Rule, Colorado Oil and Gas Conservation Commission, § 805(b). 

33 
meet declining emissions reductions over time. For example, such operators must reduce overall 

VOC emissions from all of their tanks emissions by 81% during the 2009 ozone season (May 1- 

Sept. 30) and by 85% in 2010 (such owners/operators do not need to apply controls to every 

individual tank). Owners or operators must reduce non-ozone season emissions by 70% in 2009 

and 2010. Controls used to produce the requisite reductions must achieve a 95% control 

efficiency.123 Additionally, tanks installed after February 1, 2009 controlled with a combustion 

device must be equipped with an auto-igniter upon startup. Statewide, new and existing 

condensate tanks that emit equal to or greater than 20 Tpy of VOCs must control emissions by 

95%.124 

 Montana requires that VOC vapors greater than 200 British thermal units per cubic foot 

from wellhead equipment and oil and condensate storage tanks with the potential to emit equal to 

or greater than 15 tpy be routed to a capture or control device such as a pipeline or flare.125

A TCEQ case study illustrates the cost savings that can be realized from pollution control 

technologies, in this instance a storage tank bhattery in North Texas releasing 190 

Mcf/day of gas, with a heat content of 2400 Btu – 2.4 times higher than standard natural 

gas. Capturing the gas could have a monthly value of $68,000 (assuming $5/Mcf natural 

gas price adjusted for the higher heat content of the captured vent gas). In this case, the 

simple payback period for a vapor recovery unit costing $32,000 would be 14 days 

($32,000/$68,000 per month = 14 days). Some vendors of vapor recovery technology 

also offer alternative financing options to the outright purchase of the equipment, 

including providing the equipment at no up-front cost in return for a share of the 

recovered product. 

 

123 CO Regulation 7, XII.D.1. See also Colorado DPH&E Air Pollution Control Division, Oil and Gas Exploration 

& Production Regulation No. 7 Requirements, http://www.cdphe.state.co.us/ap/sbap/SBAPoilgastankguidance.pdf. 124 CO Regulation 7, XVII.C.1. 125 MT Admin. Rules § 17.8.1711. 

34 
5. Production Fugitive Emissions 

 There are a large number of uncontrolled fugitive sources in the production sector. 

California’s Climate Change Scoping Plan proposes to address fugitive emissions from the 

extraction process of the state’s large oil and gas industry, including on and off-shore sources. 

These emissions are from well and process equipment venting: leaks of flanges, valves and other 

fittings on the wells and equipment; and from separation and storage units such as sumps and 

storage tanks. Controls for the fugitive sources range from applying simple fixes to existing 

technologies to deploying new technologies to replace inefficient equipment and detect leaks and 

would include: improving operating practices to reduce emissions when compressors are taken 

off-line; installing compressor rod packing systems; substituting high bleed with low bleed 

pneumatic devices; improving leak detection; installing electronic flare ignition devices; 

replacing older equipment (flanges, valves, and fittings); and installing vapor recovery devices. 

These are proven technologies according to the U.S. EPA’s Natural Gas STAR program, which 

will pay back investments in a short period of time through saleable natural gas savings. 

California’s proposal is expected to reduce fugitive methane emissions by approximately 0.2 

MMT CO2e per year, beginning in 2015 and result in net annualized savings of $3.7 million.126

6. Plunger Lifts and “Smart” Well Automation during Well 

Unloading 

 Operators often remove unwanted fluids from mature gas wells through “well 

unloading”- practices that lead to venting of methane, HAPs and VOCs. One way to remove 

unwanted fluids without venting while also improving well productivity is to install a plunger lift 

system and “smart” well automation system. Plunger lifts use gas pressure buildup in the well 

 

126 See California’s Climate Change Scoping Plan, available at 

http://www.arb.ca.gov/cc/scopingplan/document/adopted_scoping_plan.pdf, ES-5, 3, 54-56, and V. 1 of 

Appendices, http://www.arb.ca.gov/cc/scopingplan/document/appendices_volume1.pdf, C153-154. 

