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BY CERTIFIED MAIL 

RETURN RECEIPT REQUESTED 

November 23, 2010 

Lisa Jackson, Administrator 

U.S. Environmental Protection Agency 

Ariel Rios Bldg. 

1200 Pennsylvania Ave., NW 

Washington, D.C. 20460 

Re: Opportunities to Reduce Methane Emissions from Oil and Gas Operations 

through the New Source Performance Standards, EPA-HQ-OAR-2010-0505-

0001 

Dear Administrator Jackson: 

Enclosed please find an expert report detailing the tremendous opportunities to reduce methane 

emissions from the oil and gas sector under the Clean Air Act. The U.S. Environmental 

Protection Agency (“EPA”) is currently reviewing whether to update the New Source 

Performance Standards (“NSPS”) and National Emissions Standards for Hazardous Air 

Pollutants (“NESHAP”), and whether to promulgate residual risk standards for the oil and gas 

sector. See Docket EPA-HQ-OAR-2010-0505-0001. It is our hope that this report can guide the 

Agency as it completes its review and proposes future action, particularly with regards to the 

NSPS. 

The report, which was prepared by Cindy Copeland and Megan Williams1

 for Earthjustice on 

behalf of WildEarth Guardians and San Juan Citizens Alliance, provides a critical roadmap for 

achieving at least a 90% reduction in methane, if not greater, from oil and gas operations 

nationwide using demonstrated practices and technologies. Such reductions promise a number 

of benefits: reduced greenhouse gas emissions, increased savings for industry, decreased safety 

risks, and a number co-benefits, including reductions in air toxics, ozone precursors, and greater 

overall protection for public health and welfare. Above all, these reductions would just make 

good business sense. They would encourage greater efficiency, reward those companies that 

have already mobilized methane reduction practices and technologies, and fuel the creation of 

jobs within the air pollution control sector. The benefits cannot be overstated. A 90% reduction 

in methane emissions from the oil and gas sector has the potential to recover more than $1 

billion in lost value every year.

We urge you to take into consideration the findings of this report and to seize this opportunity to 

achieve significant, sector-wide reductions in methane through the NSPS. Specifically, we urge 

you to set concrete limits on methane emissions based on the available control technologies and 

 

1

 See CVs for Ms. Copeland and Ms. Williams, attached. 
Letter to Administrator Jackson re: Opportunities to Reduce Methane Emissions from Oil and Gas Sector Page 2 

November 23, 2010 

practices outlined in the enclosed report. We further urge you to set a nationwide goal of 

reducing methane emissions by 90% or more from the oil and gas sector. The EPA’s duty and 

authority to establish such standards and goals is firmly supported by the Clean Air Act. 

As you know, the Administrator has a duty to address the issue of methane emissions through the 

NSPS. It is already recognized that the oil and gas source category releases air pollution 

anticipated to endanger public health and welfare. Furthermore, the EPA has definitively found 

that greenhouse gases, including methane, pose an endangerment to public health and welfare. 

See 74 Fed. Reg. 66496 (Dec. 15, 2009). In light of these facts, the Administrator has clear 

authority to promulgate “a standard for emissions of [methane] which reflects the degree of 

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

which ... the Administrator determines has been adequately demonstrated.” 42 U.S.C. 

§ 7411(a)(1). 

The Administrator also has a duty to regulate methane emissions from existing sources in 

accordance with Section 111(d) of the Clean Air Act. See 42 U.S.C. §§ 7411(d)(1)(A)(i) and 

(ii); 40 C.F.R. § 60.21(a). Therefore, we urge the Administrator to ensure that existing sources 

of methane are addressed as appropriate under Section 111(d). 

We appreciate your attention to this issue and your commitment to comprehensively reviewing 

the opportunities available for controlling harmful air pollution from the oil and gas sector. It is 

fortunate that there exists a wealth of proven options to cost-effectively control emissions. We 

urge you to ensure that any revised NSPS ensure concrete reductions in methane consistent with 

what we know works. If you or your staff have any questions about this report, please contact 

me at 303-996-9622. Thank you. 

Sincerely, 

Edward B. Zukoski, Staff Attorney 

Attorney for WildEarth Guardians and San Juan Citizens Alliance 

Cc: Gina McCarthy, Deputy Administrator for Air and Radiation 

 Bruce Moore, Senior Technical Advisor, Oil and Natural Gas Sector, Office of Air 

Quality Planning and Standards 

Encs. (1) Report; (2) Cindy Copeland CV; and (3) Megan Williams CV. 
METHANE CONTROLS 

FOR THE OIL AND GAS PRODUCTION SECTOR 

prepared by Megan Williams and Cindy Copeland 

November 23, 2010 

I. INTRODUCTION AND SUMMARY OF RECOMMENDATIONS 

Due to rapidly increasing and widespread oil and gas development across the country and due to 

the extraordinarily high levels of greenhouse gases and air pollutants emitted from this 

development, there is an urgent need for strong protective standards to be established for the oil 

and natural gas sector. 

Oil and natural gas production are included in the EPA’s priority list of categories set forth at 40 

CFR § 60.16, pursuant to section 111(b)(1)(A) of the Clean Air Act, which in the 

Administrator’s judgment, cause or contribute “significantly to, air pollution which may 

reasonably be anticipated to endanger public health or welfare.”1

 On June 24, 1985, EPA 

promulgated New Source Performance Standards (NSPS) for Equipment Leaks of volatile 

organic compounds (VOCs) from Onshore Natural Gas Processing Plants (40 CFR part 60, 

subpart KKK) and on October 1, 1985, EPA promulgated a NSPS for SO2 emissions from 

Onshore Natural Gas Processing (40 CFR part 60, subpart LLL). EPA has failed to promulgate 

more comprehensive standards for the much broader source category of oil and natural gas 

production (including both onshore and offshore development) and has failed to update, as 

required by law, the two standards it did promulgate. In response to a January 14, 2009 lawsuit 

brought by WildEarth Guardians and San Juan Citizens Alliance, EPA agreed to a consent 

decree whereby it would review and propose necessary revisions and expansions to the NSPS for 

the oil and natural gas production sector by January 31, 2011, and finalize standards by 

November 30, 2011.2

 

A critical component of EPA’s review and revision of the NSPSs for oil and gas operations is the 

development of standards for the reduction of methane emissions from the oil and gas sector. 

Methane is a potent greenhouse gas, roughly 20 times more powerful at warming the atmosphere 

than carbon dioxide by weight, and with a relatively short atmospheric lifetime of about 12 

years. Methane, thus, is a prime contributor to short-term climate change over the next few 

decades. 

There are many proven technologies and practices already available to reduce significantly the 

methane emissions from oil and gas operations. These technologies also offer opportunities for 

significant cost-savings from recovered methane gas. Methane is often expressly exempt from 

state regulations since greenhouse gases (GHGs) are not yet federally regulated as an air 

pollutant. EPA must fill this void by proposing comprehensive regulations for methane. EPA’s 

inclusion of methane performance standards and operating practices for oil and gas would be a 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

1 42 U.S.C. § 7411(b)(1)(A).

2 See Consent Decree, WildEarth Guardians v. Jackson, 1:09-cv-00089-CKK (D.D.C), Dkt. Entry # 25 (Feb. 4, 

2010). 
"

cornerstone in a comprehensive regulatory framework for methane emissions reductions across 

the U.S. 

We respectfully urge EPA to expeditiously develop and apply New Source Performance 

Standards for new and modified oil and gas sources that achieve at least a 90% reduction in 

methane emissions. EPA’s own voluntary Natural Gas STAR program provides an excellent 

opportunity to build from the wealth of knowledge and information regarding methane reduction 

control technologies for every component of the oil and gas sector. Based on the demonstrated 

effectiveness of many of these key control technologies, EPA should require at least 90% 

reduction in methane emissions from sources among this sector, and in some cases reductions 

greater than 90% are warranted. A framework to achieve at least a 90% reduction in methane 

emissions from oil and gas sources is laid out in this report. 

As the oil and gas sector continues to grow, more sources of methane emissions are added each 

year. These new emissions sources include a certain percentage that replace existing sources 

(e.g., new compressor engines that replace old ones) and a certain percentage that add to the total 

population. Progress in reducing emissions through standards for new and modified sources 

depends on the rate at which new emissions sources are added to the population and on the level 

of reductions implemented. The higher the level of control required, the sooner meaningful 

emissions reductions will be achieved. A 90% sector-wide reduction in emissions might still take 

years to achieve depending on how quickly new sources penetrate the source population. 

Therefore, it is imperative that EPA establish the highest level of emissions reductions possible 

for new and modified sources in the oil and gas sector. 

There are numerous existing control technologies for oil and gas emission sources that achieve a 

90% or greater control efficiency for reducing methane emissions. For example, compressor rodpacking technologies can reduce methane emissions by more than 90%, the use of no bleed 

pneumatic devices can practically eliminate methane emissions, the use of dry seals in 

centrifugal compressors can reduce methane emissions by 99%, zero emission dehydrators 

virtually eliminate methane emissions, and the use of vapor recovery units at crude oil and 

condensate storage tanks can reduce methane emissions by at least 98%. In addition, there are 

multiple examples of existing emissions reduction programs at the state, county, and 

international levels that require methane emissions reductions of 90% or greater from oil and gas 

sources. 

The following is a listing of the methane control technologies and measures recommended in this 

report. These controls were chosen because they would achieve the maximum emission 

reductions possible using available technologies or practices. The recommendations are listed by 

major oil and gas source type. 

Recommended methane controls for pneumatic devices: 

! Require Pneumatic Devices That Use Instrument Air or Mechanical Controls, Nitrogen 

Gas, or Electric Valve Controllers in Place of Gas Powered Pneumatic Devices 

! Require Low-Bleed Pneumatic Devices for New Installations and Require Modified 

Sources to Retrofit High-Bleed Devices with Low-Bleed Devices 
#

Recommended methane controls for compressors: 

! Require the Use of State-of-the-Art Compressor Rod-Packing Technology 

! Require the Use of Dry Seals in Centrifugal Compressors 

! Require the Use of Air or Electric Starters Instead of Gas Starters 

! Require the Use of State-of-the-Art Compressor Cylinder Unloader Technology and 

Require Regular Replacement 

! Require Operating Practices That Eliminate or Reroute Gas Leakage When Taking 

Compressors Off-line 

! Require Direct Inspection and Maintenance at Compressor Stations 

! Require Isolation Valves To Be Installed in Close Proximity to Compressors For All New 

Installations 

Recommended methane controls for dehydrators: 

! Require the Use of Zero Emission Dehydrators 

! Require the Use of Solid Desiccant Dehydrators in Cases Where Zero Emission 

Dehydrators Are Not Feasible 

! Require Glycol Dehydrators to Use Vapor Recovery Units 

! Require the Use of Flash Tank Separators 

! Require Circulation Rate Adjustment Practices for All Glycol Pumps 

! Require Glycol Dehydrators to Use Portable Desiccant Dehydrators During Maintenance 

! Require Installation of BASO® Valves 

Recommended methane controls for tanks: 

! Require the Use of Vapor Recovery Units With at least 98% Control Efficiency for All 

New Crude Oil and Condensate Storage Tanks 

Recommended methane controls for wells: 

! Require the Use of Reduced Emissions Completions or Green Completions 

! Require the Installation of Plunger Lift Systems and the Development of Operational 

Practices that Minimize Methane Emissions 

! Require the Installation of Downhole Separator Pumps, Where Applicable 

! Require Mud Degassing Vents Be Routed to a Vapor Recovery Unit 

Recommended methane controls for pipelines: 

! Require the Use of Gas Main Flexible Liners and State-of-the-Art Pipeline Material and 

Protective Coatings 

! Require Maintenance Practices for Pipelines 

! Require the Installation of Excess Flow Valves on All Gas Service Lines 

Recommended methane controls for flares: 

! EPA should require producers to reduce emissions by instituting a gas utilization 

program, such as sending emissions to a vapor recovery unit, rather than flaring and 

venting.
$

Recommended methane controls for directed inspection and maintenance practices: 

! EPA should require that operators implement directed inspection and maintenance 

programs and good work practices in all possible sectors in order to detect and reduce 

methane emissions. 

There is a large body of scientific work documenting the adverse impacts to public health and 

welfare from climate change caused by GHG emissions, such as methane. More recently, 

scientific studies have also demonstrated that these same methane emissions contribute to the 

formation of ground-level ozone, a harmful air pollutant that impacts the health of millions of 

Americans.3

 Specifically, the U.S. Climate Change Science Program recently reported that 

methane reductions accomplish the dual goal of addressing climate change and ozone pollution.4

Methane reductions achieved through new source performance standards and practices will have 

a direct impact on both climate change and ozone pollution. 

Many of the methane emission controls for the oil and gas sector also reduce VOCs and 

hazardous air pollutants (HAPs), while some controls also have the added benefit of improving 

safety at the sources. State, local and international programs that aim to reduce VOCs and HAPs 

and are reviewed in this report because of the co-benefit any such reductions would have for 

reducing methane emissions. Any strategy to limit the amount of VOC or HAP emissions from 

oil and gas processes would also reduce methane emissions. And conversely, regulatory 

reductions in methane emissions will also reduce VOC and HAP emissions. The associated air 

quality benefits that result from reductions in VOC and HAP emissions are a huge co-benefit of 

methane reduction technologies. 

VOCs are an important component in the formation of ozone. Ozone pollution causes breathing 

problems, chest pain and even permanent lung damage after repeated exposure. Oil and gas 

sources are major contributors to ozone problems in areas of highly concentrated development, 

such as western Wyoming, where sparsely populated Sublette County is a proposed ozone 

nonattainment area.5

 Most of the VOCs emitted from oil and gas sources are also hazardous air 

pollutants. HAPs present in oil and gas development include benzene, toluene, ethylbenzene, 

xylene and n-hexane, which cause a wide array of adverse health impacts, including cancer and 

other serious illnesses.6

 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

3 See, e.g., 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, April 30, 2008, p.1 (“[I]n 

the presence of nitrogen oxides (NOx), tropospheric CH4 [methane] oxidation leads to the formation of O3

[ozone].”)

4 See 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”, 

September 2008, p. 65, http://www.climatescience.gov/Library/sap/sap3-2/final-report/ (finding that reducing 

methane emissions “lead[s] to reduced levels of atmospheric ozone, thereby improving air quality” and “lead[s] to 

reduced global warming”).

5

 See Wyoming Department of Environmental Quality at 

http://deq.state.wy.us/aqd/Ozone%20Nonattainment%20Information.asp 6

 see EPA, http://www.epa.gov/airquality/oilandgas/basic.html 
%

California’s Proposed Greenhouse Gas Reduction Plan is an Example of a Comprehensive 

Mandatory Approach to Greenhouse Gas Reductions 

California is currently working to require GHG emissions reductions in a broad sweeping plan. 

In 2011, the California Air Resources Board (CARB) will consider a historic proposal to limit 

GHG emissions from every sector in the state. If approved, this measure will be implemented in 

2012.7 CARB’s Climate Change Scoping Plan aims to achieve greenhouse gas reductions in oil 

and gas extraction and transmission. These strategies will use proven technologies from EPA’s 

Natural Gas STAR program, but the program will be mandatory rather than voluntary. The 

control measures for the oil and gas extraction sector will 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.” The GHG control technologies for the oil and 

gas transmission sector will include “improving operating practices to reduce emissions when 

compressors along the pipeline are taken off-line, as well as installing compressor rod packing 

systems and replacing older equipment (flanges, valves and fittings) along the pipelines.”8

 

California’s oil and gas sector includes onshore and offshore operations. The Oil and Gas 

Extraction GHG Emission Reduction measure targets fugitive emissions (which are mostly 

methane) from extraction sources; these emissions are estimated to be 0.3 million metric tons 

CO2 equivalent (MMTCO2e) in 2020 and currently account for approximately 5% of the GHG 

emissions from this sector. With these estimates, CARB acknowledges that while historical 

trends are used for calculations, this sector could see even more growth in the future with 

increased oil extraction as a result of increased crude oil prices. The oil and gas extraction 

emission reduction measures are projected to result in a 0.2 MMTCO2e emissions decrease per 

year beginning in 2015, a 67% reduction in emissions.9 The 2020 inventory projections for the 

oil and gas transmission category are 1.7 MMTCO2e and the implementation of the scoping plan 

will reduce emissions by 0.9 MMTCO2e, a greater than 50% reduction in emissions.10 These 

planned GHG emission reduction measures will result in significant economic benefits. The cost 

savings for the oil and gas GHG reduction extraction measures are expected to be $3.7 million 

annually, while the reduction measures for oil and gas transmission are projected to save $17 

million annually.11 

California’s efforts to reduce GHG emissions from all sources across the state is evidence that 

technology standards and practices are available to support mandatory reductions. 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

7

 California Air Resources Board, Scoping Plan Measures Implementation Timeline, July 1, 2010, 

http://www.arb.ca.gov/cc/scopingplan/sp_measures_implementation_timeline.pdf. & “Climate Change Scoping Plan Appendices, Volume 1: Supporting Documents and Measure Detail, a framework 

for change,” California Air Resources Board, December 2008, pp. C-153 and C-154, 

http://www.arb.ca.gov/cc/scopingplan/document/appendices_volume1.pdf#page=184. ' Id. p. C-153. 10 Id. pp. C-153 and C-154. 11 Id.
(

II. REVIEW OF METHANE EMISSIONS CONTROLS BY MAJOR OIL AND GAS 

SOURCE TYPE 

This section provides a review of currently available technologies and practices, as well as 

existing regulatory initiatives, to reduce methane emissions for each of the following major oil 

and gas source types: pneumatics, compressors, dehydrators, tanks, wells, pipelines and flares. 

The section ends with a more general section on the value of directed inspection and 

maintenance practices. 

In general, methane emissions occur across all sectors of the natural gas industry (i.e., 

production, processing, transmission and distribution) in both onshore and offshore applications. 

Emissions occur during normal operations and routine maintenance events and also as a result of 

leaks and system upsets. Fugitive emissions occur as a result of both intentional venting and 

unintentional leakage. In addition to natural gas operations, methane emissions also occur in the 

oil industry, primarily from field production operations (e.g., the venting of associated gas from 

oil wells), oil storage tanks, and production-related equipment (e.g., gas dehydrators and 

pneumatic devices). The following subsections discuss the multiple control technologies 

available to significantly reduce the methane emissions of a particular source (e.g., venting from 

the device, leaks, offshore applications, etc.).

A. Pneumatic Devices 

Pneumatic devices are used in all sectors of the oil and natural gas industry for liquid level 

controllers, pressure regulators and valve controllers. Such devices are typically powered by 

natural gas, although some are powered by electricity or compressed air. The natural gas 

powered devices vent large amounts of methane to the atmosphere as part of their normal 

operations. There are 3 main types of pneumatic devices in use in the natural gas industry, which 

include: (1) continuous bleed devices that generally bleed natural gas continuously and act to 

modulate flow, liquid level or pressure; (2) actuating or intermittent bleed devices that open and 

close, releasing gas to the atmosphere periodically; and (3) self-contained controllers that do not 

release any gas to the atmosphere, sending the gas downstream instead. The Natural Gas STAR 

Program defines any pneumatic device that bleeds over 6 standard cubic feet per hour (scfh) of 

natural gas as a high-bleed device. The Natural Gas STAR Program states: 

In general, the bleed rate will also vary with the pneumatic gas supply pressure, 

actuation frequency, and age or condition of the equipment. Due to the need for 

precision, controllers that must operate quickly will bleed more gas than slower 

operating devices. The condition of a pneumatic device is a stronger indicator of 

emission potential than age; well-maintained pneumatic devices operate 

efficiently for many years.12

The production sector includes by far the largest number of gas powered pneumatic devices, 

estimated at around 400,000.13 Pneumatic devices are the largest source of methane emissions 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

12 Lessons Learned, Natural Gas STAR Partners, “Options for Reducing Emissions from Pneumatic Devices in the 

Natural Gas Industry,” October 2006, p. 4, http://www.epa.gov/gasstar/documents/ll_pneumatics.pdf. 13 Id., p. 2.
)

from the oil and natural gas production sector, totaling an estimated 43 Bcf—or 35 percent— of 

all production-based emissions (based on 2009 data).14 In this sector, controllers are used to 

regulate temperature in dehydrator regenerators, regulate pressure in flash tanks and control and 

monitor gas and liquid flows and levels in dehydrators and separators. The transmission sector is 

the second largest sector for methane emissions from pneumatic devices, with an estimated 

85,000 devices used to “actuate isolation valves and regulate gas flow and pressure at 

compressor stations, pipelines, and storage facilities.”15 Pneumatic devices in the transmission 

sector account for an estimated 11 Bcf of methane annually (based on 2009 data).16 Around 

13,000 of the pneumatic devices are used in the processing sector at gas gathering and booster 

stations for compressor and glycol dehydration control and at processing plants for isolation 

valves.17

Emissions from natural gas driven pneumatic valve and pump devices are known to be major 

contributors to fugitive emissions from the oil and gas production sector. Yet, the emission 

factors used to estimate overall emissions from pneumatic devices may underestimate emissions 

from this source category. Reported uncertainties can range from ±33% to ±407%.18 In addition 

to the uncertainty in inventory estimates, the sheer number of pneumatic devices makes this a 

particularly important source category to focus on. Emissions reductions from the hundreds of 

thousands of pneumatic devices used throughout the oil and gas sector have the potential to 

greatly influence overall emissions and associated impacts. The magnitude and importance of 

this emissions source should also drive a greater emphasis on compliance via direct measurement 

(e.g., metering), rather than compliance based on engineering estimates (e.g., Original 

Equipment Manufacturer (OEM) emission factors). EPA should require installation of gas meters 

at new installations in order to monitor instrument gas consumption and provide an accurate 

determination of methane emissions. 

1. Existing State Programs to Reduce Methane Emissions from Pneumatic 

Devices

The following state programs demonstrate that mandatory controls for reducing methane 

emissions are possible. EPA should consider these standards as minimum requirements for 

regulating sources under the NSPS. Regulations aimed at reducing VOCs and HAPs are relevant 

to consider because of the corresponding reductions in methane emissions that are achievable 

through implementation of these control technologies and practices. 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

14 EPA Natural Gas STAR, http://www.epa.gov/gasstar/basic-information/index.html#sources. 15 Lessons Learned, Natural Gas STAR Partners, “Options for Reducing Emissions from Pneumatic Devices in the 

Natural Gas Industry,” October 2006, p. 2.