35 
casing-tubing annulus to operate a steel plunger that pushes liquids to the surface.127 Smart well 

automation maximizes the efficiency of plunger lifts by routinely varying plunger well cycles to 

match key reservoir performance indices. Natural Gas STAR partners have reported annual gas 

savings averaging 600 thousand cubic feet (“Mcf”) per well and increased gas production of up 

to 18,250 Mcf per well, worth an estimated $127,750 through the implementation of plunger 

lifts. Installing smart well automation on plunger lift systems typically results in an average 

savings of 500,000 cubic feet of methane per well, per year.128 

7. Installation of BASO Valves on All Gas-fired Heaters 

 Crude oil heater-treaters, gas dehydrators and gas heaters located at exploration and 

development sites have pilot flames which can be extinguished by strong winds, causing the 

venting of natural gas. BASO valves automatically shut off the flow of natural gas upon the 

extinguishment of the pilot flame, thereby preventing unnecessary pollutant and methane losses. 

BASO valves are operated by a thermocouple that senses the pilot flame temperature and do not 

require electricity or manual operation. They are therefore ideal for remote locations. Capital 

costs are negligible, with each valve costing less than $100, and savings can be as great as 203 

Mcf year for a 1,000 barrel per day heater-treater that experiences a flameout period of 10 days 

annually. Payback depends on how often the pilot flames go out and for what length of time. 

Typically payback occurs in less than 1 year.129 A clean air standard based on the installation of 

BASO valves could result in significant product savings and emission reductions. 

 

 

127 U.S. EPA, Lessons Learned from Natural Gas STAR Partners, “Installing Plunger Lift Systems in Gas Wells”, 

available at http://www.epa.gov/gasstar/documents/ll_plungerlift.pdf. 128 U.S. EPA, “Opportunities for Methane Reductions from Natural Gas Production”, available at 

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

129 U.S. EPA, Install BASO Valves, available at http://www.epa.gov/gasstar/documents/installbaso.pdf; See also

Draft Oil and Gas Ozone Reduction Strategy – Presented at February 26, 2008 Colorado RAQC Meeting. 

36 
8. Leak Detection and Repair at Compressor Stations in the 

Transmission and Storage Sectors. 

 Compressor stations occur throughout the natural gas transmission and storage sectors 

and act to compress the gas to varying pressure points to overcome pressure losses that occur 

along a long-distance pipeline. According to EPA, compressor stations in the transmission 

sector alone account for approximately 50.7 Bcf of methane emissions annually.130 A leak 

detection and repair program, similar to that already required for equipment and compressors 

located at natural gas processing plants, see 40 C.F.R. Part 60, Subpart kkk, offers a costeffective way to prevent and eliminate emissions from compressor stations. Baseline surveys 

done by EPA partners have revealed that the majority of leaks come from a small number of 

parts, mostly valves, and that once these parts are identified, cost-effective repairs can be 

streamlined to accomplish maximum emissions reductions and gas savings. 

9. Replacing Compressor Rod Packing From Reciprocating 

Compressors. 

 Reciprocating compressors are one of the largest sources of methane emissions at natural 

gas compressor stations. Methane emissions are produced by leaks in the piston rod packing 

systems used in the compressors—especially from older systems. Replacing compressor rod 

systems reduces methane emissions, increases savings, and results in greater operational 

efficiencies and equipment life-spans. Average gas savings equal $6,055 a year and far exceed 

the $540 implementation cost and the payback is two months.131 California has proposed 

installing compressor rod packing systems as one strategy for reducing emissions from the 

state’s oil and natural gas transmission industry. This, along with other strategies such as 

 

130 U.S. EPA, Lessons Learned from Natural Gas STAR Program, “Directed Inspection and Maintenance at 

Compressor Stations”, available at http://www.epa.gov/gasstar/documents/ll_dimcompstat.pdf. 131 U.S. EPA, Lessons Learned from Natural Gas STAR Partners, “Reducing Methane Emissions from Compressor 

Rod Packing Systems”, available at http://www.epa.gov/gasstar/documents/ll_rodpack.pdf 

37 
improving operating practices when compressors are taken off-line and replacing old flanges and 

fittings along pipeline, are expected to yield 0.9 MMT CO2e annually and save the oil and gas 

industry $17 million in annualized net savings.132

10. Replacement of Wet Seals with Dry Seals on Wet Seal Centrifugal 

Compressors 

 Centrifugal compressors are widely used throughout the natural gas production and 

transmission sectors. Seals on rotating shafts are used to prevent natural gas losses from 

compressor casing. Many of these seals use high-pressure oil as a barrier against escaping gas. 

These types of seals, referred to as “wet” seals, produce methane emissions when the circulating 

oil is stripped of the gas it absorbs. Dry seals use natural gas instead of oil to prevent gas losses. 