16 EPA Natural Gas STAR, http://www.epa.gov/gasstar/basic-information/index.html#sources. 17 Lessons Learned, Natural Gas STAR Partners, “Options for Reducing Emissions from Pneumatic Devices in the 

Natural Gas Industry,” October 2006, p. 2.

18 See, e.g., API Compendium of Greenhouse Gas Emissions Methodologies For the Oil and Natural Gas Industry, 

August 2009, Table 5-15, pages 5-68 and 5-69, 

http://www.api.org/ehs/climate/new/upload/2009_GHG_COMPENDIUM.pdf.
&

Colorado 

The Colorado Department of Public Health and Environment’s Air Pollution Control Division 

addresses oil and gas related ozone issues in Regulation Number 7, which controls VOCs and 

nitrogen oxides (NOX) for the 1-hour and 8-hour ozone nonattainment or attainment/maintenance 

areas, as well as statewide. Under these regulations, all new pneumatic devices are required to be 

low-bleed and existing high-bleed (any device that emits more than 6 standard cubic feet per 

hour (scfh)) pneumatic devices must be replaced or retrofitted to meet the state’s low-bleed 

specifications of 6 or fewer scfh of natural gas.19 This regulation is aimed at reducing VOC 

emissions, but methane emissions are reduced as a co-benefit of the requirements.20 For the rest 

of the state, new, replaced or repaired pneumatic devices are required to install low-bleed valves, 

where technically feasible.21

Wyoming 

The Wyoming Department of Environmental Quality’s permitting requirements cover pneumatic 

pumps and controllers. While the main goal of the state’s rules is to reduce VOC and HAP 

emissions, methane reductions are a co-benefit of the controls. Wyoming’s most restrictive 

requirements for pneumatic pumps apply to the Jonah and Pinedale Anticline Development Area, 

where pneumatic heat trace pumps and other pneumatic pumps at all new and modified facilities 

must meet a 98% control requirement for VOC and HAP emissions.22

In addition, Wyoming’s requirements for new facilities with natural gas operated pneumatic 

controllers, or new natural gas operated pneumatic controllers at modified facilities, dictate that 

such controllers must be low or no-bleed (where low bleed is 6 scfh or less) or the controller 

discharge stream must be routed to a closed loop system. For modifications at facilities with 

existing pneumatic controllers, the devices must be replaced or converted in order to meet the 

same requirements for new facilities within 60 days of modification.23

California 

CARB’s proposed GHG rules (described above) include control measures for pneumatics to 

replace high-bleed devices with low-bleed bleed devices.24

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

19 There are certain exceptions to these requirements for high-bleed pneumatic controllers that need to remain in 

place due to safety issues.

20 Colorado Department of Public Health and Environment, Air Quality Control Commission, Regulation Number 7, 

“Control of Ozone Via Ozone Precursors (Emissions of Volatile Organic Compounds and Nitrogen Oxides),” 5 

CCR 1001-9.

21 Colorado Code of Regulations, 2 CCR 404-1 “Practice and Procedure,” §805 b(2)E, 

http://www.sos.state.co.us/CCR.

22 Wyoming DEQ, C6 S2 O&G Production Facilities Permitting Guidance, March 2010, p. 19.

23 Id, 10, 19. 24 “Climate Change Scoping Plan Appendices, Volume 1: Supporting Documents and Measure Detail, a framework 

for change,” California Air Resources Board, December 2008, C-153, 

http://www.arb.ca.gov/cc/scopingplan/document/appendices_volume1.pdf#page=184.
'

2. Available Proven Technologies for Pneumatic Devices

EPA’s own Natural Gas STAR program demonstrates that there are many currently available, 

technically feasible, and cost-effective technologies that can greatly reduce methane emissions 

from pneumatic devices. EPA should, at a minimum, require the following technologies and 

operating practices as part of its revised NSPS for oil and natural gas systems. 

Require Pneumatic Devices That Use Instrument Air or Mechanical Controls, Nitrogen Gas, or 

Electric Valve Controllers in Place of Gas Powered Pneumatic Devices 

The installation of pneumatic controls that use instrument air rather than gas powered low-bleed 

or no-bleed devices can achieve 100% methane emission reductions. Many Natural Gas STAR 

partners have realized economic benefits from switching to instrument air. This technology can 

be used where electrical power is available, or to further reduce energy demands and to expand 

possible usage, instrument air devices can be converted to solar-powered, battery-operated 

devices. Several Natural Gas STAR partners have had success with this option.25

In addition to economic benefits from using instrument air, natural gas companies can achieve an 

extended life for control devices and improve operational efficiencies beyond that of gas 

powered devices. Significant safety improvements are also realized since flammable natural gas 

is no longer used for this process, which is of particular importance at offshore operations where 

there are greater risks from flammable and hazardous materials.26 

Pneumatic controllers can also employ mechanical control, nitrogen gas, or electric valve 

controllers. Some Natural Gas STAR partners have reported success with the use of mechanical 

controls in remote, non-electrified production, processes, transmission and distribution sites. 

“The most common mechanical control device is a level controller, which translates the position 

of a liquid-level float to the drain valve position with mechanical linkages. There is no gas usage 

in either the process measurement or valve actuation, and reliability is very high.”27 Use of 

nitrogen gas or electric valve controllers are additional alternatives to gas pneumatics, although 

they each present significant limitations.28

CARB lists replacing gas powered pneumatic devices with compressed air systems or nitrogen 

gas as a Best Management Practice (BMP) for oil and gas sources.29 EPA should require that all 

new pneumatic device installations use instrument air, powered either by electricity of solar 

energy or use mechanical controls, nitrogen gas or electric valves if instrument air is not feasible. 

All modified sources should be required to convert gas powered pneumatic control devices to 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

25 EPA, “Solar Power Applications for Methane Emissions Mitigation: Lessons Learned from the Natural Gas 

STAR Program,” 8/31/2009, 15-23.

26 Id. 5,6. 27 Lessons Learned, Natural Gas STAR Partners, “Convert Pneumatics to Mechanical Controls,” September 2004, p. 

1 & 2.

28 Lessons Learned, Natural Gas STAR Partners, “Convert Gas Pneumatic Controls to Instrument Air,” October 

2006, p. 15.

29 The California Air Resources Board’s Clearinghouse of non-CO2 Greenhouse Gas Emission Control 

Technologies, http://www.arb.ca.gov/cc/non-co2-clearinghouse/non-co2-clearinghouse.htm. 
*+

meet the standards for new sources. Reductions in methane emissions of 100% would be 

expected from this technology. 

Require Low-Bleed Pneumatic Devices for New Installations and Require Modified Sources to 

Retrofit High-Bleed Devices with Low-Bleed Devices 

Methane emission reductions can be achieved by requiring low-bleed devices in place of highbleed natural gas powered pneumatic devices, and by improving maintenance in order to reduce 

methane emissions. Installing low-bleed pneumatic devices instead of high-bleed devices is a 

cost-effective methane reduction strategy. Depending on the device installed, annual savings 

from emission reductions can vary from $315 to $1820 and the cost of installation is often 

recovered in one year.30 For example, the installation of a low-bleed liquid level controller, at an 

initial $513 for the unit, would save $1165 annually.31 For any new and modified installations 

where non-gas powered pneumatic devices are not feasible, EPA should require the use of lowbleed devices. 

For modified sources, switching high-bleed pneumatic devices to low-bleed involves replacing, 

retrofitting and maintaining the devices and using all or one of these strategies in order to 

achieve the low-bleed rate of less than 6 scfh natural gas (over 50 Mcf/year). Significant savings 

and methane emission reductions have been achieved by Natural Gas STAR partners who have 

implemented these strategies.32 Replacing, retrofitting and maintaining pneumatic devices also 

has the added benefit of increasing operational efficiencies for the devices by improving both 

system-wide performance and reliability, and monitoring of parameters such as gas flow, 

pressure, or liquid level.33 

EPA should require that any new pneumatic devices that must be gas-powered be low-bleed or 

that modified devices be replaced or retrofitted to meet low-bleed criteria. As discussed above, 

the states of Colorado and Wyoming already have programs in place for requiring low-bleed 

pneumatic devices and California is currently considering this strategy as part of its greenhouse 

gas reduction plan. In addition, both the Bureau of Land Management (BLM) and CARB list the 

use of low-bleed pneumatics as a BMP for oil and gas sources.34 This proven best management 

practice should be required for all new pneumatic devices in order to achieve emission 

reductions of 98% for these units. 

3. Summary Recommendations for Pneumatic Devices

EPA should implement the following technology standards and operating practices for all new 

pneumatic devices: 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

30 Lessons Learned, Natural Gas STAR Partners, “Options for Reducing Emissions from Pneumatic Devices in the 

Natural Gas Industry,” October 2006, p. 4.

31 Id., p. 7. 32 Id., p. 1. 33 Id., p. 4. 34 U.S. Department of Interior, Bureau of Land Management, “Air Resource BMPs,” 8/24/09, www.blm.gov/gov 

and The California Air Resources Board’s Clearinghouse of non-CO2 Greenhouse Gas Emission Control 

Technologies, http://www.arb.ca.gov/cc/non-co2-clearinghouse/non-co2-clearinghouse.htm. 
**

! Require Pneumatic Devices That Use Instrument Air or Mechanical Controls, Nitrogen 

Gas, or Electric Valve Controllers in Place of Gas Powered Pneumatic Devices 

EPA should require that all new pneumatic device installations use instrument air, 

powered either by electricity of solar energy or use mechanical controls, nitrogen gas or 

electric valves if instrument air is not feasible. All modified sources should be required to 

convert gas powered pneumatic control devices to meet the standards for new sources. 

Reductions in methane emissions of 100% would be expected from this technology. 

! Require Low-Bleed Pneumatic Devices for New Installations and Require Modified 

Sources to Retrofit High-Bleed Devices with Low-Bleed Devices 

,PA should require that any new pneumatic devices that must be gas-powered be lowbleed or that modified devices be replaced or retrofitted to meet low-bleed criteria. 

B. Compressors 

Fugitive methane emissions from compressors (e.g., from compressor seals) are a significant 

source of methane emissions from the natural gas processing sector. Compressors are also 

integral in the transmission of natural gas from field production and processing to the distribution 

sector. Compressor station facilities are used to transport gas through the network of 

transmission lines throughout the United States. Fugitive methane emissions from these 

compressor stations account for a significant portion of all emissions from the transmission 

sector. Compressors housed at storage facilities are also a large source of fugitive methane 

emissions. At these facilities, natural gas is stored during periods of low demand (e.g., in 

summer), and subsequently processed and distributed during periods of high demand (e.g., in 

winter). 

According to U.S. Greenhouse Gas Inventory data, compressor fugitive emissions, venting and 

engine exhaust account for about 12 Bcf—or about 10 percent—of methane emissions from the 

production sector. Reciprocating compressors account for another 16 Bcf and 41 Bcf—or about 

50 percent and 40 percent—of methane emissions from the processing and transmission sectors, 

respectively. All told, methane emissions from compressors reportedly account for at least one 

fifth of all methane emissions from oil and gas systems. 

 

These estimates, however, may underestimate actual emissions. According to EPA’s recent 

rulemakings for the Mandatory Reporting of Greenhouse Gases program, several emissions 

sources are believed to be “significantly underestimated” in the U.S. GHG Inventory 

(EPA/GRI/Radian, 1996).35,36 Specifically, EPA identifies the following sources of underreported emissions: (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 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

35 EPA/GRI (1996) Methane Emissions from the Natural Gas Industry. Prepared by Harrison, M., T. Shires, J. 

Wessels, and R. Cowgill, eds., Radian International LLC for National Risk Management Research Laboratory, Air 

Pollution Prevention and Control Division, Research Triangle Park, NC. EPA-600/R-96-080a.

36 Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry Background Technical 

Support Document, U.S. Environmental Protection Agency Climate Change Division Washington DC, p. 7.
*"

today” and, in fact, EPA believes “that emissions from some sources may be much higher than 

currently reported in the U.S. GHG Inventory.”37 EPA includes revised emission factors for four 

of these underestimated sources, including the addition of a factor for centrifugal compressor wet 

seal degassing venting of 233 metric tons per year, or 12 million cubic feet per year (MMcf/yr).38

Overall, the revisions to just these four sources results in a more than 100% increase in estimated 

emissions from the oil and gas production sector and a 67% increase in estimated emissions from 

the transmission and storage sector.39 These enormous underestimates alone are enough of a 

reason to insist on rigorous performance standards and work practices for these particular 

categories. However, there is even more evidence that the emissions estimates for these and other 

sources remain uncertain and continue to be greatly underestimated. 

Preliminary findings from an EPA-funded project at the University of Texas indicate that 

fugitive methane emissions from compressor engines can be substantially higher than expected 

from the currently accepted emission factors.40 Specifically, current emission factor estimates do 

not distinguish compressor seal emissions by compressor type (reciprocating or centrifugal) and 

do not distinguish between emissions from the seal face and emissions from seal oil degassing.41

It is worth noting that direct measurement of emissions from both reciprocating and centrifugal 

compressors is possible as a means to accurately demonstrate compliance with performance 

standards established by EPA. EPA proposed direct measurement methods for determining 

reported emissions under the Mandatory Reporting Rule (MRR).42

1. Existing State and International Programs to Reduce Methane Emissions 

from Compressors

The following state and international programs demonstrate that mandatory controls for reducing 

methane emissions are possible. EPA should consider these standards as minimum requirements 

for regulating sources under the NSPS. Regulations aimed at reducing VOCs and HAPs are 

relevant to consider because of the corresponding reductions in methane emissions that are 

achievable through implementation of these control technologies and practices. 

California 

The state of California proposed greenhouse gas rules (described in the Introduction and 

Summary Recommendations section above) that include control measures for compressors to 

improve operating practices and therefore reduce emissions when compressors are taken off-line 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

37 Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry Background Technical 

Support Document, U.S. Environmental Protection Agency Climate Change Division Washington DC, p. 23.

38 Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry Background Technical 

Support Document, U.S. Environmental Protection Agency Climate Change Division Washington DC, p. 8, Table 1.

39 Id. at 9. 40 University of Texas (Cooperative Agreement number XA-83376101-0).

41 Quality Assurance Project Plan, Greenhouse Gas (GHG) Emission Factor Development Project 

Cooperative Agreement number XA-83376101-0, January 30, 2008, Dr. David T. Allen (Principal Investigator) and 

Cyril Durrenberger (Project Quality Assurance Officer) Center for Energy and Environmental Resources University 

of Texas J.J. Pickle Research Campus 10100 Burnet Road, Mail Code R7100 Austin, Texas 78758, p.8.

42 75 FR 18608, April 12, 2010.
*#

and install compressor rod packing systems. This would apply to compressors in both the oil and 

natural gas extraction and transmission sectors.43

Cherkasytransgas 

Cherkasytransgas, a Ukrainian natural gas transmission company with a capacity to transmit 120 

billion cubic meters of natural gas annually, implemented a directed inspection and maintenance 

program at its compressor stations in 2002. Since then the company has achieved huge 

reductions in methane emissions from these sources through monitoring, leak repair, and 

equipment and valve sealant upgrades. In 2002, the company identified and repaired leaks, 

reducing methane emissions by 1.9 million cubic meters per year. In 2006, the company again 

conducted repairs and installed high efficiency equipment, reducing emissions by 5.9 million 

cubic meters annually. During the last round of repairs in 2008-2009, the company upgraded the 

sealant on 174 valves at transmission stations, distribution stations and linear pipes. These 

improvements reduced annual methane emissions by 3.5 million cubic meters.44

2. Available Proven Technologies for Compressors

EPA’s own Natural Gas STAR program provides evidence that there are many available, 

technically feasible, and cost-effective technologies that can greatly reduce methane emissions 

from gas compression activities. These options include both: (1) technology standards for 

compressor equipment; and (2) improving operating practices to reduce emissions (e.g., when 

compressors are taken off-line). EPA should, at a minimum, require the following technologies 

and operating practices as part of its revised NSPS for oil and natural gas systems. 

Require the Use of State-of-the-Art Compressor Rod-Packing Technology 

EPA should require the use of state-of-the-art rod-packing technology and identify a replacement 

threshold for replacing packing rings and piston rods as a practical method to reduce methane 

emissions from reciprocating compressors. Both the BLM and CARB already list compressor 

rod-packing technology as a BMP for oil and gas sources.45

Leakage can be reduced through a requirement to develop a proper monitoring plan and a costeffective schedule for replacing packing rings and piston rods. Monitoring and replacing 

compressor rod packing systems on a regular basis can greatly reduce methane emissions from 

compressors. According to EPA Natural Gas STAR partner reports, as packing deteriorates, leak 

rates can increase to the level at which replacing packing rings more frequently can be 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

43 “Climate Change Scoping Plan Appendices, Volume 1: Supporting Documents and Measure Detail, a framework 

for change,” California Air Resources Board, December 2008, C-153 and C-154, 

http://www.arb.ca.gov/cc/scopingplan/document/appendices_volume1.pdf#page=184. 44 Methane to Markets, Oil & Gas Methane Reduction Project Opportunity, “Directed Inspection and Maintenance 

and Valve Sealant Updgrades,” Cherkasytransgas, Cherkassy, Ukraine, 

http://www.methanetomarkets.org/projects/projectDetail.aspx?ID=1152.

45 U.S. Department of Interior, Bureau of Land Management, “Air Resource BMPs,” 8/24/09, www.blm.gov/gov 

and The California Air Resources Board’s Clearinghouse of non-CO2 Greenhouse Gas Emission Control 

Technologies, http://www.arb.ca.gov/cc/non-co2-clearinghouse/non-co2-clearinghouse.htm. 
*$

economically justified.46 In addition, more frequent ring replacement might actually extend the 

life of the compressor rod. EPA should require operators to establish baseline leakage rates and 

monitor changes in leakage rates to establish an emission threshold and corresponding 

replacement frequency similar to EPA’s “economic replacement threshold” analysis promoted 

through its Natural Gas STAR program.47 

For example, conventional bronze-metallic packing rings require replacement about every “three 

to five years,”48 but a more precise monitoring program will allow individual applications to 

optimize replacement so as to extend the life of the equipment and reduce increasing emissions. 

Requiring an aggressive monitoring and replacement schedule is an essential component of a 

comprehensive performance standard for this source. In addition to monitoring leakage rates, 

operators should be required to regularly monitor appropriate lubrication and cooling parameters 

to help minimize wear on packing rings.

The most advanced ring materials and designs for packing cases should guide EPA’s 

performance standard for this source. New packing ring materials (e.g., high-performance nonmetallics and polymers), types, and entirely new packing systems are available and becoming 

more common. There are many examples of companies that provide new low emission packing 

rings and packing case assemblies.49 EPA should consider all available emission-lowering rod 

packing technologies when setting the performance standard for this source. 

EPA reports there are 51,000 reciprocating compressors operating in the U.S. natural gas 

industry (2006), accounting for about 72.4 Bcf/yr of methane gas emissions.50 EPA further 

reports that new rod packing systems, properly installed and operated, lose approximately 12 

scfh compared with emissions that range from tens of scfh to hundreds of scfh for aged systems 

(EPA uses an example of 900 scfh).51 If, as reported by EPA, economic replacement of rods and 

rings for applications demanding a payback of less than one year would mean replacing 

equipment when leak rates reach a level of 376 scfh, then these systems would see a 97% 

reduction in emissions.52 New state-of-the-art rod packing technology required to emit no more 

than 12 scfh at installation would still represent a 90% reduction in methane emissions compared 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

46 Lessons Learned, Natural Gas STAR Partners, “Reducing Methane Emissions from Compressor Rod Packing 

Systems”, October 2006, http://www.epa.gov/gasstar/documents/ll_rodpack.pdf. 47 Id. 48 Id at 3. 49 Specific examples include: (1) Compressor Engineering Corp (CECO) Low Emission Packing (LEPTM), see

http://www.tryceco.com/ceco-parts-and-repair/rings-rider-band-rod-packing/lep-low-emission-packing.htm; (2) 

Cook Compression’s “COOK CLEAN emission-control solutions,” “Seal Assist SystemTM, the ultimate in 

emissions control,” and “[v]ented and buffered cases specially designed for your application to reduce fugitive 

emissions,” see http://www.cookcompression.com/index.cfm/lev2/813/Packing.Cases ; (3) Hoerbiger’s “BCD 

balanced cap design” which the company promotes as a “new low emission packing ring that operates at low 

temperatures and maintains the seal even during compressor shutdown,” see company materials at 

http://www.hoerbiger.com/Packing-rings.14186.0.html?&L=33; (4) Aavolyn Corporation’s ring and packing 

assemblies made of various materials (bronze, cast iron and Teflon blends) that “keep gas from leaking from the 

cylinder to the atmosphere” and “prevent leakage of gas along the rod when the compressor is shut down under the 

load” and include “Green Compressor Packing” technology, see http://www.aavolyn.com/cg020001.htm. 50 Lessons Learned, Natural Gas STAR Partners, “Reducing Methane Emissions from Compressor Rod Packing 

Systems”, October 2006, http://www.epa.gov/gasstar/documents/ll_rodpack.pdf. 51 Id. 52 Id at 8.
*%

to systems operating with leak rates of only 120 scfh. 

To achieve a 90% reduction in emissions from this source, EPA should require new technology 

standards and operating practices that prescribe initial leakage rates no greater than 12 scfh and 

replacement of compressor rod packing when leakage rates exceed 120 scfh,53 or when indicated 

by an established source-specific replacement threshold that maximizes methane reductions 

while also considering cost-effectiveness. 

Require the Use of Dry Seals in Centrifugal Compressors 

Centrifugal compressors are common in the production and transmission sectors of natural gas 

systems. Replacing wet seals (oil seals) used on the rotating shafts of the compressors with dry 

seals can significantly reduce methane emissions from this source. In fact, installing two or more 

dry seals together, in series, is even more effective in reducing emissions. According to EPA, 

these types of “tandem dry seals” result in less than 1% of the leakage of a wet seal system that is 

vented to the atmosphere and “cost considerably less to operate.”54 

The use of dry seals is proven and has been recently documented by the Global Methane 

Initiative.55 Specifically, methane emissions were shown to be 99.99% lower with the use of dry 

seals in an application in Mexico in 2010.56 In 2006, EPA reported that 90% of all new 

compressors are already equipped with dry gas seal systems. In addition, both the BLM and 

CARB list the use of dry seals as a BMP for oil and gas sources.57 

This technology is also an effective means of reducing methane emissions at offshore oil and gas 

operations. A recent paper on offshore platform methane reduction strategies analyzed offshore 

oil and gas methane emissions and control strategies, and devised an emission reduction strategy 

for the most significant sources at the lowest cost. The replacement of centrifugal compressor 

wet seals with dry seals is one of the recommended strategies for reducing methane emissions in 

offshore applications.58

The world’s largest natural gas company, Gazprom (with operations in Russia), has committed to 

replacing wet seals and dry seals at centrifugal compressors (which total more than 4,000). 

Between 2006 and 2008, the company converted seals at 59 compressor stations and 250 gas 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

53 120 scfm leak reduction rate would require roughly 2 years payback assuming a gas cost of $7/Mcf, a 10% 

interest rate and 8,000 hours of operation. 

54 Lessons Learned, Natural Gas STAR Partners, “Replacing Wet Seals With Dry Seals in Centrifugal 

Compressors”, October 2006, http://www.epa.gov/gasstar/documents/ll_wetseals.pdf.

55 See, e.g., April 2010 (http://www.epa.gov/gasstar/documents/workshops/ashgabat2010/0427_1135_compressors.pdf ), March 2010 

(http://www.methanetomarkets.org/expo/docs/postexpo/oil_betancourt_2.pdf) and September 2009 

(http://www.methanetomarkets.org/documents/events_oilgas_20090914_robinson3.pdf) Methane to Markets 

presentations.

56 Petróleos Mexicanos (Pemex) demonstrated a reduction in emission rate from 43.11 scfm to 0.02 scfm with seal 

replacement, see http://www.methanetomarkets.org/expo/docs/postexpo/oil_betancourt_2.pdf. 57 U.S. Department of Interior, Bureau of Land Management, “Air Resource BMPs,” 8/24/09, www.blm.gov/gov 

and The California Air Resources Board’s Clearinghouse of non-CO2 Greenhouse Gas Emission Control 

Technologies, http://www.arb.ca.gov/cc/non-co2-clearinghouse/non-co2-clearinghouse.htm. 58 Bylin, Carey et al. for Society of Petroleum Engineers, “Designing the Ideal Offshore Platform Methane 

Mitigation Strategy,” 2010, p. 1.
*(

pumping aggregate superchargers located at extraction facilities, gas transport facilities and 

underground storage facilities.59 

Since dry seal conversions may not be technically feasible for all compressors due to housing 

design and/or operational requirements, EPA should also investigate seal oil degassing vent 

recovery technology as an alternative performance technology requirement, where dry seal 

installations are not possible.60 

EPA should require the installation of tandem dry seals on all new compressors, or seal oil 

degassing vent recovery devices in cases where dry seals are not technically feasible. If, 

according to EPA, methane emissions typically range from 40 to 200 scfm for wet seals and 

from 0.5 to 3 scfm for dry seals, then EPA should require methane emissions from new units to 

emit no more than 3 scfm from the dry seals (representing at least a 92.5% reduction in 

emissions from this source). With demonstrated installations reporting emission reductions over 

99% and rates as low as 0.02 scfm (approximately 10 Mcf/yr at 8,000 hours of operation), this 

should be an achievable standard. Based on EPA’s recent estimate of 12 MMcf/yr from 

centrifugal compressor wet seal degassing venting, reductions of over 90% from this source 

would drop this emission factor estimate for new units to just over 1 MMcf/yr (or just under 3 

scfm for a unit that operates 8,000 hours).61

In addition to reducing methane emissions, replacing wet seals with dry seals significantly 

reduces operating costs and increases compressor efficiency. Specifically, EPA reports that dry 

seals: (1) are safer to operate because there is no need to operate a high-pressure oil system; (2) 

are mechanically simpler; (3) consume less energy (90–95% less); (4) result in less compressor 

downtime; (5) have lower maintenance costs and last twice as long as wet seals; and (6) their use 

does not result in contamination of the gas stream and degradation of the pipeline from oil 

usage.62 

Require the Use of Air or Electric Starters Instead of Gas Starters 

Gas starters use natural gas to power the starter motor and then vent the discharge gas to the 

atmosphere. Compressor starters that use compressed air or electricity instead of natural gas to 

power the starter motor are not sources of methane emissions. Requiring the use of air or electric 

starters instead of gas starters for all natural gas pneumatic starter motors will ensure reduced 

methane emissions, as well as reduced VOC and HAP emissions, from this source. A standard 

air starter would require a stationary or mobile air compressor (with an electrical power source). 

Operation costs would include the cost of the electrical power needed to compress the air. 

Replacing starter expansion turbines with an electric motor starter, similar to an automobile 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

59 Oil & Gas Methane Reduction Project Opportunity, Compressor Seal Conversions, OAO Gazprom, 

(http://www.methanetomarkets.org/projects/projectDetail.aspx?ID=1151) and Gazprom Activities on Methane 

Emissions Reduction, G.S. Akopova, Laboratory of Environmental Protection and Resource Saving, Moscow 2010, 

at 13, (http://www.methanetomarkets.org/expo/docs/postexpo/oil_apokova.pdf).

60 See slides 11-12 from Methane to Markets April 2010 presentation 

(http://www.epa.gov/gasstar/documents/workshops/ashgabat-2010/0427_1135_compressors.pdf). 61 Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry Background Technical 

Support Document, U.S. Environmental Protection Agency Climate Change Division Washington DC, p. 8, Table 1.

62 Lessons Learned, Natural Gas STAR Partners, “Replacing Wet Seals With Dry Seals in Centrifugal 

Compressors”, October 2006, http://www.epa.gov/gasstar/documents/ll_wetseals.pdf.
*)

engine starter, may include a connection to utility electrical power, site generated power, or solar 

recharged batteries. Use of air and electric starters completely eliminates the venting of methane 

to the atmosphere and the leakage of methane through the gas shutoff valve. EPA has reported 

this technology as a cost-effective control technique in its Natural Gas STAR program.63 

EPA has reported a 1,524 thousand cubic feet (Mcf) per year average leakage rate from 

compressor starter lines.64 An average methane emission factor for compressor engines used in 

gas processing is about 4 million cubic feet (MMcf) per year for reciprocating engines and about 

8 MMcf per year for centrifugal engines.65 Requiring air or electric starters on all applicable 

engines would reduce methane emissions by roughly 40% in new reciprocating engine 

applications and 20% in new centrifugal engine applications. CARB already lists the use of air or 

electric starters as a BMP for oil and gas sources.66

Require the Use of State-of-the-Art Compressor Cylinder Unloader Technology and Require 

Regular Replacement 

Compressor cylinder unloaders employed in the transmission sector are used to control gas 

volumes (e.g., for capacity control, to prevent an overload when there is an upset in the system, 

or to reduce the load during engine start-up, etc.). Unloaders can be a significant source of 

fugitive methane emissions (e.g., from leaking o-rings, covers and pressure packing) and have 

been identified as one of the top causes of unscheduled shutdowns for reciprocating compressor 

engines.67 

EPA should thoroughly investigate the state-of-the-art technology for unloaders and require the 

use of the best available technologies to reduce vented emissions from this source. Examples of 

such technologies are the use of multiple innovative sealing elements (including elastomeric 

sealing elements) to reduce emissions and the use of port/plug-type designs to avoid operational 

problems inherent in finger-type unloader designs.68 

In order to reduce the amount of unscheduled shutdowns and frequent maintenance required for 

aging unloader systems (and the associated fugitive emissions that result from these episodes), 

EPA should specify a conservative replacement period that will ensure optimal equipment 

performance over the life of the unloader system and parts. One possible method would be to 

establish an acceptable emission threshold and specify a corresponding replacement frequency 

based on that threshold. 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

63 See EPA Natural Gas STAR Program Partner Reported Opportunities (PRO), PRO Fact Sheet Nos. 103 and 108, 

http://www.epa.gov/gasstar/documents/replacegas.pdf and 

http://www.epa.gov/gasstar/documents/installelectricstarters.pdf. 64 EPA ORD, “Methane Emissions from The Natural Gas Industry”, Volume 8, GRI-94 /0257.23, EPA 600/R-96-

080h, June 1996, p. 58. 

65 Id. at 48. 66 The California Air Resources Board’s Clearinghouse of non-CO2 Greenhouse Gas Emission Control 

Technologies, http://www.arb.ca.gov/cc/non-co2-clearinghouse/non-co2-clearinghouse.htm. 67 “Compressor Valves and Unloaders for Reciprocating Compressors - An OEM's Perspective”, S. Foreman 

Dresser-Rand, Painted Post, NY, USA, available at http://www.dresser-rand.com/techpapers/tp015.pdf. 68 See EPA Gas STAR Program Partner Reported Opportunities (PRO), PRO Fact Sheet No. 110, 

http://www.epa.gov/gasstar/documents/replacecylinder.pdf.
*&

Potential methane emission reductions from using the best available compressor cylinder 

unloader technology are not easily quantified and depend, among other things, on compressor 

maintenance activities. However, it is important to include technology requirements and 

replacement schedules for this source since the potential for fugitive methane emissions is 

significant. Fugitive methane emissions from faulty unloaders have been reported to be as high 

as 3.5 MMcf per compressor engine,69 which represents a huge fraction of average annual 

emission rates for compressors at transmission sites (roughly 5.5 MMcf/yr and 11 MMcf/yr for 

an average reciprocating and centrifugal compressor, respectively).70 

CARB already lists the use of cylinder unloaders and their regular replacement as a BMP for oil 

and gas sources.71

Require Operating Practices That Eliminate or Reroute Gas Leakage When Taking Compressors 

Off-line 

When taking compressors offline for operational reasons, EPA should require operators to keep 

compressors pressurized and to connect the blowdown vent lines to the fuel gas system in order 

to allow the gas that is normally vented to be used as fuel while the compressor is off-line. In 

situations where routing gas to the fuel gas system is not possible EPA should require the 

installation of a static seal on the compressor rods to eliminate rod-packing leaks that occur 

during the shutdown process. Keeping compressors fully pressurized avoids significant fugitive 

emissions from leaks across the unit valves. 

For situations where compressors cannot remain pressurized when they are taken offline for 

maintenance and for system shutdowns, EPA should require collection and re-routing of any 

vented gas. Not allowing venting to the atmosphere of the high-pressure gas that is left in the 

compressor when it is taken offline (i.e., blowdowns) will require capturing the gas and rerouting it for other use (e.g., to the sales line). The design of blowdown systems and emergency 

shutdown system practices to capture gas should be required in accordance with acceptable 

industry safety standards (e.g., OSHA, API, ANSI, ASME, etc.). Rerouting highly-combustible 

gases has the added benefit of reducing safety risks in the work area. 

EPA has reported huge savings by Natural Gas STAR partners when maintaining pressurized 

systems during shutdowns. Keeping the system pressurized can reportedly, alone, avoid over 4 

MMcf/yr of methane emissions per compressor.72 When also requiring the rerouting of gas to the 

fuel system, methane emissions savings can be as high as 5.3 MMcf/yr per unit.73 EPA-reported 

average emission rates for compressor blowdown valves are an order of magnitude higher in 

depressurized systems than in pressurized systems (1.4 MMcf/yr for pressurized systems 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

69 Id. 70 EPA ORD, “Methane Emissions from The Natural Gas Industry”, Volume 8, GRI-94 /0257.23, EPA 600/R-96-

080h, June 1996, p. 52.

71 The California Air Resources Board’s Clearinghouse of non-CO2 Greenhouse Gas Emission Control 

Technologies, http://www.arb.ca.gov/cc/non-co2-clearinghouse/non-co2-clearinghouse.htm. 72 Lessons Learned, Natural Gas STAR Partners, “Reducing Emissions When Taking Compressors Off-Line”, 

October 2006, p. 1, http://www.epa.gov/gasstar/documents/ll_compressorsoffline.pdf. 73 Id.
*'

compared with over 14 MMcf/yr for depressurized systems).74 Again, these emission rate 

estimates represent a substantial portion of the overall methane emission rates from compressors 

(roughly 5.5 MMcf/yr and 11 MMcf/yr for an average reciprocating and centrifugal compressor, 

respectively).75

Significant emissions reductions and cost saving will result from avoiding routine compressor 

blowdown and eliminating or rerouting leakage. EPA must require operating practices to ensure 

the best system of emissions reductions is established.

Require Direct Inspection and Maintenance at Compressor Stations 

Direct Inspection and Maintenance (DI&M) is “a proven management practice for cost-effective 

reduction of methane emissions” that can significantly reduce fugitive methane emissions from 

the gas processing sector.76 A DI&M is not the same thing as EPA’s regulatory leak detection 

and repair (LDAR) program for reducing VOC emissions.77 A successful DI&M program 

includes a baseline survey, cost-effective repairs and subsequent targeted surveys based on 

findings from the initial baseline survey. In general, the cost of the baseline survey is reportedly 

recovered in gas savings during the first year.78 The costs of subsequent surveys are minimized 

by focusing the components that were identified through the initial baseline study as having a 

high potential for leakage. A variety of screening and measurement devices (e.g., infrared gas 

imaging, optical remote leak detection, etc.) can be used to obtain accurate leak data and high 

volume gas samplers can be used to identify and quantify leaks.79 According to EPA Natural Gas 

STAR partners, a DI&M program should “target the five categories of equipment components 

that contribute to the majority of methane losses: block valves, control valves, connectors, 

compressor seals, and open-ended lines.”80 Additionally, a DI&M program should include 

regular inspection of blowdown valves at compressor stations, which can be significant methane 

emissions sources due to substantial pressure, thermal and mechanical stresses.81

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

74 EPA ORD, “Methane Emissions from The Natural Gas Industry”, Volume 8, GRI-94 /0257.23, EPA 600/R-96-

080h, June 1996, p. 56. NOTE: the depressurized emission rates do not include the vented emissions from 

depressuring the compressor.

75 Id. at 52. 76 Lessons Learned, Natural Gas STAR Partners, “Directed Inspection and Maintenance at Gas Processing Plants 

and Booster Stations”, October 2003, http://www.epa.gov/gasstar/documents/ll_dimgasproc.pdf

77 See, NSPS Subpart KKK - Standards of Performance for Equipment Leaks of VOC From Onshore Natural Gas 

Processing Plants.

78 Lessons Learned, Natural Gas STAR Partners, “Directed Inspection and Maintenance at Gas Processing Plants 

and Booster Stations”, October 2003, http://www.epa.gov/gasstar/documents/ll_dimgasproc.pdf

79 See, e.g., Directed Inspection and Maintenance (DI&M) at Gas Processing Plants, Innovative Technologies for the 

Oil & Gas Industry: Product Capture, Process Optimization, and Pollution Prevention, 

Targa Resources and the Gas Processors Association, July 27, 2006 Hobbs, NM, 

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

80 Lessons Learned, Natural Gas STAR Partners, “Directed Inspection and Maintenance at Gas Processing Plants 

and Booster Stations,” October 2003, http://www.epa.gov/gasstar/documents/ll_dimgasproc.pdf. 81 See EPA Natural Gas STAR Program Partner Reported Opportunities (PRO), PRO Fact Sheet No. 601, “Inspect 

and Repair Compressor Station Blowdown Valves,” 

http://www.epa.gov/gasstar/documents/inspectandrepaircompressorstationblowdownvalves.pdf. 
"+

A pilot study conducted by EPA and the Gas Technology Institute demonstrated a DI&M 

program at gas processing facilities that reduced methane emissions by up to 96%.82 EPA should 

require all gas processing facilities to establish and implement a DI&M program to reduce 

fugitive methane emissions. Potential methane reductions from implementing a DI&M program 

will vary depending upon the operating characteristics of the facility but EPA should prescribe a 

program that represents the best available practices for DI&M. 

Require Isolation Valves To Be Installed in Close Proximity to Compressors For All New 

Installations

When individual compressors are taken off-line, valves are used to isolate the unit and the 

natural gas between these valves is vented to the atmosphere. Similarly, when real or simulated 

emergencies occur at compressor stations, fire gate valves are activated to stop the flow of gas 

into the station. Through improved compressor facility design, the volume of methane gas that is 

vented when sections of isolated equipment are blown out or when fire gate valves are activated 

can be minimized.83 EPA should require all new compressor stations to locate isolation valves 

and fire gate valves in close proximity to compressors in order to minimize the lengths of gasfilled piping to be vented to the atmosphere. 

3. Summary Recommendations for Compressors

EPA should implement the following technology standards and operating practices for all new 

compressor engines: 

! Require the Use of State-of-the-Art Compressor Rod-Packing Technology 

EPA should prescribe initial leakage rates no greater than 12 scfh and replacement of 

compressor rod packing when leakage rates exceed 120 scfh, or when indicated by an 

established source-specific replacement threshold that maximizes methane 

reductions while also considering cost-effectiveness. 

! Require the Use of Dry Seals in Centrifugal Compressors 

EPA should require the installation of tandem dry seals on all new compressors, or seal 

oil degassing vent recovery devices in cases where dry seals are not technically feasible. 

! Require the Use of Air or Electric Starters Instead of Gas Starters 

EPA should require the use of air or electric starters instead of gas starters for all natural 

gas pneumatic starter motors. 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

82 Lessons Learned, Natural Gas STAR Partners, “Directed Inspection and Maintenance at Gas Processing Plants 

and Booster Stations”, October 2003, http://www.epa.gov/gasstar/documents/ll_dimgasproc.pdf.

83 See EPA Natural Gas STAR Program Partner Reported Opportunities (PRO), PRO Fact Sheets No. 606 and 608, 

“Design Isolation Valves to Minimize Gas Blowdown volumes” and “Move Fire Gates In to Reduce Venting at 

Compressor Stations,” 

http://www.epa.gov/gasstar/documents/designisolationvalvestominimizegasblowdownvolumes.pdf and 

http://www.epa.gov/gasstar/documents/movefiregatesin.pdf. 
"*

! Require the Use of State-of-the-Art Compressor Cylinder Unloader Technology and 

Require Regular Replacement 

EPA should require the use of the best available unloader technologies to reduce vented 

emissions from this source. EPA should also specify a conservative replacement period 

that will ensure optimal equipment performance and minimize methane emissions over 

the life of the unloader system and parts. 

! Require Operating Practices That Eliminate or Reroute Gas Leakage When Taking 

Compressors Off-line 

EPA should require operators to keep compressors pressurized and to connect the 

blowdown vent lines to the fuel gas system in order to allow the gas that is normally 

vented to be used as fuel while the compressor is off-line. In situations where routing gas 

to the fuel gas system is not possible, EPA should require the installation of a static seal 

on the compressor rods to eliminate rod-packing leaks that occur during the shutdown 

process. For situations where compressors cannot remain pressurized when they are taken 

offline for maintenance and for system shutdowns, EPA should require collection and rerouting of any vented gas. 

! Require Direct Inspection and Maintenance at Compressor Stations 

EPA should require all gas processing facilities to establish and implement a DI&M 

program to reduce fugitive methane emissions. EPA’s prescribed work practice should 

represent the best available practices for DI&M. 

! Require Isolation Valves To Be Installed in Close Proximity to Compressors For All New 

Installations 

EPA should require all new compressor stations to locate isolation valves in close 

proximity to compressors in order to minimize the lengths of gas-filled piping to be 

vented to the atmosphere.

C. Dehydrators 

Saturated water found in produced gas must be removed prior to gas transmission. Glycol 

dehydrators are the most common technology used to remove water from gas. Glycol 

dehydrators are sources of methane emissions from the reboiler vent and from pneumatic 

controllers. The glycol used to absorb water from the gas stream also absorbs a small amount of 

methane, which is then driven off to the atmosphere (along with water vapor) through the 

reboiler vent. The majority of glycol dehydrators are used in the production sector, although they 

are also used during processing, transmission and storage. Methane emissions from dehydrator 

vent stacks are highest in the production sector due both to the higher number of units and also to 

the fact that most production dehydrators do not operate with flash tank separators. 

According to U.S. Greenhouse Gas Inventory data, dehydrators and pumps account for about 12 

Bcf—or about 10 percent—of methane emissions from the production sector and an additional 1 
""

Bcf—or about 3 percent—from the processing sector.84 These estimates are based on dehydrator 

population estimates made up of 95% glycol dehydrators and 5% other types of dehydrators.85 

Emission factors for glycol dehydrators are dependent on the existence of certain technologies, 

namely: (1) use of a flash tank; (2) use of stripping gas; (3) use of gas-driven pumps; and (4) use 

of vent controls routed to a burner. According to the EPA/GRI inventory, use of flash tanks can 

reduce methane emission rates by 98%.86 The use of stripping gas increases methane emissions. 

Gas from the absorber outlet (or the flash tank) is sometimes used in the regenerator to help strip 

the water and other absorbed compounds out of the glycol; the methane that is in the stripping 

gas passes through the regenerator and to the atmospheric vent. These emissions can be 

significant.87 According to EPA/GRI emission factors, the use of gas-driven pumps can also 

greatly increase methane emissions. Spent pumping gas is flashed off in the regenerator and can 

result in significant methane emissions (equivalent to over five times what is estimated for still 

vent emissions).88 The use of combusted vent controls can reduce methane emissions and, in 

fact, the EPA/GRI inventory assumes no methane emissions from units that employ combustion 

vent controls.89 Although primarily used to control HAP emissions (e.g., benzene, toluene, 

ethylbenzene and xylenes (BTEX)) the methane in the vent can be used as fuel in the regenerator 

burner. 

EPA proposed the use of engineering measurements as a means to report emissions from 

dehydrator vent stacks under EPA’s Mandatory Reporting Rule for GHG emissions.90 EPA’s 

proposed use of estimates based on the GLYCalcTM simulation software was also supported by 

the Western Climate Initiative in its recommendations to EPA on measuring GHG emissions 

from the oil and gas industry. These same methods can be employed for compliance 

demonstration purposes, as appropriate. 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

84 Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990 - 2007, USEPA, April, 2009, see

http://www.epa.gov/gasstar/basic-information/index.html#sources. 