They also have lower power requirements, improve compressor and pipeline operating efficiency 

and performance, enhance compressor reliability, and require significantly less maintenance. A 

dry seal can save about $315,000 per year and pay for itself in as little as 11 months. One 

Natural Gas STAR partner who installed a dry seal on an existing compressor reduced emissions 

by 97 percent, from 75 to 2 Mcf per day, saving almost $187,000 per year in gas alone.133 

III. EPA ADOPTION OF RIGOROUS, WELL-DESIGNED EMISSION 

STANDARDS FOR THE SUITE OF AIR POLLUTANTS DISCHARGED 

BY THE OIL AND GAS SECTOR WILL ACHIEVE VITAL PUBLIC 

HEALTH AND ENVIRONMENTAL PROTECTIONS. 

 Section 111 of the Clean Air Act requires EPA to establish technology-based standards 

that limit the emissions of air pollutants from categories of stationary sources that “cause[s], or 

contribute[s] significantly to, air pollution which may reasonably be anticipated to endanger 

public health or welfare.”134 From “time to time” EPA must revise this list.135 Once EPA 

 

132 California’s Climate Change Scoping Plan, V. 1 of Appendices, supra note 126, at 131. 133 U.S. EPA, Lessons Learned from Natural Gas STAR Partners, “Replacing Wet Seals with Dry Seals in 

Centrifugal Compressors”, available at http://www.epa.gov/gasstar/documents/ll_wetseals.pdf. 134 42 U.S.C. § 7411(b)(1)(A). 135 Id. 

38 
publishes a category of stationary sources, it must establish new source performance standards 

for air pollutants emitted from new and modified sources within the category (NSPS).136 New 

source performance standards must reflect “best demonstrated technology” which is “the degree 

of emission limitation achievable through the application of the best system of emission 

reduction which (taking into account the cost of achieving such reduction and any nonair quality 

health and environmental impact and energy requirements) the Administrator determines has 

been adequately demonstrated.”137 

 EPA listed the Crude Oil and Natural Gas Production on its “priority” list of categories 

that “cause[s], or contribute[s] significantly to, air pollution” which endangers human health and 

welfare in 1979.138 Accordingly, EPA is obligated to promulgate new source performance 

standards for sources within this category. As demonstrated above, this source category consists 

of a wide range of equipment such as pneumatic devices, dehydrators, tanks, separation units, 

flanges, valves and other fittings, compressors, pumps, and heater-treaters located at and inbetween wells, compressor stations and gas processing plants. In addition, these sources emit a 

range of pollutants including VOCs, methane, NOx, and sulfur dioxide (“SO2”). Despite the 

large number of sources within the source category, and the myriad pollutants they emit, to date 

EPA has issued only two performance standards for this category. Specifically, to limit VOCs, 

EPA has established a VOC leak detection standard for certain equipment located at onshore gas 

processing plants (e.g., compressors, other than reciprocating compressors in wet gas service, 

glycol dehydrators, pumps, valves and flanges) and a standard that limits SO2 emissions from 

 

136 42 U.S.C. § 7411(a)(1). 137 42 U.S.C. § 7411(a)(1). 138 42 U.S.C. § 7411(b)(1)(A); 44 Fed. Reg. 49222 (August 21, 1979) (codified at 40 C.F.R. § 60.16). 

39 
sweetening units and sulfur recovery units also located at natural gas processing plants.139 These 

standards fall woefully short of providing adequate protection to human health and the 

environment as they apply to only a fraction of the sources located within the Crude Oil and 

Natural Gas Production source category and only to two of the many types of air pollutants 

emitted by sources within the category.140 

 Existing sources account for a significant percentage of emissions from oil and gas 

sources. To date, EPA has not issued any emission guidelines to reduce air pollution from 

existing sources.141 The Clean Air Act calls for EPA to issue emission guidelines applicable to 

existing sources once it establishes new source performance standards for a category of new 

sources: 

 Concurrently upon or after proposal of standards of performance for the control 

 of a designated pollutant from affected facilities, the Administrator will publish a 

 draft guideline document containing information pertinent to control of the 

 designated pollutant form designated facilities... and upon or after promulgation 

 of standards of performance for control of a designated pollutant from affected 

 facilities, a final guideline document will be published and notice of its 

 availability will be published in the FEDERAL REGISTER. (emphasis added). 