85 EPA ORD, “Methane Emissions from The Natural Gas Industry”, Volume 14, GRI-94 /0257.31, EPA 600/R-96-

080n, June 1996, p. 2.

86 The reported emission factor for a dehydrator with a flash tank is 3.57 scf of methane per MMscf throughput 

compared to the emission factor for a dehydrator without a flash tank, which is 175.10 scf of methane per MMscf 

throughput. The emission factor for a dehydrator with a flash tank is 98% less than that without a flash tank (175.10 

– 3.57 / 175.10 = 0.98). Id at Appendix A. 87 EPA ORD, “Methane Emissions from The Natural Gas Industry,” Volume 14, GRI-94 /0257.31, EPA 600/R-96-

080n, June 1996. This report estimates an incremental methane emission rate for dehydrators with stripping gas of 

670 scf of methane per MMscf throughput. Compared with total emission rates from dehydrators without flash tanks 

of 175 scf of methane per MMscf throughput, these additional methane emissions from the use of stripping gas can 

be quite significant (over 3 times that from dehydrator reboiler vent emissions from units without flash tanks). 

88 EPA ORD, “Methane Emissions from The Natural Gas Industry,” Volume 15, GRI-94 /0257.33, EPA 600/R-96-

080o, June 1996, p. 14. This report estimates an emission factor for gas-assisted glycol pumps at production sites of 

992 scf of methane per MMscf throughput, which is over 5 times higher than the emission factor for dehydrators 

without flash tanks of 175 scf of methane per MMscf throughput (found in Volume 14). 

89 EPA ORD, “Methane Emissions from The Natural Gas Industry,” Volume 14, GRI-94 /0257.31, EPA 600/R-96-

080n, June 1996, Appendix A.

90 75 FR 18608, April 12, 2010. Note, EPA proposed engineering estimates as the means for demonstrating 

compliance for conventional well completions and conventional well workovers.
"#

1. Existing Federal, State and County Programs to Reduce Methane 

Emissions from Dehydrators

The following federal, state and county programs demonstrate that mandatory controls for 

reducing methane emissions are possible. EPA should consider these standards as minimum 

requirements for regulating sources under the NSPS. Regulations aimed at reducing VOCs and 

HAPs are relevant to consider because of the corresponding reductions in methane emissions that 

are achievable through implementation of these control technologies and practices. 

Federal NESHAP Requirements 

EPA’s National Emission Standards for Hazardous Air Pollutants (NESHAP) for Oil and Natural 

Gas Production Facilities (40 CFR 63 Subpart HH) and for Oil and Gas Transmission and 

Storage Facilities (40 CFR 63 Subpart HHH) require installation of equipment to either: (1) 

reduce HAPs from dehydrator vents by 95 percent using either closed-vent control systems or by 

implementing process modifications; or (2) combust HAPs below 20 ppmv.

91 These NESHAPs 

are applicable to production facilities with a throughput floor of 3MMscf/day and to transmission 

and storage facilities with a throughput floor of 10MMscf/day. These NESHAP requirements are 

also triggered if total benzene emissions exceed one ton per year. Many of the same technologies 

used to meet the NESHAP requirements (e.g., installing flash tank separators) are also applicable 

methane control techniques that EPA should consider as technically feasible and cost-effective 

options for methane performance standards. In addition to these federal requirements, some 

states have implemented certain control requirements and operating practices for reducing VOC 

and HAP emissions from dehydrators that are discussed in more detail below. EPA should also 

take into account these state program requirements when considering methane performance 

standards from the oil and gas sector. 

Wyoming 

Permitting rules in Wyoming address VOC and HAP emissions from dehydration units with a 

tiered approach that requires tighter controls in the most concentrated development area (the 

Jonah and Pinedale Anticline Development area). For this area, 98% control efficiency is 

required for all dehydration unit process vents at all new or modified facilities.92 The statewide 

and Concentrated Development Area require that all oil and gas operators must follow one of the 

two scenarios laid out in guidance for reducing emissions from dehydration units. Under scenario 

1, 98% control efficiency is required for all new and modified facilities. Combustion units used 

can be removed after one year on all units with still vent condensers installed that are under 6 

tons per year (tpy). Scenario 2 requires that installation of glycol flash separators and reboiler 

still vents at all new or modified facilities. If potential uncontrolled VOC emissions are equal to 

or greater than 8 tpy, 98% control efficiency must be achieved on all units within 30 days of first 

date of production or upon the date of modification. Combustion units used can be removed after 

one year on all units with flash separators and still vent condensers installed that are under 8 tpy. 

All non-condensable still vent and glycol flash separator vapors must be routed to the 

combustion unit for 98% control of VOC and HAP emissions or used as fuel for process 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

91 66 FR 34548, June 29, 2001.

92 Wyoming DEQ, C6 S2 O&G Production Facilities Permitting Guidance, March 2010, p. 18.
"$

equipment burners in facilities were a combustion unit is required. When a combustion unit is 

not required, glycol flash separator vapors must be collected and used as fuel in process 

equipment burners. Any excess vapors not used may then be vented to the atmosphere.93

Colorado 

The state of Colorado’s air pollution regulations include 90% control efficiency requirements for 

natural gas dehydrators at oil and gas exploration and production operations, natural gas 

compressor stations, drip stations or gas processing plants statewide. Any single dehydrator or 

grouping of dehydrators with VOC emissions exceeding 15 tpy (on a rolling 12-month basis) 

must meet this control requirement. For groups of dehydrators that exceed the 15 tpy threshold, 

all single dehydrators over 2 tpy are subject to the 90% control efficiency requirement.94 

In 2008, Colorado’s Air Pollution Control Division proposed a more stringent control strategy 

for dehydrators. The strategies considered were to increase the required control efficiency from 

90% to 98% and to reduce the applicability threshold from the existing 15 tpy down to 2 tpy in 

the ozone nonattainment area and 5 tpy for the rest of the state. The state also considered 

requiring optimization of lean glycol pump circulation rates, requiring the installation of flash 

tank separators and the control of emissions on new dehydration systems, and requiring the use 

of portable desiccant dehydrators. 

Part of the rationale for increasing the control efficiency was that, “[m]any control technologies 

already in place achieve control efficiencies of at least 98 percent, such as vapor recovery units, 

enclosed smokeless combustion devices (e.g., thermal vapor incinerators, boilers, or process 

heaters), and smokeless flares.”95 However, this more stringent approach was not adopted by the 

state since these additional controls were not needed to demonstrate attainment of the 8-hour 

ozone standard. In addition, the oil and gas industry believed that the 90% level of control could 

be achieved using a condenser rather than having to install a combustion device, which would be 

necessary if the required control efficiency were 98%.96

 

The Colorado Oil and Gas Conservation Commission also regulates VOC emissions from natural 

gas dehydrators in three counties97 with high volumes of oil and gas production that are outside 

of the ozone nonattainment or attainment/maintenance areas. Any dehydrator with a potential to 

emit (pte) VOC of 5 tpy or greater, that is located within 1⁄4 mile of certain public facilities or 

areas, must use control devices that can achieve 90% control efficiency and have an appropriate 

state permit.98 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

93 Id, 6-7 & 12-13. 94 Colorado Department!-.!/01234!567289!7:;!,:<3=-:>6:8?!@3=!A07238B!C-:8=-2!C->>3DD3-:?!E6F02783-:!

G0>16=!)?!HIIJ5!7:;!HKIIJLJ!M6N7=786!D6483-:D!7=6!3:420;6;!3:!896!=026D!.-=!-O-:6!:-:78873:>6:8!7=67D!-=!

78873:>6:8P>73:86:7:46!7=67D!7:;!.-=!D8786!-:2B!=6Q03=6>6:8D!108!896!748072!=6Q03=6>6:8D!7=6!3;6:83472J! 95 Draft Oil and Gas Ozone Reduction Strategy – Presented at February 26, 2008 RAQC Meeting, Colorado Air 

Pollution Control Division.

96 Email communication with Christopher Laplante, Oil & Gas Team Permitting Supervisor, Air Pollution Control 

Division, Colorado Dept. of Public Health and Environment, October 27, 2010.

97 Garfield, Mesa & Rio Blanco Counties. 

98 Colorado Code of Regulations, §805 b(2)C, http://www.sos.state.co.us/CCR.
"%

Ventura County, California 

In 1994, the Ventura County Air Pollution Control District adopted a rule targeting Reactive 

Organic Compound (ROC) emissions from glycol regenerator vents. Under the rule, operators 

can chose from several options that would all achieve a 95% reduction in ROC emissions from 

glycol regenerator vents. The first option requires the collecting and condensing of all ROC by a 

condenser/separator system that directs all uncondensed ROC to a vapor recovery/disposal 

system. The vapor disposal system can use any method with a removal efficiency of at least 

95%. The second option under this rule is the use of a flare or incinerator that is operated in a 

specified manner so as to decrease ROC emissions and the third option allows for any other 

control mechanism that would achieve the 95% removal efficiency.99

2. Available Proven Technologies for Dehydrators

EPA’s own Natural Gas STAR program provides evidence that there are many available, 

technically feasible and cost-effective technologies that can greatly reduce methane emissions 

from dehydrators. These options include both: (1) technology standards for dehydrators; and (2) 

improving operating practices to reduce emissions. EPA should, at a minimum, consider the 

following technologies and operating practices as cost-effective standards for reducing methane 

emissions from oil and natural gas systems. 

Require the Use of Zero Emission Dehydrators 

Zero emission dehydrators combine several technologies to virtually eliminate methane 

emissions from the dehydration process by recovering methane from the still column, 

eliminating the need for gas strippers and using electricity to power the circulation pumps. 

Specifically, non-condensable vapors collected from the glycol still column are used as fuel for 

the reboiler, a water exhauster is used in place of a gas stripper and an electric pump is used to 

circulate the glycol solution. According to EPA, “[c]apital costs of a zero emissions dehydrator 

are similar to installing a conventional dehydrator with a thermal oxidizer.”100 The Four Corners 

Air Quality Task Force report of Oil and Gas Mitigation Options indicated that the zero emission 

dehydrator could, in fact, be used as a mandatory technology in areas experiencing air quality 

problems and would achieve large reductions in VOC, HAP and methane emissions.101

According to this same report, “[o]perating and [m]aintenance costs are greater than $1,000 per 

year, but lower than the maintenance costs for conventional glycol dehydrators” and “EPA 

estimates the payback to occur in less than a year.”102 EPA should require the use of zero 

emission dehydrator technology for all new installations. 

EPA’s Environmental Technology Verification (ETV) program has evaluated the performance of 

a zero emission dehydrator called the Quantum Leap Dehydrator (QLD). The QLD, 

manufactured by Engineered Concepts, LLC, uses a series of heat exchangers, condensers, 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

99 Ventura County Air Pollution Control District, Rule 71.5 Glycol Dehydrators, adopted 12/13/94, 

http://www.vcapcd.org/Rulebook/Rule4.htm.

100 See EPA Natural Gas STAR Program Partner Reported Opportunities (PRO), PRO Fact Sheet No. 206, “Zero 

Emissions Dehydrators”, http://www.epa.gov/gasstar/documents/zeroemissionsdehy.pdf. 

101 Four Corners Air Quality Task Force Report of Mitigation Options, November 1, 2007, pp. 91-93. 102 Id.
"(

separators and electric pumps to recover still column vapors. In 2003, the ETV program certified 

certain performance and environmental performance criteria for a QLD unit installed in 

Brighton, Colorado and did not detect methane concentrations during any of the test periods.103

The HAP destruction efficiency was calculated at greater than 99.74 ± 0.01 percent.104 EPA’s 

ETV program was designed to facilitate the use of “innovative or improved environmental 

technologies through performance verification and information dissemination.” According to 

EPA, “[t]he ETV program goal is to further environmental protection by accelerating the 

acceptance and use of improved and cost-effective technologies.”105 EPA should therefore 

consider the zero emission dehydrator as a technically and economically feasible option for all 

new dehydrator installations. 

Require the Use of Solid Desiccant Dehydrators in Cases Where Zero Emission Dehydrators Are 

Not Feasible 

Natural Gas STAR partners have found that solid desiccant dehydrators (using adsorption) 

reduce methane, VOC, and HAP emissions by 99 percent compared with glycol dehydrators and 

also have lower operating and maintenance costs.106 Solid desiccant dehydrator technology uses 

a drying bed of desiccant tablets to remove water from the produced gas stream. The tablets 

extract moisture from the gas as it passes through the bed of tablets. A solid desiccant dehydrator 

operates as a fully enclosed system with essentially no emissions. A small amount of emissions 

occur when the vessel is opened for maintenance or other reasons (e.g., desiccant tablets that 

dissolve over time need to be replaced periodically). Solid desiccant dehydrators are very simple 

devices with no moving parts and no external power supply needs. They are appropriate for use 

in a wide variety of applications, including for use at remote sites and for portable applications. 

The amount of moisture that can be removed from the produced gas stream by a solid desiccant 

dehydrator is dependent on the type of desiccant used, as well as the temperature and pressure of 

the gas stream. EPA should consider the latest available desiccant technology when determining 

the applicability of this technology to all types of new installations. For example, calcium 

chloride is the most common and the least expensive desiccant but has more limited operating 

ranges than other desiccants. According to EPA Natural Gas STAR Partners, “calcium chloride 

can achieve pipeline-quality moisture contents at temperatures below 59oF and pressures above 

250 psig.”107 Lithium chloride is a more expensive desiccant but has a much wider operating 

range (i.e., up to 70oF and above 100 psig). Some desiccants (aside from calcium chloride) can 

be re-generated and re-used. A cursory review of currently-available desiccant dehydrator 

technology shows that there are several companies offering units that can effectively operate at 

high temperatures (e.g., as high as 200oF) and at high pressure (e.g., max allowable working 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

103 ETV Joint Verification Statement, Quantum Leap Dehydrator, pp. S-4 and S-5, available online at 

http://www.epa.gov/etv/pubs/03_vs_quantum.pdf. The minimum detection limit was 0.1 ppmvd so methane 

concentrations were < 0.1 ppmvd (or < 0.00004 lb/hr).

104 Id at S-5. 105 Id. 106 Lessons Learned, Natural Gas STAR Partners, “Replacing Glycol Dehydrators with Desiccant Dehydrators”, 

October 2006, http://www.epa.gov/gasstar/documents/ll_desde.pdf. 

107 Id.
")

pressures as high as 2220 psig) and are marketed for “environmentally sensitive applications.”108

Silica gel type desiccants can be designed to also extract marketable liquid hydrocarbons from 

the dehydration process.109 These examples are evidence that EPA must seriously consider solid 

desiccants as a technically feasible standard for dehydration units. 

While replacement cost of the desiccant is slightly higher than the glycol used in a glycol 

dehydration system (because the desiccants themselves need regular replacement whereas the 

glycol is re-circulated), this is the only O&M cost for these systems. In a recent Global Methane 

Initiative presentation, comparison of costs for installation of a solid desiccant dehydrator versus 

a glycol dehydrator showed slightly higher costs for installation, operation and maintenance of a 

glycol system than for a solid desiccant system.110 EPA lists desiccant dehydrators as a costeffective technology with a payback of 1-3 years.111 This is evidence that EPA should consider 

this technology to be a cost-effective option for dehydration. CARB already lists the use of 

desiccant dehydrators as a BMP for oil and gas sources.112

EPA should require all new dehydrators to first use zero emission dehydrator technology and use 

solid desiccant technology in applications where zero dehydrator technology is not feasible. If, 

after thorough consideration of existing state-of-the art technology, EPA determines that zero 

emission dehydration and solid desiccant dehydration are not universally applicable, then EPA 

should require it where possible and also require specific technology standards and operating 

practices for glycol dehydration units where zero dehydration and solid desiccant dehydration are 

not technically feasible. 

Require Glycol Dehydrators to Use Vapor Recovery Units 

Requiring that flash tank separators and other vents be piped to a vapor recovery unit (VRU) will 

result in less methane emissions vented from the reboiler. The VRU can then increase the 

recovered gas pressure enough to inject it into a fuel gas system or gathering/sales line. 

According to a recent proposal by the Colorado Air Pollution Control Division to increase 

control device efficiencies on dehydrator units from 90% to 98%, “many vapor recovery units 

and combustion devices already have control efficiencies of at least 98 percent.”113 EPA should 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

108 See, e.g., Emerson Process Management’s Bettis Molecular Sieve Desiccant Dehydrator For Natural Gas with a 

regenerable desiccant bed and operating temperature range from -80o

F to 200oF, 

http://www2.emersonprocess.com/siteadmincenter/PM%20Valve%20Automation%20Documents/Bettis/Brochure/

MolecularSieve.pdf; see also Cameron’s Natco Desi-Dri Desiccant Dehydration, “emissions-free” natural gas 

dehydration system that uses proprietary desiccants and is “environmentally safe and reduces capital costs, as well 

as operating and compliance costs,” http://www.c-a-m.com/Forms/Product.aspx?prodID=fdee24ed-c860-40bb947a-fb917fcafe92. 

109 http://www.kwintl.com/glycol-dehydrators.html. 110 Methane to Markets slide presentation, “Production/Processing Best Practices: Natural Gas Dehydrator and 

Pneumatic Controller Optimization for Methane Emission Reductions”, Oil & Gas Subcommittee, Technology 

Transfer Workshop, January 28, 2009 Monterrey, Mexico, slide 24, 

http://methanetomarkets.org/documents/events_oilgas_20090127_techtrans_day2_plauchu1_en.pdf. 

111 http://www.epa.gov/gasstar/tools/recommended.html. 112 The California Air Resources Board’s Clearinghouse of non-CO2 Greenhouse Gas Emission Control 

Technologies, http://www.arb.ca.gov/cc/non-co2-clearinghouse/non-co2-clearinghouse.htm. 113 Draft Oil and Gas Ozone Reduction Strategy – Presented at February 26, 2008 Regional Air Quality Council 

Meeting, “APCD OZ ISSUE PAPER oil and gas all strategies.doc,” Prepared by the Colorado Air Pollution Control 

Division, Contact: Rose Waldman, available at 
"&

require the use of vapor recovery units with control efficiencies of at least 98%, or other 

technology or operational practice that would achieve a similar or greater reduction in methane 

emissions. CARB already lists the use of use of vapor recovery units at glycol dehydrators as a 

BMP for oil and gas sources.114

This technology is also an effective means of reducing methane emissions at offshore oil and gas 

operations. In a paper on offshore platform methane reduction strategies, the authors analyzed 

offshore oil and gas methane emissions and control strategies to devise an emission reduction 

strategy for the most significant sources at the lowest cost. The use of vapor recovery units at 

dehydrators is one of the recommended strategies for reducing methane emissions in offshore 

applications.115

Jatco Incorporated’s Jatco Vapor Recovery Unit (JVR) is an example of an available technology 

designed to recover vapors with use of a Venturi valve. According to manufacturer information, 

the JVR unit can be used in remote field application with no electrical power requirement and 

has wide-ranging applications including glycol dehydrators and storage tank vapors.116 This 

technology has been successfully applied by an EPA Natural Gas STAR partner in the DenverJulesburg Basin in Colorado to reduce methane, VOC and BTEX emissions.117

Additional benefits of VRUs include the economic benefit of the recovered salable gas as well as 

reductions in vented VOC and HAP emissions from the reboiler. 

Require the Use of Flash Tank Separators For Glycol Dehydrators 

Requiring the use of flash tank separators on glycol dehydrators is a cost-effective way to reduce 

methane emissions. Recovered gas can be recycled and used as a fuel for the reboiler or 

compressor engine. EPA Natural Gas STAR economic analyses show flash tank separators 

installed on dehydration units can payback costs in less than one year.118 Operation of a flash 

tank can capture approximately 90% of methane entrained by the glycol.119 EPA should require 

the use of flash tank separators on all glycol dehydration units. CARB already lists the use of 

flash tank separators for glycol dehydrators as a BMP for oil and gas sources.120

In addition to reduced methane emissions, use of flash tank separators will result in VOC and 

HAP emissions reductions, as well. The flash tank separator can capture approximately 10%-

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! http://www.cdphe.state.co.us/ap/ozone/RegDevelop/IssuePapers/February22-

08/APCDOZISSUEPAPEROGdehydrators_000.pdf. 

114 The California Air Resources Board’s Clearinghouse of non-CO2 Greenhouse Gas Emission Control 

Technologies, http://www.arb.ca.gov/cc/non-co2-clearinghouse/non-co2-clearinghouse.htm. 115 Bylin, Carey et al. for Society of Petroleum Engineers, “Designing the Ideal Offshore Platform Methane 

Mitigation Strategy,” 2010, p. 1.

116 Jatco Inc, http://www.jatcoinc.com/products/jatco-vapor-recovery-unit/jatco-vapor-recovery-unit. 117 See, “Methane Reduction from Natural Gas Dehydration in the DJ Basin,” Producers Technology Transfer 

Workshop, EPA’s Natural Gas STAR Program Glenwood Springs, CO September 11, 2007, 

http://www.epa.gov/gasstar/documents/workshops/2008-tech-transfer/rocksprings9.pdf. 118 Lessons Learned, Natural Gas STAR Partners, “Optimize Glycol Circulation and Install Flash Tank Separators in 

Glycol Dehydrators,” October 2006, http://www.epa.gov/gasstar/documents/ll_flashtanks3.pdf. 119 Id. 120 The California Air Resources Board’s Clearinghouse of non-CO2 Greenhouse Gas Emission Control 

Technologies, http://www.arb.ca.gov/cc/non-co2-clearinghouse/non-co2-clearinghouse.htm. 
"'

90% of the VOCs entrained by the glycol.121 And in particular, BTEX emission reductions with 

flash tank separator use can be significant for large dehydrators.122 Dehydration units that have 

flash tank separators in combination with a condenser on the reboiler vent result in overall 

improved efficiency of the condenser. 