 

40 C.F.R. § 60.22(a).142 Emission guidelines must reflect “the application of the best system of 

emission reduction (considering the cost of such reduction) that has been adequately 

demonstrated.”143 As demonstrated above a number of western states require air pollution 

reductions from existing sources. Accordingly, in tandem with the revision of the current NSPSs 

 

139 “Equipment Leaks of VOCs from Onshore Natural Gas Processing Plants”, 50 Fed. Reg. 26122 (June 24, 1985); 

Onshore Natural Gas Processing SO2 Emissions, 50 Fed. Reg. 40158 (October 1, 1985). 

140 EPA has also issued standards to reduce NOx from new gas powered engines including spark ignition internal 

combustion engines and reciprocating internal combustion engines. See standards listed at supra note 7. 141 See 40 C.F.R. 60.30, Subpart C. 142 See also 42 U.S.C. §7411(d) (requiring the Administrator to “establish a procedure...under which each State 

shall submit to the Administrator a plan which (A) establishes standards of performance for any existing source...”. 143 40 C.F.R. § 60.22(b)(5). 

40 
and promulgation of additional NSPSs, EPA must promulgate standards for the control of air 

pollution from existing sources. 

In addition to its duty to control air pollution from new and modified stationary sources 

under section 111, EPA must also issue standards to reduce HAPs from new and existing 

stationary sources.144 Like section 111, section 112(c)(1) of the Clean Air Act requires EPA to 

publish a list of categories and subcategories of major and area sources of HAPs.145 EPA must 

“from time to time, but no less often than every 8 years, revise, if appropriate, in response to 

public comment or new information” its list of categories.146 It may also add additional 

categories or subcategories at any time.147 Once EPA lists a category of sources of HAPs it must 

establish emission standards that require the “maximum degree of reduction in emissions” of 

HAPs from new and existing sources.148 

EPA included the “Oil and Natural Gas Production” category in its initial list of major 

source categories of HAPs in 1992.149 EPA subsequently listed oil and natural gas production 

for regulation as part of its Urban Air Toxics Strategy in 1999 because TEG glycol dehydration 

units at oil and gas production facilities contributed nearly 50% of the national benzene 

emissions from area sources.150 In 1998 EPA added the Natural Gas Transmission and Storage 

category to its list of major source categories of HAPs based on its finding that “natural gas 

transmission and storage facilities have the potential to be major HAP sources...[and] that there 

are major source TEG dehydration units in the natural gas transmission and storage source 

 

144 See 42 U.S.C. § 7412. 145 42 U.S.C. § 7412(c)(1). 146 Id. 147 42 U.S.C. § 7412(c)(5). 148 42 U.S.C. § 7412(c)(2),(d). 

149 57 Fed. Reg. 31576 (July 16, 1992). 150 64 Fed. Reg. 38706 (July 19, 1999). 

41 
category.151 These listings triggered the requirement for EPA to promulgate emission standards 

for major and area sources within the Oil and Natural Gas Production category and for major 

sources within the Natural Gas Transmission and Storage category.152 

 Like the current NSPSs, the existing NESHAPs control HAPs from a limited number of 

oil and gas sources. Specifically, the NESHAPs apply to three types of equipment used during 

the production, processing and transmission of oil and gas: 1) glycol dehydrators; 2) storage 

vessels with the potential for flash emissions (i.e. condensate and oil tanks); and 3) certain 

equipment located at gas processing plants. Like the NSPSs, the NESHAPs fail to protect 

human health and the environment adequately by limiting emissions only from large glycol 

dehydrators, storage vessels and gas processing plants located at major sources.153 According to 

EPA, this leaves a large number of dehydrators, storage vessels and equipment at gas processing 

plants unregulated: specifically the rule only applies to 440 out of 100,00 to 250,000 production 

facilities and 7 out of 2,000 transmission and storage facilities.154 Moreover, the rules do not 

limit emissions from other sources such as wells, pneumatic devices, compressor seals, valves, or 

flanges or other production equipment located at oil and gas production facilities or natural gas 

storage and transmission facilities. 

 In 2007 EPA issued standards to limit emissions of HAPs from process vents on glycol 

dehydration units located at area sources within the Oil and Natural Gas Production category.155 

 

151 63 Fed. Reg. 6288, 6290 (Feb. 6, 1998). 152 42 U.S.C. § 7412(c)(2); 42 U.S.C. § 7412(k)(3)(B) (source categories identified as part of the Urban Air Toxics 

Strategy “are or will be listed pursuant to subsection (c) of section 112”). 153 The rule exempts dehydrators with an annual average natural gas flowrate less than 85 thousand m3/day or 

benzene emissions less than 0.90 Mg/yr. Similarly, only storage vessels that contain a hydrocarbon liquid with a 

storage tank gas to oil ratio equal to or greater than .31 m3/liter, an API gravity equal to or greater than 40 degrees, 

and an actual average throughput of hydrocarbon liquids equal to or greater than 79,500 liter/day are covered. 

Tanks located at facilities that exclusively process, handle or store black oil are also excluded. 154 “National Emission Standards for Hazardous Air Pollutants: Oil and Natural Gas Production and Natural Gas 

Transmission and Storage”, 64 Fed. Reg. 32610 (June 17, 1999). 

155 72 Fed. Reg. 26 (Jan. 3, 2007). 

42 
Pursuant to the 2007 standard units located near urban areas must comply with the same standard 

that applies to units located at major sources, i.e. connect, through a closed-vent system, each 

process vent on the glycol dehydration unit to an air emission control system which must reduce 

HAP emissions by 95 percent or more. Units in rural areas need only comply with management 

practices to reduce glycol circulation rates. While the area source standards for glycol 

dehydrators located at oil and natural gas facilities expanded the scope of NESHAPs to apply to 

some smaller sources of HAPs, it still leaves many area sources of HAPs unregulated (e.g. well 

completions, re-completions, unloading, pneumatic devices and sources of fugitive emissions 

such as compressor seals and rod packing in the production and transmission and storage 

categories). 

Rigorous, well-designed clean air standards will protect human health and the 

environment by addressing the suite of air pollutants emitted from the new, modified and 

existing sources of air pollution located at oil and natural gas exploration and production, 

processing, transmission and distribution facilities. Such standards should encompass the 

emissions reductions achievable through the implementation of the following cost-effective 

technologies: 

• low or no-bleed pneumatic devices; 

• green or reduced emissions completions and recompletions; 

• still vent condensers and glycol flash separators or other technologies that reduce 

vented emissions from glycol dehydrators by 98% or better; 

• vapor recovery units or other equipment that reduces emissions from crude oil, 

condensate and produced water tanks by 98% or better; 

• leak detection and repair for production fugitives; 

43 
44 

• plunger lifts and “smart” well automation systems for well unloading; 

• BASO valves on heater-treaters, gas dehydrators and gas heaters; 

• leak detection and repair at compressor stations; 

• replacement of compressor rod packing; 

• dry seals for centrifugal compressors; 

IV. CONCLUSION 

For the foregoing reasons, we respectfully request EPA protect human health and the 

environment by adopting clean air measures to reduce emissions of methane, air toxics and other 

hydrocarbon emissions from the full range of oil and gas activities. 

 
Appendix A: Emissions Estimates and Projections: Key oil and gas producing bas

Intermountain West and Gulf region. Table 1: 2006 VOC and NOx emissions and projected 2010/2012 emissions (Tons per Year)

Haynesville 

shale* 

Oil & gas emissions 

source 

DenverJulesburg basin Uinta basin Piceance basin North San Juan basin** South 

b

VOC 

2012 

mod. 

2012 

agg. 2006 2010 2006 2012 2006 2012 2006 2012 2006 

Condensate 

tanks 

N/A N/A 53,510 53,109 6,195 21,719 3,405 1,895 0 0 3,964 

Oil tanks N/A N/A 0 0 14,357 20,722 0 0 165 165 2,430 

Dehydrators 33 88 506 332 19,470 30,665 2,929 2,371 14 10 11,372 

Well 

completions 

664 850 1,174 1,428 278 383 12,279 5,457 0 0 14,492 

Well blowdowns 22 26 1,744 2,207 292 460 2,172 2,444 0 0 13,145 

Fugitives 26 29 8,024 10,498 1,910 3,212 1,330 1,871 0 0 4,137 

Pneumatic 

devices & pumps 

460 533 12,381 16,342 23,301 39,404 2,532 3,835 0 0 1,726 

NOx 

Compressor 

engines 

N/A N/A 11,506 12,625 2,207 3,169 5,705 6,497 4,947 3,362 35,545 

Drill rigs 20,236 25,962 5,152 6,267 4,779 4,773 5,382 1,668 225 249 848 

*Haynesville shale emission estimates for 2012 under moderate and aggressive development scenarios. The moderate scenpresence of 37 drill rigs each drilling 5.8 wells a year with a success rate of 55%. The aggressive scenario assumes the preHaynesville emissions are scaled from estimated tons per day to annual emissions by multiplying by 365. **VOC emission estimates in the Haynesville Shale and N. San Juan basin are substantially smaller than for other areas inv

nature of the respective resources. The Haynesville formation primarily produces dry natural gas, with no significant quan