Require Circulation Rate Adjustment Practices for All Glycol Pumps

Methane emissions from a glycol dehydrator are directly proportional to the amount of glycol 

circulated through the system; the higher the circulation rate the more methane is vented from 

the reboiler. Over time, production rates at the wellhead decline and circulation rates designed 

for the initial well production rate exceed those required for a mature well. According to EPA 

Natural Gas STAR partners, circulation rates “are often two to three times higher than the level 

needed to remove water from natural gas,” which means methane emissions are two to three 

times higher than necessary.123 Both the BLM and CARB list the optimization of circulation 

rates as a BMP for oil and gas sources.124 EPA should require operating practices that reduce 

circulation rates in order to reduce methane emissions. This practice can be implemented without 

affecting dehydration efficiency and without additional cost to the operator. EPA should require 

operators to review and adjust glycol circulation rates to optimize efficiency. Operators should 

also be required to incorporate circulation rate adjustments into regular O&M practices. 

Require Glycol Dehydrators to Use Portable Desiccant Dehydrators During Maintenance

During complete shutdowns for maintenance of glycol dehydrators, production wells can either 

be shut in or vented to the atmosphere. EPA should require the use of portable solid desiccant 

dehydrators in place of a glycol dehydrator during maintenance to avoid venting of methane to 

the atmosphere. The State of Colorado has proposed requiring the use of portable desiccant 

dehydrators at new installations.125

Require Installation of BASO® Valves

EPA should require that all new gas dehydrators employ BASO® valve technology to shut-off 

the gas flow in the event that pilot lights are extinguished (e.g., from high winds, etc.). This is a 

simple, cost-effective technology that prevents methane emissions that result when the pilot light 

is extinguished in any air-aspirated burner. 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

121 Lessons Learned, Natural Gas STAR Partners, “Producer and Processor Best Management Practices”, July 23, 

2008, http://www.epa.gov/gasstar/documents/workshops/2008-tech-transfer/midland7.ppt. 122 Lessons Learned, Natural Gas STAR Partners, “Optimize Glycol Circulation and Install Flash Tank Separators in 

Glycol Dehydrators”, October 2006, http://www.epa.gov/gasstar/documents/ll_flashtanks3.pdf. 123 Id. 124 U.S. Department of Interior, Bureau of Land Management, “Air Resource BMPs,” 8/24/09, www.blm.gov/gov 

and The California Air Resources Board’s Clearinghouse of non-CO2 Greenhouse Gas Emission Control 

Technologies, http://www.arb.ca.gov/cc/non-co2-clearinghouse/non-co2-clearinghouse.htm. 125 Colorado Air Pollution Control Division, Draft Oil and Gas Ozone Reduction Strategy – Presented at February 

26, 2008 RAQC Meeting. 
#+

3. Summary Recommendations for Dehydrators

Zero emission dehydrators virtually eliminate methane emissions from the dehydration process. 

The State of Wyoming’s existing requirements for dehydrators and the State of Colorado’s 

recent proposed control strategy for dehydrators are evidence that 98% control of emissions—

including methane emissions—from dehydrator units is technically and economically feasible. 

The fact that solid desiccant dehydrator technology can achieve 99% reduction in methane 

emissions and the use of flash tank separators and vapor recovery units in glycol dehydration 

systems can achieve 98% reduction in methane emissions means that EPA should call for 

nothing less than 98% reduction in methane emissions when considering technology standards 

and operation practices for this emissions source. 

Specifically, EPA should propose the following technology standards and operating practices for 

dehydration units: 

! Require the Use of Zero Emission Dehydrators 

EPA should require the use of zero emission dehydrator technology for all new 

installations. 

! Require the Use of Solid Desiccant Dehydrators in Cases Where Zero Emission 

Dehydrators Are Not Feasible 

EPA should require all new dehydrators to first use zero emission dehydrator technology 

and use solid desiccant technology in applications where zero dehydrator technology is 

not feasible. Solid desiccant dehydration should reduce methane emissions by 99%. If, 

after thorough consideration of existing state-of-the art technology, EPA determines that 

zero emission dehydration and solid desiccant dehydration are not universally applicable 

then EPA should require it where possible and also specific technology standards and 

operating practices for glycol dehydration units where zero emission dehydration and 

solid desiccant dehydration are not technically feasible. 

! Require Glycol Dehydrators to Use Vapor Recovery Units

EPA should require the use of vapor recovery units with control efficiencies of at least 

98%, or other technology or operational practices that would achieve a similar or greater 

reduction in methane emissions. 

! Require the Use of Flash Tank Separators 

EPA should require the use of flash tank separators on all glycol dehydration units to 

ensure reduction of methane emissions by at least 98%. 

! Require Circulation Rate Adjustment Practices for All Glycol Pumps

EPA should require operators to review and adjust glycol circulation rates to optimize 

efficiency. Operators should also be required to incorporate circulation rate adjustments 

into regular O&M practices. 
#*

! Require Glycol Dehydrators to Use Portable Desiccant Dehydrators During 

Maintenance

EPA should require the use of portable solid desiccant dehydrators in place of a glycol 

dehydrator during maintenance to avoid venting of methane to the atmosphere. 

! Require Installation of BASO® Valves

EPA should require that all new gas dehydrators employ BASO® valve technology to 

shut-off the gas flow in the event that pilot lights are extinguished (e.g., from high winds, 

etc.).

D. Tanks 

Onshore production and processing storage tanks and transmission storage tanks are sources of 

methane emissions from the oil and gas sector. Storage tanks provide for the temporary storage 

of liquids prior to when produced liquids are moved off-site for processing. Emissions of 

methane from storage activities occur through several mechanisms: (1) flashing losses that result 

when pressure is reduced in the tank; (2) working losses that result when filling and emptying of 

the storage tank occurs; and (3) breathing (or standing) losses that result when the tank gas 

volume expands and contracts in response to environmental conditions (e.g., changes in 

temperature and pressure). 

According to U.S. Greenhouse Gas Inventory data, storage tank venting accounts for about 5 

Bcf—or about 4 percent—of methane emissions from the production sector.126 These estimates, 

however, may grossly underestimate actual emissions from this source. According to EPA’s 

recent rulemakings for the Mandatory Reporting of Greenhouse Gases program, several 

emissions sources are believed to be “significantly underestimated” in the U.S. GHG Inventory 

(EPA/GRI/Radian, 1996).127,128 Specifically, EPA identifies crude oil and condensate storage 

tanks as a source of under-reported emissions where the true magnitude of emissions may be 

over five times greater than previous estimates. According to EPA, the emissions estimates for 

these under-reported 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.”129 EPA includes revised emission factor for all of the 

underestimated sources except the categories of crude oil and condensate storage tanks and 

flares, for which “no new reliable data are available.”130 The uncertainty in the degree to which 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

126 Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990 - 2007, USEPA, April, 2009, see

http://www.epa.gov/gasstar/basic-information/index.html#sources. 

127 EPA/GRI (1996) Methane Emissions from the Natural Gas Industry. Prepared by Harrison, M., T. Shires, J. 

Wessels, and R. Cowgill, eds., Radian International LLC for National Risk Management Research Laboratory, Air 

Pollution Prevention and Control Division, Research Triangle Park, NC. EPA-600/R-96-080a.

128 Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry Background Technical 

Support Document, U.S. Environmental Protection Agency Climate Change Division Washington DC, p. 7.

129 Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry Background Technical 

Support Document, U.S. Environmental Protection Agency Climate Change Division Washington DC, p. 23.

130 Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry Background Technical 

Support Document, U.S. Environmental Protection Agency Climate Change Division Washington DC, p. 7, also see 

Footnote 4: “EPA did consider the data available from two new studies, TCEQ (2009) and TERC (2009). However, 

it was found that the data available from the two studies raise several questions regarding the magnitude of 
#"

storage tank emissions are underestimated is sufficient reason to insist on rigorous performance 

standards and work practices for this particular category. However, there is even more evidence 

that the emissions estimates for this and other sources remain uncertain and continue to be 

greatly underestimated. 

A study prepared for the Texas Environmental Research Consortium measured emissions rates 

from several oil and condensate tanks in Texas and developed average emission factors based on 

direct measurement of vent gas flow rates.131 The U.S. GHG Inventory mentions this study but 

indicates that “[b]ecause of the limited dataset and unexpected jumps in data points which can be 

attributed to non-flashing emission affects, the United States decided that further investigation 

would be necessary before updating the inventory emission factor.”132 The study determined “the 

direct measurement approach to be the most accurate for estimating oil and condensate storage 

tank emissions at wellhead and gathering sites; however, other, less accurate, approaches appear 

to be much more commonly used.” EPA proposed the use of modeling (using “E&P Tank”) to 

calculate emissions from storage tanks in the GHG Mandatory Reporting Rule. Yet, the TSD for 

that rulemaking acknowledges significant weaknesses with this approach.133 And, in fact, the 

Western Climate Initiative recommended major changes to EPA’s proposed reporting 

requirements for this source category.134 Due to the uncertainty in the emissions from this source, 

EPA must commit to careful consideration of this source’s contribution to overall emissions of 

methane from the oil and gas sector and should consider implementation of the best available 

performance standards and operating practices in order to achieve methane reductions from this 

important source. 

1. Existing State, County and International Programs to Reduce Methane 

Emissions from Tanks

The following state, county, and international programs demonstrate that mandatory controls for 

reducing methane emissions are possible. EPA should consider these standards as minimum 

requirements for regulating sources under the NSPS. Regulations aimed at reducing VOCs and 

HAPs are relevant to consider because of the corresponding reductions in methane emissions that 

are achievable through implementation of these control technologies and practices. 

Colorado 

Colorado has several requirements applicable to condensate tanks or tank batteries in the Denver 

8-hour ozone nonattainment area. Any condensate tank or tank battery controlled with a 

combustion device must be equipped with auto-ignition upon startup at first date of production or 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! emissions from tanks and hence were not found appropriate for any further analysis until the issues are satisfactorily 

understood and/ or resolved by the authors and covered parties.”

131 Hendler A., Nunn J., Lundeen J., McKaskle R., “VOC Emissions from Oil and Condensate Storage Tanks Final 

Report”, April 2, 2009, available online at 

http://files.harc.edu/Projects/AirQuality/Projects/H051C/H051CFinalReport.pdf. 

132 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2008 (April 2010) U.S. EPA # 430-R-10-006, 

Chapter 3, p. 3-47.

133 Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry Background Technical 

Support Document, U.S. Environmental Protection Agency Climate Change Division Washington DC, p. 134.

134 See, http://www.westernclimateinitiative.org/component/remository/Reporting-Committee-Documents/. 
##

after any new tank installation or modification.135 In addition, surveillance systems must be used 

at all existing condensate tanks with uncontrolled actual emissions over 100 tpy or greater.136 Air 

pollution control equipment at new and modified condensate tanks must meet 95% control 

efficiency requirements for the first 90 days of operation. If compliance with the system-wide 

limits can be met after initial 90-day period, then the control equipment may be removed.137 

For the system-wide control strategy, which applies to all condensate tanks greater than 2 tpy of 

actual uncontrolled VOC, Colorado is using a tiered approach (with tighter controls during the 

summertime high ozone season) that ratcheted down VOC emissions from condensate tanks 

starting in 2005 with a 37.5% emission reduction required. All required reductions apply to 

actual uncontrolled emissions. For May 1, 2010 through April 30, 2011, 85% reductions are 

required between May 1 and September 30 and 70% reductions are required for October 1 

through April 30. For May 1, 2011 through April 30, 2013, 90% reductions are required between 

May 1 and September 30 and 70% reductions are required for October 1 through April 30.138 In 

2008, the Colorado Air Quality Control Commission considered a 95% system-wide control but 

decided to defer decisionmaking on that increased requirement at the time.139,140

Colorado has an additional state-only, statewide requirement that all condensate tanks with 

actual uncontrolled VOC emissions greater than 20 tpy must control emissions by 95%. This rule 

was effective in May 2008.141

The Colorado Oil and Gas Conservation Commission also regulates VOC emissions at 

condensate tanks and crude oil and produced water tanks in three counties142 with high volumes 

of oil and gas production that are outside of the ozone nonattainment or attainment/maintenance 

areas. Any condensate tanks or crude oil and produced water tanks with a potential to emit VOCs 

of 5 tpy or greater, that are located within 1⁄4 mile of certain public facilities or areas, must use 

control devices that can achieve 95% control efficiency and have an appropriate state permit.143 

Wyoming 

The state of Wyoming controls flashing emissions from tanks with statewide requirements and 

more stringent requirements for the Concentrated Development Area and the Jonah and Pinedale 

Anticline Development Area. Under these rules, “all vapor streams containing VOC or HAP 

components from all storage tanks (e.g., oil, condensate, produced water with oil or condensate 

carryover) and all separation vessels (e.g., gun barrels, production and test separators, production 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

135 CDPHE, Colorado Regulation 7, XII.C.1.e. 136 Id, XII.C.1.f. 137 Id, XII.D.1. 138 Id, XII.D.2. 139 Id, p. 96. 140 The goal of the 2008 rulemaking was to approve a plan that shows modeled attainment of the 8-hour ozone 

standard; 95% system-wide reductions for condensate tanks were was not necessary under the state’s modeling 

scenarios. 

141 Colorado Regulation 7, XVII.C. 142 Garfield, Mesa & Rio Blanco Counties. 143 Colorado Code of Regulations, 2 CCR 404-1 “Practice and Procedure,” §805 b(2)A & B, 

http://www.sos.state.co.us/CCR.
#$

and test treaters, water knockouts, gas boots, flash separators, drip pots, etc.) at a facility which 

are or may be vented to the atmosphere shall be considered.”144 The statewide requirements for 

new facilities or modified facilities with new and existing flashing emissions require 98% control 

when flashing emissions are equal to or greater than 10 tpy VOC.145 In the Concentrated 

Development Area the requirements are more stringent, with all new multiple well facilities and 

modified facilities with new or existing flash emissions required to meet 98% control for flashing 

emissions, regardless of annual VOC emissions. For single new well facilities or single modified 

well facilities in this area, any flashing emissions equal to or greater than 8 tpy VOC must be 

controlled by 98%.146 For the Jonah and Pinedale Anticline Development Area the rules are even 

more stringent, requiring that all new or modified facilities apply 98% controls for flash 

emissions.147

Wyoming also has a 98% VOC control efficiency requirement that applies to the Concentrated 

Development Area and the Jonah and Pinedale Anticline Development area. Under both sets of 

requirements new and modified facilities must control VOC and HAP emissions from all active 

produced water tanks by 98%.148 Open-top or blowdown tanks are not allowed to be used as 

active produced water tanks but can be used during emergency or upset conditions, in which case 

the 98% control requirements does not apply.149 

Montana 

Montana's requirements to control VOC emissions from wellhead assemblies, dehydrators and 

tanks also result in methane emissions reductions at these sources. The state's rules require that 

vented gas at larger sources (i.e., PTE > 15 TPY) be captured and routed to: (1) a gas pipeline; 

(2) a smokeless combustion device (equipped with an electronic ignition device or a continuous 

burning pilot system) operating at a 95% or greater control efficiency; or (3) an air pollution 

control device with equal or greater control efficiency than a smokeless combustion device.150

India 

A planned project in India at the Uran oil and natural gas processing plant, operated by the Oil & 

Natural Gas Corporation, would install vapor recovery units on storage tanks. The new units are 

expected to be operational by December 2010.151

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

144 Wyoming DEQ, C6 S2 O&G Production Facilities Permitting Guidance, March 2010, p. 5. 145 Id. 146 Id, 11. 147 Id, 18. 148 The only the difference between these 2 sets of requirements is that the CDA rules are slightly less stringent for 

new single well facilities, where 98% control efficiency is required within 60 days of first date of production at sites 

where 98% control of flashing emissions is required. 149 Wyoming DEQ, March 2010, 16 & 20. 150 Montana Administrative Rules §17.8.1711, “Oil or Gas Well Facilities Emission Control Requirements,” April 7, 

2006. http://www.mtrules.org/gateway/ruleno.asp?RN=17%2E8%2E1711.

151 Methane to Markets, Oil & Gas Methane Reduction Project Opportunity, Oil & Natural Gas Corporation, Uran 

Oil and Natural Gas Processing Plant, http://www.methanetomarkets.org/projects/projectDetail.aspx?ID=1146.
#%

Ventura County, California 

The Ventura County Air Pollution Control District crude oil production and separation rule 

applies to equipment used in the production, gathering, storage, processing, and separation of 

crude oil and natural gas. The requirements for storage tanks under this rule require that vapor 

recovery systems be installed and meet removal efficiencies of 90% for reactive organic 

compounds, or “[a] system which directs all vapors to a fuel gas system, a sales gas system, or to 

a flare that combusts reactive organic compounds” must be in place.152 

Ventura County also has a rule for the storage that applies to any equipment used to store crude 

oil or ROC liquids with a modified Reid vapor pressure greater than 0.5 psia. These rules include 

specifications for storage tanks based on their capacities, with requirements for vapor loss 

control devices, such as the use of an external floating roof, an internal floating roof, or a vapor 

recovery system. An acceptable vapor loss control device can also be any other system that has a 

control efficiency of 95% for ROC.153

2. Available Proven Technologies for Tanks

EPA’s own Natural Gas STAR program provides evidence that vapor recovery units are a 

technically feasible and cost-effective technology that can reduce methane emissions by at least 

95% from storage tanks. EPA should consider vapor recovery units as a cost-effective 

technology for reducing methane emissions from oil and natural gas systems. 

Require the Use of Vapor Recovery Units With at least 98% Control Efficiency for All New 

Crude Oil and Condensate Storage Tanks 

Vapor recovery units are relatively simple systems that can recover over 95% of vapors for sale 

or for use as fuel on-site. According to EPA, “vapor recovery can provide generous returns due 

to the relatively low cost of the technology.”154 As is evident by the longstanding local 

requirements in Ventura County, California and in the newer state regulations in Colorado, 

Wyoming and Montana, installations of vapor recovery units (VRUs) on all new crude oil and 

condensate tanks can easily be expected to achieve an efficiency of 95 percent. 

EPA should investigate the feasibility of requiring even higher control efficiencies (e.g., 98%) in 

line with the requirement in Wyoming for controlling VOC emissions from produced water 

tanks. In fact, Colorado has proposed 98% control of vapors from dehydrator VRUs, indicating 

that “many vapor recovery units and combustion devices already have control efficiencies of at 

least 98 percent.”155 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

152 Ventura County Air Pollution Control District, Rule 71.1- Crude Oil Production and Separation, last revised 

6/16/92, http://www.vcapcd.org/Rulebook/Rule4.htm.

153 Ventura County Air Pollution Control District, Rule 71.2- Storage of Reactive Organic Compound Liquids, last 

revised 9/26/89, http://www.vcapcd.org/Rulebook/Rule4.htm.

154 Lessons Learned, Natural Gas STAR Partners, “Installing Vapor Recovery Units on Crude Oil Storage Tanks”, 

October 2006, http://www.epa.gov/gasstar/documents/ll_final_vap.pdf. 155 Draft Oil and Gas Ozone Reduction Strategy – Presented at February 26, 2008 Regional Air Quality Council 

Meeting, “APCD OZ ISSUE PAPER oil and gas all strategies.doc”, Prepared by the Colorado Air Pollution Control 

Division, Contact: Rose Waldman, available online at 
#(

The vapor recovery unit industry has seen recent advances in technology. In addition to so-called 

“conventional” vapor recovery units (e.g., rotary compressor type systems and newer scroll 

compressors) there are other technologies evolving that may make VRUs even more cost 

effective for new installations. Namely, Vapor Jet technology156 and Venturi ejector vapor 

recovery units (EVRUTM)157 both have no moving parts and have shown to be effective in 

specific applications with reduced O&M costs.158 Vapor recovery towers (VRT) include a 

separation vessel that insulates the vapor recovery unit from gas surges and provides for 

stabilized pressure to allow more effective VRU performance.159 These cost-saving and 

performance-enhancing technology advancements further support the universal use of vapor 

recovery technology to effectively control methane emissions from crude oil and condensate 

storage tanks. 

EPA’s Environmental Technology Verification (ETV) program has evaluated the performance of 

Comm Engineering USA’s environmental vapor recovery unit (EVRUTM). The EVRUTM is a 

closed loop system designed to reduce or eliminate emissions of GHGs (methane and CO2), 

VOCs, and HAPS. The test EVRUTM was used to collect low-pressure vent gas from condensate 

storage tanks. The ETV program certified certain performance and environmental performance 

criteria for an EVRUTM unit installed in McAllen, Texas.160 The EPA’s ETV program was 

designed to facilitate the use of “innovative or improved environmental technologies through 

performance verification and information dissemination.” According to the EPA, “[t]he ETV 

program goal is to further environmental protection by accelerating the acceptance and use of 

improved and cost-effective technologies.”161 EPA should therefore consider the venturi-type 

EVRUTM as a technically and economically feasible option for all new tank installations. 

In addition to reducing methane, vapor recovery units also capture HAPs and, according to EPA, 

“can reduce operator emissions below actionable levels specified in Title V of the Clean Air 

Act.”162

Methane emissions also occur when methane and VOCs flash or evaporate into the air that is 

displaced during the loading process. EPA should require that all new installations include the 

use of a recycle line to recover gas from condensate loading operations that use mobile tanks 

(e.g., trucks or railroad). Recovered gas can then either be sent to a sales line or used for lease 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! http://www.cdphe.state.co.us/ap/ozone/RegDevelop/IssuePapers/February22-

08/APCDOZISSUEPAPEROGdehydrators_000.pdf. 

156 Patented technology by Hy-Bon Engineering. 157 Patented technology by COMM Engineering. 158 See, e.g., Lessons Learned, Natural Gas STAR Partner Presentation, “Vapor Recovery Tower/VRU 

Configuration”, Producers Technology Transfer Workshop, Long Beach, CA, August 21, 2007, 

http://www.epa.gov/gasstar/documents/vrt_vru_configuration_08_21_07.pdf. 

159 Methane to Markets Presentation, Reducing Methane Emissions With Vapor Recovery on Storage Tanks, 

January 28, 2009, Monterrey, Mexico, 

http://methanetomarkets.org/documents/events_oilgas_20090127_techtrans_day2_richards_en.pdf. 