Therefore, VOC emissions are low and there are no emissions associated with condensate tanks or oil tanks. Similarly, the in the N. San Juan is coal-bed methane which also has a low VOC content. 

1 
2 

Table 2: 2006 Oil and Gas Production Data for Six Intermountain West Basins and NOx and V(TPY)Basin Spud count Well count Oil 

production (bbl) 

Gas production (mcf) 

NOx emissions (tpy) 

VOC emissions (tpy) 

DenverJulesburg 1,500 16,774 14,242,088 234,630,779 20,783 81,758Uinta 1,069 6,881 11,528,121 331,844,336 13,093 71,546Piceance 1,186 6,315 7,158,305 421,358,666 12,390 27,464North San Juan 

127 2,676 32,529 443,828,500 5,700 2,147

South San Juan 

919 20,649 2,636,811 1,020,014,851 42,075 60,697

Wind River 98 1,350 3,043,459 198,190,024 1,814 11,981
1

Appendix B: Comparison of oil and gas air regulations federal, Wyoming, 

Colorado, Montana, Utah, and California. 

Source EPA WY CO Other Emission 

Reduction 

Technology/Action

Pneumatic devices No Broad 

Coverage. 

Operators 

must use low 

or no-bleed 

devices or 

route 

discharge 

streams to 

closed loop 

systems. 

Broad Coverage. 

New and existing 

controllers in ozone 

nonattainment (NA) and 

nonattainment/maintenance 

areas (NA/M) must be lowbleed. 

Statewide, new, replaced 

or repaired devices must be 

low or no-bleed. 

Proposal. 

CA has 

proposed 

requirements 

substituting 

high-bleed 

with lowbleed 

devices. 

Replace high bleed 

devices with low or 

no-bleed devices. 

Route discharge 

streams to closed 

loop systems. 

Well venting during 

completions and recompletions 

No Broad 

Coverage. 

Must use 

green 

completions 

in JPAD 

Areas and 

CDAs.1

Broad Coverage. 

Must use green 

completions where 

technically and 

economically feasible. 

MT requires 

control of 

VOC vapors 

greater than 

200 British 

thermal 

units per 

cubic foot 

emitted from 

oil and gas 

wellhead 

equipment 

to be routed 

to a gas 

pipeline or 

smokeless 

combustion 

device 

equipped 

with an 

electronic 

ignition 

device or 

continuous 

pilot system. 

Green completions. 

Glycol dehydrators Limited 

Coverage. 

Large 

dehydrators 

located at 

major 

Broad 

Coverage. 

All new and 

existing 

dehydrators 

Broad Coverage. 

Dehydrators located at all 

O&G E&P sites, natural 

gas compressor stations, 

drip stations, or gas 

processing plants with 

No Install still vent 

condensers, glycol 

flash separators or 

utilize combustion 

device capable of 

98% destruction 

efficiency. 

                                                            1 JPAD refers to the Jonah and Pinedale Anticline Development Area.  CDA refers to other Concentrated

Development Areas.   
2

sources in 

the 

production, 

and and 

transmission 

categories 

must install 

MACT. 

Large glycol 

dehydrators 

located area 

sources in 

the 

production 

category 

near urban 

areas must 

install 

MACT. All 

other large 

dehydrators 

must comply 

with GACT. 

in JPAD 

regardless of 

total 

potential or 

actual 

emissions 

must control 

HAPs and 

VOCs by 

98%. 

All new and 

existing 

dehydrators 

in CDAs and 

statewide 

must control 

HAPs and 

VOCs by 

98% upon 

first date of 

production 

(FDOP). 

Controls may 

be removed 

after one 

year if 

emissions <6 

tpy and units 

are equipped 

with still 

vent 

condensers .2

actual VOC emissions ≥15 

tpy must be controlled by 

90% . 

Dehydrators with PTE 5 

tpy VOCs located within 1⁄4 

mile of public place in 

Garfield, Mesa and Rio 

Blanco counties must 

control emissions by 90% . 

Condensate tanks Limited 

Coverage. 

Large 

condensate 

tanks with 

the potential 

for flash 

emissions 

located at 

major 

sources in 

the 

Broad 

coverage. 3

CDAs and 

JPAD: New 

and modified 

facilities 

must control 

VOC flash 

emissions by 

98% upon 

FDOP. May 

remove 

Broad Coverage. 

All tanks with PTE 5 tpy 

VOCs located within 1⁄4 

mile of public place in 

Garfield, Mesa and Rio 

Blanco counties must 

control VOC emissions 

with a device capable of 

achieving 95% control 

efficiency. 

Tanks under common 

Limited 

Coverage 

MT requires 

control of 

VOC vapors 

greater than 

200 British 

thermal 

units per 

cubic foot 

emitted from 

tanks with 

Install vapor 

recovery systems, 

route emissions to 

control or capture 

device such as 

pipeline or flare. 

                                                                                                                                                                                    2

  Alternatively, upon FDOP units must be equipped with reboiler still vent condensers and glycol flash separators. 

If , after 30 days, potential VOCs > 8 tpy, units must install combustion control capable of reducing emissions by 

98%. After one year, combustion unit may be removed if total potential VOC emissions < 8 tpy. 3

 In Wyoming, the requirements listed for condensate tanks also apply to separation vessels (e.g.: gun barrels, 

production and test separators, production and test treaters, water knockouts, gas boots, flash separators, drip pots). 
3

production 

category 

Does not 

apply to 

facilities that 

exclusively 

handle, 

process or 

store black 

oil. 

controls after 

one year if 

emissions < 

8 tpy 

Statewide: 

New and 

modified 

facilities 

must control 

VOC flash 

emissions 

≥10 tpy by 

98% upon 

FDOP. May 

remove 

controls after 

one year if 

emissions < 

8 tpy. 

ownership or operation in 

NA, NA/M with 

cumulative emissions ≥30 

tpy must meet declining 

percent reductions using 

device capable of 

achieving 95% control 

efficiency. 

All new or modified tanks 

in NA, NA/M with VOC 

emissions greater than 1 

TPY must control 

emissions during the first 

90 days with controls 

capable of achieving 95% 

control efficiency. 

Single tanks or tanks 

collocated together 

statewide that emit > 20 

tpy of VOCs must utilize 

controls capable of 

achieving 95% control 

efficiency. 

PTE 15 tpy 

VOCs or 

more. 

Crude oil tanks Limited 

Coverage. 

See 

condensate 

tanks. 

Broad 

coverage. 

See 

condensate 

tanks. 

Limited Coverage. 

For tanks in Piceance 

basin, see condensate 

tanks. 

Limited 

Coverage. 

See 

condensate 

tanks. 

Install vapor 

recovery systems or 

equipment capable 

of achieving 95% 

control efficiency. 

 

Produced water tanks No Broad 

coverage. 

See 

condensate 

tanks. 

Limited Coverage. 

For tanks in Piceance 

basin, see condensate 

tanks. 

No Install vapor 

recovery systems 

Production/Processing 

fugitive emissions 

Limited 

Coverage. 

VOC & HAP 

emissions 

from certain 

equipment at 

gas 

processing 

plants are 

subject to 

LDAR.

No No Proposal. 

CA has 

proposed 

improved 

LDAR, 

equipment 

replacement 

and 

upgrades. 

LDAR and 

equipment 

replacement. 
4

Compressors Limited 

Coverage. 

Nonreciprocating 

compressors 

located at 

gas 

processing 

plants 

subject to 

LDAR and 

add-on 

controls to 

control 

HAPs and 

VOCs. 

No No Proposal. 

CA has 

proposed 

requirements 

to replace 

rod packing 

systems and 

reduce 

emissions 

when 

compressors 

are taken 

off-line. 

Replace rodpacking/ 

LDAR/reduce 

emissions when 

taken off-line 

Pneumatic pumps No Broad 

Coverage. 

Upon FDOP 

must control 

all VOC and 

HAP 

emissions 

associated 

with 

discharge 

streams by 

98% or 

route to 

closed loop 

system. 

No No Replace gaspowered pumps 

with solar, electric, 

or air-driven 

pumps. Flare or 

route gas to closed 

loop system (i.e. 

sales line, 

collection line, fuel 

supply line)