160 ETV Joint Verification Statement, Quantum Leap Dehydrator, pp. S-4 and S-5, available online at 

http://www.epa.gov/etv/pubs/03_vs_quantum.pdf. The minimum detection limit was 0.1 ppmvd so methane 

concentrations were < 0.1 ppmvd (or < 0.00004 lb/hr).

161 Id. 162 Lessons Learned, Natural Gas STAR Partners, “Installing Vapor Recovery Units on Crude Oil Storage Tanks”, 

October 2006, http://www.epa.gov/gasstar/documents/ll_final_vap.pdf.
#)

fuel. A vapor recovery line and the appropriate connections should be designed to attach the line 

to the storage tank or a VRU. This operating practice has been shown to be cost-effective, 

particularly when the recovered gas is sent to a sales or fuel line.163 This practice will also result 

in reduced VOC and HAP emissions. 

Gas recovery is possible at any gas gathering station and processing plant that frequently 

removes condensed liquids from its upstream gathering lines. In these situations, recovering the 

flash gas from pressurized liquid storage tanks prior to atmospheric storage can reduce emissions 

and add more gas to the sales line. EPA should require this practice, where applicable. For 

example, systems where pressurized condensate is collected from “pigging” operations and 

stored in atmospheric tanks (i.e., storage tanks receiving condensate removed from 

launching/receiving pigging operations) should include vapor recovery controls to reduce vented 

emissions.164

This technology is also an effective means of reducing methane emissions at offshore oil and gas 

operations. In a paper on offshore platform methane reduction strategies, the authors analyzed 

offshore oil and gas methane emissions and control strategies to devise an emission reduction 

strategy for the most significant sources at the lowest cost. The use of vapor recovery units for 

storage tanks is one of the recommended strategies for reducing methane emissions in offshore 

applications.165

3. Summary Recommendations for Tanks

EPA should implement the following for all new storage tank installations: 

! Require the Use of Vapor Recovery Units With at least 98% Control Efficiency for All 

New Crude Oil and Condensate Storage Tanks 

EPA should require that all new installations include a VRU with a 98% control 

efficiency and should require the use of a recycle line to recover gas from condensate 

loading operations that use mobile tanks (e.g., trucks or railroad). EPA should also 

require recovery of gas from pipeline pigging operations. 

E. Wells 

Methane emissions from well venting (e.g., from liquids unloading, well completion and well 

workover) are a significant source of emissions from the natural gas production sector. 

According to U.S. Greenhouse Gas Inventory data, well venting and flaring account for about 7 

Bcf—or just over 5 percent—of methane emissions from the production sector. These estimates, 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

163 See EPA Natural Gas STAR Program Partner Reported Opportunities (PRO), PRO Fact Sheet No. 503, “Recycle 

Line Recovers Gas During Condensate Loading”, http://www.epa.gov/gasstar/documents/recyclelinerecovers.pdf. 164 See, e.g., EPA Natural Gas STAR Program Partner Reported Opportunities (PRO), PRO Fact Sheet No. 507, 

“Recover Gas From Pipeline Pigging Operations”, October 2004, 

http://www.epa.gov/gasstar/documents/pigging.pdf and Lessons Learned, Natural Gas STAR Partner Presentation, 

“Efficient Pigging of Gathering Lines”, Processor Technology Transfer Workshop, April 22, 2005, 

http://www.epa.gov/gasstar/documents/pigging_lines.ppt. 

165 Bylin, Carey et al. for Society of Petroleum Engineers, “Designing the Ideal Offshore Platform Methane 

Mitigation Strategy,” 2010, p. 1.
#&

however, may grossly underestimate actual emissions from this source. According to EPA’s 

recent rulemakings for the Mandatory Reporting of Greenhouse Gases program, several 

emissions sources are believed to be “significantly underestimated” in the U.S. GHG Inventory 

(EPA/GRI/Radian, 1996).166,167 Specifically, EPA identifies well venting for liquids unloading, 

gas well venting during well completions and gas well venting during well workovers as three 

sources of under-reported emissions. 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.”168 EPA includes revised emission factors for all of these underestimated well venting 

sources, as follows: (1) an emission factor for well venting for liquids unloading that is 11 times 

higher; (2) an emission factor for venting during completions that is 35 times higher for 

conventional wells and almost 9,000 times higher for unconventional wells; and (3) an emission 

factor for gas well venting during well workovers that is 3,500 times higher for unconventional 

wells.169 Overall, the revisions to these and the revised factor for centrifugal compressor wet seal 

degassing venting results in a more than 100% increase in estimated emissions from the oil and 

gas production sector.170 These enormous underestimates, alone, are enough of a reason to insist 

on rigorous performance standards and work practices for these particular categories. However, 

there is even more evidence that the emissions estimates for these and other sources remain 

uncertain and continue to be greatly underestimated. 

An area of particular uncertainty appears to be gas well completions and well workovers. As 

EPA notes in the preamble to the proposed mandatory reporting rule: 

[N]o body of data has been identified that can be summarized into generally 

applicable emissions factors to characterize emissions from these sources [(i.e., 

from well completion venting and well workover venting)] in each unique field. 

In fact, the emissions factor being used in the 2008 U.S. GHG Inventory is 

believed to significantly underestimate emissions based on industry experience as 

included in the EPA Natural Gas STAR Program publicly available information 

(http://www.epa.gov/gasstar/). In addition, the 2008 U.S. GHG Inventory 

emissions factor was developed prior to the boom in unconventional well drilling 

(1992) and in the absence of any field data and does not capture the diversity of 

well completion and workover operations or the variance in emissions that can be 

expected from different hydrocarbon reservoirs in the country.171 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

166 EPA/GRI (1996) Methane Emissions from the Natural Gas Industry. Prepared by Harrison, M., T. Shires, J. 

Wessels, and R. Cowgill, eds., Radian International LLC for National Risk Management Research Laboratory, Air 

Pollution Prevention and Control Division, Research Triangle Park, NC. EPA-600/R-96-080a.

167 Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry Background Technical 

Support Document, U.S. Environmental Protection Agency Climate Change Division Washington DC, p. 7.

168 Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry Background Technical 

Support Document, U.S. Environmental Protection Agency Climate Change Division Washington DC, p. 23.

169 Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry Background Technical 

Support Document, U.S. Environmental Protection Agency Climate Change Division Washington DC, p. 8, Table 1.

170 Id. at 9. 171 75 FR 18621, April 12, 2010. 
#'

As noted, there is believed to be a significant underestimate in emissions from well completions 

based on industry experience as reported through EPA’s Natural Gas STAR program. The 2008 

U.S. GHG Inventory emphatically states that “[n]atural gas well venting due to unconventional 

well completions and workovers, as well as conventional gas well blowdowns to unload liquids 

have already been identified as sources for which Natural Gas STAR reported reductions are 

significantly larger than the estimated inventory emissions.”172 And EPA has indicated that 

“[p]resently, [reduced emission completions (REC)] reductions reported in the Natural Gas 

STAR body of work is larger than well completion venting in the inventory on an annual 

basis.”173 Specifically, the U.S. GHG Inventory is based on an emission factor of a little over 

three thousand standard cubic feet (3 Mcf) per gas well drilled and completed.174 Yet, Natural 

Gas STAR program partner experience shows several cases where emission factors were 

thousands of times higher than that shown in the 2008 inventory. Examples include: (1) a BP 

project employing green completions at 106 wells and reporting 3,300 Mcf of gas recovered per 

well;175 (2) a Devon Barnett Shale project employing green completions at 1,798 wells between 

2005 and 2008 and reporting 6,300 Mcf of gas recovery per well;176 and (3) a Williams project 

employing green completions at 1,064 wells in the Piceance Basin reporting 22,000 Mcf of gas 

recovered per well.177 All of these examples include gas recovery estimates more than 1,000 

times higher than the 3 Mcf of gas per well estimated in the U.S. GHG Inventory for 2008. These 

data are consistent with the unconventional gas well completion and workover data presented in 

EPA’s TSD for the MRR revisions (April 2010). Specifically, the technical support document 

includes four examples from the Natural Gas STAR program with gas completion rates of 6,000 

Mcf, 10,000 Mcf, 700 Mcf and 20,000 Mcf per completion.178 EPA used an average of these four 

data points for its emission factor for this source (i.e., 9,175 Mcf/completion). Using this factor 

resulted in estimated emissions from completions and well workover from conventional and 

unconventional wells of 120 billion standard cubic feet (Bcf). In comparison, the U.S. GHG 

Inventory reports emissions of just 0.1 Bcf of gas from drilling and well completions.179 

More generally, Natural Gas STAR partners reported recovering between 7 and 12,500 Mcf 

(average of 3,000 Mcf) of natural gas from each cleanup with the potential for an estimated 25 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

172 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2008 (April 2010) U.S. EPA # 430-R-10-006, 

p. 3-47.

173 See “Environmental Defense Fund (EDF) Questions & USEPA Answers – June 1, 2010” posted to the Docket for 

EPA’s MRR revisions to Subpart W on June 2, 2010, Docket ID EPA-HQ-OAR-2009-0923-0070.

174 Table A- 118: 2008 Data and CH4 Emissions (Mg) for the Natural Gas Production Stage, p. A-144, Inventory of 

U.S. Greenhouse Gas Emissions and Sinks: 1990-2008 (April 2010) U.S. EPA # 430-R-10-006.

175 See Natural Gas STAR Program Recommended Technologies and Practices for Wells at 

http://www.epa.gov/gasstar/tools/recommended.html, and specifically 

http://www.epa.gov/gasstar/documents/green_c.pdf, slide 11. 176 See attached 2009 workshop presentation by Devon, slides 3 and 13. 6,300 Mcf = 11.4 Bcf / 1,798 wells. 177 See Natural Gas STAR Program Recommended Technologies and Practices for Wells at 

http://www.epa.gov/gasstar/tools/recommended.html, and specifically 

http://www.epa.gov/gasstar/documents/vincent.pdf, slide 14. 178 Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry Background Technical 

Support Document, U.S. Environmental Protection Agency Climate Change Division Washington DC, Appendix B 

on pp. 79-82.

179 See Table A-125: CH4 Emission Estimates from the Natural Gas Production Stage Excluding Reductions from 

the Natural Gas STAR Program and NESHAP regulations (Gg), p. A-151, Inventory of U.S. Greenhouse Gas 

Emissions and Sinks: 1990-2008 (April 2010) U.S. EPA # 430-R-10-006. Drilling and Well Completion (2008) = 

2.05 Gg. (2.05 Gg * 0.052 ft3

/g = 0.1 Bcf)
$+

Bcf of natural gas recovery from green completions annually in 2005 compared with the annual 

U.S. GHG Inventory total for “Drilling and Well Completion” of just 0.1 Bcf in 2008.180,181 And 

more recently, EPA’s Natural Gas STAR program attributed 45 Bcf of gas to reduced emissions 

completions (RECs) in 2008 (representing 50 percent of EPA’s Natural Gas STAR program’s 

annual total reductions).182 If, in fact, the emission factor for well completions is at least 1,000 

times higher than what is reported in the U.S. GHG Inventory (e.g., if it is at least 3,000 Mcf 

instead of 3 Mcf) this would add 100 Bcf to the total estimated emissions from natural gas 

systems, raising the total from 240 Bcf to 340 Bcf in 2008 (a 40% increase).183 

A New York Times article published on October 15, 2009, reports that EPA is currently 

reviewing and revising methane emissions from U.S. gas wells. According to the article: 

An E.P.A. review of methane emissions from gas wells in the United States 

strongly implies that all of these figures may be too low. In its analysis, the E.P.A. 

concluded that the amount emitted by routine operations at gas wells—not 

including leaks like those seen near Franklin—is 12 times the agency’s longtime 

estimate of nine billion cubic feet. In heat-trapping potential, that new estimate 

equals the carbon dioxide emitted annually by eight million cars.184

In fact, the TSD for the April 2010 MRR includes an estimate of 120 Bcf for U.S. completion 

and workover venting. As previously discussed, this estimate is based on an emission factor of 

9,175 Mcf per completion or workover. Given the sparse data (4 data points) and the enormously 

wide range of potential emission factor values from this source (ranging from 700 to 20,000 

Mcf) even the recently revised estimates may very well continue to underestimate emissions 

from this source. 

The statistical representation of the U.S. GHG Inventory data includes a 95% range within which 

emissions from this source category are likely to fall for the year 2008. This range, for Natural 

Gas Systems, includes a lower bound of -24% and an upper bound of +43%.185 As noted in the 

uncertainty analysis, “[t]he heterogeneous nature of the natural gas industry makes it difficult to 

sample facilities that are completely representative of the entire industry.”186 And as a result, 

basing an emission factor on only a few “representative” sources when considering the highly 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

180 See http://www.epa.gov/gasstar/documents/green_c.pdf, slides 9 and 5. 181 See Table A-125: CH4 Emission Estimates from the Natural Gas Production Stage Excluding Reductions from 

the Natural Gas STAR Program and NESHAP regulations (Gg), p. A-151, Inventory of U.S. Greenhouse Gas 

Emissions and Sinks: 1990-2008 (April 2010) U.S. EPA # 430-R-10-006. Drilling and Well Completion (2008) = 

2.05 Gg.

182 See 2009 EPA Natural Gas STAR Program Accomplishments, available online at 

http://www.epa.gov/gasstar/documents/ngstar_accomplishments_2009.pdf. Total sector reductions (2008) = 89.3 

Bcf of which 50% are the result of RECs (50% of 89.3 Bcf = 45 Bcf). 

183 See Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2008 (April 2010) U.S. EPA # 430-R-10-

006, Chapter 3, Table 3-38 CH4 Emissions from Natural Gas Systems (Gg), p. 3-45. Total emissions in Bcf: 4,591 

Gg * 0.052 ft3

/g = 240 Bcf. 184 See www.nytimes.com/2009/10/15/business/energy-environment/15degrees.html#. 185 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2008 (April 2010) U.S. EPA # 430-R-10-006, 

Chapter 3, Table 3-41, p. 3-46.

186 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2008 (April 2010) U.S. EPA # 430-R-10-006, 

Chapter 3, p. 3-46.
$*

variable rates measured among these sources, results in a potentially high degree of uncertainty 

as reflected in the reported uncertainty range. 

We are hopeful that the EPA-acknowledged discrepancies between the inventory emissions 

reported to-date and the Natural Gas STAR reported reductions and the high degree of 

uncertainty in both of these data sources will be reconciled with a rigorous reporting rule for the 

oil and gas sector and, in particular, for vented emissions from wells. We also hope that EPA will 

employ rigorous performance standards for this critical source that is likely a much more 

significant source of emissions than what is reflected in the U.S. GHG inventory. 

It is worth noting that direct measurement of emissions from well venting for liquids unloading 

as well as during unconventional well completions and well workovers is possible as a means to 

accurately demonstrate compliance with performance standards established by EPA. EPA 

proposed direct measurement methods for determining reported emissions under the Mandatory 

Reporting Rule (MRR) for these source types.187

1. Existing State Programs to Reduce Methane Emissions from Wells

The following state programs demonstrate that mandatory controls for reducing methane 

emissions are possible. EPA should consider these standards as minimum requirements for 

regulating sources under the NSPS. Regulations aimed at reducing VOCs and HAPs are relevant 

to consider because of the corresponding reductions in methane emissions that are achievable 

through implementation of these control technologies and practices. 

Colorado 

The Colorado Oil and Gas Conservation Commission requires that green completions be 

installed at all wells in the state that meet a threshold requirement, except in cases where green 

completions are not technically or economically practical. Green completions are also not 

required on exploratory wells. “Green completion practices are required on oil and gas wells 

where reservoir pressure, formation productivity, and wellbore conditions are likely to enable the 

well to be capable of naturally flowing hydrocarbon gas in flammable or greater concentrations 

at a stabilized rate in excess of five hundred (500) MCFD to the surface against an induced 

surface backpressure of five hundred (500) psig or sales line pressure, whichever is greater.”188

Sand traps, surge vessels, separators and tanks must be used during flowback and cleanout 

operations, with a few exceptions. The aforementioned control devices must be used when the 

well effluent containing more than ten barrels per day of condensate or within two hours after 

first encountering hydrocarbon gas of salable quality. With this process, sand, hydrocarbon 

liquids, water, and gas are safely separated to ensure that the, “salable products are efficiently 

recovered for sale or conserved and that non-salable products are disposed of in a safe and 

environmentally responsible manner.”189 If green completions are deemed not feasible, then the 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

187 75 FR 18608, April 12, 2010. Note, EPA proposed engineering estimates as the means for demonstrating 

compliance for conventional well completions and conventional well workovers.

*&& Colorado Code of Regulations, 2 CCR 404-1 “Practice and Procedure,” §805 b(3)B, 

http://www.sos.state.co.us/CCR.

189 Id.
$"

operator must use other BMPs in order to minimize emissions, such as limiting the amount of 

flaring and venting.190

Wyoming 

As per Wyoming’s oil and gas production facilities permitting guidance, all operators must 

submit permit applications that apply best management practices for well completions or recompletions. The permits completed for the Jonah and Pinedale Anticline Development Area are 

the models to be used. The Wyoming Air Quality Division provides a sample well completion or 

green completion permit. The permits state: “The operator shall follow the operational plan for 

Best Management Practices described in the application for this permit to eliminate to the extent 

practicable emissions of volatile organic compounds and hazardous air pollutants associated with 

flaring and venting of hydrocarbon fluids recovered during well completion/re-completion 

activities.”191 Conditions under which it is unacceptable to send gas to the flare are listed in this 

permit. The permits also must include monitoring, recordkeeping, notification and reporting 

requirements. The Air Quality Division’s Well Completion Emission Spreadsheet must be used 

to calculate estimates of VOC, total HAPs, NOX and CO.192 

Montana 

Montana's requirements to control VOC emissions from wellhead assemblies also result in 

methane emissions reductions at these sources. The state's rules require that vented gas at larger 

sources (i.e., PTE > 15 TPY) be captured and routed to: (1) a gas pipeline; (2) a smokeless 

combustion device (equipped with an electronic ignition device or a continuous burning pilot 

system) operating at a 95% or greater control efficiency; or (3) an air pollution control device 

with equal or greater control efficiency than a smokeless combustion device.193

2. Available Proven Technologies for Wells

EPA’s own Natural Gas STAR program provides evidence that there are many available, 

technically feasible and cost-effective technologies that can greatly reduce methane emissions 

from wells. These options include both: (1) technology standards for wells; and (2) improving 

operating practices to reduce emissions. EPA should, at a minimum, require the following 

technologies and operating practices as part of its revised NSPS for oil and natural gas systems. 

Require the Use of Reduced Emission Completions or Green Completions 

During a reduced emission completion (REC) or “green completion” the produced natural gas 

from a well completion or well workover is recovered for salable use instead of being vented to 

the atmosphere (or flared). Produced gas condensate can also be recovered. This method of 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

190 Id., §805 b(3)C & D. 191 “Example Well Completions (“Green Completions”) Permit,” Wyoming Department of Environmental Quality, 

March 2010, p. 1.

192 Id. 193 Montana Administrative Rules §17.8.1711, “Oil or Gas Well Facilities Emission Control Requirements,” April 7, 

2006. http://www.mtrules.org/gateway/ruleno.asp?RN=17%2E8%2E1711.
$#

reducing methane emissions during gas production has been proven to be cost-effective by 

partners in EPA’s Natural Gas STAR program for over five years.194 RECs require additional 

equipment to convert the otherwise-vented gas to salable gas. Additional portable equipment is 

required and may include tanks, portable separators, sand traps, and portable gas dehydration 

devices. The equipment would be moved from well to well, as needed. Even with the additional 

capital costs for this equipment, EPA Natural Gas STAR partners report payback periods of less 

than a year for reduced emission completions.195 EPA Natural Gas STAR partners also report 

recovering up to 89% of total gas produced during well completions and workovers (average of 

53%) from high-pressure wells.196 And, in fact, at least one Natural Gas STAR partner has 

reported 100% recovery of completion gas.197 Other, more generalized, estimates of methane 

reduction efficiency based on EPA’s Natural Gas STAR partner data are around 70% for green 

completions.198 Certainly, higher efficiencies can be expected from the best available technology 

and design. Technology advances have also made recovery of gas from low-pressure wells 

possible. For example, the use of portable compressors can be used when the reservoir pressure 

is too low to enter the gas sales line.199 

EPA should require the use of reduced emission completions for all new wells unless deemed 

unsafe, as demonstrated and documented by the operator. EPA should also require 90%, or 

better, recovery. Both the BLM and CARB list green completions as a BMP for oil and gas 

sources.200 This proven, best management practice should be required for all new wells in order 

to achieve greater emission reductions. 

EPA should also require the use of portable desiccant dehydrators to support green completions. 

RECs can employ solid desiccant dehydrators that are brought on site to process vented gas 

(from well completions and workovers) before sending it to the sales line.

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

194 See EPA Natural Gas STAR Program Partner Reported Opportunities (PRO), PRO Fact Sheet No. 703, “Green 

Completions”, September 2004, http://www.epa.gov/gasstar/documents/greencompletions.pdf and Lessons Learned, 

Natural Gas STAR Partners, “Reduced Emission Completions (Green Completions)”, October 26, 2005, 

http://www.epa.gov/gasstar/documents/green_c.pdf and “Reducing Methane Emissions During Completion 

Operations”, 2006 Natural Gas STAR Annual Implementation Workshop, Houston, TX, October 24, 2006, 

http://www.epa.gov/gasstar/documents/vincent.pdf and Lessons Learned, Natural Gas STAR Partners, “Reducing 

Methane Emissions from Production Wells: Reduced Emission Completions”, May 11, 2010, 

http://epa.gov/gasstar/documents/workshops/farmington-2010/08_recs_farmington_nm_final.pdf. 195 Lessons Learned, Natural Gas STAR Partners, “Reducing Methane Emissions from Production Wells: Reduced 

Emission Completions”, May 11, 2010, http://epa.gov/gasstar/documents/workshops/farmington2010/08_recs_farmington_nm_final.pdf.

196 Lessons Learned, Natural Gas STAR Partners, “Reduced Emission Completions (Green Completions)”, October 

26, 2005, http://www.epa.gov/gasstar/documents/green_c.pdf.

197 See Williams Production RMT, Piceance Basin Operations, “Reducing Methane Emissions During Completion 

Operations”, 2006 Natural Gas STAR Annual Implementation Workshop, Houston, TX, October 24, 2006, 

http://www.epa.gov/gasstar/documents/vincent.pdf. 198 Robinson, D.R., Fernandez, R., Kantamaneni, R. K., “Methane Emissions Mitigation Options in the Global Oil 

and Natural Gas Industries, Table 2, 

http://www.coalinfo.net.cn/coalbed/meeting/2203/papers/naturalgas/NG020.pdf. 

199 Lessons Learned, Natural Gas STAR Partners, “Reducing Methane Emissions from Production Wells: Reduced 

Emission Completions”, May 11, 2010, http://epa.gov/gasstar/documents/workshops/farmington2010/08_recs_farmington_nm_final.pdf.

200 U.S. Department of Interior, Bureau of Land Management, “Air Resource BMPs,” 8/24/09, www.blm.gov/gov 

and The California Air Resources Board’s Clearinghouse of non-CO2 Greenhouse Gas Emission Control 

Technologies, http://www.arb.ca.gov/cc/non-co2-clearinghouse/non-co2-clearinghouse.htm. 
$$

In addition to reducing methane emissions, RECs produce an additional revenue stream from the 

recovery of produced natural gas and gas liquids. RECs also result in less solid waste and water 

pollution and safer operating conditions. 

Require the Installation of Plunger Lift Systems in Gas Wells to Reduce Methane Emissions 

From Blowdown Operations

Venting of a mature well to the atmosphere (well blowdown) in order to remove accumulated 

fluids can be a significant source of methane emissions. Instead of venting gas wells to force out 

accumulated well bore fluids, a plunger lift uses the well’s energy to efficiently push the fluids 

out of the well. According to EPA, plunger lift systems are a cost-effective alternative to other 

lift technologies and to well blowdowns and “can significantly reduce gas losses, eliminate or 

reduce the frequency of future well treatments, and improve well productivity.”201 EPA lists this 

technology as having a less than one-year payback.202 Since there are certain technical feasibility 

considerations for these systems (e.g., the well shut-in pressure has to be sufficiently higher than 

the sales line pressure), EPA should require the use of plunger lift systems at all gas wells unless 

the operator can adequately demonstrate that the well will not operate with sufficient shut-in 

pressure or production rate to be able to use such a system. EPA should also review the 

feasibility of requiring the use of pumpjacks and foaming agents when there is insufficient buildup in reservoir pressure to operate a plunger lift system and the use of velocity tubing strings for 

wells operating with higher reservoir pressure.203

Use of the latest information technology (e.g., online data management, satellite 

communications, etc.) can help reduce management costs (e.g., operator visits) of these systems 

and help optimize operational practices. In fact, one partner’s experience is that “[t]echnology is 

only a piece of the solution—most significant recent reductions are due to revised operational 

practices.”204 This partner reported an over 80% reduction in venting.205 EPA should require the 

installation of automated well monitoring systems to help optimize plunger lift and blowdown 

operations. “Smart Automation” systems monitor well production parameters (e.g., pressure, 

flow rate, plunger velocities, etc.) and use remote telemetry coupled with site-specific 

operational data to improve well and venting performance. These types of automated systems 

have enabled significant reductions in gas venting volumes along with production 

improvements.206 The BLM lists the use of “Smart Automation” systems as a BMP.207 Other 

operational practices include well-specific practices such as optimizing well blowdown times by 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

201 Lessons Learned, Natural Gas STAR Partners, “Installing Plunger Lift Systems in Gas Wells”, October 2006, 

http://www.epa.gov/gasstar/documents/ll_plungerlift.pdf. 202 See http://www.epa.gov/gasstar/tools/recommended.html. 203 See EPA Natural Gas STAR Program Partner Reported Opportunities (PRO), PRO Fact Sheet Nos. 706, 707, and 

704 “Use Foaming Agents”, “Install Pumpjacks on Low Water Production Gas Wells” and “Install Velocity Tubing 

Strings”, http://www.epa.gov/gasstar/documents/usefoamingagents.pdf , 

http://www.epa.gov/gasstar/documents/gaswells.pdf and 

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

204 EPA Natural Gas STAR Presentation, “Plunger Well Vent Reduction Project, G.P. (Skip) Desaulniers, BP, 2006 

Natural Gas Star Workshop, http://www.epa.gov/gasstar/documents/desaulniers.pdf. 205 Id. See Southern San Juan Quarterly Vent Volumes (slide 16). 206 See EPA Natural Gas STAR Program Partner Reported Opportunities (PRO), PRO Fact Sheet No. 709, “Gas 

Well “Smart” Automation System”, http://www.epa.gov/gasstar/documents/smart_automation.pdf.

207 U.S. Department of Interior, Bureau of Land Management, “Air Resource BMPs,” 8/24/09, www.blm.gov/gov.
$%

monitoring well flow conditions.208 EPA should require all operators to develop an operational 

plan, based on the above practices, for managing the plunger lift systems so as to minimize 

venting. 

Other benefits of plunger lift installations include gas savings from avoided blowdowns as well 

as increased gas production following plunger lift installations. According to EPA, benefits from 

increased gas production are “well- and reservoir-specific and will vary considerably.”209 EPA 

Natural Gas STAR partners have reported reductions in other air pollutants, as well, with 

installation of plunger lift technology.210 Both the BLM and CARB list the installation of plunger 

lifts as a BMP for oil and gas sources.211 Wyoming also has a BMP that requires VOC and HAP 

emissions from manual and automated blowdown and venting episodes be minimized to the 

maximum extent practicable.212

Require the Installation of Downhole Separator Pumps, Where Applicable

Downhole separator pumps, or hydrocyclones, are used for gas-liquid separation. The pumps are 

installed upon well completion or well workover and are designed to separate gas from water 

below the surface and then inject the water into a lower lying aquifer for disposal while sending 

the methane gas to the surface.213 Use of these pumps eliminates methane emissions from 

produced water storage. EPA should require the installation of downhole separator pumps in 

applications where there is a lower lying water disposal aquifer. 

Require Mud Degassing Vents Be Routed to a Vapor Recovery Unit

Mud degassing systems are used to remove entrained formation gas from the drilling mud 

(drilling fluid) to maintain higher mud density for well control. Drilling mud degassing units 

extract entrained gas from the mud at the surface and vent this gas directly into the atmosphere. 

EPA should require that these vents be routed to a vapor recovery unit to reduce methane 

emissions. 

A recent paper on offshore platform methane reduction strategies analyzed offshore oil and gas 

methane emissions and control strategies and devised an emission reduction strategy for the most 

significant sources at the lowest cost. Using a vapor recovery unit to capture mud degassing 

emissions is one of the recommended strategies for reducing methane emissions in offshore 

applications.214 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

208 See EPA Natural Gas STAR Program Partner Reported Opportunities (PRO), PRO Fact Sheet No. 708, “Gas 

Well Unloading Time Optimization”, http://www.epa.gov/gasstar/documents/unloading_time508.pdf

209 Lessons Learned, Natural Gas STAR Partners, “Installing Plunger Lift Systems in Gas Wells”, October 2006, 

http://www.epa.gov/gasstar/documents/ll_plungerlift.pdf. 210 ExxonMobil reported that their plunger lift system in the Big Piney Field in Wyoming “reduced the venting of 

ethane (6 percent by volume), C3 hydrocarbons + VOCs (5 percent), and inerts (2 percent).” Id. 211 U.S. Department of Interior, Bureau of Land Management, “Air Resource BMPs,” 8/24/09, www.blm.gov/gov 

and The California Air Resources Board’s Clearinghouse of non-CO2 Greenhouse Gas Emission Control 

Technologies, 988NRPPSSSJ7=1J47JF-<P44P:-:T4-"T4267=3:F9-0D6P:-:T4-"T4267=3:F9-0D6J98>J 212 Wyoming DEQ, C6 S2 O&G Production Facilities Permitting Guidance, March 2010, 10, 17 & 21. 213 See EPA Natural Gas STAR Program Partner Reported Opportunities (PRO), PRO Fact Sheet No. 705, “Install 

Downhole Separator Pumps”, http://www.epa.gov/gasstar/documents/installdownholeseparatorpumps.pdf. 214 Bylin, Carey et al. for Society of Petroleum Engineers, “Designing the Ideal Offshore Platform Methane 
$(

3. Summary Recommendations for Wells

EPA should implement the following technology standards and operating practices for all new 

wells: 

! Require the Use of Reduced Emissions Completions or Green Completions 

EPA should require the use of reduced emission completions for all new wells unless 

deemed unsafe, as demonstrated and documented by the operator. EPA should also 

require 90%, or better, recovery. EPA should also require the use of portable desiccant 

dehydrators to support green completions. 

! Require the Installation of Plunger Lift Systems and the Development of Operational 

Practices that Minimize Methane Emissions 

EPA should require the use of plunger lift systems at all gas wells unless the operator can 

adequately demonstrate that the well will not operate with sufficient shut-in pressure or 

production rate to be able to use such a system. EPA should also require all operators to 

develop an operational plan for managing the plunger lift systems so as to minimize 

venting. 

! Require the Installation of Downhole Separator Pumps, Where Applicable

EPA should require the installation of downhole separator pumps in applications where 

there is a lower lying water disposal aquifer. 

! Require Mud Degassing Vents Be Routed to a Vapor Recovery Unit

EPA should require that mud degassing vents be routed to a vapor recovery unit to reduce 

methane emissions. 

F. Pipelines 

Natural gas produced from gas fields is transported through pressurized pipelines to distribution 

systems. These pipelines require regular repair and maintenance as a result of corrosion (to both 

interior and exterior surfaces), leaks, materials failures, and damage caused by external factors. 

According to U.S. Greenhouse Gas Inventory data, pipeline leaks account for about 8 Bcf—or 

about 8 percent—of methane emissions from the transmission sector.215 

1. Planned State Programs to Reduce Methane Emissions from Pipelines

Under CARB’s Climate Change Scoping Plan, the state is considering a requirement for oil and 

gas operators to replace older equipment, such as flanges, valves and fittings, along pipelines.216 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!! Mitigation Strategy,” 2010, p. 1.

215 Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990 - 2007, USEPA, April, 2009, see

http://www.epa.gov/gasstar/basic-information/index.html#sources. 

216 “Climate Change Scoping Plan Appendices, Volume 1: Supporting Documents and Measure Detail, a framework 

for change,” California Air Resources Board, December 2008, pp. C-153 and C-154, 

http://www.arb.ca.gov/cc/scopingplan/document/appendices_volume1.pdf#page=184.
$)

2. Available Proven Technologies for Pipelines

EPA’s own Natural Gas STAR program provides evidence that there are many available, 

technically feasible and cost-effective technologies and operating practices that can greatly 

reduce methane emissions from pipelines. These options include both: (1) technology standards; 

and (2) improving operating practices to reduce emissions. EPA should, at a minimum, consider 

the following technologies and operating practices as cost-effective standards for reducing 

methane emissions from oil and natural gas systems. 

Require the Use of Gas Main Flexible Liners and State-of-the-Art Pipeline Material and 

Protective Coatings 

Cast iron and steel piping materials used in underground gas distribution systems have the 

highest leakage factors of all distribution piping materials.217 According to EPA, plastic pipe has 

the lowest leakage rate.218 EPA should require the use of the plastic pipe wherever feasible. 

Where the use of plastic pipe is not feasible EPA should require the use of flexible plastic insert 

liners. These types of plastic liners use the outer material for support but provide for the low 

leakage rates of plastic piping. 

For pipelines that would be designed to have a protective coating, EPA should require the use of 

the best available coating technology to ensure maximum protection of piping materials. For 

example, PRITEC® is a protective coating made of a mixture of butyl adhesive and polyethylene 

that, according to EPA, is designed to “withstands exposure to weather and ultraviolet radiation 

for prolonged periods without degradation”.219 With increasing demand for oil and gas, pipelines 

are being installed in ever-more difficult environments. The pipeline coatings industry is 

reporting market developments and technology and materials innovations to meet the demands of 

today’s applications.220 Degradation of coatings due to exposure to the sun and to water (e.g., in 

marine environments) can result in pipe corrosion and leaks. Requiring the use of the best 

available coating technology will help to minimize this potential source of methane emissions 

from pipelines. CARB already lists the replacement of cast iron and steel piping as a BMP for oil 

and gas sources.221

Require Several Operating and Maintenance Practices for Pipelines

In 2004, an estimated 12 Bcf of methane was vented to the atmosphere during routine pipeline 

maintenance and pipeline upsets. EPA should require that during routine maintenance, operators 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

217 See EPA Natural Gas STAR Program Partner Reported Opportunities (PRO), PRO Fact SheetsNo. 403, “Insert 

Gas Main Flexible Liners”, http://www.epa.gov/gasstar/documents/insertgasmainflexibleliners.pdf. 218 Id. 219 See EPA Natural Gas STAR Program Partner Reported Opportunities (PRO), PRO Fact SheetsNo. 406, “Use of 

Improved Protective Coating at Pipeline Canal Crossings”, 

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

220 See, e.g., the following October 20, 2010 News Report, “Pipeline Coatings Makers Face Historic Demands”, 

http://www.paintsquare.com/news/article_news.cfm?id=4507. 221 The California Air Resources Board’s Clearinghouse of non-CO2 Greenhouse Gas Emission Control 

Technologies, http://www.arb.ca.gov/cc/non-co2-clearinghouse/non-co2-clearinghouse.htm. 
$&

be required to use pump-down techniques to reduce the gas line pressure in the pipeline before 

venting. Alternatively, operators could opt to use an ejector or use inert gases and pigs to purge 

pipelines.222 All of these methods would reduce vented gas and can recover up to 90% of the gas 

in the line.223 Operators can use in-line compressors or portable compressors to lower the gas line 

pressure (or ejectors) and should also be required to incorporate in-line compressor pump-downs 

into emergency procedures. In addition to reducing methane emissions, natural gas that would 

have been vented to the atmosphere can be recovered and sold. In the case of production 

pipelines, the gas stream might also contain valuable heavy hydrocarbons. Pump down 

techniques also reduce odor and noise pollution and virtually eliminate HAP emissions.224

Recent success of Natural Gas STAR Partner TransCanada’s pump-down practices has resulted 

in the company’s purchase of eight portable compressor units for use mainly on its high-pressure 

lines in Canada. Future possibilities include expanding its fleet of portable compressor units and 

implementing pump-down practices company-wide (36,500 miles of pipeline). TransCanada has 

reported increased revenue and decreased methane emissions from its pump-down practices.225

EPA should also consider requiring operating practices that reduce distribution system pressure. 

According to EPA, nearly all distribution sector methane losses are a result of unidentified 

fugitive leaks.226 Systems that operate under higher than necessary pressure increase the amount 

of leakage that occurs. If operators are required to adjust system pressures at shorter intervals 

they can better match the current demand and reduce the amount of time the system operates 

under peak demand pressures. EPA should require operators to install automated control systems 

to regulate pressure. These automated systems will help ensure lower leak rates and less 

maintenance. 

EPA should also require the use of hot taps for in-service pipeline connections. Hot tapping 

allows for a new pipeline connection while keeping the pipeline in service. Hot tapping avoids 

product loss, methane emissions, and disruption of service to customers.227 According to EPA, 

“hot tapping has been found to be more cost effective than shutdown interconnects” and “recent 

design improvements have reduced the complications and uncertainty operators might have 

experienced in the past.”228 

EPA should require regular inspection of all flowlines in the production sector. The flowlines 

that transport natural gas from wells to transmission compressor stations or processing plant 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

222 See EPA Natural Gas STAR Program Partner Reported Opportunities (PRO), PRO Fact Sheets No. 404 and 405, 

“Install Ejector” and “Use Inert Gases and Pigs to Perform Pipeline Purges”, 

http://www.epa.gov/gasstar/documents/installejector.pdf and 

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

223 Lessons Learned, Natural Gas STAR Partners, “Using Pipeline Pump-Down Techniques to Lower Gas Line 

Pressure Before Maintenance”, October 2006, http://www.epa.gov/gasstar/documents/ll_pipeline.pdf. 224 Id. 225 EPA Natural Gas STAR Partner Update, Fall 2009, 

http://www.epa.gov/gasstar/newsroom/partnerupdatefall09.html. 226 EPA Natural Gas STAR “Reducing Distribution System Pressure” Presentation, 

http://www.epa.gov/gasstar/documents/red_of_pressure_part1.ppt. 227 Lessons Learned, Natural Gas STAR Partners, “Using Hot Taps for In Service Pipeline Connections”, October 

2006, http://www.epa.gov/gasstar/documents/ll_hottaps.pdf. 228 Id.
$'

booster stations are normally buried and, according to EPA, “can leak methane as a result of 

internal corrosion (particularly in wet, sour gas service), external corrosion, and abrasion from 

thermal cycling.”229 EPA estimates that methane leakage from flowlines is “one of the largest 

sources of emissions in the gas industry.”230 These underground leaks can be detected using 

ultrasound or digital radiography. 

Require the Installation of Excess Flow Valves on All Gas Service Lines 

EPA should require that excess flow valves be tested and proven at the time of installation and at 

periodic intervals not to exceed one year.231 Gas line breaks can result in unexpected gas releases 

into the atmosphere. Methane emissions can be avoided by ensuring an automated shutoff of any 

ruptured gas service line through required installation of excess flow valves. 

3. Summary Recommendations for Pipelines

EPA should implement the following for all new pipeline installations: 

! Require the Use of Gas Main Flexible Liners and State-of-the-Art Pipeline Material and 

Protective Coatings 

EPA should require the use of the plastic pipe wherever feasible. Where the use of plastic 

pipe is not feasible EPA should require the use of flexible plastic insert liners. EPA 

should require the use of the best available coating technology to ensure maximum 

protection of piping materials. 

! Require Maintenance Practices for Pipelines 

EPA should require that during routine maintenance, operators be required to use pumpdown techniques to reduce the gas line pressure in the pipeline (or ejectors or use inert 

gases and pigs to purge pipelines) before venting. EPA should also require that in-line 

compressor pump-down techniques be incorporated into emergency procedures. EPA 

should require operators to install automated control systems to regulate pressure to 

ensure lower fugitive leak rates. EPA should also require the use of hot taps for in-service 

pipeline connections. EPA should require regular inspection of all flowlines in the 

production sector. 

! Require the Installation of Excess Flow Valves on All Gas Service Lines 

EPA should require that excess flow valves be tested and proven at the time of 

installation and at periodic intervals not to exceed one year. 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

229 See EPA Natural Gas STAR Program Partner Reported Opportunities (PRO), PRO Fact Sheet No. 407, “Inspect 

Flowlines Annually”, http://www.epa.gov/gasstar/documents/inspectflowlines.pdf. 230 Id. 231 See EPA Natural Gas STAR Program Partner Reported Opportunities (PRO), PRO Fact Sheet No. 610, “Install 

Excess Flow Valves”, http://www.epa.gov/gasstar/documents/installexcessflowvalves.pdf. 
%+

G. Flaring 

Flares are widely used in the oil and gas industry to combust unsalable gas or to dispose of gas 

released for safety measures or during testing. According to EPA, 

Flares in general can be categorized into two main types; continuous and 

intermittent. Continuous flares combust casing head gas, associated gas, well 

testing gas, and gas from equipment that generate a continuous waste gas stream 

(such as glycol dehydrators, storage tanks, and pneumatic devices). Intermittent 

flares combust releases that are not continuous in nature such as streams from 

equipment/ vessel/ site blowdowns and pressure relief valves.232 

Although sending emissions to flares (rather than venting those emissions) eliminates methane, 

other air pollutants, including CO2 are released into the atmosphere. The U.S. Energy 

Information Administration estimated CO2 emissions from natural gas flaring to be 1,187.48 

MMT in 2006.233 In order to reduce methane emissions without increasing additional air 

pollution, alternatives to flaring should be required by EPA. 

These emission estimates for flaring may grossly underestimate actual emissions from this 

source. According to EPA’s recent rulemakings for the Mandatory Reporting of Greenhouse 

Gases program, several emissions sources are believed to be “significantly underestimated” in 

the U.S. GHG Inventory (EPA/GRI/Radian, 1996).234,235 According to EPA, the emissions 

estimates for these under-reported 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.”236 EPA includes revised emission factors for all 

of the underestimated sources except the categories of crude oil and condensate storage tanks and 

flares for which “no new reliable data are available.”237 

EPA should avoid flaring as a control option for vented emissions, relying on vapor recovery 

technologies and operating practices that minimize vented emissions instead. A comprehensive 

plan to improve the environment through the reduction in methane emissions should not increase 

other air pollutant or greenhouse gas emissions. And, in fact, there are several existing 

international programs aimed at reducing the use of flaring as a control technique. 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

232 Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry Background Technical 

Support Document, U.S. Environmental Protection Agency Climate Change Division Washington DC, Appendix I.

233 U.S. Energy Information Administration, International Energy Annual 2006: World Carbon Dioxide Emissions 

from the Use of Fossil Fuels, Table H.3co2, http://www.eia.doe.gov/iea/carbon.html. 234 EPA/GRI (1996) Methane Emissions from the Natural Gas Industry. Prepared by Harrison, M., T. Shires, J. 

Wessels, and R. Cowgill, eds., Radian International LLC for National Risk Management Research Laboratory, Air 

Pollution Prevention and Control Division, Research Triangle Park, NC. EPA-600/R-96-080a.

235 Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry Background Technical 

Support Document, U.S. Environmental Protection Agency Climate Change Division Washington DC, p. 7.

236 Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry Background Technical 

Support Document, U.S. Environmental Protection Agency Climate Change Division Washington DC, p. 23.

237 Id. p. 7.
%*

1. Existing International Programs to Reduce Flaring

The following international programs demonstrate that mandatory methane reduction programs 

can be implemented in parallel with programs aimed at eliminating or reducing flaring. 

The World Bank’s Global Gas Flaring Reduction (GGFR) Partnership is a public-private 

partnership started in 2002, with the goal of recovering natural gas that would normally be sent 

to flares or vented to the atmosphere. The GGFR partners include countries, organizations and 

gas companies, including the U.S. The GGFR developed a Voluntary Standard for Global Gas 

Flaring and Venting Reduction with the primary objectives of “eliminating routine sources of 

venting and eliminating or reducing the large sources of flaring. These goals can be achieved 

through investment in gas utilization projects that encourage the use of gas that would otherwise 

be flared or vented.”238

Norway is said to be the world’s leader when it comes to restrictions for flaring, and this country 

is a member of the GGFR. In 1996, the Petroleum Activities Act was passed, requiring that, 

“[b]urning of petroleum in excess of the quantities needed for normal operational safety shall not 

be allowed unless approved by the Ministry.”239 And according to the World Bank, routine 

flaring is not normally allowed in Norway under any economic conditions.240 

In Alberta, Canada, the Energy Resources Conservation Board regulates flaring, incinerating and 

venting at oil and gas operations under, Directive 060: Upstream Petroleum Industry Flaring, 

Incinerating, and Venting. This measure addresses upstream operations as well as transmission 

facilities. These regulations and guidelines are broad and sweeping, and include detailed 

requirements for flaring, incinerating and venting at many emission points.241 Directive 060 

includes well test flaring, incinerating and venting duration limits; the testing time limit for gas 

wells is 72 hours in order to limit emissions from flaring and venting. In addition to the duration 

limits for testing, the rules require that in-line testing be used when it is economic and feasible.242

Other sources of emissions, including gas batteries, dehydrators, compressor stations, gas plants 

and pipelines are required to limit flaring, incinerating and venting through such measures as 

volume limits.243

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

238 World Bank, GGFR Partnership, 

http://web.worldbank.org/WBSITE/EXTERNAL/TOPICS/EXTOGMC/EXTGGFR/0,,contentMDK:20297378~men

uPK:6296802~pagePK:64168427~piPK:64168435~theSitePK:578069,00.html.

239 Norway Petroleum Activities Act No. 72, Section 4-4, 29 November 1996, last amended by Act 19 June 2009, 

No 104, http://www.npd.no/en/Regulations/Acts/Petroleum-activities-act/.

240 World Bank, Comparison of Associated Gas Flaring Regulations: Alberta & Norway, 

http://web.worldbank.org/WBSITE/EXTERNAL/TOPICS/EXTOGMC/EXTGGFR/0,,contentMDK:21840526~men

uPK:5221283~pagePK:64168445~piPK:64168309~theSitePK:578069,00.html.

241 “Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting,” Energy Resources 

Conservation Board, Alberta, November 16, 2006.

242 Id, p. 21-3. 243 Id. passim.
%"

2. Available Proven Technologies for Flaring

As described above, gas utilization projects can be implemented to eliminate flaring or venting.

CARB lists the use of associated gas that would otherwise be vented or flared as a BMP. 

“Instead of venting or flaring, emissions can be reduced by using the associated gas for reinjection into the field for enhanced oil recovery, or for consumption within the facility.”244

3. Summary Recommendations for Flaring

EPA should require producers to reduce emissions by instituting a gas utilization program, such 

as sending emissions to a vapor recovery unit, rather than flaring and venting. While flaring 

eliminates methane emissions, CO2 and other air pollutant emissions are increased with the 

practice. 

H. Directed Inspection and Maintenance 

In addition to methane reduction technologies for the numerous emission sources at oil and gas 

operations, directed inspection and maintenance (DI&M) and other work practices can bring 

about large methane reductions. As previously described in this report under the “Compressors” 

section, DI&M is “a proven management practice for cost-effective reduction of methane 

emissions” that can significantly reduce fugitive methane emissions from the gas processing 

sector.245 A DI&M program is not the same thing as EPA’s regulatory leak detection and repair 

(LDAR) program for reducing VOC emissions.246 A successful DI&M program includes a 

baseline survey, cost-effective repairs and subsequent targeted surveys based on findings from 

the initial baseline survey. In general, the cost of the baseline survey is reportedly recovered in 

gas savings during the first year.247 The costs of subsequent surveys are minimized by focusing 

the components that were identified through the initial baseline study as having a high potential 

for leakage. A variety of screening and measurement devices (e.g., infrared gas imaging, optical 

remote leak detection, etc.) can be used to obtain accurate leak data and high volume gas 

samplers can be used to identify and quantify leaks.248 According to EPA Natural Gas STAR 

partners, a DI&M program should “target the five categories of equipment components that 

contribute to the majority of methane losses: block valves, control valves, connectors, 

compressor seals, and open-ended lines.”249

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

244 The California Air Resources Board’s Clearinghouse of non-CO2 Greenhouse Gas Emission Control 

Technologies, http://www.arb.ca.gov/cc/non-co2-clearinghouse/non-co2-clearinghouse.htm. 245 Lessons Learned, Natural Gas STAR Partners, “Directed Inspection and Maintenance at Gas Processing Plants 

and Booster Stations”, October 2003, http://www.epa.gov/gasstar/documents/ll_dimgasproc.pdf.

246 See, NSPS Subpart KKK - Standards of Performance for Equipment Leaks of VOC From Onshore Natural Gas 

Processing Plants.

247 Lessons Learned, Natural Gas STAR Partners, “Directed Inspection and Maintenance at Gas Processing Plants 

and Booster Stations”, October 2003, http://www.epa.gov/gasstar/documents/ll_dimgasproc.pdf.

248 See, e.g., Directed Inspection and Maintenance (DI&M) at Gas Processing Plants, Innovative Technologies for 

the Oil & Gas Industry: Product Capture, Process Optimization, and Pollution Prevention, 

Targa Resources and the Gas Processors Association, July 27, 2006 Hobbs, NM, 

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

249 Lessons Learned, Natural Gas STAR Partners, “Directed Inspection and Maintenance at Gas Processing Plants 

and Booster Stations”, October 2003, http://www.epa.gov/gasstar/documents/ll_dimgasproc.pdf.
%#

The use of a DI&M program is also an effective means of reducing methane emissions at 

offshore oil and gas operations. In a paper on offshore platform methane reduction strategies, the 

authors analyzed offshore oil and gas methane emissions and control strategies to devise an 

emission reduction strategy for the most significant sources at the lowest cost. The 

implementation of a directed inspection and maintenance program to target fugitive emissions is 

one of the recommended strategies for reducing methane emissions in offshore applications.250 In 

addition, both the BLM and CARB list the use of directed inspection and maintenance programs 

as a BMP for oil and gas sources.251

1. Existing International Programs to Reduce Methane Emissions Using 

Directed Inspection and Maintenance 

As described above under the “Compressors” section of this report, the Ukrainian natural gas 

transmission company, Cherkasytransgas, implemented a directed inspection and maintenance 

program at its compressor stations in 2002 with huge success in reducing methane emissions. 

The last round of repairs, in 2008-2009, reduced annual methane emissions by 3.5 million cubic 

meters when the company upgraded the sealant on 174 valves at transmission stations, 

distribution stations and linear pipes.252

2. Available Proven Technologies/Methods for Directed Inspection and 

Maintenance

In addition to the DI&M program described above for compressor stations, there are several 

other promising technologies available to further reduce methane emissions. 

Directed Inspection and Maintenance at Gate Stations and Surface Facilities and Gas 

Processing Plants and Booster Stations 

Gate stations are the gas transfer point from transmission pipeline to the distribution system, 

where the gas is depressurized. The surface facilities contain heaters and pressure regulators. 

“Gate stations and surface facilities contain equipment components such as pipes, valves, 

flanges, fittings, open-ended lines, meters, and pneumatic controllers to monitor and control gas 

flow.”253 Methane emissions from leaking meters and regulating equipment at gate stations and 

surface facilities account for around 27 MMcf. Using a DI&M program, operators use a baseline 

survey of the gate stations and surface facilities to direct further inspection and maintenance 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

250 Bylin, Carey et al. for Society of Petroleum Engineers, “Designing the Ideal Offshore Platform Methane 

Mitigation Strategy,” 2010, p. 1.

251 U.S. Department of Interior, Bureau of Land Management, “Air Resource BMPs,” 8/24/09, www.blm.gov/gov 

and The California Air Resources Board’s Clearinghouse of non-CO2 Greenhouse Gas Emission Control 

Technologies, http://www.arb.ca.gov/cc/non-co2-clearinghouse/non-co2-clearinghouse.htm. 252 Methane to Markets, Oil & Gas Methane Reduction Project Opportunity, “Directed Inspection and Maintenance 

and Valve Sealant Updgrades,” Cherkasytransgas, Cherkassy, Ukraine, 

http://www.methanetomarkets.org/projects/projectDetail.aspx?ID=1152.

253 Lessons Learned, Natural Gas STAR Partners, “Directed Inspection and Maintenance at Gate Stations and 

Surface Facilities,” October 2003, p. 2, http://www.epa.gov/gasstar/documents/ll_dimgatestat.pdf.
%$

measures. Likewise, a DI&M program can also be used at gas processing plants and booster 

stations to reduce methane emissions, which emit an estimated 36 Bcf annually.254 

The same leak detection practices can be utilized at gate stations and surface facilities as well as 

gas processing plants and booster stations. Several options for leak screening techniques exist, 

including soap bubble screening, electronic screening using hand-held gas detectors equipped 

with catalytic oxidation and thermal conductivity sensors, organic vapor analyzers and toxic 

vapor analyzers which are also portable devices with hydrocarbon sensors, and portable acoustic 

leak detection devices. Leak measurement techniques are another important component to a 

DI&M program. Options for leak measuring include: organic vapor analyzers and toxic vapor 

analyzers used to estimate mass leak rates, “bagging techniques” where the leak or leaking 

component is covered with a bag or tent to collect and measure the gas, high volume samplers 

collect and accurately quantify leak emission rates, and rotameters and other high volume meters 

are used to measure large leaks.255 

Directed Inspection and Maintenance Using Infrared Laser Detection 

There are several leak detection options under this category. Live leak imaging cameras provide 

real time and video recordings of gas leaks using infrared technology to detect otherwise 

invisible gas. Aerial leak surveys are performed by helicopter to detect large leaks at remote 

facilities. There are also infrared laser techniques available to use laser beam to scan methane 

leaks.256 Dynegy Midstream Service, LLP, has had great success in reducing methane leaks using 

a DI&M program that involves aerial optical surveying and handheld optical surveying. Using 

the aerial screening method, Dynegy was able to identify and repair leaks in its pipelines, 

reducing its annual methane emissions. Dynegy also used handheld optical devices to further 

reduce methane emissions.257 

Work Practices 

In addition to a DI&M program, Natural Gas STAR partners have achieved methane reductions 

through work practice techniques. These work practices include eliminating unnecessary 

equipment and/or systems, optimizing processes, decreasing the time between fugitive emissions 

“walking” surveys and requiring improvements in the quality of gas received from producers.258

3. Summary Recommendations for Directed Inspection and Maintenance

EPA should require that operators implement DI&M programs and good work practices in all 

possible sectors in order to detect and reduce methane emissions. 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

254 Lessons Learned, Natural Gas STAR Partners, “Directed Inspection and Maintenance at Gas Processing Plants 

and Booster Stations”, October 2003, p. 1.

255 Id., pp. 3-7. 256 US EPA’s Natural Gas STAR: Directed Inspection and Maintenance (DI&M) Using Infrared Laser Detection, 

http://www.epa.gov/gasstar/documents/leak_detect.pdf. 257 Natural Gas STAR Partner Update, Fall 2005, p. 2, http://www.epa.gov/gasstar/documents/ngstar_fall2005.pdf. 258 http://www.epa.gov/gasstar/tools/recommended.html#other. 
%%

III. CONCLUSION 

Oil and gas extraction and production emit significantly large quantities of GHGs and other air 

pollutants, and U.S. oil and gas production is expected to grow rapidly. The oil and gas 

industry’s significant emissions of GHGs and other air pollutants and forecasted growth warrant 

significant action on the part of EPA. Oil and gas production has exploded in places like the 

Rocky Mountain West, contributing to rising greenhouse gas emissions as well as unprecedented 

air pollution levels. 

Given that: 

(1) methane emissions from oil and gas development in the U.S. constitute a significant, 

often underestimated and growing portion of the overall greenhouse gas mix; and 

(2) methane is a potent greenhouse gas with a relatively short atmospheric lifetime, making it 

a prime candidate for impacting climate change in the short-term; and 

(3) methane emissions contribute to ozone pollution; and 

(4) there are already many proven technologies and practices available to significantly reduce 

methane emissions from oil and gas systems; and 

(5) these technologies also offer opportunities for significant cost-savings in the form of 

recovered methane gas; 

the need for meaningful performance and operating standards to reduce methane emissions from 

the oil and gas source category is vital to ensure that increasing energy production does not occur 

at the cost of our nation’s air quality and public health. 

EPA has failed to date to implement and maintain comprehensive standards for the oil and gas 

sector, despite the fact that our understanding of the adverse impacts of methane emissions on 

public health and welfare has improved—in particular with regard to methane’s significant 

contribution to climate change and ozone pollution. We urge EPA to issue comprehensive 

regulations for the oil and gas sector, including standards and practices targeted at achieving 

meaningful methane emissions reductions. New source standards and operating practices should 

be based on the available methane reduction and reuse technologies that reflect best 

demonstrated technologies and practices. 

EPA must also adopt comprehensive monitoring, reporting and recordkeeping requirements to 

support new and revised NSPS for the oil and gas sector. These compliance demonstration 

techniques should be aligned with the recently finalized reporting requirements for the oil and 

gas industries in Subpart W of 40 CFR Part 98.259 Under EPA’s mandatory reporting 

requirements, facilities are required to quantify GHG emissions, including methane emissions, 

according to a range of methods that include the direct measurement of emissions, engineering 

estimation methods (e.g., simulation models, engineering calculations, original equipment 

!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!!

259 Administrator Jackson signed the rule on November 8, 2010 (Federal Register citation pending). 
%(

manufacturer emission factors, default emission factors, etc.), leak detection and leaker emission 

factors as well as equipment count and population emission factors. We urge EPA to develop 

mechanisms to move the newly-established reporting system steadily towards the most accurate 

and precise reporting methods possible which will mean moving towards the use of more direct 

measurement methods and will also mean systematically and periodically auditing and reviewing 

the reporting requirements to ensure continuous improvement in the reported data. EPA should 

commit to a rigorous periodic statistical sampling and audit program in order to ensure 

continuous improvement in the data collected under the MRR and in the compliance 

demonstration techniques used in support of NSPS. EPA should establish as part of this 

rulemaking comprehensive compliance demonstration methods and a plan for periodically 

updating these methods as improvements in the techniques for monitoring methane emissions 

from oil and gas sources occur. Rigorous monitoring techniques that are based on the latest 

measurement methods will be a key component of NSPS for the oil and gas sector. 
Megan M. Williams

Page 1 of 2

Megan M. Williams

756 Cottage Lane • Boulder, CO 80304 • 303 - 630 - 9620 • megan@sevenfivesix.org

SKILLS

Over 10 years of experience working on air quality issues

Technical and Policy areas of expertise 

• Analyzing and characterizing air emissions from a variety of air pollution sources

• Determining air emissions reduction potentials from control technology scenarios

• Reviewing public lands management actions taken under the National Environmental Policy Act (e.g., 

 Environmental Impact Statements, Environmental Assessments, Resource Management Plans, Travel 

 Management Plans, etc.)

• Reviewing new, existing and modified state air quality regulations to determine if they meet federal 

 Clean Air Act requirements

• Reviewing proposed federal and state air quality rules and policy to determine if they are as rigorous 

 and stringent as possible

• Thorough understanding of the requirements of the nonattainment new source review and prevention 

 of significant deterioration construction permit programs and Title V operating permit program

Computer skills

• Highly proficient in MS Windows and Macintosh

• Experienced with numerous standard software packages

• Experienced writing programs to perform data analysis (e.g., Excel macros, etc.)

Communication skills 

• Experienced and thorough in writing both technical and policy documents

• Presented half-day technical seminars on Indoor Air Quality (to teachers, maintenance staff, etc.)

• Active in EPA’s Environmental Education Council (1998-2000)

Completed numerous technical and policy courses offered by the EPA Education and Outreach Program

PROFESSIONAL EXPERIENCE

VARIOUS ENVIRONMENTAL AND GOVERNMENT ORGANIZATIONS Boulder, CO

July 2003–present

Air Quality Consultant

• Provide a variety of technical and policy analyses related to national, regional and local air quality and 

 energy issues. Includes technical and policy research, the production of written documents and 

 reports, quantitative determinations and qualitative assessments. 
Megan M. Williams

Page 2 of 2

U.S. ENVIRONMENTAL PROTECTION AGENCY Denver, CO

January 1998–November 2002

Environmental Engineer, May 2000–November 2002

Air Quality Planning Group

• Region 8 lead for nonattainment new source review and prevention of significant deterioration policy 

 development and planning analyses (2001–2002) 

• Reviewed state rules and rule changes related to new source review permitting to determine if they 

 met federal Clean Air Act requirements

• Prepared official documents to approve or disapprove state implementation plan revisions 

• Reviewed PM10 redesignation requests and prepared official documents for redesignating PM10

 nonattainment areas to attainment

• Primary contact for Wyoming air issues (2001–2002)

• Compiled EPA-approved implementation plan for Wyoming

• Co-led a national working group to re-examine EPA’s existing policy on redefining “baseline 

 areas” under the Clean Air Act. Planned and hosted national workgroup meeting in Denver to develop 

 criteria for approving baseline area redesignations. Co-authored a Technical Memo to EPA’s Office 

 of Air Quality Planning & Standard’s Director proposing use of the new criteria 

• Received Superior Accomplishment Recognition for technical and policy work on an air quality 

 dispersion modeling analysis of Prevention of Significant Deterioration (PSD) increment consumption 

 in North Dakota and eastern Montana (report available upon request).

Regional Indoor Air Quality Program Manager, January 1998–May 2000

• Managed EPA Region 8’s voluntary Indoor Air Quality Program

• Provided technical assistance and outreach to schools, state/local officials and the general public

• Initiated and managed research projects to assess indoor air quality interventions

• Developed and maintained regional IAQ website 

• Received Superior Accomplishment Recognition for working with schools to voluntarily implement 

 EPA’s Indoor Air Quality Tools for Schools program 

• Received regional award for Excellence in Environmental Education

WISCONSIN DEPARTMENT OF NATURAL RESOURCES Madison, WI

Air Management Engineer, January 1997–December 1997

• Wrote Title V Operating Permits for sources in northwest Wisconsin (e.g., power plants, paper mills, 

 breweries, and military operations) 

Air Management Intern, August 1995–December 1996 

(part-time position in conjunction with the Air Resources Management graduate program at UW - Madison)

• Wrote Title V Operating Permits for sources in northwest Wisconsin 

• Developed statewide general Title V Operating Permits for small heating units and ethylene oxide 

 sterilizers

EDUCATION

UNIVERSITY OF WISCONSIN – MADISON

Institute for Environmental Studies

Master of Science, Air Resources Management, December 1996

UNIVERSITY OF COLORADO – BOULDER

College of Engineering and Applied Sciences

Bachelor of Science, Applied Mathematics (emphasis Mechanical Engineering), May 1995
Cindy S. Copeland

1

CINDY S. COPELAND

1071 Tantra Park Circle · Boulder, CO 80305 · 303-520-8248 · cindycopeland5@gmail.com

 

FOCUS AREA

Outstanding background in environmental policy with a focus on air quality and climate change. 

Extensive experience with air pollution reduction control strategies and scenarios. 

SKILLS

Over 10 years of experience working on air quality issues

Technical and Policy areas of expertise

• Analyzing and characterizing air emissions from a variety of air pollution sources

• Determining air emissions reduction potentials from control technology scenarios

• Reviewing new, existing and modified state air quality regulations to determine if they meet 

federal Clean Air Act requirements

• Reviewing proposed federal and state air quality rules and policy to determine if they are as 

rigorous and stringent as possible

• Thorough experience with the requirements of particulate matter control through state 

implementation plan requirements under the Clean Air Act

Communication skills

• Numerous presentations made to state and tribal air quality officials

• Extensive experience in negotiations over highly technical and politicized issues

• Experienced and thorough in writing both technical and policy documents 

• Testified at hearings for federal and state rulemakings

• Experience with press statements and presentations

• Preparing briefings for high level management 

EXPERIENCE

Environmental Consultant. (January 2006-present)

• Extensive policy and technical analyses of federal and state actions concerning air quality 

and climate

• Represent environmental groups at stakeholder meetings

Program Associate. Environmental Defense, Boulder, Colorado (March 2004-September 2005)

• Assisted with a variety of policy and technical air quality reviews

• Coordinated and contributed to official organization reports on air quality and climate

• Represented organization in state stakeholder and rulemaking processes

• Authored extensive regulatory and technical letters commenting on EPA and state actions

• Testified at state and federal regulatory hearings on proposed rule changes
Cindy S. Copeland

2

Teaching Assistant. University of Colorado, Boulder, Colorado (Spring Semester 2003)

• Instructed two undergraduate sections of a weather lab

• Graded student work products

Environmental Protection Specialist. U.S. Environmental Protection Agency, Region 8, 

Denver, Colorado 

(January 1998-August 2002) 

• Acted as the Environmental Protection Agency Region 8 Particulate Matter Program 

Manager 

• Participated in development of air pollution control regulations for Colorado, Montana, Utah, 

Wyoming, North Dakota, South Dakota and 27 local Tribal governments 

• Represented all EPA Regions as the Regional lead on particulates and collaborated with the 

EPA's headquarters office on policy development and implementation 

• Received the EPA Bronze award for being the lead program person on the redesignation of 

the Denver PM10 nonattainment area to attainment/maintenance.

• Presented information updates and issues to State and Tribal environmental divisions, 

including State Air Directors and State Air Quality Boards

• Presented public outreach on outdoor air, indoor air, and asthma 

• Reviewed, evaluated and approved state air quality plan revisions 

• Responded to state, local and private inquiries to requirements and implementation of the 

Clean Air Act 

• Coordinated and conducted internal and external meetings to evaluate, resolve, and 

implement solutions to issues with technical, legal, and managerial personnel 

• Served on the Region 8 agricultural task team

EDUCATION

Master of Science. University of Colorado Environmental Studies Program (2004)

Thesis: Facing Climate Change in New Mexico

Bachelor of Arts. Willamette University, Salem, Oregon (1997) 

Major: Politics

Minor: Environmental Science

Senior Thesis: Global Climate Change: The International and United States Responses